UK Oil and Gas Law: Current Practice and Emerging Trends: Volume II: Commercial and Contract Law Issues 9781474421751

Table of contents :
CONTENTS
List of Figures and Tables
List of Contributors
List of Abbreviations and Acronyms
Foreword to the First Edition
Preface to the First Edition
Preface to the Second Edition
Preface to the Third Edition
Table of Cases
Table of Statutes
Table of Statutory Instruments
Table of European Legislation
Table of International Instruments
Introduction and Context
II-1 Oil and Gas Law on the United Kingdom Continental Shelf: Current Practice and Emerging Trends in Contracting and Commercial Law
Commentary on Specific Contracts and Contractual Issues
II-2 Joint Operating Agreements
II-3 Unitisation
II-4 Dissecting the Dayrate Drilling Contract
II-5 Contractual Standardisation and the LOGIC Standard Contracts
II-6 Risk Allocation in Oil and Gas Service Contracts
II-7 Commercial Agreements and Issues in the Transportation of Oil and Gas
II-8 Petroleum Sales Agreements
Issues of Commercial Law in the Oil and Gas Context
II-9 Acquisitions and Disposals of Upstream Oil and Gas Interests
II-10 Finance, Security and Insolvency in the Upstream Oil and Gas Sector
II-11 Competition Law and the Upstream Oil and Gas Business
II-12 Law and Technology in the Oilfield
II-13 Aspects of Land Law Relative to the Transportation of Oil and Gas in Scotland
II-14 Selected Employment Law Issues in the Oil and Gas Industry
II-15 Dispute Management and Resolution
Index

Citation preview

UK OIL AND GAS LAW VOLUME II

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UK OIL AND GAS LAW CURRENT PRACTICE AND EMERGING TRENDS 3rd edition VOLUME II COMMERCIAL AND CONTRACT LAW ISSUES

Edited by Greg Gordon, LL.B., Dip.L.P., LL.M., Ph.D. Senior Lecturer and Head of School of Law, University of Aberdeen John Paterson, LL.B., Dip.L.P., LL.M., Ph.D. Professor of Law and Vice-Principal, University of Aberdeen Emre Üșenmez, B.Sc., B.A., LL.M., M.Sc., Ph.D. Lecturer in Law, University of Aberdeen Editorial Assistant James Cowie, LL.B.

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Note: all chapters and sections are prefixed “II” to denote Volume II; cross-references that are prefixed “I” refer to items in Volume I.

Edinburgh University Press is one of the leading university presses in the UK. We publish academic books and journals in our selected subject areas across the humanities and social sciences, combining cutting-edge scholarship with high editorial and production values to produce academic works of lasting importance. For more information visit our website: edinburghuniversitypress.com

© editorial matter and organisation Greg Gordon, John Paterson and Emre Üșenmez, 2018 © the chapters their several authors, 2018

First edition published in 2007 by Dundee University Press Second edition 2011

Edinburgh University Press Ltd The Tun – Holyrood Road 12 (2f) Jackson’s Entry Edinburgh EH8 8PJ

Typeset in Sabon by Fakenham Prepress Solutions, Fakenham, Norfolk NR21 8NN, and printed and bound in Great Britain

A CIP record for this book is available from the British Library

ISBN 978 1 4744 2174 4 (paperback) ISBN 978 1 4744 2175 1 (webready PDF) ISBN 978 1 4744 2176 8 (epub)

The right of the contributors to be identified as authors of this work has been asserted in accordance with the Copyright, Designs and Patents Act 1988 and the Copyright and Related Rights Regulations 2003 (SI No. 2498).

Published with the support of the University of Edinburgh Scholarly Publishing Initiatives Fund.

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CONTENTS List of Figures and Tablesvii List of Contributorsviii List of Abbreviations and Acronyms Foreword to the First Edition Preface to the First Edition

x xvi xviii

Preface to the Second Edition

xx

Preface to the Third Edition

xxi

Table of Cases Table of Statutes

xxiii xxxix

Table of Statutory Instruments

lvii

Table of European Legislation

lxxvii

Table of International Instruments

lxxxiii

Introduction and Context II-1 Oil and Gas Law on the United Kingdom Continental Shelf: Current Practice and Emerging Trends in Contracting and Commercial Law Greg Gordon and James Cowie

3

Commentary on Specific Contracts and Contractual Issues II-2 Joint Operating Agreements Scott Crichton Styles

15

II-3 Unitisation Nicola MacLeod

74

II-4 Dissecting the Dayrate Drilling Contract Greg May and Eve Brazier

107

II-5 Contractual Standardisation and the LOGIC Standard Contracts149 Lorna Dawson II-6 Risk Allocation in Oil and Gas Service Contracts Greg Gordon

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175

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II-7 Commercial Agreements and Issues in the Transportation of Oil and Gas 235 Laura Petrie II-8 Petroleum Sales Agreements Yanal Abul Failat

263

Issues of Commercial Law in the Oil and Gas Context II-9 Acquisitions and Disposals of Upstream Oil and Gas Interests297 Norman Wisely II-10 Finance, Security and Insolvency in the Upstream Oil and Gas Sector Jenny Allan and Sian Aitken

331

II-11 Competition Law and the Upstream Oil and Gas Business368 Judith Aldersey-Williams II-12 Law and Technology in the Oilfield Martin Ewan II-13 Aspects of Land Law Relative to the Transportation of Oil and Gas in Scotland Roderick Paisley

404

426

II-14 Selected Employment Law Issues in the Oil and Gas Industry448 Sarah Arnell

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II-15 Dispute Management and Resolution Margaret Ross and Valerie Allan

490

Index

529

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FIGURES AND TABLES

FIGURES II-6.1 Simplified Example of a Set of Back-to-back Mutual Hold Harmless Indemnity Provision in Respect of Personal Injury II-6.2 Hypothetical Liabilities Matrix Based on a Relatively Simple Set of Operator-Contractor Indemnity and Hold Harmless Provisions II-6.3 Simplified Example of Contractual Relations on a Production Platform

191 195 217

TABLES II-4.1 The Risk Matrix Table II-5.1 Outline of Contractual Structure II-10.1 Lifecycle and Finance Source II-10.2 Risks and Mitigants II-11.1 Risk Matrix for Information Exchange

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148 151 333 334 395

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CONTRIBUTORS Judith Aldersey-Williams, B.A., LL.M., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP Jenny Allan, LL.B., Dip.L.P., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP Valerie Allan, LL.B., Dip.L.P., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP Sian Aitken, LL.B., Dip.L.P., J.I.E.B., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP Sarah Arnell, LL.B., Dip.L.P., LL.M., Solicitor Lecturer, The Law School, Robert Gordon University Eve Brazier, B.A., LL.B., Dip.L.P., Solicitor Senior Solicitor, Brodies LLP James Cowie, LL.B. Trainee Solicitor, Jones Day Lorna Dawson, LL.B., Dip.L.P., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP Martin Ewan, LL.B., Dip.L.P., LL.M., M.A., B.Sc., M.Sc., Solicitor Partner, Pinsent Masons LLP Yanal Abul Failat, LL.B., LL.M., Solicitor Associate, LXL LLP Greg Gordon, LL.B., Dip.L.P., LL.M., Ph.D. Senior Lecturer in Law, University of Aberdeen Nicola MacLeod, LL.B., Dip.L.P., LL.M., Solicitor Director of Legal, Commercial and External Relations, Maersk Oil Greg May, LL.B., Solicitor Partner, Brodies LLP Roderick Paisley, LL.B., Dip.L.P., Ph.D., Solicitor Professor of Scots Law, University of Aberdeen Laura Petrie, LL.B, Dip.L.P., Solicitor Legal Director, Womble Bond Dickinson

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c ont r i b u to rs ix

Margaret Ross, LL.B., Solicitor Professor of Law and Vice-Principal for People, University of Aberdeen Scott C. Styles, M.A., LL.B., Dip.L.P. Senior Lecturer in Law, University of Aberdeen Norman Wisely, LL.B., Dip.L.P., Solicitor Partner, CMS Cameron McKenna Nabarro Olswang LLP

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ABBREVIATIONS AND ACRONYMS AA AAA/ICDR AAPL ADR AFE AIPN ALARP AMI API ARN ASCOBANS BAT BATNA BEIS BEP BNOC boe BPEO CAEM CAR CCS CCW CEDR CEFAS CERM CGT CIMAH CMR COMAH

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appropriate assessment American Arbitration Association/ International Court of Dispute Resolution American Association of Professional Landmen alternative dispute resolution authorisation for expenditure Association of International Petroleum Negotiators as low as reasonably practicable Area of Mutual Interest Agreement American Petroleum Institute automatic referral notice Agreement on Small Cetaceans of the Baltic and North Seas Best Available Technique best alternative to a negotiated agreement Department for Business, Energy and Industrial Strategy Best Environmental Practice British National Oil Corporation barrels of oil equivalent best practicable environmental option Center for the Advancement of Energy Markets Construction All Risk carbon capture and storage Countryside Council for Wales Centre for Effective Dispute Resolution Centre for Environment, Fisheries and Aquaculture Science Co-ordinated Emergency Response Measures Capital Gains Tax Control of Industrial Major Accident Hazard Regulations (1984) Convention on the Contract for the International Carriage of Goods by Road Control of Major Accident Hazard Regulations (1999)

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CPA 1949 CPC CPR CRINE CSIS CT CTA 2010 CVA DBERR DEAL DECC DEFRA DEn DNV DOPWTS DSA DTI EA E&P EAT EC ECJ ECT EEA EIA EMT EMV EPC Regulations ERA ES EU FEPA 1985 FPAL FPSO FRS FSA FY GAAP GATT GDP GFU

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Coast Protection Act 1949 central product classification Civil Procedure Rules (1998) Cost Reduction Initiative for the New Era Center for Strategic & International Studies Corporation Tax Corporation Tax Act 2010 company voluntary arrangement Department for Business, Enterprise and Regulatory Reform Digital Energy Atlas and Library Department of Energy and Climate Change Department of Environment, Food and Rural Affairs Department of Energy Det Norske Veritas Dispersed Oil in Produced Water Trading Scheme decommissioning security agreement Department of Trade and Industry environmental assessment exploration and production Employment Appeal Tribunal European Community European Court of Justice Energy Charter Treaty European Economic Area environmental impact assessment Environmental Management Team expected monetary value Offshore Installations (Emergency Pollution Control) Regulations 2002 Employment Rights Act 1996 environmental statement European Union Food and Environment Protection Act 1985 First Point Assessment Ltd floating production, storage and offloading Fisheries Research Services Formal Safety Assessment financial year generally accepted accounting practice General Agreement on Tariffs and Trade gross domestic product Norwegian Gas Negotiation Committee

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GHG GLA H2S HMRC HP/HT HSC HSE HSWA 1974 IAPP Certificate IATA ICC ICOP ICSID IEA IEP Agreement IGIP IMCA IMHH IMO IP IRR IT ITF IUK JBA JNCC JOA JOC JV KP3 LCIA LCP LCPD LNG LOC LOGIC MC MCA

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greenhouse gas General Lighthouse Authority hydrogen sulphide Her Majesty’s Revenue and Customs high pressure/high temperature Health and Safety Commission Health and Safety Executive Health and Safety at Work, etc Act 1974 International Air Pollution Prevention Certificate International Air Transport Association International Chamber of Commerce Infrastructure Code of Practice International Centre for Settlement of Investment Disputes International Energy Agency Agreement on an International Energy Program initial gas in place International Maritime Contractors Association Industry Mutual Hold Harmless Deed (strictly, the Mutual Indemnity and Hold Harmless Deed) International Maritime Organization intellectual property internal rate of return income tax Industry Technology Facilitator Interconnector UK Ltd joint bidding agreement Joint Nature Conservancy Council joint operating agreement Joint Operating Committee joint venture Key Programme 3 London Court of International Arbitration large combustion plant Large Combustion Plants Directive liquefied natural gas letter of credit Leading Oil and Gas Industry Competitiveness Model Clause Maritime and Coastguard Agency

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Merchant Shipping Merchant Shipping (Oil Pollution   (OPRC)   Preparedness, Response and Co-operation  Regulations  Convention) Regulations 1998 mmb/d million barrels of oil per day MOOIP moveable oil originally in place NARUC National Association of Regulatory Utility Commissioners NEC Regulations National Emission Ceilings Regulations 2002 NERC Natural Environment Research Council NH3 ammonia NOx nitrogen oxide NPI net profit interest NPV net present value NPV/I net present value to investment ratio NSRI National Subsea Research Institute NTS National Transmission System or non-technical summary (in ES) OC Regulations Offshore Chemical Regulations 2002 OCA Offshore Contractors Association OECD Organization for Economic Co-operation and Development OED Offshore Environment and Decommissioning Unit OFT Office of Fair Trading OGA Oil and Gas Authority OGIA Oil and Gas Independents’ Association OGITF Oil and Gas Industry Task Force OGUK Oil & Gas UK ONS Office for National Statistics OPA Regulations Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 Opcom Joint Operating Committee OPEC Organization of the Petroleum Exporting Countries OPOL Offshore Pollution Liability Agreement OSPAR Convention for the Protection of the Marine Environment of the North-East Atlantic 1992 OSPRAG Offshore Spill Prevention and Response Advisory Group OTA 1975 Oil Taxation Act 1975 OTA 1983 Oil Taxation Act 1983 PAPS Regulations Merchant Shipping (Prevention of Air Pollution from Ships) Regulations 2008 PCG parent company guarantee

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PED

Petroleum Engineering Division (of the Department of Energy) PEDL Petroleum Exploration and Development Licence PILOT successor to the Oil and Gas Industry Task Force PON Petroleum Operation Notice PPSGS Regulations Merchant Shipping (Prevention of Pollution by Sewage and Garbage from Ships) Regulations 2008 PPWG Progressing Partnership Work Group PRT Petroleum Revenue Tax PSPA Petroleum and Submarine Pipelines Act 1975 PTW permit to work QCI qualifying combustion installation QRA Quantified Risk Assessment RFCT Ring Fence Corporation Tax ROV remotely operated vehicle RPGA Rules and Procedures Governing Access to Offshore Infrastructure SAC Special Area of Conservation SC Supplementary Charge SEA strategic environmental assessment SEAM Senior Executive Appraisal Mediation SECA SOx emission control area SEPA Scottish Environment Protection Agency SGERAD Scottish Government Environment and Rural Affairs Department SMS Safety Management System SNH Scottish Natural Heritage SO2 sulphur dioxide SOAEFD Scottish Office Agriculture, Environment and Fisheries Department SPA Special Protection Area STOOIP stock tank oil originally in place t tonnes (metric) TDM Transnational Dispute Management TFEU Treaty on the Functioning of the European Union toe ton oil equivalent TPA transport and processing agreement TWJA 1878 Territorial Waters Jurisdiction Act 1878 UCTA Unfair Contract Terms Act (1977) UK LIFT United Kingdom Licence Information for Trading

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UKAPP Certificate UKCS UKOOA UNCITRAL UNCLOS UOA UUOA VOC WSCA WTO

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United Kingdom Air Pollution Prevention Certificate United Kingdom Continental Shelf United Kingdom Offshore Operators Association (now Oil & Gas UK Ltd) United Nations Commission on International Trade Law United Nations Convention on the Law of the Sea unit operating agreement unitisation and unit operating agreement volatile organic compound Well Services Contractors Association World Trade Organization

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FOREWORD TO THE FIRST EDITION I write this Foreword at a time when crude oil prices have jumped to a record high of over US $80 a barrel (West Texas Intermediate). At the same time, there is a world credit crunch, and it remains to be seen what impact this will have upon the oil and gas sector. At a recent major conference of the Association for the Study of Peak Oil, Lord Oxburgh (the former chairman of Shell) gave a stark warning that the price of oil could hit US $150 per barrel and that oil production could peak within the next 20 years. The rapid increase in the price of oil seems inevitable as demand continues to outstrip supply. However, it is also going to become very expensive indeed to extract oil from the ground. We already see that in our maturing province in the UKCS, with a considerable increase in costs for operating and developing oil and gas fields. This is an industry in a state of flux, and there is a great responsibility on industry lawyers and commercial negotiators to come up with innovative business models and flexible, streamlined legal agreements and processes to facilitate the maximum recovery of remaining reserves in the UKCS. This we must do by working closely with our technical colleagues who are charged with developing increasingly innovative and cost-effective technical solutions to reserves recovery. It is also the responsibility of lawyers, along with our commercial, tax and finance colleagues, to be effective advocates for appropriate changes to UK oil and gas legislation to ensure a successful future for the UKCS. To meet this responsibility, the industry needs dynamic and competent advice at a time when we are experiencing an extreme shortage of experienced oil and gas lawyers. It is all the more important, then, that lawyers coming into our industry have access to reliable and up-to-date reference books on oil and gas law. If we are to meet the challenges ahead, we must pass on the knowledge we already have to a new generation of lawyers; this book helps enormously in that task. Often our oil and gas industry leaders decry lawyers as those who simply “paper” the deals and arrangements put in place by technical and commercial people. This book goes a long way towards dispelling that myth. It shows the complexity and sophistication of oil and gas law, and its breadth. UK oil and gas law is formed by a layering of statute, commercial agreements, EU and UK competition and procurement law, industry voluntary codes (such as CCOP and ICOP) and DBERR Guidance. Oil and gas law is a very important

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f o r e wo r d to t h e f i rs t e d i t i o n xvii

field of law and yet there are very few reference sources. This volume is long overdue and very welcome. It describes, in depth, most of the recent developments in this very broad and diverse field. Most importantly, it captures with great clarity the many joint industry and government initiatives since 2000 which impact the legal and commercial arrangements in our sector, for instance those on fallow acreage, stewardship, CCOP and ICOP. It is also the first time the legal basis for these initiatives has been analysed in detail. There is an enormous challenge ahead. In a time of high oil prices, owners of infrastructure inevitably wish to protect their own production and fair allocation of risk remains difficult to achieve. The “mutual hold harmless” principle is being pushed to its limits, with creeping practices of uncapped liability and indemnity clauses on third-party infrastructure users. As an industry lawyer for the past 15 years, I have been passionate about improving the way the industry conducts its business to take duplication and waste out of legal processes. This began in 1995 when I worked on the setting up of First Point Assessment Ltd (“FPAL”) and the development of the Memorandum and Articles for the new entity. It is with pride that I note that FPAL celebrated its 10th anniversary at Offshore Europe this month. It has been an enormous privilege for me to have played a part in many of the industry legal working groups which have brought about streamlined agreements (IMHH, Standard Contracts, ICOP, DSA, SPA and Master Deed). We can be proud of what has been achieved and the contribution made by industry and private practice lawyers alike to such progress. This book is an excellent consolidated source on all of these important initiatives and is testimony to the considerable progress made. May it foster even greater academic enquiry and innovation among oil and gas lawyers. In summary, never has oil and gas law been more complex, never have the expectations of government and industry leaders on lawyers and commercial advisers been higher – and all this at a time of uncertainty as to how the oil and gas market will play out. The industry requires highly competent future lawyers, great clarity of legal thinking and drafting and – above all else – swift close-out of transactions. This excellent book stands us in good stead for meeting the exciting challenges ahead. Jacquelynn F Craw Legal Manager, Director and Company Secretary Talisman Energy (UK) Ltd September 2007

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PREFACE TO THE FIRST EDITION This book arose as a result of several inter-related stimuli. In developing the LL.M. in Oil and Gas Law, upon which course the editors and several of the book’s contributors teach, it became increasingly apparent that while there has been a constant throughput of primary materials in the form of statutes, statutory instruments, guidance and codes, surprisingly little in the way of secondary comment has been published in the area of UK oil and gas law over the years. Moreover, although much of the work published is of a very high standard, there are some noticeable gaps in coverage – and some of the works which are available, and which continue to be of great value, are beginning now to show their age as the UKCS develops and new issues become increasingly relevant.1 In addition, many of the materials which are available assume a considerable degree of industry knowledge and experience. It can be difficult for a student, or indeed a qualified lawyer making his or her way into the industry, to find a book which will provide a clear but concise account. Finally, many of the books which are available are so highly priced that they are prohibitively expensive to students, and indeed many libraries. The decision to write this book was taken by the editors over coffee while discussing these matters. Much coffee has been drunk by the editors since. The editors have many people to thank. Our most obvious debt is to the contributors. The book could not have been produced within a reasonable timescale if the editors had had to write it all themselves, and some of the chapters here could not have been written at all. In addition to writing chapters within the book, Margaret Ross, Roderick Paisley, Norman Wisely, Judith Aldersey-Williams and Uisdean Vass read and offered useful comments upon other chapters. Valuable comments have also been received from Lorna Hingston of CMS Cameron McKenna, Bob Ruddiman of McGrigors and Angus Campbell of the University of Aberdeen. The editors are very grateful to all of them for taking the time and trouble to assist. The editors are also very grateful to Carole Dalgleish for commissioning

 This observation does not apply to Daintith, Willoughby and Hill’s excellent and regularly updated UK Oil and Gas Law.

1

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p r e fac e to t h e f i rs t e d i t i o n xix

the work, and to her and all involved at Dundee University Press for their unfailing commitment and encouragement. This book is not intended to supplant existing materials, but to supplement them, and hopefully to bring them to the attention of a wider readership. Nor is it intended to be a comprehensive exposition of all legal issues facing the oil and gas industry in the UKCS. There is more that could usefully be said in relation to many of the areas which have been covered, and many other topics could have been selected were it not for the constraints of space and time.2 Finally, it is hoped that this book will go some way towards stimulating more writing about, and more debate in, what is a fascinating and important area of (or perhaps more properly, context for) the law. Towards that end, the editors invoke the spirit of Sir John Skene’s dedication to the reader: “Quhatever I have done, I did it nocht to offend thee or to displease anie man, bot to provoke uthers to doe better.”3

Greg Gordon John Paterson August 2007

  Environmental law, for instance, is dealt with at several points, but considerations of environmental law as relative to the oil and gas industry could very easily form the subject of a large book on their own 3   Sir John Skene, De Verborum Significatione (1597). 2

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PREFACE TO THE SECOND EDITION It is very gratifying to see the book go into a second edition. The editors’ aim in producing the first edition of this work was to provide a clear, reasonably concise and affordable account of contemporary oil and gas practice in the UKCS. That aim is unchanged. The book attempts to describe the law as it stood in January 2011, but it has been possible to incorporate at proof stage passing reference to some later developments. As before, the editors have many people to thank. First, the new contributors (Martin Ewan, Luke Havemann and Emre Üșenmez) who have allowed us to expand the scope of the book by authoring chapters on technology in the oilfield, environmental regulation, energy security and taxation. The inclusion of these topics is of great benefit to the book. Second, we must thank all of the original contributors who kindly agreed to update their chapters. Law and practice have certainly not stood still in the 4 years since the first edition of this book was published and in many cases this has involved a significant amount of work. Thanks are also due to David Roper for his preparatory work in the chapter on technology in the oilfield. The editors are also grateful to Christine Gane for allowing us to use her index for the first edition as the basis for the second and to Karen Howatson at Dundee University Press for updating the index. We would also like to thank Carole Dalgleish and all involved at Dundee University Press for their ongoing commitment and support. Finally, the original editors are delighted to welcome Emre Üșenmez to both the editorial team of this work and the lecturing staff at the University of Aberdeen. Emre has undertaken a significant amount of the editing work for the new edition as well as contributing two new chapters to the book. He also makes a mean cup of coffee. This is not something we say lightly; readers of the preface to the first edition will know the importance which that beverage has played since the very inception of this book. But we should also emphasise that Emre was recruited on the basis of his legal and analytical skills alone. Greg Gordon John Paterson Emre Üșenmez April 2011

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PREFACE TO THE THIRD EDITION The third edition of this book comes seven years after the second. Those years can fairly be described as turbulent. Oil price, which spent much of the period 2011–2014 at or above $100 per barrel, has since then never risen above $60, falling as low as $30 per barrel in early 2016. As we write this Preface in the summer of 2017, it stands at around $48 per barrel, a price at which much of the production on the United Kingdom Continental Shelf (UKCS) is marginal at best. The impact upon the industry of the new economic reality can hardly be overstated. There has been an intense focus upon costcutting and rationalisation. Thousands of jobs have been lost, within both the service sector and the oil companies themselves. Projects and exploration have been postponed and contracts renegotiated. Companies have merged and insolvencies – previously as rare as hen’s teeth – have become prevalent. And the first great wave of decommissioning projects – long anticipated, but previously kept at bay by a combination of technological innovation and high oil price – is upon us. It is not yet wholly clear what all of these changes portend. Some would argue that they signal the advent of the industry’s twilight years. Others contend that – painful as they have been – the industry will emerge leaner, fitter and better placed to ensure that production continues for decades to come. Oil and gas law and practice has not emerged unchanged from this turmoil. Contracting practice and the fiscal system have both undergone significant change. The Wood Review, with its focus on maximising economic recovery of oil and gas from the UKCS, although commenced in a high-price environment became a central plank of the Government’s attempts to respond to the new low-price environment. And all the while, attempts have been made to launch an onshore unconventionals industry in the face of considerable public opposition and at a time of great constitutional uncertainty. Keeping up with this has been no small task. As a result, the third edition of this book is much changed from the second. It has increased in size to such an extent that it has had to be split into two volumes, the first focusing on issues of resource management and regulation and the second on commercial and contractual issues.

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As always, the editors have many people to thank. We are grateful to the authors of the new chapters, to the contributing authors who have had to make painstaking changes to their original work and to the new authors who have joined the writing team in order to update the work of original authors unable, due to pressure of time, to complete the updating task. We are grateful, too, to Sam Dunkley, Legal Counsel for Oil and Gas UK, for kindly providing us with a foreword, and to James Cowie, without whose outstanding editorial assistance the book would have been (even more) seriously delayed. Finally, we are particularly grateful to John Watson and Laura Williamson for commissioning this third edition, and to all at Edinburgh University Press involved in the editing, production and marketing process of the book for all of their diligence, professionalism, enthusiasm and encouragement. The law is stated as at April 2017. Greg Gordon John Paterson Emre Üșenmez July 2017

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TABLE OF CASES A Turtle Offshore SA v Superior Trading Inc [2008] EWHC 3034 (Admlty), [2008] 2 CLC 953.................................. II–6.05 ACF Chemiefarma NV v Commission (C-41/69) [1970] ECR 661........................................................................ II–11.12 Adam v Newbiggin (1888) 13 App Cas 308.......................... II–2.15 Advocate (Lord) v Scotsman Publications Ltd 1989 SC (HL) 122........................................................................ II–12.29 Advocate (Lord) v Wemyss [1896] 24 R 216, (1899) 2 F (HL) 1............................................................................ II–13.01 Ailsa Craig Fishing Co Ltd v Malvern Fishing Co Ltd [1983] 1 WLR 964.......................................................... II–6.43 Ainsworth v Inland Revenue Commissioners [2009] UKHL 31; (2009) 4 All ER 1205; [2009] ICR 985; [2009] IRLR 677....................................................................... II–14.71 Aird v Prime Meridian Ltd [2006] EWCA Civ 1866........... II–15.53 Akzo Chemie BV v Commission (C-62/86) [1991] ECR I-3359............................................................................ II–11.19 Aldred Mcalpine Capital Projects Ltd v Tilebox Ltd [2005] EWHC 288 (TCC)........................................................... II–2.67 Alliance Pipeline Ltd v Seibert [2003] 25 Alta LR (4th) 365................................................................................ II–13.14 Allonby v Accrington & Rossendale College [2004] ICR 1328.............................................................................. II–14.26 Allseas UK Ltd v Greenpeace 2001 SC 844......................... II–15.17 Almelo v Energiebefriff Ijsselmij (C-393/92) [1994] ECR I-1477............................................................................ II–11.11 Amoco Production Co v Wilson, 976 P 2d 941..................... II–2.43 Amoco (UK) Exploration Co v Amerada Hess Ltd [1994] 1 Lloyd’s Rep 330............................................................ II–3.39 Anchor Line (Henderson Brothers) Ltd (No 2), Re [1937] Ch 483........................................................................... II–10.69 Anderson v Brattisanni 1978 SLT (Notes) 42...................... II–13.03 Anderson v Stena Drilling Pte Ltd 2006 WL 2524780........ II–14.37, II–14.38, II–14.40, II–14.41 Arnold v Britton [2015] UKSC 36.............. II–1.01, II–1.08, II–2.80, II–6.34, II–6.36–7, II–6.41, II–6.44 Ashborder BV v Green Gas Power Ltd [2004] EWHC 1517 (Ch)............................................................................... II–10.83

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Aslam v Uber BV [2017] IRLR 4......................................... II–14.07 Assessor for Strathclyde Region v BP Refinery Grangemouth Ltd 1983 SC 18....................................... II–13.14 Atherton (HM Inspector of Taxes) v British Insulated and Helsby Cables Ltd [1925] KB 421, 10 TC 155 (CA)........ I–7.38 Attorney-General of Southern Nigeria v John Holt & Co Ltd [1915] AC 599 (PC (S Nigeria)).............................. II–13.22 Auquhirie Land Co Ltd v Scottish Hydro Electric Transmission plc, unreported, 10 August 2016.............. II–13.31 Autoclenz Ltd v Belcher [2011] ICR 1157............ II–14.07, II–14.08 Bahler v Shell Pipe Line Corp (1940, DC Mo) 34 F Supp 10.................................................................................. II–13.17 Bank of Nova Scotia v Société Générale (Canada) (1998) 87 AR 133, 58 Alta LR (2d) 193 (Alberta CA)................ II–2.43 Barber v RJB Mining (UK) Ltd [1999] 2 CMLR 833.......... II–14.72 Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730................ II–14.22, II–14.26, II–14.27 Bear Scotland Ltd v Fulton [2015] 1 CMLR 40; [2015] IRLR 15 EAT................................................................. II–14.64 Berdur Properties (Pty) Ltd v 76 Commercial Road (Pty) Ltd 1998 (4) SA 62 (D).................................................. II–13.23 Besser v Buckeye Pipe Line Co (1937) 57 Ohio App 341, 13 NE 2d 927................................................................ II–13.17 BHP Petroleum Ltd v British Steel plc and Dalmine SpA [2000] 2 Lloyd’s Rep 277................................... II–6.77, II–6.80 BICC plc v Burndy Corp [1985] Ch 232............................... II–2.64 Blantyre (Lord) v Waterworks Commissioners of Dumbarton (1886) 15 R (HL) 56.................................. II–13.23 Bleuse v MBT Transport Ltd [2008] ICR 488; [2008] IRLR 264................................................................................ II–14.43 Bombay Official Assignee v Shroff (1932) 48 TLR 443......... II–2.86 Borland’s Trustee v Steel Bros & Co Ltd [1901] 1 Ch 279.................................................................................. II–2.86 Boss Projects v Bragg 2013 WL 6536645............................ II–14.09 Botham v Ministry of Defence [2006] ICR 250.................. II–14.33, II–14.36, II–14.37 BP Exploration Operating Company Ltd v Dolphin Drilling Ltd [2009] EWHC 3319.............................................. II–5.22–4 Bristol and West Building Society v Mothew [1998] Ch 1..... II–2.40 British Eagle International Airline Ltd v Cie Nationale Air France [1975] 1 WLR 758............................................... II–2.87 British Gas Trading v Eastern Electricity plc [1996] EWCA Civ 1239.......................................................................... II–9.54

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British Sugar plc v NEI Power Projects Ltd (1997) 87 BLR 42.................................................................................... II–6.78 Brown v Rice, Patel and the ADR Group [2007] WL 763674.......................................................................... II–15.53 Brown v Voss 105 Wash 2d 366, 715 P 2d 514 (1986)............................................................................ II–13.23 Bruce v Dalrymple (1731) Elch Serv No 2; 5 Brown’s Supp 220................................................................................ II–13.22 Buchan v Cockburn (1739) Elch ‘Clause’ 2; M6528............ II–13.07 Buchan v Hunter, Unreported Property Cases p 311........... II–13.22 Burmah Oil Co (Burma Trading) Ltd v Lord Advocate 1964 SC (HL) 117......................................................... II–13.04 Byrne Bros (Formwork) Ltd v Baird [2002] ICR 667......... II–14.03, II–14.23, II–14.27 Cable and Wireless v IBM United Kindom Ltd [2002] 2 All ER (Comm) 1041........................................... II–15.34, II–15.36 Cable and Wireless v Muscat [2006] IRLR 354.................. II–14.13, II–14.14, II–14.15 Cairn Energy plc v Greenpeace Ltd [2013] CSOH 50.......... II–15.17 Caledonia North Sea Ltd v British Telecommunications plc 2002 SC (HL).................................................................. II–6.13 Caledonia North Sea Ltd v London Bridge Engineering Ltd 2000 SLT 1123; 2002 SC (HL) 117, [2002] 1 All ER (Comm)................II–1.08, II–6.09, II–6.13, II–6.18, II–6.19–20, II–6.24, II–6.28–9, II–6.34, II–6.38, II–6.41–2, II–6.45, II–6.50, II–6.77, II–6.79, II–6.80 Callan v McAvinue, unreported, Irish High Court, 11 May 1973.............................................................................. II–13.22 Campbell v Conoco (UK) Ltd [2003] 1 All ER (Comm) 35........................................................II–4.143, II–6.18, II–6.47 Campbell Discount Co Ltd v Bridge [1962] AC 600.............. II–2.62 Canada Steamship Lines Ltd v The King [1952] AC 192...... II–6.38, II–6.40, II–6.42–3 Canadian Western Natural Gas Co v Empire Trucking Parts (1985) Ltd [1998] 61 Alta LR (3rd).............................. II–13.17 Caparo Industries plc v Dickman [1990] 2 AC 605............. I–12.77, II–6.30 Capita Translation and Interpreting Ltd v Siacunas (Debarred), Ministry of Justice, Appeal No UKEAT/0181/16/RN; 2017 WL 00737371.................... II–14.28 Carlile v Douglas (1731) M 14524...................................... II–13.22 Carmichael v National Power plc [2000] IRLR 43 (HL).... II–14.07, II–14.08 Castellain v Preston [1883] 11 QBD 380............................... II–6.04

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Cavendish Square Holdings BV v El-Makdessi [2015] UKSC 67; [2015] 3 WLR 1373..............II–2.59, II–7.83, II–8.40 CD Robinson Steel v RD Retail Services Ltd [2006] IRLR 386................................................................................ II–14.64 Central RC v Ferns 1979 SC 136......................................... II–13.17 Chartbrook Ltd v Persimmons Homes Ltd [2009] UKHL 38; [2009] 1 AC 1101...................................................... II–6.36 Cheever v Jefferson Properties Ltd (1995)........................... II–13.03 Christie v Wemyss (1842) 5 D 242...................................... II–13.22 Clark v Craig, unreported, Stonehaven Sheriff Court, 12 February 1993............................................................... II–13.22 Clarke v Oxfordshire Health Authority [1998] IRLR 125................................................................................ II–14.08 Clydebank Engineering & Shipbuilding Co Ltd v Don Jose Ramos Yzquierdo y Castaneda [1905] AC 6......................................................................... II–2.61, II–2.74 Coco v A N Clark (Engineers) Ltd [1969] RPC 41.............. II–12.29 Cofts v Vetal Ltd [2006] ICR 250......................... II–14.33, II–14.37 Commissioner of Public Works v Hills [1906] AC 368..................................................................... II–2.59, II–2.74 Commune de Mesquer v Total France SA and Total International Ltd ECR 2008 I-04501............................I–11–105 Consafe Engineering (UK) Ltd v Emtunga UK Ltd [1999] RPC............................................................................... II–12.16 Consistent Group Ltd v Kalwak [2008] IRLR 505.............. II–14.07 Cooper v Strathclyde RC 1993 GWD 31-2013.................... II–13.11 Cornelis v Fernando (1962) 65 NLR 93.............................. II–13.07 Cornwall CC v Prater [2006] 2 All ER 1013....................... II–14.08 Cotswold Developments Construction Ltd v Williams [2006] IRLR 181........................................................... II–14.27 CRA v NZ Goldfields Investments [1989] VR 873 (Victoria Supreme Court)............................................................... II–2.64 Craigie v London Borough of Haringey [2006] UKEAT 0556/06/JOJ.................................................... II–14.14, II–14.15 Crehan v Inntrepreneur Pub Co [2007] 1 AC 333............... II–11.01 Crofts v Veta Ltd [2006] ICR 250....................... II–14.33, II–14.35, II–14.37, II–14.38, II–14.40, II–14.42, II–14.43 Dacas v Brook Street Bureau (UK) Ltd [2004] EWCA Civ 217; [2004] ICR 1437......II–14.11, II–14.12, II–14.14, II–14.15 Daks Simpson Group plc v Kuiper 1994 SLT 689............... II–15.53 Dalkia Utilities Services plc v Celtech International Ltd [2006] EWHC 63 (Comm).............................................. II–8.12 Deepak Fertilisers and Petrochemicals Corporation v ICI Chemicals & Polymers Ltd (1999) 1 TCLR 2000............ II–6.78

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Delimitation of the Continental Shelf (UK/France) (Arbitral Award of 30 June 1977)................................................... I–8.12 Dewhurst v Citysprint (UK) Ltd (Case No 2202512/16).................................................................. II–14.07 Dhuma v Creditsights Ltd UKEAT/02416/12....................... II–14.43 Director General of Telecommunications v Mercury Communications Ltd, CA, unreported........................... II–15.60 Dispute Concerning Delimitation of the Maritime Boundary in the Bay of Bengal (Bangladesh/Myanmar) (ITLOS Judgment) 51 (2012) ILM 840.............I–8.23–4, I–8.29 Dobie v Burns International Security Services (UK) Ltd 1984 ICR 812, CA......................................................... II–14.83 Dole Food Company Inc and Dole Fresh Fruit Europe v Commission (C-286/13P)............................................... II–11.61 Donoghue v Stevenson [1932] AC 562.................................. II–6.30 Duncombe v Secretary of State for Children, Schools and Families [2011] 4 All ER 1020...................................... II–14.39 Dunlop Pneumatic Tyre Co Ltd v New Garage & Motor Co Ltd [1915] AC 79................II–2.59, II–2.61, II–2.68, II–2.74 Dunnett v Railtrack plc [2002] 1 WLR 2434....................... II–15.43 Dyce v Hay (1852) 305........................................................ II–13.22 EC Gransden & Co Ltd v Secretary of State for the Environment [1987] 54 P & CR 361................................ I–9.78 ECC Quarries Ltd v Watkins (Inspector of Taxes) [1975] 3 All ER 843, (1977) 1 WLR 1386...................................... I–7.38 El-Makdessi v Cavendish Holdings BV [2015] UKSC 67; [2016] AC 1172; [2015] 3 WLR 1373; [2016] 2 All ER 519; [2016] 2 All ER (Comm) 1; [2016] 1 Lloyd’s Rep 55; [2015] 2 CLC 686; [2016] BLR 1; 162 Con LR 1; [2016] RTR 8; [2016] CILL 3769..................... II–1.04, II–2.63, II–2.69–74, II–2.76, II–2.79 El Paso Field Service Inc v Stephen Minvielle, 867 So 2d 120 (La App 3d Cir, 2004)............................................. II–13.17 Elf Enterprise Caledonia Ltd v Orbit Valve Co Europe [1995] 1 All ER 174..............II–1.08, II–4.144, II–6.11, II–6.27, II–6.34, II–6.38–42, II–6.45, II–6.47 Ellenborough Park, Re [1956] 1 Ch 131.............................. II–13.27 Emirates Trading Agency LLC v Prime Mineral Exports Private Ltd [2014] EWHC 2104 (Comm)...................... II–15.34 Enviroco v Farstadt [2009] EWCA Civ 1399......................... II–5.58 Erewhon Exploration Ltd v Northstar Energy Corp [1993] 147 AR 1, 15 Alta LR (3d) 200 9 (Alberta QB)............... II–2.43 Euro London Appointments v Claessens International [2006] EWCA Civ 385.................................................... II–8.41

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Express & Echo Publications Ltd v Tanton [1999] ICR 693................................................................. II–14.09, II–14.24 Exxon Corporation v Exxon Life Insurance Consultants International Ltd [2982] Ch 119................................... II–12.18 Exxon Pipeline Co v LeBlanc 763 So 2d 128 (La App 1 Cir 2000)............................................................................. II–13.09 Faccenda Chicken Ltd v Fowler [1986] 1 All ER 617................................................................. II–12.30, II–12.33 Farm Assist Ltd (in liquidation) v Secretary of State for the Environment, Food and Rural Affairs (No 2) [2009] EWHC 1102 (TCC)....................................................... II–15.53 Farstad Supply A/S v Enviroco Ltd [2010] UKSC 18, 2010 SCLR 379.................II–4.140, II–6.05, II–6.09, II–6.14, II–6.15, II–6.22, II–6.28, II–6.29, II–6.51, II–6.61 Farstad Supply A/S v Enviroco Ltd [2011] UKSC 16..................................................................... II–6.52, II–10.88 Ferguson v John Dawson & Partners (1976) 1 WLR 1213.............................................................................. II–14.07 Firma C-Trade SA v Newcastle Protection and Indemnity Association (The Fanti) (No 2) [1991] 2 AC 1 (HL).................................................................... II–6.03, II–6.05 Fisher v California Cake & Cookie Ltd [1997] IRLR 212................................................................................ II–14.87 Fontenot v Mesa Petroleum 791 F 2d 1207........................... II–6.18 Forder v Great Western Railway Co [1905] 2 KB 532..................................................................... II–2.28, II–2.30 Fourie v Marandellas Town Council 1972 Rhodesian Law Reports 164................................................................... II–13.22 Franks v Reuters Ltd [2003] EWCA 417............................. II–14.12 Fraser v Oystertec plc [2004] BCC 233................................. II–2.89 Friedman v Murray [1952] OWN 295, [1952] 3 DLR 159 (HC), affirmed [1953] OWN 486; [1953] 3 DLR 313 (CA)............................................................................... II–13.23 Gairlton v Stevenson (1677) M 12769................................. II–13.22 Gallagher v Alpha Catering Services Ltd (t/a Alpha Flight Services) [2005] ICR 673............................................... II–14.52 Gateshead MBC v Secretary of State for the Environment [1995] Env LR 37................................................. I–9.74, I–9.79 George Wimpey East Scotland Ltd v Fleming 2006 SLT (Lands Tr) 2................................................................... II–13.20 Gerald Metals SA v the Trustees of Timis Trust [2016] EWHC 2327.................................................................. II–15.65 Gibb v United Steel Companies Ltd [1957] 2 All ER 110.... II–14.06

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Gillespie Bros & Co Ltd v Roy Bowles Transport Ltd [1973] QB 4000............................................................... II–6.38 Glasgow Corporation v McEwan (1899) 2 F (HL) 25......... II–13.22 Glencore Energy UK Ltd v Cirrus Oil Services Ltd [2014] EWHC 87 (Comm).......................................................... II–6.78 Glen’s Trs v Lancashire and Yorkshire Accident Insurance Co Ltd (1906) 8 F 915.................................................... II–6.33 Goldacre (Offices) Ltd v Nortel UK Ltd [2009] EWHC 3389 (Ch).................................................................... II–10.102 Graham v Belfast and Northern Counties Railway Co [1901] 2 IR 13................................................................. II–2.28 Graham v Teesdale (1981) 81 LGR 117................................ II–2.29 Grange v Abellio London Ltd [2017] IRLR 108.................. II–14.52 Gray v Maxwell (1762) M 12800........................................ II–13.22 Groupement des cartes bancaires (CB) v Commission (C-67/713P)................................................................... II–11.61 Gulf Pipe Line Co v Kaderli (1927, Tex Civ App) 299 SW 534................................................................................ II–13.14 Gulf Pipe Line Co v Thomason(1927, Tex Civ App) 299 SW 532.......................................................................... II–13.14 Gunlegal Ltd, Re [2003] EWHC 1844 (Ch)........................... II–2.13 Hadley v Baxendale (1854) 9 Ex 341..........II–6.78, II–6.79, II–6.80 Halliburton Energy Services Inc v Smith International (North Sea) Ltd [2006] RPC 2....................................... II–12.16 Halsey v Milton Keynes General NHS Trust [2004] 1 WLR 3002.............................................................................. II–15.43 Hamilton-Gray v Sherwood, Sheriff Court, 27 August 2002.............................................................................. II–13.17 Hamlyn & Co v Talisker Distillery (1894) 21 R (HL) 21.... II–15.65 Harlow v O’Mahony, Appeal No UKEAT/0144/07/LA; 2007 WL 3001900........................................................ II–14.17 Hashami v OMV Maurice Energy Ltd [2015] WCA Civ 1171; [2015] 2 CLC 80................................................... II–2.19 Hashwami v Jivraj (London Court of International Arbitration intervening) [2011] ICR 1004..................... II–14.26 Hayns v Secretary of State for the Environment (1978) 36 P & CR 317.................................................................. II–13.30 Heatherwood and Wexham Park Hospitals NHS Trust v Kulubowila 2007 WL919521 (EAT).............................. II–14.15 Henderson v Merrett Syndicates Ltd [1995] 2 AC 145.......... II–2.41 Higginbotham v Holme (1812) 19 Ves 88............................. II–2.83 High Court in the Office of Fair Trading v Abbey National plc [2008] EWHC 875 (Comm) and Civ 116 [2010] 1 AC 696......................................................................... II–8.41

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HIH Casualty & General Insurance Ltd v Chase Manhattan Bank [2003] UKHL 6, [2003] 2 Lloyd’s Rep 297....................................................................... II–6.43–5 HJ Banks and Co Ltd v Shell Chemicals UK Ltd CA11/05 [2005] CSOH 123......................................................... II–13.04 Holland House Property Investments Ltd v Crabbe 2008 SLT 777......................................................................... II–15.60 Hollier v Rambler Motors (AMC) Ltd [1972] 2 QB 71......... II–6.43 Holloway v Chancery Mead [2008] 1 All ER (Comm) 653................................................................. II–15.34, II–15.36 Horobin’s case [1952] 2 Lloyd’s Rep 460.............................. II–2.30 Hospital Products Ltd v United States Surgical Corp (1984) 55 ALR 417..................................................................... II–2.39 Hotel Services Ltd v Hilton International Ltd [2000] 1 All ER (Comm) 750.............................................................. II–6.78 Huckvale v Aegean Hotels Ltd (1989) 58 P & CR 163....... II–13.27 Hurst v Leeming [2003] 1 Lloyd’s Rep 279......................... II–15.43 ICI v Commission (Dyestuffs) (C-48/69) [1972] ECR 619................................................................................ II–11.12 Industrial Gas Co v Jones (1939) 62 Ohio App 553, 24 NE 2d 830........................................................................... II–13.17 Investors Compensation Scheme Ltd v West Bromwich Building Society [1997] UKHL 28...................... II–6.33, II–6.36 Irvine Knitters Ltd v North Ayrshire Co-operative Society Ltd 1978 SC 109........................................................... II–13.23 Ithaca v NSE [2012] EWHC 1793 (QB)............... II–2.19, II–2.52–3 ITP SA v Coflexip Stena Offshore Ltd 2004 SLT 1285........ II–12.16 Jackson v Hughes Dowdall 2008 SC 637............................ II–15.75 James v Greenwich Council [2006] UKEAT 0006/06/1812.......................................................... II–14.14–16 James v Greenwich Council [2008] ICR 545....................... II–14.14 James v Redcats 2007 WL504779 (EAT); [2007] ICR 1006................................................II–14.24, II–14.28, II–14.30 James v Redcats (Brands) Ltd [2007] ICR 1006.................. II–14.09 Jay, Ex p; In re Harrison (1880) 14 Ch D 19........................ II–2.83, II–2.85, II–2.86 Jeffery v British Council [2016] IRLR 935........................... II–14.42 Jengle v Keetch (1992) 89 DLR (4th) 15............................. II–13.28 Jobson v Johnson [1989] 1 All ER 621 (CA); [1989] 1 WLR 1026 CA.......................................II–2.59, II–2.64, II–2.65 Jodrell, Re (1890) 44 Ch D 590............................................. II–6.33 Johnson, Thomas and Thomas (a Firm) v Smith 2016 GWD 25-456................................................................. II–13.22

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Jones v Tower Hamlets [2001] RPC 23............................... II–12.22 KCA Drilling Ltd v Robert S Breeds 2000 WL 824099 (EAT)........................................................ II–14.84, II–14.89–93 Kelly v Cooper [1993] AC 205.............................................. II–2.39 Kelly v Ohio Oil Co, 49 NE 399 (Ohio, 1897)...................... II–3.04 Kerr v Brown 1939 SC 140................................................. II–13.03 Knight v Fairway and Kenwood Car Service UKEAT/0075/12/LA...................................................... II–14.07 Labinski Ltd v BP Oil Development Ltd, 24 January 2003, IH, 18 December 2001, OH.......................................... II–13.14 Lackey v Joule, App, 577 SW 2d 114.................................. II–13.22 Landeshauptstadt Kiel v Norbert Jaeger [2003] ECR 1-8389.............................II–14.50, II–14.51, II–14.52, II–14.53, II–14.55, II–14.58, II–14.66, II–14.74, II–14.75, II–14.78, II–14.79, II–14.80 Lawson v Serco Ltd, Botham v Ministry of Defence and Crofts v Veta Ltd [2006] ICR 250................. II–14.33, II–14.35, II–14.36, II–14.37, II–14.39, II–14.40, II–14.42, II–14.43 Lean v Hunter 1050 SLT (Notes) 32.................................... II–13.25 Leisure (Norwich) (II) Ltd v Luminar Lava Ignite Ltd [2012] EWHC 951...................................................... II–10.102 Liscombe v Maughan (1928) 62 OLR 328, [1928] 3 DLR 397 (CA)........................................................................ II–13.23 Lloyd v McMahon [1987] AC 625........................................ II–2.29 Lock v British Gast Trading Ltd [2013] CJEU Case C-539/12........................................................................ II–14.64 Lock v British Gast Trading Ltd [2016] EWCA Civ 983; [2017] 1 CMLR 25........................................................ II–14.64 London & Blenheim Estates Ltd v Ladbroke Retail Parks Ltd [1993] 4 All ER 157................................................ II–13.25 Lundy Granite Co ex p Heavan (1870-71) LR 6 Ch App 462.............................................................................. II–10.104 Luscar Ltd v Pembina Resources Ltd (1995) 24 Alta LR (3d) 305, [1995] 2 WWR 153 (Alberta CA).................... II–2.43 Lyddon v Englefield Brickwork Ltd [2008] IRLR 198......... II–14.64 McCain Foods GB Ltd v Eco-Tec (Europe) Ltd [2011] EWHC 66 (TCC)............................................................. II–6.78 MacCartney v Oversley House Management [2006] ICR 510...................................II–14.52, II–14.75, II–14.77, II–14.80 McCosh v Brown & Co’s Trs (1889) 1 F (HL) 86................. II–2.15 MacDonald Estates plc v National Car Parks Ltd 2010 SC 250, 2010 SLT 36............................II–15.59, II–15.60, II–15.61

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Macepark (Wittlebury) Ltd v Sargeant [2003] 2 P & CR 12................................................................... II–13.23, II–13.24 MacFarlane v Glasgow City Council [2001] IRLR 7, EAT................................................................ II–14.09, II–14.24 McLellan v Hunter 1987 GWD 21-799............................... II–13.22 McMeechan v Secretary of State for Employment [1995] ICR 444................................................................... II–14.10–11 Madden v Coy [1994] VLR 88............................................ II–13.01 Mair v Wood 1948 SC 83...................................................... II–2.07 Manfredi v Lloyd Adriatico Assicurazioni (Joined Cases C-298/04 and 299/04) [2006] 5 CMLR 17.................. II–10.105 Mangold v Helm [2006] All ER (EC) 383........................... II–14.43 Maritime Delimitation and Territorial Questions (Qatar v Bahrain) [2002] 40 ICJ Rep 847....................................... I–8.02 Markerstudy Insurance Co Ltd v Endsleigh Insurance Services Ltd [2010] EWHC 281 (Comm)........................ II–6.78 Market Investigations v Minister for Social Security [1969] 2 QB 173....................................................................... II–14.06 Martha Envoy [1978] AC 1................................................... II–5.21 Midgulf International Ltd v Groupe Chimique Tunisien [2010] EWCA 66 (Civ).................................................. II–15.65 Millar’s Machinery Co v David Way & Son [1935] 40 Com Cas 204........................................................................... II–6.78 Moncrieff v Jamieson 2005 1 SC 281.................................. II–13.22 Money Markets International Stockbrokers Ltd (in liquidation) v London Stock Exchange [2002] 1 WLR 1150................................................................................ II–2.88 Montgomery v Johnson Underwood Ltd [2001] ICR 819..... II–14.11 Moody v Steggles (1879) 12 Ch 261.................................... II–13.07 Mosaic Oil NL v Angaari Pty Ltd [1990] 8 ACLC 780 (New South Wales Supreme Court)..................... II–2.64, II–2.91 Motours Ltd v Eurobell (West Kent) Ltd [2003] EWHC 614 (QB).......................................................................... II–6.77 Murray v Mags of Peebles, 8 Dec 1808, FC......................... II–13.28 National Grid Electricity Transmission plc v Wood, Appeal No ULEAT/0432/07/DM, 2007 WL 3002010............... II–14.17 National Semiconductors (UK) Ltd v UPS Ltd [1996] 2 LL Rep 212........................................................................... II–2.30 National Westminster Bank plc v Spectrum Plus Ltd [2005] UKHL 41....................................................................... II–10.83 Nelson v Atlantic Power and Gas Ltd 1995 SLT 102............ II–1.08, II–6.38, II–6.40, II–6.41 Neste Production Ltd v Shell UK Ltd [1994] 1 Lloyd’s Rep 447.................................................................................. II–3.39

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Nethermere (St Neots) Ltd v Taverna & Gardiner [1984] IRLR 240....................................................................... II–14.08 Newitt, Ex p; In re Garrud (1991) 16 Ch D 522................... II–2.86 Newport County Borough v Secretary of State for Wales and Browning and Ferris Environmentaal Services Ltd [1998] Env LR 174............................................... I–9.75, I–9.79 Nigel Witham Ltd v Smith (No 2) [2008] EWHC 12 (TCC)............................................................................ II–15.43 Norscot Rig Management PVT Ltd v Essar Oilfields Services [2010] EWHC 195 (Comm)............................. II–15.69 North British Railway v Park Yard Co Ltd (1898) 25 R (HL) 47.......................................................................... II–13.25 North Sea Continental Shelf Cases (Germany v Denmark; Germany v Netherlands) [1969] ICJ Rep 3..................... I–8.07, I–8.11–12, I–8.34, I–8.35, II–3.05 Nutting v Baldwin [1995] 1 WLR...................................... II–2.76–9 Oceanbulk Shipping and Trading SA v TMT Asia Ltd (aka TMT Asia Ltd v Oceanbulk Shipping and Trading SA) [2010] UKSC 44............................................................ II–15.53 Olympia and York Canary Wharf Ltd, Re [1993] BCC 154................................................................................ II–10.99 Parker Hannifin Manufacturing and Parker-Hannifin v Commission (Case T-146/09 RENV)............................. II–11.03 Peacock v Custins [2001] 2 All ER 827, [2001] 13 EG 152, CA................................................................................. II–13.23 Penney’s Trade Mark, Re [1978] OJ L60/19........................ II–11.12 Perpetual Trustee Co Ltd v BNY Corporate Trustee Services Ltd and Lehman Brothers Special Financing Inc and Butters v BBC Worldwide Ltd [2009] EWCA Civ 1160; [2010] 3 WLR 87; [2010] Bus LR 632; [2010] BCC 59............................................................... II–2.90, II–2.91 Petrofac Offshore Management Ltd v Olley 2005 WL3142404 (EAT)....... II–14.84–8, II–14.89, II–14.92, II–14.93 Philips v Attorney-General of Hong Kong [1993] 61 BLR 41.................................................................................... II–2.66 Phillips v First Secretary of State [2004] JPL 613.................... I–9.80 Photo Production Ltd v Securicor Transport Ltd [1980] AC 827.................................................................................. II–6.77 Pickard v Somers (1932) 48 Sh Ct Rep 237......................... II–13.22 Pillar Denton Ltd v Jervis [2014] EWCA Civ 180......................................................... II–10.102–3, II–10.105 Pimlico Plumbers Ltd v Smith [2017] EWCA Civ 51................................................................... II–14.09, II–14.27

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Pine Energy Consultants Ltd v Talisman Energy (UK) Ltd [2008] CSOH 10........................................................... II–12.29 Polkey v AE Dayton Services Ltd [1987] IRLR 503............. II–14.87 Polypearl Ltd v E.On Energy Solutions Ltd [2014] EWHC 3045 (QB)........................................................................ II–6.78 Porter v Magill [2001] UKHL 67; [2002] 2 AC 357 (HL).................................................................... II–2.29, II–2.31 Prenn v Simmonds [1971] 1 WLR 1381................................ II–6.36 Printers & Finishers Ltd v Holloway [1965] 1 WLR 1........ II–12.30 Proton Energy Group SA v Orlen Lietuva [2013] EWHC 2782................................................................................ II–8.07 Quashie v Stringfellow Restaurants Ltd [2012] EWCA Civ 1735; [2013] IRLR 99................................................... II–14.28 R v A-G for Northern Ireland ex p Burns [1999] IRLR 315................................................................................ II–14.56 R v Kite and OLL Ltd [1994] (unreported).......................... I–10.78 R v Secretary of State for Trade and Industry, ex parte Greenpeace Ltd (No 2) [2001] Env L R 221..................... I–4.25 R (ex p Cowl) v Plymouth City Council [2002] 1 WLR 903................................................................................ II–15.43 R (on the application of Copeland) v Tower Hamlets LBC [2010] LLR 654................................................................ I–9.66 R (on the application of Hottak) v Secretary of State for Foreign and Commonwealth Affairs [2016] 1 WLR 3791.............................................................................. II–14.43 Rainy Sky v Kookmin Bank [2011] UKSC............................. II–2.80 Rattray v Tayport Patent Slip Co (1868) 5 SLR 219............ II–13.22 Ravat v Halliburton Manufacturing & Services Ltd 2012 SC (UKSC) 265......................................... II–14.39–40, II–14.42 Ready Mixed Concrete (South East) Ltd v Minister of Pensions and National Insurance [1968] 2 QB 497..................................................II–14.06, II–14.08, II–14.11 Reardon Smith Line Ltd v Hansen-Tangen [1976] 1 WLR 989.................................................................................. II–6.36 Reed Executive plc v Reed Business Information Ltd [2004] 1 WLR 3026.................................................................. II–15.53 Regia Autonoma de Electricitate Renel v Gulf Petroleum International Ltd [1996] 1 Lloyd’s Rep 67.................... II–15.72 Robb v Salamis M & I Ltd 2007 SLT 158............................. II–6.46 Rochon v Charron, 2 May 2002, Cour du Québec, QCCQ 705-22-003035-001....................................................... II–13.22 Rule v Hazlehaw Properties Ltd and Scottish Power UK plc [2017] SC GLA 1........................................................... II–13.11

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Russell v Transocean International Resources Ltd [2011] UKSC 57; 2012 SC (UKSC) 250......II–14.51, II–14.62, II–14.80 Safeway Food Stores Ltd v Wellington Motor Co (Ayr) Ltd 1976 SLT 53.................................................................. II–13.24 Safeway Ltd v Twigger [2010] EWCA Civ 1472.................. II–11.02 Saga Cruises BDF Ltd v Fincantieri SPA [2016] EWHC 1875 (Comm).................................................................. II–6.79 Saint Line v Richardsons (1940) 2 KB 99.............................. II–6.78 Saltman Engineering Co Ltd v Campbell Engineering Co Ltd [1948] 65 RPC 203................................................. II–12.29 Salvin’s Indenture, Re [1938] 2 All ER 498.......................... II–13.24 Scandinavian Trading Tanker Co AB v Flota Petrolea Ecuatorina (The Scapade) [1983] QB 529....................... II–2.64 Scott v Bogle, 6 July 1809, FC............................................. II–13.23 Scottish Ambulance Service v Truslove UKEATS/0028/11/ BI; 2012 WL 2800455................................................... II–14.52 Scottish Highland Distillery Co v Reid (1877) 4 R 1118..... II–13.22 Scottish & Newcastle plc v G D Construction (St Albans) Ltd [2003] EWCA Civ 16................................................ II–6.04 Scottish Oil Company Ltd (in liquidation), Re The (2013) CSIH 108..................................................................... II–10.114 Scottish Power UK plc v BP Exploration and Drilling [2015] EWHC 2658........................................................ II–6.79 Scotto v Petch [2001] BCC 899............................................. II–2.13 Shell UK Ltd v Enterprise Oil plc [1999] 2 Lloyd’s Rep 456.................................................................................. II–3.39 Shetlands Islands Council v BP Petroleum Development Ltd 1990 SLT 82.................................................................. II–13.12 Shiloph Spinners Ltd v Harding [1973] AC 671.................... II–2.63 SHV Gas Supply & Trading SAS v Naftomar Shipping & Trading Co Ltd [2006] 1 LLR 163.................................. II–8.17 Sindicato de Medicos de Assitencia Publica (SIMAP) v Conselleria de Sanidad y Consumo de la Generalidad Valenciana [2000] ECR 1-7963..................... II–14.54, II–14.73, II–14.78, II–14.79, II–14.80 Skull v Glenister (1864) 16 CB (NS) 81............................... II–13.23 Slessor v Vetco Gray, unreported, 7 July 2006, Court of Session, Outer House...............II–6.07, II–6.18, II–6.27, II–6.34, II–6.45, II–6.48–9, II–6.72 Smith v Carillon, Case No A2/2014/0395/EATRF, [2015] EWCA Civ 209; [2015] IRLR 467................................. II–14.17 Smith v South Wales Switchgear Co Ltd [1978] 1 WLR 165..................................................................... II–6.43, II–6.47 Smith v UMB Chrysler (Scotland) Ltd 1978 SC (HL) 1......... II–6.38

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Société de Vente de Ciments et Bétons de l’Est SA v Kerpen & Kerpen GmbH und Ko KG (C-319/82) [1983] ECR 4173.............................................................................. II–11.13 Soufflet Negoce SA (2009) EWHC 2454 (Comm); [2010] 1 Lloyd’s Rep 718; Affd [2010] EWCA Civ 1102; [2011] 1 Lloyd I Rep 531............................................................ II–8.12 South China Sea Arbitration (Phillippines v China) (award of 12 July 2016)............................................................... I–8.33 South Lanarkshire Council v Taylor 2005 1 SC 182............ II–13.12 Southern Star Central Gas Pipeline Inc v Murray 190 SW 3d 423 Mo App SD, 2006.............................................. II–13.17 Sovmots Investments Ltd v Secretary of State for the Environment [1979] AC 144.......................................... II–13.03 Sport International Bussum BV v Inter-Footwear Ltd [1984] 1 WLR 776.......................................................... II–2.64 Spree Engineering & Testing Ltd v O’Rourke Civil & Structural Engineering Ltd, Unreported, 1999 WL 33453546, QBD.......................II–2.17, II–2.18, II–2.19, II–2.22 Star Energy Weald Basin Ltd v Bocardo SA [2010] UKSC 35, [2010] 3 WLR 654..................................................... I–4.08 Starsin case [2003] UKHL 12; [2004] 1 AC 715.................... II–6.36 Stewart v Stewart (1788) Hume 731.................................... II–13.28 Stringer v Minister of Health for Housing and Local Government [1970] WLR 1281........................................ I–9.59 Sul America Cia Nacional de Seguros SA v Enesa Engenhara SA [2001] EWCA Civ 638............ II–15.34, II–15.36 Sweeney v Lagan Developments [2007] NICA 11................. II–2.02, II–2.18, II–2.19, II–2.22 TCS Holdings Ltd v Ashtead Plant Hire Co Ltd 2003 SLT 177................................................................................ II–13.12 Tesco Stores v Secretary of State for Environment [1995] 1 WLR 759.......................................................................... I–9.69 Texas Eastern v EE Caledonia, CA, 1989............................... II–9.52 Texas Eastern v Enterprise Oil plc, CA, 21 July 1989 (unreported)..................................................................... II–2.13 Thames Valley Power Ltd v Total Gas & Power Ltd [2006] Lloyd’s Rep 441................II–15.14, II–15.31, II–15.58, II–15.61 Thompson v T Lohan (Plant Hire) Ltd [1987] 1 WLR 649.................................................................................. II–6.29 TNT Global SPA v Denfleet International Ltd [2007] EWCA Civ 405; [2008] 1 All ER (Comm) 97; [2007] 2 Lloyd’s Rep 504.................................................. II–2.30, II–2.31 Todd v Adams [2002] 2 All ER (Comm)................................ II–2.21 Todd v Scoular 1988 GWD 24-1041................................... II–13.22

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Todrick v Western National Omnibus Co [1934] Ch 561................................................................................ II–13.07 Transco plc v HMA 2004 SLT 41......................................... I–10.78 Transocean Drilling UK Ltd v Providence Resources plc [2016] EWCA Civ 372.................................................... II–6.79 Transocean International Resources Ltd v Russell, Case no S/104056/04................................................................... II–14.45 Trevett v Secretary of State for Transport, Local Government and the Regions [2002] EWHC 2696 (Admin)............................................................................ I–9.81 Truslove v Scottish Ambulance Service [2014] ICR 1232................................................II–14.76, II–14.77, II–14.80 Veba Oil Supply and Trading GmbH v Petrograde Inc [2001] 2 Lloyd’s Rep 731............................... II–15.58, II–15.61 Venture North Sea Gas Ltd v Nuon Exploration & Production UK Ltd [2010] EWHC 204........................... II–2.19 Voice v Bell [1993] EGCS 128, (1993) 68 P & CR 441....... II–13.25 Walker v Crystal Palace Football Club Ltd [1910] 1 KB 87, CA................................................................................. II–14.06 Watteau v Fenwick [1893] 1 QB 346..................................... II–2.38 Weiner v Harris [1910] 1 KB 285.......................................... II–2.16 Wessanen Foods Ltd v Jofson Ltd [2006] EWHC 1325 (TCC).............................................................................. II–6.77 West Midlands Probation Committee v Secretary for the Environment [1998] 76 P & CR 589................................ I–9.72 WesternGreco Ltd v ATP Oil and Gas (UK) Ltd [2006] EWHC 1164 (Comm)...................................................... II–6.84 Westminster City Council v Great Portland Estates plc [1985] AC 661.................................................................. I–9.63 White & Carter (Councils) Ltd v McGregor [1962] AC 413.................................................................................. II–8.41 Whitmore v Mason (1861) 2 J & H 204........................... II–2.83–4 William Tracey Ltd v Scottish Ministers 2016 SLT 1049..... II–13.31 Williams’ Trs v Macandrew and Jenkins 1960 SLT 246....... II–13.22 Windle v Secretary of State for Justice [2016] EWCA Civ 459; [2016] ICR 721.......................II–14.22, II–14.27, II–14.28 Wittenberg v Sunset Personnel Services Ltd UKEAT/0019/13............................................................ II–14.43 Wong Kwok-chiang v Longo Construction Ltd (1987) Hong Kong Law Reports 345........................................ II–13.22 Wood Group Engineering (North Sea) Ltd v Robertson, Appeal No UKEATS/0081/06/MT, 2007 WL 2186972........................................................................ II–14.17

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Wood v Capita Insurance Services Ltd [2017] UKSC 24..................................................................... II–2.80, II–4.141 Wright v Logan (1829) 8 s 247............................................ II–13.22 Yewens v Noakes 6 (1880) QBD 530.................................. II–14.06

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TABLE OF STATUTES 1890 Partnership Act .......................................................... II–2.20 s 1������������������������������������������������������������������������������ II–2.20 s 2������������������������������������������������������������������������������ II–2.20 (1)������������������������������������������������������������������������� II–2.20 (2)������������������������������������������������������������������������� II–2.20 (3)������������������������������������������������������������ II–2.20, II–2.21 ss 5–18���������������������������������������������������������������������� II–2.22 s 19���������������������������������������������������������������������������� II–2.22 1891 Stamp Act s 55���������������������������������������������������������������������������� II–9.86 1906 Marine Insurance Act s 1������������������������������������������������������������������������������ II–6.04 s 55(2)����������������������������������������������������������������������� II–2.29 1909 Housing & Town Planning Act����������������������������������� I–9.29 1918 Petroleum (Production) Act���������������������������������������� I–4.07 s 1(1)�������������������������������������������������������������������������� I–4.07 Representation of the People Act�������������������������������� I–5.05 1925 Law of Property Act s 52(1)��������������������������������������������������������������������� II–10.89 s 205(1)(ii)��������������������������������������������������������������� II–10.89 s 205(1)(ix)�������������������������������������������������������������� II–10.89 1928 Drainage of Land Act (Australia)����������������������������� II–13.01 1934 Petroleum (Production) Act����������������������������������������I–4.08, I–4.10, I–4.36, I–5.05, I–10.05 s 1������������������������������������������������������������������������������� I–4.09 (1)������������������������������������������������������������� I–4.08, II–3.10 s 2������������������������������������������������������������������������������� I–4.09 s 3������������������������������������������������������������������������������� I–4.09 s 4������������������������������������������������������������������������������� I–4.09 s 6������������������������������������������������������������������������������� I–4.09 Sch 2, Cl18��������������������������������������������������������������� I–11.06 1938 Coal Act s 3������������������������������������������������������������������������������� I–4.01 1940 Law Reform (Miscellaneous Provisions) (Scotland) Act s 3������������������������������������������������������������������������������� II.6.50 1946 Atomic Energy Act s 6������������������������������������������������������������������������������� I–4.01 s 7������������������������������������������������������������������������������� I–4.01

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National Health Act��������������������������������������������������� I–5.05 1947 Town and Country Planning Act�������������������������������� I–9.31 1949 Coast Protection Act������������������I–11.72, I–11.74–8, I–12.58 s 34������������������������������������������������������������� I–11.72, I–11.74 (1)(a)�������������������������������������������������������������������� I–11.74 (1)(b)�������������������������������������������������������������������� I–11.74 (1)(c)�������������������������������������������������������������������� I–11.74 (2)������������������������������������������������������������������������ I–11.75 (3)������������������������������������������������������������������������ I–11.76 s 36 (1)��������������������������������������������������������������������� I–11.76 s 36A������������������������������������������������������������������������ I–11.75 1959 Coastal Protection Act���������������������������������������������� I–11.72 1960 Occupiers’ Liability (Scotland) Act�������������������������� II–13.11 1961 Companies (Floating Charges) (Scotland) Act���������� II–10.69 1964 Continental Shelf Act����������I–1.16, I–4.10, I–10.03, I–10.04, I–10.13, I–11.84 s1 (1)�������������������������������������������������������������������������� I–4.09 (2)�������������������������������������������������������������������������� I–4.09 (3)�������������������������������������������������������������� I–4.09, I–5.05 (7)������������������������������������������������������������������������ I–11.79 s 3����������������������������������������������������������������������������� I–10.04 s 4(1)���������������������������������������������������������� I–11.72, I–11.74 1965 Gas Act�������������������������������������������������������������������� II–13.09 s 4������������������������������������������������������������� II–13.02, II–13.31 s 5������������������������������������������������������������� II–13.02, II–13.31 s 12��������������������������������������������II–13.02, II–13.09, II–13.31 s 13��������������������������������������������II–13.02, II–13.09, II–13.31 War Damage Act����������������������������������������������������� II–13.05 1969 Employers’ Liability (Compulsory Insurance) Act�����I–10.42, II–2.36 1970 Conveyancing and Feudal Reform (Scotland) Act Pt II�������������������������������������������������������������������������� II–10.89 1971 Mineral Workings (Offshore Installations) Act�����������I–1.16, I–10.03, I–10.12–17, I–10.18, I–10.19, I–10.20, I–10.22, I–10.24, I–10.37, I–10.40, I–12.55 1972 Island of Rockall Act�������������������������������������������������� I–8.13 1973 Prescription and Limitation (Scotland) Act s 3(2)����������������������������������������������������������������������� II–13.07 Seas and Submerged Lands Act (Australia) s 10A�������������������������������������������������������������������������� I–4.09 1974 Consumer Credit Act s 21����������������������������������������������������������������������������� I–4.04 Health and Safety at Work Act���������I–1.16, I–9.15, I–10.03, I–10.18–30, I–10.22, I–10.86, II–14.70

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s 2��������������������������������������������������������������� I–10.22, I–10.85 s 33��������������������������������������������������������������������������� I–10.85 (1)������������������������������������������������������������������������ I–10.85 s 37��������������������������������������������������������������������������� I–10.87 Sch 3A���������������������������������������������������������������������� I–10.85 1975 Employment Protection Act�������������������������������������� I–10.27 Offshore Petroleum Development (Scotland) Act��������������������������������������������������������������������������� II–13.09 Oil Taxation Act��������������������������������������������������������� I–5.05 Pt I������������������������������������������������������������������������������ I–5.05 s 1 (2)������������������������������������������������������������������������� I–7.09 s 3(1)(i)(hh)–(j)��������������������������������������������������������� I–13.03 s 13����������������������������������������������������������������������������� I–7.02 Petroleum and Submarine Pipe-lines Act�������I–5.05, I–10.17, I–10.40, I–A.7, I–A.20, I–A.29 s 17����������������������������������������������������������������������������� I–5.05 s 18����������������������������������������������������������������� I–4.17, I–4.51 Sch 2, Pt II, Model Cl 11.............................................. I-4.02 Sch 4��������������������������������������������������������������������������� I–5.05 1976 Energy Act������������������������������������������������������ I–3.34, I–3.67 s 6������������������������������������������������������������������������������� I–3.34 (6)�������������������������������������������������������������������������� I–3.34 Restrictive Trade Practices Act��������������������������������� II–11.39 1977 Patents Act Pt II�������������������������������������������������������������������������� II–12.15 s1 (1)(a)������������������������������������������������������������������� II–12.13 (1)(b)������������������������������������������������������������������� II–12.13 (1)(c)������������������������������������������������������������������� II–12.13 (1)(d)������������������������������������������������������������������� II–12.13 s 3���������������������������������������������������������������������������� II–12.13 s 25(1)��������������������������������������������������������������������� II–12.12 s 30 (2)����������������������������������������������������������������������� II–12.14 (4)����������������������������������������������������������������������� II–12.14 s 31 (3)����������������������������������������������������������������������� II–12.14 (4)����������������������������������������������������������������������� II–12.14 s 39(1)(b)����������������������������������������������������������������� II–12.36 s 40�������������������������������������������������������������������������� II–12.37 s 60�������������������������������������������������������������������������� II–12.12 Unfair Contract Terms Act�������������� II–2.38, II–6.05, II–6.77, II–6.83, II–6.84 s2 (1)������������������������������������������������������������ II–6.28, II–6.29

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(2)������������������������������������������������������������������������� II–6.29 (4)������������������������������������������������������������ II–6.05, II–6.28 s 3������������������������������������������������������������������������������ II–6.29 s 4������������������������������������������������������������������������������ II–6.28 s 12���������������������������������������������������������������������������� II–6.28 s 16(1)(a)������������������������������������������������������������������� II–6.28 s 16(1)(b)������������������������������������������������������������������� II–6.29 s 17���������������������������������������������������������������������������� II–6.29 s 18���������������������������������������������������������������������������� II–6.28 s 26 (3)������������������������������������������������������������������������� II–8.02 (4)������������������������������������������������������������������������� II–8.02 1979 Sale of Goods Act������������������������������������������������������ II–8.02 s8 (1)������������������������������������������������������������������������� II–8.18 (2)������������������������������������������������������������ II–8.18, II–8.42 s 12��������������������������������������������������������������� II–8.12, II–8.30 s 13 (1)��������������������������������������������������������� II–8.08, II–8.51 s 14 (2)������������������������������������������������������������ II–8.08, II–8.51 (2B)���������������������������������������������������������� II–8.09, II–8.51 s 15(2)���������������������������������������������������������� II–8.08, II–8.51 s 15A������������������������������������������������������������������������� II–8.08 s 16���������������������������������������������������������������������������� II–8.30 s 27���������������������������������������������������������������������������� II–8.17 s 61(1)����������������������������������������������������������������������� II–8.02 1982 Civil Jurisdiction and Judgments Act����������������������� II–14.38 Local Government Finance Act s 20���������������������������������������������������������������������������� II–2.29 (1)������������������������������������������������������������������������� II–2.29 1983 Finance Act s 36(2)������������������������������������������������������������������������ I–7.27 Petroleum Royalties (Relief) Act s 1������������������������������������������������������������������������������� I–7.27 (2)(a)���������������������������������������������������������������������� I–7.27 1984 Control of Industrial Major Accident Hazard (CIMAH) Regulations (SI 1984/1902)�������������������������������������� I–10.38 National Fishing Enhancement Act (PL 98-623) (USA) Title II����������������������������������������������������������������������� I–12.10 Occupiers’ Liability Act������������������������������������������� II–13.11 Telecommunications Act Sch 2 paras 2–6�������������������������������������������������������� II.13.31 1985 Companies Act s 736�������������������������������������������������������������������������� II–9.50 Environment Protection Act�������������������������������������� I–12.58

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Food and Environment Protection Act��������I–11.37, I–11.44, I–11.49, I–11.72, I–12.22, I–12.58 s 5��������������������������������������������������������������� I–11.49, I–11.72 (a)������������������������������������������������������������������������� I–11.37 (b)������������������������������������������������������������������������ I–11.37 s 7����������������������������������������������������������������������������� I–11.72 s8 (3)������������������������������������������������������������������������ I–11.49 (10)���������������������������������������������������������������������� I–11.49 s9 (11)(a)������������������������������������������������������������������ I–11.49 (11)(b)������������������������������������������������������������������ I–11.49 s 11��������������������������������������������������������������������������� I–11.49 (b)������������������������������������������������������������������������ I–11.49 s 21 (2A)(a)������������������������������������������������������������������ I–11.49 (2A)(b)����������������������������������������������������������������� I–11.49 (6)������������������������������������������������������������������������ I–11.49 1986 Company Directors Disqualification Act s 9(A–E)������������������������������������������������������������������� II–11.02 Gas Act�������������������������������������������������������������������� II–13.09 Sch 4������������������������������������������������������������������������ II–13.01 Insolvency Act s 1(3)(a)����������������������������������������������������������������� II–10.119 s 72A����������������������������������������������������������������������� II–10.95 s 72B–H������������������������������������������������������������������� II–10.95 s 72E�������������������������������������������������������� II–10.24, II–10.95 s 178����������������������������������������������������� II–10.112, II–10.114 s 214���������������������������������������������������������������������� II–10.116 Sch 2A��������������������������������������������������������������������� II–10.95 Sch B1 para 3(1)������������������������������������������������������������� II–10.97 para 22�������������������������������������������������������������� II–10.116 paras 42–44�������������������������������������������������������� II–10.98 para 64�������������������������������������������������������������� II–10.108 para 71�������������������������������������������������������������� II–10.117 para 83�������������������������������������������������������������� II–10.110 para 99(3)��������������������������������������������������������� II–10.100 1987 Petroleum Act���������������� I–12.22, I–12.36, I–12.41, II–13.09 s 21��������������������������������������������������������������������������� I–12.78 s 22��������������������������������������������������������������������������� I–12.78 s 23��������������������������������������������������������������������������� I–12.78 s 27�������������������������������������������������������������������������� II–13.09 Territorial Sea Act s 1���������������������������������������������������������������������������� II–13.01

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(1)(b)�������������������������������������������������������������������� I–9.125 1988 Copyright, Designs and Patents Act Ch 6��������������������������������������������������������������������������� I–4.04 s 1(1)����������������������������������������������������������������������� II–12.18 s3 (1)����������������������������������������������������������������������� II–12.17 (1)(b)������������������������������������������������������������������� II–12.23 (2)����������������������������������������������������������������������� II–12.17 s 4���������������������������������������������������������������������������� II–12.17 s 11(2)��������������������������������������������������������������������� II–12.34 s 17(1)��������������������������������������������������������������������� II–12.19 s 18�������������������������������������������������������������������������� II–12.19 s 18A����������������������������������������������������������������������� II–12.19 s 50A����������������������������������������������������������������������� II–12.24 s 90(3)��������������������������������������������������������������������� II–12.35 s 215(3)������������������������������������������������������������������� II–12.34 s 217(2)������������������������������������������������������������������� II–12.24 Court of Session Act s 27�������������������������������������������������������������������������� II–15.76 Income and Corporation Taxes Act s 416 (2)������������������������������������������������������������������������� II–9.34 (4)������������������������������������������������������������������������� II–9.34 (6)������������������������������������������������������������������������� II–9.34 Sch 19B, para 4���������������������������������������������������������� I–7.31 Road Traffic Act s 87����������������������������������������������������������������������������� I–4.04 1989 Companies Act s 144�������������������������������������������������������������������������� II–9.50 Electricity Act Sch 4 para 6(6)(a)��������������������������������������������������������� II–13.31 para 6(6)(b)��������������������������������������������������������� II–13.31 1990 Environment Protection Act�������������������������������������� I–12.58 Law Reform Miscellaneous Provisions (Scotland) Act s 66�������������������������������������������������������������������������� II–15.66 Sch 7������������������������������������������������������������������������ II–15.66 Town and Country Planning Act�������������������������������� I–9.33 s 55����������������������������������������������������������������������������� I–9.38 s 57����������������������������������������������������������������������������� I–9.37 s 70����������������������������������������������������������������������������� I–9.49 (1)(a)���������������������������������������������������������������������� I–9.44 (2)�������������������������������������������������������������������������� I–9.57 1992 Offshore Safety Act���������������������������I–1.16, I–9.16, I–10.03, I–10.40–7

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Taxation of Chargeble Gains Act s 8������������������������������������������������������������������������������ II–9.18 Trade Union and Labour Relations (Consolidation) Act������������������������������������������������������������ II–14.19, II–14.31 1993 Finance Act s 185��������������������������������������������������������������������������� I–7.09 Radioactive Substances Act��������������������������������������� I–12.58 1994 Coal Industry Act s 1(1)(a)���������������������������������������������������������������������� I–4.01 1995 Gas Act�������������������������������������������������������������������� II–13.09 s 12����������������������������������������������������������������������������� I–6.25 s 19�������������������������������������������������������������������������� II–13.28 Merchant Shipping Act��������������������������������������������� I–11.82 s 128(1)�������������������������������������������������������������������� I–11.51 s 277������������������������������������������������������������������������� I–11.84 s 293(2)(za)��������������������������������������������������������������� I–10.71 1996 Arbitration Act�������������������������������������������������������� II–15.66 s 1���������������������������������������������������������������������������� II–15.65 s 5���������������������������������������������������������������������������� II–15.65 Employment Rights Act������������������������������������������� II–14.31 Pt IVA������������������������������������������������������� II–14.19, II–14.20 ss 13–23������������������������������������������������������������������ II–14.71 s 94 (1)�����������������������II–14.33, II–14.34, II.14.36, II–14.37, II–14.38, II–14.39 s 98(4)���������������������������������������������������������������������� II.14.90 s 108 (1)������������������������������������������������������������������ II–14.02 s 155������������������������������������������������������������������������ II–14.02 s 196��������������������������������������������������������� II–14.34, II–14.35 s 201��������������������������������������������������������� II–14.30, II–14.37 s 230������������������������������������������II–14.22, II–14.26, II–14.46 (1)����������������������������������������������������������������������� II–14.05 (2)����������������������������������������������������������������������� II–14.05 (3)����������������������������������������������������������������������� II–14.20 (3)(b)������������������������������������������������������������������� II–14.26 Employment Tribunals Act s 7(3AA)������������������������������������������������������������������ II–15.47 Housing Grants, Construction and Regeneration Act����������������������������������������������������������������������������� II–5.19 Pt II�������������������������������������������������������������������������� II–15.62 s 105������������������������������������������������������������������������ II–15.62 (2)����������������������������������������������������������������������� II–15.63 (2)(a)������������������������������������������������������������������� II–15.63 (2)(c)������������������������������������������������������������������� II–15.63 (3)����������������������������������������������������������������������� II–15.63 (4)����������������������������������������������������������������������� II–15.63

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uk o i l a nd gas l aw vo l u m e i i Scotland Act����������������������I–4.13, I–9.112, I–9.113, I–12.82 s 2����������������������������������������������������������������������������� I–9.113 s 29(2)(b)������������������������������������������������������������������ I–9.113 Sch 5 Pt II Head D���������������������������������������������������� I–9.117 Sch 5 Pt II Head D1�������������������������������������������������� I–9.117 Sch 5 Pt II Head D2�������������������������������������������������� I–9.117 Sch 5 Pt II Head D4�������������������������������������������������� I–9.117 Contracts (Rights of Third Parties) Act����� I–13.27, II–4.140, II–6.31, II–6.66 Employment Relations Act s 10����������������������������������������������������������� II–14.19, II–14.20 Pollution Prevention and Control Act����������������������� I–11.60 s 3����������������������������������������������������������������������������� I–11.90 Abolition of Feudal Tenure (Scotland) Act s 1������������������������������������������������������������������������������� I–9.08 s 67�������������������������������������������������������������������������� II–13.12 Financial Services and Markets Act s 19(1)����������������������������������������������������������������������� II–9.22 Utilities Act Pt V������������������������������������������������������������������������� II–13.09 Capital Allowances Act����������������������������������������������� I–7.30 Pt 2����������������������������������������������������������������������������� I–7.30 Pt 5����������������������������������������������������������������������������� I–7.30 Pt 6����������������������������������������������������������������������������� I–7.30 s 4������������������������������������������������������������������������������� I–7.38 s 56(2)������������������������������������������������������������������������ I–7.29 ss 162–165��������������������������������������������������� I–7.30, I–13.03 s 163��������������������������������������������������������������������������� I–7.46 Enterprise Act������������������������������������������� II–10.95, II–11.01 s 188������������������������������������������������������������������������ II–11.02 s 189������������������������������������������������������������������������ II–11.02 Communications Act s 363��������������������������������������������������������������������������� I–4.04 Land Reform (Scotland) Act������������������������������������ II–13.03 Title Conditions (Scotland) Act�������������������������������� II–13.30 Pt 1�������������������������������������������������������������������������� II–13.30 Pt 9�������������������������������������������������������������������������� II–13.20 s 75(3)(b)�������������������������������������������������� II–13.15, II–13.30 s 76(2)��������������������������������������������������������������������� II–13.22 s 77����������������������������������������������������������� II–13.07, II–13.14 Energy Act s 84��������������������������������������������������������������������������� I–12.82 Planning and Compulsory Purchase Act��������������������� I–9.33 Companies Act Pt 21A��������������������������������������������������������������������� II–10.88

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s 859A��������������������������������������������������������������������� II–10.68 (4)����������������������������������������������������������������������� II–10.68 s 859D��������������������������������������������������������������������� II–10.68 s 859E��������������������������������������������������������������������� II–10.68 s 859F(3)����������������������������������������������������������������� II–10.68 s 859H��������������������������������������������������������������������� II–10.68 s 1159������������������������������������������������������������������������ II–9.50 Offshore Petroleum and Greenhouse Gas Storage Act (Australia) s 6����������������������������������������������������������������������������� I–11.25 s 16����������������������������������������������������������������������������� I–4.18 Planning (Scotland) Act���������������������������������������������� I–9.34 2007 Consolidated Act No 889 on the Use of the Danish Subsoil (Denmark) s 1������������������������������������������������������������������������������� I–4.09 s 2������������������������������������������������������������������������������� I–4.09 Corporate Manslaughter and Corporate Homicide Act�������������������������������������������I–10.77, I–10.78–84, I–10.86 s 1����������������������������������������������������������������������������� I–10.83 (1)������������������������������������������������������������������������ I–10.79 (3)������������������������������������������������������������������������ I–10.79 (4)(b)�������������������������������������������������������������������� I–10.80 (4)(c)�������������������������������������������������������������������� I–10.80 (5)���������������������������������������������������������� I–10.78, I–10.79 (6)������������������������������������������������������������������������ I–10.83 s 2����������������������������������������������������������������������������� I–10.79 (1)(a)�������������������������������������������������������������������� I–10.80 (1)(c)�������������������������������������������������������������������� I–10.80 (4)������������������������������������������������������������������������ I–10.80 s8 (2)������������������������������������������������������������������������ I–10.81 (3)������������������������������������������������������������������������ I–10.81 (4)������������������������������������������������������������������������ I–10.81 s 18��������������������������������������������������������������������������� I–10.80 s 28(3)(e)������������������������������������������������������������������ I–10.79 2008 Climate Change Act���������������������������������������������������� I–3.72 s 1������������������������������������������������������������������������������� I–3.60 s 4������������������������������������������������������������������������������� I–3.60 s 5������������������������������������������������������������������������������� I–3.60 ss 12–14��������������������������������������������������������������������� I–3.60 s 33(3)������������������������������������������������������������������������ I–3.60 s 36(1)������������������������������������������������������������������������ I–3.60 Employment Act Pt 1�������������������������������������������������������������������������� II–15.47 s 4���������������������������������������������������������������������������� II–15.47

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(10)������������I–6.22, I–6.31, I–6.32, I–6.36, I–6.40, I–6.56, I–6.101, I–6.120 (11)������������I–6.27, I–6.31, I–6.33, I–6.34, I–6.35, I–6.36, I–6.38, I–6.44, I–6.46, I–6.56, I–6.59–61 (12)������������������������������������������������������������������������ I–6.33 (17)������������������������������������������������������������������������ I–6.34 (e)������������������������������������������������������������������������� I–6.104 ss 82–84��������������������������������������������������������������������� I–6.46 ss 82–91��������������������������������������������� I–6.14, I–6.18, I–6.21 s 83������I–6.21, I–6.22, I–6.35, I–6.37, I–6.42, I–6.46, I–6.99 (3)�������������������������������������������������������������������������� I–6.35 s 84������������������������������������������I–6.38, I–6.41, I–6.42, I–6.46 (2)�������������������������������������������������� I–6.39, I–6.40, I–6.46 (3)�������������������������������������������������������������������������� I–6.39 s 87����������������������������������������������������������������� I–6.21, I–6.46 (1)�������������������������������������������������������������������������� I–6.42 (4)�������������������������������������������������������������������������� I–6.29 s 89A�������������������������������������������������������������������������� I–6.46 s 89B�������������������������������������������������������������������������� I–6.46 s 90����������������������������������������������������������������������������� I–6.25 (1)�������������������������������������������������� I–6.23, I–6.24, I–6.25 (2)�������������������������������������������������������������� I–6.24, I–6.25 Finance Act s 7(1)�������������������������������������������������������������������������� I–7.08 Historic Environment (Amendment) Scotland Act������ I–9.34 Localism Act��������������������������������������������������������������� I–9.33 2012 Finance Act Sch 22������������������������������������������������������������������������� I–7.12 2013 Energy Act���������������������������������������������������������������� I–9.119 Finance Act s 80(3)���������������������������������������������������������������������� I–13.36 2014 Finance Act s 70����������������������������������������������������������������������������� I–3.44 Sch 15������������������������������������������������������������������������� I–3.44 Historic Environment (Scotland) Act�������������������������� I–9.34 2015 Consumer Rights Act���������������������II–6.05, II–6.28, II–11.01 Finance Act����������������������������������������������������������������� I–7.40 s 47����������������������������������������������������������������������������� I–7.32 Sch 11������������������������������������������������������������������������� I–7.32 Sch 12������������������������������������������������������������������������� I–7.36 Finance (No 2) Act s 7������������������������������������������������������������������������������� I–7.07 Infrastructure Act��������������� I–5.38, I–6.45–8, I–9.35, II.3.11 s 41������������������I–5.28, I–5.33, I–5.34, I–5.35, I–6.16, I–6.19 s 42����������������������������������������������������������������������������� I–5.28

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2016

ss 43–48������������������������������������������������������������������� I–9.120 s 50����������������������������������������������������������������� I–9.27, I–9.28 s 56��������������������������������������������������������������������������� I–9.120 Small Business, Enterprise and Employment Act������ II–10.88 Energy Act������������������I–5.33, I–5.36, I–6.15, I–6.16, I–6.19, I–6.21, I–6.75, I–12.06, I–12.47, I–12.50, I–12.63, II–3.10, II–3.11, II–9.03 s 1������������������������������������������������������������������������������� I–6.18 s 19�������������������������������������������������������������������������� II–15.10 ss 19–26������������������������������������������������������������������ II–15.10 s 22����������������������������������������������������������������� I–6.21, I–6.37 s 23(4)��������������������������������������������������������������������� II–15.10 s 24����������������������������������������������������������������������������� I–6.21 s 26�������������������������������������������������������������������������� II–15.09 s 34����������������������������������������������������� I–6.21, I–6.43, I–6.44 (4)�������������������������������������������������������������������������� I–5.35 s 42����������������������������������������������������������������� I–6.46, I–6.48 (3)(a)���������������������������������������������������������������������� I–5.35 (3)(b)���������������������������������������������������������������������� I–5.35 (4)�������������������������������������������������������������������������� I–5.37 s 43����������������������������������������������������������������������������� I–5.37 ss 44–46��������������������������������������������������������������������� I–5.37 s 47����������������������������������������������������������������������������� I–5.37 s 48����������������������������������������������������������������������������� I–5.37 s 49����������������������������������������������������������������������������� I–5.37 ss 50–52������������������������������������������������������������������ II–15.09 s 58�������������������������������������������������������������������������� II–15.09 s 70����������������������������������������������������������������������������� I–6.46 s 71����������������������������������������������������������������������������� I–6.46 Sch 1 paras 63–72������������������������������������������������������ I–6.18 Finance Act s 46����������������������������������������������������������������������������� I–7.07 s 58����������������������������������������������������������������������������� I–7.08 s 140(1)���������������������������������������������������������������������� I–7.09 Petroleum Act����������������������������������������������������������� I–12.75 Scotland Act s 36��������������������������������������������������������������������������� I–12.82 s 47 (1)������������������������������������������������������������������������ I–9.124 (2)������������������������������������������������������������������������ I–9.125 (3)������������������������������������������������������������������������ I–9.125 s 49(1)���������������������������������������������������������������������� I–9.125

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TABLE OF STATUTORY INSTRUMENTS 1935 Petroleum (Production) Regulations (SR&O 1935/426).................................................................. I–10.05 1964 Continental Shelf (Designation of Areas) Order (SI 1967/697)............................................................... I–8.07 Petroleum (Production) (Continental Shelf and Territorial Sea) Regulations (SI 1964/708)................. I–10.05 Sch 2, Cl 18........................................................... I–10.05 1972 Mineral Workings (Offshore Installations) Act 1971 (Commencement) Order (SI 1972/644)...................... I–10.16 Offshore Installations (Logbooks and Registration of Death) Regulations (1972/1542)........................... I–10.16 Offshore Installations (Managers) Regulations (SI 1972/703)............................................................. I–10.16 Offshore Installations (Registration) Regulations (SI 1972/702)............................................................. I–10.16 1973 Offshore Installations (Inspectors and Casualties) Regulations (SI 1973/1842)....................................... I–10.16 1974 Offshore Installations (Construction and Survey) Regulations (SI 1974/289)......................................... I–10.16 Offshore Installations (Public Inquiries) Regulations (SI 1974/338)............................................................. I–10.16 1976 Employment Protection (Offshore Employment) Order (SI 1976/766).................................................. II.14.31 Offshore Installations (Emergency Procedures) Regulations (SI 1976/1542)....................................... I–10.16 Offshore Installations (Operational Safety, Health and Welfare) Regulations (SI 1976/1019).................. I–10.16 Petroleum (Production) Regulations (SI 1976/276)...... I–4.36 Submarine Pipe-lines (Diving Operations) Regulations (SI 1976/923).......................................... I.10.16 1977 Health and Safety at Work Act 1974 (Application Outside Great Britain) Order (SI 1977/1232)............ I–10.22 Offshore Installations (Life-Saving Appliances) Regulations (SI 1977/486)......................................... I–10.16 Safety Representatives and Safety Committees Regulations (SI 1977/500)......................................... I–10.26 Submarine Pipe-lines (Inspectors) Regulations (SI 1977/835)................................................................... I.10.16

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1978 Offshore Installations (Fire-Fighting Equipment) Regulations (SI 1978/611)......................................... I–10.16 1980 Offshore Installations (Well Control) Regulations (SI 1980/1759)........................................................... I–10.16 1981 Employment Protection (Offshore Employment) (Amendment) Order (SI 1981/208)............................ II.14.31 1982 Petroleum (Production) Regulations (SI 1982/1000) Sch 5....................................................................... I–7.29 1984 Control of Industrial Major Accident Hazard Regulations (SI 1984/1902)....................................... I–10.38 1985 Deposits in the Sea (Exemption) Order (SI 1985/1699)............................................. I–11.49, I–11.72 reg 14.................................................................... I–11.37 reg 15.................................................................... I–11.37 reg 15A................................................................. I–11.37 1986 Insolvency Rules (SI 1986/1925) r 2.87.................................................................. II.10.103 r 15.34(4)............................................................ II.10.120 Insolvency (Scotland) Rules (SI 1986/1915) r 1.16A(2)........................................................... II.10.120 r 2.39B................................................................ II.10.100 r 4.67.................................................................. II.10.100 1988 Petroleum (Production) (Seaward Areas) Regulations (SI 1988/1213)...................................................I–4.19, I–A.7 reg 3(1)....................................................... I–4.03, I–4.41 reg 7(5)................................................................... I–4.23 Sch 1........................................................... I–4.03, I–4.41 Sch 4.......................................................... I–A.20, I–A.29 Model Cl 16............................................................I–A.20 Model Cl 17............................................................I–A.29 1989 Offshore Installations (Pipe-line Valve) Regulations (SI 1989/680)............................................................. I–10.45 Offshore Installations (Safety Representatives and Safety Committees) Regulations (SI 1989/971)............................................... I–10.39, I–10.50 1992 Health and Safety (Display Screen Equipment) Regulations (SI 1992/2792)....................................... I–10.46 Management of Health and Safety at Work Regulations (SI 1992/2051)....................................... I–10.46 Manual Handling Operations Regulations (SI 1992/2793)........................................................... I–10.46 Offshore Installations (Safety Case) Regulations (SI 1992/2885)................................................ I–9.16, I.10.41 reg 4 (1)..................................................................... I–10.41

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(2)..................................................................... I–10.41 reg 5...................................................................... I–10.41 reg 6...................................................................... I–10.41 reg 7...................................................................... I–10.41 reg 8...................................................................... I–10.41 reg 9...................................................................... I–10.41 reg 10...................................................... I–10.41, I–10.42 reg 13.................................................................... I–10.41 reg 14.................................................................... I–10.41 Sch 3..................................................................... I–10.41 Sch 4..................................................................... I–10.41 Sch 5..................................................................... I–10.41 Personal Protective Equipment of Work Regulations (SI 1992/2966)........................................................... I–10.46 Personal Protective Equipment Regulations (SI 1992/3139)........................................................... I–10.46 Provision and Use of Work Equipment Regulations (SI 1992/2932)........................................................... I–10.46 1993 Act of Sederunt (Sheriff Court Ordinary Cause Rules) (SI 1993/1956) Ch 40................................................................... II–15.75 r 9.13................................................................... II–15.43 r 40.12(3)(m)....................................................... II–15.75 1994 Act of Sederunt (Rules of the Court of Session) (SI 1994/1443) Ch 47................................................................... II–15.75 Ch 77................................................................... II–15.76 Ch 78................................................................... II–15.76 r 47.11(1)(e)......................................................... II–15.75 Conservation (Natural Habitats) Regulations (SI 1994/2716)............................................................. I–4.25 1995 Borehole Sites and Operations Regulations (SI 1995/2038)................................................. I–9.17, I–9.19 reg 7(2)................................................................... I–9.17 Hydrocarbons Licensing Directive Regulations (SI 1995/1434)............................................................. I–4.16 reg 3 (1)........................................................... I–4.36, I–4.37 (1)(a).................................................................. I–4.38 (1)(b).................................................................. I–4.38 (1)(d)...................................................... I–4.38, I–4.49 (2)....................................................................... I–4.37 (4)....................................................................... I–4.37 reg 4 (1)....................................................................... I–4.16

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(2)....................................................................... I–4.16 reg 5........................................................................ I–4.37 Offshore Installations (Management and Administration) Regulations (SI 1995/738)............... I–10.42 reg 5...................................................................... I–10.42 reg 6...................................................................... I–10.42 (b)..................................................................... I–10.42 reg 7...................................................................... I–10.42 reg 8...................................................................... I–10.42 reg 9...................................................................... I–10.42 reg 10.................................................................... I–10.42 reg 11.................................................................... I–10.42 reg 12.................................................................... I–10.42 reg 13.................................................................... I–10.42 reg 14.................................................................... I–10.42 reg 15.................................................................... I–10.42 reg 16.................................................................... I–10.42 reg 17.................................................................... I–10.42 reg 18.................................................................... I–10.42 reg 19.................................................................... I–10.42 reg 20.................................................................... I–10.42 reg 21.................................................................... I–10.42 Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations (SI 1995/743)............................................... I–10.43, I–10.71 reg 4 (1)..................................................................... I–10.43 (2)..................................................................... I–10.43 reg 5...................................................................... I–10.43 reg 6...................................................................... I–10.43 reg 7...................................................................... I–10.43 reg 8...................................................................... I–10.43 reg 9...................................................................... I–10.43 reg 10.................................................................... I–10.43 reg 11.................................................................... I–10.43 reg 12.................................................................... I–10.43 reg 13.................................................................... I–10.43 reg 14.................................................................... I–10.43 reg 15.................................................................... I–10.43 reg 16.................................................................... I–10.43 reg 17.................................................................... I–10.43 reg 18.................................................................... I–10.43 reg 19.................................................................... I–10.43 reg 20.................................................................... I–10.43 reg 21.................................................................... I–10.43

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Petroleum (Production) (Landward Areas) Regulations (SI 1999/1436) Sch 3....................................................................... I–4.79 Petroleum (Production) (Seaward Areas) (Amendment) Regulations (SI 1995/1435) reg 6........................................................................ I–4.23 1996 Merchant Shipping (Prevention of Oil Pollution) Regulations (SI 1996/??)............................................ I–11.87 Offshore Installations and Wells (Design and Construction) Regulations (SI 1996/913).................... I–9.19, I–9.21, I–10.44 Pt II....................................................................... I–10.44 Pt III...................................................................... I–10.44 Pt IV...................................................................... I–10.44 reg 2(1)................................................................. I–10.44 reg 4 (1)..................................................................... I–10.44 (2)..................................................................... I–10.44 reg 5...................................................................... I–10.44 reg 6...................................................................... I–10.44 reg 7...................................................................... I–10.44 reg 8...................................................................... I–10.44 reg 9...................................................................... I–10.44 reg 10.................................................................... I–10.44 reg 13 (1)..................................................................... I–10.44 (2)..................................................................... I–10.44 reg 14.................................................................... I–10.44 reg 15.................................................................... I–10.44 reg 16.................................................................... I–10.44 reg 17.................................................................... I–10.44 reg 18.................................................................... I–10.44 reg 19.................................................................... I–10.44 reg 20.................................................................... I–10.44 reg 21.................................................................... I–10.44 reg 22.................................................................... I–10.44 Sch 1..................................................................... I–10.44 Pipelines Safety Regulations (SI 1996/825)................. I–9.16, I–10.45, I.12.58 1997 Copyright and Rights in Databases Regulations (SI 1997/3032)........................................................... II.12.12 Diving at Work Regulations (SI 1997/2776).............. I–10.45 1998 Civil Procedure Rules (SI 1998/3132)........................ II.15.43 Ch 78.................................................................... II.15.77 Pt 36..................................................................... II.15.43

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Pt 58..................................................................... II.15.75 r 1.4(2)(e).............................................................. II.15.43 r 26.4(1)................................................................ II.15.43 r 44.4.(3)(a)(i)....................................................... II.15.43 r 44.5(a)................................................................ II.15.43 Lifting Operations and Lifting Equipment Regulations (SI 1998/2307)....................................... I–10.45 Management of Health and Safety at Work Regulations (SI 1996/2306)....................................... I–10.46 Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations (SI 1998/1056)........I–11.81, I–11.82–5, I–11.87 reg 2...................................................................... I–11.82 reg 3 (2)..................................................................... I–11.84 (a)..................................................................... I–11.83 reg 4 (1)(c)................................................................. I–11.83 (5)(b)................................................................ I–11.83 (7)..................................................................... I–11.83 (a)(iii)............................................................... I–11.83 (a)(iii)(bb)......................................................... I–11.83 reg 5 (1)..................................................................... I–11.85 (2)..................................................................... I–11.85 reg 7(1)................................................................. I–11.83 reg 8...................................................................... I–11.84 Provision and Use of Work Equipment Regulations (SI 1998/2306)........................................................... I–10.46 Working Time Regulations (SI 1998/1833).............. II–14.19, II–14.23, II–14.44–82 reg 2.............II.14.46, II.14.49, II.14.54, II.14.56, II.14.78 (1)(b)............................................................... II–14.25 reg 4...................................................................... II.14.47 (1)..................................................................... II.14.72 reg 5...................................................................... II.14.65 (2)..................................................................... II.14.65 (3)..................................................................... II.14.65 reg 6.................................................................. II.14.56–9 (1)..................................................................... II.14.58 (2)..................................................................... II.14.58 (3)..................................................................... II.14.56 (7)..................................................................... II.14.58 reg 7...................................................................... II.14.59 reg 8...................................................................... II.14.60

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reg 9...................................................................... II.14.61 reg 10.................................................................... II.14.50 (1).................................................................... II–14.50 reg 11.................................................................... II.14.51 (1).................................................................... II–14.51 (2).................................................................... II–14.51 reg 12.................................................................... II.14.52 (1)..................................................................... II.14.52 reg 13................................................................ II.14.62–4 reg 13A................................................................. II.14.62 reg 18.................................................................... II.14.45 reg 21...................................... II–14.51, II.14.58, II.14.66 (a)....................................... II–14.50, II.14.52, II.14.58 reg 22................................................................ II.14.53–5 reg 23.................................................................... II.14.67 (a)..................................................................... II.14.56 reg 24.........II–14.50, II.14.52, II.14.53, II.14.58, II.14.66, II.14.67, II.14.74 reg 25B....................................................II.14.47, II.14.48 reg 28.................................................................... II.14.69 reg 29.................................................................... II.14.70 reg 30.................................................................... II.14.71 reg 36.................................................................... II.14.46 Sch 3..................................................................... II.14.70 Working Time (Northern Ireland) Regulations (SI 1998/386)............................................................. II.14.56 1999 Control of Major Accident Hazard (COMAH) Regulations (SI 1999/743)............................ I.10.38, I–10.84 Management of Health and Safety at Work Regulations (SI 1999/3242)....................................... I–10.46 reg 3...................................................................... II.14.57 Merchant Shipping (Marine Equipment) Regulations (SI 1999/1957)............................................. I–11.67, I–11.69 National Minimum Wage (Offshore Employment) Order (SI 1999/1128)................................................ II.14.31 Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations (SI 1999/360)................................................ I–11.16, I.12.67 reg 4...................................................................... I–11.16 reg 5...................................................................... I–11.16 (4)(b)(ii)............................................................ I–11.19 reg 6...................................................................... I–11.45 reg 9...................................................................... I–11.17 Sch 2 (a)..................................................................... I–11.17

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(a)(i)................................................................. I–11.17 (a)(ii)................................................................ I–11.17 (a)(iii)............................................................... I–11.17 (b)..................................................................... I–11.17 (c)(i).................................................................. I–11.17 (c)(ii)................................................................. I–11.17 (d)..................................................................... I–11.17 (e)..................................................................... I–11.17 Petroleum (Current Model Clauses) Order (SI 1999/160) Schs 1–14.................................................... I–4.17, I–5.01 2000 Employment Relations (Offshore Employment) Order (SI 2000/1828)................................................ II.14.31 2001 Offshore Combustion Installations (Prevention and Control of Pollution) Regulations (SI 2001/1091)......................................................I–11.58–61 reg 2.......................................... I–11.58, I–11.59, I–11.60 reg 3...................................................................... I–11.59 reg 4...................................................................... I–11.61 (1)..................................................................... I–11.60 (2)(g)(i)............................................................. I–11.60 (2)(g)(ii)............................................................ I–11.60 (2)(g)(iii)........................................................... I–11.60 reg 5...................................................................... I–11.59 (3)..................................................................... I–11.59 reg 7 (3)..................................................................... I–11.60 (4)..................................................................... I–11.60 reg 9...................................................................... I–11.61 reg 10.................................................................... I–11.61 regs 13–16............................................................. I–11.61 reg 18.................................................................... I–11.61 (4)..................................................................... I–11.61 Offshore Petroleum Activities (Conservation of Habitats) Regulations (SI 2001/1754).......I–4.25, I–11.08–15 reg 2........................................................................ I–4.25 (1)(a)................................................................ I–11.08 (1)(b)................................................................ I–11.08 (1)(c)................................................................. I–11.08 (1)(d)................................................................ I–11.08 (1)(e)................................................................. I–11.08 (1)(f)................................................................. I–11.08 (2)..................................................................... I–11.08 reg 4 (1)(a)................................................................ I–11.13 (1)(b)................................................................ I–11.13

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(1)(c)................................................................. I–11.13 reg 5........................................................ I–11.08, I–11.14 (1)........................................... I–4.25, I–11.08, I–11.09 (2)......................................................... I–4.25, I–11.09 (3)......................................................... I–4.25, I–11.09 (4)..................................................................... I–11.09 reg 6 (1)(a).................................................... I–4.25, I–11.09 (1)(b).................................................... I–4.25, I–11.09 (2)(a).................................................................. I–4.25 (2)(b).................................................................. I–4.25 reg 7...................................................................... I–11.12 (1)(a)................................................................ I–11.10 (1)(c)................................................................. I–11.10 (2)(a)................................................................ I–11.10 reg 10...................................................... I–11.11, I–11.12 reg 11...................................................... I–11.11, I–11.12 reg 11(a)................................................................ I–11.11 reg 12.................................................................... I–11.12 reg 14.................................................................... I–11.11 reg 16.................................................................... I–11.12 reg 17.................................................................... I–11.12 reg 18.................................................................... I–11.12 reg 19 (2)..................................................................... I–11.12 (3)..................................................................... I–11.12 (4)..................................................................... I–11.12 2002 Merchant Shipping (Hours of Work) Regulations (SI 2002/2125)........................................................... II.14.45 National Emission Ceilings Regulations (SI 2002/3118)........................................................... I–11.62 reg 2...................................................................... I–11.64 (2)(a)................................................................ I–11.64 (2)(b)................................................................ I–11.64 reg 3...................................................................... I–11.64 reg 4(1)................................................................. I–11.64 Offshore Chemical Regulations (SI 2002/1355)........ I–11.38, I–11.44, I–11.45–8, I–11.87 reg 2............................ I–11.38, I–11.45, I–11.46, I–11.47 reg 3 (1)..................................................................... I–11.45 reg 4 (1)..................................................................... I–11.45 (1)(a)................................................................ I–11.45 (2)..................................................................... I–11.45

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reg 5 (1)..................................................................... I–11.46 (2)..................................................................... I–11.46 reg 6 (1)(a–d)............................................................. I–11.46 reg 7 (1)..................................................................... I–11.45 (2)..................................................................... I–11.45 (3)..................................................................... I–11.45 reg 10 (1)..................................................................... I–11.46 (2)..................................................................... I–11.46 (3)..................................................................... I–11.46 (5)..................................................................... I–11.46 reg 11.................................................................... I–11.47 (2)..................................................................... I–11.47 (4)..................................................................... I–11.47 reg 12.................................................................... I–11.47 (2)..................................................................... I–11.47 (7)..................................................................... I–11.47 reg 13 (1)..................................................................... I–11.48 reg 14 (1)..................................................................... I–11.46 (2)..................................................................... I–11.46 reg 15 (1)(a)................................................................ I–11.48 (1)(b)................................................................ I–11.48 (2)..................................................................... I–11.48 reg 16.................................................................... I–11.48 reg 18.................................................................... I–11.48 (4)..................................................................... I–11.48 (6)..................................................................... I–11.49 Offshore Installations (Emergency Pollution Control) Regulations (SI 2002/1861)...........I–11.38, I–11.42, I–11.81, I–11.90–3 reg 2...................................................................... I–11.90 reg 3 (1)(a)................................................................ I–11.91 (1)(b)................................................................ I–11.91 (1)(c)................................................................. I–11.91 (2)..................................................................... I–11.91 (3)..................................................................... I–11.91 (3)(a)................................................................ I–11.91 (3)(b)................................................................ I–11.91

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(3)(c)................................................................. I–11.91 (4)..................................................................... I–11.91 (4)(b)................................................................ I–11.91 (4)(c)................................................................. I–11.91 reg 5 (2)..................................................................... I–11.93 (4)..................................................................... I–11.93 Offshore Safety (Miscellaneous Amendments) Regulations (SI 2002/2175)....................................... I–10.42 Renewables Obligation Order (SI 2002/914)............... I–3.63 art 3........................................................................ I–3.63 art 6........................................................................ I–3.63 Sch 1....................................................................... I–3.63 2003 Financial Collateral Arrangements (No 2) Regulations (SI 2003/3226)........................II–10.90, II-10.91 reg 8..................................................................... II–10.90 Working Time (Amendment) Regulations (SI 2003/1684)........................................................... II.14.45 2004 Environmental Information Regulations (SI 2004/3391) reg 12(5)(e)........................................................... I–11.28 Petroleum Licensing (Exploration and Production) (Seaward and Landward Areas) Regulations (SI 2004/352)..............................................I–4.52, I–11.22–9 reg 9(1)(e)............................................... I–11.28, I–11.29 Sch 1....................................................... I–11.22, I–11.23 Model Cl 1(2)................................................... I–11.23 Model Cl 2......................................... I–11.22, I–11.24 Model Cl 3....................................................... I–11.22 Model Cl 7(1)................................................... I–11.24 Model Cl 7(2)................................................... I–11.24 Model Cl 7(4)................................................... I–11.24 Model Cl 7(5)................................................... I–11.24 Model Cl 7(6)................................................... I–11.24 Model Cl 7(7)................................................... I–11.24 Model Cl 9(1)..................................... I–11.24, I–11.26 Model Cl 9(2)................................................... I–11.25 Model Cl 9(3)................................................... I–11.26 Model Cl 10..................................................... I–11.26 Model Cl 11(1)................................................. I–11.28 Model Cl 12.......................................................I–A.20 Model Cl 12(1)(a)............................................ I–11.28 Model Cl 12(2)................................................. I–11.28 Model Cl 13.......................................................I–A.29 Model Cl 14..................................................... I–11.28 Model Cl 14(b)................................................. I–11.28

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Model Cl 14(c)................................................. I–11.28 Model Cl 14(d)................................................. I–11.28 Model Cl 15(a)................................................. I–11.28 Model Cl 16(a)................................................. I–11.29 Model Cl 16(b)................................................. I–11.29 Model Cl 17..................................................... I–11.29 Model Cl 20(2)(a)............................................ I–11.29 Model Cl 20(2)(c)............................................. I–11.29 Model Cl 20(2)(e)............................................. I–11.29 Model Cl 20(2)(f)............................................. I–11.29 Model Cl 20A.................................................. I–11.29 Model Cl 23(1)................................................. I–11.27 Model Cl 23(2)................................................. I–11.27 Model Cl 23(a)................................................. I–11.27 Model Cl 23(c)................................................. I–11.27 Schs 1–7.................................................................. I–4.17 Schs 2–4................................................................ I–11.22 Sch 4.......... I–4.43, I–4.54, I–4.57, I–4.58, I–A.20, I–A.29 Sch 6......................................................... I–4.79, I–11.22 Sch 7..................................................................... I–11.22 Renewables Obligation Order (SI 2004/924)............... I–3.63 2005 Offshore Installations (Safety Case) Regulations (SI 2005/3317)............................I.1.16, I–10.03, I–10.48–54, I–10.64, I.12.58 reg 2..........................................................I-10.51, I.10.52 reg 5...................................................................... I–10.51 reg 6...................................................................... I–10.49 reg 9(1)................................................................. I–10.49 reg 10.................................................................... I–10.49 reg 11.................................................................... I–10.49 reg 12.................................................................... I–10.50 reg 13.................................................................... I–10.49 reg 14.................................................................... I–10.49 reg 24.................................................................... I–10.49 Sch 2, para 3......................................................... I–10.50 Offshore Petroleum Activities (Oil Prevention and Control) Regulations (SI 2005/2055).....................I–11.35–6, I–11.81, I–11.86–9 reg 2........................................................ I–11.35, I–11.86 reg 3 (1)....................................................... I–11.35, I–11.86 (2)(a)................................................................ I–11.87 (2)(b)................................................................ I–11.87 (2)(c)................................................................. I–11.87 (4)..................................................................... I–11.87

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reg 4 (1)....................................................... I–11.87, I–11.88 (2)..................................................................... I–11.88 (3)..................................................................... I–11.88 (4)..................................................................... I–11.88 (a)..................................................................... I–11.88 reg 5 (1)(a)................................................................ I–11.87 (1)(b)................................................................ I–11.87 (1)(c)................................................................. I–11.87 (2)..................................................................... I–11.87 reg 7 (1)..................................................................... I–11.88 (2)..................................................................... I–11.88 reg 8...................................................................... I–11.88 reg 9 (1)(a)................................................................ I–11.87 (1)(b)................................................................ I–11.88 reg 12.................................................................... I–11.89 (1)(a).................................................. I–11.35, I–11.89 (1)(b).................................................. I–11.35, I–11.89 reg 14 (1)..................................................................... I–11.89 (2)..................................................................... I–11.89 reg 16.................................................................... I–11.89 (2)(a)................................................................ I–11.89 (2)(b)................................................................ I–11.89 (3)(b)................................................................ I–11.89 Renewables Obligation Order (SI 2005/926)............... I–3.63 2006 Petroleum Licensing (Exploration and Production) (Seaward and Landward Areas) (Amendment) Regulations (SI 2006/784)............................... I–4.17, I–4.79 Renewables Obligation Order (SI 2006/1004)............. I–3.63 Transfer of Undertakings (Protection of Employment) Regulations (SI 2006/246).............................................II.10.117, II.14.02 Working Time (Amendment) (No 2) Regulations (SI 2006/2389)........................................................... II.14.45 2007 Large Combustion Plants (National Emissions Reduction Plan) Regulations (SI 2007/2325)............... I–3.37 reg 8........................................................................ I–3.37 Marine Works (Environmental Impact Assessment) Regulations (SI 2007/1518) reg 2(1)................................................................. I–11.72 Offshore Petroleum Production and Pipelines

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(Assessment of Environmental Effects) (Amendment) Regulations (SI 2007/933)............................ I–11.16, I.12.67 Renewables Obligation Order 2006 (Amendment) Order (SI 2007/1078).................................................. I–3.63 2008 Merchant Shipping (Prevention of Air Pollution from Ships) Regulations (SI 2008/2924).................I–11.51–7 Pt III...................................................................... I–11.55 reg 2 (1)........................... I–11.52, I–11.53, I–11.55, I–11.56 (5)(b)................................................................ I–11.54 reg 3 (5)..................................................................... I–11.57 (13)(c)............................................................... I–11.56 (13)(c)(1).......................................................... I–11.56 (13)(e)............................................................... I–11.55 regs 5–15............................................................... I–11.54 reg 9(1)................................................................. I–11.54 reg 16(1)............................................................... I–11.57 reg 18.................................................................... I–11.57 reg 20 (1)..................................................................... I–11.55 (3)..................................................................... I–11.55 (4)..................................................................... I–11.55 reg 21.................................................................... I–11.55 reg 22.................................................................... I–11.55 (3)(a)................................................................ I–11.55 (3)(b)................................................................ I–11.55 reg 23.................................................................... I–11.56 reg 24 (4)..................................................................... I–11.56 (5)..................................................................... I–11.56 reg 25.................................................................... I–11.56 (1)(c)................................................................. I–11.56 reg 28(1)............................................................... I–11.57 Merchant Shipping (Prevention of Pollution by Sewage and Garbage from Ships) Regulations (SI 2008/3257)......................................................I–11.65–72 reg 2 (1)...........................I–11.65, I–11.66, I–11.67, I–11.68, I–11.69, I–11.70 (4)....................................................... I–11.67, I–11.69 (6)(b)................................................................ I–11.68 reg 7........................................................ I–11.67, I–11.68 reg 8...................................................................... I–11.68 reg 9(1)................................................... I–11.68, I–11.69

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reg 21 (1)..................................................................... I–11.69 (1)(a)................................................................ I–11.67 (1)(b)................................................................ I–11.67 (2)....................................................... I–11.67, I–11.69 reg 23 (1)..................................................................... I–11.67 (3)..................................................................... I–11.67 reg 24...................................................... I–11.67, I–11.69 (a)..................................................................... I–11.67 (b)..................................................................... I–11.67 (c)..................................................................... I–11.67 reg 25...................................................... I–11.67, I–11.69 (1)(a)................................................................ I–11.67 (1)(b)................................................................ I–11.67 (2)..................................................................... I–11.67 (3)..................................................................... I–11.67 reg 26(1)............................................................... I–11.70 reg 29.................................................................... I–11.70 (2)..................................................................... I–11.70 reg 32.................................................................... I–11.70 reg 36.................................................................... I–11.71 reg 38.................................................................... I–11.71 Petroleum Licensing (Production) (Seaward Areas) Regulations (SI 2008/225)...................I–4.12, I–4.38, I–5.05, I–11.30–3, I–11.62–3, I–12.77, I–A.20, II–2.05 reg 23 (3)(a)................................................................ I–11.62 (4)..................................................................... I–11.63 (7)..................................................................... I–11.62 (7)(a)................................................................ I–11.62 (7)(b)................................................................ I–11.62 reg 40(1)............................................................... II.10.75 Sch.............................................................. I–4.44, I–5.06 Model Cls.............................................. I–4.14, II–3.10 Model Cl 1(2)................................................... I–11.30 Model Cl 2................................ I–4.12, I–4.41, II–3.10 Model Cl 3......................................................... I–4.52 Model Cl 3(2)..................................................... I–4.53 Model Cl 4......................................................... I–4.13 Model Cl 4(2)(b)................................................ I–4.50 Model Cl 6(3)..................................................... I–4.54 Model Cl 7............................................. I–4.13, I–4.56 Model Cl 8(1)..................................................... I–4.57 Model Cl 8(3)(a)................................................ I–4.57

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Model Model Model Model Model Model Model Model Model Model Model Model Model Model Model



Model Model Model Model Model Model Model Model Model Model Model Model



Model Model Model Model Model Model Model Model Model Model Model Model Model Model Model Model

Cl 8(3)(b)................................................ I–4.57 Cl 8(3)(c)................................................. I–4.57 Cl 12....................................................... I–4.45 Cl 12(2)................................................... I–4.51 Cl 14............................... I–4.13, I–4.51, I–4.60 Cl 15....................................................... I–4.60 Cl 16........I–4.13, I–4.83, I–A.7, I–A.28, I–A.29 Cl 16(2).......................... I–4.51, I–A.20, I–A.28 Cl 16(3)................................................... I–4.51 Cl 16(4)................................................... I–4.51 Cl 16(4)(a).............................................. I–4.51 Cl 16(4)(b).............................................. I–4.51 Cl 16(6)................................................... I–4.51 Cl 16(7)................................................... I–4.51 Cl 17..... I–4.13, I–4.83, I–11.30, I–A.7, I–A.28, I–A.29, I–A.30, I–A.31, I–A.47, I–A.50, II–3.12 Cl 17(1)...................................................I–A.28 Cl 17(1)(a)............................................ I–11.30 Cl 17(1)(b)............................................ I–11.30 Cl 17(2)............. I–A.28, I–A.31, I–A.32, I–A.47 Cl 17(2)(c)............................................. I–11.30 Cl 17(3)...................................... I–A.31, I–A.47 Cl 17(4)...................................................I–A.28 Cl 17(4)(c)(ii)........................................ I–11.30 Cl 17(5)...................................................I–A.28 Cl 17(6)...................................................I–A.28 Cl 17(9)................................................. I–11.30 Cl 18.......I–4.83, I–5.06, I–A.7, I–A.28, I–A.29, I–A.31, II–3.12 Cl 18(6)................................................. I–11.30 Cl 19......................................... I–4.60, I–11.31 Cl 19(12)(a).......................................... I–11.31 Cl 19(12)(b).......................................... I–11.31 Cl 20.......................................... I–4.60, II–3.12 Cl 21............................. I–4.13, I–4.60, I–11.32 Cl 21(4)................................................. I–11.32 Cl 23................. I–4.13, I–4.60, I–5.06, I–11.32 Cl 23(3)(a)............................................ I–11.32 Cl 23(7)(a)............................................ I–11.32 Cl 23(9)................................................. I–11.32 Cl 24.............................. I–4.13, I–4.60, II–2.24 Cl 24(1).................................................. II–9.31 Cl 24(2).................................................. II–9.36 Cl 27...................................................... II–3.12 Cl 27(1).................................................. II–3.13

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Model Cl 27(2).................................................. II–3.13 Model Cl 27(4)..................................... II–3.13, II–3.16 Model Cl 27(5).................................................. II–3.13 Model Cl 28......................................... II–3.12, II–3.50 Model Cl 29....................................................... I–4.60 Model Cl 30....................................................... I–4.60 Model Cl 31....................................................... I–4.60 Model Cl 40(1).................................................. II–9.30 Model Cl 41....................................................... I–4.13 Model Cl 41(2)(b).............................................. I–4.51 Model Cl 41(3).............................................. II–9.34–5 Model Cl 41(4).................................................. II–9.34 Model Cl 42....................................................... I–4.13 Model Cl 43...................................................... II–3.13 Model Cl 43(1)................................................... I–4.13 Model Cl 44....................................................... I–4.60 Model Cl 45........................................... I–4.13, I–4.60 Model Cl 176..................................................... I–4.57 2009 Offshore Exploration (Petroleum and Gas Storage and Unloading) (Model Clauses) Regulations (SI 2009/2814) Sch.....................................................................I–4.39–40 Model Cl 2......................................................... I–4.39 Model Cl 3......................................................... I–4.39 Model Cl 4......................................................... I–4.39 Model Cl 9......................................................... I–4.40 Model Cl 11....................................................... I–4.40 Model Cl 13....................................................... I–4.40 Model Cl 22....................................................... I–4.40 Model Cl 23....................................................... I–4.40 Petroleum Licensing (Amendment) Regulations (SI 2009/3283).......................................... I–4.12, I–4.44, I–5.05 Renewables Obligation Order (SI 2009/785)............... I–3.63 Sch 1....................................................................... I–3.63 Renewables Obligation (Northern Ireland) Order (SI 2009/154)............................................................... I–3.63 Renewables Obligation (Scotland) Order (SI 2009/140)............................................................... I–3.63 2010 Environmental Permitting (England and Wales) Regulations (SI 2010/675)........................................... I–9.26 Equality Act 2010 (Offshore Work) Order (SI 2010/1835)........................................................... II.14.31 Merchant Shipping (Prevention of Air Pollution from Ships) (Amendment) Regulations (SI 2010/895)............................................................. I–11.51

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Merchant Shipping (Prevention of Pollution by Sewage and Garbage from Ships) (Amendment) Regulations (SI 2010/897)......................................... I–11.65 2011 Offshore Petroleum Activities (Oil Prevention and Control) (Amendment) Regulations (SI 2011/983).... I–11.81 2012 Oil Stock Order (SI 2012/2862).......... I–3.34, I–3.35, I–3.67 reg 3........................................................................ I–3.34 Pollution Prevention Control (Scotland) regulations (SI ??)........................................................................... I–3.40 2013 Environmental Permitting (England and Wales) (Amendment) Regulations (SI 2013/390)..................... I–3.40 Pollution Prevention and Control (Industrial Emissions) Regulations (Northern Ireland) (SI 2013/160)............................................................... I–3.40 2014 Merchant Shipping (Maritime Labour Convention) (Hours of Work) (Amendment) Regulations (SI 2014/308)............................................................ II–14.45 Petroleum (Exploration and Production) (Landward Areas) Regulations (SI 2014/1686)............... I–9.125, II–3.10 s 4 I–9.09 Sch 1..................................................................... I–9.125 Sch 2........................................................... I–4.79, I–9.11 Sch 3....................................................................... I–4.79 Model Cl 2............................................................. II–3.10 2015 Control of Major Accident Hazard (COMAH) Regulations (SI 2015/483)......................................... I–10.63 Infrastructure Act (Commencement No 1) Regulations (SI 2015/481) reg 3(b)................................................................... I–5.35 Offshore Installations (Offshore Safety Directive) (Safety Case) Regulations (SI 2015/398)..........................................I–10.64–76, I–11.97 reg 2 (1)..................................................................... I–10.67 (7)..................................................................... I–10.67 (8)..................................................................... I–10.67 reg 4...................................................................... I–10.64 reg 6...................................................................... I–10.75 reg 7 (2)(a)................................................................ I–10.65 (2)(b)................................................................ I–10.65 reg 8 (1)..................................................................... I–10.66 (2)..................................................................... I–10.66

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(3)..................................................................... I–10.66 reg 9 (1)..................................................................... I–10.67 (1)(a)................................................................ I–10.67 (1)(b)................................................................ I–10.67 (2)..................................................................... I–10.67 (3)..................................................................... I–10.67 (4)..................................................................... I–10.67 reg 10(1)............................................................... I–10.67 regs 10–13............................................................. I–10.68 reg 11(2)(b)........................................................... I–10.68 reg 21 (3)..................................................................... I–10.68 (4)..................................................................... I–10.68 (6)..................................................................... I–10.68 reg 26.................................................................... I–10.75 reg 28 (3)..................................................................... I–10.69 (4)..................................................................... I–10.69 reg 29 (1)..................................................................... I–10.70 (2)..................................................................... I–10.70 reg 30 (1)(a)................................................................ I–10.71 (1)(b)................................................................ I–10.71 (3)..................................................................... I–10.72 (14)................................................................... I–10.71 reg 31 (1)(a)................................................................ I–10.72 (1)(b)................................................................ I–10.72 reg 32(1)............................................................... I–10.73 reg 33.................................................................... I–10.74 reg 34(1)............................................................... I–10.65 Sch 1..................................................................... I–10.65 Sch 2..................................................................... I–10.66 para 2............................................................... I–10.65 Sch 3..................................................................... I–10.66 Sch 4 Pt 1................................................................... I–10.67 Pt 2................................................................... I–10.68 Sch 11................................................................... I–10.73 Sch 13, paras 33–40.............................................. I–10.64 Offshore Petroleum Licensing (Offshore Safety Directive) Regulations (SI 2015/385) reg 1...................................................................... I–10.64

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reg 7...................................................................... I–10.76 reg 8(2)................................................................. I–10.76 Renewables Obligation Order (SI 2015/1947)................................................. I–3.63, I–3.73 2016 Energy Act 2016 (Commencement No 2 and Transitional Provisions) Regulations (SI 2016/920) reg 2(b)................................................................... I–5.35 Insolvency (England and Wales) Rules (SI 2016/1024) r 3.51.................................................................. II.10.100 r 14.1.................................................................. II.10.103 r 15.34................................................................ II.10.120 Oil and Gas Authority (Fees) Regulations (SI 2016/904)............................................................... I–4.34 Onshore Hydraulic Fracturing (Protected Areas) Regulations (SI 2016/??).............................................. I–9.28 reg 2........................................................................ I–9.27 reg 3........................................................................ I–9.27 Petroleum (Exploration and Production) (Landward Areas) (Amendment) Regulations (SI 2016/1029) reg 2........................................................................ I–4.79 Petroleum (Transfer of Functions) Regulations (SI 2016/898).................................................................... I–5.33 reg 2........................................................................ I–4.10

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TABLE OF EUROPEAN LEGISLATION Treaties 1957 Treaty Establishing the European Community.......... II–11.09 2009 Treaty of the Functioning of the European Union (TFEU)...................................................................... II–11.09 Art 4(3)..................................................................... II–11.62 Art 101.................... I–6.64, II–11.09, II–11.10–17, II–11.61, II–11.64 Art 101(1)...................II–11.14, II–11.31, II–11.41, II–11.43, II–11.45, II–11.47–9 Art 101(3)...................II–11.17, II–11.30, II–11.32, II–11.35, II–11.61 Art 102.................... I–6.64, II–11.09, II–11.18–20, II–11.51, II–11.53, II–11.58 Directives 1968 68/414/EEC imposing an obligation to maintain minimum stocks of crude oil and/or petroleum products........................................................... I–3.26, I–3.31 Art 1��������������������������������������������������������������������������� I–3.26 Art 6��������������������������������������������������������������������������� I–3.26 Art 7��������������������������������������������������������������������������� I–3.26 1972 72/425/EEC of 19 December amending Directive 68/414/EEC................................................................. I–3.27 1973 73/238/EEC of 24 July on measures to mitigate the effects of difficulties in the supply of crude oil and petroleum products...................................................... I–3.28 Art 1��������������������������������������������������������������������������� I–3.28 Art 3��������������������������������������������������������������������������� I–3.28 Art 5��������������������������������������������������������������������������� I–3.28 1979 79/409/EEC Birds Directive....................................... I–11.09 Art 1������������������������������������������������������������������������� I–11.11 Art 4(1)...................................................................... I–11.08 Art 4(2)...................................................................... I–11.08 1982 82/501/EEC Seveso Directive..................................... I–10.38 1985 85/337/EEC Environmental Impact Assessment................................................... I–11.16, I–12.67 Art 1��������������������������������������������������������������������������� I–4.26 Art 2(1)........................................................................ I–4.26

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1989

Art 4(2)........................................................................ I–4.26 Arts 5–7....................................................................... I–4.26 Annex 1..................................................................... I–11.73 Annex 2..................................................................... I–11.72 Annex 2(2)(f)............................................................... I–4.26 Annex 2(2)(g).............................................................. I–4.26 89/391/EEC Framework Safety at Work Directive.................................................................... I–10.46 Art 2������������������������������������������������������������������������ II–14.44 Art 16(1).................................................................... I–10.46 1989 89/655/EEC on minimum safety and health requirements for the use of work equipment by workers at work........................................................ I–10.46 1989 89/656 Personal Protective Equipment at Work Directive.................................................................... I–10.46 1989 89/686/EC Personal Protective Equipment Directive.................................................................... I–10.46 1990 90/269/EEC Manual Handling Directive................... I–10.46 1990 90/270/EC Display Screen Equipment Directive........ I–10.46 1992 92/43/EEC Habitats Directive.........I–4.24–5, I–4.27, I–11.09 Art 4������������������������������������������������������������������������� I–11.08 Art 4(2)...................................................................... I–11.08 Art 6(3)...................................................................... I–11.14 Art 6(4)...................................................................... I–11.14 Annex IV(a)............................................................... I–11.11 1992 92/85/EEC Pregnant Workers Directive..................... I–10.46 1992 92/91/EEC Extractive Industries Directive...................................................... I–10.46, I–10.59 1993 93/104/EC Working Time Directive.......... II–14.44, II–14.73, II–14.80 Art 1(3)..................................................................... II–14.44 1994 94/22/EC Hydrocarbons Licensing Directive.............. I–4.11, I–4.14, I–4.36 Art 3��������������������������������������������������������������������������� I–4.19 Art 3(2)(a)................................................................... I–4.20 Art 3(2)(b)................................................................... I–4.22 1994 94/33/EC on the protection of young workers........... I–10.46 1995 95/63/EC................................................................... I–10.46 1996 96/82/EC Seveso II Directive...................................... I–10.38 1997 97/11/EC......................................... I–4.26, I–11.16, I–12.67 1998 98/93/EC of 14 December amending Directive 68/414/EEC................................................................. I–3.31 Preamble, para 2.......................................................... I–3.31 Preamble, para 9.......................................................... I–3.31 Preamble, para 11........................................................ I–3.31

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1999 2000 2001

Art 1(1)........................................................................ I–3.31 Art 1(4)........................................................................ I–3.31 Art 1(4)(3)................................................................... I–3.31 Art 1(6)........................................................................ I–3.31 Art 1(7)........................................................................ I–3.31 1999/63/EC Seafarers Directive................................ II–14.45 Art 1������������������������������������������������������������������������ II–14.45 Art 2������������������������������������������������������������������������ II–14.45 2000/34/EC Working Time Directive......... II–14.44, II–14.45 Art 20(2)................................................................... II–14.47 2001/42/EC Strategic Environmental Assessment Directive.......................................................... I–4.24, I–4.27 Art 2(b)........................................................................ I–4.27 Art 3(1)........................................................................ I–4.27 Art 3(2)(a)................................................................... I–4.27 Art 3(2)(b)................................................................... I–4.27 Art 3(3)........................................................................ I–4.27 Art 5��������������������������������������������������������������������������� I–4.27 Art 6��������������������������������������������������������������������������� I–4.27 Art 7��������������������������������������������������������������������������� I–4.27 Art 8��������������������������������������������������������������������������� I–4.27 2001 2001/77/EC on the promotion of electricity produced from renewable energy sources in the internal electricity market.................... I–3.30, I–3.63, I–3.73 Art 3��������������������������������������������������������������������������� I–3.30 2001 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants........................................................................... I–3.37 Art 2(10)...................................................................... I–3.37 2003 2003/35/EC................................................................. I–4.26 2003 2003/105/EC............................................................. I–10.38 2004 2004/35/EEC Environmental Liability Directive....... I–10.60, I–11.105, I–11.106 2006 2006/67/EC imposing an obligation on Member States to maintain stocks of crude oil and/or petroleum products.......................................... I–3.31, I–3.32 2008 2008/52/EC on certain aspects of mediation in civil and commercial matters............................................ II–15.46 2008 2008/98/EC Waste Directive.................................... I–11.105 2009 2009/24 on the legal protection of computer programs Recital 3................................................................... II–12.23 2009 2009/28 Renewable Energy Directive.............. I–3.30, I–3.73 Art 3(1)........................................................................ I–3.30 Art 3 (2)...................................................................... I–3.30 Art 17.......................................................................... I–3.63

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Art 19.......................................................................... I–3.63 Annex 1....................................................................... I–3.30 2009 2009/31/EC on the geological storage of carbon dioxide......................................................................... I–4.26 2009 2009/119/EC................................................... I–3.31, I–3.32 Art 3(1)........................................................................ I–3.31 Art 5��������������������������������������������������������������� I–3.31, I–3.35 Art 7��������������������������������������������������������������������������� I–3.35 Art (9)(2)..................................................................... I–3.35 Art 13.......................................................................... I–3.31 Art 19.......................................................................... I–3.31 2010 2010/75/EU Industrial Emissions Directive.................. I–3.40 Art 32.......................................................................... I–3.40 Art 33.......................................................................... I–3.40 2013 2013/20/EU Platform Directive...... I–11.04, I–11.95, I–11.97 Art 1������������������������������������������������������������������������� I–11.04 Art 3������������������������������������������������������������������������� I–11.95 Art 6������������������������������������������������������������������������� I–11.95 Art 6(6)...................................................................... I–11.95 Art 7������������������������������������������������������������������������� I–11.96 Art 8(3)...................................................................... I–11.95 Art 11........................................................................ I–11.95 Art 28........................................................................ I–11.96 2013 2013/30/EU Offshore Safety Directive......I.1.16, I–10.60–76, I–11.105 2014 2014/89/EU Framework Directive on maritime spatial planning........................................................... I–4.30 Art 8(2)........................................................................ I–4.30 2016 2016/943 Trade Secrets Directive.............................. II–12.31 Art 2������������������������������������������������������������������������ II–12.31 Regulations 2000 1346/2000 on Insolvency Proceedings...................... II–10.96 2003 1/2003 Modernisation Regulation............. II–11.17, II–11.53 Art 1������������������������������������������������������������������������ II–11.21 Art 23(2)(a).............................................................. II–11.01 2006 1907/2006 Registration, Evaluation, Authorisation and Restriction of Chemicals (REACH) Regulations.................................................................. I–9.26 2010 330/2010 on block exemption for vertical agreements................................................. II–11.17, II–11.56 Art 3������������������������������������������������������������������������ II–11.56 Art 4(a)..................................................................... II–11.58 2010 1217/2010 on block exemption for research and development agreements........................................... II–11.17

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2010 1218/2010 on block exemption for specialisation agreements................................................. II–11.17, II–11.48 Art 3 II–11.48 Art 4(a)..................................................................... II–11.48 2014 316/2014 Technology Transfer Block Exemption..... II–12.27 Art 1(1)(i)................................................................. II–12.27 Art 1(1)(i)(i).............................................................. II–12.27 Art 1(1)(i)(ii)............................................................. II–12.27 Art 1(1)(i)(iii)............................................................ II–12.27 2015 848/2015 on Insolvency Proceedings........................ II–10.96 Decisions 1977 Council Decision 77/706/EEC of 7 November on the setting of a Community target for a reduction in the consumption of primary sources of energy in the event of difficulties in the supply of crude oil and petroleum products...................................................... I–3.29 Preamble...................................................................... I–3.29 Art 1��������������������������������������������������������������������������� I–3.29 2011 Commission Decision 2011/13/EU.............................. I–3.63 2012 Commission Decision M6477 (BP/Chevron/Eni/ Sonangol/Total/JV).................................................... II–11.27 2013 Commission Decision M6801 (Rosneft/TNK).......... II–11.27 2013 Commission Decision M6910 (Gazprom/ Wintershall/Target Companies)................................. II–11.27 2014 Commission Decision M7316 (DNO/Marathon)...... II–11.27 2014 Commission Decision M7318 (Rosneft/Morgan Stanley Global Oil Merchanting Unit)...................... II–11.27 2015 Commission Decision M7631 (Royal Dutch Shell/ BG Group)................................................................ II–11.27

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TABLE OF INTERNATIONAL INSTRUMENTS 1948 Inter-Governmental Maritime Consultative Organization Convention Art 1������������������������������������������������������������������������� I–12.10 Art 29........................................................................ I–12.10 1956 CMR (Convention on the Contract for International Carriage of Goods by Road).......................... II–2.29, II–2.30 1958 Continental Shelf Convention..........I–8.04–5, I–8.07, I–8.11, I–8.16, I–8.34, I–10.04, I–12.06, I–12.09 Art 1������������������������������������ I–8.05, I–8.16, I–8.31, II–12.15 Art 2��������������������������������������������������������������������������� I–8.04 (1)������������������������������������������������������������ I–4.09, I–12.07 Art 5 (1)������������������������������������������������������������������������ I–12.07 (2)������������������������������������������������������������������������ I–12.07 (5)������������������������������������������������������������������������ I–12.07 Art 6��������������������������������������������������������������������������� I–8.07 (1)�������������������������������������������������������������������������� I–8.08 (2)�������������������������������������������������������������������������� I–8.08 Art 60(3).................................................................... I–12.08 Art 80........................................................................ I–12.08 New York Convention (Convention on the Recognition and Enforcement of Foreign Arbitral Awards)..................................................................... II.15.81 Art V(1)..................................................................... II.15.68 Art V(2)(b)................................................................. II.15.81 Territorial Sea Convention........................................... I–8.31 Art 10.............................................................. I–8.31, I–8.32 Art 11.......................................................................... I–8.31 1960 OECD Convention...................................................... I–3.16 1965 Denmark-Norway Continental Shelf Delimitation Agreement................................................................... I–8.08 UK-Netherlands Continental Shelf Delimitation Agreement.................................................. I–8.08, II–3.52–7 Art 1�������������������������������������������������������������������������� II–3.52 Art 2������������������������������������������������������������� II–3.52, II–3.55 UK-Norway Continental Shelf Delimitation Agreement.................................................. I–8.08, II–3.58–9 Art 4������������������������������������������������������������� II–3.58, II–3.60

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1966 ICSID (International Convention on the Settlement of Investment Disputes)............................................. II.15.48 UK-Denmark Continental Shelf Delimitation Agreement................................................................... I–8.08 1968 Sweden/Norway Continental Shelf Delimitation Agreement................................................................... I–8.08 1969 International Convention on Civil Liability for Oil Pollution Damage.................................................... I–11.104 1970 Patent Co-operation Treaty....................................... II–12.15 1971 Denmark-Germany-Netherlands Continental Shelf Delimitation Agreement............................................... I–8.12 International Convention on the Establishment of an International Fund for Compensation for Oil Pollution Damage.................................................... I–11.104 UK-Germany Continental Shelf Delimitation Agreement................................................................... I–8.12 1972 London Dumping Convention...............I–12.06, I–12.11–12, I–12.22, I–12.37 Annex I........................................................ I–12.11, I–12.12 Annex II..................................................................... I–12.11 Annex III................................................................... I–12.12 (a)(ii)..................................................................... I–12.12 Annex IV(1)............................................................... I–12.12 Oslo Convention for the Protection of Marine Pollution by Dumping from Ships and Aircraft........ I–12.13, I–12.17, I–12.22, I–12.24, I–12.36 1973 European Patent Convention.................................... II–12.15 MARPOL 73/73 (International Convention for the Prevention of Pollution from Ships) Annex IV..................................................... I–11.65, I–11.71 Annex V...................................................... I–11.65, I–11.71 Annex VI................................................................... I–11.51 1974 IEP Agreement............................................I–3.16–21, I–3.32 Art 1��������������������������������������������������������������������������� I–3.17 Art 2 (1)�������������������������������������������������������������������������� I–3.17 (2)�������������������������������������������������������������������������� I–3.17 Art 5��������������������������������������������������������������������������� I–3.18 Art 7 (3)�������������������������������������������������������������������������� I–3.19 (4)�������������������������������������������������������������������������� I–3.18 Art 8��������������������������������������������������������������������������� I–3.19 Art 13.......................................................................... I–3.18 Art 17(1)...................................................................... I–3.19 Ch III........................................................................... I–3.19

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Paris Convention for the Prevention of Marine Pollution from Land-based Sources........................... I–12.13 1976 Frigg Field Agreement.............................. II–3.59–61, II–3.63 Art 2�������������������������������������������������������������������������� II–3.60 1979 Murchison Field Agreement........................... II–3.59, II–3.63 Statfjord Field Agreement.................II–3.59, II–3.62, II–3.63 1980 Rome Convention on the Law Applicable to Contractual Obligations............................................II-14.38 1982 UNCLOS (UN Convention on the Law of the Sea).... I–8.14, I–8.16, I–8.18, I–12.06, I–12.81 Preamble.................................................................... I–12.08 Art 57.......................................................................... I–4.01 Art 60(3)....................................................... I–12.10, II–2.93 Art 74.......................................................................... I–8.23 Art 76.................................................. I–8.16, I–8.17, I–8.24 (3)�������������������������������������������������������������������������� I–8.17 (8)�������������������������������������������������������������������������� I–8.23 (10)......................................................................... I–8.23 Art 77(3)...................................................................... I–8.23 Art 83.......................................................................... I–8.23 Art 84.......................................................................... I–8.17 Art 121(3)........................................................ I–8.32, I–8.33 Art 123....................................................................... II–3.51 Art 298(1).................................................................... I–8.35 Art 311(1).................................................................... I–8.15 Pt V II–3.15 Pt XIV......................................................................... I–8.29 Pt XV.......................................................................... I–8.35 Annex II Art 9............................................................. I–8.24 1985 UNCITRAL Model Law on International Commercial Arbitration............................................ II–15.66 1988 UK/Ireland Continental Shelf Delimitation Agreement................................................................... I–8.21 1992 Markham Agreement.............................................. II–3.53–7 Art 5�������������������������������������������������������������������������� II–3.54 Art 10......................................................................... II–3.55 Art 16......................................................................... II–3.54 Art 23......................................................................... II–3.55 OSPAR Convention (Convention for the Protection of the Marine Environment in the North-East Atlantic)..............I–5.23, I–11.36, I–11.38, I–11.44, I–11.45, I–11.46, I–11.47, I–12.06, I–12.13–18, I–12.19, I–12.36, II–2.93 Art 1 (a)������������������������������������������������������������������������� I–12.13

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(f)������������������������������������������������������������������������� I–12.13 (g)������������������������������������������������������������������������� I–12.13 Art 2 (1)(a)..................................................................... I–12.14 (2)(a)..................................................................... I–12.15 (2)(b)..................................................................... I–12.15 (3)(b)..................................................................... I–12.15 Annex III Art 5(1)................................................................. I–12.16 Art 5(3)................................................................. I–12.17 Art 6..................................................................... I–12.18 Art 8..................................................................... I–12.18 Art 10................................................................... I–12.18 App 1......................................................................... I–12.15 1994 Energy Charter Protocol on Energy Efficiency and Related Environmental Aspects.................................... I–3.22 Energy Charter Treaty......................I–3.22–5, I–3.68, I–4.13 Annex 1....................................................................... I–3.22 Art 2��������������������������������������������������������������������������� I–3.22 Art 19.......................................................................... I–3.22 (2)�������������������������������������������������������������������������� I–3.22 Art 26........................................................................ II.15.48 1995 WTO GATS (General Agreement on Trade in Services) Art XXIII................................................................... II.15.48 1996 Protocol to London Convention.................. I–12.06, I–12.37 Art 3 (1)������������������������������������������������������������������������ I–12.37 (2)������������������������������������������������������������������������ I–12.37 Art 4(1.2)................................................................... I–12.37 Annex I...................................................................... I–12.37 Annex II..................................................................... I–12.37 2001 International Convention on Civil Liability for Bunker Oil Pollution Damage.................................. I–11.104 2002 UNCITRAL Model Law on International Commercial Conciliation.......................................... II–15.66 2005 UK-Norway Framework Treaty.............................. II–3.63–5 Art 1 (14)........................................................................ II–3.64 (15)........................................................................ II–3.64 Art 3�������������������������������������������������������������������������� II–3.64 (1)(1)...................................................................... II–3.64 (2)(1)...................................................................... II–3.64 (2)(2)...................................................................... II–3.64 (3)������������������������������������������������������������������������� II–3.64 (4)������������������������������������������������������������������������� II–3.64

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(7)������������������������������������������������������������������������� II–3.64 (9)(1)...................................................................... II–3.64 (12)........................................................................ II–3.64 Art 5�������������������������������������������������������������������������� II–3.64 Annex D..................................................................... II–3.64 (2)������������������������������������������������������������������������� II–3.64 (4)������������������������������������������������������������������������� II–3.64 (5)������������������������������������������������������������������������� II–3.64 2010 Vienna Convention (Convention on Contracts for the International Sale of Goods)................................. II–8.02 Arts 61–70.................................................................. II–8.02

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INTRODUCTION AND CONTEXT

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CHAPTER II-1 OIL AND GAS LAW ON THE UNITED KINGDOM CONTINENTAL SHELF: CURRENT PRACTICE AND EMERGING TRENDS IN CONTRACTING AND COMMERCIAL LAW Greg Gordon and James Cowie

INTRODUCTION As has already been observed in the introductory chapter to the II-1.01 first volume of this work, a great deal has happened in the seven years since the second edition of this book was published, both in the specific context of the oil and gas industry and in world affairs at large.1 On the United Kingdom Continental Shelf (UKCS), government and industry has had to wrestle with the problems of the ever-increasing maturity of (at least parts of) the offshore area, and with the complications and technicalities of implementing the MER UK obligation that is the principal legacy of the Wood Review – which, in itself, was conceived as part of the answer to the problem of maturity. They have also had to contend with the ongoing fall-out from the Deepwater Horizon disaster and the consequences of a material change to supply dynamics of the global oil market, and a resultant sharp and prolonged drop in oil price. As we have already seen, these issues have had significant consequences for resource management and regulatory law. They are also highly germane to commercial law and practice. Following Arnold v Britton,2 commercial context may not be quite as influential as once it was upon the question of how to interpret a contractual provision;

  See para I-1.01.   Arnold v Britton & ors [2015] UKSC 36. This case is further discussed at paras II-6.36 to II-6.44.

1 2

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however, there can be no doubting the very real and pervasive influence that context has upon legal commercial practice. The challenges (and corresponding opportunities)3 identified above do not impact merely upon the public law and regulatory world; they flow through into the commercial world too. They influence the risk and upside of investments. They play a determining role in whether and how deals are done and influence the availability and structure of funding. They fuel the industry’s desire to reduce transactional costs, although – as was previously noted in the second edition of this work – a certain trend towards simplification was already previously identifiable.4 Moreover, in the post-Wood, MER-driven environment, the worlds of regulation and commercial practice have never been so interconnected. The light-handed regulatory approach of the Department of Energy and Climate Change (DECC) and its predecessor departments has been replaced by the hands-on approach of the Oil and Gas Authority (OGA), a regulator that has been established with a remit to – among other things – attend meetings, interpose itself in commercial disputes and encourage (and perhaps coerce) parties to alter legal practices and commercial behaviours. This inevitably changes commercial practice. New layers of complication are added: complying with competition law becomes a tricky business when the state is, while wearing its OGA hat, instructing you to collaborate with your competitors while simultaneously, in its guise as the Competition and Markets Authority, saying, “but not too much”. But the change may be beneficial, too. Already it is clear that there is renewed focus upon cost-cutting through standardisation and innovative contractual models. The extent to which this

 The worker who has lost his or her job as a result of a drop in the oil price would be hard pressed to see the downturn as anything but bad news. However, viewed from another perspective, the opportunity is clear. For any investor with access to finance who believes that the oil price will recover, the downturn provides a superb opportunity to acquire under-priced assets. 4  As was noted in the introduction to the second edition, “Maturity is a factor that impacts not just upon the state’s interactions with the industry, but also upon the commercial contracts which industry players enter into between themselves. The reducing size of new discoveries and the corresponding increase in unit costs means that economies must be found where possible if developments are to continue to be profitable. This is an environment where waste and over-elaboration are to be avoided. Legal costs are among those which the industry has targeted as ones which may be cut without having a deleterious effect upon safety. This factor, together with the desire to accelerate the pace of the negotiation process (which desire is driven at least in part by the need to develop reserves before the obsolescence of critical infrastructure) has led to the increasingly widespread use of standardised contracts and the launch of initiatives such as the Industry Mutual Hold Harmless scheme and the Master Deed initiative.” G Gordon, J Paterson and E Üșenmez, Oil and Gas Law: Current Practice and Emerging Trends (2nd edn, 2011), para 1.14. 3

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has been brought about by the activities of the OGA and the extent to which it may be attributed to the low oil price is not yet known, and is perhaps not knowable, given the problems of attribution which occur when a change occurs after two variables have altered more or less simultaneously. Perhaps only time and an increase in oil price will tell. The industry has previously taken an interest in such things in other times of low oil price, only for that focus to fade, at least to some extent, when the price recovers. If the industry remains committed to simpler and/or innovative contracting processes in a time of high oil price, there may be grounds for arguing that the OGA’s intervention has succeeded in forcing a cultural shift. As a result of the matters just discussed, and of the more run of II-1.02 the mill, incremental changes to law made in the ordinary course of events,5 the treatment of commercial and contracting issues in the third edition of this work was inevitably going to be somewhat lengthier than in the second. However, the editors have, in addition, decided to significantly increase the coverage of the particular issues discussed. Previously seven chapters were given over to commercial and contracting issues; we now have fourteen. Doubling the number of topics under discussion has, as already noted, required us to split the book into two volumes: one devoted to issues of resource management and regulatory law, and the other to commercial and contractual issues. It has also allowed us both to expand our treatment of upstream contractual and commercial issues and to depart from the rather narrow focus of the first two editions, which were almost exclusively concerned with that sector of the industry. The process of expanding the discussion of upstream matters has been achieved by adding a new chapter on financing and insolvency in the upstream oil and gas sector6 and by adding commentaries on drilling contracts7 and contractual standardisation.8 The introduction of more breadth has come with a new chapter on transportation agreements,9 moving us into the midstream, before finally we expand our treatment of the downstream by including a new chapter on oil sales agreements.10 We have also been able to reintroduce a chapter  As we shall see, significant changes have taken place in general contract law since the second edition, perhaps most obviously in contractual interpretation and the treatment of penalties. 6   J Allan and S Aitken, “Finance, Security and Insolvency in the Upstream Oil and Gas Sector”, Chapter II-10. 7   G May and E Brazier, “Dissecting the Dayrate Drilling Contract”, Chapter II-4. 8   L Dawson, “Contractual Standardisation and the LOGIC Standard Contracts”, Chapter II-5. 9   L Petrie, “Commercial Agreements and Issues in the Transportation of Oil and Gas”, Chapter II-7. 10   Y Abul Failat, “Petroleum Sales Agreements,” Chapter II-8. 5

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present in the first edition but which was omitted from the second for reasons only of timing, Employment Issues in the Upstream Oil and Gas Sector, authored by Sarah Arnell. CHAPTER-BY-CHAPTER OUTLINE AND INDICATION OF CROSS-CUTTING THEMES II-1.03 The chapters making up this volume have been subdivided into two sections. The first seven substantive chapters focus on contractual matters, being in essence a series of commentaries on specific contract types11 and/or discussions of contractual issues of particular relevance to the oil and gas industry.12 The second seven are unified by the theme of law in context: in other words, they consider the particular issues which arise when selected commercial law topics are examined within the specific setting of oil and gas operations. II-1.04 The first part of the book opens with Scott Styles’ chapter on joint operating agreements. These agreements are fundamental to the way in which offshore oil and gas operations are undertaken in the UKCS. Styles’ account explains the factors which drive the industry towards joint operations, and describes and critically comments upon the key features of such agreements, noting, in particular, that the concerns that have historically existed about the enforceability of the default provisions commonly seen in these agreements may have been overstated and would seem to have further receded as a result of the UK Supreme Court’s decision in El-Makdessi v Cavendish Holdings BV.13 II-1.05 Chapter II-3, by Nicola MacLeod, continues the theme of upstream co-operative production contracts by addressing the issue of unitisation. This is a particular legal response to the facts, first, that oil and gas fields may not lie wholly within one block of licensed acreage but may lie partly within another contiguous block which is allocated to a different licensee and, secondly, that oil and gas migrate once a well is drilled into a reservoir. In the absence of any provision to the contrary, the rule of capture in property law might lead to competitive drilling which would be detrimental to the reservoir as a whole. Unitisation is the means by which affected licensees agree to treat the reservoir as one unit, to develop it as such and to share the production equitably irrespective of which part of the reservoir it has   See eg Chapter II-4.   See eg Chapter II-6. Chapter II-5 is a hybrid of the two; it commences with a discussion of standardisation issues in general and then moves on to provide a commentary on selected issues in the Leading Oil and Gas Industry Competitiveness (LOGIC) standard form contracts. 13   [2015] UKSC 67. 11 12

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come from. Unitisation has always been a live issue on the UKCS, but has become increasingly important as the province has matured because the area of the blocks being licensed is now considerably less than was previously the case, making it more likely that any discoveries, even of the small size now more usually encountered, will underlie more than one block. Having examined the concept of unitisation, MacLeod goes on to look at the way in which it operates within the UK. This depends in particular on powers vested in the OGA in this regard under the licence, which enable it, in the ultimate, to serve a notice compelling the preparation of a unitised development scheme. The mere existence of this power appears to have been sufficient to ensure that affected licensees actually do discuss and produce agreed development programmes for the approval of the Secretary of State. MacLeod goes on to examine the unitisation and unit operating agreement that is required in such circumstances, as well as the sorts of issues that commonly arise, before concluding with a consideration of unitisation across international borders. Chapter II-4 addresses the day-rate drilling contract. As drilling II-1.06 involves the deployment and use of extremely sophisticated and expensive equipment, co-operation between a range of workers employed by a multiplicity of companies and the making of a direct connection between the surface and the underground reservoir, these contracts are among the most complex and challenging of the oilfield service contracts. May and Brazier have provided a detailed and comprehensive commentary on the day-rate drilling contract’s principal terms. Unsurprisingly, given what has been said above, the need for parties to identify and carefully manage all material risks features prominently in the authors’ analysis. As noted above, issues of standardisation, simplification and II-1.07 innovation are currently to the fore as a result of the low oil price and the need for parties to implement MER UK.14 Lorna Dawson’s Chapter II-5 addresses each of these issues. After a discussion of the development of standardisation within the context of joint operating agreements (JOAs) and field agreements, it moves on to discuss the benefits (as well as the pitfalls) of contractual standardisation in oilfield service contracts, before providing an overview of the current LOGIC suite of Standard Contracts, a commentary on their key terms and locating UK practice within a broader comparative context. It concludes by noting what may prove to be the next step in the simplification process: not merely standardisation, but automation.   Although the contracting sector is in general under no obligation to implement MER, the fact that the oil companies with whom it interacts are under such an obligation has the effect of indirectly joining the contracting community into the process.

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II-1.08 Chapter II-6, by Greg Gordon, addresses the key contractual issue of risk allocation in oilfield service contracts. Gordon indicates how the industry’s practice departs quite radically from common law presumptions with respect to risk allocation. The reasons for this are related, first, to the fact that oil and gas operations are subject to multiple risks and, second, to the prevalence of contractors and subcontractors in the industry. There is accordingly the potential for significant losses and a tendency towards complex contractual arrangements. Leaving the allocation of risk to the general law is, therefore, likely to lead to problems – particularly economic inefficiencies – which could hamper the development of the industry, and the industry has accordingly responded by evolving alternative methods of allocating risk, which Gordon discusses under three main headings: indemnity and hold harmless provisions; liability for consequential losses; and overall caps on liability. The most significant alternations to the chapter, in this third edition, are with regard to contractual interpretation, where the author undertakes the task of reconciling Arnold v Bennett, the Supreme Court’s leading decision on contractual interpretation in general, with the older decisions decided specifically in oil and gas cases. Gordon argues against cases such as Orbit Valve, which adopted a strict lexicon-based approach to interpretation, and in favour of those, such as Nelson and to some extent London Bridge, which adopted a more broadly based textual approach, which, the author contends, is in sympathy with the law as laid down by the Supreme Court. II-1.09 Chapter II-7 is concerned with transportation and other related agreements. In a mature province where new finds are, generally speaking, small and capable by being developed only if the licensees are in a position to make use of existing infrastructure owned by others, the issue of access to that infrastructure is of great significance. The book has never neglected that issue: Uisdean Vass’s chapter (I-6) is the third he has provided for us on the regulatory dimension of this question.15 This, however, is only part of the issue. The suite of commercial agreements necessary to get oil from well to shore also needs to be considered, and this is something that was covered only in passing in previous editions. Laura Petrie’s chapter plugs this gap by sketching the commercial context, setting out the range of agreements necessary to permit evacuation of hydrocarbon by pipeline (including confidentiality, proximity, construction and tie in, and transportation agreements) and discussing the key commercial terms and risk allocation provisions, which differ markedly from  Property law issues pertaining to onshore transportation by pipeline have also been covered since the first edition of this book and this continues with Roderick Paisley’s Chapter II-13.

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agreement type to agreement type due to the particular commercial imperatives of the contracts concerned. Petrie then moves on to consider the likely impact of decommissioning and the role of the OGA, concluding that while the OGA may impact the manner in which such agreements are negotiated, ultimately, their nature and commercial terms are likely to be unchanging. In a new chapter commissioned for the third edition of this book, II-1.10 “Petroleum Sales Agreements” (Chapter II-8), Abul Failat covers important downstream contracts in the oil and gas industry. In between the producer and the final consumer, oil and gas will be traded, sometimes multiple times, among producers, refiners, traders and banks, etc. The unique characteristics of oil, gas and liquefied natural gas (LNG) have led to the development of specialised contracts for the sale and purchase of these hydrocarbons, which is the focus of this chapter. The first section looks at sale and purchase agreements for crude oil (oil SPAs). The form of these contracts is analysed before a discussion of the special provisions associated with oil SPAs, including title, risk, quality and payment. A similar approach is taken in relation to gas sales agreements (GSAs). An examination of the different destinations of gas under GSAs is followed by a detailed analysis of the key terms under the contracts. The characteristics of LNG have merited a separated discussion of LNG sale and purchase agreements. The chapter concludes with a discussion of the security (collateral support) typically required under these downstream contracts. We come now to the strand of chapters which address a particular II-1.11 commercial or corporate law topic within the specific oil and gas context. The first such chapter (Chapter II-9, authored by Norman Wisely) is on the issue of acquisitions and disposals of upstream oil and gas interests. With the UKCS having moved from its pioneering state into maturity, it is to be expected that there should be some degree of realignment of interests with the exploration- and development-focused specialists who generally help to open up new provinces looking to divest of assets, and late-life specialists who are adept at maximising production from part-depleted assets looking to move in. Both companies and the state therefore share an interest in ensuring that commercial practice allows for a smooth transfer of assets. Wisely notes that such transfers of licence interests have increased significantly in recent years. In his chapter he focuses in particular upon asset sales for a cash consideration and examines in turn acquisition structures; the due diligence process; approvals and consents; pre-emption and restrictions on assignment and consents and approvals; acquisition agreements; and completion. Chapter II-10 is another new chapter commissioned for this II-1.12 edition. As has been noted above, the UKCS is now at a stage in

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its development where if it is to continue as a viable oil and gas province, it needs to attract new entrants. However, this will not be possible unless finance is available to fund the acquisition. In practice, the availability of finance at a reasonable rate generally depends upon the availability of security. Jenny Allan and Sian Aitken’s chapter provides an overview of the various forms of finance available, focusing in particular upon the options which are more unusual or specific to the UK upstream oil and gas industry. The chapter provides an indication of the circumstances (including the project lifecycle) that might impact upon financing availability and option choice. The recurrent theme of risk management and mitigation is again central to this chapter, in this case, viewed primarily from the perspective of the investor. The chapter closes with a consideration of insolvency. While the UKCS must bring in new entrants if it is to continue as a viable oil province, it is an inescapable fact that this means the introduction of the province of smaller operators less well able than the majors to ride out the storms of sustained drops in oil price or project failure, for example. This in turn means that insolvency issues – traditionally somewhat neglected on the UKCS – now arise in sharper focus than ever before. An overview of the main options available when an oil company approaches insolvency is provided, and the chapter discusses selected key issues in the administration of an insolvent upstream oil company. II-1.13 We then move onto two chapters each of which deals with commercial issues that have been impacted by the Wood Review and the resultant obligation to implement MER UK. Judith AlderseyWilliams’ Chapter II-11 addresses competition law and the upstream oil and gas business, Martin Ewan’s Chapter II-12 law and technology in the oilfield. Aldersey-Williams notes in her introduction both the serious consequences that flow from infringement and the difficulty of actually complying with the rules. She proceeds by outlining first of all what it is that competition law prohibits in the form of anticompetitive agreements and abuse of a dominant position, before considering how one decides whether one needs to take account of only UK law or to look also at European law. Aldersey-Williams then examines the issue of defining the relevant market that will require analysis in terms of competition law as well as the difference between vertical and horizontal agreements before moving on in the second half of her chapter to look at common competition issues that arise in upstream oil and gas business. As was noted above, the Wood Review’s focus upon co-operation has placed competition law – a means by which legal systems place barriers in the way of at least certain forms of collaboration and information-sharing – in sharp focus. Aldersey-Williams’ chapter has been extensively rewritten to

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take account of the tension between these competing legal demands, and to suggest strategies for resolving it. The inter-relationship between factors such as, on the one hand, II-1.14 the fact of maturity and the high cost of operations in the UKCS and, on the other, the law of intellectual property may not be immediately apparent. However, as Ewan notes, the connection between these factors is clear. The days of elephantine finds are probably over – in the developed part of the UKCS, at least. To get oil, the industry must be more creative than ever before. It must develop new means of finding oil and new techniques of recovering higher proportions of each find. And it must develop new ways of carrying out exploration, development and production activity at reduced cost. There is, therefore, great commercial value in innovation: value which is lost if innovators are not scrupulously careful to protect their own interests. But in an industry where specialist contractors work side by side with each other and where the operator will have overall control of operations, it is practically impossible to keep new tools and processes wholly “under wraps”. Ewan’s chapter discusses the problems faced by the innovating contractor in greater detail, noting throughout the support mechanisms for innovation that are starting to develop as the industry begins to engage with the need to implement MER UK and the Wood Review’s broader vision for the future. We have already noted the significance of access to infrastructure II-1.15 and transportation of hydrocarbons in the offshore area. However, oil and gas is transported by pipeline near-shore and onshore too. In Chapter II-13, Roderick Paisley focuses on the transport of oil and gas by pipelines passing through land in private ownership, which, as he notes, may well arise once they cross into territorial waters. His chapter is accordingly concerned with real rights, that is, ownership, leasehold and servitudes. Of these three, the most significant (and perhaps the least widely understood) is servitude. The bulk of the chapter is accordingly devoted to a consideration of how this right can be used to allow a pipeline to be laid across private land and oil and gas to be transported through it for commercial purposes – including the question of what happens when it is proposed to transport a different gas and in the opposite direction from originally envisaged, as might be contemplated in the case of a carbon capture and storage scheme. The oil and gas industry is characterised by working patterns II-1.16 and practices that may seem to be unusual when compared to other industries. Workers spend extended periods of time travelling to work at remote locations. Particularly when working offshore, they spend extended periods of time at their work location, substantially cut off from family and friends and unable to fully escape the workplace environment, even when at rest within an accommodation

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module. Expatriate working, or regular long-distance – sometimes inter-continental – commutes are commonplace; so too are working relationships that may fall short of full contracts of employment. It is therefore not surprising that the oil and gas industry has proved to be a fertile area for the development of employment law, particularly in areas such as workers’ rights and the territorial extent of the relevant UK law. Sarah Arnell’s Chapter II-14 provides a detailed commentary on a selection of employment issues of particular interest to the oil and gas industry. II-1.17 In the final chapter of the book, Margaret Ross and Valerie Allan consider dispute management and resolution within the oil and gas industry. They note that the specific nature of oil projects has historically given rise to a specific culture of dispute management and culture; however, given the changing face of the industry as a result of maturity, it cannot be taken for granted that this will continue in the future. Thus, the fact that delays are often extremely expensive means that dispute resolution processes must be fast and efficient, while the fact that parties to disputes are usually “repeat players” rather than “one-shotters” means that there is frequently a reluctance to litigate and a preference for private and flexible alternatives. But will this continue, with industry players now increasingly more diverse and frequently holding smaller portfolios – meaning that a dispute in any one project is simply more significant than before? This – together with the sustained, sharp drop in oil price – might seem to point in the direction of a more litigious industry. And yet, the Wood Review seeks to encourage a more, rather than less, co-operative approach, and wishes to see the OGA become proactive in managing the handling of disputes. Will these two contrasting imperatives wrestle each other to a standstill, meaning that in practice little changes? Will the OGA succeed in helping the industry to implement major cultural change? Here, as elsewhere, the fact of increasing maturity and the industry and its regulators’ responses to it continue to throw up new challenges and to encourage the evolution of new solutions.

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COMMENTARY ON SPECIFIC CONTRACTS AND CONTRACTUAL ISSUES

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CHAPTER II-2 JOINT OPERATING AGREEMENTS Scott Crichton Styles

INTRODUCTION The joint operating agreement (JOA) is the common means by II-2.01 which businesses come together as a joint venture in their search for and production of oil and gas, both within the United Kingdom Continental Shelf (UKCS) and internationally. The need for a JOA is primarily driven by the economics of oil exploration, which is a high-risk, high-cost enterprise with a heavy frontloading of costs, albeit one which offers high rewards to successful parties. There are several benefits in entering into a JOA. Joint ventures allow oil companies to come together to mitigate their risks and share in the outlays required for capital-intensive exploration, development and production activities. Joint ventures also facilitate cost savings and economies of scale which enable the participating companies to operate with fewer employees, permit the elimination of duplicate facilities, equipment and functions, and allow cost savings through bulk purchases of supplies and materials. The joint venture is also important in that it allows upstream oil and gas companies to manage their portfolio of assets in a manner that seeks a balance between  minimising risk and maximising returns by allowing each company to invest in several different prospects for the same capital outlay. The term “joint venture” is not a term of art1 in English or II-2.02 Scots law2 and it can be used to refer to a specifically established   The question of the legal nature of the joint venture is discussed further at para II-2.07 onwards. 2   In the UKCS, the vast majority of JOAs contain a choice of law clause stating that the contract will be governed by English law and interpreted by the English courts should any 1

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limited company, a partnership or an unincorporated contractual association for a given purpose. It is the unincorporated joint venture which is used by the oil industry in the UKCS (and most commonly throughout the rest of the world). But although the term joint venture is not a technical legal term, it has been recognised by the courts in numerous cases and the current judicial approach may legitimately be considered to be summarised by the Court of Appeal in Northern Ireland in Sweeney v Lagan Developments,3 discussed further below.4 The unincorporated joint venture has been favoured by the oil industry over other possible models, such as legal partnership or incorporation into a limited company, because of the tax advantages it provides and because of the lack of mutual liability which is possible under the JOA. Like many other aspects of oil industry practice, the use of the unincorporated joint venture as a means of pooling resources in the search for hydrocarbons has its origins in the United States.5 MODEL FORM JOAS II-2.03 By the 1950s, there was a widely perceived need within the US oil industry for a standardised JOA which would minimise time spent arguing over contractual matters. There soon developed a standardised US model form operating agreement, the American Association of Petroleum Landsmen’s Model Form Operating Agreement, also known as the AAPL Form 610 of 1956. The AAPL Form 610 has been revised several times since then, most recently in 2015,6 but remains very similar to the 1956 original. The AAPL Form

dispute arise between the parties. For this reason, while Scots law shall be noted in passing at points throughout this chapter, the principal focus shall be on English law. 3   [2007] NICA 11. 4   See para II-2.06. 5   See eg M Taylor and S Tyne, Taylor and Winsor on Joint Operating Agreements (2nd edn, 1992) (hereinafter “Taylor and Winsor”), at xxiii. The reasons behind the adoption of the unincorporated joint venture, rather than the partnership, as the commercial vehicle of choice for oil and mining companies seems to have arisen in the prohibition under US law of companies forming partnerships. 6  It was previously revised in 1982 and 1989. The AAPL Form 610 is very much an American document and can be purchased through the AAPL’s website at www.landman. org (accessed 2 September 2017). It should be noted that Form 610 is for onshore JOAs. The AAPL’s Model JOAs for the US Outer Continental Shelf (Form 710) and deepwater (Form 810) are available for download from the OCS Advisory Board website at www. ocsadvisoryboard.org (accessed 1 May 2017). In 1990 the Association of International Petroleum Negotiators produced a model JOA for the international context, the AIPN Model Form International Operating Agreement. A revised version was produced in 2002 and another in 2012. For an account of the AIPN Model Form see P Weems and M Bolton, “Highlights of Key Revisions – 2002 AIPN Model Form International Operating

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610 was an influential model on the early UKCS JOAs which were introduced in the wake of the first licensing round in 1964. Although no absolutely standard form of the UKCS JOA has ever emerged, a major step towards standardisation in this regard occurred during the fifth round of UKCS licensing in 1977. Licences granted under the fifth round were given to consortia that had to include the then state-owned British National Oil Corporation (BNOC),7 and the JOA had to be in terms acceptable to BNOC. BNOC took a model form JOA drafted by the United Kingdom Offshore Operators Association (UKOOA)8 a year earlier, adapted it to their needs and produced the BNOC Proforma Joint Operating Agreement for Fifth Round Licences. This pro-forma JOA (together with the very similar sixth round proforma that followed) proved to be a workable document which secured widespread industry acceptance. Its legacy continues to be seen in UKCS JOAs to this day, long after the nationalised BNOC itself has ceased to exist. In advance of the twentieth UKCS offshore licensing round in 2002, a group of industry lawyers working under the auspices of UKOOA used the BNOC proforma as a starting point to produce the UKOOA 20th Round Draft JOA. This 20th Round JOA was consequently revised in 2008 by a group of industry lawyers working under the auspices of Oil & Gas UK to bring it into line with the standard Decommissioning Security Agreement (DSA)9 published by Oil & Gas UK Ltd,10 and the new Oil & Gas UK Model JOA was published in February 2009.11 This has proved to be an influential model for UKCS JOAs and frequent reference will be made to the Oil & Gas UK Model JOA, hereafter referred to simply as the “2009 Model JOA” in this chapter. As was noted earlier, while there has been movement towards II-2.04 standardisation, in practice no absolutely standard JOA has emerged. Documents such as the 20th Round and the 2009 Model JOAs are influential, but each oil company tends to have its own preferred style of JOA and disagreements can arise between the parties over

Agreement”, (2003) IELTR 169. In Canada the standard JOA is the Canadian Association of Petroleum Landsmen’s (CAPL) Operating Procedure. This was revised in 2007 and again in 2015. The 2015 edition and supporting documentation is available from the CAPL website at http://landman.ca/resources/forms-store/2015-capl-operating-procedure (accessed 1 May 2017). 7   For a short discussion of the history of BNOC, see para I-4.01. 8   The United Kingdom Offshore Operators Association (UKOOA) was succeeded by Oil & Gas UK Ltd in April 2007. 9   For DSAs, see Chapter I-13. 10  This JOA may be purchased through Oil and Gas UK Ltd’s website at www.oilandgasuk.co.uk (accessed 7 May 2017). 11   See http://oilandgasuk.co.uk/oil-gas-uk-presents-suite-of-model-agreements-to-improveindustry-efficiency (accessed 2 September 2017).

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the finer points of certain terms. For reference, it should be noted that there is a major policy difference between the US and the UK forms of JOA, namely that the US JOAs place the operator in a very strong, even dominant, position with regard to the non-operators, while under the UK JOAs non-operators have more rights and more say than they would have under a US JOA.12 JOINT BIDDING AGREEMENT II-2.05 Every JOA follows on from a joint bidding agreement (JBA) or an area of mutual interest agreement (AMI). These contracts are agreements between interested parties to bid for selected acreage under a UKCS licensing round, or to make an out-of-round bid, with the aim of securing from the government the award of a Production Licence. In an AMI, the parties specify an area of licensing acreage within which they agree to work jointly and to the exclusion of any non-signatory third parties should any licensing possibilities arise. A JBA commits the parties to bid jointly for selected acreage in a particular licensing round (or out-of-round bid) and, if the application is successful, commits them to conclude a JOA as quickly as possible in order to conduct operations under the licence. It is now common practice to attach the whole of the proposed JOA to the JBA in order to facilitate its implementation without unnecessary delay. A JOA only comes into existence when a licence has been granted by the government to the members of a successful JBA; the members of the JBA will then solidify their relations by executing the JOA. II-2.06 The central right granted by a UK licence is to “to search and bore for, and get” petroleum.13 UKCS licences and model clauses generally refer to “licensee” in the singular and are also silent about the legal relations between any co-licensees.14 As the whole purpose of the bidding agreement is to secure a licence then, obviously, all the members of the prospective JOA must satisfy the UK Government’s criteria for the award of a Production Licence. These are that applicants must meet certain minimum standards of financial and technical capability and environmental management. Provided that these thresholds are met, then the key factors in determining the actual award of a licence are the geological rationale for the appli-

  See eg Taylor and Winsor, p 11 and more generally throughout Chapter 2 of that work.  The Petroleum Licensing (Production) (Seaward Areas) Regulations 2008 (2008 Regulations), (SI 2008/225) (hereafter “2008 Regulations”), Model Cl 2(1). See further the discussion at paras I-4.41 to I-4.60. 14 30   Under the 2008 Regulations Model Clause 1 “Licensee” is defined as the “person or persons to whom this licence is granted, his personal representatives and any person or persons to whom the rights conferred by this licence may lawfully have been assigned”. 12 13

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cation and the programme of exploration work that is proposed. In short, the parties willing to spend the most in exploration are the ones who are most likely to be awarded the licence.15 NATURE OF THE JOINT VENTURE As mentioned above, the term “joint venture” is not a term of legal II-2.07 art in English or Scots law and to add further to the conceptual confusion the term is often used in quite different ways. When two or more parties choose to pool their efforts by setting up a limited company, that is often spoken of as an “incorporated joint venture”. However, for lawyers at least, this terminology is confusing as, whatever the underlying commercial reality, the legal obligations constituted by such an “incorporated joint venture” are simply those of normal company law. The terminological confusion is exacerbated by the fact that the terms “joint venture” or “joint adventure” have been used in both Scots and English law16 to designate partnerships for a fixed period or specific project, a designation which again prima facie would appear to govern the typical North Sea JOA. A situation where “joint venture” has been understood as simply meaning “temporary partnership” can be found in the Scots case of Mair v Wood,17 where Lord President Cooper, at p 86, stated that the joint venture is a species of partnership. This is an overstatement and an oversimplification. The real distinction, as discussed below, is that in a true joint venture, the aim of the joint venture is to share production not profits. But there is no doubt that this legal homonym can mislead practitioners and judges. Perhaps it would be better if the JOA referred not to “joint ventures” but instead to “alliances” and “alliancing”, terms which at least run no risk of having any implication, as the term joint venture does, of fixed-term partnerships. However, the terminology of “joint venture” is so embedded in the usage and practice of the international oil industry that the use of that expression is likely to continue for many years to come. Moreover, the conceptual basis of the unincorporated joint venture is far from clear in English or Scots law. The concept of the joint venture seems to rest uneasily between two well-established legal concepts and institutions, namely contract and partnership. The concept of the joint venture seems slightly “fuzzy” because, in many ways, it seems to function as a partnership but – quite deliber  See further the discussion at paras I-4.35 to I-4.38.   See, for English law, Lord Mackay of Clashfern (General Editor), Halsbury’s Laws of England (4th edn, 2003 reissue) (hereinafter “Halsbury”), vol 35, para 8; for Scots Law, Bell, Principles, para 392. 17   1948 SC 83. 15 16

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ately – lacks many of the key characteristics of a partnership. Some doubts still remain about the courts’ attitude to the unincorporated joint venture. This issue will be discussed further at paras II-2.15 to II-2.18, under the heading “Partnership or Not?”. II-2.08 The unincorporated joint venture is a form of contractual association; that is, the relationship is created by contract – the JOA itself – and the terms of the joint venture will largely be proscribed and limited to those set out in the JOA. The JOA thus functions as the constituent contract of the commercial relations between the parties. Indeed, it is normal for the JOA to contain a clause reducing the entire terms of the contract to the JOA itself. The JOA needs to carry out a number of important functions. It will define the proportionate interests of the parties and allocate control mechanisms and rights: all the joint operations must be conducted in accordance with the terms of the JOA. In addition to the agreement of the parties, because the creation or amendment of a JOA commonly entails the apportionment of at least some of the rights granted by a Petroleum Act licence, both its creation and amendment requires the consent of the Secretary of State, acting on behalf of the UK Government. As the JOA is a contract it may, of course, only be amended by the unanimous consent of the parties and therefore it is vital that the JOA be as well drafted and fit for purpose as is possible, because it may well have to endure for many years. II-2.09 Notwithstanding the need for the Secretary of State’s consent, the JOA is, in essence, a private contract between the licensees which governs the “horizontal” relations between the parties, and the purpose of a JOA is to allocate control, risk and reward between the licensees inter se, as distinct from their “vertical” relationship with the government. That vertical relationship is governed by the terms of the licence.18 The scope of the JOA is the exploration for and production of petroleum under the relevant licence, together with those activities which flow inevitably from that task, ie, the storage and transport of the petroleum product and so on.19 Unless terminated at an earlier date by the parties, the JOA will terminate   The licence lays down various obligations, most of which are contained in the model clauses. Examples of these obligations are discussed in Chapter I-4 and Appendix I-A. From the standpoint of the vertical relationship between the government and the JOA members qua licensees, liability for any breach of these obligations is joint and several between all the licensees. As between the licensees/JOA members themselves, the extent of their liability will depend on the nature of the fault, but most JOAs make provision that any civil liabilities arising under the licence will be allocated on a pro rata basis. 19   For example, the 2009 Model provides at clause 3.1.1: “The scope of this Agreement shall extend to:      (a) the exploration for, and the appraisal, development and the production of Petroleum under the Licence; 18

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when all commercially available hydrocarbons have been extracted and the costs for the decommissioning of the field have been met. While it is extant, the JOA has two quite distinct legal functions: a proprietorial one and a functional-relational one. In other words, the contract both establishes the property interests of the parties and regulates the rights and duties of the parties. These respective functions will be discussed in turn. Proprietorial functions – declaration of percentage interest and creation of tenancy in common The proprietorial role of the JOA is to establish the legal nature II-2.10 or form of the property interest of the parties and to allocate the proportion of that proprietary interest between them. The most important clause of all in any JOA is arguably the one which specifies the respective proportional interests of the parties in the licence in any petroleum won, and in any property owned by the JOA. Such a clause is commonly known as the “interests clause”. For instance, clause 4 of the 2009 Model JOA provides: “Subject to the provisions of this Agreement, the Licence, all Joint Property, all Joint Petroleum and all costs and obligations incurred in, and all rights and benefits arising out of, the conduct of the Joint Operations shall be owned and borne by the Participants in proportion to their respective Percentage Interests which at the date hereof are as follows …”

The interests clause allocates the percentage property rights of each II-2.11 member of the JOA under the licence. All other rights and duties of the JOA members are borne in proportion to the extent of their proprietary interest in the licence.20 Furthermore, the declaration that joint property is to be held in proportion to the parties’ respective percentage interests provides the all-important “words of severance”  (b) without prejudice to clause 18, the treatment, storage and transportation of Petroleum using Joint Property;     (c) [[without prejudice to clause 18, the consideration of technical and operational issues in connection with the treatment, storage and transportation of Petroleum using third party infrastructure;]]      (d) [[the consideration of technical and operational issues in connection with the use of Joint Property by third parties;]]      (e) the decommissioning or other disposal of Joint Property; and      (f) the conditions for the carrying out of Sole Risk Projects in the Licence.”      Note that the sub-clauses 3.1.1(c) and (d) are new additions in the 2008 Draft to bring the third party access to infrastructure within the scope of JOA. For regulatory discussion on access to infrastructure see Chapter I-6. 20   The JOA may also provide for non pro rata sharing in certain circumstances, eg where there are sole risk operations. See below at paras II-2.50 and II-2.51.   

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which English law requires if the “joint tenancy”21 granted to the licensees by the state by the award of the licence is to be replaced by a “tenancy in common.”22 In other words, the collective unitary form of ownership granted by the licence is transformed by the interests clause into individual ownership of proportions of the property, each owner having a separate undivided share of the JOA assets. The central form of reward under the JOA is the allocation of production in kind of any assets produced by the joint operation.23 The undivided interest is a form of intangible personal property,24 or to put the matter more precisely, it is a chose in action,25 and, subject to any restrictions on assignment, may be sold or mortgaged by its owner. II-2.12 The transfer of an interest in a JOA and in a licence is done by a process of novation and assignment.26 All and any such trading in licence interests is subject to consent being granted by the Government, but there is in place a system of open permission.27 Furthermore, as regards securities, it is government policy not to allow them to be granted over licence interests unless they are used to finance offshore operations.28 Assignation and pre-emption rights II-2.13 Until 2002, it was usual for JOAs to contain a clause restricting the assignment of a co-venturer’s interest in the JOA.29 The main

 Joint tenancy is a form of ownership by which two or more persons, called joint tenants, share ownership of the property in an equal and undivided manner. Obviously oil companies do not wish to hold their interest in a licence in an equal and undivided manner. 22  Tenancy in common is a form of ownership by which two or more persons have community of possession but distinct and several titles to their shares which need not necessarily be equal and which they may dispose of separately. See Halsbury, vol 39(2), para 208. 23   That is, allocation not of equivalent monetary value but of the volume of hydrocarbon produced. 24   Personal property is used here in its sense under English Law; in Scots Law is would be classified as moveable property. 25  See Halsbury, vol 6, para 1. 26   See further on this topic Chapter II-13. 27  A copy of this Open Permission (Operating Agreements) is available from www. gov.uk/guidance/oil-and-gas-petroleum-licensing-guidance (accessed 7 May 2017). Note, however, that the open consent “permits the several companies that together constitute the Licensee to novate an Operating Agreement (including both Joint and Unit Operating Agreements) in the course of implementing a Licence Assignment that has already been approved by the Secretary of State”. See the Explanatory Note which accompanies the Open Permission (emphasis added). 28  A copy of this Open Permission (Creation of Security Rights over Licences) can be downloaded from www.gov.uk/government/uploads/system/uploads/attachment_data/ file/15148/openpermchg.pdf (accessed 7 May 2017). 29   For a discussion, see R Major, “A practical look at pre-emption provisions in upstream oil and gas contracts”, (2005) IELTR 117. 21

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argument in favour of pre-emption rights in a JOA is that they preserve the identity of the original group and can help to keep out undesirable new joint venture partners. This approach makes sense if a JOA is viewed primarily as a relational contract, like a traditional partnership, with a significant element of delectus personae.30 An incoming party to a JOA is not just buying equity in a project (as, for example, a purchaser of shares in a limited company does), it is also becoming liable for his share of expenditure, and the rest of the JOA participants would like to be reassured as to his solvency. On the other hand, if one views the JOA primarily as a proprietary contract granting a right to certain shares in production from the area of operations, then pre-emption rights can be seen as an unjustifiable restraint upon commerce. By the end of the 20th century, pre-emption rights were seen by the UK Government as a major impediment to the free trading of interests and as a factor which served to delay or even entirely prevent the introduction of new funds and resources into the UKCS.31 Accordingly, the UK Government worked with the offshore industry32 to bring in arrangements under a “Master Deed” to facilitate asset transfers under existing licences. It also announced that, other than in certain specially justified circumstances, JOAs in respect of licences granted from the 20th round33 onwards would not be approved if they contained pre-emption clauses, and that in all cases they must follow the Master Deed format.34 The Master Deed greatly expedites the transfer of UKCS offshore licence interests and  The courts tend to uphold pre-emption rights: see eg Texas Eastern Corporation (Delaware) & Others v Enterprise Oil Plc and Others, CA, 21 July 1989 (unreported) in which the Court of Appeal effectively rewrote the pre-emption clause in the joint operating agreement, which had become totally unworkable if given a literal meaning. The assignment clause in this case stated that the parties had pre-emption rights in the ratio to their percentage interest. Over 25 years, however, the contract area had been subdivided into numerous sub-areas in which different parties had different percentage interests. It was, therefore, difficult to apply the clause. Nevertheless, the Court of Appeal felt that the parties were duty bound to give effect to the intention behind the clause and required the parties to work out a formula so that it could be applied. But, obviously pre-emption rights will not apply to situations where the proposed transfer is permitted; see company law examples of Scotto v Petch [2001] BCC 899 and Re: Gunlegal Ltd [2003] EWHC 1844 (Ch). 31  See PILOT’s Progressing Partnership Working Group’s Operators Final Report, PP/94/01, 18 December 2001, s 6, available at www.pilottaskforce.co.uk/data/actareas. cfm/23 (accessed 3 September 2017); see also C Kehoe and N Foate, “Pre-emption Clauses Under Attack”, 9 July 2002, available at www.herbertsmith.com/Publications/ archive/2002/enr9july2002.htm (accessed 7 May 2017). 32  Through PILOT’s Progressing Partnership Working Group (PPWG) and a number of other interested organisations. 33   The 20th round licences were granted in July 2002. 34   S Gyaltsen and A Turton, “The Master Deed and Changes in the North Sea”, (2003) 9 IELTR 258–260. 30

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other agreements relating to associated assets and infrastructure. It also introduces a standard pre-emption regime to give confidence to incoming companies.35 Functional-relational aspect of the JOA II-2.14 The JOA creates what contract theorists now refer to as a “relational” contract, which is to say a contract that seeks to govern an ongoing relationship between the parties which will typically last for several years.36 The JOA creates a relationship between the parties of investors involved in the joint operation of exploring for and producing oil under the relevant licence. In more straightforward terms, the JOA creates contractual rights and duties of performance between the co-venturers. Partnership or not? II-2.15 As mentioned earlier, for reasons of tax and minimising the liabilities of the members to the JOA inter se, all standard JOAs contain a clause denying that the agreement constitutes a partnership.37 However, the English and Scottish courts take a somewhat ambivalent attitude to such clauses. There is a tension in the attitude of the courts between, on the one hand, a desire to give effect to the legitimate intentions of persons engaged in commerce as agreed by contract, and on the other, a desire to recognise that the mere label which is attached to a contract does not of itself determine its legal content and meaning. There is clear judicial authority that the courts will look beyond the wording of labelling or deeming clauses and towards the actuality of matters: “If a partnership in fact exists, a community of interest in the adventure being carried on in fact, no concealment of name, no verbal equivalent for the ordinary phrases of profit or loss, no indirect expedient for enforcing control over the adventure will prevent the substance and reality of the transaction being adjudged to be a partnership….”38

  Discussed further at paras II-9.43 to II.9-45.  See I R Macneil, “Contracts: adjustments of long-term economic relations under classical, neo-classical, and relational contract law”, 72 NWULR 854 (1977–1978). 37   For example, 2008 Draft JOA, cl 22.1 states: “The liability of the Participants hereunder shall be several and not joint or collective and each Participant shall be responsible only for its individual obligations hereunder. It is expressly agreed that it is not the purpose or intention of this Agreement to create, nor shall it be construed as creating, any mining partnership, commercial partnership or other partnership.” 38   Adam v Newbigging (1888) 13 App Cas 308, at 315, affirmed by Lord Chancellor Halsbury in the Scottish appeal of McCosh v Brown & Co’s Trs (1889) 1 F (HL) 86, at 88. 35 36

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This is so even where there is an express denial of partnership in the II-2.16 contract: “Two partners enter into a transaction and say, ‘It is hereby declared that there is no partnership between us.’ The court pays no regard to that. The court looks at the transaction and says, ‘Is this, in point of law, really a partnership?’ It is not in the least conclusive that the parties have used a term or language intended to indicate that the transaction is not that which in law it is.”39

Thus, the courts will assess the question by reference to what the II-2.17 arrangement is, not how it is labelled. However, it is a strange fact that despite the increasing use of the unincorporated joint venture as a commercial vehicle beyond the oil industry and despite its near universal use in the UKCS as the commercial vehicle by which operations to the value of billions of dollars have been conducted, there have been only two cases where the actual legal nature of the unincorporated joint venture has been recognised.40 In the unreported English case of Spree Engineering & Testing Limited v O’Rourke Civil & Structural Engineering Limited,41 the High Court expressly recognised the existence of the unincorporated joint venture,42 as distinct from that of a partnership, in the instant case. In the course of his opinion, the judge made the following observations: “22 Mr Davis [counsel for O’Rourke], however, referred to me to Hewitt on joint ventures, and in particular to pages 55 to 58, and 79 to 81. He submits that the situation here fits with the description at page 56 of an unincorporated venture based on a simple contract between the parties, detailing their cooperation. Such an arrangement usually involves the sharing of costs and resources, and sometimes income, on terms which do not give rise to a legal partnership. A typical unincorporated venture is a bidding agreement, which was the essence of the joint venture agreement here. Mr Davis drew attention to a passage on page 81 which reads:

  Weiner v Harris [1910] 1KB 285 per Cozens-Hardy MR, at 290.   That is, cases where the legal nature of an unincorporated joint venture was a disputed issue before the court. There are many reported cases involving joint ventures where the issue is something other than the nature of the joint venture itself. 41   Spree Engineering & Testing Limited v O’Rourke Civil & Structural Engineering Limited, Unreported, 18 May 1999, 1999 WL 33453546 (High Court of Justice Queen’s Bench Division) (hereinafter “Spree”). 42   Spree Engineering per Mr T Stow QC, at para 26: “I have reached the firm conclusion that the contractual arrangements between Kent and ROR amounted to a non-integrated joint venture, and did not consist of a partnership. Even if I had been in doubt about their status, I would have resolved this doubt in favour of ROR by reason of the clear terms of clause 18 of the joint venture agreement. As is pointed out in Lindley at para 504, such a declaration may be of particular significance where the nature of the relationship does not appear clearly from the remainder of the agreement.” 39 40

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uk o i l a nd gas l aw vo l u m e i i ‘In the absence of strong tax considerations or professional requirements, it is comparatively rare to find a commercial joint venture business organised in the UK on a partnership basis.’

23 He also referred to passages on pages 29 and 30 of Linklaters and Payne’s work on joint ventures, and submits that the case here is a classic illustration of a non-integrated joint venture which is not a partnership. In analysing the situation here, I derive considerable assistance from passages on page 30 of this last work. It reads as follows: ‘The participants in a non-integrated joint venture would typically assume the same joint and several liability to the employer for the performance of their obligations under the construction contract, as would parties to an integrated joint venture. In a non-integrated joint venture on the other hand, no profit is struck at the level of the joint venture. Instead, the work is divided up into discreet segments which the participants carry out severally, each bearing their own costs of performance, and dividing between them the flow of payments from the employer under the construction contract. Profit is thus taken, not at the level of the non-integrated joint venture, but severally by the participants, and it is possible for one participant to show a profit, and another a loss, on their respective parts of the work under a non-integrated joint venture. It will be seen that the status of the two types of venture is very different for the purposes of the Partnership Act. An integrated joint venture generally satisfies the test of “the relation which subsists between persons carrying on business in common with a view to profit.” On the other hand, the non-integrated joint venture generally falls to be treated simply as an unincorporated association, since the participants generally share no more than the gross payments received from the employer under the construction of the contract — see the Partnership Act sub-section 2.2.’ 24 I accept Mr Davis’s submission that this description of a non-integrated joint venture is close to the situation we have in this case. One must be cautious about accepting at face value the opinions of authors, unsupported directly by authorities of the courts, but I find the analysis compelling, and likely to represent the views of professionals used to dealing with joint ventures on a regular basis.”43

II-2.18 However, Spree is only a decision at first instance in the High Court, and is therefore not in itself of very high authority, but the approach of the court in Spree was confirmed in the Court of Appeal in   Spree 1999 WL 33453546, paras 22–24.

43

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Northern Ireland in Sweeney v Lagan Developments.44 The Court made the following important remarks: “[13] Clause 3 of the Consortium Agreement makes clear that what the parties were setting out to establish was a joint venture. The term ‘joint venture’ does not have a precise legal significance not being a legal term of art. As Hewitt’s ‘Joint Ventures’ 3rd Ed at para 1.11 makes clear it refers to a range of collaborative business arrangements, the fundamental characteristic of a joint venture being collaboration between the participants involving a significant degree of integration between the joint venturers. The key element to be considered and agreed by the joint venturers is the degree and nature of that collaboration. Joint ventures may take the form of a contractual alliance, a partnership or a corporate joint venture. As is pointed out in Lindley and Banks on Partnership 18th Ed at paragraph 5.07 although partnerships and joint ventures have a number of common characteristics, in some instances the two expressions appear to be used interchangeably whilst in others the joint venture is recognised as a relationship quite separate and distinct from partnership. Whilst it can probably be said that all partnerships involve a joint venture the converse proposition does not hold good. In Spree Engineering and Testing Limited v O’Rourke Civil and Structural Engineering Limited 18th May 1999 (NLC 299069302) the court concluded that the particular arrangement between two companies in a joint venture did not involve a partnership because they specifically agreed provisions which avoided the degree of integration necessary to found a partnership. The companies carried out their own part of the work independently. The court concluded that:‘An integrated joint venture generally satisfies (the partnership) test of “the relation which subsists between persons carrying on business in common with a view to profit.” On the other hand a non-integrated joint venture generally falls to be treated simply as an unincorporated association since the participants generally share no more than gross payments received.’ [14] It is clear that joint venturers must be in agreement as to the model of the joint venture if they are to reach a consensus necessary for a contract since very different legal and financial consequences flow from the model adopted. There are clear legal differences between running a joint venture as a company and running it as a loose contractual alliance. These include the management framework, the decision making arrangements, the funding arrangements and the financial powers of the entity (a company, for example, having powers to raise money by way of floating charges). Clearly there will be different exit strategies and issues relating to the division of profits.”45   [2007] NICA 11. The case concerned potential building development where the parties had formed an incorporated joint venture with a view to establishing a company, ie an incorporated JV if their bid for the land was successful. 45   [2007] NICA 11, paras 13–14. 44

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II-2.19 It is submitted that the approach taken by the Courts in Sweeney and Spree may legitimately be considered to accurately embody the current approach of the British courts on the issue of the nature of joint ventures. Moreover, whilst there is a paucity of case law discussing the issue of whether or not a particular joint venture is a partnership, there are numerous cases where the courts have considered joint ventures in some other context and the existence and nature of the unincorporated joint venture has been accepted by the court. For example, in Venture North Sea Gas Ltd v Nuon Exploration & Production UK Ltd,46 there was a dispute over whether the joint operating agreements, as executed, were substantially different from the unexecuted draft form of that JOA. The court held that they were different and so had not taken effect, but the court accepted that a joint venture was a legitimate way of doing business. See, for example, Ithaca v NSE47 and Hashwani & Ors v OMV Maurice Energy Ltd48 where the validity of the JV as a business vehicle was not challenged but rather assumed by the court. So it would seem that the UK courts are increasingly comfortable with the notion of the unincorporated joint venture. II-2.20 Any definitive answer confirming the separate existence of a joint venture will always presuppose that the concept can be meaningfully distinguished from a partnership. The question then becomes: what constitutes a partnership in English and Scots law? Unfortunately, the law here is far from clear. The Partnership Act 1890 defines partnership as “the relation which subsists between persons carrying on a business in common with a view of profit”.49 But this definition merely describes three necessary conditions of partnership: more than one party, in business and attempting to make a profit – it does not lay down sufficient conditions of partnership. Section 2 of the Act gives some more guidance and provides that neither co-ownership50 nor the sharing of gross returns51 will of themselves constitute a partnership. It does, however, go on to provide that “the receipt by a person of a share of the profits of a business is prima facie evidence that he is a partner”, but then gives five exceptions to that principle.52 So the only things   [2010] EWHC 204.   [2012] EWHC 1793 (QB). The dispute concerned a sole risk clause. 48   [2015] EWCA Civ 1171; [2015] 2 CLC 80. The dispute concerned an arbitration clause and a farm-out agreement. 49   Partnership Act 1890 (c 39), s 1. 50  The Partnership Act 1890, s 2(1), provides “Joint tenancy, tenancy in common, joint property, common property, or part ownership does not of itself create a partnership.” 51   Ibid, s 2(2). 52   Ibid, s 2(3): “The receipt by a person of a share of the profits of a business is prima facie evidence that he is a partner in the business, but the receipt of such a share, or of a 46 47

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we can say for certain about a partnership is that, of themselves, sharing ownership or gross returns will not create a partnership, but there is a rebuttable presumption that the sharing of profits will create a partnership. The strongest accounts of the legal case against a court deeming a JOA to be a partnership are those given by M Crommelin53 and by G Lewis.54 Crommelin argues that a JOA does not carry on a business in common with a view to profit, but rather each party is carrying on his own distinct business with a view of separate profits, although admittedly some parts of that business are performed in common. In his comment on Crommelin’s paper, Lewis states: “Now the normal joint operating agreement does not involve the sharing of gross returns, but it does involve that each participant is entitled and bound to take in kind its share of the crude or the gas which is produced … and to sell its share for its own account. There is much to be said for the view that these arrangements do not amount to a sharing of profits which the Partnership Act definition requires. In effect, the participants share the expenses of the production, but sell the products separately. Ladbury has described the matter this way:

payment contingent on or varying with the profits of a business, does not of itself make him a partner in the business; and in particular:    (a) The receipt by a person of a debt or other liquidated amount by instalments, or otherwise out of the accruing profits of a business does not of itself make him a partner in the business or liable as such     (b) A contract for the remuneration of a servant or agent of a person engaged in a business by a share of the profits of the business does not of itself make the servant or agent a partner in the business or liable as such      (c) A person being the widow or child of a deceased partner, and receiving by way of annuity a portion of the profits made in the business in which the deceased person was a partner, is not by reason only of such receipt a partner in the business or liable as such      (d) The advance of money by way of loan to a person engaged or about to engage in any business on a contract with that person that the lender shall receive a rate of interest varying with the profits, or shall receive a share of the profits arising from carrying on the business, does not of itself make the lender a partner with the person or persons carrying on the business or liable as such. Provided that the contract is in writing, and signed by or on behalf of all the parties thereto     (e) A person receiving by way of annuity or otherwise a portion of the profits of a business in consideration of the sale by him of the goodwill of the business is not by reason only of such receipt a partner in the business or liable as such.” 53  M Crommelin, “The Mineral and Petroleum Joint Venture in Australia”, 4 (1986) JENRL 65–79 (hereinafter “Crommelin, ‘Joint Venture’”). Despite the Antipodean title, the arguments in this paper apply with equal force in the UK, as the Australian law in this area follows English law. This is the point that Lewis makes in his comment. 54   G Lewis, “Comment: The Joint Operating Agreement: Partnership or not?”, 4 (1986) JENRL 80–84 (hereinafter “Lewis, ‘Partnership or not?’”)

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uk o i l a nd gas l aw vo l u m e i i ‘… [it] is likely that the major difference between the mining joint venture and partnership is that in the joint venture the profit or gain will be derived by the venturers individually and will not be derived for their common or joint benefit. The mining joint venture is an expense sharing and production sharing agreement.’”55

II-2.21 This would suggest that the separate disposal of petroleum is an essential component of the claim that a JOA does not amount to a partnership, because it is production not profits which are shared, and therefore the sharing does not fall within the ambit of Section 2(3) of the Partnership Act. Notwithstanding the apparent clarity of this analysis, it is submitted that the waters are somewhat muddier than they may at first seem. This is so because even the sharing of gross returns, whilst not constitutive of partnership in the same way as is the sharing of profits, may nevertheless give rise to a presumption of partnership. For instance, in Todd and Others v Adams,56 a Court of Appeal case on share fishermen, Neuberger J stated: “Although I am not saying that the arrangement in the present case was necessarily a partnership, it is interesting to note this observation in Lindley and Banks on Partnership (17th ed., 1995) at par. 5–27: ‘Persons who agree to share the profits of a venture are prima facie partners, even though they may also have agreed between themselves that they will not be liable for losses beyond the amount of their respective contributions.’”57

II-2.22 It is not altogether easy to provide a settled and confident conclusion on this issue, as the case law does not all pull in one direction. However, it is possible to say that it is extremely prudent to provide in the JOA that each co-venturer has the right to take and dispose separately of its share of the petroleum obtained.58 Such a provision makes it clear that the common enterprise of the joint venture is   Lewis, “Partnership or not?”, at 82. The internal quotation is to R Ladbury, “The Joint Development of Resource Projects in Australia”, a paper given at the SERL Singapore regional seminar on the joint development of resources projects, September 1985. 56   Todd and Others v Adams [2002] 2 All ER (Comm) 97 (hereinafter “Todd v Adams”). 57   Todd v Adams per Neuberger J, at para 78. See also the dictum of Mance LJ, at para 104: “Partnership, in contrast, is the relationship existing between two or more independent persons, contracting together to engage in a business in common with a view to making and sharing profit. Generally, a partner will contribute either property, skill or labour, but sleeping partners who contribute nothing are also not uncommon. Generally, partners share in any losses, but this too is not ‘essential to the legal notion of partnership’ … Whether a partnership exists is a mixed question of fact and law … It is an inference from the primary facts.” 58   In practice, JOAs invariably contain language to this effect. The 2009 Model JOA, Cl 18(a), for example, states that “each of the Participants shall have the right to take in kind and separately dispose of its Percentage Interest share in the total quantities of Petroleum available under this Agreement” while Cl 18(b) provides that “each of the Participants 55

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limited to the exploration for and/or the production of the oil or gas which the co-venturers hold in common. As each co-venturer is acting in the course of its own business when it comes to the disposal of the resulting product, then there is no mutual profit which could give rise to a partnership. But, notwithstanding the functional test listed above, it is submitted that most third parties working within the oil industry doing business with an operator could be reasonably expected to be aware of the nature of the unincorporated joint venture. Furthermore, comfort may be derived from the explicit recognition of the existence of an unincorporated JOA in the Spree Engineering and Sweeney decisions, and its implicit recognition in several other cases.59 It is accordingly submitted that even absent a separate disposal clause, the courts might be slow to disrupt the long established expectations of parties in the industry and to impose partnership. Obviously, the presumption might not be as strong if the operator deals with a third party whose primary business is not oil specific, for example, a software specialist, and in those circumstances there may be a greater risk that a court might deem a partnership to exist. On the other hand, it must be stressed that even if partnership were to be found by a court, this would not of itself regulate the relations of the parties inter se, as partners are specifically allowed by the Partnership Act to order their internal relations as they agree between themselves.60 The mandatory provisions61 of the Partnership Act apply only to external relations with third parties. For parties participating in the oil industry, any risk of extra liabilities arising as a result of a JOA being deemed to be a partnership are therefore likely to be small or nonexistent. However, the one major impact of a judicial decision which considered a JOA to be a partnership would probably be on the tax position of the parties. THE TWO CLASSES OF CO-VENTURER: THE OPERATOR AND THE NON-OPERATORS There are two classes of member of any JOA: the “operator”, II-2.23 who actually executes the collective will of the members of the joint venture and is responsible for the day-to-day management of the joint operations; and the other members, who are simply

shall have the obligation to take in kind and separately dispose of its Percentage Interest share in all Petroleum produced” (emphasis added). 59   See para II-2.17. 60  Partnership Act 1890, s 19: “The mutual rights and duties of partners, whether ascertained by agreement or defined by this Act, may be varied by the consent of all the partners, and such consent may be either express or inferred from a course of dealing.” 61   Ibid, ss 5–18.

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designated as “non-operators”. The institutional link between the operator and the non-operators is the Joint Operating Committee (JOC, often referred to informally as the “Operating Committee” or, most commonly of all, the “Opcom”) on which all the co-venturers sit.62 The operator II-2.24 The operator is responsible for the day-to-day exploration, development and production activities in the venture whilst the remaining interest holders are non-operating members who share in the costs and production (if any) of the joint venture activities. There is only ever a single operator, and the identity of the first operator in a given JOA will be specified in the agreement.63 The JOA will also contain provisions for the possible removal of the operator and his replacement by another party.64 The choice of operator is subject to Government approval with the Minister holding the right to revoke that approval.65 The role of the operator is to act on behalf of the JOA members in the exploitation of any reserves which come to the JOA members under the licence. Although operatorship inevitably entails much work and responsibility for the operator, it is a central feature of the JOA that the operator works in that role gratuitously for the benefit of all members of the JOA: that is, he gets no payment for his troubles in exercising his role of operator but rather, he simply takes his rewards, if any, pro rata from the production of the field. The question arises then as to why (other than for reasons of pure altruism) any JOA member would wish to act as operator. The answer is that traditionally the perception has been that the operator has de facto much more say over the entire project than the non-operators and is best positioned to take the initiative. Thus, the operator is rewarded with greater power, rather than greater potential profits. Usually, the JOA member with the largest percentage interest in the JOA will be the operator of the joint venture. During the negotiations, the operator will generally want to have operator removal provisions limited to those requiring good cause, for example, default or wilful misconduct.66 The operator will also seek to have a removal clause which requires unanimity among the JOA members, which of course allows the operator to veto any attempt to remove him. Conversely,   The JOC or Opcom is discussed further at paras II-2.45 to II-2.48.   See eg 2008 Draft JOA, cl 5.1. 64   Ibid, cl 5.3. 65   2008 Regulations, Model, cl 24. 66   “Wilful misconduct” is discussed further at para II-2.28. 62 63

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the non-operators may seek to have a removal clause which is without cause and based on majority voting of the members. The actual outcome of these discussions will be dependent on the relative negotiating strengths of the parties and the extent to which they trust each other. The JOA will also contain clauses allowing the operator to resign, and which provide for the selection of a replacement.67 This is an area where there may be tensions over the relevant pass mark for making this decision, as discussed further at para II-2.38 below. In recent years, there has been a tendency towards delegating II-2.25 operating functions to professional contractors who are not actually members of the JOA. Such contractor-operators are not generally dealt with in the JOA. Rather the tendency is for the JOA operator to delegate in turn much of his day-to-day management role to the contractor-operator. Such delegation would generally require the consent of the other members. Duties and liabilities of the operator Broadly speaking, the operator has the day-to-day responsibility for II-2.26 the conduct of the exploration and development operations. The operator is obliged to “conduct the Joint Operations by itself, its agents or its contractors under the overall supervision and control of the [JOC]”.68 Even “[i]f the Operator does not conduct any of the Joint Operations itself, it shall nevertheless remain responsible” for the joint operations as the operator.69 The major duties of the operator include (but are not limited to):70 (a) the preparation of programmes, budgets and AFEs;71 (b) the implementation of JOC-approved programmes; (c) the provision to each of the co-venturers of reports, data and information. As the de facto day-to-day manager of the project and agent of the II-2.27 JOA, the operator owes a duty of care to the other members in his capacity as operator. The nature of the duty is usually specified in the JOA as the duty to perform the role of operator in “a proper and workmanlike manner” in accordance with “good oilfield practice” and “in compliance with the requirements of the Acts, the licence and any other applicable legislation” and to carry out, “with due diligence, all such acts and things within its control as may be   See eg 2008 Draft JOA, cl 5.2.   2009 Model JOA, cl 6.1.1. 69   Ibid, cl 6.1.2. 70   Ibid, cl 6.2.1. 71   “Authorisations for expenditure”. AFEs are discussed further at para II-2.49. 67 68

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necessary to keep and maintain the Licence in force and effect”.72 “Good oilfield practice” is defined as: “the application of those methods and practices customarily used in good and prudent oil and gas field practice in the [UKCS] with that degree of diligence and prudence reasonably and ordinarily exercised by experienced operators engaged in the [UKCS] in a similar activity under similar circumstances and conditions”.73

Therefore, the exact nature of what counts as “good oil field practice” will depend upon the circumstances and will also change as technology develops. The corollary of the principle that the operator qua operator is not remunerated for his services is that he will usually only be liable qua operator to the non-operators if he is responsible for “wilful misconduct”74 or fails to maintain insurance.75 In other words, the operator enjoys immunity from liability within the contractual nexus of the JOA for his actions qua operator and is only liable to the extent of his percentage interest in the JOA. However, the operator will not usually be liable for an honest mistake, a misjudgement or negligent act or omission. In the US, as a result of the Deepwater Horizon oil spill, the immunity of the operator has been narrowed in scope to only cover authorised or approved operations by the US AAPL Model Form 810 (2015) for deep water drilling, which has been modified in the light of Macondo, and Article 22 gives participants the options to either share liability for gross misconduct/wilful negligence (with or without a cap) between all the co-venturers or to impose such liability solely upon the party which was grossly negligent, which means, in effect, the operator. Article 22 also provides that all participating parties must reimburse the operator for their proportionate share of costs and expenses until a final determination of gross negligence/wilful misconduct is made.76   2009 Model JOA, cl 6.2.2.   Ibid, cl 1.1. This is the definition of the term “good oilfield practice” in the JOA context. See the discussion at para I-4.60 for the definition in the licensing context. 74   Ibid, cl 6.2.4. Note, however, that sub-clause (b) provides that non-operators should “defend, indemnify and hold the Operator harmless … from and against any Consequential Loss … even in the event of [the Operator’s] negligence and/or breach of duty … and/or Wilful Misconduct” (emphasis added). Also see para II-2.28. 75   See further para II-2.36. 76   AAPL-810 (2015) Art 22.5: Liability for Damages.      “Unless specifically provided otherwise in this Agreement, liability for losses, damages, Costs, expenses, or Claims involving activities or operations under this Agreement or affecting the Leases or the Contract Area shall be borne by each Party, subject to the provisions of this Article 22.5, in proportion to its Participating Interest Share in the activity or operation out of which that liability arises, REGARDLESS OF FAULT. However, subject to Articles 22.7 (Damages to Reservoir and Loss of Reserves) and 72 73

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“Wilful misconduct” is not a concept whose meaning is entirely II-2.28 clear under English common law.77 However, there is some judicial guidance as to its meaning. In Forder v Great Western Railway Co,78 Lord Alverstone CJ adopted the following definition given by Johnson J in Graham v Belfast and Northern Counties Railway Co:79

“Wilful misconduct … means misconduct to which the will is party as contradistinguished from accident, and is far beyond any negligence, even gross or culpable negligence, and involves that a person wilfully misconducts himself, who knows and appreciates that it is wrong conduct in his part in the existing circumstances to do, or to fail or to omit to do (as the case may be), a particular thing, and yet intentionally does or fails or omits to do it, or persists in the act, failure or omission, regardless of the consequences. The addition which I [Lord Alverstone] would suggest is ‘or acts with reckless carelessness, not caring what the results of his carelessness may be’.”

In order to avoid any doubts as to the scope and meaning of “wilful II-2.29 misconduct”, the standard practice is to define the term “wilful misconduct” in the JOA itself as a “deliberate or reckless action resulting in loss”, a definition which is a much narrower concept than simple negligence, and one with a higher evidential burden 22.9 (Liability for Consequential and Indirect Damages), when any liability results from the Gross Negligence or Willful Misconduct of a Party, that Party shall be solely responsible for such liability (including all losses, damages, Costs, expenses or Claims)      [Select this provision if the Participating Parties will share in the liability Regardless of Fault up to a specified dollar amount.]     0 in excess of ____ billion dollars ($ _,000,000,000), to the extent such liability is attributable to its Gross Negligence or Willful Misconduct. Fines and penalties assessed against a Party in connection with activities or operations under this Agreement or in connection with the Leases shall be the sole responsibility of such Party only to the extent such fines and penalties are attributable to or the result of such Party’s Gross Negligence or Willful Misconduct.      In no event shall an assertion or allegation of Gross Negligence or Willful Misconduct of a Party constitute a defense to the other Parties’ obligations to timely reimburse the Operator for its proportionate share of losses, damages, Costs, expenses and Claims in accordance with the provisions of Exhibit ‘C.’ To the contrary, all Parties shall timely pay their proportionate share of such losses, damages, Costs, expenses and Claims until such assertion or allegation results in a final, non-appealable judgment or final determination of the arbitrators pursuant to Exhibit ‘H,’ subject to reimbursement with interest (assessed at the rate set forth in Exhibit ‘C’) or other adjustment for amounts paid [Select this provision if the Participating Parties will share in the liability Regardless of Fault up to a specified dollar amount by checking the optional provision above.]      0 in excess of the ___ billion dollars ($_,000,000,000), upon such final judgment or arbitration determination, if appropriate. 77  It is, however, to be found in certain UK statutes; see the discussion later in this paragraph. 78   [1905] 2 KB 532, at 535–536. 79   [1901] 2 IR 13.

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resting on the party which seeks to rely upon it. The 2009 Model JOA, clause 1.1 defines “wilful misconduct” as: “an intentional, or reckless disregard by Senior Managerial Personnel of Good Oilfield Practice or any of the terms of this Agreement in utter disregard of avoidable and harmful consequences but shall not include any act, omission, error of judgement or mistake made in the exercise in good faith of any function, authority or discretion vested in or exercisable by such Senior Managerial Personnel and which in the exercise of such good faith is justifiable by special circumstances, including safeguarding of life, property or the environment and other emergencies”.

In addition to any contractual definition contained within the JOA itself, there is also a growing body of case law on the statutory use of the term “wilful misconduct”80 which, it is submitted, might be useful in any contractual dispute about the meaning of the terms. For example, in Porter v Magill,81 the House of Lords had to define the meaning of wilful misconduct under Section 20 of the Local Government Finance Act 1982.82 In so doing, the Lords reviewed and approved the existing case law in the following terms: “That expression [wilful misconduct] was defined by Webster J in Graham v Teesdale … to mean ‘deliberately doing something which is wrong knowing it to be wrong or with reckless indifference as to whether it is wrong or not.’ That definition was approved by the Court of Appeal [and the House of Lords] in Lloyd v McMahon … It was adopted by the Divisional Court [and by the Court of Appeal] in the present case … There was no challenge to this definition before the House and I would accept it as representing the intention of Parliament when using this expression.”83

II-2.30 In TNT Global SPA v Denfleet International Ltd,84 on the meaning of wilful misconduct under the Convention on the Contract for the International Carriage by Goods by Road (CMR) 1956, the   The phrase is used in the Convention on the Contract for the International Carriage of Goods by Road (CMR) 1956 and there is a considerable body of case law on the meaning of the term in that context. In addition, the term is found in a number of statutory provisions, eg Marine Insurance Act 1906, s 55(2); Local Government Finance Act 1982, s 20. 81   [2001] UKHL 67; [2002] 2 AC 357 (HL). 82   Section 20(1) of the Local Government Finance Act 1982 provided:     “(1) Where it appears to the auditor carrying out the audit of any accounts under this Part of this Act … (b) that a loss has been incurred or deficiency caused by the wilful misconduct of any person, he shall certify that … the amount of the loss or the deficiency is due from that person and, subject to subsections (3) and (5) below, both he and the [local authority] in question … may recover that … amount for the benefit of that [local authority]”. 83   Porter v MaGill [2002] 2 AC 357 HL per Lord Bingham of Cornhill, at para 19. 84   [2007] EWCA Civ 405; [2008] 1 All ER (Comm) 97; [2007] 2 Lloyd’s Rep. 504. 80

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Court of Appeal gave a useful summary of the various authorities. The case concerned a lorry driver who fell asleep at the wheel causing an accident and the issue was whether this amounted to wilful misconduct. The court concluded that falling asleep at the wheel does not amount to wilful misconduct, partially for evidential reasons, and the case is a good example of what degree of misconduct is necessary before a court will consider it wilful. The court cited with approval85 Forder (above) and also the passage in National Semiconductors (UK) Ltd v UPS Ltd86 where Longmore J, having considered various authorities on wilful misconduct, said:87 “If I summarise the principle in my own words, it would be to say that for wilful misconduct to be proved there must be either (1) an intention to do something which the actor knows to be wrong or (2) a reckless act in the sense that the actor is aware that loss may result from his act and yet does not care whether loss will result or not or, to use Mr Justice Barry’s words in Horobin’s case, ‘he took a risk which he knew he ought not to take’ [1952] 2 Lloyd’s Rep. at p 460.”

Although most of these judicial definitions of wilful misconduct II-2.31 have been given in the context of statutory interpretation, there seems to be no need to restrict them to that setting, an approach confirmed by the Court of Appeal in TNT Global where the court did not restrict its search for authorities on the definition of wilful misconduct merely to cases on the CMR itself. It is submitted that this judicial exposition of the meaning of wilful misconduct by the Lords in Porter v Magill88 as “deliberately doing something which is wrong knowing it to be wrong or with reckless indifference as to whether it is wrong or not” is one which well captures the concept of wilful misconduct as used in the oil industry generally and in JOAs in particular. Deepwater Horizon oil spill in the Gulf of Mexico 2010 An example of how important a wilful misconduct clause can be II-2.32 when a joint venture finds itself in difficulties was given by the Deepwater Horizon major oil spill incident at the Macondo field in the Gulf of Mexico off the coast of Louisiana, when, as a result of a blow-out, 11 men were killed and between 3 and 5 million barrels of oil spewed into the Gulf, causing huge environmental harm to over 1,300 miles of the Gulf of Mexico’s coastline.

  Opinion of Court, paras 8–13 [2007] 1 CLC 710, at 714–715.   [1996] 2 LL Rep 212. 87   Ibid, at 214. 88   [2001] UKHL 67; [2002] 2 AC 357 (HL). 85 86

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II-2.33 The Macondo field was owned and developed by a joint venture with BP as operator and a 65 per cent interest, and non-operators Anadarko Petroleum (25 per cent interest) and Mitsui of Japan (10 per cent interest). As co-venturers and under the fundament principle that parties to a joint venture bear all costs in proportion to their interest in the JOA, one would have expected that each party would have been responsible for its share of the costs, viz. 65 per cent, 25 per cent and 10 per cent, respectively. However, after the blow-out occurred, both Anadarko and Mitsui argued that the responsibility for the blow-out was BP’s alone and that they should not be held liable for their share of the enormous costs. For example, in June 2010, Anadarko Petroleum Corporation announced that it would not contribute towards the massive compensation costs resulting from the oil spill on the ground that “BP’s behavior and actions likely represent gross negligence or wilful misconduct and thus affect the obligations of the parties under the operating agreement”.89 To put the matter concisely, Anadarko sought to escape from its liability for 25 per cent of all costs arising out of the Deepwater Horizon   From the press release issued by Anadarko Petroleum Corporation, Houston, TX, on 18 June 2010, this is a fuller extract: “(BUSINESS WIRE) – Following this week’s hearings in Washington regarding the Deepwater Horizon tragedy, Anadarko Petroleum Corporation (NYSE: APC) issued the following statement:  ‘The events surrounding the Deepwater Horizon explosion represent a terrible loss for the families of those who lost their lives and an unprecedented environmental tragedy,’ Anadarko Chairman and CEO Jim Hackett said. ‘Sadly, it also continues to have tremendous impacts on the livelihoods of many Gulf Coast families and their communities. We, along with others in the industry, have continued to support the Unified Command in its response with technical expertise and specialized equipment.  ‘The mounting evidence clearly demonstrates that this tragedy was preventable and the direct result of BP’s reckless decisions and actions. Frankly, we are shocked by the publicly available information that has been disclosed in recent investigations and during this week’s testimony that, among other things, indicates BP operated unsafely and failed to monitor and react to several critical warning signs during the drilling of the Macondo well. BP’s behavior and actions likely represent gross negligence or wilful misconduct and thus affect the obligations of the parties under the operating agreement,’ continued Hackett.  Under the terms of the joint operating agreement (JOA) related to the Mississippi Canyon block 252 lease, BP, as operator, owed duties to its co-owners including Anadarko to perform the drilling of the well in a good and workmanlike manner and to comply with all applicable laws and regulations. The JOA also provides that BP is responsible to its co-owners for damages caused by its gross negligence or wilful misconduct. Importantly, any actions Anadarko may take under the agreement to protect its rights relative to BP’s performance as operator in the drilling of the well will in no way shift any financial burden to the American taxpayer. Hackett also said, ‘We recognize that ultimately we have obligations under Federal law related to the oil spill, but will look to BP to continue to pay all legitimate claims as they have repeatedly stated that they will do’. Available at www. anadarko.com/Investor/Pages/NewsReleases/NewsReleases.aspx?release-id=1439839 (accessed 1 September 2010).

89

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blow-out and consequential massive oil spill by arguing that as BP’s behaviour amounted to wilful misconduct, BP alone should bear the clean-up costs which eventually amounted to $62 billion.90 Although legal action between the co-venturers was threatened in order to establish whether or not BP had been responsible for wilful misconduct, eventually all three parties reached an out-ofcourt settlement in which Anadarko and Mitsui paid lump sums to BP, transferred their share of the JOA to BP and were indemnified against all further costs by BP. In effect, the non-operators bought themselves out of their liability under the Macondo JOA. Anadarko paid BP $4 billion91 and Mitsui agreed to pay BP $1.06 billion.92 Given that the total costs of the Deepwater Horizon blow-out came to $62 billion ($44 billion after tax),93 Anadorko and Mitusi seem to have made a good deal with BP. The $62 billion BP liability was a total made up of compensation payments to parties affected by the oil pollution, $14 billion on stopping the leak and cleaning up oil, and major fines such as a $20 billion settlement with the US Federal Government and the five affected riparian states and $4.5 billion on criminal fines for breach of environmental statutes. It is good practice to explicitly exclude any potential liability II-2.34 by the operator for consequential losses, and if the formulation contained in the 2009 Model JOA is followed, then the operator has no liability whatsoever to the non-operators for any consequential loss suffered by them because of the acts or omissions of the operator, even should he be guilty of wilful misconduct.94 The operator will make contracts on behalf of the joint venture, II-2.35 but contracts above a defined level of value may only be made by

 See Financial Times, “BP draws line under Gulf spill costs”, 24 July 2016, available at www.ft.com/content/ff2d8bcc-49e9-11e6-8d68-72e9211e86ab (accessed 7 May 2017). 91  BP, Press Release, “BP announces settlement with Anadarko Petroleum Company of claims related to Deepwater Horizon accident”, 17 October 2011, available at www.bp.com/en/global/corporate/media/press-releases/bp-announces-settlement-withanadarko-petroleum-company-of-claims-related-to-deepwater-horizon-accident.html (accessed 7 May 2017). 92  BP, Press Release, “BP announces settlement with Moex/Mitsui of claims between the companies related to the Deepwater Horizon accident”, 20 May 2011, available at www.bp.com/en/global/corporate/media/press-releases/bp-announces-settlement-withmoexmitsui-of-claims-between-the-companies-related-to-the-deepwater-horizon-accident. html (accessed 7 May 2017). 93  See Financial Times, “BP draws line under Gulf spill costs”, 14 July 2016, available at www.ft.com/content/ff2d8bcc-49e9-11e6-8d68-72e9211e86ab (accessed 29 September 2017) and BP, Press Release, “BP estimates all remaining material Deepwater Horizon liabilities”, 14 July 2016, available at www.bp.com/en/global/corporate/media/pressreleases/bp-estimates-all-remaining-material-deepwater-horizon-liabilitie.html (accessed 7 May 2017). 94   2009 Model JOA, cl 6.2.4(b). 90

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the operator with the consent of the JOC and after being put out to competitive tender.95 II-2.36 The operator is obliged to acquire and maintain all appropriate insurances in compliance with the requirements of the licence and any other applicable legislation, or of “any contract entered into by the Operator in furtherance of Joint Operations … except in respect of any insurance which the Operator must take out in its own name”.96 The cost of insurance is charged between the co-venturers in proportion to their respective percentage interests, unless a co-venturer chooses not to participate in the insurance.97 The only required insurances are those for employee protection98 (which will be carried in the operator’s own name) and the pollution insurance provided by the Offshore Pollution Liability Agreement (OPOL),99 which is required of the operator by all UKCS JOAs.100 The operator will also take out on behalf of the entire joint venture any other insurance which the Joint Operating Committee thinks appropriate.101 The most common form of optional insurance taken out by a JV is Construction All Risk (CAR) insurance to cover the construction of the installation and any other joint developments. The operator is also required to give notice to the non-operators of any incidents which may give rise to litigation. The operator is generally authorised to conduct any litigation arising out of the joint operations up to a low limit but otherwise generally may only conduct litigation with the approval of the Opcom.102

  Ibid, cll 6.5.4 and 6.5.5.   Ibid, cl 8.1. 97   Ibid, cl 8.1.1. 98  Under the Employers’ Liability (Compulsory Insurance) Act 1969 employers must provide insurance for all employees working in the UK, and this legislation has been extended offshore. 99  The most recent version, 1 January 2010, of OPOL is available from the Offshore Pollution Liability Association Ltd website at www.opol.org.uk (accessed 7 May 2017). Under OPOL, member operating companies agree to accept strict liability for pollution damage and the cost of remedial measures with only certain exceptions, up to a maximum of US $120,000,000 per incident. As a result of the concerns arising in the wake of the Deepwater Horizon explosion on 20 April 2010 in the Gulf of Mexico, the UK signatories to the OPOL met on 18 August 2010 and agreed to raise the compensation limit from $120 million to $250 million per incident. These changes took effect from 1 October 2010. Financial Times, “Oil groups ready to fight tougher rules”, 18 August 2010, available at www.ft.com/cms/s/0/be351e8e-aaf6-11df-9e6b-00144feabdc0.html (accessed 7 May 2017) and private correspondence with OPOL. Within this limit there may also be included the cost of remedial measures undertaken by the party to OPOL involved in the incident. 100   2009 Model JOA, cl 8.2. 101   Ibid, cl 8.1.1. 102   Ibid, cl 8.3. 95 96

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Agency of the operator Unlike the position with partnership,103 the typical JOA contains no II-2.37 clause expressly denying the agency of the Operator with respect to the joint venture (obviously there is no need to deny the agency of the non-operators). This is not surprising given that the relationship between the operator and non-operators is inevitably in the form of agency. When contracting on behalf of the joint venture, the operator will, by definition, be acting qua agent for the group of principals who are the members of the JOA. Agency creates liability in the principal, ie, the non-operators – for the authorised contracts and actions of the agent. Accordingly, in the case of a typical JOA, the operator will simultaneously be a joint principal along with the other JOA members and acting in a representative capacity as agent. In this sense at the least, the role performed by the operator is analogous to that of a partner contracting on behalf of a partnership where the roles of agent and principal are performed concurrently. Whether or not the agency of the operator is disclosed or II-2.38 undisclosed is a matter of varying practice. The 2009 Model JOA provides that all contracts made by the operator are made for itself and also as agent and should disclose the fact that the operator is acting qua agent.104 Where an operator does not disclose that he is contracting on behalf of the JV, this would be deemed by the courts to be an instance of undisclosed agency.105 As regards a third party, the standard rule in undisclosed agency is that the third party must elect to sue either the agent or the principal, once the fact of the undisclosed agency has been disclosed to or discovered by the third party. However, this doctrine of election is irrelevant in the case of a JOA because the doctrine is based on the premise that the apparent principal was in reality only an agent and the undisclosed principal was the real principal, whereas in the case of undisclosed operatorship – ie, the operator contracting apparently as principal – the operator is both principal and agent. Accordingly, it would seem to follow logically that the third party would be able to sue both the operator and the undisclosed non-operators together if the need arose. Likewise, in a situation of undisclosed agency, the non-operators are entitled to sue the third party once the agency is disclosed. The 2009 Model JOA attempts to get round these complexities by the paradoxical provision that the operator should disclose his agency when making contracts but notwithstanding the disclosure of agency any rights and duties arising out of the contract

  See para II-2.15.   2009 Model JOA, cl 6.5.8. 105   Watteau v Fenwick [1893] 1 QB 346 is the leading case. 103 104

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may be claimed against or made by the operator alone.106 The effect of such a provision is effectively to prevent the imposition on the operator of any agency duties which would arise under the common law of agency by means of a contractual agreement to exclude the application of any such duties. However, to be effective the contents of this clause would have to be accepted by any third party contracting with the operator, as the internal contractual arrangements of the co-venturers naturally cannot affect the position of a third party unless that third party explicitly accepts them. Even if a third party were to do so, there must be some doubt as to whether these terms would be upheld by a court as they seem to give the co-venturers all the benefits of being a principal (because through the mechanism of the JOA they can compel the operator to sue on their behalf) but gives them apparent immunity from suit by third parties. It is submitted that, on the grounds of agency law, public policy and the terms of the Unfair Contract Terms Act 1977, a court might well strike down such clauses. In the case of tortious liability, as opposed to contractual liability, the agent is personally liable alone unless the wrongful act was in the course of his duties or authorised or ratified by the principal. In the case of a JOA, it follows that the operator alone will be liable unless the Opcom authorised or ratified the wrongful act, or it was clearly within the scope of his responsibilities as agent. Should an operator be found liable in tort, then the

  2009 Model JOA, cl 6.5.8 provides: “The Operator shall act as agent of the Participants in dealings with contractors and shall use all reasonable endeavours to include in all contracts made pursuant to this Agreement, a provision which ensures that the Operator makes the contract on behalf of all the Participants. The Operator shall use all reasonable endeavours to include in all such contracts provisions in the following or similar form for which purpose ‘COMPANY’ refers to the Operator and ‘CO-VENTURERS’ refers to the Non-operators: The COMPANY enters into the CONTRACT for itself and as agent for and on behalf of the other CO-VENTURERS. Notwithstanding the above:   (a) the CONTRACTOR agrees to look only to the COMPANY for the due performance of the CONTRACT and nothing contained in the CONTRACT will impose any liability upon, or entitle the CONTRACTOR to commence any proceedings against any CO-VENTURER other than the COMPANY;   (b) the COMPANY and only the COMPANY is entitled to enforce the CONTRACT on behalf of all CO-VENTURERS as well as for itself. For that purpose the COMPANY shall commence proceedings in its own name to enforce all obligations and liabilities of the CONTRACTOR and to make any claim which any CO-VENTURER may have against the CONTRACTOR.  (c) all losses, damages, costs (including legal costs) and expenses recoverable by the COMPANY pursuant to the CONTRACT or otherwise shall include the losses, costs (including legal costs) and expenses of the COMPANY’s CO-VENTURERS and AFFILIATES except that such losses, damages, costs (including legal costs) and expenses shall be subject to the same limitations or exclusions of liability applicable to the COMPANY or the CONTRACTOR under the CONTRACT.”

106

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non-operators will be liable pro rata to the operator for any damages he has to pay in compensation. Fiduciary duties Some commentators have argued that joint ventures give rise to II-2.39 fiduciary duties because, rather than working at arm’s length as in a normal commercial contractual situation, the co-venturers are working together towards the same goal: the finding of petroleum and maximising its extraction.107 But the importance of the terms of the contract must be stressed in establishing whether or not there is a fiduciary duty.108 This was a point made by Lord Browne-Wilkinson, giving the judgment of the Privy Council in Kelly v Cooper,109 where, quoting with approval from the judgment of Mason J in Hospital Products Ltd v United States Surgical Corp,110 he stated: “That contractual and fiduciary relationships may co-exist between the same parties has never been doubted. Indeed, the existence of a basic contractual relationship has in many situations provided a foundation for the erection of a fiduciary relationship. In these situations it is the contractual foundation which is all important because it is the contract that regulates the basic rights and liabilities of the parties. The fiduciary relationship, if it is to exist at all, must accommodate itself to the terms of the contract so that it is consistent with, and conforms to them. The fiduciary relationship cannot be superimposed upon the contract in such a way as to alter the operation which the contract was intended to have according to its true construction.”111

A useful definition of fiduciary duties was given by Millett LJ in II-2.40 Bristol and West Building Society v Mothew: “A fiduciary is someone who has undertaken to act for or on behalf of another in a particular matter in circumstances which give rise to a relationship of trust and confidence. The distinguishing obligation of a fiduciary is the obligation of loyalty. The principal is entitled to the single-minded loyalty of his fiduciary. This coreliability has several facets. A fiduciary must act in good faith; he must not make a profit out of his trust; he must not place himself in a position where his duty and his interest may conflict; he may not act for his own benefit or the benefit of a third person without the informed consent  The most exhaustive account of this view can be found in G Bean, Fiduciary Obligations and Joint Ventures: The Collaborative Fiduciary Relationship (1995) (hereinafter “Bean, Fiduciary Obligations and Joint Ventures”). 108  The contracts used in the UKCS will often exclude or at least seriously curtail the possibility of fiduciary duties: see para II-2.43. 109   Kelly v Cooper [1993] AC 205 (hereinafter “Kelly v Cooper”). 110   (1984) 55 ALR 417, at 454–455. 111   Kelly v Cooper per Lord Browne-Wilkinson, at 215. 107

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of his principal. This is not intended to be an exhaustive list, but it is sufficient to indicate the nature of fiduciary obligations. They are the defining characteristics of the fiduciary … he is not subject to fiduciary obligations because he is a fiduciary; it is because he is subject to them that he is a fiduciary.”112

II-2.41 The difficulty of establishing when fiduciary duties occur was highlighted by Lord Browne-Wilkinson in Henderson v Merrett Syndicates Ltd: “The phrase ‘fiduciary duties’ is a dangerous one, giving rise to a mistaken assumption that all fiduciaries owe the same duties in all circumstances. That is not the case. Although, so far as I am aware, every fiduciary is under a duty not to make a profit from his position (unless such profit is authorised), the fiduciary duties owed, for example, by an express trustee are not the same as those owed by an agent. Moreover, and more relevantly, the extent and nature of the fiduciary duties owed in any particular case fall to be determined by reference to any underlying contractual relationship between the parties. Thus, in the case of an agent employed under a contract, the scope of his fiduciary duties is determined by the terms of the underlying contract … The existence of a contract does not exclude the coexistence of concurrent fiduciary duties (indeed, the contract may well be their source); but the contract can and does modify the extent and nature of the general duty that would otherwise arise.”113

II-2.42 A fiduciary duty may therefore be summed up as the obligation not to make a profit at the expense of, or hidden from, one’s partners (using that term in a loose, non-technical sense). There are two possible grounds for arguing that a JOA gives rise to fiduciary duties. The first possible ground, which would apply equally to all the co-venturers, is that as the contractual relationship is joint, there is an element of mutuality which gives rise to a fiduciary relationship. The second possible ground stems from the law of agency, and on the basis that as the operator is an agent, he is automatically in a fiduciary relation to the non-operators. If a fiduciary duty were to apply to a JOA, it would logically apply with equal measure to all the co-venturers and not just the operator, although arguably the operator has more opportunities for the making of secret profits, for example by taking a secret commission from a contractor. That said, non-operators could abuse their position by, for instance, using confidential data confided to them qua JOA members.114   Bristol and West Building Society v Mothew [1998] Ch 1 per Millet LJ, at 18.   Henderson v Merrett Syndicates Ltd [1995] 2 AC 145 per Lord Browne-Wilkinson, at 206A–D. 114   A duty of confidentiality is in any case an explicit term of any well-drafted JOA. 112 113

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There has been some judicial support for the existence of fiduciary II-2.43 duties in various common law jurisdictions. In the US, for example, the Kansas Supreme Court has held that the parties to a JOA were in “fiduciary like” relations and owed a duty of fair dealing to each other.115 Also, Alberta, Canada has proved especially welcoming of the application of fiduciary principles to JOAs.116 But so far there is no case law to support this argument in English or Scots law. The concept of fiduciary duty is unlikely to have much application in UKCS JOAs for three reasons. Firstly, in almost all important decisions, the operator can only act with the authority of his fellow co-venturers as given by the Opcom. The UKCS operator, therefore, has much less scope for independent decision making than operators acting under the US AAPL Form 610, or under the Canadian CAPL Operating Procedure JOA which gives the non-operators far less say in the conduct of the operations, and gives the operator correspondingly greater freedom. Secondly, the tendency in the UKCS is to exclude (or at least substantially curtail the effect of) the application of fiduciary duties through the drafting of the JOA.117 Thirdly, UKCS JOAs generally contain a clause reducing the entire agreement to

  Amoco Production Co v Wilson, 976 P 2d 941. For an analysis of this case R James, “Kansas Oil and Gas Law: Defining the Duty between Participants in a Joint Operating Agreement”, 39 (1999) Washburn L J 128. 116  See Bank of Nova Scotia v Société Générale (Canada) (1988) 87 AR 133, 58 Alta LR (2d) 193 (Alberta CA); Luscar Ltd v Pembina Resources Ltd (1995) 24 Alta LR (3d) 305, [1995] 2 WWR 153 (Alberta CA); Erewhon Exploration Ltd v Northstar Energy Corp (1993) 147 AR 1, 15 Alta LR (3d) 200 9 (Alberta QB). 117  See 2009 Model JOA, cl 1.1 definition of “Consequential Loss”: “‘Consequential Loss’ means any indirect or consequential loss howsoever caused or arising whether under contract, by virtue of any fiduciary duty, in tort or delict (including negligence), as a consequence of breach of any duty (statutory or otherwise) or under any other legal doctrine or principle whatsoever whether or not recoverable at common law or in equity. ‘Consequential Loss’ shall be deemed to include, without prejudice to the foregoing generality, the following to the extent to which they might not otherwise constitute indirect or consequential loss:  (a) loss or damage arising out of any delay, postponement, interruption or loss of production, any inability to produce, deliver or process hydrocarbons or any loss of or anticipated loss of use, profit or revenue;  (b) loss or damage incurred or liquidated or pre-estimated damages of any kind whatsoever borne or payable, under any contract for the sale, exchange, transportation, processing, storage or other disposal of hydrocarbons;   (c) losses associated with business interruption including the cost of overheads incurred during business interruption;   (d) loss of bargain, contract, expectation or opportunity;   (e) damage to any reservoir, geological formation or underground strata or the loss of hydrocarbons from any of them;   (f) any other loss or anticipated loss or damage whatsoever in the nature of or consequential upon the foregoing.” 115

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the express written terms of the JOA.118 Taken together, these three considerations would seem to exclude the potential importation of fiduciary duties into the agreement by the UK courts. The non-operators II-2.44 The role of the non-operators in the joint venture is one of non-operating, non-working interest owners or, to put it more simply, one of an investor. But non-operators are active investors, in that they have an active say in the managing of the project through the Joint Operating Committee.119 The existence of the Opcom is one of the most significant differences between the typical UKCS JOA, such as the 2009 Model JOA, and a US JOA based on AAPL Form 610, where there is no provision for an Operating Committee.120 The most important duty of a non-operator is to provide its share of funds when faced with a cash call. Should any co-venturer fail to pay its share, when called upon to do so, then it will be deemed to be in default.121 MANAGING THE JOINT VENTURE AND THE RELATIONSHIP BETWEEN THE MEMBERS: THE JOINT OPERATING COMMITTEE (THE OPCOM) II-2.45 Ultimate responsibility for the management of the joint venture is entrusted to the Joint Operating Committee. The Opcom is composed of representatives of each of the members of the JOA. Normally the JOA will provide that each member is entitled to one representative on the Opcom but the representatives may send

118   See 2009 Model JOA, cl 3.2: “This Agreement represents the entire understanding of and agreement between the Participants in relation to the matters dealt with in this Agreement, and supersedes all previous understandings and agreements, whether oral or written, relating to such matters. Each Participant agrees that it has not been induced to enter into this Agreement in reliance upon any statement, representation, warranty or undertaking other than as expressly set out in this Agreement, and to the extent that any such representation, warranty or undertaking has been given, the relevant Participant unconditionally and irrevocably waives all rights and remedies which it might otherwise have had in relation to it …”; as well as cl 31.2: “This Agreement represents the entire agreement of the Participants in relation to its subject matter and supersedes any prior understanding, agreements or undertakings in relation to it (other than the JOA).” 119   This may be contrasted with the passive investor role of a shareholder in a corporation. 120  For an excellent discussion of the differing positions of non-operators in UK and US JOAs see E Pereira, “Rights and Obligations under Oil and Gas Joint Operating Agreements – The Non-Operator’s Perspective: A Comparative and Evaluative Study”, 6 (2011), OGEL, available at www.ogel.org/article.asp?key=3218 (accessed 7 May 2017). 121   For further discussion on “Default and Forfeiture”, see para II-2.54 onwards.

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alternatives when necessary and likewise may invite other persons to attend to give technical advice as appropriate.122 Voting on the Opcom is weighted, with each representative casting a voting interest equal to the percentage interest in the JOA held by the member he represents.123 The Opcom will normally appoint area-specific subcommittees to deal with the major technical matters in more detail. Typical subcommittees would be technical, commercial and reservoir subcommittees. In practice, often the decisions are substantially made by the experts in the subcommittees, which are then ratified by the Opcom itself. The authority of the Opcom will encompass all major policy II-2.46 decisions involving the joint venture. The JOA will probably specify the powers of the Opcom in the broadest possible way and then add some specific examples of matters which are encompassed by that general authority such as the consideration, revision and approval, or disapproval, of all proposed programmes, budgets and “authorisations for expenditure”, generally referred to simply as AFEs, and deciding upon the timing and location of any wells drilled.124 There will also generally be a provision in the JOA authorising the operator to act without agreement or consultation in the case of an emergency. As mentioned above, voting in all Opcom decisions is pro rata II-2.47 to the interest of the participating members. However, the effective   2009 Model JOA, cl 9.2.   Ibid, cl 9.8.1. 124  For more detail on AFEs see para II-2.49. See 2009 Model JOA, cl 9.1: “There is hereby established a Joint Operating Committee which shall exercise overall supervision and control of all matters pertaining to the Joint Operations. Without limiting the generality of the foregoing, but subject as otherwise provided in this Agreement, the powers and duties of the Joint Operating Committee shall include: (a) the consideration and determination of all matters in general relating to policies, procedures and methods of operation hereunder with the intent that all such operations should be undertaken in a manner consistent with Good Oilfield Practice and in compliance with best practice standards in respect of health and safety and of the environment; and   (b) the consideration, and, if so required, determination of inter alia the following:   (i) exploration, appraisal, development and production strategies;   (ii) contract strategy;   (iii) decisions as to cessation of production, strategies for Decommissioning and the disposal of Joint Property; and   (iv) any other matter relating to the Joint Operations which may be referred to it by the Participants or any of them (other than any proposal to amend this Agreement) or which is otherwise designated under this Agreement for reference to it.   (c) the approval of Programmes and Budgets;   (d) the amendment of the monetary limits set out in this Agreement from time to time either generally or in respect of particular operations or particular phases of operations, to take account of the general level of inflation and (if appropriate) the prevailing costs of relevant goods and services, at the request of the Operator or any Participant.” 122 123

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value of any percentage voting right will be affected by the “pass mark” laid down in the JOA. The pass mark is the percentage interest share of votes which must be obtained before the Opcom may make a binding decision. Obviously, the pass mark cannot be less than 50 per cent, but often it is much higher, 70 per cent being a common level. Decisions as to the size of the pass marks tend to be one of the most hotly contested matters when a JOA is being negotiated. A low pass mark will give the largest interest holder dominant position, while a higher pass mark will give smaller interest holders more influence on the management of the joint venture. The JOA is a private contract, not an experiment in participatory democracy, and the actual pass mark is a matter for negotiation and agreement between the parties, the outcome being dependent on the relative contractual strengths of the parties and the degree of trust they have in each other. It is also possible to have different pass marks for different types of decision, for example, a lower pass mark for the comparatively low-cost exercises of exploration and appraisal than for the much more expensive activity of development. Certain major decisions will typically be specified as requiring unanimity, for example, relinquishment of the licence. II-2.48 As the operator is very much in control of day-to-day operations, one of his major duties to the non-operators is to keep them informed of developments and this will be done by providing the Opcom representatives with reports and data. Expenditure II-2.49 As mentioned above, the day-to-day control of joint operations rests with the operator. In practice, this reduces the position of the non-operators to one major duty and one major right. The major duty is to pay pro rata for all expenditure authorised by the Opcom and to contribute pro rata towards any liabilities incurred by the joint operations. The non-operators’ major right is to uplift pro rata their share of any production arising out of the joint operations.125 In practice, the main way the non-operators exercise influence over the development of the joint operations is through the Opcom’s control of the approval of programmes and budgets, a procedure which is generally done annually.126 The programme will outline any work which the joint venture plans to undertake and the budget is the estimate of how much those works will cost. The budget is usually divided into a capital budget to cover drilling and development

  2009 Model JOA cl 18.   Ibid, cll 10–13.

125 126

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costs and an operating budget for staff costs and overheads.127 It is generally recognised that both programme and budget are “living documents” and may require amendment as events unfold. A budget is in the way of an estimate of costs, but does not of itself authorise the operator to demand financial contributions from the JOA members; rather this is done by the eponymous “authorisation for expenditure”.128 The need for the operator to secure agreement on AFEs greatly strengthens the influence of the non-operators over the development of joint operations, as it means there can be no cash call on the non-operators without sufficient consent to make the stipulated pass mark.129 Sole risk and non-consent In an ideal world, there would be unanimous agreement among the II-2.50 members on all significant decisions. In practice, there will from time to time be disagreements among the members and normally these disputes will be resolved within the Opcom by means of decisions taken which secure a pass mark. Where, however, for some reason there is a disagreement on a fundamental decision of policy as to whether to engage in further operations, disputes may be resolved by the use of “sole risk” or “non-consent” clauses, each of which allows for the non-participation of one or more members. The difference between the two types of clause is essentially II-2.51 between the amount of support a proposal has obtained at the JOC. A sole risk project is one which has failed to obtain the pass mark in the Opcom, but which the defeated member or members nevertheless wish to go ahead. A non-consent project, by contrast, is one which succeeds in obtaining the pass mark in the Operating Committee, but where the outvoted minority nevertheless elect not to participate in the proposed project. Both sole risk and non-consent clauses are in a very real sense inimical to the very raison d’être of a joint venture: mutual decision-making with the aim of sharing of risk, costs and production. In practice, sole risk clauses are much more common in UKCS JOAs than non-consent clauses.130 Where a project   Ibid, cl 14.3.   Ibid, cll 10.2, 11.2, 12.2 and 13.2, read together with cl 14.1.5. 129   For discussion of the “pass mark”, see para II-2.49. 130   For example the UKOOA 20th Round Draft JOA provides for a sole risk clause (clause 14) but not a non-consent one. However, the 2009 Model JOA, cl 11.1.4 provides a non-consent option with respect to amending “Development Programmes and Budgets”: “Upon the Secretary authorising … the commencement of the development, any of the Participants may, if [the JOC approved Development Programme and Budget] has been or is required to be amended … elect not to proceed with the development … [In such an event the] provisions of clause 15.8.6 shall apply.” Clause 15.8.6, in turn, states that 127 128

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proceeds on a sole risk basis, the sole risking members will bear all the costs of the operation,131 and will be entitled to the entirety of any production that should result from the sole risk operations. In principle, and legal and economic logic, the non-sole risk members should not be entitled to any production which ensues from the sole risk operation. However, most JOAs which contain a sole risk clause will also provide measures which allow the non-sole risk members to buy themselves back into a share of the production, but only on the basis of a large premium.132 The most likely member to be a sole risker is the operator, but where it is a non-operator then the JOA will allow the operator to carry out the sole risk project on behalf of the sole risker, or to cease acting as operator either by volunteering to do so or on the request of the sole risk members.133 Where sole risk operations are in progress, the JOA will usually provide that they will be managed by an Operating Committee comprised only of sole risk members.134 II-2.52 There is only one reported case on the interpretation of sole risk and non-consent clause in the UK courts, that of Ithaca Energy (UK) Ltd v North Sea Energy (UK) Ltd.135 The case concerned a JOA operating the ‘Jacky J03’ well in the inner Moray Firth area of the North Sea. There were three parties to the JOA: Ithaca (having a 47.5 per cent share; the Operator); Dyas (having a 42.5 per cent share) and NSE (10 per cent). The JOA contained a pass mark of 65 per cent for making binding decisions, but also contained sole risk and non-consent clauses for certain specified operations. One of the specified operations was for non-consent to certain types of drilling, defined as: “the drilling, completion and production testing of an appraisal well inside, or the carrying out of geophysical work in respect of, the interpreted closure of any geological structure or stratigraphic trap on which a well has been drilled in which Petroleum has been found to be present.”

“In the event that, following the Secretary authorising … the commencement of a development in which all the Participants are participating, any of the Participants elects not to proceed with the development under clause 11.1.4, the other Participants shall be entitled to proceed with the development in accordance with the approved development Programme and Budget (as amended) …”. 131  The sole risker will also solely bear any liability to third parties arising out of the sole risk operations by means of indemnifying and holding harmless the non-sole risk members. See 2009 Model JOA, cl 15.2.5. 132   For the premium on acquiring information and data see 2009 Model JOA cll 15.4.5 and 15.7.6; for buying back into a discovery as a result of sole risk drilling see 2009 Model JOA cl 15.6; and for development see 2009 Model JOA, cl 15.8. 133   2009 Model JOA, cl 15.2.9. 134   Ibid, cl 15.2.10(a). 135   Ithaca Energy (UK) Ltd v North Sea Energy (UK) Ltd [2012] EWHC 1793

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Ithaca and Dyas wished to undertake further drilling, but NSE did II-2.53 not. At the Opcom NSE was outvoted 90 per cent to 10 per cent. Ithaca and Dyas designated this work as production drilling at the Opcom and in correspondence. NSE disputed this characterisation of the drilling as had the well been designated an “appraisal” well they would have been entitled to opt out of contributing to the costs of this well under the non-consent clause. NSE lost the argument, as the court concluded that the well in question was not an appraisal well but a production well, because it considered contemporaneous designation of the well by the majority parties as decisive, and so NSE was obliged to contribute costs towards the drilling of the well in question. The message for parties to JOAs is to draft the non-consent conditions as clearly and as narrowly as possible. Default and forfeiture The most important duty of all members of a JOA is to provide II-2.54 funds when requested under a cash call. Each JOA is built on the founding presumption that the burden of financing operations shall be shared. Any co-venturer failing to fulfil his financial obligations under an AFE has, therefore, breached his most basic duty under the JOA. Moreover, such failure may cause real financial difficulties to the other members of the JOA, who will have to make good the shortfall. The standard remedy under a JOA for failure to honour a cash call is forfeiture.136 All JOAs will provide that monies due must be paid up after notice has been given within a set time limit. After the time limit expires without payment, the operator will issue the defaulting party with a default notice and, if the default continues for more than a short defined period (typically between 6 and 12 days), then, upon service of the default notice, the defaulter loses his rights under the JOA to attend meetings of the JOC and his right to his share of production.137 At the same time, the non-defaulting members of the JOA will have to make up the financial shortfall pro rata. The defaulting party will have the right to remedy the default at any time prior to forfeiture of his interest by payment of the sums due plus interest. If, however, the defaulting party fails to remedy the situation within the specified time – typically 60 days138 – then, in the case of a total forfeiture clause, each of the non-defaulting parties has the right to have the defaulting party’s interest forfeited to it in   Note, however, that there is more than one type of forfeiture clause: see, for example, the discussion on withering interest clauses, a specific sub-category of forfeiture clause, at para II-2.63. 137   2009 Model JOA, cl 17. 138   Ibid, cl 17.6.1. 136

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proportion to its interest.139 If the non-defaulting parties do not wish to acquire the defaulter’s interest, the JOA will normally provide that operations be abandoned, the licence surrendered and decommissioning (if appropriate) commenced, with each party remaining liable pro rata for its share of the decommissioning costs. II-2.55 Up until now, default has been quite rare within the UKCS, but as the UKCS petroleum and gas industry winds down it may well become more likely, for two reasons. Firstly, there is a current tendency in the UKCS for the major operators – the multinational giants such as Shell and BP – to divest themselves of their smaller assets in favour of smaller independent oil companies. Small companies, however, are much more likely to go bankrupt than major ones as they, by definition, do not enjoy the same financial strength to weather emergent problems. Secondly, when a field is at or near exhaustion a co-venturer has little financial incentive to stay in the licence because the licence now constitutes a liability, not an asset, in which circumstance, far from being a penalty, forfeiture might well be seen as a benefit by a party. To these factors has been added the significant fall in the price of oil which began in July 2014 when oil was $120 per barrel and reached a 12-year low in January 2016 of $30. As of the time of writing, in May 2017, the price now hovers around $50. II-2.56 The first two of these three trends came together in the case of the development of the Ardmore Field by Tuscan Energy, who became insolvent in 2005.140 Thus, one major practical weakness with forfeiture as a remedy for default on obligations, even assuming such clauses are upheld as valid,141 is that while such a sanction is of value before or during the productive life of the joint operation acreage, it is of no effect once the field has ceased producing, when all the members of the JOA can look forward to is paying the costs of abandonment. The third of these trends, the low oil price, has resulted in a sharply increased number of UK oil producers becoming insolvent. In the four years from 2012 to 2015, nine UK oil and gas companies went insolvent, whilst in 2016 alone the number was 16.142 Ultimately, the best protection a joint venturer can have is to choose his co-venturers wisely from those parties

139   Ibid, cl 17.6. See para II-2.63 for a discussion on the consequences of defaulting upon a withering interest clause. 140   As there were no other parties from whom to seek recompense, the decommissioning costs have had to be covered by the Government. 141   See the discussion on the validity of forfeiture clauses from para II-2.57 onwards. 142  See report by Moore Stephens “UK based oil and gas sector insolvencies hit a new high”, 3 January 2017, available at www.moorestephens.co.uk/news-views/january-2017/ uk-based-oil-and-gas-sector-insolvencies (3 September 2017).

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who are competent, trustworthy and, above all, solvent and who are likely to remain so. Although the contractual provisions regarding forfeiture of II-2.57 licence interests on default are very clear, there has always been some concern within the industry as to whether such a forfeiture clause would be enforceable in court if default should occur in the production phase of the operations.143 This is because in these circumstances the defaulting party would lose everything after having already incurred a substantial expenditure towards the joint operations. Given that the whole purpose of a joint venture is the joint sharing of costs and liabilities, it is only reasonable that some sort of sanction be applied to defaulting parties. However, the issue of the validity of forfeiture for default has always been a contentious one. In the absence of direct authority in English law, aid is sought from analogous cases, such as forfeiture of leases. There are two possible threats to the validly of forfeiture clauses. First, they might be struck down as being de facto penalty clauses. Second, they may be held to breach the general law of insolvency by creating an unfair preference in favour of the JOA members. Each of these possibilities will be considered below in some detail. Forfeiture clauses may be penalty clauses Strictly speaking, forfeiture and penalty clauses are different types of II-2.58 sanction: forfeiture is the negative sanction of loss of property rights, while a liquidated damages/penalty clause is a positive obligation to pay money to the innocent party; however, in practice they have the same economic effect – a point well made by Atiyah: “… it is worth noting that penalties and forfeiture are closely related. In essence they are the same thing, the only difference between them being that the role of plaintiff and defendant are reversed. In the case of penalties, one party is seeking to recover money from the other beyond the value of the damage he has actually suffered; in the case of forfeiture, he already has the money and is seeking to keep it while the other party is trying to recover it.”144

This tendency to equate forfeiture with liquidated damages/penalty II-2.59 clauses has found increasing favour with courts.145 The general law on the issue of penalties and liquidated damages was laid down by   See G Willoughby, “Forfeiture of Interests in Joint Operating Agreements”, 3 (1985) JENRL 256–265. 144   P Atiyah, An Introduction to Contract (2nd edn, 1971), at p 269. Interestingly, this passage does not appear in more recent editions of this work. 145   See eg Jobson v Johnson [1989] 1 All ER 621 (CA) (hereinafter “Jobson v Johnson”), discussed further at para II-2.65, and the Supreme Court decision in Cavendish Square Holdings BV v El-Makdessi [2015] UKSC 67; [2015] 3 WLR 1373. 143

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Lord Dunedin in a pair of House of Lords cases in the early 20th century: Commissioner of Public Works v Hills146 and Dunlop Pneumatic Tyre Co. Ltd. v New Garage & Motor Co. Ltd.147 In the former judgment, Lord Dunedin defined the distinction between liquidate damages and penalty clauses thus: “The general principle to be deduced … is … that the criterion of whether a sum – be it called penalty or damages – is truly liquidated damages, and as such not to be interfered with by the Court, or is truly a penalty which covers the damage if proved, but does not assess it, is to be found in whether the sum stipulated for can or can not be regarded as a ‘genuine pre-estimate’ of the creditor’s probable or possible interest in the due performance of the principal obligation.”148

II-2.60 The distinction between a sanction clause being found to be liquidated damages or a penalty149 is of crucial importance because, while a liquidated damages clause can be enforced, a contractual term found to be a penalty clause is treated by the courts as invalid. Lord Dunedin, in the second judgment, laid down the criteria by which the courts make the distinction between legitimate enforceable liquidated damages clauses and unenforceable penalty clauses: “1. Though the parties to a contract who use the words ‘penalty’ or ‘liquidated damages’ may prima facie be supposed to mean what they say, yet the expression used is not conclusive. The Court must find out whether the payment stipulated is in truth a penalty or liquidated damages. This doctrine may be said to be found passim in nearly every case. 2. The essence of a penalty is a payment of money stipulated as in terrorem of the offending party; the essence of liquidated damages is a genuine covenanted pre-estimate of damage. 3. The question whether a sum stipulated is penalty or liquidated damages is a question of construction to be decided upon the terms and inherent circumstances of each particular contract, not as at the time of the breach.

  Commissioner of Public Works v Hills [1906] AC 368 (hereinafter “Commissioner of Public Works”); see also (for the position in Scots law) Clydebank Engineering and Shipbuilding Co Ltd v Don Jose Ramos Yzquierdo y Castaneda (1904) 7 F (HL) 77. 147   Dunlop Pneumatic Tyre Co Ltd v New Garage & Motor Co Ltd [1915] AC 79 (hereinafter “Dunlop Pneumatic Tyre Co Ltd”). 148   Commissioner of Public Works, at p 375f. 149  For a full discussion, see Law Commission for England and Wales Working Paper on Penalty Clauses and Forfeiture of Monies Paid (WP No 61, 1975); for a Scottish perspective see Scottish Law Commission, Report on Penalty Clauses (Scot Law Com No 171). See also the Scottish Law Commission (hereinafter “SLC”) discussion paper on penalty clauses published on 30 November 2016 as part of its current review of contract law in Scotland. 146

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joi nt op e r at i ng ag re e m e n t s 55 4. To assist this task of construction various tests have been suggested, which if applicable to the case under consideration may prove helpful, or even conclusive. Such are: (a) It will be held to be [a] penalty if the sum stipulated for is extravagant and unconscionable in amount in comparison with the greatest loss that could conceivably be proved to have followed from the breach. (b) It will be held to be a penalty if the breach consists only in not paying a sum of money, and the sum stipulated is a sum greater than the sum which ought to have been paid. This though one of the most ancient instances is truly a corollary to the last test … (c) There is a presumption (but no more) that it is [a] penalty when ‘a simple lump sum is made payable by way of compensation, on the occurrence of one or more or all of several events, some of which may occasion serious and others but trifling damage’… (d) It is no obstacle to the sum stipulated being a genuine pre-estimate of damage, that the consequences of the breach are such as to make precise pre-estimation almost an impossibility. On the contrary, that is just the situation when it is probable that pre-estimated damage was the true bargain between the parties.”150

Lord Dunedin’s judgment in Dunlop has traditionally been expressed II-2.61 as being a dichotomy between compensatory and deterrent clauses and so stress was made on the distinction between genuine pre-estimates of loss, which were enforceable, and “mere” deterrents which were unenforceable. This approach, although accurate as far as it went, was always an over-simplification in that it ignored the judgment in Clydebank Engineering & Shipbuilding Co Ltd v Don Jose Ramos Yzquierdo y Castaneda151 (in 1905) where a forfeiture clause was held enforceable even though there was no actual economic loss, because the contract was with a sovereign state (Spain) for the delivery of military vessels (torpedo boats), which should alert parties to the facts that pure economic loss is not the only factor to be considered. A straightforward example of the application of the Dunlop II-2.62 criteria is Campbell Discount Co Ltd v Bridge,152 where the House of Lords struck down as a penalty a clause in a hire purchase agreement, requiring the hirer to pay compensation for premature termination on the grounds that the clause provided a sliding scale which operated in the wrong direction: the less the depreciation of the vehicle, the greater was the compensation payable.   Dunlop Pneumatic Tyre Co Ltd per Lord Dunedin, at pp 86–88.   [1905] AC 6. 152   Campbell Discount Co Ltd v Bridge [1962] AC 600. 150 151

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II-2.63 In the 1970s and 1980s, there was widespread concern within the industry that a total forfeiture clause153 might be deemed by the courts to be a penalty clause,154 and this resulted in some parties adopting a so-called “withering interest” forfeiture clause.155 Under such a clause, the interest of the defaulting parties “withered away”, ie, decreased in proportion to the increasing amount by which the party was in default. However, withering interest clauses are very complex to apply and, in any case, all such clauses do is moderate the degree of the punishment, not eliminate the element of forfeiture. In recent years, withering interest clauses seem to have become less common in UKCS JOAs,156 but perhaps because of El-Makdessi157 (see para II-2.69) they may become more common again. II-2.64 By contrast to the above situation, however, a trio of cases in the 1980s158 indicated that the courts would be reluctant to grant relief against forfeiture. This rather more robust approach to the issue provided the oil industry with some reassurance that forfeiture clauses, whether withering or total, would be upheld. The old fears of unenforceability were re-awoken, however, at least to some extent, by an Australian case, Mosaic Oil NL v Angaari Pty Ltd,159   That is, one where if the default continued after the expiry of the due notice and the opportunity to redress the fault then the defaulting party lost their entire interest in the JOA and their share of production. 154   These fears seem to have been promoted by the opinion of Lord Wilberforce in Shiloh Spinners Ltd v Harding [1973] AC 671. The case concerned the forfeiture of a lease. Although on the facts the House of Lords was satisfied that forfeiture was appropriate, certain dicta suggested that the court reserved the right to grant relief in cases where the default had not been wilful, and where (a) the primary function of the contract was to procure a certain result; (b) that result could still be attained at the time when the matter came before the court; and (c) the forfeiture provision acted as a security against the obtaining of that result. Legal advice given in the light of that case to parties negotiating the JOA for the Thistle Field was influential in promoting the fear, and therefore the move towards withering interest clauses. See G Willoughby, “Forfeiture in Joint Operating Agreements”, 256 (1985) JENRL, at 258–259. 155   J Waite and D Dawborn, “Contractual Forfeiture of Joint Venture Interests: are such clauses enforceable?”, 11 (1990) OGLTR 389. 156   The 2009 Model JOA reinstates the defaulting party at the original share and not at a lower rate. The 2009 Model JOA cl 17.3.2 says “… the Defaulting Participant shall … have restored to it the right to take in kind and dispose of its Percentage Interest share of the Petroleum subject to any lifting procedures …”. However, UKCS JOA forfeiture clauses often contain a provision that where a defaulting party is reinstated on remedy of the default the party will be reinstated with a lower interest. This is in order to discourage opportunist withholding of funds. 157   [2015] UKSC 67; [2016] AC 1172; [2015] 3 WLR 1373. 158   Scandinavian Trading Tanker Co AB v Flota Petrolera Ecuatorina (The Scaprade) [1983] QB 529; Sport International Bussum BV v Inter-Footwear Ltd [1984] 1 WLR 776 and BICC plc v Burndy Corp [1985] Ch 232. 159   [1990] 8 ACLC 780 (New South Wales Supreme Court). But a decision regarding a mining JV that went in the opposite direction in a different Australian state the previous 153

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where the judge made some obiter remarks to the effect that such clauses might be unenforceable as being de facto penalty clauses. But, almost simultaneously, the industry in Britain was given further reassurance that JOA forfeiture clauses would be upheld at least in part by Jobson v Johnson.160 Jobson v Johnson concerned a share sale agreement for a football II-2.65 club which provided for the sale of shares to the defendant’s nominee for £40,000. By a side letter, the defendant agreed to pay additional sums for the shares by half-yearly instalments. The additional sum of just under £311,000 was to be paid by six instalments of just under £52,000 each. A paragraph in that side letter provided that if there was a default in the first instalment, the defendant would retransfer 49 per cent of the share capital of the football company. For any defaults in later instalments, there was a provision that he would transfer the shares subject to a payment to him of £40,000. There was a default and the question arose whether the obligation to transfer the shares subject to a payment of £40,000 was a penalty or forfeiture clause. The Court of Appeal held that a forfeiture clause and a penalty clause shared similar characteristics. Both were subject to equitable jurisdiction. Such clauses would not be enforced without giving a proper opportunity for relief, but they were enforceable to the extent that they provided the innocent party with compensation for his loss. On the facts of this particular case, the court ordered a sale of the shares with an obligation to pay the plaintiff the amount of the unpaid instalments. The court also confirmed that an excessive deposit in the form of a large initial instalment could be regarded as a penalty. So the court held that the buyer’s obligation to re-transfer shares at a set price which was much lower than that which the buyer had paid, was effectively a penalty clause and unenforceable to the extent that it provided for compensation for the innocent party in excess of its loss. On the other hand, the judgment suggested that a penal forfeiture clause would be enforced to the extent that it was not penal, allowing the courts to wither down a clause until it reflected the actual loss suffered by the innocent party. This aspect of Jobson led many contract drafters to use withering interest forfeiture clauses in order (it was hoped) to increase the likelihood that such a clause would be upheld. Another alternative method favoured by some, to lessen the risk of a forfeiture clause being deemed to be a penalty clause, is a “compensated sale clause upon default”, especially once a discovery has been made and the JOA has year was CRA v NZ Goldfields Investments [1989] VR 873 Supreme Court (Victoria). In CRA a clause which required a defaulting party to sell its interest to the non-defaulting party at fair market value less 5 per cent was upheld and not considered as a penalty. 160   [1989] 1 ALL ER 621 CA; [1989 1 WLR 1026 CA.

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reached development stage. This possibility is set out in the AIPN JOA in respect of default occurring “at any time under an approved Development Plan”.161 II-2.66 An illuminating case in this respect is Philips v Attorney-General of Hong Kong.162 Here, the Privy Council upheld the decision of the Hong Kong Court of Appeal that the liquidated and ascertained damages clause in a construction contract was valid and enforceable. It was held that the fact that in certain circumstances a party to a contract might derive a benefit in excess of his loss did not outweigh the very definite practical advantages of the present rule upholding a genuine estimate of probable loss, formed at the time the contract was made. II-2.67 A good general overview of the robust approach of the English courts was provided in the more recent case of Alfred Mcalpine Capital Projects Limited v Tilebox Limited.163 The background to this case was that on 27 April 2001, Tilebox and McAlpine entered into a written building contract. Clause 24 of the contract conditions provided that McAlpine should pay liquidated and ascertained damages for delay at the rate of £45,000 per week or part thereof. The contract completion date was 14 August 2002, but the building works were not completed by that date, and not expected to be complete until June 2005 (ie, some two-and-a-half years late). Against this background, McAlpine became concerned about its potential liability (of something approaching £6 million) to liquidated and ascertained damages under clause 24 of the contract conditions. McAlpine took legal advice and, having done so, formed the view that the rate of liquidated and ascertained damages specified in the building contract was excessive, and was a penalty clause and therefore invalid. Tilebox denied that clause 24.2 was a penalty clause. In his opinion the judge, Mr Justice Jackson, considered the authorities and made the following general observations: “(1) There seem to be two strands in the authorities. In some cases judges consider whether there is an unconscionable or extravagant disproportion between the damages stipulated in the contract and the true amount of damages likely to be suffered. In other cases the courts consider whether the level of damages stipulated was reasonable … I accept, that these two strands can be reconciled. In my view, a pre-estimate of damages does not have to be right in order to be reasonable. There must be a substantial discrepancy between the level of damages stipulated in the contract and the level of damages

  See AIPN 2012 cl 8.4 D.3.   [1993] 61 BLR 41. 163   [2005] EWHC 281 (TCC): 25 February 2005. 161 162

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joi nt op e r at i ng ag re e m e n t s 59 which is likely to be suffered before it can be said that the agreed pre-estimate is unreasonable. (2) Although many authorities use or echo the phrase ‘genuine pre-estimate’, the test does not turn upon the genuineness or honesty of the party or parties who made the pre-estimate. The test is primarily an objective one, even though the court has some regard to the thought processes of the parties at the time of contracting. (3) Because the rule about penalties is an anomaly within the law of contract, the courts are predisposed, where possible, to uphold contractual terms which fix the level of damages for breach. This predisposition is even stronger in the case of commercial contracts freely entered into between parties of comparable bargaining power. (4) Looking at the bundle of authorities provided in this case, I note only four cases where the relevant clause has been struck down as a penalty … In each of these four cases there was, in fact, a very wide gulf between (a), the level of damages likely to be suffered, and (b), the level of damages stipulated in the contract.”

Based upon the above, and the circumstances of this case, Mr Justice II-2.68 Jackson formed the view that the liquidated damages clause in question was not a penalty clause, and therefore would be enforced. However the Dunlop approach, which was the orthodoxy for II-2.69 100 years, was reconsidered by the Supreme Court in the 2015 case of El-Makdessi v Cavendish Square Holdings BV (hereinafter El-Makdessi).164 El-Makdessi retained the distinction between enforceable liquidated damages clauses and unenforceable penalty clauses but redrew the boundary between them. El-Makdessi only partially overrules Dunlop by adopting a new test whist retaining the Dunlop in terrorem criterion as a long stop limiting factor on deciding whether or not a term is a penalty. El-Makdessi is now considered to be the leading case on penalty II-2.70 clauses. Unfortunately, however, the reasoning of the learned justices is far from clear, especially with regard to its effect on forfeiture. As Hewitt remarks: “[i]t appears that every commentator on El-Makdessi v Cavendish draws a different conclusion from the case”.165 Hewitt thinks that the case has made little real difference as to whether a forfeiture clause is enforceable, whilst AlderseyWilliams et al. come to the rather equivocal conclusion, despite an impressively lengthy and thorough consideration of the case, that: “[t]he Supreme Court decision in El-Makdessi v Cavendish does not answer the question on whether any of the forfeiture provisions used   [2015] UKSC 67; [2015] 3 WLR 1373.   G Hewitt, “Default on the UKCS and the law on penalties – has anything changed?” (Case Comment), 1 (2016) IELR 5, at 7.

164 165

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in oil and gas industry JOAs are enforceable”.166 For the reasons enumerated below, the present author’s view is that El-Makdessi has made it more likely that forfeiture classes will be upheld, but to that extent the case merely confirms the direction of travel of the existing case law. II-2.71 In El-Makdessi, Lords Neuberger and Sumption created a new set of tests in relation to penalty clauses. They asked two questions: “In what circumstances is the penalty rule engaged?”167 and “What makes a contractual provision penal?”168 Their answers to these questions was that primary obligations can never be penal, but secondary obligations may potentially be penal under certain extreme circumstances: “The true test is whether the impugned provision is a secondary obligation which imposes a detriment on the contract-breaker out of all proportion to any legitimate interest of the innocent party in the enforcement of the primary obligation. The innocent party can have no proper interest in simply punishing the defaulter. His interest is in performance or in some appropriate alternative to performance. In the case of a straightforward damages clause, that interest will rarely extend beyond compensation for the breach, and we therefore expect that Lord Dunedin’s four tests would usually be perfectly adequate to determine its validity. But compensation is not necessarily the only legitimate interest that the innocent party may have in the performance of the defaulter’s primary obligations.”169

II-2.72 Significantly, in considering whether a secondary obligation can be penal, the Supreme Court moved away from the emphasis on “genuine pre-estimate” of a financial loss and instead emphasised the legitimate interest of the parties, holding that the test for whether a clause is penal is: “… (whether the clause) is a secondary obligation which imposes a detriment on the contract breaker which is out of all proportion to any legitimate interest of the innocent party in the enforcement of the primary obligation”.170

II-2.73 It appears to the present author that a JOA forfeiture clause is both a primary obligation and one which can never be deemed unenforceable. It is a primary obligation because it is directly connected with the only obligation shared by all the parties to a JV,

 J Aldersey-Williams et al., “Default clauses in joint operating agreements: recent guidance from the English courts”, 2 (2016) IELR 36, at 48. 167   El-Makdessi [2015] 3 WLR 1373, at 1384–1386 (see [19]–[35]). 168   Ibid, at 1386–1394. 169   Ibid, at 1392–1393. 170   Ibid, at 1392. 166

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viz. to honour cash calls. Even if, however, it was deemed to be a secondary obligation, forfeiture is enforceable in the JOA context for reasons that will be explored immediately below. Arguments for believing that JOA forfeiture clauses are enforceable Whether the detriment or loss to the contract breaker is out of all II-2.74 proportion is a question of fact and is consequently determined by the particular circumstances of the contract: its wording and its context. The importance of context was stressed in Lord Mance’s judgement: “It is clear from these three decisions [Clydebank, Comr of Public Works and Dunlop] that a concern can protect a system which it operates across its whole business by imposing an undertaking on all its counterparties to respect the system, coupled with a provision requiring payment of an agreed sum in the event of any breach of such undertaking. The impossibility of measuring loss from any particular breach is a reason for upholding, not for striking down, such a provision. The qualification and safeguard is that the agreed sum must not have been extravagant, unconscionable or incommensurate with any possible interest in the maintenance of the system, this being for the party in breach to show.”171

The foregoing passage seems an apposite description of a petroleum II-2.75 JOA: it is a “system” (contract) which operates across the whole of the business, viz. the field operated by that particular joint venture under that particular JOA. The very essence of the petroleum JOA, as discussed above, is that it is a high-risk, highly capital-intensive undertaking, which means that while the precise potential extent of loss (for forfeiture or any other reason) at the time the JOA is entered into may be unknown to parties, what is known for certain is that the risk and potential scale of any losses is very considerable. The fact that the parties have willingly entered into the high-risk, high-cost contractual nexus of a petroleum JOA suggests that the threshold of whether the detriment to the contract breaker is out of all proportion to his loss will be a difficult one to cross; indeed, arguably it is entirely inapplicable. In all JOAs, the parties run the risk of losing much or even all of their capital investment. They may drill a dry hole, a government may confiscate their assets or the value of the production will fall. In other words, in a contract where all the parties may lose all their investment, the forfeiture on default becomes simply one more risk which the parties have willingly accepted in their quests for potentially high rewards should they   Ibid, at 1432–1433.

171

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find oil in commercial quantities. Furthermore, most contractual uses of liquidated damages clauses or forfeiture clauses are one-sided because they apply to only one of the parties to the contract (the contractor, the tenant, etc), who, if he fails to perform his contractual obligation, is made subject to the contractually stipulated level of damages or forfeiture. Such asymmetrical terms always carry a risk of being abused by the more powerful contracting party and hence the rationale for the rule against penalties to afford some protection to weaker parties. By contrast, in a JOA the obligation to honour one’s cash calls is imposed equally on all the parties to the JOA; indeed, for non-operators, the duty to pay is their only obligation under the JOA. Complementing that symmetrical contractual duty to pay one’s cash call is the contractually agreed remedy of forfeiture of one’s interest in the JOA on default. This risk is applied symmetrically to all the co-venturing parties, a fact, it is submitted, which mitigates strongly against it being held to be a penalty. II-2.76 One important case on forfeiture clause, which reinforces the above analysis of the El-Makdessi principle and was very unfortunately overlooked in that case – and indeed never seems to be referred to in the many commentaries and articles on JOA forfeiture clauses – is the case of Nutting v Baldwin.172 Nutting is a case which illustrates the English courts’ robust approach, well before El-Makdessi, to the enforceability of forfeiture clauses, and one which, while having its origins in a very different context from those found in a UKCS JOA, is nevertheless a case in which the facts are strongly analogous to the economic realities and legal structure of a petroleum JOA. This case stemmed from a professional negligence litigation pursued by 986 Lloyd’s members against a managing agent of Lloyd’s. An association was formed by the members to co-ordinate and finance legal proceedings against the agent by the pooling of claims and the levying of subscriptions to cover the costs of litigation. The association was controlled by a committee elected by the members. The committee of the association was empowered to levy additional subscriptions from members, subject to the passing of a supporting resolution by two-thirds of the members present and voting at a general meeting. Such a resolution was duly passed and members were given written notice requiring them to pay an additional subscription by 1 February 1991. By 5 July 1991, despite reminders sent out in April, 19 members had failed to pay their additional subscriptions, and accordingly the committee purported to exercise its power under the rules to declare them to be defaulting members, with the result that they were no longer

  Nutting v Baldwin [1995] 1 WLR 201 (hereinafter “Nutting”).

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entitled to share in anything which the association might recover from the managing agent and the members’ agents. Two actions were brought by the association which eventually resulted in an agreement by the syndicate agent to pay £116 million to the association’s solicitors on trust for the committee to apply in paying the association’s outstanding liabilities and distributing the balance among members of the association other than defaulting members. The committee sought and obtained a court declaration that it was authorised to distribute the amount recovered on the footing that no defaulting member was entitled to a share of the award. The High Court held that the essence of the contract between the members of the association was that there should be a pooling of the members’ claims and of individual contributions required to meet the risks of the proposed litigation; that it was an essential part of that arrangement that if a member ceased to contribute to the cost of pursuing the claims he should cease to share in the pool of benefit represented by the proceeds of such claims, and accordingly the exclusion from benefit was not a penalty for breach of contract; that, while the exclusion of a defaulting member from the sharing in the proceeds was a “forfeiture” of his share, the object of the power to exclude a member was to ensure that all those who were going to share in the fruits of the litigation should also share in the risks involved and it would be wrong, whatever the individual circumstances, for the court to grant relief against forfeiture to those who had not shared in the risks involved. The court found that when payment at a given time was an II-2.77 essential part of the contract, the forfeiture of rights would not be considered a penalty: “… In my judgment the essence of the contract between the members of the association is that the burden and benefit of enforcement of the members’ claims against the agents should be shared between all the members. There is a pooling of all such claims and a pooling of contributions in the form of subscriptions for the purpose of financing the enforcement of such claims. It is an essential part of the arrangement that if a member ceases to contribute to the pool of financial contributions to the cost of pursuing the claims there should be power for the committee on behalf of all the members to determine that he shall cease to share in the pool of benefit represented by the proceeds of such claims. In other words a member who fails to shoulder his share of the burden of this essentially multilateral arrangement runs the risk of being excluded from his share of the benefit of the arrangement. This is not a penalty for breach of contract. It is an essential part of the pooling arrangement thereby effected.”173

  Nutting per Rattee J, at 208 (emphasis added).

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II-2.78 This clear statement by Rattee J is a further clear indication that the courts will be predisposed towards enforcing contractual duties and slow to find ground for relief. A further quotation from the judgment will perhaps serve to demonstrate why: “… To allow a member who has not undertaken his share of the risk by paying his subscriptions on time to come in after the litigation has been successfully concluded, so that there is no longer any risk, and still share in the fruits of the litigation on payment of his overdue subscription would, in my judgment, undermine rather than attain the object of the forfeiture provision against which relief is sought, and indeed one of the fundamental objectives of the constitution of the association. This being so, whatever the individual circumstances of the defendants, and whatever the reasons for their default, it would in principle be wrong for the court to grant relief against forfeiture. However hard the result may bear on individual defaulting members they must, in my judgment, be held to the arrangement constituted by the rules of the association to which they expressly agreed when they signed their application to join the association.”174

II-2.79 The parallels between the association in Nutting and a JOA are striking. In each case an association is formed to bear the high costs of a high risk/high reward operation: litigation and oil exploration. In each case, the finances of the group are based on contractually agreed cost sharing, and in each case failure to contribute results in the loss of any right to the proceeds of the operation: monetary award and oil respectively. It is submitted that this case gives good grounds to believe that the courts will uphold forfeiture clauses, and, indeed, following the logic of Nutting they should uphold total forfeiture clauses, not just withering interest ones. It is submitted that El-Makdessi is fully compatible with Nutting when considering the validity of forfeiture clauses in petroleum JOAs. II-2.80 Overall, it can be said that the English courts are normally strongly inclined, where possible, to uphold contractual terms that have been freely agreed between the parties.175 Furthermore, another strong argument against a forfeiture clause in a JOA being considered as a penalty clause is that it is a clause which applies equally to all the parties, whilst generally the contractual clauses which the courts have considered to be penalty clauses were those which were designed to benefit only one party to the contract.

  Nutting per Rattee J, at 210.  See El-Makdessi; see also Arnold v Britton [2015] UKSC 36; [2015] 2 WLR 1593, but cf. Rainy Sky v Kookmin Bank [2011] UKSC. The Supreme Court has now sought to reconcile the apparently contrasting approaches to contractual construction and interpretation adopted by the Supreme Court in those two cases in Wood v Capita Insurance Services Limited [2017] UKSC 24.

174 175

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Thus, taking all the above factors into consideration, it would II-2.81 seem that, other than in the most exceptional of cases, the courts are very unlikely to find a liquidated damages clause to be a penalty clause. In practice the risk of a forfeiture clause being struck down by the II-2.82 courts is small because the only relief which the courts will be likely to grant in those rare occasions when they see fit to intervene is to give the debtor time to pay his debt, and, arguably, the time periods provided by most JOAs already provide a reasonable time to make payment. So even if relief from forfeiture were to be granted by the courts, the actual effect would be minimal. Ironically, the real danger from a dispute over the validity of a forfeiture clause comes not from any remedy which might be granted by the courts but rather from the high costs and long delays associated with a court action which could well have a negative impact upon the conduct of the joint operations. Rather more problematic is the effect of English insolvency law, discussed below. Forfeiture clauses and insolvency law It is a longstanding principle176 of English law that a private contract II-2.83 cannot thwart the operation of the general law of insolvency: “there cannot be a valid contract that a man’s property shall remain his until his bankruptcy, and on the happening of that event shall go over to someone else, and be taken away from his creditors”.177 This rule is often referred to for conciseness as the “anti-deprivation principle”. In the context of the provisions of a petroleum JOA, there is thus a possibility that a forfeiture clause might be struck down as an unfair provision which is contrary to the anti-deprivation principle on the ground that it deprives the insolvent co-venturer’s non-JOA member creditors of their right to share in his assets, including his share of production under the JOA. But while the rule is clear, its application is not: “(t)he scope of this common law rule of public policy is, however, notoriously uncertain”.178 The case law is certainly not entirely easy to follow either. However, one case in this line of authority, which is striking in its similarities to the position of a JOA with a defaulting member, is the case of Whitmore v Mason.179 In Whitmore, a certain Mr Mason had been granted a mining II-2.84 lease that he held on trust for himself and four partners in shares 176  See Higinbotham v Holme (1812) 19 Ves 88 where Lord Eldon laid down the principle that no one can be allowed to derive benefit from a contract that is in fraud of the bankruptcy laws. 177   Ex p Jay; In re Harrison (1880) 14 Ch D 19, per Cotton LJ, at 26. 178   J Armour, “The Uncertain Flight of British Eagle”, (2003) CLJ 39–42, at 39. 179   Whitmore v Mason (1861) 2 J & H 204 (hereinafter “Whitmore”).

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based on the amounts they each had subscribed to the capital of the partnership. The partnership deed included a provision that in the event of the bankruptcy of any of the partners his share of the assets would be forfeited to the remaining partners. On Mason’s bankruptcy, the court deemed this provision to be void and unenforceable. II-2.85 A similar approach was taken in Ex p Jay; In re Harrison,180 where a building agreement provided that the contractor was to erect 40 houses and was to be granted leases as and when the houses were completed. The agreement provided that, in the event of the contractor’s insolvency, all the improvements on the land not demised to the builder as well as all the building materials which had been placed upon that land by the builder should become absolutely forfeited to the landlord. The Court of Appeal held that the agreement was unenforceable so far as it related to the building materials: “a simple stipulation that, upon a man’s becoming bankrupt, that which was his property up to the date of the bankruptcy should go over to someone else and be taken away from his creditors, is void as being a violation of the policy of the bankrupt law … I think we cannot escape from applying that principle to the present case.”181

II-2.86 However, a case on very similar facts the very next year, Ex p Newitt; In re Garrud182 was decided differently and a forfeiture clause upheld as valid, sowing seeds of confusion which have persisted to the present day.183 For example, clauses preventing the transfer of shares to creditors in a private company have been upheld where they are valueless or transferred for value,184 and the imposition of restrictions upon transfer of membership to creditors of an unincorporated non-profit-making association has also been upheld as valid.185 II-2.87 The leading modern case on this is the House of Lords decision in British Eagle International Airlines Ltd v Cie Nationale Air France.186 The plaintiff and defendant were members of the International Air Transport Association (IATA), which established a clearing house arrangement contractually binding on all its members, with the object of providing machinery for the settlement of debits and credits arising where members performed services for one another. Under   Ex p Jay; In re Harrison (1880) 14 Ch D 19 (hereinafter “Ex p Jay”).   Ex p Jay per James LJ, at 25. 182   (1881) 16 Ch D 522. 183   The contrast between the outcomes of Ex p Jay; In re Harrison and Ex p Newitt; In re Garrud was described as “rather surprising” by F Oditah in “Assets and the Treatment of Claims in Insolvency”, 108 (1992) LQR 459, at 476. 184  See Borland’s Trustee v Steel Bros & Co Ltd [1901] 1 Ch 279. 185   Bombay Official Assignee v Shroff (1932) 48 TLR 443 (Privy Council). 186   [1975] 1 WLR 758. 180 181

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those regulations, the members could not claim payment directly from one another but only from IATA on the basis of the balances due to them under the clearing house scheme. In IATA’s clearing house manual of procedure, it was expressly stated that it was to “be deemed to be an express term of every contract agreement or arrangement for the time being subsisting between any two members” that any “debit or credit shall be payable or receivable by and through the medium of the clearing house in accordance with the regulations and current clearing procedure and not otherwise in any manner”. The House of Lords held that such a contracting out was contrary to public policy, and the rules of the general liquidation should prevail over the clearing house arrangements. British Eagle can hardly have been said to clarify the law in II-2.88 this general area.187 In Money Markets International Stockbrokers Ltd (in liquidation) v London Stock Exchange Ltd and another,188 the High Court wrestled with the conflicting authorities, and the opinion of Neuberger J contains a magisterial review of the conflicting case law in this area. In the instant case it was concluded that a term which forfeited an insolvent party’s membership of the London Stock Exchange was valid and not in breach of insolvency law on the grounds that a membership of the LSE was personal in character, and not proprietary. So if a court were to be persuaded that membership of a JOA was essentially personal in character, there might be grounds for arguing that a forfeiture clause be upheld. However, it is clear that, as stated at the beginning of this chapter, a JOA does possess a dual function, and it has a proprietary character as well as a personal one.189 Another recent case, Fraser v Oystertec plc,190 concerned a II-2.89 company, Easyrad, which owned a patent that had been bought from its inventor, Mr Davidson. The contract granting ownership to Easyrad contained a clause which provided that if the company became insolvent then the ownership of the patent would automatically be assigned back to Mr Davidson in return for payment of any expenditure by Easyrad in securing the patent protection. The Patents Court deemed this clause to be invalid in terms which, if followed by a court considering the validity of a JOA forfeiture clause, might indicate that it would strike down a JOA forfeiture clause:   G McCormack commented, with some understatement, “The result in British Eagle v Air France has not been the subject of universal approbation”: see Proprietary Claims and Insolvency (1997), at 18. 188   [2002] 1 WLR 1150. 189   See the discussion at paras II-2.10 to II-2.22. 190   [2004] BCC 233 (hereinafter “Fraser”). 187

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“[W]here a business owns an asset of substantial independent value, whose existence lies at the heart of the venture, and that asset is held out to the outside world as the property of the business without qualification, an agreement entered into by that business according to which it may be peremptorily deprived of that asset on the grounds of its insolvency, by unilateral action to be taken pursuant to that agreement, does not constitute a relevant exception to the principle [that insolvency law prevails over private contracts]. Thus such an agreement is to that extent null and void.”191

II-2.90 Further support for the validity of forfeiture clauses can be found in the conjoined cases of Perpetual Trustee Co. Ltd v BNY Corporate Trustee Services Ltd and Lehman Brothers Special Financing Inc and Butters v BBC Worldwide Ltd.192 The Court of Appeal had to consider the effect of the anti-deprivation rule in two separate cases. The Lehman case concerned a credit-linked note issued by a Lehman Brothers’ structured issuance vehicle and the BBC case concerned a licence issued under an incorporated joint venture agreement between BBC World and the Woolworths Group. So both cases were about the effectiveness of a contractual priority or forfeiture provision in the context of the defaulter’s insolvency. In the Lehman case, the court had to consider whether a clause in a security trust deed which provided that a swap counterparty (Lehman) was to be paid in priority to noteholders, unless an event of default occurred under the swap agreement, in which case the priority “flipped” so that noteholders would be paid in priority to LBSF (the so-called “flip clause”), infringed the anti-deprivation principle. The court held it did not. In the BBC case, which is more directly analogous to default under a JOA, the court had to consider whether clauses in a licence of intellectual property rights granted to an incorporated JV company which operated to terminate the licence to certain intellectual property rights on the insolvency of a contracting party were effective. The agreement provided that in the event of the insolvency of a joint venture partner (or the parent company of a joint venture partner), the joint venture agreement and the licence would terminate and the solvent joint venturer would have a pre-emption right over the insolvent party’s share in the JV company. These clauses were not considered to be penalties and were upheld by the Court of Appeal. II-2.91 There has yet to be a UK case on the validity of a JOA forfeiture clause, but when an Australian court, in Mosaic Oil NL v Angaari Pty Ltd,193 had to consider the specific issue of the relationship between a forfeiture clause under a petroleum JOA and insolvency law, it was   Fraser per Prescott QC, at para 124.   [2009] EWCA Civ 1160; [2010] 3 WLR 87; [2010] Bus LR 632; [2010] BCC 59. 193   (1990) 8 ACLC 780 (New South Wales Supreme Court), discussed at para II-2.64. 191 192

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held that the latter would prevail and that such a forfeiture clause would not be upheld. Taken overall, then, the authorities indicate that whilst there must be a possibility that a forfeiture clause might possibly be deemed unenforceable on the grounds it gives an unfair preference to the co-venturers, the tendency in the recent case law from the English courts, not least Perpetual Trustee, seems to indicate that the courts would uphold forfeiture clause under a JOA as valid. DECOMMISSIONING In the initial years of the North Sea oil industry, neither the oil II-2.92 industry nor the British government gave much thought to the issue of the removal and disposal of redundant installations and infrastructure when the recoverable reserves of a field had been exhausted.194 Accordingly, the JOAs agreed in the 1960s and 1970s paid little attention to the issue of decommissioning and when the issue was eventually considered it was almost always dealt with in a separate decommissioning agreement. This was generally referred to as an “abandonment security agreement”, agreed by the co-venturers several years after the JOA had been agreed. However, since the 1980s, as many oil and gas fields began to approach the end of their productive lifespan, the industry began to take the issue of decommissioning increasingly seriously. At the same time, developments in international law which have been transposed into UK domestic law195 meant that the issue of potential decommissioning costs is one that has become increasingly onerous. Accordingly, the Government now requires that all fields have decommissioning plans and it is now best practice to agree a Decommissioning Security Agreement at the same time as, or shortly after, the JOA is agreed. Decommissioning Security Agreements, as the name implies, are an attempt by the co-venturers to supply some sort of financial security in the form of a guaranteed source of funds that may be accessed if the need arises in order to pay for the actual costs of decommissioning installations. Financial security becomes a paramount issue in the final stage of an oil or gas field’s productive life as, by definition, the time for making a profit out of the field’s assets has passed and the field now represents a financial liability rather than a financial asset. The industry in the early 21st century is very aware of the need to make provision for decommissioning; the 2009 Model JOA makes provision for decommissioning in Articles 13 and 26 and

  See para I-12.04.   See especially para I-12.42 onwards.

194 195

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in Schedule C where it is presumed that the provision for decommissioning will take the form of the Oil & Gas UK 2009 Model Decommissioning Security Agreement.196 However, the parties are of course free to make whatever arrangement they like provided they meet with Government approval. II-2.93 As discussed in greater detail in Chapter I-12, the nature and extent of the decommissioning obligations laid upon the co-venturers is largely determined by international law. Article 60(3) of the United Nations Convention on the Law of the Sea of 1982 (UNCLOS) provides that: “any installations or structures which are abandoned or disused shall be removed to ensure safety of navigation, taking into account any generally accepted international standards established in this regard by the competent international organisation”. The “competent international organisation” mentioned in Article 60(3) is the International Maritime Organization (IMO), which in 1989 adopted Resolution A.672(16), 19 October 1989, with an annex on Guidelines and Standards for the Removal of Offshore Installations and Structures on the Continental Shelf and in the Exclusive Economic Zone. These guidelines require the removal of: (1) all installations standing in less than 75 metres of water and weighing less than 4,000 tonnes; (2) all installations placed on the seabed after 1 January 1998, standing in less than 100 metres and weighing less than 4,000 tonnes; and (iii) installations located in primary navigational routes. However, neither UNCLOS nor the IMO guidelines give explicit direction on how to dispose of disused installations, and during the early 1990s the oil industry and the UK Government believed that, in certain circumstances, deep sea disposal of assets remained a lawful option. However, the political mood regarding the acceptability of deep sea disposal changed in the wake of the Brent Spar incident in 1995. The regional international body responsible for environmental regulation of the North Atlantic and the North Sea, the Convention on the Protection of the Marine Environment of the North East Atlantic (OSPAR) effectively banned deep sea disposal of installations by means of OSPAR Decision 98/3.197 The obligation to entirely remove almost all installations has significantly increased the costs of decommissioning.198 As a matter of international law under UNCLOS and OSPAR, II-2.94 the UK Government has the primary obligation to ensure the appropriate removal of decommissioned offshore installations. However, the UK Government, by virtue of internal domestic law, notably the  Available at www.oilandgasuk.co.uk/publications/index.cfm (accessed 5 September 2017) (hereinafter “2009 Model DSA”). See further the discussion in Chapter I-13. 197   This came into force on 25 March 1998. For further details, see para I-12.39. 198   See para I-12.03. 196

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Petroleum Act 1998, has transferred the primary liability for decommissioning from itself onto the oil companies, although obviously it remains ultimately liable for decommissioning in the event that the relevant oil company licensees should all default on their obligations. This imposition of primary liability upon the licensees may be seen as a classic example of the implementation of the “polluter pays” principle in environmental law. If international law determines the extent of the decommissioning obligations of the parties, the liability to pay those costs is determined by a mixture of contract, the terms of the JOA and the DSA, and statute, the Petroleum Act 1998. This liability for decommissioning costs may be described as contractual primary several pro rata liability, undergirded by a potential statutory secondary joint liability. The Decommissioning Security Agreement The 2009 Model JOA presumes that the 2009 Model DSA will be II-2.95 annexed to the JOA as a schedule. This can be done at the same time as the JOA is agreed or it can be agreed later and added to the JOA. For obvious reasons, it is envisaged that the DSA be agreed prior to the filing of a field development plan. In order to ensure that there will be sufficient funds available to pay for the decommissioning costs of a given field, the DSA provides that a trust fund be established to pay for the decommissioning when a time known as the “trigger date” is reached. The trigger date occurs when the net value of reserves remaining in the field is equal to or less than the estimated remaining net costs, including those associated with decommissioning, as escalated by a risk factor to be agreed between the parties. The risk factor, which is commonly 120 per cent to 150 per cent, is an attempt to cope with the double financial risk that decommissioning works entails. Firstly, the costs of decommissioning may well fluctuate, generally in an upwards direction. Secondly, given the high volatility of oil and gas prices it is always difficult to actually estimate how much in situ reserves will be required to pay for the decommissioning of a given field. The decommissioning trust will be constituted with a third party as trustee and each party will be required to contribute a sum (the “provision amount”) to the trust on an annual basis from the “trigger date” until the “end date”. The end date is defined as occurring after decommissioning is completed, and when 12 months after the submission to the Secretary of a “close-out report” have elapsed. The period between the trigger date and the end date is known as the “run-down period”. The calculations for net cost and net value are made by the operator in accordance with the decommissioning plan, which the operator is obliged to provide annually beginning the year before the run-down period commences.

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the decommissioning plan will include the calculations for net cost and net revenue and must be approved unanimously by the parties or be referred to an expert. The purpose of the trust is that any funds residing in it can act as security for payment of the costs of decommissioning the field, but the primary method of collecting funds to pay for the decommissioning plan remains AFEs issued in the usual way under the JOA and the intention is that the funds in the decommissioning trust are security for payment. The strength of financial protection provided to the co-venturers and the Government by the DSA has been greatly enhanced by the insertion of Section 38A in the Petroleum Act 1998 by the Energy Act 2008, which provides that all sums set aside as security for decommissioning under a DSA will be protected from any creditors of any of the co-venturers in insolvency and will thus remain available for the purposes of paying decommissioning costs.199 Alternative security and default II-2.96 Whilst the 2009 Model DSA envisages cash for security purposes being held by a decommissioning trust, it also allows that the parties may provide alternative security. The Model DSA “alternative provision” for security allows for several different forms of security, which include the provision of a letter of credit, corporate bond or a parent company guarantee (PCG) in the forms annexed to the DSA. The UK Government requirements for letters of credit are for a credit rating equivalent to AA (Standard and Poors) or Aa2 (Moodys). It should be noted that the Government does not accept PCGs or parent bonds due to issues of enforceability against foreign companies and EU state aid rules for UK domestic companies. Default on a DSA is triggered by the failure to provide or maintain the security to the requisite amount or credit rating. However, a default under the parent JOA itself will also trigger default under the DSA. The usual remedy of forfeiture of participating interest in the JOA and licence applies, subject to rights to remedy a default. This will entail the defaulting party’s interest being transferred to the non-defaulting parties in addition to any sum held by the trustee as security. But obviously, as mentioned earlier,200 forfeiture is not much of a penalty at a stage when a field represents liabilities rather than potential profits.

  See para I-12.55.   See discussion on default and forfeiture, from para II-2.54 onwards.

199 200

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CONCLUSION The unincorporated JOA has proved to be a flexible and cost- II-2.97 effective means by which parties who wish to share the risks and rewards of oil and gas exploration may come together and it is likely to remain the dominant form of alliancing in the oil and gas industry both within and outwith the UKCS for the foreseeable future.

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CHAPTER II-3 UNITISATION Nicola MacLeod

II-3.01 Conventional oil and gas deposits are typically composed of porous rock bounded by impermeable strata which serve to trap the oil and gas under conditions of high pressure.1 Drilling through the impermeable cap decreases the pressure of the reservoir and allows the oil and gas to migrate through the porous rock to the source of lower pressure (in most cases the drilled well) in order to be extracted.2 Thus, oil and gas behave quite differently to other minerals such as coal, stone and metal ores, which exist in strata in solid state and in a fixed position. As we will see, petroleum’s migratory (sometimes described as “fugacious”) characteristics pose some particular challenges for the law. II-3.02 As we have already seen in Chapter I-4, in the UK, oil and gas production is generally permitted and governed primarily by (in seaward areas) Production Licences and (in landward areas) Petroleum Exploration and Development Licences (PEDLs). Such licences are granted in respect of areas known as blocks.3 In many cases the boundaries of an oil or gas field will be contained wholly within the area of one block. In such a case, the field can be developed by the parties who are entitled to produce oil from that block by virtue of a licence from the state and the terms of the contractual arrangements they have entered into with their co-venturers.4  The geological characteristics of unconventional deposits are different: see further the discussion in Chapter I-9. 2   T Reynolds, “Delimitation, Exploitation, and Allocation of Transboundary Oil and Gas Deposits Between Nation-States” (1995) ILSA Journal of International and Comparative Law, Spring (hereinafter “Reynolds, ‘Delimitation’”), at 136. 3   See para I-4.18. 4   Joint operating agreements (JOAs) are discussed in Chapter II-2. 1

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However, there are many examples of fields which do not lie wholly within one block but instead extend either into vacant territory, into blocks where licences have already been granted to different parties, or across a line of international maritime delimitation into parts of the Continental Shelf controlled by another state. In all such situations, careful thought must be given as to how the reserves are to be extracted.5 This is chiefly because petroleum deposits “are characterised by a complicated ‘equilibrium of rock pressure, gas pressure and underlying water pressure,’ so that extracting natural gas or petroleum at one point unavoidably changes conditions in the whole deposit”.6 The fugacious character of oil and gas raises a host of legal II-3.03 questions. For instance: who can be said to own or otherwise control a mineral that migrates? Can the person who owns or otherwise holds exclusive rights appertaining to one particular area of the subsoil legitimately complain if drilling activities carried out at a remote location reduce the amount of oil and gas within that person’s area of entitlement? Is ownership of oil and gas in situ even an appropriate legal concept? These questions will be considered throughout this chapter. PREVENTING WASTE AND MAXIMISING RECOVERY: THE CASE FOR UNITISATION AND RELATED CROSSBOUNDARY CONTROLS On first discovering that a field within one’s own licensed area II-3.04 continues into another licensee’s block, assuming that there is an absence of any legal controls prescribing what kind of development is and is not legitimate, at first sight the most economically beneficial strategy seems clear: to develop the field aggressively in order to cause as much oil and gas as possible to migrate from neighbouring areas into one’s wells, thereby maximising one’s own take from the common field. This approach was taken in the USA in the early days of oil and gas production.7 At this point there was no systematic control over the exploitation of common fields, and property in oil 5  B Taverne, Co-operative Agreements in the Extractive Petroleum Industry (1996) (hereinafter “Taverne, Co-operative Agreements”), at p 70; see also B Taverne, Petroleum, Industry and Government: An introduction to petroleum regulation, economics and government policies (2000) (hereinafter “Taverne, Petroleum, Industry and Government”), at paras 11.3.1 to 11.3.2. 6   D Ong, “Joint Development of Common Offshore Oil and Gas Deposits: ‘mere’ state practice or customary international law?”, 93 (1999) Am J Intl L 771 (hereinafter “Ong, ‘Joint Development’”), at 778. The internal quotation is from N Ely, “The Conservation of Oil”, 51 (1937–38) Harv L Rev, at 1209. 7   See eg Kelly v Ohio Oil Co, 49 NE 399 (Ohio, 1897) (hereinafter “Kelly”).

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and gas was governed by the rule of capture, which is the “legal rule of non-liability for (a) causing oil or gas to migrate across property lines and (b) producing oil or gas which was originally in place under the land of another, so long as the producing well does not trespass”.8 Wells were commonly drilled at, or close to, the boundary of a property in order to draw in as much oil and gas from deposits underlying neighbouring areas. However, this in turn tended to encourage the proprietors of neighbouring areas to engage in similar behaviour in order to seek to maximise their own recovery.9 This practice was known as competitive drilling and, due to the rule of capture, was legal.10 However, studies in the United States11 have shown that such competitive production leads to a proliferation of wells and associated infrastructure and higher subsurface costs. Subsurface pressures are prematurely and unnecessarily depleted, oil recovery is reduced12 and, ultimately, the field will be abandoned sooner as it is not commercially profitable in its later stages.13 This form of drilling can also result in unnecessary duplication of expenditure14 and protracted court proceedings.15  T Daintith, G Willoughby and A Hill, United Kingdom Oil and Gas Law (3rd edn, looseleaf, 2000–date) (hereinafter “Daintith, Willoughby and Hill”), at para 1-724. See also Kelly v Ohio Oil Co, 49 NE 399 (Ohio, 1897). As we shall see at para II-3.10, the rule of capture also has a role to play in UK oil and gas law. 9   See eg J Lowe, O Anderson, E Smith and D Pierce, Cases and Materials on Oil and Gas Law (4th edn, 2002) (hereinafter “Lowe et al., Cases and Materials”), p 786. 10   It should be noted here that the rule of capture has not been confined to the past. As a principle of property law, it is still extant. However, property law is no longer the only source of regulation of these matters. On the grounds of conservation and enhanced recovery, most states in the USA now impose significant controls on cross-boundary developments, including well spacing, pooling and compulsory unitisation provisions. For a detailed review, see Lowe et al., Cases and Materials, Chapter 6. For an overview, see Reynolds, “Delimitation”, at 138 and/or J Weaver, D Asmus et al., “International Unitization of Oil and Gas Fields: The Legal Framework of International Law National Laws and Private Contracts”, Association of International Petroleum Negotiators Research Paper, 2005 (hereinafter “Weaver et al., ‘International Unitization’”), at 12. Texas does not have a compulsory unitisation statute: see P Murray and F Cross, “The Case for a Texas Compulsory Unitization Statute”, 23 (1992) St Mary’s LJ 1099. 11  See eg G Libecap and D Wiggins, “Oil Field Unitization: Contractual failure in the presence of Imperfect Information”, 75 (1985) American Economic Review 368; “The Influence of Private Contractual Failure on Regulation: The Case of Oil Field Unitization” (1985) Journal of Political Economy 670; “Contractual Responses to the Common Pool: Prorationing of Crude Oil Production”, 74 (1984) American Economic Review 87. 12  Reynolds, “Delimitation”, at 139. The promotion of recovery and the reduction of waste is a matter of concern not just to licensees but also to the state: see the discussion at para I-4.1 and throughout Chapter I-5. 13   Weaver et al., “International Unitization”, at 7. 14  P Deemer, “Unitisation Agreements”, Conference Paper, University of Dundee, September 2004 (hereinafter “Deemer, ‘Unitisation Agreements’”), at 2. 15   E Poitevent, “Oil – proceeds from unitised field” (2000) IELTR N10. See also R Pound, 8

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Unitisation is one of a number of legal devices16 which seek to II-3.05 remove the destructive competitive element stimulated by the rule of capture. The field is developed as a whole, expenditure is reduced and recovery is maximised. Libecap and Wiggins summarise the position thus:

“The potential aggregate gains from unitized, single firm production are large: extraction rates can more fully consider user costs and follow rent-maximizing patterns; capital costs can be reduced through elimination of excessive wells and subsurface storage; and total oil recovery can be increased since subsurface pressures can be better maintained through controlled oil withdrawal.”17

INTRODUCTION TO THE CONCEPT OF UNITISATION Unitisation is the process whereby the oil and gas reserves of II-3.06 a reservoir that does not sit within an area covered by a single licence are treated as a single unit (hence the term “unitisation”) for the purposes of development and operation, with the resulting production from the field divided between the licensees in agreed proportions irrespective of where within the unitised area the oil and gas has been produced.18 The licensees of the areas containing the reservoir enter into a unitisation and unit operating agreement (UUOA) to regulate how the reservoir will be developed. Alternatives to full unitisation As we have already seen, one alternative to regulating by way of II-3.07

Law Finding Through Experience and Reason (1960), at pp 63–64. 16   See also the alternatives to unitisation discussed at paras II-3.7 to II-3.10. 17   G Libecap and D Wiggins, “The Influence of Private Contractual Failure on Regulation: The Case of Oil Field Unitization” (1985) Journal of Political Economy 670, at 712. See also Taverne, Co-operative Agreements, at p 82: “Co-operation in the exploitation of a straddling (single, continuous) petroleum reservoir is not only a legal necessity when so instructed by the competent authority but also, generally speaking, a technical necessity, assuming the respective (adjacent) rightholders aim or are obliged in the context of good oilfield practice to aim at a maximum efficient recovery of petroleum. The alternative, ie independent, non-co-operative exploitation of the separate parts of a straddling reservoir, will lead to costly defensive or competitive drilling.” The principle of joint development has also received support at the highest international level from the International Court of Justice, which has held that joint development is particularly appropriate to preserve the unity of a deposit: see The Continental Shelf Cases (1969) ICJ Reports, at 52, paras 97–99. 18  T Winsor and S Tyne, Taylor and Winsor on Joint Operating Agreements (2nd edn, 1992) (hereinafter “Taylor and Winsor”), p 110. See also Weaver et al., “International Unitization”, at 1, where the process is described as the joint, co-ordinated operation of a petroleum reservoir by all the owners of rights in the reservoir, a process of combining the separately held portions of the reservoir or field into a large unit.

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unitisation is quite simply not to regulate, and to leave matters to be governed by property law concepts, most notably the rule of capture.19 As discussed above, there are good reasons to reject such an approach, and as such, it will not be further considered here. However, depending on the factual circumstances, there may very well be occasions when approaches other than full unitisation are merited. For instance, where the field is found to extend beyond the boundary of the licence holders’ block into unlicensed territory, it may, in some jurisdictions, be possible for the licence group to make an out-of-rounds application.20 If such an application is granted, then both parts of the field will be licensed to the same group of licensees and the need for unitisation will therefore have been obviated. II-3.08 Even where a field extends into territory which has already been let to another licensee or, more likely, a group of licensees,21 unitisation is not inevitable. Another alternative is for one licence group to purchase the adjoining acreage from the other, and then develop the field under their existing joint venture agreement. Such an arrangement has the benefit of simplicity. It is, however, likely to be attractive to either group only if the extension into the adjoining area is very clearly a small one. If it is sizeable, then commercial factors22 are likely to push the parties towards unitisation,23 or at least one of the cognate agreements discussed below. II-3.09 There are also some variations on full unitisation, such as fixedinterest agreements and cross-licence agreements. “Fixed interest” is where the percentage interests of the parties are agreed at the outset of development to avoid the requirement for complicated and costly redeterminations.24 In this situation the parties need to agree the technical parameters without having drilled any development wells. This requires a leap of faith by the parties, one, moreover, which may   See para II-3.04.  This is possible in the UK: see T Daintith, Discretion in the Administration of Offshore Oil and Gas (2006) (hereinafter “Daintith, Discretion”), para 5406; see also the discussion, at paras I-4.22 and II-3.10. Canadian petroleum law also provides for this type of situation, although not in an identical manner to that of the UK: see Daintith, Discretion, para 5412. Neither Australia nor the United States has equivalent provisions: see Daintith, Discretion, paras 5401 and 5415 respectively. 21   See Chapter II-2 for a discussion of why oil and gas companies generally explore for and develop assets jointly. 22   For instance, the purchasers may not be able to afford the purchase price, or may at least be unwilling to run the commercial risks associated with paying a capitalised sum for an asset of uncertain size and volatile value. Similarly, the selling licence group will be unlikely to wish to run the risk of selling out at too low a price, or of discovering that the asset sold was significantly larger than they initially believed it to be. 23   W English, “Unitisation Agreements”, in M David, Upstream Oil and Gas Agreements (1997) (hereinafter “English, ‘Unitisation Agreements’”), at 115. 24   Ibid, at 115. Redetermination is discussed at paras II-3.28 to II.3.40. 19 20

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have significant financial implications, which is why this alternative is generally agreed only in the case of small developments.25 “Crosslicensing” involves the licensees taking an assignment of each other’s licences and becoming parties to the entire unitised area.26 This also has the requirement that the parties reach agreement on the split of reserves and is, in practice, uncommon for much the same reasons as have already been discussed. UNITISATION AND RELATED PRACTICES WITHIN THE UNITED KINGDOM The legal regime in the UK As has already been noted, Section 1(1) of the Petroleum (Production) II-3.10 Act 1934 expressly vested “property in petroleum, existing in its natural condition in strata in Great Britain” in the Crown.27 Thus, oil and gas reserves under the landmass of Scotland, England and Wales, and their associated territorial seas, are owned by the Crown. One might therefore think that, because licensees do not take original ownership, but instead derive ownership from the state, there is no scope for the operation of the rule of capture here. That, however, would be an over-simplification. Model Clause28 2 of both a Seaward Production Licence and a Landward PEDL29 provides the licensee with “exclusive licence and liberty during the continuance of this licence and subject to the provisions hereof to search and bore for, and get, Petroleum under [the licensed area]”. The responsible government department30 formerly interpreted this to mean that licensees had a vested right to such petroleum as underlay their licensed area.31 However, that interpretation was disagreed with by

  However, English does refer to “at least two major fields” in the UKCS which proceeded on this basis: English, “Unitisation Agreements”, at 115. 26   Ibid, at 115. 27   See para I-4.08. 28   Sets of model clauses which are incorporated into new seaward licence grants can be found in the Petroleum Licensing (Production) (Seaward Areas) Regulations 2008 (SI 2008/225). Unless the context requires otherwise, references throughout this chapter to a “model clause” will be to the standard seaward Production Licence Model Clauses. See, however, the discussion at para I-4.17. 29  The model clauses for new PEDLs are to be found in the Petroleum Licensing (Exploration and Production) (Landward Areas) Regulations 2014 (SI 2014/1686). 30  Previously the Department of Energy and Climate Change, the Department for Business, Enterprise and Regulatory Reform and the Department of Trade and Industry. Today, licensing is regulated by the Oil and Gas Authority (OGA), a Government company established by the Energy Act 2016 with the Secretary of State for the Department of Business, Energy and Industrial Strategy as the sole shareholder. 31   See Daintith, Willoughby and Hill, para 5-2732. 25

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a number of commentators32 and has subsequently been departed from, at least in relation to the UKCS.33 Moreover, as we have already seen, in the UKCS outside the territorial sea the Crown has only a sovereign right to exploit resources, not a full right of ownership.34 If the state does not own oil and gas in situ, it cannot pass title on to its licensees. Instead, its licensees obtain original title upon extraction.35 This is the rule of capture in its purest form. However, competitive drilling is inherently unlikely to occur in the UKCS. The dangers of competitive drilling have been identified and legislated for from the earliest days of the UK’s development of its petroleum law.36 II-3.11 The Infrastructure Act 2015 put into statute the principle of maximising the economic recovery of the UK’s oil and gas resources (MER) by amending the Petroleum Act 1998. Under Section 9C of the Petroleum Act 1998, licence holders are required to act in accordance with the current MER Strategy for the UK.37 The Strategy’s central obligation states that “relevant persons must take the steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath UK waters”. In complying with the central obligation, relevant persons should consider whether collaboration could improve recovery of economically recoverable petroleum. While MER, and the UK’s associated Strategy, is still in its infancy, the use of unitisation agreements is likely to be compliant with the MER obligation, although in certain circumstances the Oil and Gas Authority (OGA) may press for additional measures, such as hub development.38 The Energy Act  See eg Daintith, Willoughby and Hill, para 1-347; Daintith, Discretion, para 5408; English, “Unitisation Agreements”, 98. 33  Daintith, Discretion, paras 5408 and 5421. No similar declaration appears to have been made in relation to landward licences or those within the territorial sea, although, as has been noted above, the clause granting the licence in these cases is identical in all material respects. 34   See para I-4.09. 35  In Scotland, this is as a result of the principle of occupatio; in England and Wales, of ownership by occupancy. See (for the position in Scotland) W Gordon, “Corporeal Moveable Property”, in K Reid (ed.), The Law of Property in Scotland (1996), para 539; for the position in England and Wales see Lord Mackay of Clashfern (General Editor), Halsbury’s Laws of England (4th edn, 2003 reissue), vol 35, para 1236. 36   See Daintith, Willoughby and Hill, at para 1-103. 37  The MER Strategy is available for download from www.ogauthority.co.uk/ news-publications/publications/2016/maximising-economic-recovery-of-uk-petroleumthe-mer-uk-strategy (accessed 5 August 2017). 38  In the Government’s Response to the Wood Review, the possibility of vesting new powers in the regulator regarding unitisation was discussed, but these have yet to be introduced. The Government’s Response is available for download from www.gov.uk/ government/publications/government-response-to-sir-ian-woods-review-of-the-uk-continental-shelf-ukcs (accessed 5 August 2017). For a further discussion of MER, see Chapter I-5. 32

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2016 created the legislative framework in establishing the OGA and its powers, which is the new regulator overseeing compliance with MER. In addition to the MER obligation, the Secretary of State enjoys a II-3.12 number of licence powers designed to prevent competitive drilling, as implemented by the OGA. The provisions most specifically directed towards this purpose39 are the general prohibition upon the drilling of wells less than 125 metres from any of the boundaries of the block,40 provisions relative to the development of fields which cross international lines of maritime demarcation41 and the OGA’s power, in certain circumstances, to compel unitisation.42 In addition to the OGA’s powers under the licence, it should also be recalled43 that where the field is found to extend beyond the boundary of the licence holders’ block into unlicensed territory the licensees may make an out-of-round application44 for a licence to the adjacent block. If such an application is approved,45 the need for unitisation will be eliminated. However, even if the application is not approved, given what has been said in this paragraph about the OGA’s present views on the stage at which property rights to petroleum vest, there would seem to be no reason in principle why the OGA should not approve a production and development programme the effect of which would be to drain hydrocarbons from an area outside the licensed area, as long as it was satisfied that the operations carried out under the programme would not damage the underlying reservoirs, reduce overall recovery or otherwise be contrary to good oilfield practice. Unitisation in practice Where satisfied that a petroleum field in one block extends into II-3.13 another block in respect of which a UK Production Licence is extant, and if “it is in the national interest in order to secure the maximum ultimate recovery of Petroleum and in order to avoid unnecessary competitive drilling that the Oil Field should be worked and  Other Model Clauses, including the Model Cll 17 and 18 powers of the Secretary of State to exercise control over production discussed in the Appendix to this volume, although not so specifically directed towards the issue, are also relevant. See eg Daintith, Discretion, at para 5408. 40   Model Cl 20. The OGA does, however, reserve an unfettered discretion to consent to such drilling. 41   Model Cl 28, discussed further at para II-3.50. 42   Model Cl 27. This power will be discussed further at para II-3.13. 43   See para II-3.07. 44   Out-of-rounds applications are discussed above at paras I-4.22 and II-3.07. 45  And if the OGA is satisfied that “geological or production considerations” (see para II-3.50) justify it, this is the likely outcome. 39

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developed as a unit”,46 then the OGA is entitled to serve a notice in writing compelling the preparation by all the relevant licensees of a unitised development scheme.47 The OGA is entitled to design and impose a “fair and equitable” unitised development programme upon the licensees if they cannot agree on one within the timescale set out, or if the OGA does not approve the scheme submitted,48 however this is made subject to the licensees’ right to arbitrate.49 Although the UK Government has never served a notice to unitise under these powers, the mere existence of the ability to do so, along with some encouragement from the OGA, is thought enough to ensure that licensees take the appropriate measures to gain approval.50 If a field extends into a neighbouring licensee’s area the OGA will II-3.14 need to be satisfied that the development plan for that area is the one most likely fully to exploit the recovery of economic reserves before any approval will be given. The OGA states that: “Where a determination extends across more than one licence, the OGA may require licensees to enter into a Unitisation and Unit Operating Agreement (UUOA)  prior to submitting a field development plan. This UUOA needs to be approved by the OGA prior to field development plan approval.”51

II-3.15 Unitisation is becoming increasingly prevalent within the UKCS. The Clair Field, operated by BP, is one of the most significant finds of recent years, with an estimated 7–8 billion barrels of oil equivalent (boe) in place. Clair is managed under a unitisation agreement comprising four licences and six blocks, owned by four co-venturers: BP, Shell, Conocophillips and Chevron. While the use of unitisation in one of the few remaining jewels of the UKCS highlights the importance of the agreements it is important to remember that it may not be the only solution if not all parties agree to proceed with the development. For instance, the recent sale of equity in a block containing an extension to the Columbus field in 2015 was deemed necessary to proceed with the development.52 Unitisation may not always be the best commercial option; nevertheless, it will continue to be a feature of industry practice on the UKCS as it enters its twilight phase. One of the reasons for this is the decreasing size of the acreage available   Model Cl 27(1).   Model Cl 27(2). 48   Model Cl 27(4). 49   Model Cl 27(5); read with Model Cl 43. 50   English, “Unitisation Agreements”, 100; Deemer, “Unitisation Agreements”, at 3. 51  www.ogauthority.co.uk/exploration-production/development/field-determinations 52   Serica Energy plc, Acquisition of interest in Columbus field extension, notice available at www.serica-energy.com/downloads/releases/Columbus%20Equity%20transfer%20 press%20release%2027%20Oct%202015.pdf (accessed 5 September 2017). 46 47

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for lease. States who license on the basis of a grid pattern determined before specific discoveries have been made are always likely to encounter situations where fields extend outside the discovery block.53 The frequency with which that situation is encountered will only increase as the average size of block falls. When licensing first began in the UKCS the average size of licence blocks was 250 square km. This figure has been gradually reduced over time, principally as a result of the sub-division of blocks, relinquishment of acreage and the drawing of the median lines “carving up” the Continental Shelf into exclusive economic areas associated with individual states.54 As a result of these developments, oil and gas reservoirs are increasingly found to underlie more than one block. The unitisation and unit operating agreement (UUOA) The unitised area is treated as a single unit for development purposes II-3.16 as if merged into one single licence. The practical effect of unitisation is that the licensees will have to negotiate a new type of operating agreement – a unitisation and unit operating agreement (UUOA) – to govern the conduct of operations in the unitised area. UKCS fields will generally be unitised prior to development because of the necessity of OGA approval. The OGA will want to be satisfied that the agreement provides for the maximum recovery of petroleum, that no company has an unfair advantage and that there are appropriate arrangements in place to deal with abandonment (including the financial or security provisions between the parties).55 While, at least in the context of an intra-national unitisation, the OGA is not directly concerned as to how the reserves are shared out among the licensees,56 as we have already seen, Model Clause 27(4) allows the OGA to prepare a development scheme which is “fair and equitable to the licensee and all other licensees” if the scheme originally submitted is unacceptable. The scheme submitted must therefore be reasonable and, as long as the OGA’s main concern of maximum recovery of reserves is satisfied, the plan should be approved. Due to the time it takes to negotiate the full UUOA and gain OGA II-3.17 approval, the UUOA will often be preceded by a pre-unitisation agreement between the members of the licence groups in order to allow preliminary work to be carried out in the area.57 The size and

 Daintith, Discretion, para 5400.   Daintith, Willoughby and Hill, at para 1–723. See also UN Convention on the Law of the Sea 1982, Part V. 55   See Chapter I-13. 56  The OGA will take a different view of these matters in the international context: see para II-3.48. 57   Entry into such an agreement has been endorsed as a best practice which helps to avoid 53 54

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scope of pre-unitisation agreements vary enormously;58 however, they will often provide for the conducting of seismic surveys, the establishment of a common database of results pertaining to the reservoir, and a joint programme to appraise and evaluate any drilling. The results of these preliminary studies will determine whether there is a case for developing the field on a unitised basis. The pre-unitisation agreement is viewed as beneficial even if it is ultimately found that there is no case for unitisation, as the parties will have made financial savings by jointly conducting these studies. If a case for unitisation is established, the OGA will usually require that the UUOA is signed prior to or at the time of field development consent. The UUOA will essentially include all the main features of a joint venture or joint operating agreement (JOA)59 (and may be based on one of the licence groups’ current agreements) including: the appointment of an operator; the establishment of a unit operating committee; voting provisions; sole risk provisions; work programmes and budgets; default clauses; procedures for the disposal of petroleum; and accounting mechanisms. Many of the clauses and issues of contention discussed in Chapter II-2 are therefore equally relevant here. In addition, however, a UUOA will also contain some special provisions applicable to a unitised field. These provisions are discussed more fully later in this chapter, the most important ones being the declaration that the field will be operated as a single unit, the tract participations (these are the percentage interests held by each of the licence groups in the unit) and detailed redetermination provisions.60 It is possible to have separate agreements for the unitisation and operation of the unit area, as is often the case in the United States; however, in the United Kingdom the two are almost always combined.61 This does not mean that the UUOA will effect a termination of the JOAs between each of the licence groups. These agreements will continue to be fully operative in the parts of the relevant licence areas that lie outside the unitised area, with the UUOA governing the unit area only.62 It is also possible for the UUOA to cover only certain substances or certain depths and in these cases the JOAs will continue to govern with respect to those substances and/or depths that are not unitised. The existing JOAs

delay at full unitisation stage by senior officials within the OGA: see Taylor and Winsor, p 113. 58   Weaver et al., “International Unitization”, at 49; Taylor and Winsor, p 113. 59   English, “Unitisation Agreements”, 97. 60   Deemer, “Unitisation Agreements”, at 1. 61  See Taylor and Winsor, pp 113–114; also English, “Unitisation Agreements”, 97. 62   Daintith, Willoughby and Hill, para 1-741.

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will require to be amended either directly or through the UUOA to exclude the area, substances or depths subject to the unitisation. The JOAs may also continue to govern the relationships between II-3.18 the licensees within each licence group with regard to such areas as withdrawal, assignment and default. For example, if a party wishes to assign its unit share, that party will usually have to follow the assignment provisions in both the UUOA and its own licence group’s JOA.63 It is therefore important when drafting the UUOA to consider how the provisions relate to the underlying JOAs. In order to resolve any potential conflict between the UUOA and the JOAs, the UUOA will commonly contain a clause stating that in the event of conflict between the two the UUOA shall prevail. COMMON ISSUES IN UNITISATION Tract participations; determination; re-determination; and dispute resolution Tract participation Typically, a UUOA will contain a clause to the effect that:

II-3.19

“all rights and interests of the Parties under the Licences are hereby unitised in accordance with the provisions of this Agreement insofar as such rights and interests pertain to the Unitised Zone and each of the Parties shall own all Unit Property and Unitised Petroleum in undivided shares in proportion to its Unit Equity”.64

It follows that wherever in the field the unitised oil and gas comes II-3.20 from, the owners will have a claim to such production in their unitised shares. Each individual licensee’s unitised share will be a function of their equity holding in their own licence group JOA, and the percentage interest in the unit held by each of the separate licence groups, or, as it is known, each licence group’s “tract participation”.65 Determination The characteristic provisions of a unitisation agreement, and those II-3.21 that distinguish it from an ordinary JOA, are the determination of the tract participations and the subsequent re-determination provisions.66 The tract participation provisions determine the percentage interests held by each of the separate licence groups in the unit. Once determined, each of the parties will be entitled to its tract participation percentage of unitised production, regardless of from where   Ibid, para 1-741.   English, “Unitisation Agreements”, 97. 65   See Daintith, Willoughby and Hill, at para 1-742. 66   Ibid, at para 1-742. 63 64

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within the unit it is produced, and will also be liable for that same undivided percentage of costs and liabilities.67 Due to the significant sums involved, each of the licensees has an interest in maximising its share of the reserves and therefore its licence group tract. At the same time, parties do not wish to be responsible for upfront costs for a greater area than estimated, especially as they will have no revenue stream from the field at this point.68 It is not surprising, therefore, that these provisions are often the subject of lengthy negotiations. II-3.22 In the early stages of development, there will be insufficient technical data to calculate precisely each party’s share of reserves. The tract participations will therefore be determined on a provisional basis. The two or more licence groups will agree the participations based on a best estimate of the percentage of the hydrocarbons underlying each of the separate licence areas. As the parties will at this point have at least a somewhat imperfect knowledge of the physical characteristics and extent of the reserves,69 this will be a negotiated figure rather than a technical one and may well have been concluded in a pre-unitisation agreement. This allocation will then be maintained until the first re-determination.70 II-3.23 As mentioned earlier, the determination of the tract participations is one of the most lengthy and difficult areas to bargain, particularly where the formula for the original calculations is also to be used for the re-determinations.71 There are several methods used for determining tract participation and re-determinations, the three most common being “stock tank oil originally in place” (STOOIP), “recoverable reserves” and “moveable oil originally in place” (MOOIP).72 II-3.24 STOOIP relates to the total volume of oil originally in the reservoir. This is generally considered to be the easiest method to determine, and one which can be determined with finality as soon as development drilling has been completed.73 However, this method may not be completely equitable, as some of the oil will never actually be

  Weaver et al., “International Unitization”, at 58.   English notes that in a development costing £1 billion, each 1 per cent share is worth £10 million and as such can have a significant impact on a company’s finances: English, “Unitisation Agreements”, 105. 69   Although with modern improved seismic and other surveying and modelling techniques the parties are nowadays likely to have much better information on which to base their “best guess” than was formerly the case. 70   English, “Unitisation Agreements”, 105. 71   Taylor and Winsor, p 114. 72  These are by no means the only methods currently available, nor is the terminology used to describe any given basis uniform. See also the list of potential bases offered by English: English, “Unitisation Agreements”, 105. 73   Daintith, Willoughby and Hill, para 1-742; see also Taylor and Winsor, p 115. 67 68

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produced. In addition, it makes no distinction between the reserves that are produced and those which are left in the reservoir.74 Recoverable reserves are simply those reserves which are recovered. II-3.25 In theory this method is arguably the most equitable, however in practical terms it cannot be finally determined until the reservoir has been completely depleted and at this point there are no reserves left for making final equitable adjustment of quantities.75 MOOIP relates to the oil originally in place minus the theoretical II-3.26 oil left in the reservoir once depleted. This is no more equitable than STOOIP and has more uncertainties.76 Therefore, the majority of unitisations in the UKCS have been based on the STOOIP method.77 English states that: “As the methods become progressively more complicated they will in theory become more equitable, but there will also be greater scope for disagreement. There tends therefore to be a preference within the industry for opting for one of the more straightforward methods, providing that it will give an equitable result.”78

In contrast, unitisations in the United States commonly use complex II-3.27 formulae taking into account factors such as well productivity, well density, reservoir penetration and acre-feet of reservoir rock.79 Derman and Derman state that more sophisticated geophysics has allowed the industry to understand better the subsurface of the reservoir. As a result of these improvements they argue that re-determination methods should advance accordingly. They assert that the typical re-determination process is both ambiguous and contentious, and advocate a new mathematical formula based on the Nigerian offshore model.80 With a marked increase in the incidence of unitisa  Daintith, Willoughby and Hill, para 1-742.  This point is developed in the discussion on re-determination below at paras II-3.28 to II.3.34. 76  P Worthington, “Provision for expert determination in the unitization of straddling petroleum accumulations”, 9 (2016) JWEL&B 254 (hereinafter “Worthington, ‘Expert determination’”), at 259 highlights that “static” methods of determining tract participation have been, globally, the industry’s preference. He notes, however, the possibility of hybrid methods, whereby “static” reference conditions (such as STOOIP) are used for tract participation in the early life of a field, followed by “dynamic” methods of determination in the mid-life cycle of a field. “Dynamic” reference conditions can potentially ascertain licensee entitlements more accurately than “static” methods using reservoir simulators, calibrated through history-matching. They do, however, carry associated increases to uncertainty and costs. 77   Daintith, Willoughby and Hill, para 1-742. The equivalent method to STOOIP for a gas field is called “initial gas in place”, or IGIP. 78   English, “Unitisation Agreements”, 106. 79   Weaver et al., “International Unitization”, at 60. 80   P Derman and A Derman, “Unitization? A mathematical formula to calculate redeterminations”, 1 (2003) OGEL (hereinafter “Derman and Derman, ‘Unitization’”). 74 75

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tions in the UKCS and elsewhere, and the problems associated with the re-determination process (discussed below), it is possible that the industry may at least experiment with these and other new methods for handling this difficult and contentious process. Re-determination II-3.28 As the development proceeds, the parties will learn more about the characteristics of the field and gain a much greater technical understanding of the reservoir. By the time of first production, the parties will have a much firmer idea of the extent to which the field underlies each of the blocks. The UUOA will therefore usually contain provisions for parties to be able to request a re-determination (or series of re-determinations) of the tract provisions at certain stages throughout the development.81 As re-determination is an expensive and time-consuming process,82 the UUOA will usually place at least some restriction upon the circumstances in which a re-determination is permitted.83 For instance, re-determination may be permitted only after a specific number of wells have been drilled, or after the lapse of a certain period of time. Some UUOAs will only permit re-determinations after all development drilling has been completed, or when significant new geological data is available, or even after the unitised area has been expanded.84 If based only on time or the number of wells drilled, it would be possible for several re-determinations to be requested throughout the life of the field. As such there is usually a limit placed on the total number of re-determinations that can be conducted, and a minimum time limit between each one. In addition, the agreement may provide that in the event that a re-determination is found to be “frivolous” – for instance, if it results in less than a certain agreed percentage shift in tract interests – then the licence group who requested the re-determination may be responsible for meeting all or a proportion of the other licence groups’ costs.85

 It should, however, be noted that UUOAs in the United States do not often contain re-determination provisions: Derman and Derman, “Unitization”, at 2. 82   See para II-3.32. 83   Critical as the process of re-determination is, fatigue can sometimes set in. In the case of the Statfjord Field discussed at para II-3.63, the UUOA provided for a series of re-determinations to be carried out, initially every two years and then at three- and four-year intervals. In the event, however, a number of these re-determinations were waived by the parties: see Daintith, Willoughby and Hill, para 1-743. 84   Deemer, “Unitisation Agreements”, at 7. Daintith, Willoughby and Hill cite the example of a medium field whereby 30 wells are to be drilled requiring the first re-determination after 15 wells have been drilled and then a second after the field is fully developed. They also state that a larger field may require more than two re-determinations during the life of the field: see para 1-743. 85   Weaver et al., “International Unitization”, at 63. 81

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The UUOA will also set out in detail the procedure for conducting II-3.29 re-determinations. In some instances the operator will be charged with carrying out the re-determination, reporting to a re-determination committee made up of the licensees. More commonly, the re-determination committee and subcommittees will themselves carry out the process, or the re-determination may be contracted out to a specified third party. Whichever method is used, all interested parties will be involved throughout the process.86 The financial consequences of a re-determination can be very II-3.30 substantial.87 As a result of each re-determination, the tract participations of the licence groups will either increase or decrease, and each licence group will receive a new entitlement to petroleum from the field. Once the re-determination has been agreed, the UUOA will contain provisions for the adjustment of costs and/or production, the principle being that the participants should, so far as possible, be put in the position in which they would have been had the new tract participations prevailed from the outset.88 Thus the re-determination will ordinarily be intended to have retroactive effect, meaning that “the performance by participants of all their rights and obligations which are dependent on or determined by reference to their respective unit percentage interests have to be revised and the appropriate adjustments have to be made”.89 The re-determination provisions will generally provide a II-3.31 mechanism for reallocating past capital expenditures, operating costs and past production of oil and gas. Capital expenditures are usually handled by immediate cash payments from those parties whose tract participation has increased to those whose share has reduced.90 The licence group whose tract participation has increased will have received an inadequate share of production from the field prior to the re-determination. This is usually dealt with under the UUOA by providing that the deficient parties can lift their share of production each year and in addition lift a percentage of their deficient amount. They are not usually allowed to lift their entire deficient amount at one time, as this could cause severe financial disruption to the other parties; however, if production is not sufficient for make-up to be accomplished in the required time, this percentage may be increased. If make-up is still not possible over the life of the field, for example

  See English, “Unitisation Agreements”, p 107f.  The editors are aware of one relatively recent re-determination on a relatively small field where a move of less than a quarter of one percentage point on an individual licensee’s unit share cost that licensee a sum in the order of £10 million. 88   Taylor and Winsor, p 118. 89  Taverne, Co-operative Agreements, p 89. 90   See English, “Unitisation Agreements”, 111; Taylor and Winsor, p 117f. 86 87

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in the case of substantial re-determinations or re-determinations late in the life of the field, the UUOA may require the other licence groups to make a cash payment to the deficient licence group. This produces a number of issues in itself, such as how to value the oil and whether interest should be payable. There may also be significant negative tax implications with regard to a cash payback.91 These are all significant issues that must be considered when negotiating the re-determination provisions in the UUOA, and are among the issues which led Derman and Derman to argue that a new mathematical formula is required.92 II-3.32 Re-determinations are extremely time-consuming and very expensive to conduct. Taylor and Winsor, writing in 1992, stated that on average it is estimated that a re-determination will keep twelve people employed for two years and cost £2 million.93 In addition, re-determinations will also involve a considerable amount of management time and financial planning. It has been observed that “the human resource cost, particularly the opportunity cost, associated with protracted unitisation and re-determination procedures and negotiations may be larger than the actual benefits accruing from minor increases in unit interests”.94 II-3.33 Despite these difficulties, re-determinations have historically still been deemed necessary by most companies in the UKCS. The prime reason for this is that determination and re-determination bear directly upon the value of the asset. There is an argument that advances in technology have reduced the need for re-determinations as parties are now more knowledgeable about the reservoir from the outset; however, many companies have to date been unwilling to take this “risk”. This may change as the average size of fields discovered in the UKCS decreases.95 Companies may take the view that they do not wish to waste precious time and resources conducting an exercise which may not be worth the candle.96   Deemer, “Unitisation Agreements”, at 11.   Derman and Derman, “Unitization”, at 2. 93   Taylor and Winsor, p 116. Weaver et al. cite the admittedly extreme example of the Prudhoe Bay re-determination in the US which was estimated to have cost between $50 and $100 million due to the number of complications involved and litigation spanning five years: see Weaver et al., “International Unitization”, at 63–67. 94   P Jones, “Unitisation and redetermination – key issues/corporate responses”, Conference paper, London, November 1994 (hereinafter “Jones, ‘Unitisation and redetermination’”), at 2. 95   English, writing in 1997, noted that as field size decreases in the UKCS, “the potential advantage to be gained by a change in equity is unlikely to be much greater in value [than the costs of the exercise]”: English, “Unitisation Agreements”, 108. 96  Daintith, Willoughby and Hill note that in a number of recent unitisations the co-venturers have opted to have no re-determination provisions except in cases where the field is extended considerably: see para 1–745. Deemer also cites one example whereby 91 92

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Whichever method is used, it can be seen that re-determinations II-3.34 are difficult and time-consuming to negotiate. They are also the reason for most disputes arising under UUOAs.97 Given the huge sums involved and the potential for discord, it is common for parties to insert dispute resolution methods into the UUOA in an effort to manage, prevent or limit such disputes.98 These methods often provide for the use of an independent expert procedure which, rather perversely, can often itself transpire to be the cause of litigation.99

Dispute resolution: the independent expert The general intent of a UUOA is that re-determinations will be II-3.35 reached by consensus. If, in the process of reaching agreement on the new tract participations, the parties are unhappy with any element in the calculation, the UUOA will often have a provision for the matter to be referred to an independent expert. In negotiating the expert procedures in the UUOA, a number of issues commonly arise. These include the matters that can be referred to an expert; who can request a referral; how the expert is selected; what data they have access to; and what procedure the expert should follow.100 The parties will be concerned that the procedure is fair, and that any referral will be carried out within a limited period of time and with a minimum of expense. The expert will usually be an independent company with the II-3.36 necessary expertise to carry out the work. Its role will be somewhere between that of a traditional expert, who will provide an opinion by which the parties will agree to abide, and an arbitrator, who will look at the merits of the competing claims.101 An increasing trend in dispute resolution is for the expert to adopt II-3.37 the “pendulum procedure” method – a procedure commonly used in United States labour disputes. This is where the expert is required to adopt the position of one or other of the parties in dispute and is barred from settling for anything between the two positions. It is argued that this method strongly encourages parties to put forward more reasonable positions as, without it, the parties, suspecting that the expert will adopt the middle ground, will tend to put forward extreme cases. Others, such as Taylor and Winsor, contend that it is the re-determination process was so difficult that the parties stuck with the original tract participations: Deemer, “Unitisation Agreements”, at 7. 97   English, “Unitisation Agreements”, 106. 98   A Steele-Nicholson, “Unitisation Disputes: Do Pendulum Procedures Offer Fairness in Equity Redeterminations?” (2001) IELTR 234 (hereinafter “Steele-Nicholson, ‘Pendulum Procedures’”), at 234. 99   See para II-3.39. 100   Deemer, “Unitisation Agreements”, at 8. 101   English, “Unitisation Agreements”, 109.

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draconian in its nature.102 Worthington suggests that the pendulum method introduces a subjectivity which is ill-suited to equity re-determination, and can be exploited in agreements between more than two licensee/licensee groups by closely aligned parties to manipulate the outcome.103 Nevertheless, Steele-Nicholson has studied this procedure104 and has concluded that it can be a useful tool to help limit disputes. He notes that while the procedure does have some pitfalls, these can be avoided with careful draftsmanship.105 II-3.38 Some recent UUOAs provide for the independent expert to be involved in all stages of the re-determination process in order to settle disputes as they arise.106 This is sometimes referred to as the “guided owner” approach. The expert will have observed all of the discussions, will be aware of the circumstances of the case and the positions of both parties, and, as such, will be able to make an informed decision. Although this approach will involve greater involvement by the expert and increased costs, considerable savings can be gained in the overall time taken by the re-determination, if a dispute is successfully avoided.107 An alternative is an integrated expert determination process, requiring an expert to decide only on matters in dispute between the parties, as part of a technical workflow. The expert will deliver a single tract participation re-determination, as opposed to delivering a decision at each disputed step. This approach is better suited to dealing with a situation where the expert’s view is inconsistent with a decision previously agreed by the parties, by allowing the expert to rework the agreed matter in its determination. This is not as readily achievable under the “guided owner” approach due to the often stop-start nature of an expert’s involvement in disputes as they arise.108 The risk of the expert departing from previously agreed steps can, however, be avoided by careful drafting of the expert’s mandate in the UUOA. II-3.39 Most UUOAs contain detailed provisions for the selection and remit of the expert. A number of cases have been brought concerning the role of the expert and the mechanics of the

  Taylor and Winsor, p 117.   Worthington, “Expert Determination”, 264. 104   Steele-Nicholson, “Pendulum Procedures”, provides a detailed account of the advantages and disadvantages of the pendulum procedure including case studies of how it has been used. 105   Steele-Nicholson, “Pendulum Procedures”, at 240. 106   Jones, “Unitisation and redetermination”, 4. 107   Daintith, Willoughby and Hill, para 1-743. 108  For a discussion of integrated expert determination, see Worthington, “Expert Determination”, 265. 102 103

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procedure. In Amoco (UK) Exploration Co v Amerada Hess Ltd,109 the underlying UUOA contained complicated “guided owner” provisions which identified twenty-one key steps which would take place in accordance with an agreed timetable and without being interrupted by court proceedings. During one of these steps, one of the parties referred to, and the expert made use of, data which was not expressly included in the guided owner provisions. The plaintiffs sought a court order determining the data and material which could be referred to and utilised in the determination process. The defendants contended that the guided owner provisions contained a mechanism for objecting to the data which the plaintiffs had failed to use, and that, having so failed, it was inappropriate to seek the relief of the court. The court agreed with the defendant’s analysis and held that, as the guided owner provisions contained a complex dispute resolution mechanism which did not envisage interruption by the court, the plaintiff’s application should be stayed. In Shell UK Ltd v Enterprise Oil plc,110 a dispute arose over the computer program used to re-determine tract participation. The agreement between the parties and the expert specified that a certain computer program would be used for most purposes and that a second program would be used for one limited purpose. In the event, however, the expert, apparently as a result of an honest misinterpretation of the degree of freedom afforded to him by the contract, used the second program far more broadly than the contract envisaged. It was held that this was a material departure from his instructions likely to put the defendants at a disadvantage, as they did not have access to the second program. The decision issued by the expert was therefore vitiated and rendered contractually ineffectual. In Neste Production Ltd and Another v Shell UK Ltd and Others,111 a dispute arose between the parties as to whether the expert should issue his judgment in accordance with the second interim operating agreement, or a somewhat different provision contained in a variation which had, at least, been under contemplation, but which, by the time it came for the expert to issue his determination, some parties contended had never been formally agreed to. It was held that the independent expert provisions could not be construed so as to oust the jurisdiction of the court,112 and, moreover, that the question of whether the parties had agreed to vary the contractual provisions did not fall within the expert’s   [1994] 1 Lloyd’s Rep 330.   [1999] 2 Lloyd’s Rep 456. 111   [1994] 1 Lloyd’s Rep 447. 112   In this respect Amoco (UK) Exploration Co v Amerada Hess Ltd [1994] 1 Lloyd’s Rep 330 was distinguished. 109 110

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remit.113 The twin issues of which set of provisions governed, and how those provisions were to be construed, were therefore determined by the court. II-3.40 It follows that provisions governing the appointment of an independent expert, describing his powers (and the extent to which he is to be subject to controls by the court) and narrating the procedure through which he is to reach his decision, should be carefully drafted and unequivocal, if unnecessary and costly litigation is to be avoided. These are all matters which will turn on the construction of the relevant contract, whether that be the UUOA itself or an ancillary agreement entered into to regulate the expert determination itself. Moreover, if difficulties are to be avoided, the terms and construction of the relevant contractual provisions should be borne in mind by both the parties while the determination process is ongoing. Non-unit operations and sole risk II-3.41 The UUOA applies to all areas within the unit area; however, it is only the unitised zone which will be exploited jointly. If a licence group wishes to drill an exploration well outside the unitised zone, the UUOA may provide for the conduct of non-unit operations on approval from the other parties.114 While unit operations under the UUOA will always take priority over non-unit operations,115 the UUOA may allow the use of unit facilities for the conduct of a non-unit operation.116 The licensees may wish to use any spare capacity in the unit II-3.42 facilities for their own interests, either for the production and transportation of oil and/or gas from an adjoining field, or from an accumulation discovered as a result of a non-unit operation.117 Such spare capacity can usually be used without additional cost if total usage by the licence group is not in excess of its tract participation interest. If it is in excess then a payment may have to be made to the other licence groups. II-3.43 Sole risk operations may also be permitted under the UUOA. These are operations which the unit operating committee has rejected but which a party or parties wish(es) to carry out themselves. These are usually only permitted to enable a licence group to obtain data on its tract, at its own expense, for use in future re-determinations. 113   Neste Production Ltd and Another v Shell UK Ltd and Others [1994] 1 Lloyd’s Rep 447, at 453. 114   English, “Unitisation Agreements”, 114. 115   Taylor and Winsor, p 119. 116   Daintith, Willoughby and Hill, para 1-745. 117   English, “Unitisation Agreements”, 114.

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This work will be carried out by the unit operator and, as with the non-consent provisions, such operations will not be permitted to take precedence over any unit operations.118 Operatorship, voting and control The UUOA involves two or more groups of parties; as such, two II-3.44 different decision-making structures are possible. The first, and the one used for most decision making, is individual voting by each unit party. The second structure, usually restricted to re-determination decisions, is decision making by each licence group.119 The party with the largest share will usually become the operator and they, along with the other parties with a large interest in the field, will not want their operations to be vetoed by an owner with a smaller interest. The smaller interest holders, on the other hand, will not want to be pressurised into accepting a decision with which they do not agree. This can lead to contentious debate in the negotiation process and is usually resolved by agreement that no licence group will be forced into a decision by the vote of the others unless that licensee’s share is minimal: otherwise, at least one vote from each licence group.120 This is due to the cost and value of offshore developments and companies not being prepared to be voted into anything with which they do not agree.121 To ensure that deadlock does not occur, the matter may sometimes be referable to the independent expert. Default and forfeiture of interest Taverne states that the principal obligation of any party is to II-3.45 make payments in response to cash calls from the unit operator in accordance with the provisions of the UUOA.122 Non-payment of the monies required by these cash calls will constitute default under the UUOA. Due to the nature of unitisation, the formal default mechanisms II-3.46 contained in a standard JOA123 are not usually carried through into the UUOA.124 There is some dispute as to what is the ordinary   Daintith, Willoughby and Hill, para 1-745.   Weaver et al., “International Unitization”, at 72. 120  English, “Unitisation Agreements”, 103. See also Taverne, Co-operative Agreements, p 91. 121  Taverne, Co-operative Agreements, p 107. 122  Taverne, Petroleum, Industry and Government, para 11.3.4.14. 123   On which, see paras II-2.54 to II-2.91. 124   English, “Unitisation Agreements”, 113. See also Taylor and Winsor, p 121. The issue which makes a straightforward JOA-style forfeiture clause inappropriate is that, if such a clause operated at the level of the UUOA, forfeiture would be to all the participating 118 119

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practice in the event of default. English states that if a party is in default under the UUOA its share of costs will ordinarily be borne by its own licence group, who will then in turn seek recompense under the provisions of its JOA,125 and that the JOA will also usually provide for forfeiture or some lesser form of redress in the event that the default is not remedied within a certain time period.126 The non-defaulting parties will be able to force this forfeiture if the default is not remedied and subsequently acquire the defaulting party’s share under the JOA and thence on to the UUOA. Taylor and Winsor admit of this possibility, but also suggest that the practice of including a default clause in the UUOA which provides not for a transfer of interest but simply a suspension of the rights of the defaulting party is an appropriate solution to the problem relatively commonly encountered.127 CROSS-BORDER UNITISATION International laws and treaties II-3.47 Unitisation agreements may also be required at an international level where a reservoir is found to straddle an international boundary, or, in the case of the UKCS, a line of international maritime delimitation. In this situation the reservoir will fall partly under the jurisdiction of two different states. The national rules of the states on joint exploitation will be insufficient, as the Governments will not have the jurisdiction to require the licensees of the other state to co-operate in the development of the field. Instead, an agreement must be reached between the states concerned. This agreement will then be used to form the basis of a further UUOA between all of the licensees.128 II-3.48 It has been argued that the successful sharing of cross-border reserves relies on difficult bilateral negotiations backed up with the political will of both countries to reach an agreement.129 These negotiations are so protracted because the Governments face a number of potential problems in coming to such an agreement. In the first instance, the Governments will be mindful of their respective goals to ensure that the field is developed in such a way as to maximise the recovery of petroleum. They will also wish to parties, not just those within the defaulter’s own licence group. This would not usually be the commercial intention of the parties. 125   English, “Unitisation Agreements”, 113. 126   As to the enforceability of such provisions, see the discussion in Chapter II-2. 127   Taylor and Winsor, p 121. 128   S Chatterjee, “Unitisation: Certain Policy Issues”, 12 (1986/1987) OGLTR 309. 129   D Pike, “Cross-border hydrocarbon reserves”, in R Schofield, Territorial Foundations of the Gulf States (1994), at p 187.

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retain the power to control the unitisation process, such as the right to approve the operator and the determinations. Third, they will be concerned as to how they can ensure the maximum financial return from the field through royalties130 and/or taxation.131 In the case of a field wholly within one jurisdiction, the Government will not be overly concerned as to the equity split as it will receive its tax take irrespective of the percentage shares of each licensee. However, when a field straddles an international boundary line, the interests of each Government become aligned to those of the “home” licence group, ie the Government has an interest in the licence group which holds its licensed interests from it obtaining the maximum tract participation possible so that the Government can maximise its tax take.132 Consequently, Governments will be keenly interested in the terms not only of the bilateral treaty, but also of the agreement negotiated between the licence groups.133 As exploration in the UKCS expanded in the 1960s and 1970s, II-3.49 certain countries contiguous to the North Sea, such as Germany, Denmark, Norway, the United Kingdom and the Netherlands, mandated by treaty the manner in which a field found to be straddling their borders should be most efficiently exploited.134 The agreements between the United Kingdom and the Netherlands, and the United Kingdom and Norway, are discussed in more detail later in this chapter; however, in general they follow the template of a standard UUOA with some additional provisions required to protect the Governments’ interests in the development. These include such matters as the reservation of the right to approve the initial determination and re-determination; applicable law and arbitration; health and safety; movement of personnel across the international median line; transportation; and taxation issues.135 The agreements are between the respective Governments and II-3.50 as such are not binding directly on the interest holders; however, they will be made binding through the application of the countries’

  Royalty continues to exist in some jurisdictions but is no longer relevant in the UK where it has been abolished, at least in practice if not strictly in law. See para I-4.33. 131   Deemer, “Unitisation Agreements”, at 3. 132   English, “Unitisation Agreements”, 100. 133  This may explain why most countries, excepting the US and Canada, require licence groups to submit “all the detailed operating agreement terms to the host government for approval, when such approval of unitization by the host government is required”: J L Weaver and D F Asmus, “Unitizing Oil and Gas Fields Around the World: A Comparative Analysis of National Laws and Private Contracts”, 28(1) (2006) Houston Journal of International Law 71, available from Association of International Petroleum Negotiators (AIPN). 134   Steele-Nicholson, “Pendulum Procedures”, at 234. 135   English, “Unitisation Agreements”, 101. 130

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national legislation. In the United Kingdom this is achieved through the application of the model clauses. Model Clause 28 provides that where the Minister is satisfied that any strata in the licensed area form part of a field which extend into an area controlled by another jurisdiction, and the Minister is satisfied that it is expedient136 that the field should be unitised, the Minister may serve the licensee with a notice providing “such directions as the Minister may think fit, as to the manner in which the rights conferred by this licence shall be exercised”.137 The licensee is under an obligation to observe and perform all such requirements in relation to the licensed area as may be specified in the direction.138 The model clause specifically provides that any such direction may add to, vary or revoke the provisions of a unit development scheme.139 II-3.51 It has been argued that international state practice may have led to the emergence of a customary rule of international law that would require states to co-operate in the exploitation of cross-boundary reservoirs.140 There is certainly some evidence of this, for example the principles of co-operation exhibited by many states reflect those embodied in the 1982 Convention on the Law of the Sea which provides that “States bordering an enclosed or semi-enclosed sea should cooperate with each other in exercise of their rights and in the performance of their duties”.141 Reynolds comments that if this Convention was stronger in its wording as to require unitisation between states the result would be “maximized recovery (value) for all concerned parties, minimized waste and minimized environmental concerns and operating costs”.142 Ong reviewed UN General Assembly resolutions, the Convention and relevant case law to assess whether there is an international obligation for states to co-operate. He concluded that while the obligation to co-operate does not extend so far as to require states actually to participate in the joint development of shared reserves, many examples can be found whereby the joint development of international common zones is standard practice.143   Note that the test in this instance is expedience. Compare this to the rather stricter test which applies in domestic law: see para II-3.13. 137   Model Cl 28(1). 138   Model Cl 28(2). 139   Model Cl 28(3). 140   R Lagoni, “Oil and Gas Deposits Across National Frontiers”, 73 (1979) Am J Intl L 215. 141   Art 123, as noted in Ong, “Joint Development”, at 782. 142  He comments that the Convention has been criticised for being too vague in parts, possibly as a result of trying to get the agreement ratified by all parties: Reynolds, “Delimitation”, at 140. 143  Ong, “Joint Development”, at 788. In addition to the three examples discussed at 136

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The UK/Netherlands example On 6 October 1965 the United Kingdom and the Netherlands signed II-3.52 a bilateral delimitation agreement to establish the boundaries of the Dutch Continental Shelf.144 At the same time as the boundary agreement the countries entered into an agreement to govern the exploitation of any field which crossed the international border.145 Article 1 of this agreement provides that, where a field extends across the border, the States “shall seek to reach agreement as to the manner in which the structure or field shall be most effectively exploited and the manner in which costs and proceeds relating thereto shall be apportioned, after having invited the licensees concerned, if any, to submit agreed proposals to this effect”. Article 2 provides that, if the parties fail to reach an agreement, the parties shall appoint an arbitrator and be bound by his decision.146 The Markham field was the first cross-border field to be developed II-3.53 between the United Kingdom and the Netherlands as a unitised field. In 1985, under an Exploration Licence awarded to Ultramar Exploration (Netherlands) BV, a reservoir of approximately 700 billion cubic feet was discovered to straddle the international border.147 The discovery was named the Markham Field Reservoirs. The countries signed the Markham Agreement on 26 May 1992148 to govern the joint exploitation of the field. paras II-3.52 to II-3.62, Deemer notes also that, outside the UKCS, whether concession agreements, production sharing contracts or risk service contracts are the standard form of agreement used, “those documents frequently contain provisions giving government the power to require unitisation”: Deemer, “Unitisation Agreements”, at 1. For a detailed discussion of co-operation in the development of resources in international law, see P D Cameron, “The rules of engagement: Developing cross-border petroleum deposits in the North Sea and Caribbean”, 55 (2006) ICLQ 559–586. For a discussion of joint development in the absence of agreement on international boundaries, see Y M Yusuf, “Is joint development a panacea for maritime boundary disputes and for the exploitation of offshore transboundary petroleum deposits?”, 4 (2009) IELR 130; and also C W Dundas, “The impact of maritime boundary delimitation on the development of offshore mineral deposits” 20(4) (1994) Resources Policy 273. 144   Neth Treaties Series (Tractatenblad) 1965, no 191 and (Tractatenblad) 1966, no 130. This treaty was amended on 28 January 1971 following the signing of delimitation agreements between the Netherlands, Germany and Denmark. 145  Agreement between the Government of the United Kingdom of the Netherlands and the Government of the United Kingdom of Great Britain and Northern Ireland relating to the exploitation of single geological structures extending across the dividing line on the Continental Shelf under the North Sea, 6 October 1965 (Tractatenblad) 1965, no 192, as amended on 25 November 1971 (Tractatenblad) 1972, no 139. 146  M Roggenkamp, “The Markham Field: Joint Exploitation by the Netherlands and the United Kingdom”, 7 (1992) OGLTR 193 (hereinafter “Roggenkamp, ‘The Markham Field’”), at 194. 147   Roggenkamp, “The Markham Field”, at 194. 148   That is, the Agreement relating to the Exploitation of the Markham Field Reservoirs

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II-3.54 The Markham Agreement was based on the unitisation agreements signed between the United Kingdom and Norway (as discussed in detail below) for the joint exploitation of gas fields straddling the United Kingdom–Norway border.149 Under the Markham Agreement, the Governments of both countries required their relevant licence groups to enter into a UUOA to govern the exploitation of the reservoir. We have already seen how UUOAs differ from JOAs. The Markham Agreement contains all these particular provisions, including the apportionment of petroleum and re-determination provisions.150 A further variation, particular to cross-border UUOAs such as the Markham Agreement, is that each of the countries involved retains jurisdiction over that part of the field on its side of the border. In order to avoid conflict between the two jurisdictions, the agreement contains special “umbrella” provisions declaring whether specific provisions of national laws are applicable or not. New obligations can also be created under the agreement, such as the requirement of approval by the Governments of both countries for any new unit operator or for any development plan, neither of which is usually required under Dutch law.151 II-3.55 Following Article 2 of the 1965 Agreement, the Markham Agreement contains provisions for dispute resolution.152 In the first instance, the parties must try to resolve the dispute through the Markham Commission, established for the purposes of implementing the agreement. If unresolved, the two Governments must then enter into negotiations, and it is only if these fail that the dispute may be submitted to an arbitral tribunal. II-3.56 Other jurisdictional issues addressed by the agreement include safety and taxation. Both Governments may determine the safety measures they wish to apply in their own jurisdiction; however, uniform standards were required to make the operations workable. Article 10 of the Agreement provides standard safety regulations which include, among others, those recommended by the Cullen Report (discussed extensively in Chapter I-10). In addition, both the Health and Safety Executive of the United Kingdom and the equivalent body in the Netherlands153 have access to all installations and information pertaining to the field. The United Kingdom and the Netherlands each have their own taxation regimes, and all profits gained from the exploitation of the field are taxed in accordance and the Offtake of Petroleum Therefrom (hereinafter “Markham Agreement”). 149  Taverne, Co-operative Agreements, p 82. 150   Arts 5 and 16 respectively. 151   Roggenkamp, “The Markham Field”, at 195. 152   Art 23. 153   The Staatstoezicht op de Mijnen.

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with these regimes and also the applicable conventions on double taxation. Roggenkamp concludes that the negotiation of agreements, such II-3.57 as the Markham Agreement, is a time-consuming and difficult process; however, once agreed, they provide a framework for the successful development of the field and can be used as a template for any future unitisations between the countries.154 The UK/Norway example The United Kingdom and Norway suite of agreements provides an II-3.58 excellent example of successful trans-boundary unitisation, and the progress that can be achieved by countries with a strong bilateral relationship. The United Kingdom and Norway signed a bilateral delimitation treaty on 10 March 1965. This agreement contained the first explicit provision for the action to be taken in the event of a cross-border discovery of petroleum. The treaty, as amended in November 2009, stipulated that: “If any single geological petroleum structure or petroleum field … extends across the dividing line and the part of such structure or field which is situated on one side of the dividing line is exploitable, wholly or in part, from the other side of the dividing line, the Contracting Parties shall, in consultation with the licensees, if any, seek to reach agreement as to the manner in which the structure or field shall be most effectively exploited and the manner in which the proceeds deriving therefrom shall be apportioned.”155

Although the treaty does not specify that the reservoir should be II-3.59 exploited as a unit, this was the procedure followed by the states. The treaty provided the foundation for the three cross-border unitisation agreements subsequently entered into, namely the Frigg, Statfjord and Murchison Field Agreements signed in 1976, 1979 and 1979 respectively.156 The first of the agreements signed (the Frigg Agreement) and the agreement pertaining to the largest area of United Kingdom–Norway unitised reserves (the Statfjord Agreement) are outlined briefly below. The UK–Norway 2005 Framework Treaty is then considered in more detail.   Roggenkamp, “The Markham Field”, at 197.  Agreement between the Government of the United Kingdom of Great Britain and Northern Ireland and the Government of the Kingdom of Norway relating to the delimitation of the continental shelf between the two countries, 10 March 1965, as amended on 22 December 1978 and in November 2009 (hereinafter “UK–Norway Delimitation Treaty of 1965”), Art 4. 156  Frigg Field Agreement (Cmnd 6491); Statfjord Field Agreement (Cmnd 8288); and Murchison Field Agreement (Cmnd 8270) (as amended by Cmnd 8577). 154 155

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Frigg Agreement II-3.60 The Frigg field was initially discovered in 1969, and in 1972 it was found to straddle the international line of maritime demarcation between the UK and Norway. In accordance with Article 4 of the United Kingdom–Norway Delimitation Treaty, the countries were obliged to agree on how the field should be developed and how the proceeds from such development should be apportioned. In this particular arrangement it was the United Kingdom and Norwegian licensees who made the first moves towards unitisation. In conjunction with their respective Governments, the licensees signed a series of agreements to unitise the Frigg field. These included the Frigg Field Main Agreement, the Frigg Field Operating Agreement and the Frigg Field Expert Agreement. The host Governments then confirmed these arrangements in the Frigg Field Agreement dated 10 May 1976.157 This agreement stated that: “[t]he two Governments shall consult with a view to agreeing to a determination of the limits and estimated total reserves of the Frigg Field Reservoir and an apportionment of the reserves therein … For this purpose the licensees shall be required to submit to the Governments a proposal for such determinations”.158

II-3.61 The Agreement went on to state that a single operator acting for all licensees should develop the single unit, and the countries should share the proceeds from the field in accordance with the proportion of the deposit within their jurisdiction. A commission was established to supervise the operations and administration of the field. Weaver et al. note that to mitigate the potentially conflicting effect of the involvement of two separate jurisdictions, the Agreement provided for consultation between the Governments on issues such as uniform safety and installation standards.159 Statfjord Agreement II-3.62 The most important example, in terms of volume of oil and gas, is the Statfjord Agreement, signed on 16 October 1979.160 Taverne notes that this agreement followed the form of the Frigg Field Agreement.161 As with the Frigg Agreement, it contains the basic principle that the field should be exploited as a single unit. Unlike the Frigg Agreement, however, it contains no provisions on the   Weaver et al., “International Unitization”, at 109.   Frigg Treaty, Art 2. 159   Weaver et al., “International Unitization”, at 111. 160   Known as the Agreement between the Government of the United Kingdom of Great Britain and Northern Ireland and the Government of the Kingdom of Norway relating to the Statfjord Field Reservoirs and the Offtake of petroleum therefrom. 161  Taverne, Co-operative Agreements, p 83. 157 158

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manner in which the reserves should be exploited, the specific means of transportation to be used or the destination for the oil and associated gas. This is left to the individual licensees to agree in accordance with the provisions of the inter-state agreement. The Governments did, however, ensure that they retained control of important areas such as the right to approve the unit operator, the determination of the limits of the reservoir and the apportionment of reserves between the United Kingdom and Norwegian parts of the Continental Shelf. Either Government may also request a review of the reservoir and the apportionment of reserves in order to arrive at a re-determination.162 Another issue reserved by the Governments is that of taxation. The Agreement states that profits from the field will be taxed in accordance with the laws of the United Kingdom and Norway respectively, and that the jurisdiction of each country over the Continental Shelf remains unaffected by the Agreement. The 2005 UK–Norway Framework Treaty On 4 April 2005, the United Kingdom Energy Minister and his II-3.63 Norwegian counterpart finally agreed the text of the long-awaited new framework treaty on cross-border petroleum co-operation.163 The Treaty covers the construction and operation of pipelines carrying oil and gas from Norway to the United Kingdom; the joint exploitation of reservoirs straddling the borderline; and the joint use of infrastructure. It also aims to harmonise regulations and simplify the administration of cross-border projects, one of the hopes being to remove the need for separate agreements, such as the Frigg, Statfjord and Murchison Agreements discussed above. The Treaty contains specific provisions with regard to uniti- II-3.64 sation. These include an obligation on each Government to unitise in accordance with the terms of the Framework Agreement, unless they mutually decide not to,164 and to require their licensees to enter into a Licensees’ Agreement to regulate the exploitation of a transboundary reservoir.165 This agreement must be submitted to both Governments for their approval,166 and must contain provisions to the effect that, in the event of a conflict between the Licensees’ Agreement and the Framework Agreement, the latter will prevail.167

  Ibid, p 84.   The treaty is available for download from www.gov.uk/government/ publications/framework-agreement-between-the-uk-and-norway-concerning-crossboundary-petroleum-co-operation (accessed 27 March 2017). 164   Framework Agreement, Art 3.1(1). 165   Ibid, Art 3.2(1). 166   Ibid, Art 3.2(2). 167   Ibid, Art 3.2(1). 162 163

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Government approval is also required for the appointment of the unit operator,168 any development plan,169 cessation of production170 and the decommissioning of installations associated with crossboundary projects.171 The Framework Agreement also contains provisions relevant to the determination172 and re-determination of reserves, and the provision of an independent expert in the event of disagreement.173 It is noteworthy that the provisions relative to the expert’s role and the basis on which he is to carry out a re-determination are remarkably open-textured and vague, in comparison with the corresponding provisions in many UUOAs within the UK.174 In addition to the provisions specific to unitisation, it should be noted that there are provisions for the establishment of a framework forum involving members of each Government to facilitate the implementation of the agreement,175 and mechanisms for the settlement of disputes.176 II-3.65 It is clear that both Governments are seeking to simplify the process,177 especially in the case of smaller fields that cannot justify

  Ibid, Art 3.7.   Ibid, Art 3.9(1). 170   Ibid, Art 3.12. 171   Ibid, Art 1.14. 172   Ibid, Art 3.3. 173   Ibid, Art 3.4, read with Annex D. The mechanism was successfully utilised in the case of the Flyndre Field, whereby the UK initiated the independent expert process to determine tract participations. The invitation to tender services is available for download from: https://data.gov.uk/data/contracts-finder-archive/contract/1702179 (accessed 5 August 2017). 174   Ibid, Art 3.4 provides for the appointment of a single expert “within 60 days” of Governments notifying each other of the disagreement, who should “act in accordance with the terms of Annex D”. Annex D, para 2 then defines expert, and his role, as the person who can “provide undertakings in respect of any conflict of interest”; while Annex D, para 5 obliges him to provide a “preliminary decision” within “12 weeks of his appointment”. Finally, Annex D, para 4 puts the condition that every communication with and from the expert must be shared with the other party if the other party is not already present at the joint-Governmental meetings. However, apart from these provisions there are no other specifics as to the expert’s role and/or the basis on which he is to carry out re-determination. 175   Framework Agreement, Art 1.15. 176   Ibid, Art 5. 177  Clear evidence of this came even before the Framework Agreement was finalised, when the UK Government agreed to waive its interest in the mainly Norwegian Boa Field and the Norwegian Government similarly waived its interest in the mainly British Playfair Field. (See Exchange of Notes dated 30 September and 4 October 2004 relative to the Boa and Playfair Fields (Cm 6412) at 4, para c.) In each case the extension into the other’s territory was small and it was a condition of the arrangement that in neither case would active works be undertaken in respect of the area made subject to the waiver. The Agreement was made in order to simplify and accelerate the development project, and was made subject to a specific right to reconsider the manner in which these projects 168 169

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protracted governmental negotiations.178 Both Governments also hope that these new arrangements will make the North Sea more attractive to potential investors, and maximise the opportunities for renewed activity and use of existing infrastructure. This is a wise policy, and one which is in keeping with the UK Government’s general approach of taking a flexible and, in many respects, licensee-driven approach to regulation, in order to prevent petroleum law and administration from acting as a barrier to attracting new investment.179 Early indications are that the Framework Agreement is achieving its objectives.180 The first fields to make use of the Framework Agreement’s provisions were Enoch and Blane, which had development plans approved on 1 July 2005, having lain undeveloped for a number of years “mainly because of the perceived trans-boundary complications and the difficulty of reaching commercial agreement between UK and Norwegian partners”.181 CONCLUSION This chapter has discussed the issues that arise when a reservoir is II-3.66 found to underlie more than one block or to straddle an international boundary. Unitisation is by no means a process without its imperfections. It is, however, widely regarded as being one of the most efficient contractual methods for the development of crossboundary reservoirs, both by Governments who have implemented

were governed in the event that one or another of the extensions turned out to be larger than anticipated. See also Norwegian Ministry of Petroleum and Energy, “UK and Norway open way for two new North Sea projects”, available from www.regjeringen. no/en/archive/Bondeviks-2nd-Government/ministry-of-petroleum-and-energy/Nyheter-ogpressemeldinger/2004/uk_and_norway_open_way_for_two.html?id=254176 (accessed 27 March 2017). 178   One of the principal objectives of the joint PILOT and Kon-Kraft Report, Unlocking Value Through Closer Relationships, one of the main proponents of the Framework Agreement, was to streamline cross-border working practices and improve efficiencies. It was felt that the impact of this effort would be “particularly material at the field scale. This improved competitiveness will be especially attractive for smaller UK and Norwegian companies and new entrants targeting niche opportunities adjacent to the median line”. See PILOT and Kon-Kraft, Unlocking Value Through Closer Relationships (2002), p 11. 179   See also, eg, the introduction of the frontier and promote licences, discussed at paras I-4.60 to I-4.67 and I-4.68 to I-4.72 and the mature province initiatives discussed in the Appendix to vol I. 180   The Framework Agreement has been used as a blueprint for subsequent treaties. For an excellent comparison of the UK–Norway Agreement and recent framework agreements see N Bankes, “Recent Framework Agreements for the Recognition and Development of Transboundary Hydrocarbon Resources”, 29 (2014) Int’l J. Marine & Coastal L. 666. 181   See DTI, “First Strike for UK-Norway Deal”, available at www.eeegr.com/news/info. php?refnum=938&startnum=1477 (accessed 27 March 2017).

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measures for compulsory unitisation, and by the individual licensees who are happy to embrace this method without such force. II-3.67 To be successful in its implementation, sufficient care must be taken when drafting the UUOA. If the parties are pragmatic in their negotiations and considerable investment is made when drawing up the UUOA, unitisation can be an exceptionally useful method for the joint development of reserves.

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CHAPTER II-4 DISSECTING THE DAYRATE DRILLING CONTRACT Greg May and Eve Brazier

INTRODUCTION When viewed from a global perspective, the oil and gas industry has II-4.01 to face up to a diverse range of risks and uncertainties – unstable politics, volatile environment, unpredictable geology, and uncertain costs, risks and market conditions. While many of the most significant challenges do not apply to the United Kingdom Continental Shelf (UKCS), it is certainly not immune to uncertainty nor to the headwinds of changing market conditions, not least volatility in terms of the global price of hydrocarbons.1 As a mature province, the UKCS has most recently confronted change in the form of the Wood Review (with a mandate for a cultural shift toward collaboration and cost reduction), a new legislative regime (with the overriding objective of maximising economic recovery) and a new regulator (with powers to enforce and implement legislation to achieve the overriding objective).2 Change is also constant in the various sub-sectors of the oil II-4.02 and gas industry and, in recent years, this instability has been more pronounced in the offshore drilling industry than any other. Regulation is more stringent in the wake of Macondo3, equipment is more sophisticated, technology is more advanced and market

  See G May, Partner, Brodies LLP, “Emerging Markets – What are the risks and barriers to business?” – A Series of Three Articles: Subsea UK News, February 2013, June 2013 and September 2013 (hereinafter “May, ‘Emerging Markets’”), available at https://issuu. com/subseauk/docs/subseauk-news-special-2013-business (accessed 25 April 2017). 2   See further the discussion in Chapter I-5. 3  See discussion of API Standard, 53(4) (November 2012) in Offshore Technology Newsletter, March 2015. 1

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demand is more acutely depressed than ever before, with the expectation that this trend will be of unprecedented duration.4 II-4.03 Against a backdrop of these macro conditions, this chapter offers a narrow focus on the offshore dayrate drilling contract, with a detailed review of the language of various key clauses and a careful consideration of relevant issues5. Dissecting the dayrate drilling contract cannot, however, be an exercise in isolation – it must be done by reference to the macro context, showing the importance of each clause from a commercial perspective, its operational function and its contractual meaning. This chapter thus comprises three sections – the nature of the operator/contractor relationship, the nature of the drilling unit and the nature of the contract, ie a complete anatomy. NATURE OF THE OPERATOR/CONTRACTOR RELATIONSHIP II-4.04 The dynamics that drive the operator/contractor relationship are many and diverse; therefore, multiple perspectives must be considered to fully understand the intricacies of the relationship across a wide spectrum. In this section, we will look at the relationship from two perspectives – first, we consider the key features of the commercial relationship and second, we balance those features against the related and equally important characteristics of the operational relationship. Commercial relationship II-4.05 Although the commercial relationship comprises a wide range of features, the vast majority are linked to a single common denominator – the cycle of rates. The drilling industry can, in fact, be characterised as more market sensitive and cyclical than any other sub-sector.6 How and why these cycles occur are questions beyond the scope of this chapter; however, peaks and troughs are a commercial reality and the importance of this reality is underscored by the significance of a single word: “dayrate”. As explained in more   See RigZone, RigOutlook Report, March 2017, available at www.rigzone.com/oil/data/ rigoutlook (accessed 5 August 2017). 5   See eg LOGIC, “Mobile Drilling Units” (1st edn), available to download at www.logic-oil. com/content/standard-contracts-0 (accessed 5 April 2017) (hereinafter “LOGIC, ‘Mobile Drilling Units’”); IADC International Daywork Drilling Contract – Offshore (2007), available to download at https://iadc.ebiz.uapps.net/personifyebusiness/OnlineStore/ ProductListing/tabid/56/Category/CONTRACTS/Default.aspx (accessed 5 April 2017) (hereinafter “IADC, ‘Drilling Contract’”). 6   M J Kaiser and B F Snyder, The Offshore Drilling Industry and Rig Construction in the Gulf of Mexico (2013), pp 59–64. 4

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detail below, an operator will pay the drilling contractor for access to a drilling unit (“utilisation”) for a period of time, expressed either as a number of days or wells, and the compensation earned by the drilling contractor for allowing such access will be expressed as a rate per day (“dayrate”). From the contractor’s perspective, dayrate is significant because II-4.06 the revenue-generating potential of the business is derived almost exclusively from the rate each drilling unit from the fleet will earn per day under the terms of a contract. Operating costs for a drilling unit are largely constant; likewise, capital investment for the construction and/or upgrade of a drilling unit will be recognised by the drilling contractor for forward planning purposes as a fixed financial burden. However, dayrates are variable, with fluctuations driven by the market fundamentals of supply and demand. Where market capacity for supplying drilling units exceeds demand for utilising them, dayrates will fall, and vice versa.7 These are simple economic principles, but the consequences and commercial risk that flow from these fundamentals can be profound – largely due to the scale of costs involved in any given project and the value of production at stake. With the benefit of hindsight, it is clear that the industry has not historically enjoyed much success in predicting and proactively managing these risks.8 Although cycles are unpredictable, there are certain tools that can II-4.07 provide an objective measure of a drilling contractor’s commercial strength and position relative to peers in the market within the context of a given cycle. Two variables are most relevant. First, “contract backlog” – ie each signed contract that constitutes a firm commitment by an operator to pay a certain level of dayrate over a fixed period for a particular drilling unit in the fleet; and second, contract potential – ie the prospect of each drilling unit in a fleet earning future dayrate, as evidenced by a forecast of future contracting opportunities and the projected level of dayrate for each opportunity. These two factors collectively comprise a key “internal metric” by which the drilling contractor can measure the margin of its return on investment relative to capital expenditure, and the margin of its cash flow on the balance sheet relative to existing operating costs. These margins are also a key “external metric” for

 S Goodridge, Offshore Drilling Unveiled, Part 6: Understanding the Demand Side of the Offshore Drilling Industry (hereinafter “Goodridge, Offshore Drilling Unveiled, Part 6”), available at http://marketrealist.com/2016/02/understanding-demand-side-offshoredrilling-industry (accessed 5 August 2017). 8   S Goodridge, Offshore Drilling Unveiled, Part 12: Is the Customer the Kind in Offshore Drilling?, available at http://marketrealist.com/2016/02/understanding-demand-sideoffshore-drilling-industry (accessed 5 August 2017). 7

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the financial market to assess a drilling contractor’s potential to provide a meaningful return on investment to shareholders and any other stakeholders.9 Given the vital importance of dayrate to a drilling contractor’s balance sheet, a contractor’s principal focus will be the continuous and uninterrupted application of dayrate throughout the contract term. Financial strength is demonstrated by a strong balance sheet and this can only be sustained by having robust contracts underpinned by clear and balanced terms under which the drilling contractor will have the opportunity to earn dayrate on a continuous basis at a level guaranteeing a valuable rate of return.10 An additional concern, of equal importance, is maintaining continuity of dayrate during any transition to a follow-on contract, a change of locale or a change of operations. As explained in more detail in Section 2 of this chapter, a drilling unit is mobile by nature, not a fixed installation. Given its dynamic characteristics, the drilling contractor must be vigilant to commercial risk that may arise when a drilling unit is moving between operators and well locations, or moving onto a well location.11 From the operator’s perspective, the amount of dayrate is the single most significant component of cost for any campaign of drilling operations. When an operator has an authorisation for expenditure pursuant to a joint operating agreement to carry out a scope of work for drilling one or more wells, the dayrate under the drilling contract can, in fact, comprise as much as 50 per cent of the total budgeted project expenditure. A drilling contract commitment is therefore commercial exposure that an operator will only assume with the most measured and careful consideration.12 Given the magnitude of cost, the operator’s fundamental commercial concern will be management and control of operations in a way that will optimise quality and maximise efficiency. The operator’s acute focus will be on the drilling contractor’s capacity, capability and competence to fulfil its primary role, and responsibility of timely provision of the drilling unit to a design specification and a functional standard as set forth in the drilling contract. Referring to para II-4.112 later in the chapter, these specifications and standards will be embodied in an exhibit – frequently referred

9  Goodridge, Offshore Drilling Unveiled, Part 7: Dayrates and Lifelines of Offshore Drilling Companies, available at http://marketrealist.com/2016/02/understanding-demandside-offshore-drilling-industry (accessed 5 August 2017). 10  Goodridge, Offshore Drilling Unveiled, Part 6. 11   O L Anderson, “The Anatomy of an Oil and Gas Drilling Contract”, 25 (1990) Tulsa Law Journal 382 (hereinafter “Anderson, ‘Anatomy’”). 12  Goodridge, Offshore Drilling Unveiled, Part 6.

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to as the IADC equipment list.13 An additional concern, of equal importance, will be the drilling contractor’s role and responsibility in providing a full complement of crew, adequate consumables and many other ancillary tools and materials. Referring to para II-4.59, these requirements will also be specified in an exhibit – typically referred to as the “checklist”.14 When distilling commercial risk and competing concerns of the II-4.12 operator and contractor to the above fundamentals, it can be argued that a drilling contract is, in essence, no more complicated than a simple commodity contract. The drilling contractor is providing a commodity at a price and the operator is utilising a commodity and paying a price for that use. The intricacies of the commercial relationship are, of course, much more complex – as will be shown by looking in-depth at key clauses in Section 3. However, first principles are the foundation of any commercial relationship and for that reason, we will frequently refer to the fundamentals throughout this chapter when looking more closely at the contract, the contractual relationship and specific clauses. Operational relationship First principles are also the foundation of the operational relationship. II-4.13 One core principle for understanding this relationship is recognition of the drilling unit as a tool – albeit a complicated one that is utilised by the operator for the primary purpose of drilling a hole to depth, and also as a platform for other drilling operations relating to the construction of the well. It is a common misconception that the drilling contractor will perform the totality of drilling operations. In fact, the dayrate drilling contract is only one of many contracts II-4.14 held by the operator for the purpose of conducting drilling operations and constructing a well. A wide variety of tangibles and consumables will form part of the well construction, including drill pipe, conductor pipe, casing, cement, circulation and pressure control fluids, drill collars and many components comprising the bottomhole assembly. Also, a vast number of downhole tools, equipment and services will be used for the drilling process – including tools to measure and log while drilling,15 centralisers to keep the casing stable

  See www.iadc.org/contracts-committee/resources (accessed 5 April 2017).  See IADC, Drilling Contract, Appendix D, available for download from the IADC’s website at https://iadc.ebiz.uapps.net/personifyebusiness/SearchResults/tabid/38/Default. aspx?Search=drilling+contract (accessed 10 September 2017). 15   Logging while drilling (LWD) is a technique of conveying well logging tools into the well borehole as part of the bottom-hole assembly to measure properties of the formation. LWD tools work with a measurement while drilling (MWD) system which transmits “real 13 14

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and secure, and fishing tools and services to recover stuck pipe and any other items of equipment and material lost in the hole.16 II-4.15 An operator’s scope of work for a project will typically involve drilling, completing, suspending, testing, plugging and/or abandoning one or more wells for the purposes of exploration, appraisal and/or development. In the current UKCS environment, a scope of work may also involve the decommissioning of one or more wells.17 Defining the scope of work, and managing, controlling and supervising all the operations required to complete the scope of work will be the core responsibility of the operator. The operator will typically have a drilling department to design the well, create a technical programme for drilling the well, and control and manage its engineering and construction. This is the conventional model of the operational relationship. There are, however, exceptions to this rule. II-4.16 A conventional model may not, for example, be aligned with the technical capability and risk profile of a small operator that may not have a drilling department to design the well and actively manage the drilling programme. It might be that technical capability is not the only concern – a small operator may also have insufficient financial capacity to assume certain types of operational risk relating to the well’s design and construction. In view of these constraints, alternative contractual models have been developed and utilised with success as a means of transferring some of the typical operator risks and responsibilities to a contractor, provided the contractor has the technical capability and/or financial capacity to assume such risks and responsibilities. Turnkey model II-4.17 One alternative model is turnkey drilling – a contract structure under which the operator will outsource the design of the well and the development of the drilling programme to a third-party turnkey drilling contractor. The drilling programme will be agreed with the operator; however it will be managed, co-ordinated and carried out by the turnkey contractor. By acting in the capacity of a “quasi-operator” for the limited purpose of well operations, the turnkey contractor will have certain duty holder responsibilities for obtaining permits and authorisations from governmental authorities time-data” to surface via a drilling mud pulser or other improved techniques while the LWD tools are still in the borehole. Complete measurement results, called “memory data”, will be downloaded from LWD tools after they are pulled out of the hole. 16  D Sharp, Upstream and Offshore Energy Insurance (2009) (hereinafter “Sharp, Upstream and Offshore Energy Insurance”), pp 53–64. 17   See www.ogauthority.co.uk/decommissioning/wells (accessed 24 April 2017).

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in respect of the particular scope of work.18 The turnkey contractor will also assume responsibility for negotiating and agreeing the dayrate drilling contract and will, in most circumstances, enter into such a contract with the owner/operator of the drilling unit. When negotiating the turnkey drilling contract, the parties will II-4.18 agree terms and conditions that identify and transfer to the turnkey contractor certain commercial and technical risks relating to the execution of the drilling programme and construction of the well.19 The transfer of such risks will largely be achieved by the turnkey contractor committing, in principle, to earn a fixed, lump-sum turnkey price for drilling a hole and constructing the well, pursuant to the drilling programme, to a depth and within the co-ordinates of a pre-determined geological target. If the depth is not reached and the geological target is not achieved due to technical risks within the scope of the drilling programme, the turnkey contractor will not earn the turnkey price, or any part thereof. For example, an indicative time and depth curve for drilling a well II-4.19 to a certain depth and target within a geological area in the central North Sea may be determined to be 50 days by reference to historical data for prior wells drilled in the same area or in similar geological conditions. A fixed, lump-sum turnkey price agreed by the turnkey contractor and operator would be based, in part, on this indicative data. If the turnkey contractor encounters risk within the scope of the drilling programme and such risk should result in 150 days of drilling operations and drilling unit utilisation (ie triple the indicative time and depth curve), the turnkey contractor’s compensation will not, in such circumstances, be more than the fixed price. By committing to the fixed price, the turnkey contractor has assumed all commercial exposure for additional costs and dayrate attributable to the 100 days of drilling operations and drilling unit utilisation in excess of the planned period of 50 days.20 There may, however, be certain types of technical risk beyond the II-4.20 scope of the drilling programme which the turnkey contractor will not be willing to assume, such as mud weight in excess of a threshold specified in the drilling programme, encountering salt, encountering basement rock, or otherwise acting on the operator’s direction to deviate from the agreed drilling programme. If any such specified risk not assumed by the turnkey contractor should arise, the parties will typically agree terms whereby the turnkey contractor will be

18   See www.ogauthority.co.uk/exploration-production/petroleum-operations-notices (accessed 25 April 2017). 19  Sharp, Upstream and Offshore Energy Insurance, p 70 and p 119. 20   Anderson, “Anatomy”, pp 378–380.

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paid a portion of the turnkey price for that part of the agreed scope of work successfully performed prior to occurrence of the event.21 Project management model II-4.21 Another alternative model is project management – a contract structure under which the operator will, again, outsource to a contractor certain functions relating to design of the well, developing the drilling programme, and managing and supervising the drilling operations.22 The project management contractor will assume substantially less responsibility and risk under this model. The operator will typically continue to act as the principal party to the dayrate drilling contract. It will also continue to have direct involvement in decisions relating to the management of drilling operations, oversight of operations of the dayrate drilling contractor, execution of the drilling programme, and construction of the well. Having assumed less responsibility and risk under the project management model, it logically follows that the project management contractor will have much less opportunity for financial reward.23 Conventional model II-4.22 A more detailed description of alternative models is beyond the scope of this chapter – however the discussion above provides context for clarifying the more limited role and responsibilities of the dayrate drilling contractor under a conventional drilling contract model.24 The drilling contractor’s fundamental role and risk under the conventional dayrate drilling contract is providing a drilling unit and a complement of crew on the unit which the operator will utilise as a primary tool for drilling the well. The drilling contractor does not design the well, plan the well, engineer and manage the drilling programme, or control the method and means for its construction. II-4.23 From the perspective of its limited role and responsibilities, the drilling contractor will strive to restrict the boundaries of risk under the dayrate drilling contract in a way that minimises or excludes its exposure to design, construction and cost of the well. The drilling contractor will contend that its lesser role should be balanced with less responsibility and risk in relation to what happens in the downhole environment. Conversely, the operator will contend that

 See http://cwilliamsmallinglaw.com/global_pictures/2g_Drilling_Contracts.pdf (accessed 20 April 2017). 22   M J Kaiser and B F Snyder, The Offshore Drilling Industry and Rig Construction in the Gulf of Mexico (2013) (hereinafter “Kaiser and Snyder”), p 70. 23  See http://cwilliamsmallinglaw.com/global_pictures/2g_Drilling_Contracts.pdf (accessed 20 April 2017). 24   Kaiser and Snyder, p 70. 21

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although the contractor may, on the one hand, be remote from the management and control of downhole decisions, it will, on the other hand, be directly involved in managing and controlling day-to-day decisions on the drilling unit. For that reason, the operator will strive to create a contractual framework under which the drilling contractor will, in principle, be held accountable for those decisions, as well as, in most circumstances, the functionality and performance of the drilling unit and other “critical-path” items of equipment. These competing concerns of the operator and contractor are II-4.24 a thread of tension that will run throughout the dayrate drilling contract. When dissecting discrete clauses from para II-4.49 onwards, we will refer to this thread. However, before turning our attention to particular clauses of the contract, we will complete the commercial and operational context by providing an overview of the nature of the drilling unit. NATURE OF THE DRILLING UNIT There are three main types of drilling unit – jack-up, semi-submersible II-4.25 and drillship. Each has the common characteristic of being mobile, but there are many differences in design, specification and capability. In the following three parts of this section, we summarise the key features and material differences of the three types. More detailed characteristics are beyond the scope of this chapter; however, where additional information is relevant to a particular provision of the contract we have provided it from para II-4.49 onwards.25 At the time of writing, there are more than 900 mobile offshore II-4.26 drilling units of all types in the world, with more than 300 being floaters (ie approximately 200 semi-submersibles and 100 drillships).26 This chapter does not cover fixed platform rigs or tender assist drilling units. Of the three classes, jack-ups are the most prevalent, and widely recognised as the work horses of the industry in the benign shallow water basins of the Middle East, the Far East, the Mediterranean, West Africa and the Gulf of Mexico.27 Higher costs and risks distinguish floaters from jack-ups. For II-4.27 example, construction costs for an ultra-deepwater floater will average $700–$750 million, with dayrates in peak market conditions approaching $850,000/day and total operating rate exceeding $1.5 million/day – ie including all support services and expendable items. By contrast, the capital cost for constructing a standard specification jack-up may be one third of the floater average. Likewise, prevailing  Sharp, Upstream and Offshore Energy Insurance, pp 45–51.   Ibid, p 47. 27   Ibid, p 45. 25 26

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dayrates, as well as total operating rates, will typically be as low as one third of floater rates. II-4.28 New build units of all three classes will be constructed to a standard that is certified by classification societies, regulated by industry organisations and registered in country (as flag state status) in the same way as any other commercial vessel.28 Post-construction, an operational unit will also be subject to ongoing requirements and standards for maintaining a current, approved classification society and flag state status. The process for continuing compliance in this regard is not a mere formality; it is a rigorous and costly exercise including “walk around” inspections each year, surveys extending to underwater areas in lieu of drydocking (UWILD) each two-anda-half-year period, and a “special periodic survey” (SPS) every five years, which requires drydock.29 The regulatory process is also recognised externally by underwriters as a pre-condition for marine insurance, by banks as a requirement for finance, and by operators as a condition of contract. Jack-up II-4.29 Of the many technical differences between the jack-up and the other two classes considered here, the most material are that (1) the jack-up is sea-bottom supported whilst operating on the well location; (2) it only floats when being towed between drilling locations; and (3) it is not self-propelled. The key features of a jack-up can be summarised as follows. II-4.30 It has three or four legs, which maintain contact with the seabed when fully jacked up over the well location. This provides a fixed and stable position for performing drilling operations. Though not self-propelled, the hull does float and, when towed and positioned over the well location, the legs are lowered to the seabed by means of hydraulic jacks in order to raise the hull above the surface of the sea. The jacking process is weather sensitive because excessive pitching and rolling of the hull can cause the lowered legs to incur significant structural damage by striking the seabed. II-4.31 When the unit is fully jacked, this anchors the drilling unit and holds the drilling deck in an elevated position above the water line. The distance between the surface of the water and the bottom of the hull is known as the “air gap”. The amount of air gap is a critical concern for operational integrity and asset safety. It must be enough 28  H Esmaeili, The Legal Regime of Offshore Oil Rigs in International Law (2001) (hereinafter “Esmaeili, Legal Regime of Offshore Oil Rigs”), p 21. 29  See https://rules.dnvgl.com/docs/pdf/DNV/codes/docs/2011-10/Oss-101.pdf (accessed 20 April 2017).

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to ensure that the largest wave crest cannot hit the hull and destabilise the unit.30 Jack-ups are typically designed to operate in shallow water, with II-4.32 standard water depth parameters of 25–300 feet. Higher specification units of the “ultra-harsh environment” variety which are more prevalent in the North Sea, have the capability to drill in water depths of 500 feet or more.31 A jack-up unit will have lower mobilisation costs, operating costs and dayrate. Compared to a drillship or semi-submersible, it can also be more readily updated, enhanced or renovated, with modifications being as extensive as leg strengthening and lengthening, adding pre-load tanks and improving environmental capabilities.32 There are two basic types of jack-ups – the independent-leg type II-4.33 typically of three legs and lattice construction, and the mat type with legs attached to a very large mat resting on the seabed.33 For independent-leg units, “pre-loading” is required to drive the legs into the ocean bottom before the hull is completely jacked out of the water. Several “pre-load” sequences are usually carried out where seawater is pumped into the pre-load tanks which adds the required weight to drive the legs into the seabed. During this process, weather risk will be a continuing concern until the unit is fully stabilised on location. Likewise, there will be a continuing concern of punchthrough risk which involves one leg penetrating the hard crust of the seabed causing the other legs to bend and the unit to list, potentially toppling.34 Recognising the range of operational risks attendant to pinning II-4.34 the jack-up on location, the parties to the dayrate drilling contract will attempt to tailor provisions that identify and manage these risks, as well as allocate commercial exposure. All of these issues and concerns are addressed in detail from para II-4.49 onwards. Semi-submersible As mentioned in the introduction, semi-submersible drilling units II-4.35 and drillships comprise a general class of vessels characterised as floaters. Within this general class, floaters are differentiated by water

 Sharp, Upstream and Offshore Energy Insurance, p 47.   Ibid, p 45. 32  See www.petrocenter.com/wd/offshore%20drilling%20rig.htm (accessed 20 April 2017). 33  Sharp, Upstream and Offshore Energy Insurance, p 47. 34  S Goodridge, Offshore Drilling Unveiled, Part 4 “Getting to Know the Types and Characteristics of Offshore Rigs”, available at http://marketrealist.com/2016/02/understanding-demand-side-offshore-drilling-industry/ (accessed 5 August 2017). 30 31

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depth capability as (1) shallow water units at less than 2,000 feet water depth; (2) intermediate, or mid-water, units at 2,000–7,500 feet; and (3) ultra-deepwater units at more than 7,500 feet.35 A semi-submersible (or “semi”) is the most common choice of floating unit in depths of over 300 feet up to several thousand feet.36 It is more expensive than a jack-up unit, but more technically capable, with higher operating costs and a higher day rate. By comparison to a jack-up, the semi (and indeed the drillship) possesses two unique characteristics: (1) when on location, it is fixed over the well by a spread-mooring system or a dynamic positioning system (“stationkeeping”); and (2) when operational, it drills through a pipe (marine riser) connected to a blow-out preventer (BOP) stack that is latched onto a wellhead at the seafloor. 37 For jack-up drilling, the BOP is located at the surface approximately 60 feet below the drill floor.38 When moored on location, the semi will maintain its position through a number of anchors (often 8–12) spanning a radius of one mile or more from the wellhead. When dynamically positioned on location, the semi will use satellite signals and a number of thrusters to maintain a particular set of co-ordinates, without making any contact with the seabed. A semi can work in water depths ranging from less than 100 feet (provided the hull is not at risk of making contact with the BOP when moving off location) to ultra-deepwater, provided it has stationkeeping capability and is equipped with the requisite technical specifications and design features. Similar to a jack-up, air gap is a key design consideration when rating for environmental conditions. The design phase will include hull motion analysis to ensure that waves cannot come into contact with the upper deck. In addition, heave, roll, pitch, sway, yaw and surge will be analysed in order to determine the upper limits of motion in which crews and equipment can operate. The deck of a semi is commonly shaped like a rectangle but can also take the form of a cruciform, pentagon or triangle. The hull is configured of either parallel rectangular pontoons or individual pontoons or caissons at the foot of each stabilising column. The hull is ballasted down by the intake of seawater to partially submerge the unit. The stabilising columns are fixed to the hull and support the deck.39   Kaiser and Snyder, p 15.  Sharp, Upstream and Offshore Energy Insurance, p 4. 37   Ibid, p 47. 38  See www.ifp-school.com/upload/docs/application/pdf/2015-02/7_blowout_preventer_ stack.pdf (accessed 4 April 2017). 39  Esmaeili, Legal Regime of Offshore Oil Rigs, pp 13–14. 35 36

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Semis are commonly referred to as a particular “generation”. II-4.40 The factors for determining the generation of a unit are date of construction (or significant upgrade date) and maximum water depth capability.40

Drillship The drillship is the class of unit most recently introduced to the II-4.41 mobile offshore drilling market. A new frontier has emerged in the ultra-deepwater environment – in particular, the basins far offshore in West Africa, Brazil and the Gulf of Mexico. The environmental, technical and operational challenges of operating in these conditions have literally positioned operators, and the whole of the supply chain, at the precipice of what is possible with current technology. These conditions have demanded the design and construction of the most technologically advanced, operationally sophisticated, capitalintensive and commercially expensive drilling units. The usual water depth in which these units can operate is up to 7,500 feet, but some units are capable of drilling in over 12,000 feet of water.41 With a daily operating cost in excess of $1 million per day, it II-4.42 is not uncommon for the cost of a single well to be $100 million and, in exceptional circumstances, exceed $200 million. Assuming a discovery in deepwater, the development cost can approach tens of billions of dollars, with a 10–15 year horizon for production. This scale of capital commitment has historically narrowed the market to major oil companies, though some substantial independents have operated in this environment.42 The extraordinary risks and challenges of conducting operations II-4.43 in the deepwater sector are too many to enumerate in this summary, but the most salient are: (1) the met-ocean environment (ie winds, waves and currents, which affect the motion and stability of the unit); (2) weather, including hurricanes and severe storms in the Gulf of Mexico and Arctic conditions in northern provinces; (3) abnormal pressures imposed by the weight of seawater in a depth of 10,000-plus feet; and (4) the stretched and strained supply lines that are critical for support, care and maintenance of a drilling unit in the most remote and extreme parts of the world.43 It is therefore worthwhile to highlight in this chapter the key features that render a deepwater vessel uniquely capable of confronting these challenges.   See www.infield.com/rigs/rig-glossary (accessed 4 April 2017).  Goodridge, Offshore Drilling Unveiled, Part 4. 42  See www.offshorecenter.dk/log/bibliotek/E6-37-06-04%5B1%5D.pdf (accessed 20 April 2017). 43  Goodridge, Offshore Drilling Unveiled, Part 4. 40 41

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II-4.44 A significant feature that differentiates the drillship from the semi is superior deck-loading capacity.44 Where resupply of materials and equipment is difficult, the capacity to carry and the deck space to accommodate such items will be vital to the continuity and cost efficiency of operations. Sophisticated and robust hoisting equipment and capabilities will also be required for much larger equipment on board. Even in benign weather, supplying the floater at a remote location far offshore will be challenged by lengthy boat and helicopter transit times. Adverse weather will further complicate water and air transportation, in particular the loading and offloading of supply boats in rough seas.45 More sophisticated technology, greater environmental demands, II-4.45 increased operational challenges and larger equipment to operate and maintain will inevitably require more crew. Depending on the operation, a drillship may have over 200 crew and personnel on board. In addition to the crew, third-party service personnel may remain aboard the vessel for long periods. As a consequence, newer drillships will have very large accommodation facilities, with over 250 bunks in predominantly two-person rooms.46 II-4.46 In order to maximise operational efficiency at a very high dayrate, most drillships have dual-activity capability. This means there are two derricks and drilling systems on one hull by which the drillship can run two risers and two BOP systems, with one drilling and the other completing a well. Dual-activity also reduces total rig time if one derrick can be used to run casing, for example, and the other to drill. When dayrate for the unit is likely to comprise the most significant component of capital spend on a project, reducing rig time will be of paramount importance. II-4.47 Newer units will also be “D3” rated, in that they have total triple redundancy. In other words, if one component of the system should fail, another comes online immediately; if another component fails, the third component comes online. By involving all system components, this arrangement will increase the reliability of the total station-keeping capability. A dynamically-positioned vessel will also have the unique feature of sailing under its own power to the well location, thereby avoiding the cost of tow and anchor handling vessels.47 The same thruster capability for moving the unit is further utilised to keep the vessel stationed on the well location. All drillships built in the current millennium are equipped with dynamic-position stationkeeping systems enabling the vessel to rotate its bow into  Esmaeili, Legal Regime of Offshore Oil Rigs, p 13.   Ibid, p 13. 46  Goodridge, Offshore Drilling Unveiled, Part 4. 47  Sharp, Upstream and Offshore Energy Insurance, p 48. 44 45

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changing weather, and thereby avoid the vagaries of vessel motion that have historically contributed to high operational downtime for moored drillships.48 We will revisit some of the key features mentioned in this section II-4.48 when looking at particular clauses in the following paragraphs – not from the perspective of an overview, but detailed insight into each clause, how it functions within the whole of the contract, how it is relevant to the drilling unit, how it interrelates with other provisions of the contract and how it is also relevant to the commercial/operational relationship. NATURE OF THE CONTRACT Background As highlighted in para II-4.21, the operator will retain ongoing II-4.49 oversight and ultimate control of the design, engineering and construction of the well. In this capacity, the operator will also control the process of selecting a preferred contractor and drilling unit, subject to any relevant restrictions of a joint operating agreement (if applicable). When commencing the process of selecting a drilling unit, the operator will commit, in the first instance, to either canvass the market at large through an invitation to tender or sole source from a preferred provider. If an invitation to tender is the chosen path to the market, it will typically involve the following steps: (a) A pre-qualification (or availability enquiry) issued by the operator for identifying one or more contractors from the market with drilling unit capacity, capability, and technical specifications for performing the relevant scope of work. (b) A formal invitation to tender (ITT) issued by the operator inviting responses from those contractors with confirmed capacity, capability and interest in the opportunity. The ITT will typically comprise: a pro-forma tender acknowledgement; a scope of work; technical specifications; draft contract; health and safety policies and procedures (often including a questionnaire); ethics and compliance questionnaire; confidentiality provisions; and details of the deadline for proposal. (c) Upon receipt of the ITT, each drilling contractor will submit a response with qualifications to the draft contract, comments on the scope of work and technical specifications (as appropriate), completed questionnaires and proposed prices.

 Esmaeili, Legal Regime of Offshore Oil Rigs, p 13.

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(d) The operator will thereafter evaluate the technical and commercial merit of each response and either select one or shortlist a number of contractors for further negotiation/ clarification. II-4.50 Whether an ITT is issued or the drilling unit is sole sourced, the operator will, typically, take the initiative in co-ordinating and controlling the process of negotiation. The operator will have, at the outset, the opportunity to propose a draft contract and such draft, together with any qualifications proposed by the drilling contractor, will form the basis of negotiation. When considering the content of the draft, the operator will be aware of the most significant areas of risk. It will also be aware of the importance of structure; having a clear and comprehensive framework for addressing all elements of exposure.49 Structure II-4.51 A typical drilling contract will, as a total structure, constitute the sum of many parts; therefore, it is critical to understand the meaning and purpose of each of the various provisions. There is detailed narrative in the following paragraphs explaining the fundamental purpose of each clause; however, it is equally important to understand the relevance of each clause within the structure of the entirety of the agreement. It is also critical to understand the interplay of various clauses within the structure. From a broad perspective, a dayrate drilling contract can be recognised as the composite of four distinct types of clauses – “commercial”; “contractual”; “operational”; and “legal/risk”. II-4.52 Referring, for example, to LOGIC General Conditions of Contract for Mobile Offshore Drilling Units (hereinafter “LOGIC MODU 97”), certain provisions can be recognised as uniquely “operational” (ie Clause 4 “Contractor’s General Obligations”, Clause 5 “Offshore Transportation”, and Clause 10 “Ingress and Egress At Location”, as well as separate Sections for “Scope of Work”, “Drilling Unit Specification” and “Health, Safety and Environment”).50 Other provisions sit squarely in the class of “legal/risk” (such as Clause 17 “Law and Regulations”, Clause 18 “Indemnities”, Clause 19 “Insurance”, Clause 20 “Consequential Loss”, and Clause 25 “Business Ethics”).51 Equally, some clauses are “commercial” (ie Clause 13 “Terms of Payment”, Clause 14 “Taxes and Exemption

 See http://cwilliamsmallinglaw.com/global_pictures/2g_Drilling_Contracts.pdf (accessed 20 April 2017). 50   See eg LOGIC, “Mobile Drilling Rigs”, cll 4, 5 and 10. 51   See eg LOGIC, “Mobile Drilling Rigs”, cll 17, 18, 19, 20 and 25. 49

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Certificates” and Section III “Remuneration”)52, while others are distinctly “contractual” by serving the particular function of managing the relationship, as well as defining it (ie “Section I Form of Agreement”, Clause 1 “Definitions”, Clause 9 “Assignment and Subcontracting”, and Clause 11 “Variations”).53 A logical order does flow from putting clauses in particular classes. The process also places a sharp focus on the fundamental purpose of each clause, while also showing how all of the clauses fit together coherently to form the entire contractual relationship. This provides a valuable context; however, it must be acknowledged that there are inherent risks in creating labels, as well as looking at any clause in isolation. Each clause must be understood in terms of the whole of the contract. Referring to LOGIC MODU 97, for example, there may be a breach of the operator’s obligation under Clause 10 “Ingress and Egress at Location” to provide “information in [its] possession concerning underwater terrain and obstructions to assist the Contractor in the safe movement of the Drilling Unit”.54 The operational issues arising from a breach of this clause are apparent. As explained in paras II-4.25 to II-4.48, a mobile installation is dynamic and navigable; therefore the integrity of the whole scope of work is predicated on the well site being free of any undisclosed conditions on the seabed that could constitute a hazard to moving on location. However, operational concerns are not the only issue.55 If, for example, the drilling unit is severely damaged by colliding with undisclosed infrastructure on the sea bed in proximity of the well location, the operator’s and contractor’s indemnities, as well as the insurance obligations under Clauses 18 and 19 of MODU 97 would be relevant. Likewise, if the drilling unit is so severely damaged that it is not functional, Section III “Remuneration” will be relevant for determining what, if any, dayrate will apply during such downtime and for how long. If the downtime period subsists for an exceptionally long period, there may be other implications in respect of Clause 22 “Termination”. Moreover, if the drilling unit causes damage to third-party infrastructure and there is a loss of production and discharge of pollution due to such damage, the operator’s indemnity obligations under Clause 18 for damage to third-party infrastructure and pollution may be relevant. We will look at Clause 10 “Ingress and Egress at Location” in much more detail in para II-4.111; however we have mentioned

II-4.53

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  See eg LOGIC, “Mobile Drilling Rigs”, cll 13 and 14, and Section III.   See eg LOGIC, “Mobile Drilling Rigs”, cll 1, 9 and 11. 54   See eg LOGIC, “Mobile Drilling Rigs”, cl 10. 55   Anderson, “Anatomy”. 52 53

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it here, as background, to illustrate the conceptual importance of not only understanding the primary purpose of a clause but also recognising its interplay with other clauses and its relevance in the context of the entire contract. In the following paragraphs, II-4.57 to II-4.104, we will apply the same three-fold approach to all clauses at the core of a typical dayrate drilling contract – casting a sharp focus on the primary purpose of a clause, looking at its correlation with others and considering it in the context of the whole of the agreement. We start with the “Form of Agreement” of LOGIC MODU 97. Form of Agreement II-4.57 Obvious issues are sometimes the most frequently overlooked and, in the case of any commercial agreement, it is indeed obvious that the parties should consider, in the first instance, what is included in the contract, and what is not. It is always in the interest of the parties to make explicit what is within the boundaries of the commercial relationship, and clearly delineate the four corners of the contract. This exercise is not only best practice for a dayrate drilling contract, it is a fundamental issue. If not carefully considered in the context of the entirety of the contractual relationship, the consequences can be significant. The risks are best understood by looking at specimen language. II-4.58 Turning to LOGIC MODU 97, the sample Form of Agreement has a separate Clause 2 for the singular purpose of setting forth explicitly those particular sections and clauses that “shall be deemed to form and be read and construed as part of the CONTRACT”. This language is coupled with Clause 26.6 of the General Conditions which provides that the “CONTRACT constitutes the entire agreement between the parties … and supersedes all prior negotiations, representations or agreements related to the CONTRACT”.56 II-4.59 When considering all of the parts of a dayrate drilling contract, on balance, the appendices and exhibits at the back of the agreement will often have the greatest commercial and operational significance. Exhibits, such as the remuneration/rates section, the checklist of responsibilities for provision of equipment, materials and personnel, and the drilling unit specification, are always at the back of the document.57 It is therefore critical to not only clearly identify what is included in the agreement, but also include language clarifying the order of precedence in the event of conflict or ambiguity

  See eg LOGIC, “Mobile Drilling Rigs”, Form of Agreement cl 2.   See IADC, Drilling Contract, Appendices A, B C, and D.

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between separate parts. This issue is addressed effectively in LOGIC MODU 97 where language appears at the end of Clause 2, Form of Agreement providing that “in the event of ambiguity or contradiction between Sections [precedence shall be given] in the order listed, with the exception that the Special Conditions of Contract shall take precedence over the General Conditions of Contract”.58 The importance of specifying what is in the agreement is seemingly II-4.60 self-evident, but the obvious should not be assumed to be properly addressed. Where key provisions of a dayrate drilling contract run throughout the agreement and where the most commercially and operationally sensitive provisions are at the back, it is always relevant to consider the interrelationship among all parts of the agreement and, in particular, what language should take precedence. If not properly considered, it may be an oversight of considerable consequence. Another clause of consequence at the beginning of the contract is the “Definitions” section. Definitions It is common for a commercial agreement to create a separate II-4.61 clause for the purpose of establishing defined terms where such terms may be required throughout the agreement and, to the extent multiple definitions are created, to have all of them located in a single part of the agreement. In this regard, oil and gas contracts are no exception. Referring to the LOGIC model contracts, a separate Clause 1 “Definitions” is a standard feature across the entire suite of documents. It is beyond the scope of this chapter to consider generally the best practice for creating a definitions clause, but it is relevant to highlight those definitions that are unique to a typical dayrate drilling contract. In the following paragraphs we have offered this insight – by reference, in the first instance, to certain definitions of LOGIC MODU 97, with the understanding that any reference to the LOGIC definition will apply equally to any similar definition in a typical dayrate drilling contract. Definition of “Contractor Group” As explained in more detail in para II-6.52, it is common for oil and II-4.62 gas service contracts to have definitions of “Company Group” and “Contractor Group” for the purpose of identifying members of the respective Groups in order to allocate risk under a corresponding indemnity regime. A detailed analysis of indemnities under a standard oil and gas service contract is already provided in Chapter II-6;

  See eg LOGIC, “Mobile Drilling Rigs”, Form of Agreement cl 2.

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however, we have commented in the latter part of this chapter on those indemnity provisions particular to a dayrate drilling contract and, in this paragraph, we also highlight two notable differences between the definition of “Contractor Group” in a dayrate drilling contract and that in other standard service agreements. 59 II-4.63 First, referring to the LOGIC MODU 97 definition of “Contractor Group”, there is a specific reference to the Drilling Unit (as defined).60 This reference is made because it is recognised that an indemnity claim, for example, or any other relevant claim could be made “in rem” against the Drilling Unit, in its own right. An action in rem would not be a claim against the owner of the property, it would be a claim made against the Drilling Unit itself. Recognising the potential for this type of claim to be made, in particular under Admiralty jurisdiction, it will always be best practice when drafting a dayrate drilling contract to make specific reference to the Drilling Unit as a separate member of the relevant Group.61 Another example of a claim that may be made against the Drilling Unit is one for monies owed. The claim is made against the property of the debtor rather than against the debtor.62 II-4.64 Second, the definition of “Contractor Group” in MODU 97 also includes a specific reference to “legal and beneficial owners of the Drilling Unit”. Why? Given the scale of cost in constructing a drilling unit, as described in para II-4.06, the owner of the drilling unit will typically have finance arrangements with external lenders. This type of entity will not be a principal party to the contract and it will not be one of the other members typically included in the definition of Contractor Group, such as an affiliate. In order to recognise the rights of this type of entity, it is best practice for the definition of “Contractor Group” to make specific reference to the “legal and beneficial owners”.63 Definition of “Drilling Unit” II-4.65 As explained in paras II-4.29 to II-4.48, the design characteristics of a drilling unit are unique, the equipment installed on it is very sophisticated, and the functional specifications and capabilities of the whole of the mobile installation will be particular to the scope of work and operating environment. Given all of these variables, the dayrate drilling contractor will typically require a definition of “Drilling Unit” which identifies a single drilling unit by name and   See para II-4.137 onwards.   See eg LOGIC, “Mobile Drilling Rigs”, cl 1.4. 61   M Summerskill, Oil Rigs: Law and Insurance (1979), p 18. 62   C Hill, Maritime Law (5th edn, 1998), pp 120–121. 63   See eg LOGIC, Mobile Drilling Rigs, cl 1.4. 59 60

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makes reference to a separate exhibit setting forth all of the design characteristics, capabilities and specifications. A dayrate drilling contractor will, in most circumstances, have II-4.65 limited capacity to offer more than one drilling unit as fit for the particular requirements of an operator’s drilling programme. Given the mobile nature of drilling units, even if multiple units from a fleet may have the right design, specification and functional capabilities, it would be common for one or more to be in the wrong location and, in that event, the cost of moving to the right location may be prohibitive. There may also be particular requirements of the regulatory regime in a given location that impose more onerous design standards and specifications than would otherwise be required for performing the same scope of work in another part of the world. In that event, it may be cost prohibitive for the owner to upgrade a drilling unit from its fleet to become compliant with local requirements and offer rates competitive against units of a similar specification and capability already in situ and operational in the relevant jurisdiction. Also, from past experience, an operator may have a preference for utilising a particular type, design and quality of drilling unit for a specific scope of work in a given geography and/ or geology. All of the above factors, and others not mentioned within the II-4.67 limited scope of this paragraph, will invariably lead the parties to identify a particular drilling unit for any one contract in respect of a particular scope of work. Referring to LOGIC MODU 97, Appendix 1.1 to Section I – Form of Agreement, there is particular language in Section II Clause 1.8 for this purpose – ie “The DRILLING UNIT shall be the “__________________”. Likewise, the sample Form of Agreement makes reference to Section IV(b) Drilling Unit Specification and, as explained in para II-4.59 of this chapter, this separate exhibit will always comprise a unique and comprehensive schedule of details in a standard IADC format that is created for each drilling unit recognised in the industry as being of a particular class, valid certification and operational capability.64 Definition of “Operating Area” or “Worksite” In the same way that a dayrate drilling contract will be tailored to II-4.68 identify a particular drilling unit for a specific scope of work, the drilling contractor will also typically require that a contract specify a clearly defined geographic area within which the operator will only be permitted, subject to certain conditions, to utilise the drilling unit. As mentioned in para II-4.05 of this chapter, the owner of a drilling

  See www.iadc.org/contracts-committee/resources (accessed 25 April 2017).

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unit will recognise a particular cost structure for a unit and such structure will be specific to any particular jurisdiction in which the unit is operational. For example, the operational cost structure for a particular unit when utilised in the UKCS will not be same as when utilised in Norway, or when deployed in Nigeria. The cost structure in any jurisdiction will be dependent, in large part, on the particular regulatory regime, tax requirements and customs rules, as well as other fiscal requirements unique to the locale. From a commercial perspective, it is therefore critical for a dayrate drilling contractor to have a definition of “Operating Area” or “Worksite” confined to a single jurisdiction.65 II-4.69 If an operator does require the latitude and forward planning flexibility, over a long-term contract, to move the drilling unit to an alternative jurisdiction, it will typically be in the commercial interest of the dayrate drilling contractor to only accommodate this type of move under the terms of a change of locale clause. It is beyond the scope of this chapter to provide a detailed consideration of this particular type of clause, as well as escalation of rate provisions that a dayrate drilling contractor may propose to incorporate to provide protection for an unanticipated change of law, change of interpretation and enforcement of existing law, and inflation of operating costs over the extended period of a long-term contract. However, it will most certainly be in the commercial interest of the dayrate drilling contractor to consider these contingencies. As further explained in paras II-4.111 to II-4.120, there may also be warranties from the drilling unit owner’s portfolio of insurance that restrict the areas in which a vessel may operate depending on the type of coverage and the perceived levels of risk in respect of war, piracy or extreme environmental conditions – ie such as the Arctic environment for which a relevant unit may not have requisite design, specifications and operational capabilities.66 If a drilling contractor is domiciled in a particular jurisdiction (such as the United States), there may likewise be certain trade restrictions imposed by applicable law, such as sanctions and export control regulations. II-4.70 Referring to LOGIC MODU 97, the definitions of “WORK” and “WORKSITE” from Section II(a), Clauses 1.15 and 1.16 respectively, make specific provision for operations only to be conducted in the UKCS. There is no corresponding change of locale clause in LOGIC MODU 97; however, Clause 11 does specify that “In the event that the CONTRACTOR or the COMPANY propose to vary

  See May, “Emerging Markets”.  See www.iims.org.uk/wp-content/uploads/2014/08/IIMS-HNC-HND-Unit22-Part-1-Version1. pdf (accessed 25 April 2017). 65 66

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the WORK or the terms hereof, such variation shall be subject to mutual agreement of the parties …” Definition of “well” In paras II-4.77 to II-4.110, we have provided detailed narrative highlighting key issues and concerns for stipulating when a dayrate drilling contract should begin, when it should end and how the period in between should be described. Where the duration of the contract is specified as a number of wells (instead of days), it will always be best practice to consider whether, and to what extent, a definition of “well” may be required. In paras II-4.104 to II-4.110, we have explained that a drilling contractor will require, in all circumstances where there is a follow-on contract in direct continuation of an existing one, to have clear visibility of when the existing contract will end. A definition of “well” (if properly drafted) will give the dayrate drilling contractor adequate comfort for horizon planning in respect of the next contract in order to avoid unpredictability, uncertainty and difficulties in managing the transition of the drilling unit from one operator to the next. With dayrate being the lifeblood of a drilling contractor’s business and continuity of dayrate being a commercial imperative, it will always be critical for a lawyer or in-house adviser to proactively consider relevant commercial issues and concerns and initiate internal discussion of best strategy for determining if a well definition is required and, if so, how it should be drafted. Likewise, having a definition of “well”, or not, is not only a question for the dayrate drilling contractor. From an operator’s perspective there may be a particular technical requirement to precisely define a “well”. For example, a drilling programme, as set forth in the relevant exhibit for the scope of work, may require particular language in a definition which will complement the technical components of well design and the operational requirements of well planning and execution. It is noteworthy that LOGIC MODU 97 does not have a definition of “well”. This provision has presumably been omitted from the model contract for all of the discretionary reasons stated above. In the absence of any language from LOGIC, we have provided specimen language below. Such language should not be treated as “fit for the purpose” in respect of any particular dayrate drilling contract, but only as an initial point of reference for bespoke drafting. Specimen Definition: “‘Well’ means a single hole drilled to a predefined final spatial target to a single downhole location. Any remedial deviations or side-tracking of the hole shall be restricted to operations required to reach such predefined final spatial geological target.”

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II-4.76 Drilling the well is the critical operation for which the contract is being performed; however, the start of drilling is not the critical time when the contractual relationship should start. As explained in the following paragraphs, it should be much earlier. When does it start? II-4.77 Two key events are relevant for defining when the operator/contractor relationship begins. The first event is the “Effective Date” – the date and time recognised as the start of the contractual relationship (ie when all terms and conditions, otherwise unqualified and unconditional, are legally binding on the parties with full legal force and effect). The second event is the “Commencement Date” – the date and time recognised as the start of the commercial relationship (ie when all dayrates under the drilling contract are applicable). II-4.78 As already mentioned in II-4.05, the dayrate provisions are a primary, if not the paramount focus of the dayrate drilling contractor, as well as the operator. The dayrate drilling contractor’s critical commercial concern will always be a continuous and uninterrupted application of dayrate throughout the term. The drilling unit will not, however, be fully operational or drilling for a continuous and uninterrupted period during the term; and when it is not, the operator will have a countervailing commercial concern that the contract is drafted with sufficient sophistication to have a comprehensive rate regime which will provide for less rate to be paid in certain circumstances and, depending on the circumstance, specify clearly how much less should be paid. II-4.79 Later, in paras II-4.121 to II-4.136, we will look in detail at a typical dayrate regime and consider the different types of rates applicable in various circumstances; however, we have referred broadly to the concept here because the definitions of “Commencement Date” and “Effective Date” are so closely connected to it. Effective Date II-4.80 When specifying an “Effective Date” on which the dayrate drilling contract will be legally binding and enforceable between the parties, it will typically be designated as the date of last signature – which is the date and time when the contract would otherwise be recognised as binding under English law, as well as the governing law of most jurisdictions. The parties are at liberty under English law, and the law of most jurisdictions, to designate an earlier or later date as the “Effective Date”. II-4.81 An earlier date may be preferred by the dayrate drilling contractor if, for example, there is a dayrate escalation clause (ie as alluded to in para II-4.69) which provides for an increase in rates to occur on

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an anniversary date determined by reference to the “Effective Date”. In that event, it would be in the contractor’s commercial interest to have an “Effective Date” on the earlier date when a rate proposal had been made, as based on costs current at the time of the proposal, not when the contract was signed. If an inspection of the drilling unit is required to determine its II-4.82 “fitness for purpose” to perform the contract, the operator may contend that the “Effective Date” should not occur until this determination has been made. However, it would not be in the interest of either party to have an “Effective Date” after an inspection, provided such inspection would involve people and property of the respective parties and members of their respective Groups, including subcontractors, being on the drilling unit. Likewise, there may be modifications and/or upgrades to the drilling unit prior to the vessel being in a state of readiness to perform drilling operations. In either event, the indemnities and various other provisions of the dayrate drilling contract would be relevant, should be applicable, and, as such, should be legally binding from a date prior to any activities occurring either in preparation for, or in anticipation of, the drilling unit being utilised by the operator. For that reason, it is most common and generally recognised as best practice for the parties to have an “Effective Date” from the date and time of last signature of the contract. Commencement Date As explained above, the Commencement Date is typically recognised II-4.83 by the parties as the point and time when the rate regime, as more particularly described in paras II-4.121 to II-4.136 will first apply. Assuming rates will apply from the Commencement Date, the II-4.84 operator will have a critical commercial concern that operating rate or any other rate of compensation should not apply until the drilling unit has been inspected and confirmed as in a satisfactory condition to fully and effectively perform the scope of the work. The dayrate drilling contractor will have the countervailing commercial concern that dayrate should continuously apply without interruption between contracts and, if the drilling unit is not on contract to a prior operator, it should apply as soon as the drilling contractor has confirmed it is ready to mobilise to the first well location of the current operator. These divergent positions will have to be reconciled through negotiation, and a compromise position will be reflected in the details of drafting. In principle, the dayrate drilling contractor will contend that II-4.85 repair rate (ie zero rate, as we later describe in para II-4.130) will be specified in the rate regime as applicable in the event that the drilling unit is not in a satisfactory condition to perform the scope of work.

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The contractor will also point to the operator’s further protection in the form of termination rights (ie also, as more particularly described in the later paras II-4.90 to II-4.103). The dayrate drilling contractor will suggest that the operator should take comfort in having these provisions to mitigate its commercial risk; however, whether such comfort is adequate will be dependent on a number of other factors – in part, the bargaining position of the operator in the current market and, also, the operational history of the drilling unit (ie is it a “hot rig”, with a “hot crew” which has successfully and effectively conducted operations on behalf of a prior operator for an extended and continuous period; is it a “cold rig” which has been idle or “cold stacked” in a moored location for an extended period; or is it a new build being delivered from the shipyard). II-4.86 Referring to LOGIC MODU 97, there is pro forma language in Appendix 1.1 to Section I – Form of Agreement which provides, in relevant part, that “The COMMENCEMENT DATE … shall be the date when the DRILLING UNIT is ready, with the last anchor racked, to commence tight tow to the COMPANY’s first well location”. However, this language does beg the question: in whose opinion, determination and/or discretion will the DRILLING UNIT be recognised as ready? Perhaps this is not clearly addressed in the LOGIC language because it has been assumed that the absence of explicit wording in this regard will prompt the question, and ultimately lead the parties to negotiate additional language which will answer the question in a way which is commensurate to existing market conditions and reflective of the relative bargaining positions of the parties.67 II-4.87 The above recited language is only part of the pro forma definition of “Commencement Date” from LOGIC MODU 97. The remainder of the pro forma language provides that “The COMMENCEMENT DATE shall be between ______________ and ________________ (conditions applicable (see 22.1(f)).” This additional language contemplates that the operator may have certain time constraints for utilising the drilling unit to perform the relevant scope of work under the dayrate drilling contract and will, therefore, require a deadline for delivery. These constraints will not, in typical circumstances, be either arbitrary or self-imposed. For example, (1) an operator may have an obligation under an existing licence or concession to drill one or more wells by a deadline; or (2) there may be budgetary constraints recognised by the operator, in its own right, or imposed by a joint venture; or (3) the complexity of the whole of the project

  See eg LOGIC, “Mobile Drilling Rigs”, Appendix 1.1 to Section I – Form of Agreement, cl 5.

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being managed and controlled by the operator will involve a number of agreements in addition to the dayrate drilling contract with logistical demands and commitments, as well as related costs, and these demands may not permit the operator the latitude for delayed delivery of the drilling unit.68 It is noteworthy that the LOGIC MODU 97 language is not II-4.88 expressed as a “single date deadline” for delivery but as a “window” for delivery between two dates (eg a six-month window expressed as “a period between 1 January 2017 and 1 July 2017”). Providing a window is a more balanced position which recognises that the dayrate drilling contractor with a drilling unit on contract to an incumbent operator cannot anticipate and plan, to the precision of a single day, when the drilling programme under the prior contract will be completed and the drilling unit will be released. A deadline for delivery, whether expressed as a single date or II-4.89 a window, will typically provide that the remedy for the drilling contractor’s failure to meet the deadline will be the operator’s right, exercisable at its sole discretion, to terminate the contract. Where the LOGIC MODU 97 language, as recited above, makes reference to “(conditions applicable (see 22.1(f))”, the corresponding provision to which it refers is Clause 22 “Termination” of the LOGIC MODU 97 General Conditions.69 Given the severity of the commercial hardship to the dayrate drilling contractor as a consequence of an operator’s decision to terminate the contract on grounds of delivery, the contractor may argue that it should not suffer a termination event if the relevant delay in delivery is attributable to a cause beyond its control – eg a force majeure event. Again, all of these questions and concerns will have to be considered at some length in negotiation and specifically addressed in the details of drafting. There is, unfortunately, neither an industry standard position nor industry recognised standard language to offer a definitive answer to the question “When does it start?” When does it end? Natural expiry The same competing concerns and common thread of commercial II-4.90 tension described as relevant to “Commencement Date” will apply, in equal measure, to the concept of “Completion Date”. The dayrate drilling contractor will have both eyes on the horizon for forward planning to ensure a seamless transition to a follow-on contract

  Ibid, cl 5.   See eg LOGIC, “Mobile Drilling Rigs”, General Conditions, cl 22.

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with the next operator. Again, the paramount commercial concern will be maintaining continuity of dayrate. Assuming there is a follow-on contract, the countervailing concern of the operator will be protecting the commercial position that it will not be obliged in any circumstances to pay dayrate beyond the point and time when the dayrate drilling contractor has the first opportunity to earn compensation under the follow-on contract. II-4.91 Referring to LOGIC MODU 97, there is no pro-forma language as a point of reference for addressing these competing concerns. However, from a practical perspective, the dayrate drilling contractor and the incumbent operator will typically recognise that a balanced position will be achieved by drafting the “Completion Date” under the existing contract in precisely the same terms as the “Commencement Date” under the follow-on contract. For example, the next operator will typically require a “Commencement Date” under the follow-on contract at the point of the drilling unit reaching, at a minimum, the boundary of 500 metres from the location of the prior operator’s last well (ie recognised in the UKCS as the safety zone).70 The prior operator will typically be agreeable to that being the same point at which the “Completion Date” under the existing contract will occur, provided that the drilling unit has been accepted by the next operator under tight tow at the relevant 500-metre point. II-4.92 However, having the opportunity to earn rate under the next contract is not tantamount to the dayrate drilling contractor, in fact, earning rate. It will be in the commercial interest of the dayrate drilling contractor to recognise the risk of a prior operator having equipment, materials and personnel on board the drilling unit after its release to the next operator. In that event, follow-on operations under the next contract could be disrupted and, as a consequence, the dayrate drilling contractor may be on “zero rate”. In order to proactively address this risk, the dayrate drilling contractor may, in certain circumstances, propose to add language to the definition of “Completion Date” which provides explicitly that the incumbent contract will not end until “the drilling unit is under tight tow five hundred metres away from the operator’s last well location and all personnel, equipment and materials of the operator have been removed from the drilling unit”. II-4.93 The other contingency that must be considered when drafting a definition of “Completion Date” is the potential of not having a follow-on contract. Even the most vigilant dayrate drilling contractor with both eyes on the horizon will not always be successful in securing follow-on work and have the opportunity to maintain a

 Esmaeili, Legal Regime of Offshore Oil Rigs, pp 125–128.

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seamless continuity of dayrate. Assuming the absence of a follow-on contract, the parties will typically provide for such contingency by including language in the definition of “Completion Date” which specifies that “where the drilling unit is going directly to a sheltered or stacked location or to a shipyard for inspection, the Completion Date will occur when the drilling unit is safely moored at an agreed demobilisation delivery port or equidistant location …”. Termination When the “Completion Date” occurs, it represents the natural II-4.94 process of the dayrate drilling contract coming to an end. However, when negotiating a dayrate drilling contract it will typically be recognised by the parties that the operator, in particular, may require the right, in certain circumstances, to bring the dayrate drilling contract to a premature end – ie termination. The operator, and indeed the dayrate drilling contractor, will II-4.95 already have a right at law to terminate – although under English law, the right will be limited. It will only arise in exceptional circumstances where there is a breach of condition or a repudiatory breach of an ordinary term that is so substantial to go to the root of the contract and have the consequence of depriving the innocent party of substantially the whole benefit of the contract.71 Given the limited position at law, a dayrate drilling contract will II-4.96 typically provide for the operator, in particular, to have a range of rights to terminate – either in addition to those rights and remedies already available at law or as a sole and exclusive remedy. In summary, there are four basic types of rights typically set forth in a termination clause. (a) convenience; (b) contractor’s default (cause); (c) insolvency; or (d) force majeure. We will consider each in turn, as follows, and also refer to relevant II-4.97 pro forma language from LOGIC MODU 97. It is noteworthy that, in LOGIC (as well as the language of any other typical dayrate drilling contract), any provision specifying the nature of the right to terminate, in the first instance, will be accompanied by language in a separate clause setting forth the commercial consequences flowing from the termination. It is always necessary, therefore, to look at the language of these separate provisions in parallel and recognise that  Brodies LLP, “Contracting Compass White Paper: Pointing the Compass toward Remedies for Breach”, 15 October 2016, available online at: www.brodies.com/remedies (accessed 15 May 2017).

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each right to terminate, where provided under the contract, must be carefully considered in the context of what the commercial position of each party should be in the wake of bringing the commercial relationship to a premature end. Convenience and force majeure II-4.98 Where a contract is being terminated for a force majeure occurrence, the contractor will typically be entitled to payment up to the date of termination, including any demobilisation costs. This is a balanced commercial position because neither the contractor nor the operator has caused or contributed to the termination.72 II-4.99 However, in the event of termination for convenience, the operator is exercising a right at its absolute discretion and sole option to end the commercial relationship and walk away. The operator will typically require this flexibility because the planning of a project may require long-lead commitment for utilisation of a drilling unit and, over the intervening period between signing the contract (ie the “Effective Date”) and commencement of the project, those plans may materially change. Likewise, investment decisions in respect of a project may change over time and an operator’s commitment (ie on behalf of a joint venture) may become secondary to other capital commitments for other projects. For example, macro-economic conditions may change in a way which renders investment in a UKCS project, for which the drilling unit is earmarked, much less attractive than deployment of the same capital for investment in a lower cost basin. Also, if a scope of work for the drilling of ten exploration wells over a two-year period, for example, is executed in part by the drilling of five dry holes, the operator may require the flexibility to take a technical view that continuing the drilling campaign is not viable. II-4.100 These commercial concerns of the operator will, during any negotiation, have to be balanced against the competing concern of the dayrate drilling contractor to protect contract backlog. As explained in para II-4.08, where a signed contract constitutes a commitment by an operator to pay dayrate over a certain period, the dayrate drilling contractor (as well as the investment community) will look to this commitment as a basis for judging financial performance and strength of the dayrate drilling contractor relative to peers in the market. II-4.101 Therefore, when the parties to a dayrate drilling contract have agreed to a provision whereby the operator will be entitled to terminate for convenience, there will be careful consideration of

 See eg LOGIC, “Mobile Drilling Rigs”, General Conditions, cll 22.1(a) and (b) and 22.2(a).

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the commercial consequences that should flow from such event. If demand for the drilling unit is high and market conditions are favourable to the dayrate drilling contractor, it may have the strength of bargaining position to demand an early termination fee equivalent to the entirety of the contract value. For example, if a dayrate drilling contract has been signed for utilisation of a drilling unit for a fixed period of 730 days and the operator elects to terminate for convenience prior to commencement of mobilisation of the drilling unit, the early termination fee may be agreed as a lump sum amount equal to the operating dayrate multiplied by 730 days, minus any substitute dayrate the drilling contractor may be able to secure from alternative work scope during the relevant 730-day period. Conversely, if demand is low and market conditions are favourable II-4.102 to the operator, it may have the bargaining strength to negotiate an early termination fee in an amount substantially less than the full contract value. However, in any given market, the dayrate drilling contractor will always attempt to secure, at a minimum, an early termination fee of operating dayrate multiplied by the number of days (eg 60 days) that the contractor would typically require to put the drilling unit on the market and pursue available opportunities for alternative work. For cause or insolvency A termination for cause provision in a dayrate drilling contract will II-4.103 typically contemplate a number of separate events that would have been agreed by the parties as a reasonable ground for the operator to walk away from the commercial relationship. These scenarios, and corresponding language, will typically centre on circumstances such as poor or non-performance, breakdown for excessive periods, failure to follow instructions, late delivery of the drilling unit, actual or constructive loss of the drilling unit, or contractor’s insolvency. In any such event of termination for cause, the dayrate drilling contractor will typically be entitled to compensation up to the date of termination for services performed in accordance with the contract and recovery of costs of demobilisation, unless termination is due to contractor’s default.73 Duration As broadly explained earlier in para II-4.71, there are two ways the II-4.104 duration of the dayrate drilling contract between the “Commencement

  See eg LOGIC, Mobile Drilling Rigs, General Conditions, cll 22.1(c)–(h) and 22.2(b), (c) and (d).

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Date” and “Completion Date” will be measured and delineated: (1) by a number of days (“term-based”); or (2) by a number of wells (“well-based”). II-4.105 A term-based contract will be for a fixed period, for example, 365 days. It will be critical for the parties to clearly identify when the counting of days will commence – eg does the fixed term start on the Commencement Date or when the drill bit passes through the rotary table (ie when operations on location commence)? II-4.106 As also mentioned in para II-4.71, the duration of the dayrate drilling contract may be “well-based”. In that event, each of the wells to be drilled under the terms of the contract will be identified in a detailed drilling programme within a scope of work exhibit, and programme details will typically include an estimated number of days for each well. Whether a well-based or term-based contract is chosen, the following points should be considered. Sidetracks II-4.107 If the dayrate drilling contract term is “well-based” and a definition of “Well” is included for the reasons stated in the earlier paras II-4.71 to II-4.76, the parties may consider it relevant to make specific reference to a “sidetrack”. It may be necessary, from the dayrate drilling contractor’s perspective, to clarify whether a “Well” should be defined to include both “mechanical sidetracks” and “geological sidetracks”. If a “Well” is defined to include “geological sidetracks”, the dayrate drilling contractor may be concerned that a number of lateral wells may be drilled to multiple separate geological targets from a single hole. If multilaterals are drilled from a single hole, this could be viewed by the dayrate drilling contractor as creating uncertainty as to when the drilling programme is projected to finish, and may obstruct visibility for horizon planning of when the drilling unit will be released to the next operator. Well in Progress II-4.108 A term-based dayrate drilling contract will typically provide for an automatic extension until operations are completed on the well-inprogress upon conclusion of the specified term – eg 30–60 days under the same commercial conditions. The dayrate drilling contractor may consider it appropriate to propose language to stipulate that the operator shall not, without the prior written consent of the drilling contractor, commence operations on any new well which is anticipated by the operator to take longer than a specified period, such as 30 days, after the expiry of the fixed term. Again, the dayrate drilling contractor may recognise that this type of contractual control is required for effective forward planning to ensure seamless transition and continuity of dayrate between the existing contract and the next.

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Options Whether the duration of a dayrate drilling contract is “term-based” II-4.109 or “well-based”, the operator may propose to have a right to extend the duration, typically exercisable at its sole discretion, but conditional upon a period of advance written notice being given to the contractor. An option will be viewed by the operator as providing flexibility for forward planning in respect of any project. However, any flexibility required by the operator may act as a constraint on the dayrate drilling contractor’s efforts to manage forward planning in respect of subsequent utilisation of the drilling unit by a follow-on operator. For that reason, the dayrate drilling contractor will require a specified period of prior written notice in respect of each option. Consideration of whether rates for an option should be the same II-4.110 as the rates agreed for the fixed term will be a market sensitive discussion during any negotiation. If rates prevailing in the market when the fixed term is agreed are low, it logically follows that the operator may attempt to negotiate the same rates for any option period. If the fixed term is a short period and the dayrate drilling contractor does not anticipate a rapid return to higher market rates, it may be agreeable for option rates to be the same or similar amount. However, if the fixed term is a long period (eg three years), the dayrate drilling contractor would typically require option rates to be negotiable, or alternatively linked to an agreed market index. Site access/ingress and egress at the well location As mentioned in para II-4.15, the technical process of defining and II-4.111 designating a well location will be controlled exclusively by the operator and all relevant details of the location selected for each well will be set forth explicitly in a separate exhibit for the scope of work. The process of identifying the location of a well will not, however, occur as an isolated technical exercise; it will always be carried out in conjunction with both parties carefully considering a number of issues under a separate clause in the body of the contract. A typical dayrate drilling contract will have such a clause in the form of two parts – one part dedicated to “access” to the well site and the other part addressing issues and concerns relating to the “condition” of the site. The extent of focus by both parties, and the degree of detail in drafting relevant provisions of this clause, will vary depending on the type of drilling unit. In respect of jack-ups, as well as semi-submersible drilling units II-4.112 with an anchor pattern (“moored semis”), the drilling unit will come into contact with the seabed and the extent of such contact will be a key driver for determining the amount of due diligence required, as well as defining the various roles and responsibilities of the

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parties in carrying out a safe and efficient operation to position and maintain the drilling unit on location. Where these critical issues are addressed in this separate clause, there will also be close interplay with other provisions – such as the exhibits for the scope of work, the equipment list and remuneration. II-4.113 When drafting a site access and location clause for jack-ups and moored semis, the parties will further attempt to identify certain risks particular to the process of pinning the unit on location, as well as highlighting particular steps that may be required to proactively address or manage such risks. To the extent certain risks cannot, or have not been, addressed or managed from an operational and technical perspective, this clause may also have particular provisions for allocating risk from a contractual or commercial perspective. Likewise, if such risks are not specifically addressed in this clause, they may be addressed in other clauses. II-4.114 Referring to the two-fold structure of a typical clause, LOGIC MODU 97 follows this form, with Clause 10.1 covering site access and Clause 10.2 addressing all requirements to confirm the satisfactory condition of the site.74 Referring to Clause 10.1, it provides in relevant part that the “COMPANY shall provide the CONTRACTOR with sufficient rights of ingress to and egress from the locations where wells are to be drilled. In the event of any restrictions or limitations in the COMPANY’s permit which restrict such rights, the COMPANY shall promptly advise the CONTRACTOR in writing of the same. Should the CONTRACTOR be denied access to the location(s) for any reason beyond the CONTRACTOR’s control, any time lost thereby shall be paid for at the Standby Rate detailed in Section III – Remuneration”.75 Properly drafted provisions providing for necessary access to the II-4.115 well site is an issue and concern for a dayrate drilling contractor in respect of all types of drilling units – whether a jack-up resting on the seabed, a semi anchored to the seabed or a dynamically positioned drillship without physical contact. The operator will hold the licence or concession (whether in its own right or on behalf of the joint venture) and a typical dayrate drilling contract will provide that the operator will unconditionally assume responsibility for taking all necessary steps, and fulfilling all requirements to procure permits and authorisations required for drilling unit access to the well location. It is important to recognise that this obligation will always be expressed in the contract separately from the more general requirements for customs clearance of the drilling unit and

  See eg LOGIC, “Mobile Drilling Rigs”, General Conditions, cll 10.1 and 10.2.   Ibid, cl 10.1.

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other items of equipment and materials. It is beyond the scope of this chapter to consider in detail any provisions of a typical tax and customs clearance clause; however, it does suffice to say that particular provisions in this regard must be carefully considered in the context of each jurisdiction, with a clear understanding of the many roles and responsibilities of both parties for managing the regulatory process, as well as the logistics of moving the drilling unit into a jurisdiction. Where Clause 10.1 addresses site access, Clause 10.2 of MODU II-4.116 97 covers the separate, but related topic of location due diligence. It provides, in relevant part, that the “COMPANY shall provide … navigational directions and information in [its] possession, concerning existing underwater terrain and obstructions” and all “drilling locations … shall be surveyed by the COMPANY and results thereof provided to the CONTRACTOR”. MODU 97 language is a meaningful point of reference for under- II-4.117 standing, generally, the role and responsibilities of the operator; however, as mentioned above, where the subject of the contract is a jack-up drilling unit, the dayrate drilling contractor will have more particular concerns about the condition of the seabed and will require more detailed technical analysis of the operational footprint where leg penetration will occur. Likewise, where a moored unit will have anchors connected to the seabed, the location of any obstructions within the anchor pattern will be a critical concern, as well as the condition of the seabed in those areas where anchor penetration will occur. As reflected in Clause 10.2 MODU 97, the operator will typically II-4.118 have an obligation to provide all information in its possession relating to the relevant area, including subsea pipelines, cables and other structures, wreckage or debris and also arrange a survey to identify any additional obstructions or hazards (ie debris survey). For a jack-up drilling unit, the dayrate drilling contractor will require more detailed language to address the following further issues and concerns. The drilling contractor’s operational management system, as well as conditions of its hull and machinery policy of insurance may, on a case-by-case basis, require sea bed cores to determine the stability of the sea bed in the relevant area where the unit will be positioned. Approvals from underwriters in this regard, and the technical due diligence required in advance of such approval, must, in many circumstances, be carried out multiple weeks prior to the planned commencement of drilling operations. The amount of lead time required will be dependent, in part, on the quality and type of information being provided and, in certain situations, the dayrate drilling contractor may also require the location to be cleared of debris or prepared using mattresses, anti-scour protection, and

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rock or gravel dumping – all of which will typically be a cost of the operator. II-4.119 It will always be in the commercial interest of the dayrate drilling contractor to carefully consider the consequences of any information being omitted by the operator, or incorrect or inaccurate information provided. The extent of any remedy in this regard may be, in part, dependent on market conditions, the negotiating strength of the dayrate drilling contractor and the risk profile of the particular location. II-4.120 In certain circumstances, there may be scope for the dayrate drilling contractor to negotiate terms of redress from the operator that would apply (eg to the minimum extent of reimbursement of the contractor’s insurance deductible) where damage to the drilling unit has occurred. In that event, there may also be scope for the dayrate drilling contractor to receive additional dayrate protection by including a separate provision providing that operating rate, not repair rate, would apply for the entirety of downtime attributable to repairs. Alternatively, there may be scope for the dayrate drilling contractor to negotiate a provision for the operator to provide indemnity in respect of (1) damage to the drilling unit, (2) damage to any third-party infrastructure and loss of product therefrom, and (3) down time incurred to repair any damage to the drilling unit. Dayrates II-4.121 As mentioned in the earlier overview of the operator/contractor commercial relationship in para II-4.05, a dayrate drilling contract will always have a “rate regime” that will specify the amount, if any, of rate per day the operator will pay to compensate the dayrate drilling contractor for utilising the drilling unit. II-4.122 The rate regime of a dayrate drilling contract will typically provide for a number of rates that will variably apply to different activities and operational circumstances arising during the relevant contract term. It is well understood, and fully anticipated, that drilling operations will not be continuous and uninterrupted and, where they are interrupted, the different types of rates applicable will be expressed in different ways on a contract-by-contract basis. There is not a uniform approach. In this chapter, we have however highlighted the types of rates typically provided in a dayrate drilling contract. It is also worthwhile to recognise, as a general principle, that all of the provisions in a typical rate regime will fall into two broad categories: (a) where full progress is being made on the critical path of performing drilling operations; and

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In respect of item (a), only the Operating Rate will typically apply II-4.123 in these circumstances. Item (b) will typically apply to a variety of circumstances, most of which are described in more detail below. As a general principle, the rates in category (b) can also be sub-classified as two particular types: those which are due to the fault of the dayrate drilling contractor and those which are not. The rate provisions may be included in the body of the contract, II-4.124 may appear in the appendices at the back of the contract or may appear in both parts with detailed cross-references. A typical dayrate drilling contract will express rates in a US dollar amount; however, in some jurisdictions, split dayrates involving two different currencies may be required – either by one of the parties or by local authorities. Operating Rate As mentioned above the Operating Rate will typically apply when II-4.125 critical path drilling operations are being performed. The preferred commercial position of the dayrate drilling contractor will be to have Operating Rate apply as a default position throughout the term of the dayrate drilling contract. In other words, Operating Rate will apply unless any other rate is specified under separate terms of the rate regime as being applicable. Where other rates are specified as being applicable, they will II-4.126 be expressed as a percentage of the Operating Rate. Each of those rates in the regime, other than Operating Rate, will be incrementally reduced depending on the type of circumstances or events – eg weather conditions or force majeure. The amount of the percentage of incremental reduction agreed by the parties and reflected in the terms of the rate regime will, in large part, be market sensitive. Standby Rate The incremental reduction for Standby Rate will typically be a II-4.127 marginal amount applicable to periods when the drilling unit is prevented from operating for reasons not attributable to the dayrate drilling contractor – eg, delays for necessary Government approvals or waiting on instructions from the operator, or any interruption of critical path drilling operations due to inspection, repair and modification of the drilling unit. In a typical dayrate drilling contract, Standby Rate (or Operating II-4.128 Rate) may also be specified to apply to planned maintenance. Other provisions of the dayrate drilling contract will require the drilling contractor to maintain its equipment in accordance with manufac-

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turer’s requirements and specifications, ie perform preventative maintenance. This is a contractual obligation of the dayrate drilling contractor for the benefit of the operator, because unplanned maintenance can have a material effect on the efficient performance of the entirety of the scope of work. Also, where a performance obligation is imposed on the dayrate drilling contractor, it will be a commercially balanced position for the dayrate drilling contract to provide for the dayrate drilling contractor to be compensated. II-4.129 It is also a commercially balanced position for Standby Rate (or Operating Rate) to apply to planned maintenance performed without causing a shutdown in drilling operations. However, it is recognised that a shutdown will typically occur for planned maintenance of some items of equipment (particularly the top drive). Time for all types of planned maintenance is often limited to an agreed allowance per month or day. Repair Rate II-4.130 Where unplanned repair of equipment due to the mechanical failure is required and such repair prevents critical path drilling operations, it is commercial custom and practice for the operator to agree to pay a rate for a number of hours calculated over a relevant period, typically 30 days. For example, a contract may provide for repair time allowance of at least 24 hours per each 30-day period at Operating Rate, or an alternative rate marginally less than Operating Rate. Thereafter the contractor will be on zero rate until the repair event ceases, whereupon Operating Rate, or the alternative rate, will resume. Force Majeure Rate II-4.131 A force majeure event is an uncommon occurrence; however provision is always made in a dayrate drilling contract for this contingency. It is also commercial custom and practice in the industry for a drilling contractor to be paid for a period of time during a force majeure occurrence prior to the operator having the right to terminate. The length of this period will be dependent in part on the drilling contractor’s negotiating strength in a given market and the duration of the contract. II-4.132 The parties should also consider the interplay between the rate provisions and other provisions of the contract. As mentioned earlier in paras II-4.98 to II-4.102, in some circumstances a force majeure event may entitle the operator to terminate the contract. However, if a force majeure event does not prevent critical path drilling operations being performed by the dayrate drilling contractor, it may be appropriate for the parties to consider whether the operator should have a right to terminate the contract. For example, a recent event in the UKCS involved the presence of volcanic ash in the atmosphere which interrupted the operator’s performance of its obligation to provide

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helicopter transportation to and from the drilling unit, but where such event had not interrupted critical path drilling operations, the dayrate drilling contractor may contend perhaps that termination of the contract by the operator would not be an appropriate outcome. Weather Rate Similar to force majeure, a weather event is beyond the drilling II-4.133 contractor’s control and should not, in principle, cause the contractor to suffer interruption of dayrate. From the dayrate drilling contractor’s perspective, it does not receive sufficient margin under the terms of a typical dayrate drilling contract to assume the risk of contingencies such as weather. Redrill Rate As previously mentioned in paras II-4.22 to II-4.24, there is a thread II-4.134 of tension between the dayrate drilling contractor’s responsibility to provide a fully functional drilling unit and the operator’s responsibility for designing and constructing the well. Redrill Rate is one provision of the contract that brings this tension into sharp focus. The dayrate drilling contractor will not typically assume downhole II-4.135 risk in relation to the design, engineering and construction of the well; however, the operator may contend that the contractor should accept some risk in the form of a reduced amount of rate, ie Redrill Rate to the extent that redrill or repair of the well is attributable to the fault of the contractor. It is customary for any redrill obligation to be the operator’s sole II-4.136 remedy and it is usually contingent upon the drilling unit remaining at or in proximity of location of the well in question. Referring to the incremental reduction of rates previously mentioned above, Redrill Rate will typically be less than Standby Rate and more than Force Majeure Rate. Indemnities and liabilities The detailed content of Chapter II-6 provides a comprehensive II-4.137 analysis of all legal principles and points of law relating to the structure of indemnity regimes, and the mechanics of how they operate across the entire spectrum of commercial relationships that exist in the oil and gas industry – including operator-to-operator upstream and midstream agreements, operator-to-contractor top-tier contracts and contractor-to-subcontractor relationships throughout the supply chain. Supplemental narrative in this regard is not required from the unique perspective of the dayrate drilling contract and, therefore, this paragraph does not revisit or refer, in particular, to any content from that chapter. This final paragraph is limited to

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the brief and narrow focus of a few key points of practical importance in respect of how an indemnity regime can be best understood, in general, and drafted, in particular, from the unique perspective of the dayrate drilling contract. II-4.138 A dayrate drilling contract between an operator and a drilling contractor will typically be drafted to provide for indemnities that do not exist in other contracts within the supply chain – either operatorto-contractor contracts or contractor-to-subcontractor relationships. The dayrate drilling indemnity regime is unique largely because drilling is well recognised as creating exposure to certain risks in the downhole environment that can be characterised as catastrophic in terms of the scale and staggering in terms of cost. Reference to two catastrophic events, Macondo and Piper Alpha, is sufficient to fully reinforce this point. When a reservoir is tapped, the consequences that inevitably flow to the surface cannot always be controlled. Likewise, as mentioned throughout this chapter, drilling is a high cost/high stakes endeavour, with expensive equipment being utilised at a significant cost. II-4.139 From a practical perspective, it is therefore worthwhile applying a structured process to understanding and analysing a complicated, and sometimes convoluted, indemnity structure. Where the indemnity regime of the dayrate drilling contract can be complex, sometimes resulting in convoluted language, we have highlighted below a summary of steps that may be taken for a structured and systematic approach to analysing and understanding the relevant indemnities. This practical approach is a simple two-step process: the first step of asking five questions and the second step of plotting a risk matrix in a similar format to that shown below. The five questions Question 1: “Who” is assuming the indemnity obligation and who is receiving the benefit? II-4.140 An indemnity regime should always be drafted to provide that a single party (ie a party to the contract) is assuming the indemnity obligation. Under English law, and the law of many jurisdictions, an obligation cannot be imposed on a non-party, ie other members of the respective groups.76 The respective members of the groups (as properly defined) can receive the benefit of an indemnity. Under English law, and the law of many jurisdictions, the benefit can be conferred on a non-party.77

  Farstad Supply AS v Environco [2010] UKSC 18, 2010 SCLR 379.   See Contract (Rights of Third Parties) Act 1999.

76 77

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Question 2: The indemnity applies to “what”? It is the making of a claim that triggers the indemnity not, for II-4.141 example, the loss or damage to property or injury or death of person. It is important to properly define “claim” so all intended triggers for the indemnity are covered.78 Question 3: The indemnity will apply “where”? The claim (as defined) relates to the different heads of indemnities. II-4.142 Referring to those listed below, those denoted in italics are typically unique to a dayrate drilling contract, as well as certain contracts for well services.79 (a) personnel and property of the respective groups (as defined) (b) down hole tools (c) surface pollution (d) sub-surface pollution (e) loss of hole (f) blow-out (g) underground/reservoir damage (h) third-party people and property Question 4: “When” does it apply? The indemnity will apply when the relevant loss which is the subject II-4.143 of the relevant claim (as defined) has been confirmed, for example, as “arising from, relating to or in connection with the Contract”. An indemnity should not be drafted to cover a loss of indeterminate scope. If properly drafted, an indemnity regime will always specify clearly when the loss is required to occur in order for any claim in respect of such loss to be covered by the indemnity.80 Question 5: “How” does it apply? The indemnity will apply, for example, irrespective of cause, eg II-4.144 “notwithstanding the indemnifying party’s negligence of any degree or character, wilful misconduct, breach of duty (whether statutory or otherwise), and irrespective of whether the claim arises in tort, breach of contract or otherwise at law”.81

  Wood v Capita Insurance Services Ltd [2017] UKSC 24.  Brodies LLP, “Contracting Compass White Paper: Pointing the Compass toward Indemnities”, 3 May 2017, available online at www.brodies.com/indemnities (accessed May 2017). 80   Campbell v Conoco (UK) Ltd [2003] 1 All E R (Comm) 35. 81   Elf Enterprise Caledonia Ltd v Orbit Valve Co Europe [1995] 1 All ER 174. 78 79

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X

X

Consequential loss

X

X

Downhole tools and equipment of a subsea nature (subject to agreed depreciation)

Third-party injury, death or property damage (to the extent of indemnitor’s negligence)

X

Underground/reservoir damage

X

X

All other loss related to a blow-out

Proximate third-party infrastructure damage

X

Pollution/contamination emanating from or associated with a blow-out

X

X

X

Pollution/contamination not related to blow-out emanating below the water line

Pollution/contamination originating above the water line

X

Loss of hole

Contractor group receiving

X

X

Contractor giving

Company group’s property and personnel

Contractor group’s property and personnel

Elements of liability risk

Table II-4.1  The Risk Matrix Table

X

X

X

X

X

X

X

X

X

X

Company giving

X

X

X

X

Company group receiving

CHAPTER II-5 CONTRACTUAL STANDARDISATIONAND THE LOGIC STANDARD CONTRACTS Lorna Dawson*

BACKGROUND Contract standardisation across the oil and gas sector has long been II-5.01 recognised as a tool for cost reduction, collaboration and efficiency. With the Wood Review and the vision in the Oil and Gas Authority’s Supply Chain Strategy1 of achieving an additional turnover in the service sector of more than £200 billion over 20 years, the industry’s focus on costs and efficiency will become ever more acute. As a mature province, the challenges faced by the oil and gas II-5.02 industry in the United Kingdom Continental Shelf (UKCS) (due to ageing infrastructure, smaller, more marginal pools, and remaining reserves which require greater technological innovation to exploit) are well known. In any oil and gas producing region, but particularly in a mature province, costs and collaboration really matter. These concerns have come to the fore once more in the “new normal”, “lower for longer”2 oil price environment, and in a region where the main players are as interdependent upon each other as in the UKCS. It is as a result of these challenges that the industry has, over the II-5.03 years, sought to co-operate in the creation of standard petroleum contracts, as well as thinking more innovatively about contract structures (such as alliancing,3 which gained traction in the last oil price   The author wishes to thank Laura Irving of CMS Cameron McKenna Nabarro Olswang LLP for her assistance in writing this chapter. 1   The OGA’s Supply Chain Strategy is available for download at www.ogauthority.co.uk/ news-publications/publications/2016/supply-chain-strategy (accessed 5 April 2017). 2   BBC News, “BP boss: Oil price will rise”, available at www.bbc.co.uk/news/business35363066 (accessed 5 April 2017). 3  “Alliancing” or “partnering” involves “a commitment between two or more organisations for the purpose of achieving specific business objectives by maximising the

*

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drop and which is being mooted as a potential model once more, and integrated services contracts,4 which have been successfully used by some contractors since the mid-1990s). This standardisation process is far from unique to the oil industry: for example, the construction industry has developed, among others, the FIDIC5 contracts and the JCT6 contracts, the marine industry has developed various standard forms of charterparty, and so on.7 Having said that, the commercial environment in the UKCS, in particular, lends itself to the application of standard forms. Although the commercial interplay between oil and gas companies is complex, at a high level, similar contractual structures govern each of the fields on the UKCS: The operator/contractor relationship II-5.04 As we can see from Table II-5.1 below, there are two main streams of contracts that sit behind the joint operating agreement (JOA). There are the “Field Agreements”, which work inter-oil company, and there are the “Supply Chain Agreements”, which are service contracts between the oil companies and their contractors in the supply chain. II-5.05 When we talk about this oil and gas “supply chain”, what do we mean? We mean the oilfield services companies – the companies who provide services to the oil companies operating assets in the North Sea. These contractors do not have a legal interest in the oil effectiveness of each participant’s resources. This requires changing traditional relationships to a shared culture without regard to organisational boundaries. The relationship is based upon trust, dedication to common goals and an understanding of each other’s individual expectations and values”. B Mak, “Partnering/Alliancing” (2001) Con LJ 218. As such, these contracts can be seen an example par excellence of a relational contract (on which see D Campbell and I R Macneill, The Relational Theory of Contract: Selected Works of Ian Macneil (2001)). However these arrangements can be onerous to manage and when disputes do arise they can prove complex and difficult to resolve, both because of the lack of clearly defined legal liabilities and because this provokes a sense of betrayal, given the trust involved in the relationship. For more on the use of alliancing contracts in the oil and gas context, see eg P Warne, “Latest developments on alliancing and relevant legal issues” (1998) OGLTR 322. 4   In an integrated services contract, the contractor offers the client an overall contractual solution involving the bundling together of work packages that would traditionally have been let separately. The expression covers a wide range of possible workscopes, from bundling together a couple of services (eg well supervision services and wireline activities) to the outsourcing of the delivery of entire projects or running whole areas of a client’s operations. See eg the integrated services contract awarded by Maersk to Amec Foster Wheeler in 2015: http://media.amecfw.com/amec-foster-wheeler-awarded-integratedservices-contract-by-maersk-oil (accessed 4 May 2017). 5   International Federation of Consulting Engineers. 6   The Joint Contracts Tribunal. 7   For a detailed discussion of some of the standard marine contracts, see S Rainey, The Law of Tug and Tow and Offshore Contracts (3rd edn, 2011).

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Table II-5.1  Outline of Contractual Structure Licence Joint operating agreement Field agreements eg Survey Agreements Construction and tie-in agreements Pipeline crossing agreements Transportation agreements Production and operating services agreements Processing agreements

Supply chain agreements eg Seismic agreements Design, construction, maintenance Marine contracting eg FPSO providers, pipelay specialists, heavy lift Drilling Well services Decommissioning Waste and chemicals management Support services: catering, warehousing, transport (helicopters)

fields themselves (although over the history of the UKCS some have bought into licences, and generally sold out of them again). Their business model is to sell their services, know-how and kit to the oil companies. As we saw in Chapter II-2, operators will be authorised and II-5.06 obliged, by the terms of their JOA, to proceed with the work programmes agreed by the operating committee under their JOA, ie to do what is necessary to “search, bore for and get petroleum”8 under the applicable licence. The work programmes agreed by the co-venturers under the JOA will include the “work obligations” imposed by the terms of the licence, which could be anything from shooting seismic to drilling wells. Of course, where an asset is held only by one company (ie it has a 100 per cent interest in the relevant licence area), and so there are no co-venturers and there is no effective JOA, that company will still be obliged, under the terms of its licence, to perform the relevant work obligations9 and will want to exploit the licence to recover petroleum for its own gain.   Part I of the Petroleum Act 1998 vests all rights to petroleum in the Crown, including the rights to search for, bore for and get it. It then goes on to empower the Secretary of State to grant licences to “search for and bore for and get petroleum” to such persons as he thinks fit. 9   Para I-4.47. 8

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II-5.07 Where there is no JOA, the oil company is free to enter into service contracts on the terms it wishes. Where there is a JOA, the operator enters into service contracts for, and on behalf of, itself and its co-venturers, whether on a single asset basis or through multifield contracts,10 and the JOA will set out the process the operator must follow in agreeing the terms of the service contracts with contractors. Usually, there will be provisions obliging the operator to enter into a competitive tendering process and thresholds governing the level of review and control the co-venturers will have over the final contract terms.11 The JOA will apply for all stages of the asset lifecycle, from exploration and appraisal, through field development, production and ultimately decommissioning. II-5.08 The costs of developing a North Sea oilfield can run into billions of pounds, and the high-risk nature of the industry is well recognised. Service contracts, therefore, are not insignificant contracts – they are often multi-million pound contracts with significant risks attached to the workscope. II-5.09 For various reasons,12 over the years, oil companies have increasingly contracted out supply chain work to the service companies, while retaining overall control and responsibility for the safe operation and management of their assets. As such, oil companies are generally not equipped to do all the engineering, design, construction, well servicing, drilling works and so on in-house. As a result, in order to fulfil their licence work obligations and the work programmes under their JOAs, operators require to contract that work out to those contractors who have the necessary technical expertise and specialist equipment. II-5.10 Generally, the operator will have various contracts in place at any one time covering various scopes of work; contractors themselves being, on the whole, specialists in their particular fields. Usually the operators will have departments specialising in procurement and supply chain, and traditionally each has developed its own preferred contract terms, usually favouring the operator.13 Contractors, particularly the larger service companies, have also developed their own standard positions: many contractors prepare “contracts   Paras II-4.38 to II-4.39.   See eg the Oil & Gas UK Joint Operating Agreement, cl 6.5. 12  Such as creating competition within the supply chain, promoting efficient use of resources such as drilling rigs, as well as ensuring access to best-in-field technical expertise. 13   Some contractors’ associations have made attempts to highlight what they perceive to be the inequities in operators’ standard terms, and to take steps to redress the imbalance. See for instance The International Marine Contractors Association General Contracting Principles, first issued in 2002. The 4th revision, issued in 2017, is available for download at www.imca-int.com/download/publication/401/imca-general-contracting-principles.pdf (accessed 4 May 2017). 10 11

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manuals” describing the terms they require in their contracts, their preferred negotiating positions, their contractual “backstops” and/or provisions which require specific Board approval. Which of the two positions the ultimate contract favours, or how much of a “middle ground” is reached during negotiation of the contract terms, tends to reflect the prevailing market conditions at the time the contract is negotiated. Unlike other upstream oil industry contracts, the parties to a supply II-5.11 chain agreement (the operator and the contractor) will be on the same side of the fence in each transaction. In most UKCS field agreements, parties to such contracts will more than likely find themselves on the other side in a similar contract elsewhere in the North Sea. For example, the operator under a JOA will be a non-operator in a different JOA; the “host” platform in one agreement may be the satellite in another.14 Because of the nature of the supply chain, the oil company tends always to be the Client, and the service company will be the Contractor, in every contract. So, unlike other oil industry contracts, the terms of service contracts are more likely to be driven by market forces, and the relative bargaining powers of the parties, including the availability, or not, of a drilling rig or a specific piece of kit, than may be the case in Field Agreements. Standard Contracts Supply chain agreements contracts will describe, in detail, the specific II-5.12 scope of work (the services and/or equipment to be provided), the legal terms and conditions governing the performance of the contract and the remuneration the contractor will receive. Contractors will be concerned with being paid – they want to ensure that they are appropriately compensated for the work done. Both the contractor and the operator will also be concerned with the allocation of risk under the contract, for reasons discussed in Chapter II-6. Risk allocation tends to be the most contentious issue in any service contract negotiation, and will often be the last provision to be agreed. Having said that, there are often generally accepted indemnity positions under various types of services contracts,15 which narrows the focus of the negotiation, but does not close the gap entirely. In practice, the industry, globally and in the UKCS, has used II-5.13 some standard form agreements for decades. We have seen this, in particular, with JOAs. A form of UKCS standard JOA was created when the British National Oil Corporation (BNOC), a government   Of course, the landscape is changing with new entrants, often backed by private equity, coming into the North Sea as infrastructure owners. 15   Paras II-5.41 to II-5.45. 14

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company, participated in the fifth round licences.16 The most recent UKCS form of JOA is the Oil & Gas UK Industry Standard JOA 2008 (25th round) (with amendments in 2013 to address the Bribery Act 2010). The Oil & Gas UK model form is the most predominant standard used on the UKCS, although it is not always followed without amendment. Internationally, several other forms are in use, the most widely used being the AIPN17 model form. II-5.14 Most UKCS standard form Field Agreements have been created under the auspices of Oil & Gas UK (or its forebear, the United Kingdom Offshore Operators Association (UKOOA)). In addition to the Oil & Gas UK JOA, other inter-oil company standard agreements, also created through Oil & Gas UK, are widely used, including the Decommissioning Security Agreement,18 a Pipeline Crossing Agreement and Pipeline Proximity Agreement, a Confidentiality Agreement and, most recently, a Study Agreement.19 II-5.15 It is easy to see how services contracts were ripe for standardisation, and this is just what the UK oil industry proceeded to do in the early 1990s, through CRINE (Cost Reduction Initiative for the New Era) which was set up under the auspices of UKOOA in 1992, by the industry and the government, in response to a lower oil price. The primary aim of CRINE was to reduce capital and operating expenditure in the UKCS, and it aimed to achieve this through several initiatives, including technical and commercial standardisation. Following the publication of the CRINE report in 1994, various sub-groups were created to progress these initiatives and to look at different ways of collaborating and reducing costs within the industry. The CRINE Standard Contracts Committee was set up in 1996, with the aim of producing a suite of standard operator/ contractor service agreements (“model contracts”). Six sets of “General Terms and Conditions” were published in 1997 and 1998: Construction (intended for use in onshore construction); Marine Construction; Offshore Services; Design; Well Services; and Mobile Drilling Rigs. Procurement specialists will be familiar with the LOGIC supply chain contracts, the suite of standard form services contracts first published as the CRINE contracts and which, through the publication of various new editions, continue in common usage in the UKCS today.

  M David, Upstream Oil and Gas Agreements (1996), at p vii.   Association of International Petroleum Negotiators. The AIPN has produced a number of model form agreements, some of which are discussed at para II-5.75. 18   See Chapter I-12. 19   All are available to purchase (or free to members) from the Oil & Gas UK website at http://oilandgasuk.co.uk/publicationssearch.cfm 16 17

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The UK Oil & Gas Industry Task Force (the predecessor to PILOT)20 II-5.16 was a government-led, rather than industry-led, initiative, formed in the late 1990s and which in its 1999 report included a recommendation that a new organisation be created to promote best practice within the industry’s supply chain. This organisation was Leading Oil and Gas Industry Competitiveness: LOGIC. LOGIC was established as a not-for-profit organisation with a Board of Directors from the founding trade organisations UKOOA (the predecessor to Oil & Gas UK (OGUK)), Offshore Contractors Association (OCA), International Association of Drilling Contractors (IADC), Energy Industries Council (EIC) and International Marine Contractors Association (IMCA). It worked with the Department of Trade and Industry, the government department then responsible for the offshore oil and gas industry, to identify, promote and manage collaborative industrywide tools. Although the Wood Review considered that LOGIC had not been sufficient, by itself, to drive the UKCS forward into a new era,21 it is still active, and continues to deliver on its core objectives: “to promote competitiveness and commerce by implementing supply chain management practice and promoting collaboration, benefits and cost savings, in relation to the means by which organisations (comprising operators, contractors and suppliers) operate in the UK oil and gas sector to achieve ‘real’ business results”.22 There are now 12 LOGIC Standard Contracts created by the II-5.17 LOGIC Standard Contracts Committee, each covering a different “service” and available for download, together with Guidance Notes, from the LOGIC website. Why standardise? The Oil & Gas Authority’s Supply Chain Delivery Programme has as II-5.18 a key activity: “[p]romote the benefit of standardisation and collaboration and the benefits of adopting new contracting models across all activities”.23 Promotion of standard form contracts is seen as key to improving cost efficiencies within UKCS supply chain and, therefore, to delivering the Oil & Gas Authority’s Supply Chain Strategy. While each particular scope of work in a supply chain contract II-5.19 will be bespoke, there will be many similar features between contracts. While a drilling contract will be different in a number of  PILOT continues today as a cross-industry and government initiative focusing on maintaining the UKCS as a globally competitive region. 21   See Chapter I-5. 22   LOGIC “General Conditions of Contract for Services On-and Off-Shore”, 3 (March 2014), at p ii. 23   Oil & Gas Authority’s Supply Chain Delivery Programme, 24 October 2016. 20

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material respects to a construction contract, most drilling contracts will be similar to each other in their contractual terms.24 II-5.20 Oil & Gas UK standard forms have a wide buy-in across the industry. Key players in the industry sit on the various contracts subcommittees and contribute significant energy and time in drafting the provisions of the LOGIC standard form agreements, considering and updating their terms, and debating the more contentious clauses. Once published, their terms are quickly familiar across the industry. It is for these reasons that these key players, as well as Oil & Gas UK, promote the use of the standard form contracts. II-5.21 The benefits of standardisation are clear.25 If the model form is used properly and multiple deviations are avoided,26 the following can be achieved: (a) Reduction of drafting and negotiating time – use of model forms avoids starting with a blank sheet of paper each time, or, more realistically, avoids each party pitching its preferred house style against the others. (b) Reduction of transaction costs – tenderers know the terms of the LOGIC Standard Contracts, allowing a more effective, focused and quicker negotiation and tendering process. (c) Focus on value-protection – rather than negotiate every clause, including all the boilerplate provisions and having to redraft standard provisions every time, the parties can focus on, and negotiate, those provisions that have genuine consequences for value and risk. (d) Benefit of industry input to the model form – a broad sector of industry players, both operators and contractors, have been involved in the creation and, over the years, the updating, of the LOGIC Standard Contracts. As a result, the contracts form a genuine attempt to collate and document industry intent and experience. (e) Non-binding – parties can negotiate terms. While efficient use  The Housing Grants Construction and Regeneration Act 1996 does not apply to these contracts: oil and gas operations are excluded from the definition of construction operations and there is an exclusion for certain plant or machinery or steel work for the purposes of power generation (s 105(2)). For a further discussion of Drilling Contracts, see Chapter II-4. 25  The benefits have been recognised judicially. See eg The Martha Envoy [1978] AC 1 per Lord Diplock at 8. 26   Although most industry players on the UKCS will use the standard LOGIC contracts, not all do so without making some revision to the form. While adjusting the terms of the form by introducing Special Conditions designed to fit the particular circumstances of the work being undertaken will often be an example of very good practice, “knee-jerk” alteration of the form simply to re-introduce one’s preferred wording serves only to undercut the benefits of standardisation. 24

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c ont r ac t ua l stan dard i sat i o n 157 of the LOGIC Standard Contracts, with as few changes as possible, is the intent, there is room for negotiation: their terms are not set in stone and the structure does allow amendment by Special Condition, making the contracts a more attractive option. (f) Common understanding on LOGIC Standard Contract terms – enhanced by academic and judicial interpretation following from increased usage.27

A case in point is BP Exploration Operating Company Limited v II-5.22 Dolphin Drilling Limited.28 This case involved termination rights under a contract for a semi-submersible drilling rig. BP was seeking to terminate the contract on the basis that it had a right to terminate the contract at its “convenience”. Dolphin, who owned and operated the rig, argued that BP was not entitled to terminate the contract until after the specified commencement date for the drilling work. The drilling contract between the parties was based on LOGIC General Conditions of Contract for Mobile Drilling Rigs, Edition 1 (December 1997), with numerous special conditions and further amendments made at a later date. The contract was signed in March 2009, with a “Commencement Date” to be between 1 January 2010 and 31 March 2010. Prior to signing the contract, Dolphin agreed with BP, pursuant to Heads of Agreement, that it would not contract out the relevant rig for any work that conflicted with BP’s planned operations. Dolphin therefore argued that it had set aside the rig for BP’s use. The parties agreed that, in accordance with the remuneration II-5.23 section, if BP terminated the contract for convenience immediately after the “Commencement Date”, it would be liable to pay Dolphin 90 per cent of the operating rate for the whole three-year term of the contract. However, the “Commencement Date”, as defined in the contract, was yet to occur. As BP was seeking to terminate before the “Commencement Date”, it argued that no sum was payable. Dolphin’s position was that this made no commercial sense and that the contract must be interpreted as meaning that a right of termination could only be exercised by BP after the “Commencement Date”. Otherwise, Dolphin would have committed to keeping the rig available for BP without any guarantee of compensation. One of the issues the court took into account in reaching its II-5.24   A T Martin and J J Park, “Global petroleum industry model contracts revisited: Higher, faster, stronger”, 3(1) (2010) Journal of World Energy Law & Business 4, at 10 (hereinafter “Martin and Park, ‘Model Contracts Revisited’”). Martin and Park highlight further advantages, including: risk avoidance, higher quality contracts, improved relationships between industry participants and association development. 28   BP Exploration Operating Company Limited v Dolphin Drilling Limited [2009] EWHC 3119 (Comm). 27

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decision was that the termination right in question is largely word for word in accordance with LOGIC General Conditions of Contract for Drilling Rigs, Edition 1 (December 1997). In addition, that model contract had been in use in the industry for a number of years and representatives from both parties were involved in the working group. The Court was not satisfied that something had gone wrong with the language and would therefore not depart from the ordinary meaning of the language used. The fact that the contract was more favourable to one party was not sufficient to conclude that there had been a mistake. BP was therefore entitled to terminate for convenience. II-5.25 The LOGIC Standard Contracts are very useful model form contracts but there are certain disadvantages: (a) “Drafting by committee” – as discussed earlier in this chapter, the LOGIC Standard Contracts were drafted by way of industry working groups consisting of representatives from across the industry, to include, so far as possible, a fair balance between operators and contractors. Such an approach can also result in drafting which, despite the best efforts of the drafters, is perhaps not as clear or as detailed as it might have been, due to disagreements over interpretation. However, it is important to bear in mind that the purpose of the LOGIC Standard Contracts was not to provide a complete solution, but only to set out a foundation for contracting and to create a set of standard terms to avoid excessive time and costs being wasted, albeit allowing amendment by Special Conditions. (b) Scope – the LOGIC Standard Contracts cannot be all things to all people. Although each of the model contracts have been drafted to fit a particular type of service, they could not be drafted with a single specific scope in mind. It may therefore be that a model contract is not quite the right fit for a particular scope of work. (c) Changes in law – while the industry working group will react as quickly as it can to a relevant change in law, it will take time for the LOGIC Standard Contracts to be amended to reflect that change. Practitioners need to be aware, therefore, of any Special Conditions required to deal with changes in law, until such a time as the General Conditions are updated. (d) Form filling – parties may assume, in error, that use of a model contract is simply a box-ticking exercise and may not give it the due consideration required. There is a risk of parties just assuming that a contract will be fit for a particular transaction and failing to fully review and amend it in each

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c ont r ac t ua l stan dard i sat i o n 159 case of use. Mistakes can therefore easily be made. Improper use of model contracts, particularly by under-qualified users, is a risk highlighted by Martin and Park. Similarly, “model paralysis” should be avoided. Well-considered changes to the Standard Contracts should not be resisted solely on the basis that they involve a departure from the industry-agreed model terms.29 (e) Consistency – the LOGIC Standard Contracts are not used consistently across industry. A number of operators and contractors choose to use their own standard terms and conditions. The key benefits of the LOGIC Standard Contracts (standardisation, cost saving and time saving) are therefore not as widespread as they could be were more parties to subscribe to using them.

LOGIC STANDARD CONTRACTS – KEY FEATURES AND PROVISIONS OF PARTICULAR CONTRACTS Contract models A number of different models of LOGIC contracts have been II-5.26 developed over the years to cover the provision of various types of services (these models have also been updated from time to time). The contracts currently available to order from the LOGIC website,30 and their intended applications,31 are as follows: (a) Construction, Edition 1 (June 1997) and Edition 2 (October 2003) (new edition expected soon) • To cover: major fabrications; topsides installation and hook-up; significant topsides modifications; construction services contracts for topsides work. (b) Design, Edition 1 (June 1997) and Edition 2 (October 2003) • To cover scopes of work for various oil and gas design services (excluding well design). (c) Marine Construction, Edition 1 (February 1998) and Edition 2 (October 2004) • To cover: pipelaying services; offshore installations; subsea construction; inspection, repair and maintenance services using diving support and other support vessels. (d) Mobile Drilling Rigs, Edition 1 (December 1997) • To cover the provision of mobile drilling units on a   Martin and Park, “Model Contracts Revisited”, p 11. This may be seen as the converse of the problem highlighted at note 27 above. 30   www.logic-oil.com (accessed 4 May 2017). 31   Intended applications are as stated in the guidance notes for each model. 29

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daywork basis. If this model were to be used for integrated services it would require some amendment. (e) Purchase Order Terms and Conditions, Edition 1 (December 1997) and Edition 2 (December 2005) (new edition expected soon) • To cover the purchase of goods. They are short form and are intended to be attached to a purchase order. Therefore, they do not follow the same form as the other LOGIC models. (f) Services (on and offshore), Edition 2 (October 2003) and Edition 3 (March 2014) • To cover scope of work for a range of onshore and offshore services. It is the most widely used of the LOGIC contracts. (g) Small/Medium Enterprises (SME) Services, Edition 1 (March 2001) • To cover a wide range of low/medium risk contracts onshore or offshore with SMEs. It is based largely on the Onshore Services and Offshore Services model. (h) Subcontract for Small/Medium Enterprises (SME) Services, Edition 1 (March 2001) • For use, principally, by a main contractor as a low-risk subcontract with an SME (the subcontractor), where the work is part of the main contractor’s larger scope of work under a contract with an operator. (i) Supply of Major Items of Plant and Equipment, Edition 1 (March 1998), Edition 2 (December 2005) and Edition 3 (December 2015) • For use in respect of the purchase of complex capital plant and equipment such as gas turbines, compressors and pumps. (j) Well Services, Edition 1 (June 1997) and Edition 2 (March 2001) • To cover scopes of work for service contracts associated with well engineering work. Also drafted, but no longer maintained, are: (a) Services for Offshore, Edition 1 (June 1997); and (b) Services for Onshore, Edition 1 (June 1997). II-5.27 While the model contracts were drafted for use in respect of the scopes of work noted above, they can be adapted to fit other similar services if appropriate amendments are made.

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Form of contracts Each of the LOGIC contracts (with the exception of the purchase II-5.28 order terms)32 is made up of three parts: (i) general terms and conditions; (ii) form of agreement; and (iii) special terms and conditions. Each will be discussed in turn. General terms and conditions These are the underlying terms and conditions on which the relevant II-5.29 services are provided. They include definitions, rules of interpretation, obligations of the parties, payment terms, termination provisions and boilerplate provisions (ie governing law, notices, force majeure and assignment etc). The governing law of all of the LOGIC Standard Contracts is English law – any practitioner should bear this in mind when using the contracts. The author has seen the LOGIC terms transposed to other legal jurisdictions, with a new governing law clause slotted in as a Special Condition, without thought as to whether the provisions will be enforceable in those jurisdictions (of particular concern here would be the indemnity provisions). Local advice should always be sought on the specific changes which would be required to make the contract work as intended in a foreign legal jurisdiction. The purpose of the general terms and conditions is to create a II-5.30 basis for contracting which is generally accepted across the oil and gas industry as reasonable and fair to both parties. As both parties know the starting point, time spent negotiating non-material terms is reduced and the parties are able to focus on those terms which are particularly relevant to the contract at hand. The general conditions can be amended by use of special conditions (discussed further at para II-5.32). Form of agreement The form of agreement sets out the details of the parties, the various II-5.31 sections which form part of the contract and signature blocks. An appendix is attached which must be completed for each contract: it specifies key details of the contract, for example the effective date, the scheduled completion date, the parties’ representatives, the defects correction period, insurance amounts and liability caps. Parties edit the form of agreement (and attached appendix) to include contract-specific information for each contract instead of amending the general terms and conditions section of the contact.

 Purchase Order Terms and Conditions, Edition 1 (December 1997) and Edition 2 (December 2005).

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Special terms and conditions II-5.32 If the parties wish to amend the general terms and conditions of the contract to suit the requirements of a particular scope of work, or particular commercial terms, this is done by way of special conditions. These may be used to amend or delete an existing provision or to add additional provisions. II-5.33 Special conditions are drafted as a separate document and are not marked up on the general terms and conditions. The form is similar to the way changes would be set out in an amendment agreement. For example, “Delete Clause 5.1 and replace with the following …”. Guidance notes II-5.34 The contracts each have accompanying guidance notes which are useful for reference when drafting or reviewing a contract using LOGIC Standard Contract terms. It was recognised by the working groups drafting the LOGIC Standard Contracts that the discussions on particular provisions and issues were ephemeral and at risk of being lost if not in some way captured. The purpose of the guidance notes is therefore to aid users in understanding the meaning and intention behind the provisions of the model contracts. II-5.35 The guidance notes include: background information on the development of the LOGIC Standard Contracts; details of the intended application of the particular contracts; structure; and comments on specific definitions and clauses (note that not all definitions and clauses are covered, just those that the working groups considered to merit comment). LOGIC Standard Contracts in practice: the tendering process II-5.36 How are the LOGIC Standard Contracts actually used? Generally, operators will require contractors to bid for work in a competitive tendering process. As discussed above, this will usually be a requirement of the governing JOA, at least for contracts over a specific value. II-5.37 If there is a competitive tendering process, the company requiring the provision of services will issue a tender pack to the contractors who have been selected to tender for the work (bidders). The tender pack will contain the draft form of contract, so where a LOGIC Standard Contract is to be used, the tender pack will note the details of the relevant model and any special conditions (ie amendments to the LOGIC General Conditions) required by the company. Bidders will then respond to the tender with the various pieces of information requested, which will include, amongst other things, qualifications to the proposed terms and conditions as well as the Contract Price.

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Qualifications are often provided by way of a table noting the provision which is to be amended, the proposed amendment and an explanation of the reason for the requested change. Once the company has selected its preferred bidder, it will proceed II-5.38 to negotiate the contract terms and conditions. The company may accept some of the bidder’s qualifications but is likely to push back on others. The parties will continue to negotiate by way of emails, calls and meetings (as required) with the qualifications table being sent back and forward between the parties until the final terms of the contract are agreed. The success of the bidder in getting its qualifications accepted by the company will depend on the particular circumstances, including the bargaining strength of the bidder, the value of the services being provided, the duration of the contract, the perceived risks and the level of competition for the work. If there is no competitive tender process, the negotiation of the II-5.39 contract will follow much the same process, ie one party will issue its proposed terms and conditions for the work, and the other party will provide qualifications which will continue to be negotiated until the final terms are agreed. LOGIC Standard Contracts in practice: the key provisions The LOGIC Standard Contracts are largely very similar in form, II-5.40 for the obvious reason that the Standard Contracts Committee has tried to keep their terms consistent, and the terms and conditions tend to differ only where there is a particular justification for such difference. For example, Well Services carry different risks, so the indemnity provisions are slightly different to On- and Offshore Services (discussed in more detail in paras II-5.45 to II-5.55). Mutual hold harmless indemnities It is very important to understand the indemnity provisions in the II-5.41 LOGIC contracts (and in respect of oil and gas supply chain contracts generally). These indemnity arrangements, for those new to the oil and gas industry, may seem unusual, but there are very good reasons behind allocating risk in this manner. For a more detailed discussion on indemnity provisions in oil and gas contracts, see Chapter II-6. It is worth noting here, however, a few particular provisions which are relevant to supply chain contracts. Liability and indemnity clauses allocate risk either in the event of II-5.42 an accident or, more generally, in relation to claims for performance risk. They are intended to apply to both minor incidents and major catastrophes, or they could allocate risk from faulty or defective work. Always, of course, consider the interaction between the liability and indemnity provisions and the warranties.

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II-5.43 It might be expected that a contractor would take responsibility for damage, losses or injuries it caused when performing a contract, under the normal common law rules, although, perhaps, with a cap on liability or some exclusions. The usual North Sea practice for supply chain contracts is to operate on a “mutual hold harmless” basis where risk is allocated not according to the fault (ie “notwithstanding the negligence or breach of duty (whether statutory or otherwise”)) of the indemnified party or any other entity or party, but, as a generalisation, each party normally taking responsibility for injury or damage to its (and its group’s)33 own people and property, regardless of who was responsible for that injury or damage. The clear allocation of risk is intended to provide certainty and, hopefully, avoid costly litigation to establish fault. It also avoids a multiplicity of insurances of the same asset: imagine the costs incurred if every contractor coming onto an oil platform had to carry insurance for damage or loss of the platform, and all the people on it. Contractors would seek to pass such costs up the contractual chain, to the operator, through the pricing mechanism in the supply chain contract. II-5.44 If contractors were exposed to the risk of liability for damage to oil installations and the resulting consequential loss, the smaller contractors would in some instances be unable to operate, and the larger ones would be keen to put caps on that liability in order to render it insurable. This would be time-consuming to negotiate and would probably in most cases still leave operators with considerable exposure and expense. II-5.45 Although a mutual hold harmless indemnity arrangement is standard in supply chain contracts, there are some generally recognised deviations from the mutual hold harmless regime in certain types of contracts. These include the deviations in the Contract for Well Services and Mobile Drilling Rigs described below.

 The mutual hold harmless indemnities usually extend to the benefit of each party’s group. The concept of a “Group” must always be defined in relation to each party so that the extent of the indemnities is clear – ie the definition of “Company Group” sets out the list of entities (1) in respect of damage to which an operator will indemnify contractor (and the other members of Contractor Group) and (2) to which the contractor gives indemnities in respect of damage caused to the Contractor Group. The wider the definition of “Group”, the fewer people will fall into the category of genuine third parties. “Company Group” in the LOGIC Standard Contracts includes company, affiliates (a term which should also be defined), co-venturers (ie the other parties to the relevant operating agreement) and their respective directors, officers and employees. LOGIC Standard Contracts do not include, as part of Company Group, company’s other contractors. The Contractor Group is defined to include Contractor, its subcontractors (as Contractor is able to set off risk and liabilities in its contracts with those subcontractors), its and their affiliates, and their directors, officers and employees.

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Well Services Due to the nature of the services typically performed under the LOGIC Standard Contract for Well Services, loss of downhole equipment, catastrophic loss and pollution are real risks, and, as with the mutual hold harmless indemnities, such risks are allocated on the basis of the parties best able to bear that risk. The contractor does not have control over the well conditions or make the overall decision in respect of works carried out within the well. Downhole equipment. The company reimburses the contractor for loss of or damage to property, materials or equipment whilst in-hole below the rotary table, except where caused by the contractor group’s negligence. Compensation is subject to depreciation.34 This operates notwithstanding the general indemnity given by the contractor to the company group in respect of the contractor group’s property. There is, of course, a fair wear and tear exception. Corrosion by well effluent. Clause 19.6 provides that the company reimburses the contractor for repair or replacement costs, where the contractor suffers “damage which could not reasonably be expected” to non-downhole equipment resulting directly from corrosion, erosion or abrasion caused by the nature of well effluent, again with the replacement costs being subject to depreciation. Catastrophic loss. Subject to the indemnities the contractor gives for its group’s people, property, third party claims and pollution in Clauses 19.1 and 19.4 of the contract, the company indemnifies the contractor against claims, losses, damages, costs, expenses and liabilities resulting from loss of or damage to any well or hole, blow-out, fire, explosion, cratering or any other uncontrolled well condition and reservoir damage or loss of oil and gas therefrom this source, irrespective of cause and notwithstanding the negligence of breach of duty (whether statutory or otherwise) of the indemnified party or any other entity or party.35 Pollution. Clause 19.3 provides that, subject to certain contractorprovided indemnities, the company indemnifies the contractor group from claims arising from pollution and/or contamination emanating from the reservoir or from the property/equipment of the company group arising from or related to the performance of the contract. Subject to certain company-provided indemnities, the contractor indemnifies the company group for pollution (1) occurring on the contractor group premises; (2) whilst on contractor group transportation to the wellsite; and (3) to the extent of the contractor group’s negligence, originating from the contractor group’s property at the

II-5.46

II-5.47

II-5.48

II-5.49

II-5.50

  LOGIC, Standard Contract for Well Services Edition 2, Cl 19.5.   Cl 19.9.

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wellsite above the rotary table or above the bottom of the vessel (where the work is performed from a vessel) or from contractor group property while being transported by the company group. II-5.51 Property lost overboard. Notwithstanding the indemnities the contractor gives for its group’s people, property and third-party claims, the company will indemnify the contractor group for the costs of recovery of property lost overboard during transportation by the company (these costs could be sizeable as it may involve contracting in a vessel or other equipment): see Clause 19.8. Mobile drilling rigs II-5.52 Where there is a drilling operation ongoing, then the biggest and most expensive piece of kit is likely to be the drilling rig. Drilling contractors are, therefore, understandably wary of granting blanket mutual hold harmless indemnities to other contractors. For this reason many of the drilling contractors are not signatories to the IMHH Scheme (see para I-5.63). In addition, the drilling contractor will seek similar protections from the operator with respect to downhole equipment and catastrophic loss. II-5.53 Downhole equipment. As in the LOGIC Standard Contract for Well Services, the company reimburses the contractor for loss of or damage to property, materials or equipment whilst in-hole below the rotary table except where caused by the contractor group’s negligence. Again, this is subject to depreciation, and there is a fair wear and tear exception, for the obvious reason that some downhole equipment, like drilling bits, has a very short working life before needing refurbishment. II-5.54 Pollution. Subject to certain contractor-provided indemnities, the company indemnifies the contractor group from claims arising from pollution and/or contamination emanating from the reservoir or from the property/equipment of the company group (including oil-based muds or similar materials used on the instruction of the company), the discharge of contaminated cuttings or storage, use or disposal of radioactive sources arising from or related to the performance of the contract. Subject to certain company-provided indemnities, the contractor indemnifies the company group for pollution originating from the hull of the drilling unit located above or below the surface of the water (excluding oil-based muds or similar materials used on the instruction of the company, the discharge of contaminated cuttings or storage, use or disposal of radioactive sources). II-5.55 Catastrophic loss. Subject to the indemnities the contractor gives for its group’s people, property and pollution, the company indemnifies the contractor against claims, losses, damages, costs, expenses and liabilities including third-party claims resulting from (1) loss of or damage to any well or hole, but where the damage is caused

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by the contractor’s or its subcontractor’s negligence in fulfilling certain specified contractual obligations, the contractor shall, at the company’s request, and provided that the drilling unit is still on site, as the company’s sole remedy re-drill the same or an equivalent hole, or repairing the damaged hole to its original state, with the contractor being paid in accordance with the Remuneration section during such re-drill and/or repair operations; (2) blow-out, fire, explosion, cratering or any other uncontrolled well condition; and (3) reservoir damage or loss of oil and gas therefrom. Common amendments to LOGIC Standard Contracts The changes made to the LOGIC Standard Contracts by way of II-5.56 Special Conditions will depend on the specific circumstances of each contract, including: the parties, their bargaining strength, whether favouring the company or the contractor, the nature of the services and the extent of risk parties are willing to take. Some of the provisions which are commonly amended are: Call-off contracts Many parties now wish to put in place master service agreements II-5.57 (MSAs). In each instance where the company wishes to instruct the contractor to perform services, a call-off order will be put in place specifying the details of the services. The call-off will be performed subject to the overarching terms set out in the MSA. The LOGIC Standard Contracts were not drafted for use as call-off contracts but for one-off scopes of work only. Substantial amendment is required to update the General Conditions to make them suitable for use as call-off contracts (including, for example, e-clauses which set out the procedure for agreeing call-off orders, precedence, appropriate limitations of liability and the effect of multiple scopes of work on the termination provisions). Corporate structure/definition of “Affiliate” This definition may be changed by parties to take their particular II-5.58 corporate structure into account. It is also normally amended (except when using a model that has been updated in the last few years) to take into account the ruling in the case of Enviroco v Farstad.36 In addition, the LOGIC Standard Contracts, as mentioned above, II-5.59 may be amended for use as call-off contracts. Given the corporate structures of many operating entities, operators often wish for more than one affiliate to be included within their corporate group (note

  Enviroco Limited v Farstad Supply A/S [2009] EWCA Civ 1399.

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that this is different from “company group” as defined in the LOGIC Standard Contracts). Again this requires amendment, for example to the “Status of company” clause, and to the relevant definitions (such as company group, affiliate, co-venturer), to ensure that it is clear who is the contracting party. Changes to warranty provisions II-5.60 Parties may wish to include specific warranties depending on the nature of the services or to amend the warranty wording to suit their company style. Mutual hold harmless indemnities II-5.61 The most common change to these indemnity provisions in recent years is the inclusion of a wilful misconduct carve out. The mutual hold harmless indemnities normally apply irrespective of the negligence or breach of duty (statutory or otherwise) of the indemnified party, but where a wilful misconduct carve out is included it results in the indemnity “flying off” where the actions of the party seeking indemnification amount to wilful misconduct and resulted in loss or damage. The term “wilful misconduct” does not have a precise meaning under English law, therefore, it should be defined if used in a contract, otherwise the courts would seek to place their own interpretation on it, which may not be what the parties to that contract intended. It is often defined by reference to a specific tier of senior management personnel and is generally intended to be set at high threshold . Contractor-contractor liability II-5.62 The mutual hold harmless indemnities extend to each party’s group, so the definition of each party’s group is very important. The definition of “company group” in the LOGIC Standard Contract does not include the company’s other contractors (or the subcontractors of such other contractors). The indemnities therefore do not cover liability in respect of incidents between different contractors at a worksite. II-5.63 Whether or not it is appropriate to include the company’s “other contractors” within the definition of company group in supply chain contracts has been a matter of much debate within the industry over the years, and has resulted in the IMHH Scheme37 being put in place by LOGIC38. The IMHH Scheme is considered by LOGIC to be the most appropriate means of dealing with the allocation of liability between a company’s contractors. Often the company will include a   See www.logic-oil.com/imhh (accessed 3 April 2017).   See discussion at para II-6.58.

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Special Condition under which the contractor is to confirm that it is a member of the IMHH Scheme and that it will (or alternatively that it will use reasonable endeavours to) procure that its subcontractors are signatories to the IMHH. Variations clause This clause is quite short in some of the LOGIC Standard Contracts II-5.64 (for example, On- and Offshore Services) and is sometimes not considered sufficient by parties. On the other hand, the construction contract contains a more lengthy variation provision. Depending on the type of services and whether this is a sensitive issues for parties, this clause may be amended to suit the particular circumstances of the contract and any concerns a contractor may have over any additional scopes of work it may be asked to perform. Anti-bribery and corruption (ABC) The majority of LOGIC Standard Contracts were drafted prior to II-5.65 the introduction of the UK Bribery Act 2010, therefore, although they contain an ethics clause, most parties prefer to include updated ABC compliance provisions.39 There is now a LOGIC form ABC (Anti-Bribery and Corruption) clause which has been incorporated into recently updated Standard Contracts in the last few years. However, not all Standard Contracts have been updated to include the ABC clause. Also, some companies have their own standard form ABC clause and prefer to include this for consistency across their contracts. UPDATING LOGIC STANDARD CONTRACTS LOGIC has always requested feedback on the Standard Contracts II-5.66 so that they can be updated as required to meet the needs of the industry. The guidance notes accompanying the contracts state that: “It is intended that these model contracts should be documents that evolve to meet the changing needs of the industry. To this end it is important that the industry provides feedback on its experience with the use of the model contracts. LOGIC requests specifically:

  Companies subject to the UK Bribery Act 2010 (hereinafter “the Act”) will be guilty of a criminal offence if they fail to prevent bribery connected with their business. The defence to this crime is for companies to demonstrate that they have “adequate procedures” in place to prevent bribery and corruption. One part of these “adequate procedures” is to include anti-bribery and corruption provisions in contracts which oblige contractors to comply with the Act and related company procedures.

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uk o i l a nd gas l aw vo l u m e i i (a) details of common areas of concern which give rise to consistent modifications to material terms of the Contract through custom and usage; (b) case histories of the model contracts being either helpful or unhelpful with specific detail of why that was so; (c) recommendations to develop the scope of existing model contracts or additional models which would serve the industry well; (d) suggested modifications or additions to the guidance notes.”40

II-5.67 The most recent updates published are Services (On and Offshore), Edition 3 (March 2014) and Supply of Major Items of Plant and Equipment, Edition 3 (December 2015). The amendments for these updates include the Affiliate definition, the inclusion of a new ABC clause, changes to the dispute resolution clauses to include specific timescales, updates to the tax provisions to account for changes in legislation, as well as a number of other small miscellaneous changes. II-5.68 Some companies have moved away from the LOGIC Standard Contracts, and therefore do not see a need to participate in these working groups, while others are struggling for resources to dedicate to the groups. With the current drive for efficiency in the industry, it may be that companies see a benefit in moving back towards using the LOGIC Standard Contracts. If operators and contractors are not both well represented at the working groups then there is a risk that any updated or new model contracts could be more favourable to one side than the other, and will not fully reflect industry experience, know-how or intent. It is therefore important for the usefulness of the LOGIC Standard Contracts that the working groups continue to attract participants from a wide range of companies. WHAT ARE OTHER JURISDICTIONS DOING? II-5.69 The UK is not the only jurisdiction to use model form service contracts in the oil and gas industry. There are other countries and organisations which have developed model forms. Some examples are noted below.41

  See Supply of Major Items of Plant and Equipment, Edition 3 (December 2015), at p 41.   This sets out a few examples of practice in other regimes and is not intended to be a comprehensive list.

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Norway In Norway, standard contracts have been developed by key operators II-5.70 and contractors since the 1980s42 and these are said to be used extensively.43 The contracts include the Norwegian Fabrication Contract (NF 07), the Norwegian Total Contract (NTK 07) and the Norwegian Total Contract Modification (NTK 07 MOD) which cover fabrication assignments, new construction and modification projects, and offshore modification projects. The newest addition to the Norwegian model form contracts II-5.71 is for offshore engineering, procurement, construction and installation modification projects: the NTK 15 MOD, which was published in 2015. There are two versions to suit different circumstances. They were negotiated by Norsk Olje og Gass (NOROG), acting for the operators, and Norsk Industri, acting for the contractors. It is expected that a new version of the Norwegian Fabrication Contract (NF 07) will follow, the Norwegian Total Contract having been revised in 2015.44 These latest publications (NTK 15 MOD) indicate that there II-5.72 has been a shift in the level of standardisation in Norway, as they leave much more room for negotiation between the contracting parties than previous standard contracts.45 It seems that the reason for this is to achieve broad acceptance of the model forms across industry.46 The USA The International Association of Drilling Contractors (IADC) has a II-5.73 suite of model drilling contracts for US onshore and offshore operations. IADC also developed international model drilling contracts, although these are not normally accepted by operators without significant amendments.47

  Haavind, “New Norwegian Offshore Standard Contracts – NTK 15 MOD”, available at https://haavind.no/en/news/news-norwegian-offshore-standard-contracts-ntk-15-mod (accessed 3 April 2017). 43   Ibid. 44  Haavind, “New Norwegian Standard Contracts – NTK 15 and NTK 15 MOD”, available at https://haavind.no/en/news/new-norwegian-offshore-standard-contracts-ntk15-ntk-15-mod (accessed 23 November 2017). 45   Ibid. 46  Wiersholm, “New standard contracts for the Norwegian shelf – NTK 15 MOD”, available at http://en.wiersholm.no/News/Newsletter--New-standard-contracts-for-theNorwegian-Shelf (accessed 3 April 2017). 47   Martin and Park, “Model Contracts Revisited”, p 21. 42

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Canada II-5.74 The Canadian Association of Oilwell Drilling Contractors (CAODC) developed standard form model drilling contracts in discussion with, amongst others, the Canadian Association of Petroleum Producers (CAPP). It had previously developed drilling contracts on its own, but found that operators were reluctant to sign up to these contracts as they were not considered to adequately represent the operator’s interests.48 International II-5.75 The Association of International Petroleum Negotiators (AIPN),49 a non-profit organisation, has, over the years, developed a number of model form contracts. These contracts are for use internationally (by which is meant anywhere outside the UK and US), rather than for any one particular jurisdiction. The AIPN models include inter alia a seismic acquisition contract, a master services agreement and a well service contract. II-5.76 The AIPN previously attempted to put in place drilling contracts but these have not thus far succeeded as they were not supported by the IADC, which took the view that the AIPN model drilling contracts could be prejudicial to its own models.50 Conclusion on other jurisdictions II-5.77 The conclusion that can be drawn from considering model form service contracts in other jurisdictions is that there is clearly perceived benefit in developing them.51 However, for model contracts to be successful, they must be developed in such a way that they reflect the interests of both operators and contractors. If they do not, they will not attract the endorsement of both parties and the model forms will either be rejected or amended to such an extent as to be almost unrecognisable. WHAT DOES THE FUTURE OF LOGIC CONTRACTS LOOK LIKE? MER UK II-5.78 The Oil and Gas Authority (OGA) “went live” as a government   Ibid.   See www.aipn.org 50   T Martin, “Model Contracts: a Survey of the Global Petroleum Industry”, 22(3) (2007) JENRL, 37. 51   For further comparative discussion, see Martin and Park, “Model Contracts Revisited”, p 14ff. 48 49

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company on 1 October 2016. A product of the Wood Review, the OGA has as its principal objective maximising economic recovery of UK petroleum (MER UK).52 To facilitate this objective it has published a number of strategies, including a Supply Chain Strategy. While the OGA’s remit, strictly speaking, does not cover the supply chain (the OGA is clear in the Strategy’s Executive Summary that it does not directly regulate the service sector), it is self-evident that the supply chain will be affected by the OGA strategies, in particular those affecting costs and contracting practices (such as the Decommissioning Strategy and the Asset Stewardship Expectations). The OGA has established the MER UK Supply Chain Task Force II-5.79 (formerly known as the Supply Chain and Exports Board) to support the UKCS supply chain industry and promote growth. The OGA believes there is scope to grow the sector not only within the UK but also globally, with the view that, ultimately, this will assist in achieving MER UK. The Task Force is a cross between a government and industry II-5.80 body, with the overarching purpose of increasing investment levels in the UKCS and creating more opportunities for the supply chain sector. More specifically, its key aims are: (a) maximising the economic potential of the UKCS – this involves considering costs and efficiency, risk and reward, increased investment and collaboration; (b) anchoring the service sector in the UK – this involves maintaining and developing skill, maintaining a technological advantage and developing new expertise; and (c) increasing the accessible market share by 2035 – this involves identifying areas for growth, considering export markets and exploiting new and developing markets. If these key aims are achieved, the OGA predicts that the UKCS II-5.81 supply chain industry could generate an additional turnover of over £200 billion over the next 20 years. Clearly, with a view to achieving the first of these aims, the benefits of standardisation will be under the spotlight once more, as will innovation in contracting, as operators and contractors look for new ways to work together.53 New LOGIC Standard Contracts The focus in recent years has been on updating the existing LOGIC II-5.82   See further the discussion at Chapter I-5.   The benefits of using LOGIC Contracts, in the MER context, are highlighted in Oil and Gas UK’s new Supply Chain Code of Practice, which is available for download at: http:// oilandgasuk.co.uk/supplychaincodeofpractice.cfm (accessed 3 April 2017).

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Standard Contracts (which is not an insignificant task) rather than producing more forms of contract. The author understands, however, that LOGIC is working on a new Standard Contract for Decommissioning – which, if taken up by the industry, could be one of the tools in working towards a common industry understanding of managing decommissioning contracts. II-5.83 With sufficient industry participation and appetite, other model forms could be created, such as Integrated Services, Call-off terms for various scopes, Waste Management or Facilities Management. Contract automation II-5.84 At the moment, and with the best will in the world, working with LOGIC Standard Contracts can involve a lot of paper. With a view towards further efficiency, the future is bound to involve contract automation, and shared sites where all parties can update and finalise the terms of their contracts.

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CHAPTER II-6 RISK ALLOCATIONIN OIL AND GAS SERVICE CONTRACTS Greg Gordon

As has already been noted, the oil and gas industry is an inher- II-6.01 ently hazardous one.1 Exploring for, producing, transporting and processing volatile hydrocarbons is attended by a whole host of risks: to people, property, the environment, and to the valuable commodity itself. The degree of difficulty associated with these operations, and therefore the level of risk which attends them, is only heightened when – as is commonly the case in the United Kingdom2 – oil and gas reserves are located offshore. The oil and gas industry has developed a number of contracting II-6.02 practices to allow it to regulate and manage these physical3 risks. Generally speaking, and subject to certain important exceptions,4 upand midstream oil and gas contracts seek to depart quite radically from the common law’s presumptions about how such risk should be allocated.5 Three vehicles are commonly used to achieve this reallocation of risk: (1) indemnity and hold harmless clauses; (2) clauses   See the discussion at para I-10.01.   As we have already seen, the UK is, at present, a primarily offshore oil and gas province, although it is possible that this may change as a result of the twin effect of depletion of offshore reserves and the development of unconventional resources. See Chapter I-9. 3   Sometimes also described as “insurable” risk. This chapter is not concerned with other risk factors such as political or geological risk. For a discussion of these risk factors, see Chapter I-4 and the sources cited therein. 4   See para II-6.26. 5   Such clauses are sometimes also called liability allocation provisions. Throughout this chapter, the expression “risk allocation” shall be preferred because at the point when the contracts are drafted and entered into, the parties are looking at the matter prospectively and are concerned with the potential consequences of events which may (or may never) come to pass. 1 2

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which exclude or limit liability for what are commonly, if rather loosely, described as “consequential losses”; and (3) overall limitations on liability. Each will be discussed in turn. INDEMNIFICATION Introduction to the concept of indemnification II-6.03 Courtney defines a contractual indemnity as “a promise to protect another against loss from an event or events, or set of circumstances”.6 An alternative formulation offered by the present author in earlier editions of this work is that an indemnity7 is “a contractual provision whereby the indemnifier agrees to make a payment to the indemnified party in the event that the indemnified party suffers loss as a result of the occurrence of a specified event”.8 Although there is considerable commonality between the two definitions, they differ in one material respect: Courtney suggests that the obligation is to “protect” against the consequences of an event. This may involve the payment of a sum or money by the indemnifier to the indemnified, but may also embrace some other form of prevention: for instance, the waiver of a claim that would otherwise have existed. The present author’s formulation, by contrast, is focused solely upon payment, meaning that, if some form of protection beyond payment is required, this must be obtained by a device other than indemnity. It is submitted that although Courtney’s definition is consistent with the way that indemnity has been expressed historically,9 the present author’s formulation is more consistent with the approach adopted in the leading Supreme Court case on the specific risk allocation provisions used in the oil and gas industry.10

 W Courtney, Contractual Indemnities (2014) (hereinafter “Courtney, Contractual Indemnities”), para 1-2. A Scots lawyer might query the use of the word “promise” and prefer a slightly revised formulation premised upon “agreement” or “consent”. To the Scots lawyer, a promise is a free-standing obligation, related to but distinct from contract: see eg Stair, Institutions, 1.10.4. For a theoretical account of contract which recasts traditional promissory theory in terms of consent, see R Barnett, “Contract is not Promise: Contract is Consent” in G Klass, G Letsas and P Saprai (eds), Philosophical Foundations of Contract Law (2014), pp 42–57. 7  That is, a contractual indemnity. Not all indemnities are contractual: some arise as a result of operation of law. See Courtney, Contractual Indemnities, paras 1.5–1.8. 8   G Gordon, J Paterson and E Üșenmez, Oil and Gas Law: Current Practice and Emerging Trends (2nd edn, 2011), para 14.3. Note that in the original the rather cumbersome phrases “indemnifying party” and “party having the benefit of the indemnity” were used instead. In this edition I have substituted “indemnifier” and “indemnified”. 9  See eg Firma C-Trade SA v Newcastle Protection and Indemnity Association (“The Fanti”) (No 2) [1991] 2 AC 1 (HL). Courtney, Contractual Indemnities, para 2.6. 10   See further the discussion at II-6.05. 6

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As we shall see, indemnification is – at least in some contexts – a II-6.04 contractual device which the courts have treated with considerable suspicion.11 It is nevertheless a commonly encountered legal concept, by no means particular to oil and gas contracts. Indemnification lies at the heart of the law of marine12 and fire13 insurance. It also features in construction contracts, where contractors will commonly provide their employer with indemnities against personal injury or death, or damage to property, in any way associated with the work contracted for,14 as well as in the aviation and shipping industries.15 The concept will also be familiar to the company lawyer: in a corporate acquisition and disposal, the seller will frequently be asked to provide an indemnity in respect of liabilities incurred by the company in the period between the deal’s conclusion and its completion.16 Many other examples could be given.17 For the remainder of this chapter, the one-sided18 indemnity clauses just described will be referred to as simple indemnity clauses in order to differentiate them from mutual indemnity clauses, which will be discussed below.

Indemnity and hold harmless clauses As we shall see in greater detail below, the oil and gas industry makes II-6.05 extensive use of a particular form of wording in its risk allocation clauses. A party will very often offer not merely to indemnify, but to indemnify and hold harmless, the other party.19 Before the UK

  See paras II-6.11 and II-6.43.   Marine Insurance Act 1906, s 1: “A contract of marine insurance is a contract whereby the insurer undertakes to indemnify the assured, in manner and to the extent thereby agreed, against marine losses.” 13   Castellain v Preston [1883] 11 QBD 380 per Brett LJ, at 386. 14   See the Joint Contracts Tribunal Standard Form of Contract, cll 6.1 and 6.2 respectively, discussed at J Uff, Construction Law (9th edn, 2005) at p 380f. For an illustration of cl 6.1.2 in operation, see Scottish & Newcastle plc v G D Construction (St Albans) Ltd [2003] EWCA Civ 16. 15   In this connection, see eg S Rainey, The Law of Tug and Tow and Offshore Contracts (3rd edn, 2011), pp 155–196. 16  See eg J Young and J Kitching, “Buying and Selling a Business: Warranties and Indemnities”, 6(10) 1995 ICCLR 336. For a discussion in the specific context of the sale and purchase of and oil and gas business, see Chapter II-13. 17  For instance, one of the leading cases on the construction of indemnities (discussed further at para II-6.38) is concerned with a lease: Canada Steamship Lines v The King [1952] AC 192. 18  The term “one-sided” is here used not to suggest that simple indemnity clauses are necessarily unfair or biased, merely to denote the fact that in a simple indemnity clause, the indemnity travels in one direction only – from the indemnifier to the indemnified party. No reciprocal indemnity is provided. 19   That said, clauses which utilise the word “indemnify” are not unknown in an oil and gas context, particularly in contracts relating to maritime matters such as towage: see eg 11 12

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Supreme Court decision in Farstad Supply AS v Enviroco Ltd,20 commentators on the industry’s risk allocation practice generally considered the words “and hold harmless” to add little or nothing to the content of such clauses, which were simply described as “indemnity clauses”.21 It is submitted that this approach was both rooted in the long-standing legal usage of the terms “indemnity” and “hold harmless”22 and accurately mirrored that of the oil and gas industry. The oil and gas industry routinely used the terms “indemnify”, “hold harmless” and “indemnify and hold harmless” interchangeably in its risk allocation arrangements. Thus, in the LOGIC Standard Contracts for the Oil and Gas Industry, clauses by which a party indemnifies and holds harmless the other are described simply as “Indemnities”.23 Similarly, while the industry’s attempt to put in place a contractual risk allocation regime between offshore contractors, who would not otherwise have a contractual relationship,24 is known throughout the industry as the Industry Mutual Hold Harmless Deed,25 the Deed is formally entitled the “Mutual Indemnity and Hold Harmless Deed”.26 Although the Deed’s central risk allocation clause uses the wording “indemnify and hold harmless”, the clause is entitled “Indemnities by the Signatories”27 and the Deed is itself referred to in the Deed of Adherence (by which parties other than the original signatories can

TOWCON cl 18 referred to in A Turtle Offshore SA v Superior Trading Inc [2008] EWHC 3034 (Admlty), [2008] 2 CLC 953, a case concerning the towage of an ill-fated drilling rig. 20   [2010] UKSC 18, 2010 SCLR 379 (hereinafter “Farstad v Enviroco”). 21   See eg Chapter 13 of the first edition of this work; G Gordon, “Indemnification and Contribution: Farstad Supply AS v Enviroco Ltd”, 14 (2010) Edin LR 102; T Hewitt, “Who is to Blame? Allocating Liability in Upstream Project Contract”, 26 (2008) JENRL 177 (hereinafter “Hewitt, ‘Who is to Blame?’”), at 182; T Daintith, G Willoughby and A Hill, United Kingdom Oil and Gas Law (3rd edn, looseleaf, 2000–date) (hereinafter “Daintith, Willoughby and Hill”), para 1-845; D Sharp, Offshore Oil and Gas Insurance (1994) (hereinafter “Sharp, Offshore Oil and Gas Insurance”), at p 108. 22   See eg Firma C-Trade SA v Newcastle Protection and Indenity Association (The Fanti) (No 2) [1991] 2 AC 1 (HL) per Lord Goff at 35: “a promise of indemnity is simply a promise to hold the indemnified person harmless against a specified loss or expense”. Courtney, for example, considers the expressions “indemnity”, “save harmless” and “keep harmless” to all fulfil the same function within the indemnity clause. Courtney, Contractual Indemnities, para 1-3. See further Courtney, Contractual Indemnities, para 8-11. 23  See eg LOGIC, Supply of Major Items of Plant and Equipment (3rd edn), cl 21, available at www.logic-oil.com/content/standard-contracts-0 (accessed 27 April 2017). 24   Discussed further in paras II-6.77 to II-6.82. 25  See eg LOGIC, Industry Mutual Hold Harmless: Introduction and Background, available for download from www.logic-oil.com/imhh (accessed 27 April 2017). 26  LOGIC, Mutual Indemnity and Hold Harmless Deed, available for download from www.logic-oil.com/imhh/documents (accessed 27 April 2017). 27   Ibid, cl 2.

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enter the scheme) as the “Indemnity Deed”. However, in Farstad v Enviroco the Supreme Court held that a clause whereby the owner of a vessel under charter agreed to “indemnify and hold harmless” the charterer against all liability resulting from loss of or damage to the vessel was not a pure indemnity clause but a mixed provision containing elements of (on the one hand) indemnity and (on the other) an exclusion or waiver of liability.28 Whether it operated as an indemnity or an exclusion would depend upon whether the clause sought to determine who was to bear responsibility for “third party exposure” (in which case the clause would be an indemnity) or whether it resolved “direct exposure to the other contracting party” (in which case the “hold harmless” dimension would be activated, and it would be an exclusion or waiver of liability).29 On the facts of the case in question, the owner had suffered damage to his own property. The case was therefore seen by the Supreme Court as one of “direct exposure”; hence the clause was, on this occasion, to be seen as an exclusion of liability clause.30 This would suggest that there will be occasions when such clauses will have to comply with the provisions of the Unfair Contract Terms Act 1977.31 See further the discussion at para II-6.26. Mutual indemnity and mutual indemnity and hold harmless clauses A mutual indemnity – sometimes also called a “reciprocal indemnity”, II-6.06 a “cross-indemnity” or a “knock for knock” indemnity – is a contractual device where the parties with the one hand give and with the other hand take an indemnity in respect of a species of loss which, if the indemnity is to avoid circularity,32 must not be

  In so holding, their Lordships laid considerable emphasis upon the fact that the parties to the contract had entitled their clause “Exceptions/Indemnities”. This, thought Lord Clarke (delivering a speech concurred in by Lord Phillips), was a feature of “particular importance”, and strong evidence of the parties’ intentions (Farstad v Enviroco per Lord Clarke at para 22; see also Lord Mance at para 56). However, their Lordships seem to have failed to notice that there were a number of indications of a contrary intention within the clause, including the obligation to exchange “mutual hold harmless indemnities” with other parties in certain circumstances. This wording might tend to suggest that the words “hold harmless” were intended only to describe a particular type of indemnity clause. Speculation is to an extent idle, but given the importance apparently attached to the title of the clause, one cannot help but wonder how their Lordships’ decision would have differed had the parties followed the form of the LOGIC contracts and entitled their clause “Indemnities”. 29   Farstad v Enviroco per Lord Mance, para 59. 30   Ibid per Lord Clarke, at para 29, and per Lord Mance, at para 59. 31   Although the Unfair Contract Terms Act 1977 has been superseded by the Consumer Rights Act 2015 in the context of consumer contracts, UCTA continues to govern the regulation of exemption clauses in the business to business context. See eg UCTA s 2(4). 32   Circularity is discussed later in this paragraph. 28

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identical to each other, but which are usually closely related. A mutual indemnity therefore differs from a simple indemnity, where one party consistently has the burden of giving the indemnity (acts as indemnifier) and the other party consistently has the benefit of being indemnified. In a mutual indemnity, each party is simultaneously both an indemnifier (in relation to one species of loss) and the indemnified (in relation to a different, but related, species of loss). In the oil and gas context, it is usual for the parties to enter into not just mutual indemnity provisions but into mutual indemnity and hold harmless clauses, thus bringing into play the further conceptual issues described at para II-6.04. II-6.07 It is important to appreciate that, to be effective, a mutual indemnity or mutual indemnity and hold harmless clause must not be drawn so as to provide that each party indemnifies (or indemnifies and holds harmless) the other against the occurrence of exactly the same species of loss. To illustrate the point by way of example, let us imagine that A and B enter into an arrangement where A grants B an indemnity against B’s house burning down, and B also grants A an indemnity against B’s house burning down. In such a situation, all the clause succeeds in achieving is a position where the losses arising if the house burns down is passed from one party to another ad infinitum. Such a clause (sometimes described as a “circular indemnity”)33 is ineffectual34 and leaves the risk it purports to allocate to be borne by the parties in the way provided for by the law at large. II-6.08 Let us now consider an example where A indemnifies B in respect of the losses incurred by B if B’s house burns down, and B in turn indemnifies A against the losses that A suffers if A’s house burns down. At first glance this may look similar to the example given immediately above. There is, however, one crucial difference. The species of loss in respect of which the indemnity is given, although conceptually related (they both pertain to the losses suffered when houses burn down) are not exactly the same: A agrees to accept the losses to B’s property, and B agrees to accept the losses to A’s property. Thus the parties have, on this occasion, avoided circularity and succeeded in reallocating the respective risk factors.   Slessor v Vetco Gray, unreported, 7 July 2006, Court of Session, Outer House, available for download from www.scotcourts.gov.uk/search-judgments/judgment?id=2fbb86a68980-69d2-b500-ff0000d74aa7 (accessed 27 April 2017). See the submissions of counsel summarised by Lord Glennie at para 6. On the facts, the court rejected the argument that the indemnity was circular. 34   It is also commercially unrealistic: why on earth would B indemnify A against the loss of B’s own house? However, the example is given because in practice one does, from time to time, encounter circular indemnities – almost invariably they arise by accident, when something has gone wrong in the drafting of the indemnity clause. 33

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Indemnity and hold harmless provisions in context Introduction to simple indemnity and hold harmless clauses in oil and gas contracts Simple indemnity clauses are used in oil and gas contracts in at least II-6.09 two ways. First, the petroleum industry sometimes just provides the commercial context for the kind of risk factor described at para II-6.03. Oil and gas contracts therefore commonly contain a number of simple indemnity clauses of a type no different from those routinely found in commercial agreements. In addition, some, but by no means all,35 up- or midstream oil and gas contracts will also contain one or more simple indemnity and hold harmless clauses designed to allocate between the parties some of the risk factors specific to the petroleum industry. These clauses will frequently be supplemented by a provision stating that the indemnifier36 will not just indemnify and hold harmless the indemnified party, but also defend claims taken against the indemnified party.37 This has the effect of imposing upon the indemnifier the burden of conducting the defence of any litigation that may arise, but also of conferring upon the indemnifier the right to control the manner in which the defence is conducted. Many indemnifiers consider that the benefit of the right to control the conduct of the defence outweighs the burden of conducting it. Best practice is now thought to be not to rely solely upon the word “defend” but to include a conduct of claims clause expressly stipulating the way in which claims are to be handled. Such a clause is absent in the present draft of the LOGIC standard form contracts, but is commonly revised into contracts based upon the LOGIC standard forms. Many examples could be given of occasions where one party II-6.10 will usually offer the other the benefit of a simple indemnity and hold harmless provision. As we have already seen at para II-2.39,   See para II-6.26.   Although, as we have seen, the Supreme Court held in Farstad v Enviroco (discussed at para II-6.05) that the words “hold harmless” add an additional element to an indemnity clause, meaning that indemnity and hold harmless clauses will in certain circumstances operate not merely as indemnities but also as exclusion clauses, for the sake of brevity and convenience: the parties giving and receiving these clauses will be described as the indemnifier and the indemnified party throughout this chapter. 37   See the observations by Lord President Rodger in the Inner House phase of Caledonia North Sea Ltd v London Bridge Engineering Ltd 2000 SLT 1123 at 1155. The Standard Contracts for the oil industry developed as part of the CRINE initiative and now maintained by LOGIC contain such a provision: see eg LOGIC, General Conditions of Contract for Services (On- and off-shore) (3rd edn, 2014), available for download from www.logic-oil.com/content/standard-contracts-0 (accessed 27 April 2017) (hereinafter “LOGIC, Services”) at cl 19.1: “The contractor shall … [s]ave, indemnify, defend and hold harmless …”. See also the discussion on the IMHH deed at para II-6.66. 35 36

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a joint operating agreement will commonly contain a clause by which the non-operators cumulatively and in accordance with their respective percentage interests indemnify and hold harmless the operator against all losses incurred by the joint venture, with the exception of those occasioned by the operator’s wilful misconduct. The justification is that, as the operator acts gratuitously, it would be inequitable if it were to bear all or a disproportionate share of the joint venture’s commercial risk. And in operator-to-contractor contracts which involve the creation of, or direct intervention with, the well – for instance, contracts for the hire of a mobile drilling unit38 or for the provision of well services39 – the indemnity and hold harmless provisions are usually significantly more complex than those associated with other operator-to-contractor contracts. The operator will ordinarily indemnify and hold harmless the contractor against risks such as loss of or damage to the hole,40 blow-out, fire, the well becoming uncontrollable or damage to the reservoir, geological formation or underground strata, howsoever caused. II-6.11 The courts have sometimes viewed indemnity clauses with suspicion, on the basis that when they are found in a contract, this is because a dominant party has imposed them upon a weaker one.41 However, in UKCS operator-to-contractor agreements, unilateral indemnity and hold harmless clauses are most commonly granted by the operator to the contractor.42 Such indemnities are not given because the operator is weak, but because it is strong. The losses that could accrue in the event that the well is lost or damaged are potentially very substantial; so large that it might not be economic, or perhaps even possible, for

 See eg LOGIC, General Conditions of Contract for Mobile Drilling Rigs (2002), available for download from www.logic-oil.com/content/standard-contracts-0 (accessed 27 April 2017) (hereinafter “LOGIC, Mobile Drilling Rigs”), at cl 18. 39  See eg LOGIC, General Conditions of Contract for Well Services (2nd edn, 2002), available for download from www.logic-oil.com/content/standard-contracts-0 (accessed 27 April 2017) (hereinafter “LOGIC, Well Services”) at cl 19. 40  However, these indemnities may differ somewhat in their precise content. Note, for instance, that in LOGIC, Well Services, cl 19.9(a) the operator offers a full indemnity in respect of loss of or damage to the hole, while in LOGIC, Mobile Drilling Rigs, cl 18.6(a) an indemnity is given subject to a (quite tightly confined) carve-out provision in respect of damage to hole caused by contractor’s negligence. “Carve outs” (qualifications to indemnities) are discussed at paras II-6.23 to II-6.25. 41   This belief informs US controls on indemnification which are discussed further at para II-6.28. See also the discussion of the Orbit Valve case at para II-6.38. 42  Perhaps the major exception to this is in the case of offshore construction works, where the contractor will commonly be asked to provide a one-sided indemnity to the operator in respect of the recovery, removal or marking of any wreck or debris associated with the work under the contract: see eg LOGIC, General Conditions of Contract for Marine Construction (2nd edn, 2004), at cl 22.2(5)(a), available for download from www. logic-oil.com/content/standard-contracts-0 (accessed 10 September 2017). 38

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contractors to obtain insurance against these contingencies. However, the operator requires the well to be drilled if he is to produce from the discovery, and is (or traditionally has been – given the changing face of the UKCS, this proposition is no longer universally true) of a sufficient size to absorb the losses if they come to pass.43 It is (or has been) therefore willing to accept them. The author is, however, aware of at least one area where the II-6.12 industry’s practice is less innocent. It is not unknown for oil and gas companies entering into contracts with employment agencies for the provision of workers to demand an indemnity from the agency against the risk that the workers make an employment tribunal claim against the company, and to seek to justify this on the basis that this is a standard oil industry indemnity clause. With respect, it is nothing of the kind. This has nothing to do with the sorts of physical or insurable risks which have thus far been under discussion; it is instead an attempt to secure an indemnity in relation to a commercial risk of a nature which it is inequitable to ask the agency to bear. Such use of indemnity clauses is to be deprecated. Introduction to mutual indemnity and hold harmless provisions in oil and gas contracts As has already been noted, the oil and gas industry is by no means II-6.13 alone in making use of indemnity clauses. However, the oil and gas industry utilises indemnity and hold harmless clauses in a more thoroughgoing way than most other industries. This is borne out by, for example, the amount of time invested by the court in Caledonia North Sea Ltd v London Bridge Engineering Ltd (hereinafter “London Bridge”)44 in examining the particular features of the oil industry which give rise to what is still viewed as an unusual and rather counter-intuitive practice.45 There is a tendency to view mutual indemnity and hold harmless II-6.14 provisions as difficult clauses to draft and understand.46 There is

  As the UKCS matures and a more diverse set of companies become operators, there will be a greater need for operators to carry insurance against such risks. 44  Rather confusingly, as a number of defenders settled the claims against them and dropped out of the case in the period between the Inner House appeal and the case’s hearing in the House of Lords, the House of Lords phase of the case is reported as Caledonia North Sea Ltd v British Telecommunications plc. In the interests of consistency the case will be referred to as “London Bridge” throughout. 45   In the Inner House of the Court of Session (London Bridge, 2000 SLT 1123) See eg s 2.5 of Lord Rodger’s speech, from 1150, Lord Sutherland at 1174E–F and L, and Lord Gill at 1213F–H. In the House of Lords (London Bridge, or see British Telecommunications plc 2002 SC (HL) 117, [2002] 1 All ER (Comm) 321), see Lord Bingham, at paras 7–9, and Lord Hoffmann, at paras 81–82. 46   See eg D Peng, “Mutual Indemnities in North Sea Contracts – Liability and Insurance 43

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some justification for this. Even experienced lawyers or contract analysts entering the oil and gas industry for the first time may find that it is not easy to draft a wholly satisfactory set of indemnity provisions,47 as is attested by the failed attempts and narrow squeaks which litter the case reports.48 All that said, most of the problems that arise with indemnification are essentially points of detail emerging because of the complexity and hazardous nature of the operations and risks that the contract seeks to govern.49 These difficulties are generally susceptible to being resolved by careful thought and skilful drafting, although this can lead to lengthy and complex clauses.50 However, following Farstad v Enviroco, the twin questions of what is the true legal nature of the clause and what consequences flow from its legal nature arise much more acutely than previously. II-6.15 While there are certainly difficulties here, the commercial purpose of an indemnity and hold harmless clause is quite simple. The parties are allocating (more properly, reallocating)51 between themselves the risk of loss associated with the occurrence of a particular event. As we have already seen, in the context of a simple indemnity and hold harmless clause, one party is agreeing that (within the parameters of this particular contract) it is better placed than the other to bear the risk of a particular type of loss.52 By contrast, in the case of a mutual indemnity and hold harmless clause, the parties are generally saying that neither of them should have sole responsibility for a particular species of risk – for instance, the risk that people engaged on the contract may be injured or killed – but that it is appropriate to divide between themselves the responsibility for that type of risk. The clause will therefore commence with the party identifying the aspect(s) of a given type of loss for which it is willing to take responsibility, and those in respect of which it is not. Each party then agrees to indemnify and hold harmless the other in respect of the element of the potential loss that it has accepted, and in return receives the benefit of an indemnity and Clauses”, in D Peng (ed.), Insurance and Legal Issues in the Oil Industry (1993), at p 156. 47  The presence of industry-accepted styles such as the LOGIC contracts referred to at paras II-6.09 and II-6.10 and the IMHH Deed described at paras II-6.58 to II-6.76 makes the process less daunting than once it was, albeit that, as with all styles, the terms of these documents should never be adopted uncritically. 48   See the cases and issues discussed throughout paras II-6.38 to II-6.54. 49   See Chapter II-4. 50   See eg LOGIC, Mobile Drilling Rigs, cl 18. 51   This exercise does not take place in a vacuum; the law has a pre-existing view on how, in the absence of agreement, such risks should be borne. See further the discussion at para II-6.27. 52   See paras II-6.04 and II-6.08 to II-6.10.

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hold harmless provision relative to the aspect of the potential loss accepted by the other party. So if A and B are respectively an oil company and a contractor who have entered into a contract, in a typical mutual hold harmless indemnity provision pertaining to the risk that personal injury or death will befall one or another of the parties’ personnel while engaged on the contract,53 A will confirm that it accepts responsibility for any injuries or fatalities suffered by A’s own personnel, however caused, and that it will indemnify and hold harmless B in respect of that category of loss. B agrees the converse: that it will accept responsibility for any injuries or fatalities suffered by B’s own personnel, irrespective of how these were caused, and that it will indemnify and hold harmless A in respect of such loss.54 Mutual indemnity and hold harmless provisions will also II-6.16 commonly be agreed in relation to other categories of risk. An operator-to-contractor agreement will typically also contain such a clause in respect of loss of or damage to property, where A confirms that it accepts responsibility for loss of or damage to A’s property, however caused, and that it will indemnify and hold harmless B in respect of that category of loss; and B agrees to accept responsibility for loss of or damage to B’s property, howsoever caused, and indemnifies and holds harmless A relative to such losses.55 Pollution risk will also sometimes be divided up along similar lines, with the contractor accepting certain kinds of pollution – commonly, that emanating from its own equipment – and the operator accepting other kinds – typically, all other instances;56 however, it is important to note that indemnities for pollution risk are more likely than those already discussed to be cut into by a qualification.57 Consequential losses will also commonly be the subject of exclusions or indemnity provisions; see further the discussion at paras II-6.77 to II-6.82.

 Such as may be found throughout the suite of LOGIC Standard Conditions: See eg LOGIC, General Terms and Conditions of Contract for Supply of Major Items of Plant and Equipment (3rd edn, 2015), available for download from www.logic-oil.com/content/ standard-contracts-0 (accessed 27 April 2017) (hereinafter “LOGIC, Supply of Major Items”), cll 21.1(b) and 21.2(b). For a discussion on the potential impact, following Farstad v Enviroco, of the Unfair Contract Terms Act 1977 upon such clauses, see para II-6.28. 54   For a discussion of drafting issues relative to “personnel” and cognate phrases, see para II-6.53. 55   For an example of such sub-clause, see LOGIC, Supply of Major Items, cll 21.1(a) and 21.2(2). For a discussion of drafting issues concerning the definition of “property”, see para II-6.54. 56   See LOGIC, Mobile Drilling Rigs, cll 18.3 and 18.4. 57   See paras II-6.23 and II-6.24. 53

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The rationale for a mutual indemnity and hold harmless regime in the oil and gas context II-6.17 The rationale underlying simple indemnity and hold harmless provisions has already been given.58 A number of factors have been advanced as the reason for the oil and gas industry’s use of mutual indemnity and hold harmless clauses. In the leading work on UK offshore oil and gas insurance, the rationale for is presented thus: “If an individual is injured he will expect to have a right to sue any party who may have been guilty of negligence leading to the circumstances which caused the injury. This party may be another contractor, the Principal or his employer, or any combination of all three. The issue can become complicated by reason of contributory negligence. Determining liability and awarding costs can be a lengthy process in these circumstances, and this can only add to the anguish of the injured party, or the dependents of the deceased who may have been the sole breadwinner. The employer therefore accepts a responsibility to provide for his employees and will generally give the party with whom he is contracting a full indemnity in respect of any suit or action brought against that other party.”59

II-6.18 Sharp’s justification was accepted by several of the judges in London Bridge, the main piece of litigation to arise out of the Piper Alpha disaster.60 However, it is only partially convincing. By definition, it can only serve to explain why the industry adopts such an approach in relation to personal injury; it cannot explain why the industry takes a virtually identical approach in relation to damage to property,61 or a broadly similar approach in relation to other matters such as pollution costs and consequential loss. It is certainly true that by and large the industry prefers swift and certain resolution to its disputes, and that it does not generally favour time-consuming and costly litigation.62 But in so far as Sharp suggests that the primary   See paras II-6.08 to II-6.10.  Sharp, Offshore Oil and Gas Insurance, at p 108. 60   In the House of Lords phase of the case, reported at 2002 SC (HL) 117, [2002] 1 All ER (Comm) 321, see the dictum of Lord Bingham at para 7 and that of Lord Hoffmann at para 82. In the earlier Inner House phase, reported at 2000 SLT 1123, see Lord President Rodger (who is rather more agnostic about Sharp’s justification than his colleagues) at 1150L–1151B, Lord Sutherland at 1174F, Lord Coulsfield at 1202K and Lord Gill at 1213J–K. 61  While, tragically, it makes perfect sense to talk of the anguish of the family in the context of a fatal injury, it makes no sense at all to describe property losses in these terms. When an oil tool is lost over the side of a vessel, it does not leave a grieving spouse and family behind. 62  See eg Peng “Mutual Indemnities”, at 157. Among the main reasons given for the practice are “that it permits the parties to assess and accept the risks more easily” and that “it avoids delays in claim settlement and it reduces the fighting of lawsuits”. However, it is not immediately apparent to the present author that indemnification reduces disputes. 58 59

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reason for the existence of the mutual indemnity regime is the industry’s desire to give an effectual remedy to, or diminish the anguish of, the injured party or his dependants, he would seem to overstate his position. If that truly were the industry’s intention, it has not implemented it very effectively. The mutual indemnity and hold harmless regime is not a system of strict liability so far as the injured worker is concerned; while it determines who will ultimately pick up the bill for a personal injury claim, for there to be a personal injury claim in the first place: the injured worker must establish that someone is legally liable for the injury. It is, moreover, unrealistic to suggest that such altruistic concerns II-6.19 lie at the very heart of the industry’s approach to risk allocation. Diminution of levels of anguish is more likely to be a fortunate sideeffect of the practice than its raison d’être. The principal reasons for the mutual indemnification regime are far more likely to be business ones. This was recognised by Lord President Rodger in the Court of Session phase of London Bridge when he noted that the practice of indemnification was “fundamental to the economics of the North Sea operation”.63 Insurance (and the broader but related concept of risk management) is the economic driver that makes this so.64 It may at first sight be surprising that something which seems to be an ancillary matter should be so fundamental. However, in a high-risk

Clauses are scrutinised carefully before claims are accepted and, if there is disagreement between the parties (or, more particularly, between the parties’ insurers) about the proper construction of the clause, litigation will follow which may prove to be time-consuming and costly: see eg London Bridge. The Piper Alpha disaster occurred on 6 July 1988. The proof began on 3 March 1993; in all, 391 days of evidence were heard. The case was not finally concluded until judgment was handed down in the House of Lords on 7 February 2002. See also the comments of Circuit Judge Brown in Fontenot v Mesa Petroleum Co, quoted by Lord President Rodger in London Bridge [2000] SLT 1123 at 1151C–F. It may be that in some cases the fact of indemnification brings a quicker resolution to the claim of the injured party: this seems to have occurred in both London Bridge and Campbell v Conoco (UK) Ltd [2003] 1 All ER (Comm) 35 at para 6. Even this, however, does not seem to be a universal truth: see the experience of the pursuer in Slessor v Vetco Gray. The pursuer suffered severe injuries in an accident in May 2003. Liability was in principle established on 23 March 2007 (see 2007 SLT 400) but even then a number of issues remained outstanding, among them the construction of the contractual indemnity clause, discussed further at paras II-6.48 to II-6.49. 63   London Bridge 2000 SLT 1123, at 1150I. 64   See Daintith, Willoughby and Hill, para 1-845: “The client will, any event, normally carry insurance cover for his own employees and his own property and the cost of this insurance would not be reduced if the particular contractor was also required to be insured against the same risks. It is thus normal for the client and the contractor to assume full liability, and give each other mutual indemnities, for claims arising out of death of or injury to their own employees and for loss or damage to their own property … regardless of any negligence or default on the part of the other party or its employees, agents or sub-contractors.”

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endeavour such as the offshore oil and gas industry, insurance premiums are not marginal costs but major expenses.65 II-6.20 If the contractual arrangements associated with oil and gas operations were simple, the mere fact that insurance is expensive might not justify the effort of superimposing a risk allocation model upon that already provided by law. However, they are not. In London Bridge, Lord Bingham identified two key features which were central to the industry’s risk allocation regime. The first was the hazardous nature of oil and gas operations, which we have already discussed. The second was “the involvement of many contractors and sub-contractors”.66 Oil platforms are not staffed wholly, or even mainly, by the operator’s own personnel. At any given moment in time, one can reasonably expect there to be representatives from upwards of 20 other companies on board.67 If a large proportion of these companies were required to carry insurance against the fairly remote, but potentially catastrophic, risk that they might cause or contribute towards the destruction of the platform and/or widespread injury or loss of life among those on board,68 then, always assuming that such insurance cover could be obtained, the cumulative cost of doing so would be very considerable. In addition, parties’ separate policies would simply run in parallel, and in the event of a catastrophic event (assuming that the cause of the calamity could be

  So great is the expense that some super majors commonly choose to self-insure (ie not to enter into contracts of insurance) where the law permits: see eg BP, Annual Report and Accounts 2005, at 26, “INSURANCE: The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than being spread over time through insurance premiums with attendant transaction costs.” This choice may seem startling, but as insurers are commercial organisations who include a profit element in the price of their premiums, if one is sufficiently asset-rich to be able to absorb serious one-off losses, one should find that, in the long term, it is more efficient not to insure than to do so. Naturally, however, this approach is too high-risk to be prudent for smaller companies. 66   2002 SC (HL) 117, [2002] 1 All ER (Comm) 321 per Lord Bingham of Cornhill, at para 2. 67   For instance, of the 165 people on the platform who lost their lives in the Piper Alpha disaster (167 people died in all; two were crew of the fast rescue ship Westhaven), 31 were employed by the operator. The remaining 134 were employed by 24 different contractors: see London Bridge 2002 SC (HL) 117, [2002] 1 All ER (Comm) 321 per Lord Bingham of Cornhill, at para 2. See also LOGIC, Introduction & Background to the Industry Mutual Hold Harmless, available at www.logic-oil.com/imhh (accessed 27 April 2017). 68   Not all contractors would necessarily be in a position to cause catastrophic loss. It is hard to imagine, for example, that the catering contractor could cause the total loss of a platform. But a fire in the kitchen or major food poisoning incident on a platform might very well cause the installation to be shut down for a period of time, potentially causing significant loss of profit. For a further discussion on claims for loss of profit, see the discussion on consequential loss in paras II-6.77 to II-6.82. 65

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identified, and was attributable to one contractor) only one policy would be claimed upon, and the remaining contractors’ policies, and that of the operator, would prove to have been surplus to requirements. This would add considerably to the cost of operations without adding any value to them. Counter-intuitive as it may at first appear, on analysis it can be seen that there are sound economic and operational reasons for the practice of mutual indemnification. Back-to-back indemnity and hold harmless provisions in oil and gas contracts Although at any given time there may be somewhere between 20 II-6.21 and 50 contractors on a producing platform, only a handful of these parties will be in a direct contractual relationship with the operator. So, for instance, in the production phase of a platform’s life, the operator will ordinarily enter into a handful of lead contracts through which it will entrust important parts of the platform’s functions to three or four contractors – typically a rig services manager, a well services supervisor and a drilling company. Most of the other “contractors” represented on the platform will be in a direct contractual relationship not with the operator, but with either the layer of contractors just described, or with their subcontractors. Viewed from the operator’s perspective, these parties will be subcontractors, sub-subcontractors and so on. Thus, at any given time,69 there will be a number of chains of contractual relationships in place.70 The significance of the above to is that every link in the chain is II-6.22 a contract in which the parties have to agree how to allocate risk as between themselves. The full economic benefits71 of instituting an indemnity and hold harmless regime do not accrue if only some of the parties are included in it; moreover, if some parties are part of the regime and others are not, there is a serious risk of misunderstandings as to who bears which risk, and of accompanying litigation, gaps in insurance cover and uninsured losses.72 The general practice is therefore for each of the contracts within the chain to  Although the example focuses on the case of a producing platform, the position is similar in other phases of the platform’s life. When it is being constructed, overhauled or decommissioned the usual position is for the operator to contract with a limited number of lead contractors and for them to let out parcels of work to appropriate subcontractors. 70  See Fig. II-6.1 for an illustration of one of these chains; see Fig. II-6.3, part of para II-6.55, for an illustration of how these various chains fit together. 71   Discussed at paras II-6.17 to II-6.20. 72   Farstad v Enviroco demonstrates the dangers which can be posed by the interaction between the contractual risk allocation provisions and the statutory law of contribution: see G Gordon, “Indemnification, Exclusion and Contribution: Farstad in the Supreme Court”, 15 (2011) Edin LR, 259–265. 69

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contain so-called “back-to-back” provisions. The overall intent of such a set of provisions is generally that, when all the clauses are read together across the set of contracts, they should have the effect that, in respect of the risk element(s) with which the indemnity clauses deal, each party in the chain bears the loss or damage directly identified with it, and such loss only. However, achieving this result requires something of a leap of faith. To make the losses migrate to the appropriate point in the chain, a contracting party has to, in the anterior contract, assume responsibility not just for the losses identified with itself, but also for the losses of the parties below it on the chain. However, in the posterior contract, it will require to be indemnified and held harmless by its subcontractor in respect of all losses identified with the subcontractor, and any subcontractors lying down the chain of whatever level. Equally, in the posterior contract, the subcontractor will demand an indemnity and hold harmless clause from the contractor in respect not just of the contractor’s losses, but also those of the parties lying above him in the chain. The contractor will give that in the knowledge that in the anterior contract, he should already have obtained an indemnity in respect of the losses identified with the parties above him in the chain. Thus if a set of back-to-back mutual hold harmless indemnities pertaining to personnel and property operate as the parties intended, the operator will ultimately carry the risk of injury to or death of its own personnel and loss of or damage to its own property, but not any like losses suffered by the lead contractor or its subcontractor; the lead contractor will bear the risk of injury or death in respect of its own personnel and loss of or damage to its own property, but not any like losses suffered by the operator or the subcontractor; and likewise the subcontractor will accept risk in relation to its own property and personnel only. This is shown diagrammatically in Fig. II-6.1. Qualified indemnity and hold harmless provisions II-6.23 As has already been noted, when parties agree to a comprehensive mutual indemnity and hold harmless regime they agree to bear the risk of loss not on the basis of who was at fault, but on the basis of who is best placed to insure against the loss or otherwise absorb it. Sometimes, however, the parties will deviate from this paradigm and one or more of their provisions will be made subject to qualifications or so-called “carve-outs”. Qualifications are commonly encountered in the provisions pertaining to responsibility for injury to or death of third-party personnel, or damage to third-party property. Here, the parties often state that the indemnity and hold harmless provision will be offered only to the extent that the injury, death or damage was caused by the negligence or breach of duty of the indemnifying

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r i sk a l l ocat i o n 191 Intended Effect

Contractual provision Operator

O On the facts given (see Note) O carries risk in relation only to its own personnel and is at the head of the contractual chain. O offers C a hold harmless indemnity in respect of personal injury or death of O’s personnel C offers O a hold harmless indemnity in respect of personal injury or death of C’s personnel and that of C’s subcontractors of whichever level

Contractor

C offers SC a hold harmless indemnity in respect of personal injury or death of C’s personnel and that of O SC offers C a hold harmless indemnity in respect of personal injury or death of SC’s personnel and that of SC’s subcontractors of whichever level

SC offers SSC a hold harmless indemnity in respect of personal injury or death of SC’s personnel and that of O and C SSC offers SC a hold harmless indemnity in respect of personal injury or death of SSC’s personnel and that of SSC’s subcontractors (of which, on the facts given, there are none)

Subcontractor

Sub-subcontractor

C Under this contract, C carries risk in relation to its own personnel and also that of all subcontractors. Thus in any dispute between O and C, O will expect C to bear any losses pertaining to those personnel. C, however, has the opportunity, in its contract with SC, to take an indemnity back in respect of the sub-contractors, thus attempting to move ultimate liability down the contractual chain.

C Under this contract, C takes the hold harmless indemnity from SC referred to above; thus when the two contracts are read together he should be carrying liability only in respect of his own personnel, not the subcontractors’. However, as regards any dispute between himself and SC, he has had to assume risk in relation to his own personnel and that of O. However, the risk to him of so doing is reduced by the terms of the hold harmless indemnity he has entered into with O in the contract above. SC The fact that SC obtains an indemnity from C in relation to injury to both C and O’s personnel means he is able to accept these losses in the contract below as, if SSC claims, he may pass these losses up the chain to C. However, under this contract, in any matter between SC and C, C is made to carry risk in relation to his own personnel and those of all SSCs. He therefore needs to ensure that his agreement with SSC contains a valid hold harmless indemnity from SSC in relation to this risk. SC In any matter between SC and SSC, SC bears the risk in relation to his own personnel as well as that of O and C. To avoid ultimate responsibility for these losses SC must ensure that it has the benefit of an effectual hold harmless indemnity from C in relation to C and O’s potential losses in its contract with C, above. SSC carries risk in relation to his own personnel only as, on the facts, there are no sub-contractors beneath him in the chain. If there were, SSC would need to enter into a further back-to-back hold harmless indemnity with them.

Note: this is a simplified representation of one (quite short) contractual chain. With regards to any given producing platform, there will be more than one such chain: the operator is likely to have entered into direct contracts with at least a handful of parties. The relationship between the parties within this chain and those in other chains gives rise to further complications discussed at para II–6.55, below.

Figure II-6.1  Simplified Example of a Set of Back-to-back Mutual Hold Harmless Indemnity Provision in Respect of Personal Injury party.73 At first sight this is a major deviation from the standard indemnity and hold harmless regime. It is, however, justifiable in the case of third-party liability as, unlike the situation where one takes   See eg LOGIC, Supply of Major Items, cll 21.1(c) and 21.2(c).

73

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responsibility for one’s own people and property come what may, neither party has a close association with a true third party such as would justify a deviation from the law’s default position on how risk should be allocated. II-6.24 At the level of oil-company-to-oil-company contracts, it is common for such mutual indemnity and hold harmless provisions as are granted to be qualified by the statement that they will not apply in the case of wilful misconduct or gross negligence. The objective of such a clause is to protect the company from acts of deliberate sabotage or conduct which falls well below the standard of care which would ordinarily be expected in such operations. Neither “wilful misconduct” nor “gross negligence” has a wholly settled meaning in English or Scots law; as a result it is prudent, when the terms are used, to define them in the agreement.74 Moreover, some (particularly US) companies have a corporate policy of not accepting indemnity and hold harmless provisions which operate in such a way as to permit a contractor to escape from the consequences of its gross negligence or wilful misconduct. Historically, some companies sought to exclude from the ambit of the indemnity and hold harmless provisions losses attributable to the “sole negligence”75 of the other party or parties, but this particular carve-out appears to be less common in current practice. Given the complexity of oil and gas operations and the inter-dependent way in which the various parties work, it is, in practice, quite rare for one party’s actions to be the sole cause of an accident; and even when it is, the time, effort and money which may have to be expended in order to establish that fact may be very considerable. Moreover, prior to the occurrence of the incident, at the point when parties are mapping their potential liabilities and purchasing the necessary insurance cover, it is impossible to know if it will be caused by the sole negligence of one or another of the parties. Thus sole negligence clauses would seem to increase the prospect of uninsured losses. II-6.25 Qualifying indemnity provisions is not without its benefits. One can readily understand why an operator would wish an obligation to re-drill to be “carved out” of the general indemnity and hold harmless provision which a drilling contractor will usually enjoy

 Among the matters to be dealt with in the definition is eg the issue of whose gross negligence or wilful misconduct is relevant to the clause: for instance, all personnel or senior management only? For a further discussion of what is meant by these terms see para II-2.25. 75   The indemnity clauses litigated in the London Bridge case were in such terms: see the extracts from the relevant contracts reproduced at London Bridge 2000 SLT 1123, at 1126–1129. 74

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relative to loss of hole. However, and notwithstanding the fact that there is some evidence that the use of qualified indemnities has increased following the Deepwater Horizon disaster,76 any widespread practice of qualifying indemnity and hold harmless provisions has a number of drawbacks. It adds considerably to the complexity of what are already rather awkward clauses. It also undercuts the economic benefits provided by the clause: the greater the number of exceptions carved out of the indemnity and hold harmless regime, the greater the risk the contractor is exposed to, and the more insurance cover it must purchase.77 Deviating from standard practice can also lead parties into error concerning the precise forms of insurance cover which they require on this particular project. But ultimately the purpose of the risk allocation regime in any contract is to express the parties’ intent, and the relative importance of these various factors, are matters for the parties to themselves determine. Oil and gas contracts which reject the indemnity and hold harmless approach As has already been noted, many up- and midstream contracts II-6.26 will contain indemnity and hold harmless provisions of the type described, albeit that they will differ in detail. There are, however, occasions where these provisions are not used at all, or where the risk allocation provisions differ so drastically from the standard approach as to be barely recognisable. This is relatively rare in operator-to-contractor contracts, or contractor-to-subcontractor ones, but will quite commonly be seen with some operator-tooperator contracts, particularly those which pertain to the use of or interference with existing items of infrastructure: for instance, tie-in agreements.78 This is because the economic drivers that lead to the use of indemnity and hold harmless clauses in other parts of the industry are generally absent here. Where (in a JOA) operators are joining together mutually to develop an oil field, they share a common goal – to find hydrocarbon and make a profit by producing and selling it. Broadly speaking, their commercial interests will be aligned. And where operators, contractors and subcontractors are putting in place a suite of contracts to facilitate an oil or gas devel-

  See eg P Cameron, “Liability for Catastrophic Risk in the Oil and Gas Industry” (2012) IELR, 207–219. 77   See paras II-6.17 to II-6.20. 78  R Palmer, “Tie-In Agreements”, in M David (ed.), Oil and Gas Infrastructure and Midstream Agreements (1999) (hereinafter “Palmer, ‘Tie-In Agreements’”), at p 239f. Liability caps, discussed at paras II-6.83 to II-6.86, are sometimes, but not always, provided in such contracts: see para I-6.80. 76

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opment, the operators’ profit motive is again the economic driver. By contrast, where one operator approaches another seeking the use of infrastructure, the host operator will often have a producing field for which the infrastructure was built. The piece of infrastructure may very well be the only (or only commercially viable) means of getting oil and gas from the wellhead to the marketplace. In these circumstances, while it is not quite correct to say that the operator wishing to tie in is there on sufferance, because a tariff can be charged for the use of the infrastructure, it is true that the infrastructure owner’s main commercial focus is likely to be the producing asset. The relatively small amount of money which the company stands to make by permitting the use of its facilities is dwarfed by the potential losses it will suffer if the accessing party compromises the infrastructure. In these circumstances, there is less in the way of a commercial imperative pushing the company towards accepting less than full compensation. However, one should not over-generalise: if, for example, the producing field is coming towards the end of its life and the value of the throughput tariff is comparatively large, then a stronger economic case can be made for allocating risk on the indemnity and hold harmless model – albeit that, even here, the indemnities may be subject to the sort of qualifications discussed at paras II-6.21 and II-6.22. The oil and gas indemnity and hold harmless regime: a suite of provisions II-6.27 As we have seen, the indemnity clause of an oil and gas contract will commonly consist of a range of different indemnities: some simple, some mutual, some qualified, some unqualified. These will typically be assembled one after the other, sub-clause by sub-clause,79 and, if those drafting the indemnity clause have (1) been properly instructed on the precise risk factors thought likely to affect the works underlying the contract and (2) taken adequate care in drafting the clause, the indemnity provisions thus completed should succeed in mapping out the scope of the parties respective liabilities for the kind of physical risks which might assail the project.80 Such a “map” may look something like that shown in Fig. II-6.2.

  Although this can appear laborious, the case law demonstrates that it can be dangerous to try to draft such clauses in too brief a form: see eg Elf Enterprise Caledonia Ltd v Orbit Valve Co Europe [1995] 1 All ER 174 (hereinafter “Orbit Valve”), discussed at para II-6.38, and Slessor v Vetco Gray, discussed at para II-6.46. 80  Always assuming, of course, that the manner in which the parties have allocated the risks is permitted by law: see further para II-6.28. 79

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r i sk a l l ocat i o n 195

A (Operator)

B (Contractor)

1. Injury to or loss of life of A’s personnel [M] 2. Damage to A’s property [M] 3. Pollution emanating from A’s property [M] 4. Damage to third-party property and injury to or death of third-party employees but only if caused by the fault of A [M; Q] 5. Loss of hole (subject to B’s requirement to re-drill if hole rendered useless as a result of B’s fault) [M; Q] 6. Blowout, damage to reservoir, geological formation and underground strata etc [S]

1. Injury to or loss of life of B’s personnel [M] 2. Damage to B’s property [M] 3. Pollution emanating from B’s property [M] 4. Damage to third-party property and injury to or death of third-party employees but only if caused by the fault of B [M; Q] 5. Liability to re-drill hole if requirement to do so arises as a result of B’s fault [M; Q]

Receives indemnity and will be held harmless for:

Receives indemnity and will be held harmless for:

1. Injury to or loss of life of B’s personnel [M] 2. Damage to B’s property [M] 3. Pollution emanating from B’s property [M] 4. Damage to third-party property and injury to or death of third-party employees caused by the fault of B [M; Q] 5. Cost of re-drilling hole if requirement to do so arises as a result of B’s fault [M; Q]

1. Injury to or loss of life of A’s personnel [M] 2. Damage to A’s property [M] 3. Pollution emanating from A’s property [M] 4. Damage to third-party property and injury to or death of third-party employees but only if caused by the fault of A [M; Q] 5. Loss of hole (subject to B’s requirement to re-drill if hole rendered useless as a result of B’s fault) [M; Q] 6. Blowout, damage to reservoir, geological formation and underground strata etc [S]

Accepts liability for:

Accepts liability for:

Key: M = mutual indemnity; Q = qualified indemnity; S = simple indemnity

Figure II-6.2  Hypothetical Liabilities Matrix Based on a Relatively Simple Set of Operator-Contractor Indemnity and Hold Harmless Provisions Selected further issues in indemnification law and practice in the UKCS Statutory control of indemnity and hold harmless clauses Unlike some other jurisdictions, for instance several of the II-6.28 petroleum-producing states of the United States of America,81 the   So-called anti-indemnity statutes have been enacted in Texas, Louisiana, New Mexico, Wyoming and Oregon: see P Gerald and H Williams, “Injuries to Third Parties Arising From Oil and Gas Operations: An Analytical Framework for Examining Indemnity and Additional Insured Issues”, 15 (1999–2000) J Nat Resources & Envtl L 21, at 28–31. For a detailed discussion of the position in Texas, see T Fox, “Return to Certainty in Risk

81

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United Kingdom has not imposed any specific statutory controls on the use of indemnity and hold harmless clauses in the oil and gas industry. So far as the general body of commercial law statutes is concerned, the Unfair Contract Terms Act 1977 as amended (hereinafter “UCTA”) imposes some relevant restrictions.82 The restrictions imposed by UCTA on the use of indemnity clauses apply only when the indemnifying party deals as a consumer.83 This, together with the belief that indemnity and hold harmless clauses were mere indemnities, led the author to state in the first edition of this work that “there are therefore no statutory controls in force in the United Kingdom which impact upon the parties’ ability to make use of indemnity clauses in commercial oil and gas contracts”. Following Farstad v Enviroco, however, this claim can no longer be made. As indemnity and hold harmless clauses have now been held to operate as exclusions when they operate in the context of “direct exposure to the other contracting party”84 (as opposed to third-party losses), then the restrictions imposed by UCTA relative to exclusion clauses also need to be considered. Of greatest concern to the oil and gas industry would be the rule contained in Sections 2(1) and 16(1)(a) UCTA,85 that any attempt to by a party to restrict its liability for death or personal injury resulting from negligence will be ineffectual. At first sight, this provision would seem to be triggered by an indemnity and hold harmless clause which pertains to losses associated with personal injury or death and which applies irrespective of negligence; and, as Hewitt notes, “[t]he application of the section appears on its face to be strict and it does not appear to be possible for the parties to contract out of the Act”.86 However, Hewitt goes on to note that: “indemnities concerning death and personal injury in the context of the oil and gas industry (even where they are caused by negligence) have been upheld, notably in London Bridge. This may be because the clauses concerned in London Bridge were not construed as exclusions of liability for death or injury but rather exclusions of liability for Assessment, Management and Transfer: The Journey of the Texas Oilfield Anti-Indemnity Act” (2001) IELTR 18. 82   The more extensive provisions of the Consumer Rights Act 2015 can be discounted as they apply only to consumer contracts. UCTA continues to govern exemption clauses in business-to-business contracts: see eg UCTA s 2(4). 83   1977 Act, ss 4 (for English law and that of Wales and Northern Ireland) and 18 (Scots law). A party deals as a consumer when he does not contract in the course of a business but the other party does: see s 12. 84   Farstad v Enviroco per Lord Mance, at para 59. 85   Section 2(1) applies in English, Welsh and Northern Irish law and s 16(1)(a) in Scots law. 86   Hewitt, “Who is to Blame?”, at p 205.

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r i sk a l l ocat i o n 197 claims by third parties in respect of the same and were therefore not covered by the strict prohibition in section 2(1)”.

Hewitt is, it is submitted, wrong to characterise the mutual hold II-6.29 harmless and indemnity clauses in London Bridge as clauses which involved an exclusion of liability. It is submitted that the clauses were, on their true construction, concerned not with extinguishing liability, but with its reallocation.87 He is, however, surely correct in conceptualising the London Bridge clauses as being essentially concerned with third-party claims. This would seem to mean that neither they (nor, it would seem, any other indemnity and hold harmless clause appertaining to liability for personal injury or death)88 would, to use Lord Mance’s Farstad v Enviroco formulation, seem to regulate “direct exposure to the other contracting party”. Thus, in this context, indemnity and hold harmless clauses would seem to operate as indemnities, not exclusions. However, this will not be the case where the clause does seek to regulate direct exposure to the other contracting party. The classic example of such a situation will be where, as in Farstad v Enviroco, the claim pertains to property belonging to one of the parties. There, the clause will be an exclusion, and UCTA (although not argued in Farstad v Enviroco) would appear to be relevant. However, the provisions engaged would not be the bright-line prohibition upon exclusion contained in Section 2(1), but the (less draconian) reasonableness requirements contained elsewhere in the Act.89 The party having the benefit of the indemnity and hold harmless clause has less to fear from these provisions than from Sections 2(1) and 16(1)(a). Given the widespread use of indemnity and hold harmless clauses within the industry and the economic benefits of the practice, one would not expect such a clause to be struck down by the court other than in very unusual circumstances.90 The law’s normal presumptions about the distribution of risk The risk distribution exercise that the parties carry out by entering II-6.30 into an indemnity and hold harmless regime does not take place

87   Thompson v T Lohan (Plant Hire) Ltd [1987] 1 WLR 649. See also Lord Mance’s “direct exposure” formulation in Farstad v Enviroco, discussed later in this paragraph. 88   A company, being an incorporeal corporation, can never itself suffer personal injury or death. Thus it would appear that, by definition, all deaths and personal injuries suffered as a result of the negligence of a company must be third-party losses for the purposes of Lord Mance’s Farstad v Enviroco formulation. 89   That is, ss 2(2) and 3 (in English, Welsh and Northern Irish law) and ss 16(1)(b) and 17 (in Scots law). 90  See further the discussion of these provisions in the context of consequential loss at para II-14.77.

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in isolation. It occurs against the background of the assumptions which, in the absence of specific agreement, the law of contract and tort/delict91 makes about how certain risks are to be allocated. In contract law, the broad expectation, under both Scots law and the law of England and Wales, is that, subject to considerations such as remoteness of damage and the need for the non-breaching party to take reasonable steps to mitigate its loss, the party in breach is obliged to make good the losses suffered by the non-breaching party.92 If a loss occurs without either party breaching the contract, then, viewed from the perspective of contract law, the loss will lie where it falls. In tort/delict, the breach of a statutory duty that causes a party loss may in some circumstances found an action in reparation.93 And the founding principle of the tort/delict of negligence is that where a person owes another a duty of care and breaches that duty, causing a loss, he is under an obligation to make a payment of compensatory damages to make good that loss.94 But if there is no breach of statutory or common law duty, neither party can sue and the loss lies where it falls. It can therefore be seen that the general law’s default position is that liability follows breach of contract or breach of duty. Under this model, liability is wedded to fault. By contrast, as we have seen, carve-outs apart, the indemnity and hold harmless regime is predicated on the basis that liability should not flow along these lines, but that it should be accepted by the party best placed to insure against or otherwise absorb that particular type of loss. Thus the common law and the contractual regime that the industry creates to govern such matters are not closely aligned. The significance of this is that when the contractual regime fails for some reason – typically, because a clause is not sufficiently clearly drafted, but perhaps, post-Farstad, because it is deemed to be an exclusion clause and fails one of the tests set out in UCTA – and risk falls to   The Anglo-American expression “tort” is not used in Scots law, which prefers “delict”. However, at least in the field of the tort/delict of negligence, there is little to distinguish the laws of England and Scotland. 92   For the position in England and Wales, see eg G Treitel, The Law of Contract (14th edn, 2015) (hereinafter “Treitel, Contract”), at p 926f. For the Scots position, see W McBryde, The Law of Contract in Scotland (3rd edn, 2007) (hereinafter “McBryde, Contract”), Chapter 22. 93  C Witting, Street on Torts (14th edn, 2015) (hereinafter “Street on Torts”), at pp 499–513; J Thomson, Delictual Liabilty (5th edn, 2014) (hereinafter “Thomson, Delict”). 94  See Donoghue v Stevenson [1932] AC 562; Caparo Industries plc v Dickman [1990] 2 AC 605. Reasons of public policy mean that the rule is modified for numerous classes of case, for instance, where what the parties seek to recover is pure economic loss or psychiatric injury, or where what is in issue is the liability of a public authority. For a comprehensive account of English tort law, see A Dugdale et al., Clerk and Lindsell on Torts (21st edn, 2016) (hereinafter “Dugdale et al., Clerk and Lindsell”). For a concise but well-written account of the Scots law of delict, see Thomson, Delict. 91

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be allocated under the general law, it will frequently be distributed in a way that is very different from that which the parties intended. This may very well mean that one or both of the parties will find themselves facing losses against which they are not insured. The stakes are therefore high when one is drafting an indemnity and hold harmless clause. The position of third parties While the law of both England and Scotland now permits the benefit II-6.31 of a contract to be extended to a third party,95 neither jurisdiction permits a contract to impose obligations upon someone who is not party to it. It is therefore not strictly correct to say, without saying more, that a well-drafted indemnity and hold harmless clause modifies or over-rides the law’s conventional approach to risk allocation. It does so only so far as the parties to the contract are concerned. A stranger to the contract – usually described as a third party – who is injured or otherwise suffers a loss as a result in the course of the execution of the contract works will seek compensation through the time-honoured route of suing the person or persons whose negligence and/or breach of statutory duty caused his loss. Sometimes the person against whom the claim is directed will, by pure coincidence, happen to be the indemnifying party, in which case the indemnity and hold harmless clause will simply reinforce the common law’s approach. Where, however, the third party sues not the indemnifier, but the indemnified party, a claim will be made by the indemnified party under the indemnity and hold harmless clause. So, if the standard mutual indemnity and hold harmless provision is in place between companies A and B and C, one of company A’s employees is injured by the negligence of one of contractor B’s employees, he can be expected to sue B for negligence and/or breach of statutory duty.96 B cannot defend C’s claim on the basis that it

  In England, where the doctrine of privity of contract was traditionally very strong, this is as a result of the Contracts (Rights of Third Parties) Act 1999. In Scotland the common law doctrine of jus quaesitum tertio has permitted third-party rights for centuries, albeit subject to some rather onerous qualifying conditions. English law may therefore be thought to have overtaken Scots law in this regard. The Scottish Law Commission has recently recommended changes to the law which would make the Scots law of third-party contract rights clearer and more dependable. For a detailed discussion of the present Scots law in this area, see Scottish Law Commission Discussion Paper No 157 on Third Party Rights in Contract (March 2014), available at www.scotlawcom.gov.uk/index.php/ download_file/view/1257/129 (accessed 10 July 2017), Chapter 2. For an account of the proposed changes, see Scottish Law Commission Report on Third Party Rights (July 2016), available at www.scotlawcom.gov.uk/files/2014/6850/9379/Review_of_Contract_ Law__Report_on_Third_Party_Rights_No_245.pdf (accessed 4 July 2017). 96   Depending on the facts, he may in addition be able to raise a case directly against A in 95

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has an indemnity, as that is irrelevant so far as C, a third party, is concerned. However, B can make a claim against A as a result of their contractual arrangements. II-6.32 The fact that the third party is disinterested in the indemnity and hold harmless clause has the potential to have serious implications for the parties, particularly in the event of insolvency. Unless it is fortified either by meaningful guarantees or by adequate levels of insurance, a right to be indemnified is only as strong as the financial covenant of the company providing it.97 Interpreting indemnity and hold harmless clauses The traditional approach to interpretation II-6.33 The general rules. Although the precise formulation of the tests used in the jurisdictions traditionally differed, it is possible to say that both English and Scots law have traditionally taken an objective approach to the interpretation of contracts.98 Although objective, neither jurisdiction has been wholly literal in approach:99 both jurisdictions require the clause or phrase under discussion to be interpreted not in isolation, but in the light of the written document as a whole.100 Both have permitted evidence as to the objective factual background to be adduced with a view to allowing the court to determine the aim or thrust of the agreement,101 albeit there are differences between the two systems surrounding precisely when this is to be permitted.102 respect of A’s breach of its non-delegable “duty to reasonable care to see that its employees are safe”. See Dugdale et al., Clerk and Lindsell, at 13.05. 97  See eg T Taylor, “Knock for Knock Revisited”, blog post, Clyde and Co website, 20 February 2013, available at www.clydeco.com/blog/energy/article/knock-for-knockrevisited (accessed 10 July 2017); P Roberts, Petroleum Contracts: English Law and Practice (2nd edn, 2016) (hereinafter “Roberts, Petroleum Contracts”), para 13.11. 98   For the traditional position in England, see K Lewison, The Interpretation of Contracts (2nd edn, 1997) (hereinafter “Lewison, Interpretation”), at para 1.05. For the position in Scotland, see Scottish Law Commission, Scot Law Com No 160, Report on Interpretation in Private Law, available for download at www.scotlawcom.gov.uk/files/1512/7989/6878/ rep160.pdf (accessed 27 April 2017) (hereinafter “SLC, Report on Interpretation”), at para 2.3. 99  SLC, Report on Interpretation, para 2.1. 100   See eg (in the law of England and Wales) Re Jodrell (1890) 44 Ch D 590; for a Scots example, see Glen’s Trs v Lancashire and Yorkshire Accident Insurance Co Ltd (1906) 8 F 915. 101   See Lewison, Interpretation, at para 2.10 102  In England, even before Lord Hoffmann’s restatement in Investors Compensation Scheme Ltd. v West Bromwich Building Society [1997] UKHL 28 (discussed at paras II-6.36 to II-6.37), and particularly thereafter, a willingness to admit “matrix of fact” evidence can be seen: see Lewison, Interpretation, para 2.10. In Scotland, evidence as to surrounding circumstances is admissible only in the case of ambiguity, or if the contract

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Interpretation contra proferentem. In addition to the generalities II-6.34 expressed above, both English and Scots law have traditionally deployed the contra proferentem rule to interpret exemption, limitation and indemnity clauses.103 An ongoing problem in the law of contractual interpretation is the extent to which individual canons of construction, such as contra proferentem, have continued to survive the upheavals in the general law of contractual interpretation. For present purposes, a precautionary approach will be adopted which assumes that such rules continue to have a residual effect and that contractual draftsmen should continue to draft as if such rules remain in effect. Contra proferentem means that “[a] mbiguous words in exemption clauses [will be] construed in the way least favourable to the party relying on them”.104 In the context of a simple indemnity, the party relying on the clause will be the one who stands to receive the benefit of it – ie the indemnified party. But who is the proferens when the clause is mutual? The prevailing view appears to be that whichever party has the misfortune to have a claim directed towards it (and therefore requests indemnification under the contractual risk allocation provisions) is to be treated as the proferens.105 This, however, reduces the question to a matter of happenstance. The arrangement is mutual – indemnity and hold harmless provisions travel in either direction – and had the facts been different the indemnity might have run in the opposite direction. It seems to be artificial, in such a situation, to contend that there is a proferens at all. This fact was recognised in the Scottish Outer House case of Slessor v Vetco Gray, where Lord Glennie stated: “I accept Mr  Armstrong’s submission that the contra proferentem approach, which in any event only applies in a case of ambiguity, has much less impact where the exemptions and indemnities are mutual or reciprocal. Both parties are, in a sense, the proferens; and it makes was unintelligible without it: SLC, Report on Interpretation, para 2.3; see in particular the materials cited in fn 7 therein. In Arnold v Britton [2015] UKSC 36, which has supplanted ICS as the leading English case in this area, the Supreme Court clearly wishes the courts to focus primarily upon the natural meaning of the words used by the parties and to have recourse to external factors such as commercial common sense only in “unusual” cases where the wording is not otherwise intelligible: Arnold v Britton, per Lord Neuberger, at para 17. Thus it may be that the effect of Arnold v Brittan will be to close the gap between the Scots and English approach. 103   For an excellent account of this area, see E Peel, “Whither Contra Proferentem?”, in A Burrows and E Peel, Contract Terms (2007), pp 61–75. 104  Treitel, Contract, p 221. 105   Orbit Valve per Steyn LJ, at 182g–h; London Bridge, (Inner House) 2000 SLT 1123 per LP Rodger, at 1148C–L and per Lord Sutherland, at 1174L. The House of Lords passed no concluded view upon the matter as their Lordships took the view that the clauses were clear and unambiguous: London Bridge (House of Lords) 2002 SC (HL) 117, [2002] 1 All ER (Comm) 321) per Lord Mackay of Clashfern, at para 43.

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little sense to construe the clause against each one of them leaving the possibility of a hole in the middle.”106

II-6.35 It is respectfully suggested that this approach is logical and takes cognisance of the realities of the parties’ contractual arrangements. It therefore has much to commend it. However, on the balance of current authority, it cannot be said to be the established view. II-6.36 Towards contextualism (and back again). The traditional approach referred to above requires now, at least in England, and possibly also in Scotland,107 to be considered in the light of subsequent developments. In Investors Compensation Scheme Ltd v West Bromwich Building Society108 Lord Hoffmann offered a dictum which has come to be known as Lord Hoffmann’s restatement of the English law of contractual interpretation. A comprehensive examination of the restatement is outside the scope of this chapter. However, putting the matter shortly, Lord Hoffmann suggested that two cases decided by the House of Lords in the 1970s109 had effected a quiet revolution: a shift away from formalism towards contextual interpretation. He considered the effect of these cases had been to discard “[a]lmost all of the old intellectual baggage of ‘legal’ interpretation”.110 In particular, Lord Hoffmann confirmed that contractual interpretation was still in a sense an objective exercise, in that it continued to be a matter of ascertaining what a reasonable and objective bystander would make of the parties’ communings. However, he added that such a bystander should be presumed to be aware of at least most of111 the background knowledge and circumstances (otherwise the “matrix of fact”) which comprised the setting in which those communings took place. Moreover, as “the meaning of the document is what the parties using those words against the relevant background would reasonably have been understood to mean”, the bystander’s knowledge of the background circumstances might from time to time prompt him to   Slessor v Vetco Gray, at para 12.  The extent to which the restatement has been received into Scots law is presently unclear: see D Cabrelli, Commercial Agreements in Scotland: Law and Practice (2006), at paras 2.03–2.24, and McBryde, Contract, paras 8.25–8.27. 108   Investors Compensation Scheme Ltd v West Bromwich Building Society (hereinafter “ICS”) [1998] 1 WLR 896. 109  That is, Prenn v Simmonds [1971] 1 WLR 1381 and Reardon Smith Line Ltd v Hansen-Tangen [1976] 1 WLR 989. 110   At first sight, this might appear to be a reference to formal legal rules such as contra proferentem: see E McKendrick, Contract Law: Cases, Text and Materials (7th edn, 2016), at 381; Peel, “Whither Contra Proferentem?”, p 61. However, as McKendrick notes, appearances can be deceptive: see further the discussion of HIH Casualty & General Insurance at para II-6.43. 111   Previous negotiations and declarations of the parties’ subjective intent continue to be excluded from consideration. 106 107

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conclude that the parties must have used the wrong words. Such a conclusion would be reached rarely as the courts would not readily accept that the parties had made linguistic mistakes; however, when an appropriate case did arise, the reasonable bystander should not attribute to the parties an intention which they plainly could not have had.112 This test, as expressed in ICS, involved a greater emphasis upon matrix of fact evidence than had previously been seen. In ICS itself, the approach led the court to conclude that something had gone wrong with the drafting of the clause in question, as a result of which the court was willing to reorder the wording of the clause in order to give it greater commercial sense. Other striking examples of what might be described as remedial re-drafting were seen in The Starsin113 and in Chartbrook Ltd v Persimmon Homes Ltd.114 In the now-leading case of Arnold v Britton,115 the Supreme Court took the opportunity to restate the restatement. While Arnold v Britton does not render matrix of fact evidence irrelevant in all circumstances, the court strongly emphasised the centrality to the interpretative exercise of the words used by the parties themselves, and relegated the role of external factors such as commercial context to supplementary criteria to which regard could only be had in “very unusual” circumstances.116 The implications for drafting indemnity and hold harmless clauses. II-6.37 In spite of Lord Hoffmann’s apparent belief that his dictum was not a radical departure, but merely a convenient synthesis of what the law already said, the restatement proved to be controversial, and there can be no doubt that Arnold v Britton represents a conscious reining-in of the contextual approach. It should be noted, however, that what Arnold v Britton promotes instead of contextualism is literalism – the finding of meaning primarily from the words used by the parties themselves – rather than canonical interpretation. Thus, while following Arnold v Britton, a court may be slower than previously to have regard to factors such as commercial common sense when interpreting an indemnity clause; Arnold v Britton provides no obvious support for the practice of adopting strained or artificial constructions of clauses in order to comply with the old canons of construction. Yet neither are these old rules expressly swept away. In these circumstances, a penumbra of doubt remains, and the only prudent approach is for contractual draftsmen charged with the task of drafting indemnity and hold harmless clauses to attempt to cross   Investors Compensation Scheme [1998] 1 WLR 896 per Lord Hoffmann, at 912–913.   [2003] UKHL 12; [2004] 1 AC 715. 114   [2009] UKHL 38; [2009] 1 AC 1101. 115   [2015] UKSC 36. 116   Per Lord Neuberger, at para 17. 112 113

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the highest barrier to implementation that they face, and to proceed on the basis that indemnity and hold harmless clauses will continue to be construed contra proferentem. Drafting in this manner should minimise the prospect of a dispute arising as to the true meaning of the clause. However, in the event that an indemnity clause is challenged on the ground that it does not satisfy one of the tests established by the traditional canons of interpretation, very careful consideration should be given to advancing the argument that all that is needed for the clause to operate is for this to be the ordinary consequence of the wording used by the parties.117 In addition, if the contract in question does not accurately express the parties’ intentions, advice should be taken on the possibility of rectifying the deed.118 Some known problems of drafting and interpretation Contra proferentem and the problem of negligence and breach of statutory duty II-6.38 As has already been noted, when the parties to an oil and gas contract opt to include an indemnity and hold harmless regime in their contract, they are choosing to superimpose their own views on risk allocation upon the one provided by the common law. As we have seen, the common law generally expects liability to follow breach of contract or breach of duty. The courts have therefore considered it to be “a fundamental consideration in the construction of contracts of this kind that it is inherently improbable that one party to a contract should intend to absolve the other from the consequences of his own negligence”,119 and have considered it to be, if anything, even less likely that one party would go so far as to accept liability for another party’s negligence.120 While the courts stop short of saying that the parties cannot use the terms of their contracts to reallocate risk in the way in which they see fit, they have traditionally invoked the contra proferentem rule to say that the parties must use clear language when they do.121 Canada Steamship Lines Ltd v   The recent evolution of the rule of contra proferentem is further considered immediately below. 118   For a general discussion on rectification of deeds, see (from the standpoint of English law) Lord Mackay of Clashfern (General Editor), Halsbury’s Laws of England (4th edn, 2003 reissue) (hereinafter “Halsbury”), vol 32, paras 52–69. For the position under Scots law, see J Murray and S Wolffe, “Judicial and Other Remedies”, The Laws of Scotland: Stair Memorial Encylcopaedia, vol 13 (1992), paras 69–70. 119   Gillespie Bros & Co Ltd v Roy Bowles Transport Ltd [1973] QB 400 per Buckley LJ, at 419. 120   Smith v UMB Chrysler (Scotland) Ltd 1978 SC (HL) 1 per Viscount Dilhorne, at 7. 121   See eg London Bridge (Inner House) 2000 SLT 1123 per LP Rodger, at 1148K–L. See 117

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The King122 is authority for the proposition that effect will be given to a term which expressly states that the indemnified party is to be relieved from the consequences of its own negligence. This could be described as the primary route to enforceability under Canada Steamship – express provision.123 However, the same case also provides that, if the clause does not expressly indemnify in respect of negligence or some synonym for it, it will operate to relieve the indemnified party from the consequences of its own negligence only if (1) the words used in the clause are “wide enough in their ordinary meaning to cover negligence” on the part of the indemnified party, and (2) no alternative ground of liability which is neither too remote or too fanciful to be in the parties’ contemplation might exist. This could be described as the secondary route to enforceability under Canada Steamship. The question of whether or not an indemnity provision will protect the indemnified against the consequences of its own negligence is not some abstruse point of theory for drafters of such clauses. Unless there have been clear instructions that the indemnified party’s own negligence is to be excluded from the ambit of the indemnity and hold harmless clause, a provision which is ineffectual against the indemnified party’s own negligence is unlikely to be what a party to an oil and gas industry contract wanted. Worse, it is unlikely to match with the risks that the party has insured against. The Orbit Valve case demonstrates the risks involved, while the Nelson case illustrates an alternative approach to this problem. In Orbit Valve, a case determined under English law, the employers of a man killed in the Piper Alpha disaster were sued by the operator, who sought reimbursement of the compensation which the operator had paid to settle a claim by the deceased’s family. The operator, who accepted that the negligent actions of one of its employees had at least contributed towards the disaster, claimed that it was entitled to recover under the contractual indemnity and hold harmless clause. However, the contractor contended that the clause was ineffectual: the operator was seeking to be reimbursed for a loss incurred at least in part as a result of its own negligence; however, the clause did not expressly state that it would operate in these circumstances. Applying Canada Steamship, the Court of Appeal held that the also Orbit Valve [1993] 4 All ER 165 (affirmed by the Court of Appeal: see [1995]1 All ER 174) per Hobhouse J, at 173f: “The parties are always able, by the choice of appropriate language, to draft their contract so as to produce a different legal effect. The choice is theirs. In the present case, there would have been no problem in drafting the contract so as to produce the result for which the plaintiffs have contended; however, the contract was not so drafted and contains only generally working and is seriously lacking in clarity.” 122   Canada Steamship Lines Ltd v The King [1952] AC 192 (hereinafter “Canada Steamship”). 123   Ibid per Lord Morton of Shuna, at 208.

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clause contained words which were wide enough to have the effect of conferring an indemnity upon the indemnified party relative to the consequences of its own negligence. However, it refused to give effect to the clause on the basis that the second limb of the Canada Steamship test was not satisfied. The words were not necessarily directed towards the indemnified party’s negligence, but could just as easily have been intended to exclude another head of claim, namely breach of statutory duty.124 This head of claim was not either too remote or too fanciful to be in the parties’ contemplation. The claim therefore failed. II-6.39 The result in Orbit Valve has received some support. Rainey, a leading commentator and practitioner in the field, recently endorsed the question posed by Lord Steyn in Orbit Valve: “Why do draftsmen not take note of the impact of a clear and consistent line of judicial decisions?”125 That is a fair question. It would certainly make life easier if draftsmen were aware of these rules, and followed them. However, I would submit that the more fundamental questions to arise from Orbit Valve pertain to the reasoning of the court, rather than the drafting of the parties. Is it really appropriate for the court to take a clause that is, in its own terms, perfectly clear and deem it ambiguous because it does not expressly deal with a matter likely to be of no significance to the parties in question, thereby breaking the clause? How are the interests of justice served when an artificial construction is applied to perfectly clear wording, leading to an unexpected result and uninsured losses? Does the occasional and highly specific use of canonical construction really make the law clearer when the law generally favours an approach based upon textual analysis? II-6.40 In the Scots case of Nelson,126 the court was faced with a factual situation and contractual clause that was very similar to that in Orbit Valve. A worker employed by a contractor was injured on an offshore installation. The operator settled the employee’s personal injury claim and intimated a claim under the indemnity against the employer of the injured worker. The indemnity and hold harmless provision envisaged that the employer would take responsibility for “any and all losses, claims, suits, demands … and causes of action in respect of death or of injury to [the employer’s] personnel … howsoever caused”. The employer argued that the indemnity did not apply in circumstances where the indemnified party was seeking   Orbit Valve [1995] 1 All ER 174 per Steyn LJ, at 181h–j.  S Rainey, “Construction of Mutual Indemnity and Knock-for-Knock Clauses”, in B Soyer and A Tettenborn (eds), Offshore Contracts and Liabilities (2014), pp 67–107, at p 107. 126   Nelson v Atlantic Power and Gas Ltd 1995 SLT 102. 124 125

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to be protected against its own negligence. However, the court rejected this argument. At first instance, the judge attached great weight to the fact that the integrity of the reciprocal arrangement of risk allocation would be seriously undermined if the employer’s argument were successful; there was no evidence that the parties considered the issue of negligence to be especially important in their system of risk allocation, and to give primacy to this issue would disrupt the parties’ own carefully considered scheme. On appeal, the Inner House of the Court of Session upheld his judgment. The Inner House endorsed the reasoning of the Lord Ordinary, and considered that it fortified its view that the clause should be given effect to.127 However – while there is an intriguing hint that the court would have been willing to distinguish Canada Steamship and decide on the basis of the Lord Ordinary’s analysis had this been necessary128 – the primary basis for the Inner House’s decision was its interpretation of the requirements of the Canada Steamship test.129 The Inner House considered that where (as here) the indemnified party’s actions causing the loss could be characterised both as negligent and as a breach of statutory duty, then while Canada Steamship might prevent the operation of the indemnity in relation to negligence, it did not preclude the indemnity from taking effect in relation to the breach of statutory duty.130 This is a markedly different approach to Canada Steamship than that taken in Orbit Valve. The House of Lords had the opportunity to consider the II-6.41 construction of oil and gas risk allocation clauses in London Bridge, a Scots case which (like Orbit Valve) arose out of the Piper Alpha disaster. Unfortunately, however, the court did not have the opportunity to settle which of the two competing approaches was to be preferred, as the wording of the contractual risk allocation clauses was materially different to those discussed in Nelson and Orbit Valve. In London Bridge, the operator sought to use indemnity and hold II-6.42 harmless provisions in order to recover from the various employers of personnel injured or killed in the disaster sums in respect of damages paid in order to settle the personal injury claims of the injured and the families of the deceased. After proof, it was held that the accident had occurred as a result of both the negligence of the operator and that of an employee of a specialist valve contractor.131   Ibid, per the Opinion of the Court, at p 104.   Ibid. 129   Ibid, pp 102–103. 130   Ibid, p 103. 131   This finding was significant as the relevant clause contained a “sole-negligence” carveout, and had liability not been at least partially the fault of another party, the pursuer’s 127 128

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The operator was again met with the argument that the clause did not provide it with a remedy as it required to be interpreted contra proferentem,132 and did not deal sufficiently clearly with the issue of negligence to satisfy the Canada Steamship requirements. As noted above, this time, the indemnity clauses133 were drafted differently to the clauses in Orbit Valve and Nelson. The clauses were rather inelegantly expressed and did not address the question of negligence as expressly as one might have desired. However, they did make express provision for how issues of contributory negligence were to be resolved.134 This fact was sufficient to permit the court to conclude that the parties had intended that the mutual indemnity and hold harmless provision would take effect even in circumstances where one of the parties was seeking protection from consequences of its own negligence.135 The claim for indemnity therefore succeeded. Although London Bridge was concerned with a clause that was markedly different from that in Orbit Valve, it can still be noted that the overall tenor of London Bridge differed from that in Orbit Valve, with the court in London Bridge being led more by the wording of the clause itself and showing markedly less concern that the clause was a trap for the unwary. II-6.43 Away from the oil and gas context, the House of Lords has had an opportunity to consider the continued role for the rules in Canada Steamship following Lord Hoffmann’s restatement. HIH Casualty & General Insurance Ltd v Chase Manhattan Bank136 (hereinafter “HIH Casualty & General Insurance”) was concerned with the interpretation of an insurance policy designed to pay out to the insured (who were investors in films) in the event that the films in which they had invested did not make enough money to permit the repayment of the investor’s loans. This rather specialised “high-risk, high-premium”137 insurance product was designed and marketed by a firm of brokers who also acted as the insured’s agent when presenting the proposal to the insurers. The policy contained a “truth

claim would have failed: London Bridge (Inner House) 2000 SLT 1123 per LP Rodger, at 1131. 132   See also the discussion at para II-6.34. 133   The case involved a multiplicity of parties; seven separate sets of indemnity provisions were under consideration. 134   See the extracts from the relevant contracts reproduced at London Bridge 2000 SLT 1123, at 1126–1129. 135  See London Bridge (House of Lords) 2002 SC (HL) 117, [2002] 1 All ER (Comm) 321 per Lord Mackay of Clashfern, at paras 40–43. 136  [2003] UKHL 6, [2003] 2 Lloyd’s Rep 297. For an excellent summary, see E Peel, “Whither Contra Proferentem?”, at pp 61–64. 137   Lord Hoffmann, at para 25. This paragraph contains an evocative description of the film investment industry which the author commends to the reader.

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of statement” clause which, put shortly, provided that the insured (ie the investors) “would have no liability of any nature to the insurers for any information provided by any other parties”, and in particular that any information either provided or not disclosed by the brokers would not be a ground by which the insurers could avoid or escape their liability to make payment under the policy. This clause was included in the policy in order to protect the insured against the risk of unwittingly becoming responsible for anything said or known by the many other players involved in the procurement of finance for any of the films in question.138 In the event, there were substantial shortfalls in the films’ revenue and the investors claimed under the policies. The insurers repudiated liability on the grounds of misrepresentation and non-disclosure, either fraudulent or negligent, on the part of the broker. The insurers contended that the wording of the “truth of statement” clause was not sufficiently specific to meet the terms of the Canada Steamship rules in that although the wording was sufficiently wide to extend to negligence or fraud, it could just as readily be intended to exclude other causes of action which it was not fanciful to imagine the parties to have had in contemplation, such as innocent misrepresentation or non-disclosure. The House of Lords agreed relative to fraud, holding, by majority, it to be “a thing apart”,139 a species of liability which “must be excluded in clear and unmistakeable terms on the face of the contract”.140 Importantly, however, the House of Lords unanimously rejected the insurers’ argument relative to negligence. Although, as Peel notes, “[t]here was no suggestion from their Lordships that [the possibility that the parties might have had in contemplation innocent misrepresentation or non-disclosure] was regarded as fanciful”,141 the so-called Canada Steamship “rules” were relegated to the status of helpful but non-determinative guidance142 as opposed to a code. As Lord Bingham put it:  A multiplicity of parties were involved, including the broker: see HIH Casualty & General Insurance per Lord Hoffmann, at paras 26–33. The insured needed to be protected against the risk (not a fanciful one, given the manifold duties generally imposed by the law upon an insured, the contract being one of utmost good faith) of being deemed to have constructive knowledge of things known by persons deemed to be the insured’s agent. 139   HIH Casualty & General Insurance per Lord Bingham, at para 15. His Lordship continued: “Parties entering into a commercial contract will no doubt recognise and accept the risk of errors and omissions in the preceding negotiations, even negligent errors and omissions. But each party will assume the honesty and good faith of the other; absent such an assumption they would not deal.” 140   Ibid per Lord Bingham, at para 16. 141   E Peel, “Whither Contra Proferentem?”, at 62. 142  As Lord Hoffmann notes at paras 61–63, they had also been characterised as mere guidelines not to be mechanistically followed in Smith v South Wales Switchgear Co Ltd 138

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“The passage does not provide a litmus test which, applied to the terms of the contract, yields a certain and predictable result. The courts’ task of ascertaining what the particular parties intended, in their particular commercial context, remains.”143

II-6.44 In turning to that task, the House of Lords had no hesitation in holding that the parties had used “comprehensive language, clearly chosen to give [the investor] an extended immunity”.144 It found “nothing commercially surprising in this interpretation”145 as in a transaction of this kind “the possibility that [the broker] might make and fail to correct a representation which was later held to be both untrue and negligent would be very real”.146 Thus, while it would appear that contra proferentem has survived the purge of “[a] lmost all of the old intellectual baggage of ‘legal’ interpretation”, it has not emerged unchanged from its brush with Lord Hoffmann’s restatement. Fraud continues to be “a thing apart”; negligence, it would seem, is not. As HIH was decided at the height of the contextual era, its authority might be thought to be questionable following Arnold v Britton. However, while the case does, at points, advert to considerations of commercial common sense, the judgment is fundamentally a close textual analysis of the wording of the insurance policy in question. As such, it is submitted that it is compatible with Arnold v Britton. II-6.45 The indemnity and hold harmless clauses presently in wide use within the industry make express reference to the parties’ intention that the clauses will be effectual irrespective of negligence or breach of duty, whether statutory or otherwise.147 It would be foolhardy for contractual draftsmen deliberately to deviate from that practice. However, in the event that a clause is, upon examination following intimation of a claim, found to have been drafted in a way which is less explicit on this point than one might wish, London Bridge and HIH Casualty & General Insurance suggest that the courts may be [1978] 1 WLR 165, Hollier v Rambler Motors (AMC) Ltd [1972] 2 QB 71 and Ailsa Craig Fishing Co Ltd v Malvern Fishing Co Ltd [1983] 1 WLR 964. 143   HIH Casualty & General Insurance per Lord Bingham, at 11. 144   Ibid per Lord Bingham, at 12. 145   Ibid. See also Lord Hoffmann at 67: “There is no inherent improbability in such an intention. As Rix LJ said, “in a case like this the question of negligence can never be all that far from the contemplation of the parties”. 146   HIH Casualty & General Insurance per Lord Bingham, at 13. See also Lord Hoffmann, at 67: “And it seems to me that the commercial objective of the Truth of Statement clause would be substantially undermined if Chase’s right to the policy monies depended upon an inquiry into whether Heaths had or had not taken reasonable care in checking the truth of representations or deciding which facts should be disclosed.” 147   See eg LOGIC, Mobile Drilling Rigs, at cl 18.8; see also the discussion of the IMHH Deed, at para II-6.59.

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willing to take a somewhat more forgiving approach than that seen in Orbit Valve. More radically – and more speculatively – if Lord Glennie’s dictum in Slessor148 finds favour, then the contra proferentem rule will be found to be wholly irrelevant in the case of mutual indemnity and hold harmless clauses.149 Words delimiting the circumstances in which the indemnity and hold harmless provision will take effect Another subtle but important issue which arises in the drafting of II-6.46 an indemnity and hold harmless clause is the need to delimit the set of circumstances in which the indemnity is to take effect. The indemnity and hold harmless provision will not be being given generally, for all times and for all circumstances. Instead, it is given because it has been rendered necessary by the fact that one party intends to carry out work under a particular contract. Words need to be included in the clause which make this clear and state the circumstances in which the provision is to take effect. If this is not done, the provision is in danger of being either struck down as a result of its indeterminate scope, or of applying in circumstances not intended by the parties. However, and again, exercising prudence as a result of the possible continued application of the contra proferentem rule, draftsmen must give careful thought to the words they use. It is dangerous to draw too narrow a connection between the operation of the indemnity and the scope of work under the contract. This is so because there are a host of circumstances in which property may be lost or personnel injured or killed while they are on an operator’s platform. Taking the example of an injury on an offshore platform, such an event may befall a worker as a result of an accident directly connected to the scope of work to be done under the contract. However, it may also occur as a result of an accident occurring while he was carrying out work, but for reasons wholly unconnected to it, or while he is on the platform but not engaged in this work.150 Smith v South Wales Switchgear is authority for the proposition II-6.47 that if an indemnity is drawn so that it takes effect only if injuries are suffered during the “execution of this Order”, it will capture only injuries occurring as a result of the doing of the contractual

  See para II-6.34.   The rule would continue in operation in the case of simple indemnities. 150  A worker may, for example, be at rest in the accommodation module when a fire breaks out, as happened to many of those killed or injured in the Piper Alpha disaster. Or the injury or illness may be the result of a more mundane accident. For instance, the employee may be injured falling from his bunk (as occurred in Robb v Salamis M & I Ltd, 2007 SLT 158, albeit no indemnification issue was litigated here). 148 149

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work.151 The dangers that this judgment poses to the party claiming the indemnity are clear. In Campbell v Conoco (UK) Ltd,152 it was argued that a clause which provided that the subcontractor would indemnify and hold harmless the lead contractor153 against all injuries suffered by the subcontractor’s employees “as a result of or arising out of or in connection with the performance or non-performance of the contract” did not take effect in circumstances where the employee suffered injuries after being struck in the back by a blast of compressed air discharged from equipment which had nothing to do with the job he was doing, but which happened to be positioned close to the area in which he was working. The subcontractors contended that the indemnity would be triggered only if the injuries were directly attributable to the performance of work under the contract.154 The Court of Appeal held that the wording of that particular clause did not bear any such construction, and that the phrase in question was wide enough to encompass at least a situation where the injury occurred while the worker was engaged in his work,155 and may well have been wide enough to encompass a situation where injury occurred while the worker was at rest.156 However, the court also observed that “each contract depends on its own wording and context”. Thus if they wish the clause to be effective for the whole period when the worker covered is on the platform, drafters of indemnity and hold harmless clauses must be careful not to use words which tie the triggering of the clause too closely to the performance of the contract or its works.157 Multi-party issues II-6.48 Sometimes, for instance, in a consortium or alliancing agreement, there will be more than two parties to the contract. This does nothing   Smith v South Wales Switchgear [1978] 1 WLR 165 per Lord Keith, at 178.   Campbell v Conoco (UK) Ltd [2003] 1 All E R (Comm) 35 (hereinafter “Campbell”). 153  The terminology used throughout the case is rather confusing: because the case concerns a subcontract which incorporated the terms of the lead contract mutatis mutandis, the contract describes the parties as operator and contractor. However, in context this is to be read respectively as contractor (Amec) and subcontractor (Salamis): Campbell, at paras 6–7. 154   Ibid, at para 10. 155   Ibid per Rix LJ, at paras 18–19. 156   This point was left open as it was not necessary for the court to decide it: see Campbell per Rix LJ, at para 24. In Orbit Valve, similar wording was held not to limit the indemnity only to occasions when the injured party was actively carrying out work under the contract but to extend also to injuries occurring while the inujured party was on the platform but at rest: Orbit Valve [1995] 1 All E R 174, at 186. 157  The modern LOGIC Standard Contract wording, “arising from, relating to or in connection with the performance of or non-performance of the CONTRACT”, is a good example of a broadly drawn formulation: See eg LOGIC, Services, para 19.2(b). 151 152

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to alter the central concept of the indemnity and hold harmless clause. However, the addition of further parties does add a further layer of complexity to the drafting exercise. Slessor v Vetco Gray illustrates the difficulties that can be caused by attempting to provide for an unfamiliar situation. This case concerned the interpretation of an indemnity clause contained not in a standard services contract but within a multi-party consortium agreement. The clause was in the following terms: “The Parties hereto mutually and irrevocably undertake to release, defend and indemnify each other for damage to any property and/or injury to/or death of the personnel of the others, arising out of or in connection with the Work, howsoever caused.”158 At first glance, this may look very like a fairly standard mutual II-6.49 indemnity and hold harmless clause (albeit one in which the parties use the expression “release” rather than “hold harmless”). However, it differs from such a clause in one crucial respect. Ordinarily, A will indemnify B in respect of any injuries suffered by A’s personnel. This clause was held to achieve something quite different: A here indemnifies B and C for any injury suffered by B and C’s personnel while B gives a like indemnity to A and C in respect of injury or death to their personnel, and party C similarly indemnifies A and B. The court declined to interpret the clause contra proferentem, for the reasons which were given above,159 and recognised that it would be unusual for the parties intentionally to draft a clause in these terms.160 However, the court felt that the words used by the draftsman were clear and unambiguous, and that effect must be given to them.161 This was a Scottish case and no attempt was made to persuade the court to apply Lord Hoffmann’s restatement. Without knowing what matrix of fact evidence would have been available, it is idle to speculate on what the outcome would have been had the case been an English one, or had the parties sought to persuade the judge that Lord Hoffmann’s restatement is part of Scots law. However, given that the wording achieved the diametric opposite of what one would

  Slessor v Vetco Gray, at para 3.   See the discussion at para 14.31. 160   Slessor v Vetco Gray per Lord Glennie, at para 11. The court observed that the usual regime could easily have been put in place by substituting the contentious phrase with “their own personnel”. A yet safer way of drafting the clause might have been to individually list out each party’s responsibilities to the others. This can be cumbersome, particularly where multiple parties are concerned, but in such matters elegance is less important than clarity. Inverting the intentions of the parties, which seems to be what occurred in Slessor, may seem an extreme drafting error, but there is always a risk, when trying to draft indemnities in too concise a form, of inadvertently creating ambiguity, or of failing to consider which result would obtain under the clause in any given factual situation. 161   Slessor v Vetco Gray, at para 11. 158 159

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ordinarily expect an indemnity clause to be seeking to achieve, one cannot help but wonder if this may have been one of the occasions referred to by Lord Hoffmann where “the language has gone wrong”. “Full and primary” II-6.50 In London Bridge, one of the arguments advanced in the attempt to defeat the operators’ claim under the indemnity was that, as the operators’ insurers had already settled the claims of the contractor’s employees or their representatives, the operators had suffered no loss in respect of which they required to be indemnified. It was also argued that the operators’ insurers could not claim under the indemnity either, on the basis that both the insurers and the contractual indemnifiers had offered primary indemnities, and the insurers were therefore not entitled to rights of subrogation, but only to contribution;162 the argument ran that subrogation rights were enjoyed only by a secondary indemnifier who has paid “out of order”, to allow it to recover from the primary indemnifier who has a stronger obligation to settle the claim. The contract was silent on this aspect of the nature of the indemnity. On the particular facts of London Bridge, it was held that the contractual indemnity was primary and the insurers were secondary indemnifiers entitled to their right of subrogation. Thus they could claim to be reimbursed in full. However it must be emphasised that this decision does not settle all such debates once and for all; for instance, the decision was based at least in part upon the fact that there was no contractual obligation upon the operators to insure.163 How the court would have decided the matter if there had been such an obligation is therefore an open question. Best practice (which does not appear to have been followed in the LOGIC Standard Contracts, but which is in evidence in the IMHH)164 is therefore to expressly state that the indemnities are “full and primary”. Stray indemnities II-6.51 Throughout this chapter, references have from time to time been made to the “indemnity clause” or the “indemnity and hold harmless clause”. However, an oil and gas contract will not necessarily have one “indemnity clause”, or even one “set of indemnity provisions”. For the reasons given at para II-6.7, in addition to the main  The Scots law of contribution is concerned with the respective liabilities of joint wrongdoers and is contained in s 3 of the Law Reform (Miscellaneous Provisions) (Scotland) Act 1940. 163   London Bridge per Lord Hoffmann, at para 97. 164   See para II-6.59. 162

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indemnity and hold harmless provision, which may be labelled “indemnities”,165 or “indemnities and exceptions”,166 there may very well be one or more less obvious indemnities lurking elsewhere in the contract. These are sometimes described as “stray indemnities”. The drafter or reviewer of the contract needs to give some thought as to how these indemnities are intended to fit together. Are all indemnities under the contract intended to be given “irrespective of negligence or breach of duty, whether statutory or otherwise”, or just the ones in the main indemnity provision? Likewise, do the parties intend to extend the benefit of all indemnities to the relevant group(s)? The client’s intentions should be checked before the contract is finalised. Definitional issues Company groups. In practice, it is common for the parties to II-6.52 intend the effect of the indemnity clause to extend beyond the immediate parties so as to include their respective groups. Thus, in an operator-to-contractor contract, a contractor will commonly agree to indemnify and hold harmless the operator’s group against loss of or damage to the contractor group’s property, and the injury or death of the contractor group’s personnel; likewise the operator167 will usually agree to indemnify the contractor group against loss of or damage to the operator group’s property, and the injury or death of the operator group’s personnel. Typically, an operator group will be defined so as to include the operator itself, its co-venturers, its and their respective affiliates and its and their respective directors, officers and employees and personnel.168 A contractor group will generally include the contractor, its subcontractors and its subcontractors’ own subcontractors of whatever level, and its and their respective affiliates and its and their respective directors, officers and employees and personnel.169 This is done in recognition of the fact that contractors and operators will commonly use other members of their groups to carry out the activities and operations envisaged by the contract, and, if the benefits of the indemnity regime discussed at paras II-6.16 to II-6.18 are to accrue fully, it is necessary for the effect170 of the indemnity provisions to extend to all parts of the   As in the LOGIC contracts; see eg Well Services, cl 19.   As in Farstad v Enviroco; see the contractual provisions reproduced as the Appendix to Lord Clarke’s judgment. 167  The operator is generally referred to, in such contracts, as the “company”, and its group as the “company group”. However, in the interests of keeping terminology consistent the term “operator” is used throughout this chapter. 168   See eg LOGIC, Services, cl 1.2. 169   See eg ibid, cl 1.6. 170  The term “effect” is used because persons who are not party to a contract cannot be directly bound by it; the grouping provisions do not directly bind the non-signatory 165 166

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group. It will usually be the intention of the parties to establish an indemnity regime on a grouped basis. However, parties need to be mindful in such cases not just to scrutinise the indemnity clause but also carefully to check the definition of “group” or whatever cognate expression is being used in the contractual documentation, and to ensure that the implications of accepting those indemnity provisions, read together with that definition, are what is truly intended.171 II-6.53 Employees and personnel. As we have seen, many indemnity clauses are concerned with dividing up responsibility for injuries, illnesses or fatalities sustained by people during the course of the project. The expectation will ordinarily be that each party takes responsibility for its own people. Great care needs to be taken in how this intention is expressed. In particular, it should not be expressed too specifically or narrowly, by using a word which has a technical legal meaning, such as “employee” or even “worker”. Many people working on a platform will not be “employees” in the formal legal sense, but contractors. If the indemnity refers only to “employees” it is most unlikely to reflect the will of the parties. The current general practice is to frame the indemnity using a less technical term, such as “personnel”, and then to define that term broadly. II-6.54 Property. Similarly, many indemnity clauses will be concerned with apportioning responsibility for damage to property. Again, it is important for the parties – most particularly, contractors and any subcontractors entrusted with expensive pieces of equipment which they do not own – not to be lured into a false sense of security by observing that the contract contains a clause of this nature, but to give critical thought as to its precise terms, and the terms of any accompanying definition. Contractors will usually want “company property” to be given an expanded definition so that it encompasses not just items owned by the company but all items on the platform which the contractor might be called upon to use and/or which might reasonably be affected by the works carried out by the contractor. The operator will not necessarily own all the expensive or important items of property on the platform: some may be hired, or subject to retention of title clauses, or may be the property of other contractors, for instance the drilling contractor.

members of the group, but achieve their effect circuitously. If there is a contract between A and B, and a dispute arises between A and a company (B2) which is part of B’s group, if A and B’s contract states that neither will be liable for the relevant species of loss and provide each other with indemnities in respect of it, then, while B2 is still entitled to sue A if B2 suffers such a loss, A can claim an indemnity in respect of it from B. 171   A second Farstad v Enviroco case arising from the same incident as the first but argued in the English courts and pertaining to the definition of “subsidiary” of a parent company group is Farstad Supply A/S v Enviroco Ltd [2011] UKSC 16.

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The problem of multiple parties Introduction to the problem As we have already seen, at any given time there is likely to be a multi- II-6.55 plicity of parties with personnel and/or property on a production platform.172 We have already discussed the special difficulties caused by ensuring that all subcontractors within a given contractual chain have appropriate risk allocation terms in place. This, however, is only part of the picture, and the relatively easy part at that. Although the great majority of the undertakings with personnel on a platform at any given time are likely to be in a contractual relationship with someone, unless special measures have been put in place,173 they will not all be in a contractual relationship with each other. They will all be involved in a contractual chain; however, they will not all be involved in the same contractual chain. Diagrammatically, the situation can be shown as in Fig. II-6.3.

Operator

A Lead contractor

B

C

D

Subcontractor

B1

B2

C1

C2

D1

D2

Sub-subcontractor

B1A

B2A

B2B

C1A

D1A D1B D1C D2A

Figure II-6.3  Simplified Example of Contractual Relations on a Production Platform   See paras II-6.21 to II-6.23.   See para II-6.57.

172 173

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II-6.56 If, for example, subcontractor D2 negligently causes an explosion which injures personnel from D, A, D1A and B2, then there will be a direct contractual link (and presumably an indemnity and hold harmless provision) between D2 and D. Moreover, it is likely that back-to-back provisions will exist which, issues such as insolvency and drafting errors apart, will have the effect of apportioning risk throughout D2’s contractual chain: ie from A, through D and D2 down to D2A. However, there is no contractual connection, and therefore no contractual indemnity, between D2 and D1A, or between D2 and B2. II-6.57 There are a number of ways in which to resolve this issue. One option available at least in theory is for the parties to simply take the view that such risk will be dealt with by the law at large.174 This, however, means that all contractors on the platform are going to have to take out extensive insurance cover against the contingency that they cause injury to each other’s personnel, or damage each other’s property. For the reasons already given,175 this solution would undercut much of the economic benefits of the indemnity regime; it is therefore unattractive. A system whereby the parties entering into individual mutual hold harmless agreements with all other contractors with whom they would otherwise have no contractual link is also a possibility, but would require significant administrative effort, expense and co-ordination and would have the potential to go awry, leaving dangerous gaps in insurance cover if, for instance, a new contractor or subcontractor not previously known to operate on the platform was awarded a contract and information about this was not promptly disseminated among the contracting community on that platform. This potential solution is therefore again unattractive in practice. Until the early 2000s, the practice in the UKCS was generally that the operator and contractor would grant indemnities on a grouped basis, with the operator’s group176 defined so as to include “other contractors”177 and the contractor’s group defined so as to include its affiliates and all subcontractors of whatever level. The operator provided the contractor with an indemnity in respect of all claims relative to the people and property not just of the operator, but also of all contractors with whom the contractor

  Discussed at para II-6.30.   See paras II-6.17 to II-6.20. 176   See para II-6.52. 177   This term would be defined so as to include all contractors involved in operations other than the contractor’s own subcontractors of whatever level. If one refers to Fig. II-6.3, if the operator (A) was contracting with contractor D on this model, A would define its Group so as to include all contractors of whatever level within the chain of contractual relationships flowing from its contracts with B and C. 174 175

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did not itself have a contractual relationship, and by the contractor providing an indemnity in respect of its group’s people and property not just to the operator, but also to the other contractors. The risks would then be further broken up and reallocated along the backto-back principles discussed at paras II-6.19 to II-6.20. Thus the problem of multiple parties was dealt with by the operator acting as a fulcrum in the contractual arrangements. This provided a workable solution to the problem.178 However, the practice was difficult and time-consuming for operators to administer. It was also risky: if, for some reason,179 the back-to-back provisions broke down, then the operator would commonly find itself responsible for a greater degree of liability than it had anticipated or intended. For both of these reasons a more ambitious solution, modelled upon what had become the practice of certain operators,180 was instituted in 2002. This is discussed further below. The Industry Mutual Hold Harmless Agreement (IMHH) The problems referred to above, and the fact that the industry II-6.58 perceived the potential for significant savings,181 led to the creation by LOGIC’s Standard Contracts Committee of an Industry Mutual Hold Harmless subcommittee which, after extensive consultation, recommended the institution of a Mutual Hold Harmless Scheme and prepared a draft of the relevant Deed.182 This scheme was initially effected by the Mutual Indemnity and Hold Harmless Deed (the “IMHH Deed”)183 which had been signed by 93 parties184 when  This approach continues to be used in a number of jurisdictions, including Norway. The author is grateful to Prof Knut Kaasen of the Scandinavian Institute of Maritime Law, University of Oslo, for this information. 179  For example, drafting error such that the first level of indemnification worked but the back-to-back provision was ineffectual; or a failure to ensure that a back-to-back arrangement was entered into. 180   Shell, for example. 181   See LOGIC, Benefits for Participants, available for download from www.imhh.com/ benefits.cfm (accessed 10 July 2017): “It is believed that the industry as whole will make a significant financial saving from an effective implementation of the IMHH Scheme. It is impossible to put precise figures on this saving but industry discussions have suggested that a saving in legal fees of £17MM per annum may be possible. In addition to this there are the internal costs of all the parties involved in claims and counter claims which must be significant. The benefit across the industry could exceed £20MM per annum.” 182  LOGIC, About: see text under the heading “Introduction”. Note that although the word “indemnity” is not used by LOGIC in its introductory discussion of the Deed, as we shall see, the core risk allocation provision of the Deed is clearly a mutual hold harmless and indemnity clause. 183   Although the Deed bringing the scheme into existence is clearly entitled the “Mutual Indemnity and Hold Harmless Deed”, it is known throughout the industry as the “IMHH Deed”. This chapter will follow the prevailing industry practice. 184   Listed in Sch 1 to the IMHH Deed. 178

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the scheme became effectual on 1 July 2002.185 A significant number of other contractors have subsequently entered the scheme since by executing standard Deeds of Adherence.186 At the time of writing, some 1,020 parties were shown as registered on the IMHH website.187 The scheme is presently administered by LOGIC188 (which is itself the beneficiary of extensive simple indemnity provisions relative to losses which might arise as a result of the manner in which it carries out its administrative function: see IMHH Deed, cll 4.2 and 4.3 read together with cl 6.1(ii)).189 LOGIC’s primary functions are to act as the signatories’ attorney in executing Deeds of Adherence with new parties, receive and intimate to the remaining parties any notices of withdrawal, ascertain and act upon the will of the signatories upon the occurrence of any of the events which allow signatories to vote on whether to terminate the scheme, and to maintain the IMHH website. The initial IMHH Deed expired at the end of 31 December 2011. A replacement Deed (the “2012 Deed”),190 which entered into force immediately upon the expiry of the 2002 Deed, now governs the IMHH arrangement. At the time of writing the second edition of this work, some attention was paid to the differences between the 2002 and 2012 versions of the Deed as the 2002 was still extant and the draft of the 2012 had been finalised but the Deed had yet to go live. However as the 2012 Deed is now in force and the 2002 Deed has been superseded, the present volume will refer to the 2012 iteration only. II-6.59 The Deed’s core indemnity provisions. The central purpose of the Deed is to provide an efficient and practical means of bringing into   IMHH Deed, cl 7.1, read together with the date of the Deed.   A pro-forma Deed of Adherence is annexed to the IMHH Deed as Sch 2. 187   See LOGIC, List of Signatories, available for download from www.logic-oil.com/imhh/ signatories (accessed 6 April 2017). This compares with some 620 at the time when the second edition of this work was in preparation in late 2010 and 320 when the first edition was being worked on in 2007. 188   IMHH Deed, cl 1.1, definition of “Administrator”. The Administrator may be replaced when a majority of signatories believe it has carried out its duties incompetently: see IMHH Deed, cl 4.4. 189  LOGIC is provided with a right to outsource the performance of its administrative duties: cl 4.4 states that the administrator shall be “entitled to discharge any of its obligations and/or duties under this Deed by procuring that such obligations or duties are performed on its behalf by another person”, to be known as the Service Provider. The Service Provider, like the administrator, may be replaced if the majority of the parties to the Deed so wish. The Service Provider does not, through the operation of the IMHH Deed itself, obtain a right to share in the simple indemnity and hold harmless provision granted to but one would presume that any person agreeing to act in that capacity would insist upon obtaining the benefit of a back-to-back indemnity from the administrator in any contract appointing them to the position. 190   Both versions of the Deed are available for download from www.logic-oil.com/imhh/ documents (accessed 27 April 2017). 185 186

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existence an effectual set191 of hold harmless indemnities between parties who, save for the purposes of entering into an agreement about the allocation of physical risks, would have no commercial imperative to contract with each other. The IMHH Deed achieves this by providing that (subject to certain very significant exceptions which are discussed at para II-6.59) “the Signatories shall be solely responsible for and shall defend, indemnify and hold harmless the other Signatories and the other members of their respective Groups against all Claims arising from, out of, or relating to the Services in connection with: (i) personal injury to or sickness, disease or death of Personnel of the Indemnifying Signatory or any other members of its Group; and (ii) loss of, recovery of, or damage to any Property of the Indemnifying Signatory or any other members of its Group; and (iii) Consequential Loss suffered by the Indemnifying Signatory or any other members of its Group”.192

The “indemnities given pursuant to this Deed”193 are expressed as II-6.60 being “full and primary” and to apply “irrespective of cause and notwithstanding the negligence or breach of duty (whether statutory or otherwise) of the Indemnified Party and shall apply irrespective of any claim in tort, under contract or otherwise at law”.194 Taking the main indemnity and hold harmless clause phrase II-6.61 by phrase, in connection with all claims arising from, out of, or relating to the services195 that it covers,196 it provides a full and primary197 mutual indemnity and hold harmless regime drawn on a grouped basis,198 operating irrespective of negligence or breach of duty, whether statutory or otherwise,199 and covering (1) personal injury, sickness, disease or death of an expansively drawn set of people defined as “Personnel”; (2) loss of, recovery of or damage to “Property”; and (3) a class of loss defined as “Consequential

  As we shall see, the Deed does not provide for a wholly comprehensive set of indemnities: matters such as pollution are not included. See para II-6.61. 192   IMHH Deed cl 2.1. 193   Note that this term is habile to include not just the main cl 2.1 indemnity but also others that may exist throughout the Deed – eg the indemnities given to the Administrator by cl 4.2 and 4.3, discussed at para II-6.58. 194   IMHH Deed cl 2.2. 195   As defined by IMHH Deed cl 1.1 196   Note the important exceptions discussed at para II-6.58. 197  The importance of obtaining a “full and primary” indemnity is discussed at para II-6.50. 198   Grouped indemnities are discussed at para II-6.52. 199   See the discussion at paras II-6.38 to II-6.45. 191

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Loss”.200 Thus the IMHH Deed provides indemnities and a hold harmless provisions in respect of many, but by no means all, of the areas where the industry commonly utilises mutual indemnity clauses.201 The indemnity clause is supported by a clause providing for a waiver of rights of subrogation202 and is a meticulously drafted clause which avoids the errors and ambiguities of many of the clauses which have been litigated in the past.203 It is superior to the standard LOGIC indemnity and hold harmless provision in that it expressly states that the indemnity is “full and primary”. II-6.62 Other important provisions. The IMHH contains a number of other significant provisions which will be discussed briefly in turn. II-6.63 Entry into force. As has already been noted, the 2012 IMHH Deed entered into force as between its original signatories on 1 January 2012.204 The Deed becomes effective as between those parties from that date.205 However, many parties have entered the IMHH scheme since it was instituted. Such parties do so by entering into a Deed of Adherence206 between themselves and all the other current members of the scheme, who sign per the Administrator as attorney.207 Such parties are known as “New Parties”208 and become members of the scheme only from the date on which a Deed of Adherence signed by that Signatory has been dated by the Administrator”.209 The IMHH website displays the date when each party to the Deed became a

 Note that each of these terms are given extended definitions: see the IMHH Deed, para 1.1. 201  The Deed does not cover, for instance, pollution: this is because “[t] he prevailing consensus in the industry was that the scheme should apply to personal injury, property damage and consequential losses only. Other areas of risk such as pollution were considered, but were ultimately discounted. One of the main reasons for having a mutual hold harmless arrangement in respect of a Signatory’s own property, personnel and consequential loss is that the Signatory is best placed to assess the value at risk and, if required, make the appropriate insurance arrangements. Pollution risks are less quantifiable and hence would have created a complication to the IMHH provisions which was not widely welcomed”. See LOGIC, IMHH General Guidance, available for download from www.logic-oil.com/imhh/general-guidance (accessed 27 April 2017) (hereinafter “LOGIC, General Guidance”). 202   IMHH Deed, cl 5. This clause is further discussed at para II-6.67. 203   Note, however, that as the IMHH Deed uses identical wording to the clause litigated in Farstad v Enviroco, there may now be occasions when its provisions will have to withstand a challenge under the terms of UCTA. See para II-6.28. 204   IMHH Deed, cl 7.1, read together with the date of the Deed. 205   Ibid, cl 11. 206   Ibid, cl 4.1; see also Sch 2 to the Deed for the prescribed form of the Deed of Adherence. 207   IMHH Deed, cl 4.2. 208   Ibid, cl 4.1. 209   Ibid, cl 11. 200

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member of the scheme.210 The Deed expressly states that the cl 2 indemnities211 do not apply and are not enforceable “in respect of any Claims arising out of events occurring prior to the date on which that Signatory became a Signatory”.212 Geographical extent. The Deed applies not only to services II-6.64 provided on or in the UKCS and/or between the United Kingdom low water mark and the innermost boundary of the UKCS, but also to those carried out within Irish territorial waters and upon the Irish Continental Shelf.213 As further noted below, the Deed does not apply to landward areas. Order of precedence. The Deed expressly provides that it “shall II-6.65 not take precedence over, amend, modify or apply to the terms of any agreement between Signatories entered into prior to, on or after this Deed becoming effective in relation to such Signatories”.214 It is worth emphasising that the Deed refers to “any” agreement. So where a particular incident involves a dispute between signatories to the Deed who are at the material time in a contractual relationship germane to the provision of Services as understood by the Deed,215 the specific contract will take precedence over the general Deed. This is so even where the specific contract is silent – either by accident or design – on the question of risk allocation. Thus the IMHH Deed will not ride to the rescue if signatories to it are in a direct contractual relationship and omit to include indemnity provisions, or include provisions which are ineffectual. This is to provide signatories with the freedom to enter into different liability arrangements if they so wish. Extension of benefits to groups. In common with many oil and gas II-6.66 indemnity clauses in the UKCS,216 the indemnity and hold harmless provisions in the IMHH Deed are drawn so as to be for the benefit only of the Deed’s immediate signatories but also to “the other members of their respective Groups”.217 The Deed defines “Group” broadly so as to include, inter alia, “the Signatory in question and its respective Affiliates, the Personnel of all of the foregoing and their Invitees”,218 and cl 6.1(i) utilises the provisions of the Contracts   See www.logic-oil.com/imhh/signatories (accessed 27 April 2017). To view the dates, click on the hyperlink embedded within the name of each of the parties. 211   That is, the core indemnity provisions discussed at paras II-6.59 to II-6.61. 212   IMHH Deed, cl 2.3. 213   Ibid, cl 1.1, under the definition of “Services”. 214   Ibid, cl 11. 215   See the definition in the IMHH Deed, cl 1.1 216   Discussed at para II-6.52. 217   IMHH Deed, cl 2.1. 218   For the full definition, see IMHH Deed, cl 1.1, “Group” read together with the other defined terms which themselves feature within that definition. 210

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(Rights of Third Parties) Act 1999 to extend the benefits of the core, cl 2 indemnity provision, and also the waiver of subrogation clause, discussed immediately below, to all members of a Signatory’s Group.219 II-6.67 Waiver of rights of subrogation. The IMHH Deed provides that the signatories thereto shall procure that their insurers shall waive their rights of subrogation or any other rights they may have to proceed against the other signatories or members of those signatories’ groups in relation to the matters covered by the Deed.220 Signatories are entitled to require each other to exhibit evidence of the waiver.221 The Deed also states that, in the event that the parties fail to procure the relevant waiver, the failing party’s rights to enforce its rights and benefits under the IMHH Deed shall be suspended.222 II-6.68 Right to defend. As has already been noted, the obligation to indemnify and hold harmless is separate and distinct from the right and obligation to defend a claim; however, it is relatively common within the UKCS for the indemnifier to accept (or demand) responsibility for conducting the defence of any claim made against the party it is indemnifying.223 Under the IMHH Deed, the indemnifying signatory (ie the party who is, in the event of a claim, liable under the Deed to indemnify whosoever the claim is initially directed towards by the party suffering a loss) is entitled, but not obliged, to take over the conduct of the defence to any such claim.224 Where this option is exercised, the indemnifying signatory accepts certain obligations concerning the provision of information to,225 and consulting with,226 the indemnified signatory, and is in turn entitled to reasonable assistance from the indemnified signatory in the conduct of the defence. II-6.69 Parties to the IMHH Deed enter into a contractual relationship which radically reallocates the legal liabilities they carry.227 Where a company is a member of the IMHH scheme, other members of the scheme are likely to feel entitled to refrain from entering into mutual

 The IMHH cl 6.1(ii) extends the benefit of the cl 4 indemnities referred to at para II-6.58 to the Administrator who, although extensively mentioned throughout the Deed, is not a party to it. 220   IMHH Deed, cl 5.1. 221   Ibid, cl 5.2. 222   Ibid, cl 5.3. 223   See para II-6.09. 224  IMHH Deed, cl 3.2. Where it does not take up this option, the Indemnified Party assumes an obligation not to settle the case without the consent of the Indemnifying Signatory: IMHH Deed, cl 3.4. 225   IMHH Deed, cl 3.2(ii). 226   Ibid, cl 3.2(iii). 227   For a general discussion on the effect that an indemnity clause has upon the normal system of risk allocation provided by the underlying law, see para II-6.30. 219

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hold harmless indemnity contracts, and/or to purchase less insurance cover which they would otherwise have been likely to believe they required. It is therefore imperative that signatories to the Deed know with certainty which parties are members of the scheme at any given time. For this reason, the right to withdraw from the scheme is quite heavily regulated. Upon signature, the parties are locked in to membership of the scheme until 31 December 2021228 subject only to potential escape points occurring on 31 December 2014 and 2017, but only in the event that they have provided the Administrator with 60 days’ notice of this intention.229 Such a withdrawal takes effect “from 00:01 hours on the date of such withdrawal”230 and does not have retrospective effect. Exceptions. A number of exceptions are carved out of the IMHH II-6.70 Deed’s core indemnity and hold harmless provisions or introduced by way of the Deed’s defined terms. Each of these has a very significant practical impact upon the Deed’s scope. Each is discussed below. Transportation by air excluded. None of the cl 2 indemnities II-6.71 applies or is given in relation to “any Claims arising from, out of or relating to the transportation by air of any member of a Signatory’s Group”. Thus, transportation by air falls wholly outside the scope of the IMHH Scheme. Landward areas. Despite the fact that, in practice, onshore II-6.72 works will quite commonly be the subject of indemnity provisions similar to those governing offshore,231 the IMHH Deed applies only to services and/or supplies “carried out on or in the United Kingdom Continental Shelf and/or between the United Kingdom low water mark and the innermost boundary of the United Kingdom Continental Shelf”.232 Thus, services or supplies carried out on the landward side of the UK low water mark are excluded. This has the effect of excluding onshore services, and will also have the effect of excluding any services or supplies carried out in the part of the territorial sea which lies on the landward side of the low water mark.233 It was decided to so limit the effect of the IMHH Deed because: “The general industry view was that extending the IMHH to cover onshore activities as well as offshore activities could have inadvert-

  IMHH Deed, cl 7.2.   Ibid, cl 7.3. The Administrator is obliged by the same clause to notify all other parties in writing. 230   Ibid, cl 7.2, read with the definition of “Signatory”. 231  LOGIC, Services is intended to be applied both on- and offshore. Note also that the pursuer in Slessor v Vetco Gray was working onshore when he was injured. 232   IMHH Deed, cl 1.1, definition of “Services”. 233  A surprisingly large area, although not one in which large amounts of oil and gas operations have been undertaken: see para II-6.01. 228 229

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ently led to the application of the IMHH in circumstances where it was not intended (eg motor vehicle accidents) and, as such, in order to avoid any ambiguity it was limited to offshore activities only.”234

II-6.73 Operators. Although operators played a substantial part in bringing it into being, the IMHH Deed is designed for, and signed by, the contracting sector. It is not well suited to operator-to-operator situations and, given that the operator sits at the top of the contractual pyramid, operators should already be in a direct or at least indirect contractual relationship with anyone who steps onto their platform for commercial purposes, and therefore in a position to negotiate whatever contractual risk allocation regime the parties to those contracts choose.235 II-6.74 Commentary and conclusions on the IMHH Scheme. Some brief concluding words on the scheme are offered below. The contractual nature of the scheme II-6.75 It is important to appreciate that the Deed is not a document in the nature of a piece of legislation, conferring rights and imposing obligations by virtue of the mere fact that it exists. It is a contractual solution to a problem; it is just not the same contractual solution that the oil and gas industry previously deployed. It is axiomatic, therefore, that it takes effect only between those parties who have executed it, or those who have entered into a Deed of Adherence. It needs to be emphasised that it cannot simply be assumed that all oil and gas contractors are adherents to the Deed. In particular, not all drilling contractors have signed the deed, although the numbers to have done so are gradually increasing. It is understood that the drillers’ general reluctance to adhere to the Deed is because the potential losses which may be suffered by drilling contractors, whose equipment is extremely valuable, and who will commonly have relatively large numbers of personnel on a rig or platform, is substantially larger than most contractors, and the drilling community have, by and large, yet to be persuaded of the value of the scheme. Other contractors will need to take appropriate steps to accommodate the risk caused by this refusal, either by seeking an indemnity from the operator, entering into a mutual hold harmless and indemnity arrangement directly with the driller, or simply by accepting the exposure and insuring accordingly. In addition, and as noted above, the Deed’s order of precedence clause means that the Deed is rendered irrelevant if there is any direct contractual relationship bearing upon “Services” as understood by the Deed.   See LOGIC, General Guidance.   See LOGIC, General Guidance, under the heading “Can Operators sign?”.

234 235

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Potential dangers of the IMHH The IMHH was launched with considerable fanfare and broad II-6.76 industry backing236 and has quickly been accepted by the majority of the contracting community in the UKCS. It provides a solution to a problem which has caused considerable difficulties and inefficiencies for some time. There is no reason to believe that in general terms the scheme has been, or will continue to be, anything other than a success. However, the IMHH initiative – or perhaps more properly, the initiative’s application in practice – is not without its potential pitfalls. The Deed, while by no means long, is, of necessity, relatively complex. While many of the contractors who operate within the UKCS are large and sophisticated companies possessing the understanding and resources to ensure that their personnel understand the full import of the scheme, this is not true of all contractors. It is least possible that, in spite of the efforts which have been made by LOGIC to promote an understanding of the Deed, not all signatories to the scheme are fully conversant with all its subtleties. Certainly in the early days of the IMHH Deed’s implementation it is fair to say that the import of the Deed’s precedence provisions was not universally appreciated,237 and some parties seemed to be unaware of the fact that the indemnities on the Deed did not cover true third-party visitors to a platform. Such misconceptions are alarming as, if the parties do not have a full comprehension of the way the IMHH Deed allocates risk, there is a danger of gaps in insurance cover. While one would hope that the Deed is now better understood, this should not be assumed: new contractors, some of whom work in the offshore field only semi-regularly, are signing up all the time. Moreover, the natural turnover of staff within even the more established players means that ongoing training and education is essential. In addition, and rather perversely, as the Deed becomes more broadly accepted, there is the danger that familiarity may breed contempt. Procedures may become sloppy, and parties may simply assume that everyone working on a particular rig or platform with whom they are not in a contractual relationship is a subscriber to the IMHH Deed. As we have already seen, however, this is unlikely to be true of the driller, and may not be true of all other contractors. If the contractor is to minimise risk it is incumbent upon it to ascertain whose property and personnel is or will be on the platform at the material time and to check that those on board fall within the ambit of the IMHH scheme, or to obtain a binding contractual undertaking from the   It was launched under the auspices of LOGIC and with the support of UKOOA, IMCA, OCA and WSCA. 237  Discussed at para II-6.65. For a time, a number of parties held the belief that the IMHH Deed could rectify a defective indemnity in an existing contract. 236

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operator that (apart from true third parties), only subscribers to the IMHH will be permitted onto the platform. None of this is intended to attack the principles underlying the IMHH Deed but simply to urge due care in the scheme’s application. LIABILITY FOR “CONSEQUENTIAL” LOSS II-6.77 In addition to containing the indemnity and indemnity and hold harmless provisions described above, a wide variety of oil and gas contracts will also include clauses which exclude, limit238 or put in place an indemnity and hold harmless regime239 in respect of liability for so-called “consequential or indirect” losses.240 Such provisions are commonplace in operator-to-contractor contracts241 and are seen in some – but by no means all – oil-company-to-oilcompany contracts.242 Where such clauses are used, their purpose is to protect parties from the full consequences of causing certain types of loss, typically delays in or loss of production, loss of use, loss of profits, and business interruption. The quantum of such losses is generally difficult to anticipate in advance, and may be hard to quantify even retrospectively.243 However, they tend to accrue on a daily basis and, if a particular field, facility or critical piece of

  With reference to the discussion at para II-6.26, in so far as these contracts “exclude” or “limit” such loss they are subject to the provisions of the Unfair Contract Terms Act 1977, but not the 1999 Regulations. However, the courts have repeatedly held that, while they will always consider full circumstances of the case (see eg Motours Ltd v Eurobell (West Kent) Ltd [2003] EWHC 614 (QB)), it will be only in unusual circumstances that they will hold a business-to-business exclusion of consequential loss clause unreasonable: see Wessanen Foods Ltd v Jofson Ltd [2006] EWHC 1325 (TCC); Photo Production Ltd v Securicor Transport Ltd [1980] AC 827. 239   A carefully drafted mutual indemnity regime is thought necessary where the intention is to extend the effect of the consequential loss provisions to groups: if there is a contract between A and B, and a dispute arises between A and a company (B2) which is part of B’s group, a simple exclusion or limitation of consequential loss will not be binding upon B2. However, if A and B state that neither will be liable for the other group’s consequential losses and provide each other with indemnities and hold harmless provisions in respect of such loss, then, while B2 is still entitled to sue A if B2 suffers a consequential loss, A can claim an indemnity back from B. 240  The precise terminology varies: sometimes “consequential loss” or “indirect loss” is used on its own. Sometimes “damages” is used instead of “loss”. See the discussion in London Bridge (Inner House) 2000 SLT 1123 per LP Rodger, at 1156D–E. 241   They appear throughout the LOGIC Standard Contracts series. See eg LOGIC, Supply of Major Items, at cl 23. 242  See A Jennings, “FPSO Agreements” and J Izod, “Satellite Tie-back and Processing Agreements”, both in M David (ed.), Oil and Gas Infrastructure and Midstream Agreements (1999), at p 209f and p 170 respectively. 243   Note the difficulties which occurred in this regard in BHP Petroleum Ltd v British Steel plc and Dalmine SpA [2000] 2 Lloyd’s Rep 277 (hereinafter “BHP Petroleum”). 238

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infrastructure is “knocked out” for a sustained period of time, these losses can rise to extraordinary and alarming levels. As such, they are frequently either excessively expensive or simply impossible for a contractor to insure against, and the industry has by and large accepted that such losses should lie where they fall. Thus we can see that economic factors very similar to those that drive the indemnity regime underpin the exclusion or limitation of consequential losses. What is “consequential loss”? There is considerable uncertainty over what, if any, fixed meaning the II-6.78 term “consequential loss” conveys. The prevailing interpretation under English law has, for some time, been that the expression is almost a term of art, which usually denotes a reference to the category of losses encompassed by the second limb of the rule in Hadley v Baxendale.244 On this analysis, if a contract excluded liability for consequential loss, the parties would still be able to recover the sort of damages envisaged by the first limb of Hadley v Baxendale, which is to say, losses “such as may be fairly and reasonably be considered … [as] arising naturally, ie according to the usual course of things, according to the breach itself”. However, the parties would not be entitled to recover in respect of the second limb, which is to say, for damages “such as may reasonably be supposed to be in the contemplation of the parties at the time they made the contract as the probable result of the breach. Now if the special circumstances under which the contract was actually made were communicated by the plaintiffs to the defendants, and thus known to both parties, the damage resulting from the breach of such a contract, which they would reasonably contemplate, would be the amount of injury which would ordinarily follow from a breach of contract under those special circumstances”.245 If this line of reasoning was ever sound,246 one could question II-6.79   (1854) 9 Ex 341. The line of reasoning sprang from Millar’s Machinery Co. v David Way & Son (1935) 40 Com. Cas. 204 and Saint Line v Richardsons [1940] 2 K.B. 99 and has subsequently been consolidated by decisions such as British Sugar P.l.c. v N.E.I. Power Projects Ltd (1997) 87 B.L.R. 42; Deepak Fertilisers and Petrochemicals Corporation v I.C.I. Chemicals & Polymers Ltd (1999) 1 T.C.L.R. 200; Hotel Services Ltd v Hilton International Ltd [2000] 1 All E.R. (Comm.) 750; McCain Foods G.B. Ltd v Eco-Tec (Europe) Ltd [2011] E.W.H.C. 66 (T.C.C.); Markerstudy Insurance Co. Ltd v Endsleigh Insurance Services Ltd [2010] E.W.H.C. 281 (Comm.); Glencore Energy U.K. Ltd v Cirrus Oil Services Ltd [2014] E.W.H.C. 87 (Comm.); Polypearl Ltd v E.On Energy Solutions Ltd [2014] E.W.H.C. 3045 (Q.B.). 245   (1854) 9 Ex 341 355-6 per Alderson B. 246   And it is submitted it was not. See G Gordon, “The Exclusion of Consequential Loss in the Piper Alpha Case: A Study of Lord Rodger’s Method of Textual Analysis”, in ARC Simpson et al., Pragmatism, Continuity and Change: Essays in Memory of Prof Angelo Forte (2016) (hereinafter “Gordon, ‘Exclusion of Consequential Loss’”), pp 434–465. 244

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whether it is consistent with the modern approach to contractual interpretation. Imposing a fixed meaning to a phrase smacks of the application of the lexiconical approach of an earlier age, rather than the literal approach currently ascendant in English law. There are some – albeit equivocal – signs that the English judiciary may be preparing to adopt a different view to this question.247 If so, it may come to follow the approach to this question taken in Scotland, which rejected the “consequential loss as second limb” approach in London Bridge.248 In London Bridge, the court held that it was not appropriate to attach “a special, technical meaning” to the phrase “indirect or consequential loss” so that the phrase would be “interpreted as referring to losses which would be regarded as indirect or consequential under the rules in Hadley v Baxendale and subsequent cases”.249 Instead, while prior court decisions were certainly a relevant consideration, they were not to be thought of as determinative. The court’s primary task was to interpret the words in the context in which they were used.250 When such an approach was taken, the Court of Session held, and the House of Lords confirmed, that the disputed loss in London Bridge251 did

 In Scottish Power UK plc v BP Exploration and Drilling [2015] EWHC 2658, Mr Justice Leggatt stated obiter (at para 180) his concurrence with a leading commentator’s critical analysis of the “consequential loss as second limb” approach. In Transocean Drilling UK Ltd v Providence Resources plc [2016] EWCA Civ 372, Lord Justice MooreBlack, delivering a judgment concurred in by Lord Justices McFarlane and Bridges, noted (at para 15) that “the expression ‘consequential loss’ has caused a certain amount of difficulty for English lawyers”, and thought it “questionable” whether some of the “consequential loss as second limb cases” would be decided in the same way today. In Saga Cruises BDF Limited & anor v Fincantieri SPA [2016] EWHC 1875 (Comm), Deputy High Court Judge Sara Cockerill QC considered (at para 198) “the consequential loss as second limb” line of authority to be “well-established”, although she did qualify this by adding the rider “on the current state of the law”. 248  As we shall see, the detailed reasoning is contained in the Inner House phase of the case. However, this reasoning was expressly approved of by Lord Mackay of Clashfern in the House of Lords: 2002 SC (HL) 117, [2002] 1 All E.R. (Comm) 321, at para 69. Lord Mackay’s judgment was in turn concurred in by all the other judges in the House. 249   Lord Rodger, at 1154. 250   London Bridge (Inner House) 2000 SLT 1123 per LP Rodger, at 1156. 251   The circumstances were rather unusual. Because the operator had a material connection to Texas, they feared (with considerable justification) that if the damages claims of the persons injured and those of the families killed in the disaster were not settled on a generous basis, they might be sued in Texas, where the level of awards of damages were significantly higher than in Scotland. The claims of the injured parties and the families of the deceased were therefore settled on a “mid-Atlantic” basis, which is to say, at a level somewhere between traditional Scots awards and those which could be expected in the state of Texas. The defenders accepted that the element of the Scots element of the damages award was a direct loss, but that the “mid-Atlantic” augmentation was an indirect or consequential loss. 247

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not fall to be considered as “indirect or consequential” but was a direct loss. 252 Commentary and conclusions on consequential loss It is wholly understandable that the parties to oil and gas contracts II-6.80 should seek to exclude, place limits upon the recovery of, or seek indemnities in respect of certain types of potentially exorbitant losses. It is, however, perhaps unfortunate that the term “consequential loss” was ever adopted as the vehicle for attempting to do so. Even when the term was thought to be a synonym for the losses envisaged by the second leg of the Hadley v Baxendale test, it created difficulties. It is not always easy to ascertain whether a particular type of loss is going to fall within limb one of the test or limb two. There was a clear danger that the contractual draftsman would assume that the expression was a convenient shorthand for all of the types of potentially exorbitant or hard to insure losses that he wished to exclude. However, it was not. Many of the most onerous losses which might be suffered during oil and gas operations do not clearly fall under the rubric of the second limb of Hadley v Baxendale, but may instead be captured by the first limb of the test. This can be illustrated by considering the factual circumstances described in BHP Petroleum. In this case, a contract was entered into for the procurement of steel for a gas reinjection pipeline. The purpose of the project was to improve production from a producing oilfield. The steel was in due course found not to conform to specification. It required to be replaced and the gas reinjection programme was delayed. In such circumstances, it is not just the cost of replacing the pipe that “[arises] naturally, ie according to the usual course of things, according to the breach itself”. It is also plainly apparent that production from that oil field will be delayed for a period of time while these works are carried out. Production lost during that period of time would therefore appear to be a direct loss, not a “consequential or indirect” one. So a clause which – without saying more – excludes “consequential or indirect” loss is unlikely to exclude the loss described. And while the London Bridge approach is, it is submitted, a just and sensible one, it does little to make the situation more straightforward. Although, as with the contextual approach more generally, it may very well make the outcome of any given litigation fairer, the uncertainty that it engenders arguably increases the chances of litigation occurring in the first place, and may very well make the scope of enquiries of any litigation which does result more wide ranging.

  For a fuller account see Gordon, “Exclusion of Consequential Loss”, 446–463.

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II-6.81 Against this rather shifting background, the safest way in which to construct a clause excluding or limiting the type of losses which the oil industry has tended to design as “consequential or indirect” is to make the working presumption that those words will of themselves convey very little reliable protection, and to define all essential content into them. This means that the draftsman must give consideration to the types of uninsurable or potentially exorbitant losses that might befall the project, and must list them out in the clause. This is the approach taken by most of the contractual documents in broad use in the industry just now. There is some disagreement on whether the best practice is to define consequential loss by reference to a closed list, or to state that consequential loss “includes but is not limited to” the potential heads of loss items listed. Jennings favours the former approach on the basis of clarity,253 but the latter approach is the one which is used more commonly throughout the industry’s standardised contractual documentation. Thus the Industry Mutual Hold Harmless Deed defines consequential loss as: “(i) consequential loss under applicable law; and (ii) loss and/or deferral of production, loss of product, loss of use and loss of revenue, profit or anticipated profit (if any) whether direct or indirect to the extent that these are not included in (i), whether or not foreseeable at the date of execution of this Deed”.254

II-6.82 Finally on this topic, where, as will frequently be the case, the contract contains both an indemnity regime and either an exclusion, limitation or an indemnity in respect of consequential loss, thought needs to be given to the interaction between these provisions. They may very well overlap. It will generally be intended that the consequential loss clause will take precedence over the indemnity provisions.255 Whatever the parties intend, clear words should be used to express their wishes. OVERALL LIMITATIONS OF LIABILITY II-6.83 An overall limitation of liability256 – sometimes described as a “liability cap” – is a clause that seeks to limit a party’s liability not   Jennings, “FPSO Agreements”, at p 210.   See the IMHH Deed, cl 1. 255   See eg LOGIC, Supply of Major Items, at cl 23. 256   A straightforward liability cap is of course a limitation clause and is therefore subject to a number of the controls imposed in UCTA, discussed at paras II-6.28 and II-6.77. For the reasons given at para II-6.77, it is thought unlikely that the courts would decline to enforce a cap on liability in all but the most unusual circumstances. However, it is also possible to draft these clauses as indemnities: for reasons similar to those given in para II-6.75, this is necessary if the intention is to extend the effect of the cap to groups. 253 254

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by reference to particular species of loss, but by reference to a total sum payable. Such caps have the benefit of providing at least a level of certainty as to overall liability257 and facilitate the obtaining of insurance.258 In any given clause, the limit or cap may be expressed in one of a II-6.84 number of different ways: either as a fixed sum of money (often the maximum amount of insurance available at an economically viable rate) or as a proportion (or multiple) of the sum payable for the job. However it is expressed, the level at which the cap is to be set is essentially a commercial matter to be agreed between the parties, albeit if the cap is set too low, there is a risk that it could be deemed unreasonable for the purposes of the Unfair Contract Terms Act 1977.259 Liability caps are commonplace in oil and gas contracting practice.260 Such clauses are less frequently written about, simpler to understand and somewhat less technically demanding to draft than either indemnity or consequential loss provisions.261 However, they are not wholly without legal difficulty. As we have already seen, an inappropriate level of liability could lead to difficulties with enforcement under UCTA 1977; and it would be prudent for the clause to clarify if it is intended to take effect even against the proferens’ own negligence. Moreover, consideration needs to be given to the interaction between the liability cap and other risk allocation provisions and, in particular, third-party claims. In WesternGeco Ltd v ATP Oil and Gas (UK) Ltd,262 the liability cap was held to apply only internally to the parties and not to have the effect of limiting the amount payable as a result of an indemnity granted against third-party claims. Contractors therefore need to understand that if the liability cap is intended to take effect against an indemnity against third-party claims, very clear and specific wording will have to be used. Liability caps are particularly important in circumstances where II-6.85 the parties are not prepared to agree to a mutual hold harmless indemnity and/or consequential loss regime.263 In these cases, the

  See the discussion at para II-6.85 relative to third-party issues.  Roberts, Petroleum Contracts, para 13.61. 259  See the discussion of UCTA at para II-6.28. See also Roberts, Petroleum Contracts, para 13-81. 260   See eg LOGIC, Supply of Major Items, cl 35. 261  This is not to say that such clauses create no difficulties. One sometimes encounters liability caps which are subject to exclusions – where this is so, proper risk management requires that the effect of the exclusion must be clearly understood before the clause is agreed to. In addition, the inter-relationship between the liability cap and the warranties provisions in the contract needs to be closely considered. 262   [2006] EWHC 1164 (Comm). 263  As we have already seen, indemnities are not uniformly accepted in all oil and gas contracts: see para II-6.26. 257 258

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liability cap is the only clause which stands between a party and the prospect of unlimited – and potentially exorbitant – liability. The importance of the clause is perhaps most clearly demonstrated in the context of applications for access to infrastructure, where owners’ refusal in some cases to agree to the bona fide enquirer’s request for a liability cap has jeopardised or even thwarted the whole commercial deal.264 II-6.86 A liability cap is arguably less important in cases where the parties have agreed upon an indemnity regime and/or exclusion of liability for consequential loss. The combined effect of these clauses is, or should be, to shut out a large number of the heads of claim which may result in losses disproportionate to the gains that a party had in contemplation when commencing on the project. However, even here a contractor should seek to obtain a liability cap for two reasons. First, some oil and gas projects are so valuable that even the potential losses which are unequivocally direct may be more than a contractor can comfortably bear. And second, even if the losses which the contractor fears should, strictly speaking, be shut out by the indemnity and/or consequential loss clause, there is always a risk that those clauses might for some reason be susceptible to challenge. A liability cap therefore performs the valuable function of providing a second line of defence against indeterminate or disproportionate liability. Any embarrassment felt by asking for a second line of protection should be swiftly overcome by considering just how dreadful the consequences are likely to be if something has gone wrong with the drafting of the indemnity or consequential loss clause.

  See para I-6.80.

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CHAPTER II-7 COMMERCIAL AGREEMENTS AND ISSUES IN THE TRANSPORTATION OF OIL AND GAS Laura Petrie

INTRODUCTION When assessing the viability of a potential oil and gas development, II-7.01 one of the key considerations in the earliest stages of planning will be for the Operator and other field owners to determine the most efficient and cost-effective offtake route. Originally this would have been a simple decision between construction of a pipeline or use of an offshore storage and tanker offtake system. In the current market, with the proliferation of smaller fields, a more developed network of existing infrastructure and the ever-present requirement to maximise economic recovery, there is a wider range of options to be considered. The increased development of smaller fields, with shorter lifespans, II-7.02 has resulted in a more “hub-based”1 transportation structure emerging in the North Sea. This utilises one key platform or floating production vessel with various spurlines linking to the individual fields.2 Use of such multi-field transportation arrangements helps to lower costs overall for parties but results in complex contractual arrangements due to the sheer volume of parties that need to be engaged.

  The reference to “hubs” relates to the systemic use of a single platform for satellite fields to link into. Following the Wood Report there is a growing awareness that the single platform and exit route being linked into may be ready for decommissioning prior to the satellite fields utilising the infrastructure and accordingly OGA is considering the “hub” approach in light of imminent decommissioning planning. 2   For example, the Scott platform acts as a “hub” for a number of fields in the Northern North Sea. 1

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II-7.03 Moreover, given the varied nature of most North Sea fields, there may be only crude oil, only gas or a mixture of both gas and crude oil to be extracted and each type of product requires specific transportation arrangements. This may require a single suitable offtake route or a combination of several pipelines to get from site to shore/ sale. II-7.04 Combination transportation arrangements (where more than one evacuation system or route is required) will be required where more than one product is produced by the relevant field (mixed gas and crude fields) and/or where the field is more remote and requires to utilise a hub platform (as outlined above) for initial processing followed by transportation-specific pipelines to get to shore.3 Each stage of transportation will be contracted for on a separate basis and it is the role of the field Operator to ensure that the various agreements “connect” to provide a full flow of production from the field to shore/sale. II-7.05 It is worth noting that almost all agreements used in relation to transportation in the United Kingdom Continental Shelf (UKCS) will be governed by English law, notwithstanding that in some cases they will relate to property matters (rights of access to areas of seabed, indemnification in relation to damage of property located in Scottish waters). This retains consistency with most field arrangements and the fact that the majority of licences which are granted are subject to English law. ARRANGEMENTS FOR TRANSPORTATION II-7.06 As highlighted above, the offtake route will vary from field to field and will also be subject to available infrastructure. There are several elements which must be taken into consideration when assessing how best to move production. Primarily, a field owner will be looking for a complete “site to shore” and, in some cases, a “site to sale” opportunity. II-7.07 Typically, the available options will be limited as a result of the type of hydrocarbon (crude oil and/or gas), the location of the development within the North Sea and available capacity in existing infrastructure.

 An example of such a field is the Rochelle Field (see www.endeavourcorp.com/operations/united-kingdom/assets) which first ties in to the Scott Platform before transporting gas and associated liquids through the Scottish Gas Evacuation (SAGE) system (as well as certain other wet gas products through SEGAL) and oil through the Forties Pipeline System (FPS).

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Site to shore In a site to shore option the field owner, or shipper, will be looking to obtain a holistic transport solution whereby one transporter, or a linked series of transporters, will take all production of all hydrocarbon forms and redeliver a marketable or sale-ready product at an onshore site. In these situations, the Operator may take control of the negotiations for all the field owners to ensure that all production is uplifted at the field and redelivered in a collective manner. This allows for better control of joint operating procedures where the Operator may be entitled to step in and take production (once it has been processed through the transportation infrastructure) in the event of field owner defaults. The Operator will seek to negotiate all major and minor infrastructure requirements and revert to the owners with a full offtake solution in place for approval. This process may require the use of various study agreements, confidentiality agreements and technical assessments to determine the suitability of a certain route for that field’s hydrocarbon specifications. In order to evacuate all hydrocarbons efficiently, the Operator may require to consider the use of two separate offtake routes, one for gas and one for crude oil, which may then also require some additional processing prior to entry into the relevant transportation systems. Subject to the offtake route selected the uplift procedures at the redelivery point will also require to be carefully managed. The majority of redelivery points either feed directly into the National Transmission System (NTS) or to sea, road or rail tanker delivery points with minimal capacity for storage so immediate uplift is required at the point of redelivery. Again, this is a point where it is beneficial to have the Operator engaged in the negotiation process from an early stage as redelivery to the Operator can be effected to allow co-ordination of a single uplift rather than multiple parties requiring to arrange collection of production. At this point the processed (and refined) products will be returned to the owner(s) for onward sale. Site to shore transportation arrangements will most commonly be used where each owner has specific commercial sale arrangements to differing buyers or where the sales of production are not being fed into the NTS.

II-7.08

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Site to sale Site to sale transportation options will occur where either (1) the II-7.12 production is intended to be inputted into the NTS, or (2) the transporter is acquiring 100 per cent of the production allocated for redelivery.

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II-7.13 The majority of the transportation arrangements will be negotiated as per site to shore transportation outlined above. At the point of redelivery, however, there will be no requirement on the owner(s) to uplift and instead the production will either pass directly into the NTS or be uplifted by the transporter purchaser. II-7.14 This option allows for a much leaner production and sale process. Once the hydrocarbons are into the relevant transportation system there is no requirement on the owner(s) to retake responsibility for production. Accordingly, the owner(s) will require to allocate fewer resources (personnel, monitoring, third-party engagement) to the asset and, moreover, will not require to make any specific lifting arrangements as everything will be managed under the transportation arrangements. II-7.15 As noted above, the Operator will negotiate the transportation arrangements but each owner will require to enter into his own sales agreement. Typically such agreements will simply refer to one hundred per cent of production, as opposed to a specific volume, so that there is no issue with reduced or failed delivery should the field not perform as anticipated. It is important that the sale arrangements are negotiated on a single owner basis, rather than collectively, in order to avoid any competition issues arising as a result of any perceived joint selling. Collective sale could also increase the risk of the joint operating agreement (JOA) being declared a partnership. II-7.16 Notwithstanding the required extent of transportation required, the options available for offtake routes will largely fall within one of two very specific categories. OFFTAKE OPTIONS II-7.17 There are two key offtake routes through which transportation of hydrocarbons can take place. These are the use of a pipeline or the use of a floating production storage and offloading (FPSO) vessel which will then commonly use tankers for onward shipping to shore. FPSO II-7.18 An FPSO unit is a vessel used for the production, processing and storage of oil at the field location until such time as a tanker is available to shuttle the hydrocarbons to an onshore location. In some cases an FPSO may be connected to a pipeline but in the UKCS, this is rare. The use of an FPSO can be a significant cost to a field owner, particularly if one requires to be constructed specifically for purpose, although these costs can be reduced if the vessel is a repurposed oil tanker.

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The FPSO will be a completely self-contained unit with capacity II-7.19 to process the hydrocarbons straight from the well, store them and then offload to tankers. Significant storage capability is important so that there is no need to continually maintain a separate tanker vessel at the field location, thus reducing vessel costs for the field owner(s). Although the Wood Review was critical of the use of FPSOs on the II-7.20 basis that they did not promote maximum overall efficiency, an FPSO is typically the offtake option of choice for remote or particularly deepwater locations where either there may not be sufficient existing infrastructure to tie-back to or where the cost of constructing seabed tie-in pipelines would be prohibitive for the field economics. Moreover, FPSOs can actually provide an attractive, cost-effective option for smaller operators or producers given their ability to be relocated and reused following cessation of production at one site. The use of an FPSO will give rise to one of two arrangements. II-7.21 Firstly, an owner, or group of owners, may wish to commission the construction of a bespoke vessel for use on a specified development. This can be vastly expensive and typically will only be done where the field economics can justify the costs of construction and where the owner(s) have multiple fields in close proximity (or which can be developed in order to allow relocation of the vessel) which would benefit from the availability of an FPSO. Alternatively, the owner(s) may elect to charter an FPSO under hire agreement from an existing owner. This contract will operate on the same basis as a normal vessel charter save that there will be increased indemnity structures4 and a longer period for the charter to allow for pre-development tie-in and the production period. Pipelines There are several major pipelines5 located within the North Sea, all of II-7.22 which ultimately redeliver hydrocarbons to shore for processing and refining. Furthermore, there are various pipelines running between the Netherlands, Norway and Belgium which seek to facilitate trading between the UK and continental European energy markets.6   Where an FPSO is subject to charter there requires to be detailed provisions for allocation of liability in instances of pollution, damage to third parties and loss of production due to vessel failure. These are more in line with pipeline transportation arrangements and obviously would not be an issue in the event of a directly owned and operated FPSO. 5   Such as Natural Gas Pipelines – Central Area Transmission System (CATS), Far North Liquids and Associated Gas System (FLAGS), Frigg UK System, Fulmar Gas Line, West of Shetland Pipeline (WOSP), SAGE pipeline, and Oil Pipelines – Brent System, Forties Pipeline System (FPS), Ninian Pipeline. 6  Interconnector (North Sea), Balgzand Bacton Line (BBL), Langeled pipeline and Norpipe. 4

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Given their key significance to recovery of hydrocarbon production there is a required element of transparency in the terms offered by all such major pipeline owners.7 To this end, the key terms for such infrastructure are commonly found on the website for the relevant transportation system.8 In most instances, the transportation system will comprise both a transportation pipeline and a production and processing plant or terminal. In addition there are a range of smaller transportation pipelines linked to mid-sized fields which feed into these larger pipelines allowing more remote sites access to the major infrastructure without requiring additional, significant, expenditure on offtake routes.9 Typically these routes will offer transportation and basic processing in order to ensure production will meet the required specification of the major transportation route. As highlighted subsequently in this chapter, the form of agreement which will be applied for the use of such pipelines will be based on a combination of the composition of the hydrocarbons to be processed and the level of services being utilised, including transportation, processing, operating and/or additional services. A key issue with the UKCS pipeline infrastructure is that a large proportion of it is ageing and near to decommissioning but still being used to almost full capacity. As a result there is a move for the existing owner-Operators to look to sell the infrastructure to third parties. A recent increase in the number of such sales10 has given the industry certainty as to the maintenance of such infrastructure and paved the way for more competitive tariffing approaches.11 As highlighted above, the offtake option selected will accordingly be based on several factors including location of the field, specification of the hydrocarbons to be produced, existing infrastructure and available capacity therein. Nonetheless, where the pipeline route is selected there are various common commercial arrangements and forms of agreement to document such arrangements which will be required.   See Chapter I-6.  For example, the SEGAL system (see www.shell.co.uk/business-customers/upstreamoil-and-gas-infrastructure/published-key-terms.html) or the Brae Infrastructure (see www. marathonoil.com/Global_Operations/United_Kingdom/Brae_Area_ICOP/), both accessed 24 November 2017. 9  Among others, SEAL and GAEL pipelines, Erskine infrastructure, Lomond infrastructure, Everest infrastructure, Shearwater system. 10  “BP sells Forties Pipeline to INEOS”, available at www.bbc.co.uk/news/uk-scotlandscotland-business-39476674 and “Apache offloads North Sea pipeline stake”, available at www.offshoreenergytoday.com/apache-offloads-north-sea-pipeline-stake (accessed 24 November 2017). 11   See Chapter I-6. 7 8

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FORMS OF AGREEMENT The securing of an offtake route will involve an extensive suite II-7.27 of agreements at every stage of discussions and development. The documents required can be broadly split into three areas, those required for the initial assessment of the potential offtake route or routes, those required to prepare the field site and the selected offtake route for transportation and finally the terms for the actual transportation. Initial assessment Once an offtake route or range of potential offtake routes have II-7.28 been identified for consideration it is not as straightforward as requesting terms and then entering into one agreement for transportation. There are various initial assessments and considerations which are required. Accordingly, there are specific agreements which are required to be allow these initial discussions and assessments to proceed. Confidentiality agreements Prior to beginning any meaningful discussions, the Operator of the II-7.29 field and the Operator/owner(s) of the infrastructure will want to ensure that any discussions or information shared are held in the strictest of confidence. In order to properly assess an offtake route for suitability, the Operator will require to disclose details regarding anticipated lifecycle of the field, expected production rates and specification of anticipated hydrocarbons. This is all information which could be commercially sensitive if made available to the wider industry. Similarly, the Operator/owner(s) of the infrastructure will seek to keep tariff, commercial arrangements and general discussions confidential so as to avoid establishing any precedent on the terms it offers.12 Confidentiality agreements or non-disclosure agreements, II-7.30 following a recognised industry standard form,13 will typically be entered into before any substantive discussions take place. These agreements should be very clear on the purpose of the discussions and also the scope of any subsequent sharing of information, such as from the Operator to the other owners or between the owners

  Indeed this commercial behaviour was one of the factors of third-party access that the Wood Review was highly critical of and that OGA has considered in its review of the use of ICOP and similar third-party access issues. See Chapter I-6 for further details. 13  Oil and Gas UK Confidentiality Agreement, available at http://oilandgasuk.co.uk/ product/confidentiality-agreement (accessed 15 May 2017). 12

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of the infrastructure (if there is more than one). The terms typically provide that in the event that any losses are suffered as a result of an unauthorised disclosure, monetary recompense may not be sufficient and the party facing such a breach will be entitled to seek injunctive relief.14 Furthermore, it has become common to see reference to a “mental impressions” clause whereby those having sight of the confidential information, or the relevant owner(s) on their behalf, undertake to not use or refer to any retained “mental impressions” during the period of confidentiality imposed by the agreement. Essentially this is intended to stop any individuals who may leave the employment of the relevant owner (whether field or infrastructure) and subsequently use such information in their new role. It is an extension of the “trade secrets” protection which is common in the United States and is beginning to make inroads into UK-based agreements. II-7.31 The terms of the confidentiality agreement will typically extend out for five years following termination of the discussions in the event that a subsequent transportation arrangement is not entered into. Where a transportation arrangement is entered into, the confidentiality agreement will fall away to be replaced by the confidentiality provisions in the relevant transportation agreement.15 Although this is a relatively lengthy period of time, given the time required to bring a development online, most parties will largely follow the industry standard without amendment. It is worth noting that where the industry standard form of confidentiality agreement is used for any matters other than transportation, this time period is typically shortened to three years. II-7.32 It is not unusual, where there are several offtake route options, for the Operator (and field owner(s)) to enter into multiple confidentiality agreements at the same time in order to progress discussions on all routes simultaneously. The definition of “Permitted Purpose” within the agreement will determine the extent of the use of any information gained pursuant to such discussion (ie whether it can only be used for the discussions with that disclosing party or by the recipient for wider review and consideration purposes) but will always remain subject to restrictions on further disclosure. This has the advantage of ensuring that there is no delay in discussion and ultimate selection of the most appropriate offtake route but can result in a host of agreements with live confidentiality obligations remaining in place for a number of years after the discussions have concluded.

  Ibid, cl 3.4.   Ibid, cl 5.1.2.

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Study agreements Once suitable routes have been determined then the next stage will be to undertake study agreements of the potential capacity of the proposed routes, the likely costs and adaptations required in order to link the field into those routes and assessment of the hydrocarbon specification to ensure compliance with the wider infrastructure specifications. There is no recognised industry standard for such agreements as each Operator (whether field Operator or infrastructure Operator) will usually have a preferred form which has been developed over time. Moreover, given their project specific nature a pro-forma approach would not be appropriate in the usual standard form contract areas such as seeking to allocate risk, determine cost sharing or apply standards for the work to be carried out. These agreements will set out the scope of the study work to be undertaken and the responsibility for instructing such work. The issue of where the work needs to be carried out (field or infrastructure) will determine which Operator undertakes responsibility. In some circumstances the study agreement will also set out either the preferred third-party contractor who will undertake the study work or a detailed tender process to source such a contractor. A timeline or end date for the work will usually also be included in order to manage expectations of the parties as to when a decision about the viability of such routes can be made. This will also include some form of commitment or undertaking about how and when updates or reports will be provided either on a staged or final basis in respect of the study. The level of investigation and study that is required will determine whether there is a need for staged reporting. Clear provision as to the allocation of costs for the study work will be set out within the agreement. However, the common approach is for all costs to be borne by the field owner(s) on the basis that it is their requirements that are necessitating the study work. On rare occasions where the study work may benefit more than the potential new shippers – for example, where there is benefit to the infrastructure owner in some way, or the information gained from the study can be passed out more widely to existing users of the infrastructure – then there may be merit in widening the pool of contributors to the costs of the study.16

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II-7.36

  One recent incidence (2016) of such cost sharing has been the various studies conducted on the Forties Pipeline System to find ways of potentially increasing capacity in the system and managing existing system constraints. Costs for this study work were borne between the owner, the existing users and a range of potential shippers who were in heads of terms negotiations with the owner.

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Once the results of such studies are known the field owner(s) will be better placed to determine the tie-in costs, feasibility of using such offtake route and the likely capacity or specification constraints which may apply.

Cost sharing agreements II-7.38 Where additional work may be required, such as engineering work or seabed surveys, or an extended piece of study work is required which may need to take place over a period of time, then the field and infrastructure Operators and owner(s) may additionally wish to consider the use of a cost-sharing agreement which allows a wider scope of work to be instructed or carried out in stages (as required) rather than being restricted to a single narrow project. Usually, the work to be carried out will be of benefit to both the proposed shipper and the infrastructure owner, hence the willingness for costs to be shared instead of carried by a single party. II-7.39 The key element of a cost-sharing agreement beyond the pricing and allocation of work costs is determining who will control the work to be done (field or infrastructure Operator) and also who will take responsibility for any cost overruns. If the overrun is a result of the fault of one side of the agreement, it may be that all cost overruns are picked up by the party at fault rather than a more equitable sharing of costs, particularly if it is that party that was wholly in control of the relevant work. II-7.40 Typically the need for a cost-sharing agreement will arise at the point where a suitable offtake route has been identified and selected, but still requires further study or investment to ensure it can accept the additional production. It is rare to see various cost-sharing agreements being used for the assessment of a range of viable options as they typically deal with work of a higher cost and increased time period which is out of step with assessment of multiple offtake options where the parties want clarity in a short time frame as to the best available offtake route. Pre-development phase II-7.41 Following selection of a single suitable offtake route (or combination of several pipelines to get from site to shore/sale) there will be a period of time required to get both the field facilities and the infrastructure ready for production to flow. During this time there will be significant technical and operational work undertaken to ensure that transportation will be possible. At this point, there may be an impact on other third-party facilities in the surrounding area or to any existing users of the infrastructure.

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Proximity and crossing agreements Where work requires to be undertaken near to or by vessels or equipment which will pass over any third-party pipelines, umbilicals or installations, there is a requirement to offer a form of indemnification to those third parties should any damage occur. The oil and gas industry has established standard form agreements to manage such situations.17 The key provision within these agreements is the cap on the indemnity offered. This can be as low as £500,000 but equally can rise to £50 million or more depending on the size of the neighbouring installation. The industry standard form (both for crossing and proximity) remains silent on the level of cap, indicating only a blank square bracketed space in the indemnity provisions for the parties to insert their agreed amount. As indicated, the level ultimately agreed will usually depend on the size and scale of the proximate or crossed infrastructure but can also be influenced by the negotiating size and position of the relevant parties. If an agreement cannot be concluded, then work usually cannot be carried out (as a potentially uncapped liability poses too high a risk) so it is important that agreement can be reached. As with any other liability provision in other agreements, the amount must be reflective of losses rather than a penalty so any figure proposed should be able to be supported by reasoning and quantification if required. Depending on the scale of work to be done in proximity to, or crossing of, the third-party infrastructure the agreement may set out the scope of initial work and also allow for future additional works either within a specified time period or for so long as the relevant agreement subsists. There will be a very specific indemnity regime included allowing for any and all direct losses which may be incurred by the thirdparty infrastructure owners as a result of the works being carried out for the purposes of the new transportation link. The key difference within the indemnity regime of proximity and crossing agreements is that there will be an acceptance of some elements of consequential loss, arising as a result of the Work being carried out, including liability for loss of production, loss of profit and/or shut-in costs.18 This indemnity will be subject to the overall cap agreed (as outlined above) so that notwithstanding the acceptance of some conse-

II-7.42

II-7.43

II-7.44

II-7.45

  Oil and Gas UK standard form contracts, available at http://oilandgasuk.co.uk/product/ pipeline-crossing-agreement-proximity-agreement-pack-october-2015 (accessed 17 May 2017). 18   Cl 5.1(b) of each of the Oil and Gas UK Proximity Agreement and the Oil and Gas UK Crossing Agreement (see note 17 above). 17

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quential losses, there is clarity for the indemnifying party or parties as to the level of liability overall. II-7.46 As with confidentiality agreements, these arrangements will have a finite time period, typically lasting until completion of the work or for a defined period after the completion of any future additional works. II-7.47 Typically these agreements require minimal negotiation as the key points to be discussed are the level of the indemnification and whether any future additional works will be required. Construction and tie-in agreements II-7.48 Just as the proximity and crossing agreements set out the right to carry out work while indemnifying third-party infrastructure owners, the construction and tie-in agreement (CTIA) establishes the same arrangements between the field Operator and owner(s) and the infrastructure Operator and owner(s). Furthermore the CTIA is the pre-cursor to the relevant transportation agreement and there will be a distinct crossover point when the rights and obligations of the parties under the CTIA will then switch to the rights and obligations under the transportation agreement and the CTIA will be deemed to be terminated. There is no agreed form standard version of a CTIA and each one will be drafted and negotiated on a transaction-specific basis. II-7.49 The CTIA must set out very clear responsibilities for the work to be undertaken and the completion markers for this. The allocation or sharing of costs for such work will also be outlined within the CTIA. For example, the infrastructure Operator will typically be responsible for ensuring that there is sufficient capacity, a clear point of origin for production to enter into the transportation system and, if required, the construction of access points, valves or flanges within the infrastructure to allow the field facilities to tie in to the relevant pipeline(s). Any costs relating to the administration of such work will usually lie with the infrastructure owner(s) but where any significant engineering or technical work is required this will be charged back to the field owner(s). The field Operator will take responsibility for ensuring there are connecting pipelines from the field facilities to the point of origin for production all of which will be for the account of the field owner(s). Notwithstanding any work that the field Operator may be carrying out, it is the infrastructure Operator which will determine when it is time to move to the commissioning phase, usually by issue of a notice to the field Operator. The field Operator will then respond with confirmation of a formal date on which initial production will be ready to flow and commissioning can commence. II-7.50 It is vital that there is a full commissioning process within the CTIA which dovetails with the point that transportation becomes

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fully effective under the transportation agreement. The commissioning phase is intended to push through first production from the field, establish a likely pressure and flow-through rate and clarify that the works completed under the CTIA have been properly completed. As with any works based agreement there will need to be provisions which allow for correction of any defective works and the repeat of the commissioning process following correction to ensure that the transportation system is fully operational prior to any charges relating to actual transportation are incurred. One key feature of the CTIA indemnity structure, which differs II-7.51 from other agreements noted in this chapter, is that there will be a payment and indemnification regime included for “shut-in” costs incurred by the infrastructure owner(s). This is in recognition of the fact that the existing owners will experience a curtailment in their right to ship production through the infrastructure during any period where flow-through requires to stop to allow works to be undertaken/connections to be made. The industry would typically consider such loss of production a consequential loss but in the circumstances (that such loss or stoppage is to directly benefit the party tying in) it is recognised that the owners should be compensated in some way for agreeing to have their right to production curtailed, albeit for a brief period, in order to permit access to a new shipper. The compensation agreed may be based on a daily rate (where the length of the shut-in is not necessarily known at the outset) or as a single lump sum amount. As with proximity or crossing agreements the CTIA will also II-7.52 include a significant indemnity regime in respect of any loss or damage to the infrastructure arising as a result of the works contemplated by the CTIA. This will again be capped and with a clear time period applicable (usually to the end of the commissioning phase) before the agreement ends and the transportation agreement provisions (and indemnities)19 take effect. Once the majority of the work required under the CTIA has been II-7.53 completed and commissioning is underway, there will be a distinct point identifiable at which time the transportation agreement, and accordingly the tariff or payment regime, will come into force. Movement of production Hydrocarbons produced from a field (“production”) cannot be II-7.54 moved from the field to any other location without an agreed set of terms relating to the movement, or transportation, of that

  As discussed below in paras II-7.64 to II-7.106 and II-7.110 to II-7.113.

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production. The key provisions of any form of transportation agreement are outlined below.20 However, there are different forms of transportation and additional services which may be bolted into the arrangements agreed for the use of infrastructure. Accordingly it is appropriate to understand the difference between such different types of transportation arrangement. Transportation agreements II-7.55 A basic transportation agreement, commonly referred to as a “TA”,21 is used where production is merely moved from one location to the other through the pipeline. The terms will include all the key matters outlined below22 but will not include any reference to services, additional processing arrangements or further agreement between the parties beyond the production entering, moving through and exiting the relevant pipeline. II-7.56 This type of agreement is most commonly used in the simpler transportation arrangements, where the field will have its own processing facilities (or other processing arrangements in place) and will manage all the service aspects relating to the transportation short of having a direct link to a site onshore or an FPSO. II-7.57 This simple arrangement is a viable approach due to the hydrocarbons produced being of a simple specification (ie low sulphur, low mercury, medium viscosity), a single type (ie gas or crude) and in line with the other hydrocarbons being produced in that area and utilising the same infrastructure. This means that minimal processing will be required at the field facilities and it will be a relatively simple process for the field Operator to ensure that any production meets the required specification for the relevant infrastructure. II-7.58 It is not unusual to see such a simple transportation agreement forming part of a wider chain of transportation arrangements where production is first subject to transportation and processing through another infrastructure system or where it is moved initially from the field to a suitable processing hub before being moved onwards to shore. Transportation and processing agreements II-7.59 Transportation and processing agreements, or TPAs, take the movement of production one step on from the TA outlined above.23 These agreements bolt in additional services to ensure that the field production is either brought up to specification for onward trans  See paras II-7.64 to II-7.106.   Can also be referred to as a transportation services agreements, or “TSA”. 22   See paras II-7.64 to II-7.106. 23   See paras II-7.55 to II-7.58. 20 21

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portation or readied for sale. Accordingly they will typically sit at the beginning or end of a transportation chain or be capable of providing stand-alone transportation and redelivery arrangements from the field facilities direct to shore. The key difference between this agreement and the transportation, II-7.60 processing and operations services agreement (TPOSA)24 as outlined below is that the field Operator will continue to retain the control of operations overall and the infrastructure Operator will defer to the field Operator for any operational decisions during the period and scope of the TPA. The field Operator will continue to manage all operations during transportation. This means that the field Operator will retain responsibility for II-7.61 all notification and liaison processes with the onshore refinery and/ or storage site and will require to engage on a daily basis with all parties included within the transportation matrix. Where there are minimal stages to transportation, field operations are largely well developed and the field owner(s) do not have a large number of sites under the supervision of the single Operator this can be a manageable situation as resources are likely to be available to allocate personnel to manage these arrangements and undertake the continual monitoring and notifications required. However, where the opposite of such positions is the case, then the TPOSA25 can offer a more suitable alternative. Transportation, processing and operations services agreement (TPOSA) A TPOSA offers a completely holistic transportation arrangement II-7.62 for a field. Combining the transportation and processing capability of a TPA,26 the TPOSA also bolts on additional operational services. This means that once the production enters the infrastructure from the field facilities (or prior transportation infrastructure where a chain is required) it is wholly managed and controlled (within the parameters of the terms of the TPOSA) by the infrastructure Operator. This allows the field Operator to take a more supervisory role and focus on other elements of the relevant field, or indeed other multiple fields. Typically, where a chain of transportation is required there will II-7.63 be at least one TPOSA in place, if not several. They are especially common where a field has a mixed hydrocarbon production. Such agreements will follow, by and large, the same structure and key provisions as a TA or TPA but will have greater detail surrounding   See paras II-7.62 to II-7.63.   Ibid. 26   See paras II-7.59 to II-7.61. 24 25

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the rights, liabilities, obligations and respective roles of the various parties to account for the operational activities. Key negotiating points II-7.64 As outlined above27 whether a field requires a TA, TPA or TPOSA, or a combination of all three, it is the scope of the agreement which will vary rather than the key terms. There are various common issues which arise irrespective of the services offered and which will largely be negotiated commercial points for discussion between the respective owners. Depending on the bargaining position and commercial weight of the infrastructure owner(s) in some situations these points can represent deal-breaking points or non-negotiable positions but most are usually willing to engage in some discussion or at least use them as trading points. II-7.65 It is also worth noting at this point that competition issues also frequently arise in respect of these points in transportation arrangements. Due to the monopoly position some infrastructures hold in certain areas of the UKCS (meaning there are no other alternatives for transportation in that area) then an intransigent position on any of the following points by an infrastructure owner could be argued to be an abuse of a monopoly position. In such instances, the use of ICOP and other third-party access remedies28 becomes much more significant in order to establish that the position is not in breach of competition law and is in compliance with “maximising economic recovery”. Capacity booking II-7.66 Within the relevant transportation agreement, the field owner(s) will have a specified capacity or ullage available to them for the purposes of shipping production. It is accepted by the infrastructure owner(s) that this capacity will not be utilised in full every day by every shipper and accordingly the transportation agreement will include procedure for booking of capacity on a daily basis. II-7.67 At the point of negotiating the transportation agreement, the field owner(s) will have a clear idea of the anticipated production schedule and related daily and monthly flow rates. A form of this schedule will be included in the transportation agreement and the maximum level of throughput anticipated by that schedule will be the maximum capacity made available to the field for the shipping of production.

  See paras II-7.54 to II-7.63.   See Chapter I-6.

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Notwithstanding the agreed overall capacity in the infrastructure II-7.68 the field owner(s), through the field Operator, will have the right to make daily capacity nominations29 which use either all or part of their maximum available capacity. Provided that the requested capacity and anticipated production flow is not lower than the agreed minimum production for any given day (which will also be included in a schedule to the relevant transportation agreement) or higher than the agreed maximum capacity then the field owner(s) will be able to flow production without any restrictions or the incurrence of any send or pay rates. In the event that the field owner(s) wish to produce more on II-7.69 any given day than the maximum agreed capacity, then a further nomination30 can be provided together with the firm nomination requesting that any available additional capacity be allocated to the field owner(s) to allow throughput of such extra production. Available additional capacity will arise due to other fields using the infrastructure which may be shut in, failing to send production which utilises their maximum capacity or where the infrastructure owner(s) have reserved capacity to themselves to benefit from such situations. Capacity and the level required is becoming a significant commodity II-7.70 in the UKCS in recent years, both in the sense of importance to the industry and in the ability to trade the same for value. In particular, the older yet still very active infrastructures have recently undertaken capacity studies to determine how best to increase this.31 Tariff The tariff to be charged for the transportation may be a simple II-7.71 formula linking the level of production being transported to a multipler which reflects the commercial expectations of the infrastructure owner(s) or it can be a complex layering of various costs, expenses and margin which takes into account a single payment by the shipper for all costs associated with transportation. Under the first approach, the infrastructure owner(s) will have II-7.72 calculated the multiplier by building in elements for their own costs and expenses and also allocated a profit margin. This figure will usually be presented as a single multiplier with limited (if any) background information as to how it has been calculated. Notwithstanding the need for transparency, the infrastructure owner(s) will be in a position to propose this provided there is a clear internal mechanism for reaching the relevant multiple which could be provided should   Usually referred to as “firm nominations” or “fixed capacity nominations”.   Referred to as the “reserved capacity nomination”. 31   See paras II-7.33 to II-7.37. 29 30

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the tariff be challenged. Ancillary costs for transportation (such as EU Emissions Trading Scheme (ETS) credits or similar taxation or customs-related matters) will remain the responsibility of the field Operator and owner(s) to make payment for directly to the relevant authority. This approach is largely utilised for simple TA or TPA arrangements where the field Operator retains control of the majority of operational and day-to-day management arrangements surrounding the transportation in any event or perhaps where the majority of processing is undertaken at the field facilities or within other transportation arrangements. On that basis, the management of and responsibility for any such ETS credit payments or similar costs will remain with the field Operator. II-7.73 An alternative calculation method sets out an allocation for the costs and expenses referred to above, the costs for operational services including the payment costs for obtaining or managing tax-related or ETS credit-related expenses, management fees for such operational services and a clear uplift for mark-up on all such costs demonstrating the owner(s)’ profit margin. This is most common where a TPOSA is in use and the infrastructure Operator has agreed to undertake responsibility for a large proportion, if not all, of the transportation operating arrangements. The methodology for calculation in this approach is much more transparent to the field owner(s) but typically is less open to challenge or attempted negotiation. II-7.74 The tariff will be payable on either a monthly or a weekly basis depending on the level of production (high volumes may be charged weekly to avoid large bills arising). As noted below32 there will also be an annual reconciliation which will result in either an additional invoice or a credit note being issued by the infrastructure Operator. II-7.75 It is worth noting that the UKCS oil and gas market utilises a very free market approach to determining tariffs compared to other markets. In particular, the Norwegian system (in respect of gas transportation) is much more closely regulated by the governing authority and there is a cap on profit margin achievable by the infrastructure owner(s).33   See paras II-7.77 to II-7.79.  Gas transport tariffs have been subject to government regulation ever since the petroleum activities started in Norway. Since the mid-1980s, all licences have been granted on the basis that investments in gas infrastructure shall yield about 7 per cent in real rate of return before tax, and tariffs have been stipulated in a separate Tariff Regulation since 2003. The objective of the regulation of gas transport has consistently been to ensure that the transport terms are in accordance with fundamental resource management considerations, and that the profit shall first and foremost be extracted on the fields. The purpose of the Amendment Regulation is to promote optimum resource management, in accordance with the objective of the Petroleum Act. However, this is currently being challenged as a

32 33

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Following the Energy Act 2008, Energy Act 2011 and the more II-7.76 recent involvement of the Oil and Gas Authority in transportation and infrastructure there may be further engagement with the industry on tariff. While unlikely that the UK would seek to follow Norway’s model there may soon be clearer guidelines and regulations surrounding this than presently available.34

Cost switch Cost switch is a concept typically included within any transpor- II-7.77 tation agreement. It permits the infrastructure Operator to propose a change in billing from the agreed tariff based formula (howsoever calculated) to an allocation of all infrastructure-related costs on a proportional basis related to throughput. The timing for this will be based on the point at which the infrastructure owner(s) have determined that the running of the infrastructure on a tariff basis will no longer be economically viable. Accordingly the relevant transportation agreement will include a defined date after which the infrastructure owner(s) have the right to issue notice that the switch to cost share will take place. Cost switch is an issue which will be of especial concern to smaller II-7.78 fields. Usually, small fields will have been offered a modest tariff where they are only paying a very small proportion of the overall infrastructure costs (as these have likely already been covered by the tariff payable by other, larger shippers) and accordingly they will really only be picking up a small proportion plus a margin. On a switch to cost share, the allocation of costs is made on a much more even and transparent basis and is linked solely to throughput. This will likely increase the costs for such smaller fields and may then make field production uneconomic, resulting in early cessation of production. Obviously this is something which is contradictory to the Oil and Gas Authority’s principle of “maximising economic recovery” and therefore cost-switch provisions are being closely monitored by the Oil and Gas Authority.35 It is also becoming more typical that transportation agreements II-7.79 include a right for the infrastructure owner(s) to sell and automatically novate any transportation agreement on the same time frame as result of the proposed Amendment Regulation which seeks to provide greater restriction on the majority infrastructure owners. See www.regjeringen.no/en/topics/energy/oil-andgas/lawsuit-over-gassled-tariffs/id2406034 (accessed 11 May 2017). 34   See Chapter I-6. 35   See para 55 of the OGA guidance on third-party access disputes at www.ogauthority. co.uk/media/2712/oga_guidance_disputes-over-third-party-acccess-to-upstream-infrastructure.pdf (accessed 11 May 2017), which clarifies that infrastructure owners are not to be worse off as a result of granting access, but also para 57 which indicates that infrastructure owners require to have regard to MER.

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the proposed switch to cost share date. This is due to the fact that it may no longer be economically viable for the existing infrastructure owner(s) to continue providing transportation on the tariff basis but a newer, infrastructure-only owner, or group of owners, may be in a position to continue the tariff basis of charging for a longer period. As noted above, such infrastructure-only sales are becoming more common in the UKCS.36 Send or pay II-7.80 For the infrastructure owner(s) the send or pay concept is one which is an absolute requirement in agreeing any transportation arrangements. At the outset, the agreement will set down the anticipated daily flow rate of production so the infrastructure owner(s) can be satisfied that they will have sufficient capacity to provide transportation to the relevant field-related counterparty. If this capacity is not used in line with the anticipated daily production flow-through, the infrastructure owner(s) will still expect at least some payment to reflect the capacity being made available. This is relevant in all transportation arrangements but is most particularly true in high volume areas of the North Sea where some infrastructures could utilise the same capacity two or three times over where it was available. By failing to send production on any given day for which production has been agreed the relevant field owner(s) responsible for such failure are risking restricting the infrastructure owner(s) rights to benefit from the sale or use of the available capacity. II-7.81 This issue is dealt with by the simple solution of a “send or pay” clause. Essentially this states that the field owner(s) will send at least the minimum agreed quantities of production every day and, if not, they will still be required to make payment of the tariff for such minimum amount. The send or pay quantity will be calculated in one of two ways. For a field with a high level of daily production, the minimum quantity will be set as a proportion of the anticipated daily throughput and the applicable tariff applied will simply be the usual agreed tariff. Alternatively, where a field has a relatively low daily production level, the minimum quantity will typically be the full anticipated daily throughput but the tariff payable will be a reduced percentage of the usual tariff. II-7.82 The minimum quantity applicable for send or pay (or the related deduction to tariff) is usually a heavily negotiated position. The minimum quantity will rise and fall with relevant stages in production37 and obviously it will be in the owner(s)’ interests to   See paras II-7.22 to II-7.26.   In the early days of production and during the run-down to cessation of production, where throughput is likely to fluctuate greatly from day to day, the minimum quantity

36 37

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have this as low as possible while the infrastructure owner(s) will seek to have the bar set as high as possible. Send or pay is not a concept exclusive to the oil and gas industry. II-7.83 It is not uncommon in numerous industries or commercial arrangements to have to pay cancellation fees or cover the costs of services to ensure they are available even if you do not ultimately use them, however, in the oil and gas industry this typically generates a higher price for failing to meet obligations. As with take or pay provisions in gas sales agreements, there has historically been a concern that such clauses may fall foul of the rule against penalties in English contract law; however such fears would seem to have been allayed by the Supreme Court’s decision in Cavendish Square Holdings v El Makdessi,38 which adopts a more permissive approach to the question of penalty than had hitherto been present in the law.39 However, in the new MER-centred era, this is not an end to the matter. As with all other aspects of transportation agreements noted in this chapter, there is a risk that the infrastructure owner(s) will face scrutiny from the Oil and Gas Authority, who may call for greater transparency or even impose sanctions in respect of send or pay clauses which are deemed to be penal in nature. Accordingly, in negotiating these provisions, infrastructure owner(s) must have regard to being clear in their objectives and likely losses and the field owner(s) should ensure there is transparency and consistency in all such provisions. Shut-in rights As noted above,40 failure to use the capacity booked and the services II-7.84 agreed can still result in the field owner(s) incurring tariff costs subject to send or pay provisions. Notwithstanding this, there will be days when there is required stoppage of production flow for the purposes of scheduled maintenance or as a result of unforeseen health and safety issues. During negotiations the field owner(s) and Operator will have to II-7.85 determine a set number of days they anticipate such shut-in might occur and seek to provide for this in the relevant transportation agreement. The agreement will then make provision in one of three ways. Firstly, where the shut-in is as a result of planned maintenance days, then the infrastructure owner may agree that there is no charge agreed will be much lower than during the mid-life cycle of the field when production flow rates will be at their peak. 38   Cavendish Square Holding BV v El Makdessi [2015] UKSC 67. 39  B Holland, “Enforceability of take-or-pay provisions in English law contracts – resolved”, 34 (2016) JENRL, 443–453. 40   See paras II-7.80 to II-7.83.

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payable on such days or a small administrative charge may apply for the purposes of shutting in the field for those maintenance days. Typically if a fee is charged it will be clear that this is purely to cover costs. II-7.86 Secondly, if the shut-in is as a result of an unforeseeable and unplanned health and safety-related incident the agreement will usually specify whether no payment will be required and production and charges will be taken as frozen until the matter is resolved or, alternatively, if minimum send or pay provisions will apply with a right of clawback if it is later established that the health and safety fault was completely unavoidable (eg act of God or similar force majeure type event) or was the fault of the infrastructure owner(s) or Operator. II-7.87 The final approach will be for unplanned maintenance shut-in. In this instance, shut-in will be required as a result of some form of breakdown or mechanical or technical issue with the field facilities. Typically the infrastructure owner(s) are completely unwilling to share the pain on such incidents and send or pay provisions will apply as normal during such shut-in period. Notwithstanding the infrastructure owner(s)’ protective approach to such unplanned shut-in there will usually be a recognition that in some instances matters may be outwith the control of the field owner(s) and/or Operator. In such instances, where the unplanned shut-in continues for a set period of time there will usually be provision in the transportation agreement that after such period has passed the applicable tariff will either be waived or reduced by a specified amount. II-7.88 The combination of shut-in days, minimum quantity for send or pay and the fixed or firm capacity bookings are three points which will typically be discussed, negotiated and agreed in a joint fashion given their strong inter-relations throughout the transportation agreement. End dates II-7.89 As noted above41 the infrastructure owner(s) will have addressed the anticipated end date for the infrastructure through the early indication of cost share and thereafter a date after which full shut-in may occur. The field owner(s) will also have to identify the anticipated life of the field and account for this within the relevant transportation agreement. The field owner(s) will already have considered this when determining the production profiles to be included in the agreement in relation to send or pay and capacity provisions but will need to establish whether the agreement will

  See paras II-7.77 to II-7.79.

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terminate on the issue of the cessation of production notice, at a defined time (with the opportunity to extend as required) or simply on delivery of notice of intended termination. For the infrastructure owner(s) a cessation of production end date II-7.90 is always preferable. This ties the field to the infrastructure for the entirety of its producing life and provides a guaranteed income route during such period. The field owner(s) will obviously be keen to limit exposure as II-7.91 much as possible and ensure there is an ability to alter transportation arrangements if the opportunity arises. In most cases, there will not be any alternative offtake routes which are truly viable other than the one contracted for. However, particularly in developing areas of the UKCS,42 it may be that as the infrastructure in the local area increases the field owner(s) will want to reconsider their options. To this end the right to terminate on notice will obviously be preferable but would require significant negotiation with the infrastructure owner(s) and may result in a slightly higher than anticipated tariff to offset the risk of termination faced by the infrastructure owner(s). Specification There are no two fields of hydrocarbons which will produce exactly II-7.92 the same specification. Accordingly all transportation systems have ranges of tolerance for the mix of hydrocarbons which can be accommodated. In some instances an infrastructure system will have a very tightly II-7.93 controlled specification and the relevant infrastructure Operator will not accept any production which does not meet this standard.43 In other instances, additional services may be offered (such as mercury treatment, sulphur reduction) to ensure that the production meets the required specification at the point of entry. Due to the impact that failure to meet specification could have II-7.94 both on the infrastructure itself44 and to other users within the infrastructure system (by affecting the ultimate product redelivered to those third-party users) the field owner(s) require to provide a range of indemnities should production be “off-spec”.

  Such as the West of Shetland.  “Forties Blend” is the hydrocarbon mix returned to shippers on redelivery from the Forties Pipeline System (FPS). It is a recognised, marketed product that can command a reasonable price and the FPS Operator strictly control the entry specification of any new fields coming online to ensure that the blend remains as stabilised as possible. 44  A vastly different specification could have corrosive effects on the infrastructure (particularly in perishing valves) or risk leaving deposits which could damage the pipelines over time. 42 43

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II-7.95 In negotiating these provisions the infrastructure owner(s) will look to have as many issues and eventualities covered as possible, including any time required to shut down and clean the system. The field owner(s) will need to be willing to accept a fair proportion of liability in such instances but would not usually extend this to consequential losses. II-7.96 It is worth clarifying that seeking to cover off-specification risk with insurance is not always a viable option. Bespoke insurance products are available for these risks but the cost is usually prohibitive for most field owner(s) and the ones which could cover the cost of the insurance would also be able to deal with the costs of being off-spec. Indemnity regime II-7.97 In addition to the indemnities provided for any production being off-spec the field owner(s) will require to provide the usual “knockfor-knock” or mutual hold harmless indemnities in respect of their own people, property and any losses incurred by third parties which are attributable to the field owner(s) or Operator.45 The infrastructure owner(s) will usually offer such reciprocal indemnities in respect of themselves, the infrastructure Operator and any other third-party users shipping production through the same infrastructure system. Where there is a significant number of third-party shippers, it is likely that the infrastructure Operator will instead look to use a cross-user liability agreement (CULA)46 to manage liability of all parties without accepting any excessive exposure or requiring to act as a co-ordinator for any claims. II-7.98 In addition, the field owner(s) will require to indemnify the Operator in respect of any losses to the infrastructure caused as a result of any negligence or wilful misconduct of any field owner(s) or the field Operator. This can include catastrophic losses where the reason for the loss is wholly attributable to the field owner(s) or Operator. However, it is common for such indemnities to be limited to a capped amount. II-7.99 The use of the industry standard mutual hold harmless approach across transportation agreements provides for a simpler system of indemnity coverage than would otherwise exist, and focuses the negotiation points around the level of responsibility to be taken in respect of the infrastructure where a loss or incident arises as a result of the fault of the field owner(s) or Operator.

  For further discussion of these indemnities see Chapter II-6.   See para II-7.107.

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Capacity – collective or shared Just as the capacity utilised by the shippers will be divided among many users, so too can the capacity on offer be divided among different infrastructure owners. This issue is not necessarily a negotiated position but it is worth understanding the background to provision of capacity in order to understand how the resultant transportation arrangements will be contracted for. Largely, the infrastructure Operator will negotiate both the transportation terms and tariff on behalf of the infrastructure owners who will collectively own the full capacity available for transportation. The infrastructure Operator will then manage all invoicing, payment and distribution of funds to the infrastructure owners (in their respective proportional interests as applicable). Nonetheless, there are at least two other structures of ownership and capacity offering which are present in the UKCS. One alternative model47 sees the infrastructure Operator agree all technical and indemnity provisions directly with the field owner(s), entering into a transportation agreement which does not include any tariffing, send or pay or invoicing provisions. These terms will be included in a separate commercial agreement with each individual infrastructure owner. In some cases, the field owner(s) will require to enter into several such commercial agreements (which will cross refer to the relevant transportation agreement) with various infrastructure owners in order to achieve the required capacity. This is usually not an overly complicated approach as ultimately it is merely two or more agreements which cross-refer to each other and work together to provide the full transportation package. Another alternative method of providing capacity48 is where two (or more) separate groups of field owners have come together to construct infrastructure which they utilise for their own field production but which has additional capacity that can then be commercialised for use by third parties. In these instances, each group of infrastructure owners will have their own transportation and tariff arrangements and agreements but not necessarily sufficient capacity to offer full access on a sole basis. Nonetheless, in order to avoid competition law issues,49 each individual group will require to contract separately with the relevant incoming field owner(s), resulting in two or more transportation agreements for the same system which may have differing terms and differing indemnity structures.

II-7.100

II-7.101

II-7.102

II-7.103

  Utilised in the ownership and management of the SEGAL pipeline.   Shown in the approach used by the SAGE pipeline. 49  Primarily the risks of collusion, collective bargaining or price fixing. See further the discussion in Chapter II-11. 47 48

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New entrants/curtailments II-7.104 Lastly, following conclusion of the negotiation of all these terms, the field owner(s) will be loath to allow any external curtailment of their agreed capacity. However, the infrastructure owner(s) will be looking to maximise utilised capacity and will seek to accommodate as many users as possible. II-7.105 In order to manage these competing expectations there will be two specific provisions included within a transportation agreement. Firstly, there will be a curtailment restriction provision which states that an existing shipper or user will not have its capacity curtailed as a result of any new field joining the transportation infrastructure. This offers the protection a shipper requires but does not overly restrict the infrastructure owner(s) from giving access. II-7.106 The second provision will state that the infrastructure owner(s) will ensure that any new entrant is required to provide indemnity terms in a similar form to those granted by the relevant shipper (or enters into a CULA50 where one exists). In return, where any consent or agreement to a deed of adherence is required from the field owner(s) an undertaking will be provided that such consent will not be unreasonably withheld or delayed. In this way the infrastructure owner(s) have comfort that new entrants will not be unreasonably blocked and existing shippers will have certainty that the new field owner(s) utilising the infrastructure are required to adhere to similar terms, at least where allocation of liability is concerned. CROSS-USER LIABILITY II-7.107 Subject to the number of other third-party users in any single infrastructure network, it may be necessary to put in place a cross-user liability and indemnity regime. The agreement for this is commonly referred to as a CULA. With a significant increase in more remote and smaller fields coming online in the UKCS there is a greater pressure on existing infrastructures to give access to the owners of such fields. Traditionally, the infrastructure owners would have entered into direct indemnities under the relevant transportation agreement51 with each individual shipper or shipper group. The infrastructure owners will take responsibility for all other infrastructure users and utilise a “back-to-back” regime across all agreements in order to ensure it is fully protected should one user cause a loss to another. This approach, however, leaves the infrastructure owners in a “middleman” situation, requiring to deal with any and all instances of liability

  See para II-7.107.   See paras II-7.97 to II-7.99.

50 51

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which arise due to their engagement in all agreements and across all indemnities. Accordingly the industry has sought more frequently to use a II-7.108 CULA in such situations. The CULA provisions typically follow the industry mutual hold harmless structure and rely on a “knockfor-knock” indemnity structure to be put in place. Each party then further provides indemnity coverage for damage directly caused by it to the other users in specific circumstances (such as off-specification production).52 This provides a direct route between the various users to raise claims and reduces the potential administrative overheads for the infrastructure owner(s) and Operator. Once a CULA is in place, the owners of any new shipper field II-7.109 which wishes to utilise the infrastructure will require to enter into a deed of adherence to the CULA. This limits the scope for the new party or parties to negotiate the terms or request any amendments but given the largely industry standard approach taken to such agreements the terms are usually reasonable. DECOMMISSIONING AND THE FUTURE It is not possible to discuss infrastructure in the UKCS without II-7.110 making a passing reference to decommissioning. The infrastructure in the North Sea is ageing and largely in need of investment and upgrade in the majority of cases. As highlighted above, this is commonly dealt with by both including a right to switch to cost share to maintain the economics of owning the infrastructure53 and also providing for an end date for use of the infrastructure54 to allow the owners a literal “get-out” clause. In addition, it is becoming more frequent for infrastructure to become independently owned following a commercial sale of the infrastructure.55 This usually coincides with the relevant infrastructure owner(s) making the decision to also sell their field interests and, in some cases, seek to exit the UKCS oil and gas market altogether. Where a sale of such infrastructure cannot be realised, then this could lead to closure and decommissioning of vital facilities.56 The Oil and Gas Authority is working closely with the industry57 II-7.111   See paras II-7.92 to II-7.96.   See paras II-7.77 to II-7.79. 54   See paras II-7.84 to II-7.88. 55   See “BP sells Forties Pipeline to INEOS”, available at www.bbc.co.uk/news/uk-scotlandscotland-business-39476674 (accessed 24 November 2017) and “Appache offloads North Sea pipeline stake”, above n 10. 56   See www.ibtimes.co.uk/conocophillips-plans-close-one-north-seas-biggest-gas-pipelinesystems-1551990 (accessed 15 May 2017). 57  See www.gov.uk/guidance/oil-and-gas-decommissioning-of-offshore-installations-and52 53

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to ensure that such sales, closures and resultant decommissioning costs are carefully managed to avoid any adverse impact on users, the UK oil and gas supply and the industry generally. II-7.112 Notwithstanding the focus on this area, it is undeniable that the resultant decommissioning costs, whether arising in the near term or at a later date due to the rise in sales of infrastructure, will likely be significant. While this has increased the availability of commercial incentives, such as the decommissioning relief deed, to ensure that owners feel they are not facing all of the cost and responsibility alone it does raise wider questions on the future of transportation for the North Sea. II-7.113 Moreover, the Oil and Gas Authority’s focus on maximising economic recovery58, which in some instances could lead to a refusal to consent to a decommissioning project if significant reliance remains in place on the infrastructure in question, is likely to increase pressure on infrastructure owners. This in turn will only lead to more onerous terms (higher tariffs or immediate cost share requirements, increased indemnity provisions) under such a transportation agreement as have been discussed here. CONCLUSIONS II-7.114 The North Sea oil and gas industry has faced a turbulent time in recent years but notwithstanding these issues, the main commercial tenets of transportation remain the same. The industry is also presently59 facing significant regulatory changes and new approaches are being made in the management and stewardship of UKCS assets. II-7.115 It is likely that while the structure of transportation and the key terms for agreements relative thereto will remain the same, there will be changes in the way the infrastructure itself in managed and maintained. It is likely there will be a continued growth in infrastructure as a commercial vehicle independent of field interests and an increase in more ongoing maintenance and cost sharing associated with that. II-7.116 Nonetheless, the key principles of tariff, indemnities and specification will continue to be the primary focus in discussing transportation arrangements at a commercial level.

pipelines (accessed 15 May 2017). 58   See Chapter I-5. 59   As at 2017.

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CHAPTER II-8 PETROLEUM SALES AGREEMENTS Yanal Abul Failat

INTRODUCTION The value of petroleum in all its forms in providing heat and gener- II-8.01 ating electricity, as a chemical feedstock, as a transport fuel and making a profit, creates an incentive for investors, including states, to devote large sums of money to search for and develop it. When it has been found and successfully produced, oil and gas producers seek to realise profits through its sale. The industry is accustomed to the volatility of petroleum prices, which are deemed an integral part of its business and deals with a variety of market, basis, credit, operational and liquidity risks. In addition, market liberalisation and increased demand has led to the development of a number of routes to the trading market, through sales involving either the physical or the notional provision of the petroleum. Petroleum may be sold through long-term bilaterally negotiated sales agreements, short-term or medium-term sales agreements usually based on standardised terms, financial paper trades and options, exchange futures and cleared trades. These agreements regulate the sale of the most volatile and strategic of commodities. The extent of freedom of contract provided under English law II-8.02 has made it a popular choice of applicable law to govern petroleum sales agreements, not only for domestic contracts but also for international sale and supply contracts. Implied terms (and/or conditions) applying under national or international legislation may be contemplated in respect of petroleum sales agreements. Domestic petroleum sales agreements governed by English law may be subject to the provisions of the Sale of Goods Act 1979 (hereinafter “1979 Act”), which implies terms relating to title, description, quality and price

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into contracts for the sale of goods including petroleum.1 Under English law, the place of business determines whether a petroleum sales agreement is a domestic or international one.2 Generally speaking, petroleum sales agreements involving a cross-border sale are likely to be deemed international, in which case similar international instruments may apply. An example is the United Nations Convention on Contracts for the International Sale of Goods (hereinafter “Vienna Convention”), which deals with the passing of risk and remedies available for breach of contract.3 While many states have ratified the Vienna Convention, the UK has not, and, therefore, it is not part of English law. Nevertheless, it may apply to international petroleum sales agreements where both parties are domiciled in countries which are parties to the Vienna Convention where it is part of the substantive law applicable to the contract.4 With a view to contract on certain and satisfactory commercial terms suitable to oil and gas traders, parties commonly contract out or limit the application of the 1979 Act or the Vienna Convention noting that the extent to which such laws can be excluded may be restricted by applicable law.5 II-8.03 While petroleum sales agreements deal with similar aspects and issues (eg quality, quantity, delivery, price and other standard and boilerplate provisions), the unique characteristics of each of oil, gas and liquefied natural gas (LNG) naturally requires that agreements be tailored to meet the intricacies of the specific underlying commodity. Long-term bilaterally negotiated petroleum sales agreements, in particular, are often complicated and require extensive attention and negotiation. The aim of this chapter is to provide an overview of the

  Sale of Goods Act 1979, s 61(1). For the applicability of the 1979 Act to petroleum sales agreements, see P Roberts, Petroleum Contracts: English Law and Practice (1st edn, 2013) (hereinafter “Roberts, Petroleum Contracts”), pp 164–170. For example, the 1979 Act does not apply to contracts, such as National Balancing Point (NBP) trades, not involving the transfer of title in the petroleum or a delivery point. 2  See the Unfair Contract Terms Act 1977 (hereinafter “UCTA”), ss 26(3) and 26(4), which provides that an international sale of goods contract involves the sale of goods between parties whose places of business are in different states and which involve either the goods being carried from one country to another, the offer and acceptance having taken place in different countries, or that the goods are to be delivered in a country other than the country where acceptance took place. 3   The United Nations Convention on Contracts for the International Sale of Goods 2010, Arts 61–70. 4  D Peacock, “Avoidance and the Notion of Fundamental Breach under the CISG: An English Perspective”, in G Moens (ed.), International Trade and Business Law Review (vol 8, 2003), p. 97. 5   There are limitations under UCTA on a party seeking to contractually exclude or limit its liability. Note that under UCTA, these limitations do not apply to an international sale of goods contract. 1

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most significant commercial and legal aspects of contracts for the sale of oil, gas or LNG that are governed by English law. CRUDE OIL SALES CONTRACTS Form and Structure A contract for the sale and purchase of crude oil (hereinafter “Oil II-8.04 SPA”) can take many forms dependent on factors including the predetermined length of the trade, the method of transporting the oil, and whether the trade involves physical or nominal delivery of crude oil. In a single oil trade, a trader would need to arrange for a suite of documents other than the Oil SPA including: (a) the charter party to carry oil by sea; (b) an insurance contract; (c) an inspection contract in relation to quality and quantity of oil; and (d) a documentary credit for the payment and the price of the crude oil.6 In the United Kingdom, producers, refiners and traders sell or II-8.05 trade oil mainly through physical trades as well as financial trades (eg over-the-counter trades, financial paper trades, options and exchange futures). Accordingly, the market has attracted a broad set of participants such as oil companies, government agencies, commodity traders, banks, fund managers and shippers. While, traditionally, trades were almost exclusively physical, financial trades are increasing. For example, the framework agreement developed by the International Swaps Association, under which individual overthe-counter derivatives transactions may be carried out, has been modified so as to include a specific schedule for trading crude oil futures and options.7 Although term contracts are not uncommon, most crude oil is sold on a spot basis (ie the sale of a single cargo for immediate or short-term delivery) and is almost invariably carried by sea.8 Oil SPAs often consist of two documents. The main commercial terms are produced in written form, known as the “special provisions” (or specific conditions), which almost customarily incorporate detailed provisions referred to as General Terms and Conditions  See P Aston, “Main Features of Contracts for the Sale of Crude Oil and Refined Products, Including LPG”, in D Hickey (ed.), Oil and Gas Trading: A Practical Guide (1st edn, 2016), p 23. 7   See 1992 ISDA Master Agreement and Schedules, available at www.isda.org (accessed 14 May 2017). 8   H Wang, Civil Liability for Marine Oil Pollution Damage: A Comparative and Economic Study of the International, US and the Chinese Compensation Regime (1st edn, 2011), 1. 6

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(GTCs). This formulation reflects the rapid pace of the spot market, whereby parties negotiate and agree the most fundamental terms over the telephone or by email and then at a later stage agree the general terms of the contract and other details.9 II-8.06 Even though crude oil is a widely traded commodity globally, there is no industry standard Oil SPA.10 Efforts towards standardisation have been made by some institutions, including the Energy Institute, which published GTCs for the sale and purchase of crude oil on both a Free on Board (FOB) basis and Cost Insurance Freight (CIF) shipping terms.11 The GTCs can be incorporated by reference into FOB/CIF contracts, whether concluded orally, in writing or otherwise.12 It is envisaged that the GTCs are supplemented by a confirmation of the contract, which the GTCs would be incorporated into.13 The trend for Oil SPAs has been that major international oil companies draft their in-house bespoke GTCs.14 While these can vary significantly in approach to key contract issues, particularly when back-to-back contracts are involved, Oil SPAs tend to be largely standardised “as a matter of form, if not detail”.15 The BP Oil International Limited’s General Terms and Conditions for the Sales and Purchases of Crude Oil and Petroleum Products, 2015 Edition (BP GTCs) are commonly used in the UK.16 Other companies, including Shell, for example, publish a range of GTCs that are governed by English law tailored

 X Burucoa and J.-P. Favennec, “International Oil Markets”, in J.-P. Favennec and R. Baker (eds), Petroleum Refining (trans. R Baker, 1st edn, 2001) (hereinafter “Burucoa and Favennec, ‘International Oil Markets’”), p 88. 10  Roberts, Petroleum Contracts, p 44. 11   See HM 80. Model General Terms and Conditions for Free on Board (FOB) Sale and Purchase of Crude Oil (hereinafter “EI FOB GTCs”) and HM 81. Model General Terms and Conditions for Cost, Insurance, and Freight (CIF) and Cost and Freight (CFR) Sale and Purchase of Crude Oil (“EI CIF GTCs”) available at www.energyinst.org (accessed 14 May 2017). See EI CIF GTCs and EI FOB GTCs, Annex A, which defines “Confirmation” as “[T]he contract telex, facsimile, or other form of communication by which the parties confirm the Agreement, set out, amend or supplement these General Terms and Conditions … and which is the confirmation from the Buyer that it has agreed to purchase the Oil from the Seller and that it will pay the price of the Oil to the Seller’s bank account.” 12   EI CIF GTCs, cl 1; EI FOB GTCs, cl 1. 13   EI CIF GTCs, Annex B; EI FOB GTCs Annex B. 14   T Martin, “Model Contracts: A Survey of the Global Petroleum Industry”, 22(3) (2004) Journal of Energy & Natural Resources Law 281, at 296. 15   M Morrison, “Crude Oil Sale and Purchase Agreement”, in G Picton-Turbervill (ed.), Oil and Gas: a Practical Handbook (1st edn, 2009) (hereinafter “Morrison, ‘Crude Oil Sale’”), p 165. 16  BP Oil International Limited, General Terms & Conditions for Sales and Purchases of Crude Oil and Petroleum Productions (2015), available at www.bp.com (accessed 17 May 2017). 9

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for international trades or particular markets.17 While GTCs may be deemed less important than the Special Provisions, they require attention as they supplement the Special Provisions and contain detail dealing with various significant aspects of a transaction including warranties, indemnities, measurements and standards, demurrage, limitations of liability, force majeure, assignments, termination, governing law and jurisdiction.18 GTCs such as Shell’s often include as schedules various standard documentation such as letters of indemnity and letters of credit as well as additional provisions including for deliveries via specific routes.19 Typically, in the case of conflict or discrepancy, the terms of the Special Provisions prevail over the terms of GTCs.20 In the same light, the Special Provisions are also used to amend any provisions of the incorporated GTCs. The fact that acceptance of the GTCs and that of the Special II-8.07 Provisions occur at different times may raise uncertainty as to when the contract was formed. The usual principles of contract formation and interpretation under English law apply, which provide that for a binding contract to exist and to be enforceable, its terms must be certain.21 In Proton Energy Group SA v Orlen Lietuva,22 the court had to decide whether an exchange of emails amounted to a contract even though certain terms were not yet agreed.23 The seller’s offer consisted of a three-page “[f]irm Offer on Delivery of ABT 25KT of CRUDE OIL MIX offering to sell 25,000 MT +/- 10 percent at [the Seller’s] option of the Product CIF Butinge, Lithuania”.24 The offer warranted the product to be of European origin, and stipulated other terms including “UK Law; London Courts” and “[a]ll other terms and conditions as per seller standard CIF contract”.25 The purchaser replied stating that it agreed to a three-day laycan (and that it would shortly confirm the location), it accepted a documentary letter of credit subject to its treasury approving the text, and that there might be small amendments to the discount depending on the

  The various GTCs are available at www.shell.com (accessed 17 May 2017).  See the BP GTCs and Shell International Trading and Shipping Company Limited General Terms and Conditions for Sales and Purchases of Crude Oil (2010) (hereinafter “Shell GTCs”). 19   Ibid; see eg Shell GTCs, Schs A–G. 20   See eg BP GTCs, s 74.4; EI FOB GTCs, cl 1.4. 21  See M Furmston and G Tolhurst, Contract Formation: Law and Practice (1st edn, 2010), p 169. 22   [2013] EWHC 2782. 23   Further complications arise when contracts are not evidenced in writing, as the claimant party would have the burden of proving and evidencing the conclusion of the contract. 24   [2013] EWHC 2782, para 16. 25   Ibid, para 16. 17 18

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final contract conditions in respect of the above terms.26 The seller subsequently agreed to all the terms except the latter, to which it responded, “[c]ontractual price is fixed as per the confirmed offer. All other contractual terms not indicated into the offer shall be discussed and mutually agreed between the parties upon contract negotiations.”27 The purchaser then responded with a one-word email stating “confirmed”.28 The court, noting that the transaction reflected a typical spot deal, decided on the fact that a contract came into existence, as the parties agreed all the key terms despite leaving certain ancillary detail (which may be substantial) to be confirmed at a later stage.29 Therefore, the contractual terms must be set out clearly from the outset, and the special provision must not lack essential or fundamental components. Alternatively, the agreement would not be considered complete, and at best would amount to an agreement to agree, which would not be enforceable, and so providing the purchaser with the opportunity to retract itself from a loss making deal easily.30 The “Confirmation” envisaged under the Energy Institute’s FOB/GTCs provides an excellent example of what the Special Provisions may entail. It requires the purchaser (by telex, facsimile or other form of communication agreed) to confirm details of the parties, the grade of the crude oil, the quality specifications, the vessel arrival period, delivery point (and liftings), price, payment method and date, laytime, demurrage rate and governing law.31 The Special Provisions Grade and quality II-8.08 The Oil SPA should describe the essential characteristics of the crude oil that is to be sold. To encourage economic certainty, provisions within Oil SPAs relating to the crude oil are deemed as fundamental to an Oil SPA as their breach by the seller would entitle the purchaser to reject the goods and terminate the agreement.32 Moreover, three conditions are implied into Oil SPAs to which the 1979 Act applies, namely that:

  Ibid, para 17.   Ibid, para 17. 28   Ibid, para 17. 29   Ibid, 39. 30   J Cradick, “Global Commodity Price Falls and Challenges to Sale Contract”, Global Guide 2015/2016 for International Trade and Commercial Transactions, Practical Law 2015 (hereinafter “Cradick, ‘Global Commodity Price Falls and Challenges to Sale Contract’”), available at www.uk.practicallaw.com (accessed 1 May 2017). 31   EI CIF GTCs, Annex B; EI FOB GTCs, Annex B. 32   With the exception of termination for minor breaches. See 1979 Act, s 15A. 26 27

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p e t ro l e um sa l e s ag re e m e n t s 269 (a) crude oil should correspond with its description in the Oil SPA; 33 (b) crude oil must be of satisfactory quality;34 and (c) crude oil sold by sample must correspond with the sample in quality and be free from contamination, making the crude oil’s quality unsatisfactory, which would not be apparent on reasonable examination of the sample.35

Satisfactory quality in this context means that the crude oil meets II-8.09 the standard that a reasonable person would regard as satisfactory, taking account of any description of the crude oil, the price (if relevant) and all other relevant circumstances, including its: (a) state and condition; (b) fitness for all the purposes for which the crude oil is commonly supplied; (c) appearance and finish; (d) freedom from minor defects; and (e) safety and durability.36 In practice the implied terms in respect of quality are not so II-8.10 important since they are usually excluded, and the Oil SPAs would normally define the quality of the crude oil. The Oil SPA may provide that the quality of the product would be determined at the load port in accordance with the usual practice of the loading facility, which would issue quality certificates. Alternatively, the quality may be described by reference to standard industry specifications, including density and sulphur content, amongst other things. For example, it could be described as “XYZ blend crude oil, as normally produced from the field with general characteristics approximately …”, noting that such general description is often said to be provided for guidance only.37 Regarding liability, a seller would seek to agree that it shall have no responsibility for any deterioration in the condition and quality of the crude oil after shipment for any reason. Quantity Amongst the key terms in Oil SPAs are those relating to quantity, II-8.11 which should specify the quantity of the cargo precisely. It should do so by setting out the number of cargoes to be delivered as well as the load size for each lifting. By way of example, in spot deals,

  Ibid, s 13(1).   Ibid, s 14(2). 35   Ibid, s 15(2). 36   Ibid, 14(2B). 37   Morrison, “Crude Oil Sale”, p 166. 33 34

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the seller might be required to deliver one cargo of 800,000 net US BBLs. Under a 12-month term Oil SPA, the seller might be required to deliver four cargoes of 800,000 net US BBLS to be lifted quarterly. The Oil SPA may allow guaranteed flexibility at loading by including a variation tolerance percentage (for example, plus or minus 7 per cent) or even a range of quantities, which can be delivered and accepted (for example, 800,000 net US BBLS or 850,000 net US BBLS). Such provisions should set out the party entitled to make the election, which is normally the purchaser, and may be qualified by wording that provides that any lifting or exercise of the option be subject to the relevant terminal’s approval. In the absence of an express provision granting either party such an option, the general rule is that under FOB terms, the purchaser has the option, and under CIF terms, the seller has the option.38 Delivery, risk and title II-8.12 The Oil SPA should set out the conditions and the manner in which the seller delivers the crude oil to the purchaser and the exact delivery location or delivery point. It would generally either require the crude oil to be delivered onto a vessel nominated by the purchaser or delivered by the seller to a specified loading point.39 It is an implied condition under the 1979 Act (and usually warranted in the Oil SPA) that the seller has the right to sell the crude oil to the purchaser free from any encumbrance.40 The point of passing the title and risk (eg loss or damage to cargo or environmental damage such as pollution) in the crude oil is invariably linked to the delivery provisions and the delivery point set in the Oil SPA. The common law rule is that risk in goods sold on any of the above terms passes on or as from shipment.41 However, the shipping terms opted for largely determine the delivery obligations and the passing of risk and title.42 These mainly include the following. II-8.13 FOB. The seller is responsible for transporting (and bearing the cost of) the crude oil to the loading port or terminal at which point   Ibid, p 168.   R Clews, Project Finance for the International Petroleum Industry (1st edn, 2016), p 116. 40   1979 Act, s 12. There is authority indicating that this implied term may not be possible to exclude contractually: see Dalkia Utilities Services Plc v Celtech International Ltd [2006] EWHC 63 (Comm). 41   Soufflet Negoce SA [2009] EWHC 2454 (Comm); [2010] 1 Lloyd’s Rep 718, per Steel J, [16]; Affd [2010] EWCA Civ 1102; [2011] 1 Lloyd’s 1 Rep 531. 42  See the International Commercial Terms published by the International Chamber of Commerce defining the delivery obligations of parties to a contract for the sale of goods, available at https://iccwbo.org/resources-for-business/incoterms-rules/incotermsrules-2010 (accessed 1 May 2017). 38 39

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delivery is complete. The purchaser is then responsible for transporting (and bearing the cost of) the crude oil to the unloading port or terminal.43 Unless varied, risk and title pass to the loading port or shipment terminal. Cost and Freight (CFR). The seller is responsible for transporting (and bearing the cost of) the crude oil to the unloading port or terminal at which point delivery is complete.44 Unless varied, risk and title pass at the loading port or terminal. CIF. The seller is responsible for transporting (and bearing the cost of) the crude oil to the unloading port or terminal at which point delivery is complete. Unless varied, risk and title pass at the loading port or terminal. The seller is also responsible for taking out and maintaining insurance for the value of the cargo transported. 45 Delivered Ex Ship (DES). The seller is responsible for transporting (and bearing the cost of) the crude oil to the unloading port or terminal. The seller loads the crude oil on a ship and tries to sell it during the voyage, and, accordingly, delivery takes place at the delivery point.46 Typically, risk and title pass at the unloading port or terminal. Under the 1979 Act, the seller’s basic duty is to deliver the goods (and the purchaser to accept them) in accordance with the Oil SPA and such a duty is usually discharged through the physical delivery of the crude oil.47 In a traditional FOB contract, the purchaser must nominate a vessel and present it on an agreed date, at which the point the seller is under a duty to load the entire cargo before the end of the delivery period.48 If the seller fails to load the whole cargo within the delivery period, the purchaser would be entitled to reject the crude oil and terminate the agreement.49 In turn, under a standard CIF contract, the seller would be responsible for tendering contractual documents (ie bill of lading, insurance and invoice).50 The seller, however, would be concerned with shipping the cargo within an agreed shipment

II-8.14

II-8.15

II-8.16

II-8.17

  Burucoa and Favennec, “International Oil Markets”, p 83.   O T Gudmestad, A Zolotukhin and E Jarlsby, Petroleum Resources with Emphasis on Offshore Fields (1st edn, 2010), p 115. 45   Ibid, p 115. 46   F Lorenzon, “International Trade and Shipping Documents”, in Y Baatz, Maritime Law (3rd edn, 2014), p 99. 47   1979 Act, s 27. 48   P Todd, Maritime Fraud and Piracy (3rd edn, 2013), p 116; see also Cradick, “Global Commodity Price Falls and Challenges to Sale Contract”: the contract may alternatively stipulate the loading is at the purchaser’s option, requiring the seller to have the cargo ready for loading immediately upon the vessel’s arrival at the agreed load port. 49   D Lucas et al., “England and Wales”, in D Lucas, Shipping & International Trade Law (1st edn, 2011), pp 83–84. 50  Roberts, Petroleum Contracts, p 171. 43 44

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period. Failure to do so would entitle the purchaser to reject the goods and claim damages for non-delivery. It is noted that Oil SPAs are not typical and it is common that they incorporate CFR/CIF terms to stipulate a delivery period rather than a shipment period or even both.51 Further, Oil SPAs commonly provide for a laycan period, namely a period within which the vessel should arrive at the load port, ready to load; this is to be distinguished from shipment periods.52 If the seller causes a delay, the purchaser may recover damages in the form of demurrage (whereas termination is unlikely to be available).53 Accordingly, a purchaser must be cautious when declaring seller in default for late shipment as many Oil SPAs may provide the seller with an automatic right to serve notice of extension of the shipment period in return for deductions to the price. Any attempt by the purchaser to terminate the agreement before the seller exercising its right to service such notice may be deemed a repudiatory breach.54 Price and payment II-8.18 Under English law, the price may be fixed by the Oil SPA or may be left to be fixed in a manner agreed by the Oil SPA, or even determined by the course of dealing between the parties.55 If the Oil SPA does not set a price, or a mechanism to determine it, then the 1979 Act implies a term, which is that the purchaser must pay a reasonable price.56 What is a reasonable price is a question of fact dependent on the circumstances of each particular case. This opens doors to disputes and, accordingly, Oil SPAs invariably fix the price or provide a formula for calculating the price of the cargo indicating: (a) the reference benchmark;57 (b) the days considered for calculating the average value of the reference point;58 (c) the price difference to apply to the reference plus or minus for the specific object of the agreement; and (d) any automatic price adjustment provision in case of deviation in the quality of the crude oil delivered to the contractual standard.

  Morrison, “Crude Oil Sale”, p 170.  See SHV Gas Supply & Trading SAS v Naftomar Shipping & Trading Co Ltd [2006] 1 LLR 163. 53   “Cradick, “Global Commodity Price Falls and Challenges to Sale Contract”. 54   J Chitty, Chitty on Contracts General Principles (31st rev. edn, 2012), p 929. 55   1979 Act, s 8(1). 56   Ibid, s 8(2). 57   For example, Arabian Light or Brent Crude. 58  That is, the pricing period, eg the average of the month loading or five days around the loading date. 51 52

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The seller would invoice the purchaser showing the quantity that will II-8.19 be advised by the operator in the bill of lading accompanying the cargo and the purchaser would be obliged to pay that. The relevant GTCs may require that the purchaser pays the seller by telegraphic transfer within 30 days of the issuance of the relevant bill of lading, the payment must correspond precisely with the price and quantity provisions set out in the Oil SPA, and that the payment should be made in a certain currency (eg US dollars). In cases where original shipping documents are not available for delivery by the relevant party when payment becomes due, it is not uncommon for Oil SPAs to require the party who is obliged to deliver such documents to provide the other with a letter of indemnity for any losses arising thereof. GAS/LNG SALES AGREEMENTS Form and Structure There are many reasons why a relevant party would trade gas, II-8.20 including satisfying its core business (gas production and sale), balancing purposes, financial hedging, risk management, portfolio optimisation, or speculation or profit. Gas or LNG is sold using a Gas Sales Agreement (GSA), also referred to as gas sales and purchase agreement, which, broadly speaking, is an agreement under which a seller agrees to sell and deliver (or nominally deliver) gas to a purchaser. Gas may be sold under long-term GSAs, over-the-counter trades and other financial trade instruments.59 Thus, GSAs can take many forms, each distinguished by key characteristics, such as the means by which gas is transported and brought into the market (ie pipeline gas, LNG, liquefied petroleum gas or compressed natural gas) and responsibility for transporting the gas (eg a FOB or CIF deal).60 For instance, the gas within the LNG supply chain integrates upstream gas supply and liquefaction, with marine transportation and downstream regasification. Accordingly, while contracts for the sale and purchase of LNG (LNG SPAs) contain similar terms and conditions as other GSAs, the unique nature and features of LNG requires tailoring some of the common GSA terms to meet such specific needs.61  P Heather, “The Evolution of European Traded Gas Hubs”, OIES Paper NG104, Oxford Institute of Energy Studies 2015 (hereinafter “Heather, ‘The Evolution of European Traded Gas Hubs’”), available at www.oxfordenergy.org/wpcms/wp-content/ uploads/2016/02/NG-104.pdf (accessed 1 May 2017). 60   D O’Neill, “Gas Sale and Purchase Agreements”, in G Picton-Turbervill (ed.), Oil and Gas: a Practical Handbook (1st edn, 2009) (hereinafter “O’Neill, ‘Gas Sale and Purchase Agreements’”), p 137. 61   E Dyer, D Reinbott and M Williams, “Liquefied Natural Gas”, in G Picton-Turbervill 59

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II-8.21 GSAs (or LNG SPAs) can also be distinguished by the stipulated volume and source commitments and, accordingly, may be referred to as depletion-based agreements or supply-based agreements. Where the seller undertakes to produce for sale to the purchaser a specific percentage, or the entirety, of the saleable gas from a particular field, it is known a depletion-based GSA.62 In such a contract, the reservoir performance is directly linked to the quantities noted. These agreements are usually in place until the reserves are fully depleted unless a contractual termination is introduced. In contrast, a supply-based agreement is typically for a fixed term and refers to a situation whereby a supplier sells a specific amount of gas each day. Under a supply-based agreement, the seller is not tied to a particular source and may even engage a third party in trade. While in practice the difference between the two agreements is “rarely so clear”, they do have different formulations.63 For instance, under a depletion-based GSA, a seller would seek to ensure that it could claim force majeure relief in case of non-performance of the particular field. A seller would be unlikely to secure the same right in respect of multiple gas fields under a supply-based GSA.64 On occasion and given the seller wanting to benefit from force majeure relief regarding the source of supply, GSAs may be a hybrid form of both depletion and term supply agreements; such a form would specify the source of the gas supply.65 As gas markets become more and more competitive, depletion agreements are becoming less common.66 In the UK, GSAs entered into pre-1990 largely consisted of depletion agreements signed by British Gas with producers, on a field-by-field (or even well-by-well) basis, whereby British Gas had the right to purchase gas from those specific production points.67 Since the start of the millennium, there was a shift from depletion agreements to term supply agreements, a change which was influenced by market liberalisation and security of supply needs.68 II-8.22 The reason for trade largely determines the route to market, the instrument for the trade of gas and its term, which could range from a day to as long as the economic life of the field from which (ed.), Oil and Gas: a Practical Handbook (1st edn, 2009) (hereinafter “Dyer et al., ‘Liquefied Natural Gas’”), p 113. 62  G Vinter and G Price, Project Finance: A Legal Guide (3rd edn, 2006) (hereinafter “Vinter and Price, Project Finance), p 114. 63   P Roberts, Gas Sales and Gas Transportation: Principles and Practice (3rd edn, 2011) (hereinafter “Roberts, Gas Sales and Gas Transportation”), p 72. 64   Ibid, p 76. 65   Ibid, p 76. 66   K Talus, Vertical Gas Transportation Capacity, Upstream Commodity Contracts and EU Competition Law (1st edn, 2011), p 13. 67   Heather, “The Evolution of European Traded Gas Hubs”, p 30. 68   Ibid, p 30.

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the gas is produced.69 Conventionally, in the UK gas producers and importers sell gas to licensed shippers who then, as owners of the gas, arrange for it to be conveyed to onshore supply points via the National Transmission System (NTS) and then sell it to gas suppliers, large consumers or other shippers. More and more non-physical trades, however, are occurring after the gas enters the NTS.70 GSAs (and LNG SPAs), which involve the notional rather than physical delivery of the petroleum, are trading agreements and are to be distinguished from sales agreements involving physical delivery. A very common form of trading today is “over-the-counter trades”, namely physical deals concluded under bilaterally traded short-term or medium-term agreements on standardised terms. In the UK, there are two industry-standard terms for the trading gas, which need to be incorporated by reference into a GSA (or LNG SPA). First, the Standard Terms and Conditions for the Sale and Purchase of Natural Gas for UK Short Term Deliveries at the Beach Sub Terminals 2015 (Beach 2015).71 Under the Beach 2015, the seller tenders the gas for delivery to an agreed entry point, delivery of which must be accepted by the purchaser.72 Second, the NBP 2015 is a contract that is specific to the UK gas market under which trades of gas are deemed to take place at the National Balancing Point (NBP).73 The NBP is a national point to which all gas, which is entering the NTS is assumed to flow, and similarly, the gas leaving the NTS is assumed to come from the NBP.74 NBP trades are concluded under the Network Code and involve the seller making a disposing trade nomination and the purchaser making a matching, acquiring trade nomination.75 Other non-physical sales agreements that may be used to trade gas (or LNG) include the Model Master Agreement published by the International Swaps and Derivatives Association (governing derivative agreements including options and futures) published in 1992 and updated in 2002.76   V Chandra, Fundamentals of Natural Gas: An International Perspective (1st edn, 2006) (hereinafter “Chandra, Fundamentals of Natural Gas”), p 112. 70   D Beggs, “Term and Sport Sales”, in M David, Natural Gas Agreements (1st edn, 2002) (hereinafter “Beggs, ‘Term and Sport Sales’”), p 159. 71   The Standard Terms and Conditions for the Sale and Purchase of Natural Gas for UK Short Term Deliveries at the Beach Sub Terminals 2015 are available at www.gasgovernance.co.uk (accessed 1 May 2017). 72   Beach 2015, cl 6.4. 73   The Short-Term Flat NBP Trading Terms and Conditions 2015 are available at www. gasgovernance.co.uk (accessed 1 May 2017). 74   Joint Office of Gas Transporters, “The Uniform Network Code: An Overview of the Industry and its Processes” (2006), available at www.gasgovernance.co.uk (accessed 1 May 2017). 75   The Network Code, s C6; see also NBP 2015, definition of NBP Trade. 76  Roberts, Petroleum Contracts, p 44.

69

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II-8.23 Although spot and short-term arrangements on standard terms are becoming more common as the market liberalises and infrastructure proliferates, most gas and LNG is sold using long-term bespoke bilateral contracts supported by take-or-pay obligations.77 Banks and lenders prefer such terms (usually 20–30 years) to ensure that sellers, as developers of producing fields, have sufficient funds to cover their capital investment and debt obligations.78 In the case of LNG, some elements that result in a more diverse LNG SPA involve increased numbers of LNG purchasers in response to increased amounts of international LNG trade, new LNG projects that span the upstream to marketing phases, significant alteration in the balance between supply and demand of gas in the short term, and the introduction of spot markets in response to increase in liquefication, regasification and shipping capacity.79 Therefore, “new” LNG SPAs (like many GSAs) frequently include the following aspects: intermittent (threeto four-year cycles) renegotiation of pricing provisions, destination flexibility (allowing the purchaser to nominate cargo at loading phase, or even during the trip itself), local gas market regulation alterations, greater emphasis from purchasers on supply security and price flexibility (which is manifested in agreements of lesser duration) and seller agreed diversion upside sharing mechanisms.80 II-8.24 Whilst these aspects are commonly dealt with contractually, they are not found in every GSA (or LNG SPA), and it is hard to standarise long-term GSAs (and LNG SPAs) due to participant diversity, an assortment of gas markets (non-liquid, liquid and liberalising) and the range of commercial models available (equity or third-party sales).81 Bilaterally negotiated GSAs (or LNG SPAs), as typically traded in the “old world” are individually negotiated agreements on bespoke terms with many variations.82 Unlike trades made on standard terms, bespoke arrangements typically cover largevolume trades over long delivery periods. Every feature of each GSA including quality, location, quantity, volume and all relevant terms and conditions require negotiation. Because of their bespoke nature, drafters of such GSAs (and LNG SPAs) need to ensure a coherent bilateral legal and credit framework between the gas producer and   O’Neill, “Gas Sale and Purchase Agreements”.  Chandra, Fundamentals of Natural Gas. 79  G Bridge and M Bradshaw, “Making a Global Gas Market: Territoriality and Production Networks in Liquefied Natural Gas”, 93(3) (2017) Economic Geography 215, 227. 80   Ibid, 215, 227. 81  S Sakmar, Energy for the 21st Century: Opportunities and Challenges for Liquefied Natural Gas (LNG) (1st edn, 2013) (hereinafter “Sakmar, Energy for the 21st Century”), p 158. 82   Heather, “The Evolution of European Traded Gas Hubs”, p 25. 77 78

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the purchaser. As the industry has gained experience in negotiating GSAs, however, it could be said that “new” GSAs are agreed on more standardised terms than before. Moves towards standardisation or rather the use of long-term model form agreements include the following: The Long-Term Gas Sales Agreement for the sale and purchase of natural gas to be delivered by pipeline, published in 2006 by the Association of International Petroleum Negotiators (AIPN GSA).83 Its focus on the sale and purchase of natural gas to be delivered by pipeline is representative of the fact that pipeline gas constitutes the majority of traded gas.84 The Master LNG Sale and Purchase Agreement published in 2012 by the Association of International Petroleum Negotiators (AIPN SPA).85 This is a master agreement86 intended to be used for spot sales of cargoes of LNG. It provides a base contract (which sets out a checklist of options) and a confirmation memorandum form, which upon execution in respect of a particular cargo, effect the obligations to buy and sell the LNG.87 The Master DES LNG Sale and Purchase Agreement published in 2010 by The European Federation of Energy Traders (EFET SPA).88 The Master FOB LNG Sales Agreement and the Master Ex-Ship LNG Sales Agreement published in 2011 by the International Group of Liquefied Natural Gas Importers.89

II-8.25

II-8.26

II-8.27 II-8.28

Key terms of long-term GSAs (and LNG SPAs) Quantity and nominations GSAs would typically be drafted on the basis that the purchaser II-8.29 nominates the amount of gas, within limits, it requires to be delivered  The AIPN Model Form Gas Sale Agreement (2006) is available at www.aipn.org (accessed 1 May 2017). 84   O’Neill, “Gas Sale and Purchase Agreements”. 85   The AIPN Model Form LNG Sale and Purchase Agreement (2012) is available at www. aipn.org (accessed 1 May 2017). 86   AIPN, “Guidance Notes to the AIPN SPA” (2012), available at www.aipn.org (accessed 1 May 2017). AIPN’s model LNG sales agreement is drafted as a master agreement. A master agreement is in the context of oil and gas typically used for spot trading and contains provisions agreed by the purchaser and seller for future (and usually non-obligatory) sale and purchase of product (in this case, LNG). When the parties wish to buy and sell LNG, they enter into a contract for each particular sale, which incorporates and supplements their master agreement. 87   Ibid. 88   The EFET Mode Master Sale and Purchase Agreement (2010) is available at www.efet. org (accessed 1 May 2017). 89  The Master FOB and Ex-Ship LNG Sales and Purchase Agreements are available at www.giignl.org (accessed 1 May 2017). 83

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on specific days. The purchaser is not required to accept or purchase any gas beyond this nominated amount. The seller is equally not required to provide additional amounts beyond what the purchaser has nominated as the daily maximum. As far as is reasonably practical, deliveries are carried out according to a uniform rate. Article 10 of the AIPN GSA, for example, provides for the purchaser to give binding nominations before the commencement of a month or week for each day of that month or week.90 Nevertheless, the AIPN GSA allows for cases where nominations on a different period are applicable (eg hourly) or that a nomination could provide for varying volume during the applicable nomination period to allow the purchaser to nominate different hourly quantities during a day.91 Some GSAs, also, provide the purchaser with the option to increase an already agreed annual contract quantity to be delivered and offtaken in a future year by a certain amount or percentage.92 In LNG SPAs, a similar approach is applied: quantity obligations might include the delivery location of the LNG (FOB) or DES downward flexibility amounts (as set out below) where applicable for the parties. The seller would also make decisions in accordance with the situations associated with DES versus FOB sales. A FOB seller is subject to greater vulnerability as he is dependent on the availability of additional shipping capacity and in a situation where the purchaser implements its downward flexibility, excess shipping capacity enables the seller to deal with untaken amounts.93 Delivery, risk and title II-8.30 The GSA would normally specify a particular delivery point at which the title, property and risk shift from the seller to the purchaser. GSAs usually contemplate a single delivery point, and in the UK this point is typically one of three places: the Beach, the National Balancing Point (NBP) or the NTS input or exit point located downstream. Some GSAs allow for substitute delivery points, subject to defined conditions and circumstances.94 If the delivery point is downstream of the NTS exit point, it must be clear who owns the pipeline that   AIPN GSA, Art 10.   Guidance Notes to the AIPN GSA, p 21. 92   An example for such options to increase delivery quantities were the stipulations in the Troll Agreement between Norwegian sellers Statoil, Norsk Hydro, Sage, Shell, Mobil and Conoco, and purchasers Rhurgas, Thyssengas, BEB, Distrigaz and Gaz de France; see A Pustisek and M Karasz, Natural Gas: A Commercial Perspective (1st edn, 2017) (hereinafter “Pustisek and Karasz, Natural Gas”), p 110. 93  S Farmer and H Sullivan, “LNG Sale and Purchase Agreements”, in P Griffin (ed.), Liquefied Natural Gas: The Law and Business of LNG (2nd edn, 2012) (hereinafter “Farmer and Sullivan, ‘LNG Sale and Purchase Agreements’”), p 29. 94   Guidance Notes to the AIPN GSA, p 21. 90 91

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connects the NTS and the purchaser’s facilities.95 Warranties and representations in respect of title in the gas (or LNG) are usually incorporated.96 The timing of passing title and risk is critical, and most parties tend to link the transfer of risk with the completion of delivery. Similarly, the AIPN GSA stipulates that title to, and custody of, gas delivered passes from the seller to the purchaser at the agreed delivery point.97 This approach tallies with the 1979 Act, which provides that title in the gas would not pass while it is commingled with other gas but rather when it is ascertainable and made divisible (eg by an allocation agreement).98 Unless otherwise agreed, the risk in the gas would pass at the same time as title passes to the purchaser. GSAs often stipulate that risk passes with the title, namely at the time of delivery or rather when the gas reaches the delivery point.99 Where there is a gap between the gas leaving the seller’s possession and delivery taking place (eg because third-party shippers deliver the gas), the seller may seek to negotiate that risk passes to the purchaser at the point when the carrier takes possession of the gas. Purchasers would be particularly concerned with this and would seek to ensure that they have appropriate protection in regards to liquidated damages and consequential loss for the seller’s failure to pass title or deliver gas (or LNG).100 In the case of gas in the NTS, the risk is governed by the Uniform Network Code,101 which provides that “Transco” is liable for failure to accept gas for delivery into the NTS, in respect of non-compliant gas offtaken from the NTS, and for gas not made available for offtake. 102 In situations where the seller is unable to deliver the gas (or LNG), it must be determined whether the non-delivery constitutes: a permissible failure, where the seller is entitled to not deliver II-8.31 under the terms of the agreement (for example, to exercise a delivery interruption or scheduled maintenance rights); a relieved breach, where the failure to deliver the gas (or LNG) II-8.32 could be in violation of the GSA (or LNG SPA), but has occurred in circumstances under which the seller could claim relief (for example, a force majeure situation); or   Beggs, “Term and Sport Sales”, p 159, who explains that this may give rise to regulatory (and consequential) third-party access issues under the Provisions of the Gas Act 1986 (as amended) and a requirement for a public gas transporter’s licence. 96   See also 1979 Act, s 12. 97   AIPN GSA, Art 11.2. 98   1979 Act, s 16; Guidance Notes to the AIPN GSA, p 22. 99   AIPN GSA, Art 11.3. 100   See Dyer et al., “Liquefied Natural Gas”, p 121. 101   The Uniform Network Code (version 5.00, as at 25 April 2017) is available at www. gasgovernance.co.uk/UNC (accessed 1 May 2017). 102   Beggs, “Term and Sport Sales”, p 155. 95

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II-8.33 an unrelievable breach, where the failure to deliver the gas (or LNG) could be in breach of the GSA (or LNG SPA), but one in respect of which the seller is not entitled to claim relief and for which the seller would be liable to the purchaser as per the terms of the GSA (or LNG SPA) and the applicable law.103 II-8.34 To mitigate the purchasers’ concerns in case of the latter, it has become increasingly common for GSAs (or LNG SPAs) to include a clause that places liability with the seller for cargo that is delivered late or not delivered at all, entitling the purchaser to terminate the contract and claim liquidated damages. 104 Understandably, the seller would be less inclined to accept such a clause under a depletion agreement since it is tied to one source of gas (or LNG).105 GSAs (and LNG SPAs) could incorporate other provisions to deal with non-delivery including purchaser-focused mitigation processes (eg ability to secure gas (or LNG) from another source), imposing limits and caps on liability, and expressly outlining the specific situations that constitute a breach of the seller’s delivery obligation. II-8.35 Long-term GSA (or LNG SPAs) normally look to the annual delivery obligation in place of a cargo-by-cargo situational analysis. This is most appropriate for use when there is a dedicated shipping line available, and the purchaser and seller have an interdependent relationship. This may be less suitable for short-term GSAs, which have a lack of dedicated shipping and a smaller amount of shipments.106 In such instances, it is preferable for the seller to give appropriate notice to the purchaser in cases when it is anticipated delivery will not be in line with the stipulations laid out in the annual programme. Additionally, should a purchaser be able to accommodate a rescheduled delivery, it is common for a seller to take on some of the costs related to the rescheduling, should the purchaser inform them of such costs in advance. Alternatively, the seller may opt to decline a rescheduling and instead take on the cost of the purchaser’s losses. Should neither party be able to agree to a rescheduled delivery and the seller does not deliver the Gas (or LNG) within the appropriate and pre-agreed timeframe, the seller will be considered to have failed to deliver.107 When calculating damages, the  Roberts, Gas Sales and Gas Transportation, pp 102–103.   See the European Federation of Energy Traders Master DES LNG Sales and Purchase Agreement (hereinafter “EFET SPA”), cl 15.3. 105  Roberts, Gas Sales and Gas Transportation, 76. 106  A Jones and Y Abul Failat, “Gas Sales and Supply Agreements” (CL’s Expert Guide: Energy and Natural Resources (2016) (hereinafter “Jones and Abul Failat, ‘Gas Sales and Supply Agreements’”), available at www.corporatelivewire.com/Awards/ENR2016/html5/ index.html?&locale=ENG (accessed 20 January 2017). 107   LXL LLP, A Guide to the Energy Industry for the In-House Energy Lawyer focusing on the Gas and LNG Sectors (2012) (hereinafter “LXL LLP”), p 61. 103 104

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seller will typically require similar considerations to ensure they are not subject to overcharging. In some instances, this may involve an external audit on a per cargo basis. This is considered to be of even greater importance in situations where the damages required more than any predetermined compensation as outlined in the GSA (or LNG SPA). Excess, over and shortfall gas delivery Some GSAs allow a purchaser to ask for additional gas beyond the II-8.36 GSA-nominated minimum, referred to as “excess gas”. Purchasers may require such excess gas during specific high-demand periods as specified in the GSA.108 Although an excess gas provision would not oblige the seller to meet these needs, it would typically request it to exert reasonable effort to do so, bringing a level of comfort to the purchaser. In such instances, the purchaser typically would pay a premium price over the contracted amount. Similarly, “overdelivery” provisions may be included in GSA, whereby the purchaser is not obligated to purchase any extra gas delivered but must also exert reasonable efforts to do so.109 In situations where the seller does not deliver the gas required, II-8.37 and the deficit is not covered within the GSA, the missing amount is known as “shortfall gas”. Several situations may result in an acceptable deficit under the GSA, including the purchaser not taking it, failed delivery due to a force majeure event or omission, planned maintenance or other intentional non-delivery, availability of a contractual remedy such as off-spec gas, or an agreed-upon shortfall tolerance.110 Shortfalls may be countered later through the provision of a reduced-price product, sold at so-called “shortfall gas price”. In other instances, the seller may provide compensation through a process known as shortfalling. Undischarged discounted shortfall gas price entitlements are covered under cash-out and gas-out provisions.111 The seller would seek to limit its liability through the application of shortfall tolerance or aggregated nominations. The former is typically expressed as a percentage of the nominated quantity protecting the seller against de minimis failed deliveries (could be subject to an annual limit) and the latter provides that the shortfall is to be aggregated over some consecutive nominations to avoid shortfall occurring in connection with one nomination.112  Chandra, Fundamentals of Natural Gas, p 113.   See AIPN GSA, Art 12.4. 110   Vinter and Price, Project Finance, p 117; see AIPN GSA, Art 12.5. 111  If the GSA ends and leaves outstanding undischarged entitlements, term extensions may be negotiated. See Roberts, Gas Sales and Gas Transportation, p 153. 112   Ibid, p 146. 108 109

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Take or pay II-8.38 In short-term GSAs, there is rarely a requirement on a purchaser to pay for any gas which was not ordered. However, in long-term GSAs, take or pay provisions (also referred to as minimum bill quantity clauses) are typically incorporated with a view to ensuring that the seller secures some income.113 Take or pay clauses are among the most important provisions of a long-term GSA. These provisions ensure that the purchaser pays for a specific minimum quantity of gas over a given period regardless of whether it physically takes it. The purchaser and the seller agree to an annual contract quantity, which specifies for gas to be delivered and taken.114 The amount of gas that comprises the agreed minimum percentage (typically 60–90 per cent) of the annual contract quantity is known as the annual take or pay quantity (ATOPQ).115 The purchaser contracts to pay and collect the ATOPQ on a yearly basis throughout the GSA. The term “take or pay” implies that the purchaser has the option but no obligation to acquire the gas. In fact, the purchaser has the choice to either pay for and take the gas or just pay for it. Such a purchase would be for at least an agreed-upon minimum quantity over the course of the year, if not more.116 Also, the seller must have gas available, but may not indeed supply it. Should the seller not deliver, or should a force majeure situation prevent the purchaser from purchasing the gas, the agreed minimum quantity would be reduced.117 Circumstances in which the purchaser takes more or less than the amount specified in the ATOPQ must be covered by the GSA. For this reason, there is typically the inclusion of make-up or carry-forward provisions. II-8.39 The seller will typically opt to regulate the ability of the purchaser to decrease its take or pay obligation (its downward flexibility capability), in favour of enabling the purchaser to obtain equivalent amounts later on. This is because the seller has often invested significant amounts, for example, in the case of LNG, in upstream and liquefaction facilities, or shipping facilities in DES sales situations. This is also because there is reduced option to market LNG spot cargoes to accommodate those that the purchaser has opted not to avail itself of during the year. In the end, concrete offtake obligations are dependent on whether the market favours the purchaser or

  This mechanism is analogous to send or pay (or ship or pay) provisions transportation contracts. See Chapter II-13 for further detail. 114   See eg AIPN GSA, Art 12.6, which provides that “[i]n each Contract Year, [the] Buyer shall be obligated to take and pay for, or to pay for it if not taken, a quantity of Gas at least equal to the Take or Pay Quantity”. 115  Chandra, Fundamentals of Natural Gas, p 114. 116   Ibid, p 114. 117   O’Neill, “Gas Sale and Purchase Agreements”, p 148. 113

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the seller, and the level of flexibility the seller is comfortable ceding to the purchaser. The make-up provision allows the purchaser to balance in the second year what was uncollected in the first year under a take or pay provision.118 For example, if the purchaser did not take all the gas paid for in the first year, the provision would permit the delivery of the balance amount in the second year (subject to a notional make-up gas account). The seller would normally seek to negotiate limitations to the purchaser’s ability to recoup make-up gas. For instance, a time limitation can be imposed, during which the purchaser can recoup the make-up gas; such a make-up period is typically set at three to five years. Further, the purchaser’s right to take its make-up gas may be limited by quantity provisions in the GSA. For instance, if a purchaser’s make-up gas balance for the first year is 200 mmscf from the first year, and its take or pay quantity in the second year is 40,000 mmscf, it would have to take and pay for 40,000 mmscf before it could receive the next 200 mmscf free as make-up gas.119 A cap can also be included in respect of the amount that a purchaser could nominate whether the nomination is for regular or make-up gas (or a mix).120 A carry-forward provision, on the other hand, refers to the II-8.40 situation in which the purchaser takes and pays for gas beyond the amount specified in the ATOPQ. In such instances, a carry-forward provision allows the purchaser to be credited for that amount, thereby reducing the ATOPQ in the second year (carry-forward gas). The concept of carry-forward is often seen as a way of “softening” take or pay obligations.121 As with make-up provisions, the seller would seek to limit the degree to which the purchaser could reduce its take or pay commitments, through imposing time limitations on the period during which a carry-forward amount could accrue (eg three years) and/or capping the amount of carry-forward amount that could be used in a year. Further, make-up and carry-forward gas have a clear interplay. For this reason, the GSA would stipulate that a purchaser could not use make-up gas in the first year as carryforward gas in the second year. To prevent this, any gas a purchaser takes beyond that specified in the ATOPQ in the first year would initially reduce any accumulated make-up gas before being allowed for use as carry-forward gas.122 The similarity in the potential

  D Langenkamp, Handbook of Oil Industry Terms and Phrases (6th edn, 2014), p 303.  S Gaille, “The Use of Quantity Terms to Improve Efficiency and Stability in International Gas Sales and Purchase Agreements”, 29(2) (2008) Energy Law Journal 645, at 661. 120   Ibid, at 661. 121   Guidance Notes to the AIPN GSA, p 24. 122   See AIPN GSAs, Arts 12.7 and 12.8. 118 119

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financial consequences between a penalty and liquidated damages clauses arising from a breach of a take or pay provision often raises questions as to the enforceability of such clause. The recent Supreme Court decision in Cavendish Square Holdings B.V. v Makdessi123 departed from the traditional approach in determining whether a clause constituted a penalty and stated that the true test for penalty clauses is, as per Lords Neuberger and Sumption: “[W]hether the impugned provision is a secondary obligation which imposes a detriment on the contract-breaker out of all proportion to any legitimate interest of the innocent party in the enforcement of the primary obligation. The innocent party can have no proper interest in simply punishing the defaulter. His interest is in performance or in some appropriate alternative to performance.”124

II-8.41 This distinction between primary and secondary obligations is the result of a “fundamental difference between a jurisdiction to review the fairness of a contractual obligation and a jurisdiction to regulate the remedy for its breach”, since “the courts do not review the fairness of men’s bargains either at law or in equity”.125 Therefore, the way in which a relevant obligation is framed in a GSA would affect the applicability of the penalty rule.126 Take or pay clauses, which do not require the purchaser to take a minimum quantity of gas, create a debt, a primary obligation, due to the seller for making gas or transportation services available and not a payment on breach as no breach arises if the purchaser elects not to take the gas.127 Accordingly, such a take or pay clause should not be deemed as a penalty and should be enforceable.128 Pricing II-8.42 In continental Europe, it is common for gas prices to be determined using competing fuel indices and to be agreed upon for the duration of the GSA.129 However, this is beginning to change due to some factors, including a more liquid and liberal gas market, an increase   [2015] UKSC 67.   Ibid, para 32. 125   Ibid, para 13. 126   That is, whether it is a primary contractual obligation (debt) or a secondary obligation (damages) providing a contractual alternative to damages at law. 127  B Holland, “Enforceability of Take-or-Pay Provisions in English Law Contracts – Resolved”, 34(4) (2016) Journal of Energy & Natural Resources 443, 446. 128   Ibid, citing a number of cases that provide authority that debt claims are not subject to the penalty rules, including in the judgments of White & Carter (Councils) Ltd v McGregor [1962] AC 413; Euro London Appointments v Claessens International [2006] EWCA Civ 385; High Court in the Office of Fair Trading v Abbey National PLC and Others [2008] EWHC 875 (Comm) and Civ 116 [2010] 1 AC 696. 129   Pustisek and Karasz, Natural Gas, p 112. 123 124

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in global LNG supply, an increase in non-traditional gas reserves (as with the USA) and a reduction in LNG demand and pipeline gas within countries impacted by the recession.130 All of the above factors have resulted in a falling market price for natural gas. Lower prices have led to GSAs being renegotiated into short-term agreements. There remains a balance between the need to ensure a long-term energy supply and the need to respond to market price volatility, risk and uncertainty. GSAs (and LNG SPAs) have three primary pricing provisions: spot market pricing, price adjustment provision-adherent previously agreed on pricing and price review/reopen clauses.131 Market indices are opted for to guarantee that pricing reflects that of spot markets, whether immediate or future. The seller normally elects a contract price for gas/LNG that is derived from the market price in the location where the purchaser plans to unload the gas/ LNG. Negotiating parties work to agree on a market index or combination of indices that suit their situations from the very start. For example, where a purchaser intends to unload in the UK, the seller might fix the price of gas to the UK NBP, which is deemed the most established spot price index in Europe.132 Alternatively, where a purchaser plans to unload in the USA, the seller might fix the price to the Henry Hub market index. Advance “freeze” pricing is often used to respond to price volatility allowing for some degree of risk should the “set” price not match the market price at the time of delivery.133 It is important for a seller to know the intended destination of the product both because of force majeure and because of the price. In LNG SPAs, for example, a diversion provision would be included to cover instances wherein the LNG cargo does not finish its journey at the planned destination. This provision would enable the seller and purchaser to take advantage of any premium or upside, which results from the changing destination altering the contract price. Medium- and long-term supply GSAs often have a pre-agreed II-8.43 price and price adjustment clause. Such clauses determine the price at the outset and index it according to particular indices. There is a risk with such circumstances that the spot market will differ from the   Ibid, p 112. See, generally, J Stern, “The Impact of Lower Gas and Oil Prices on Global Gas and LNG Markets” (OEIS Paper NG 99, Oxford Institute of Energy Studies 2015), available at www.oxfordenergy.org/wpcms/wp-content/uploads/2015/07/NG-99. pdf (accessed 1 May 2017). 131   As with oil SPAs, if a price or a formula for determining the price is fixed in the GSAs (or LNG SPAs), it is an implied term under the 1979 Act, s 8(2), that the purchaser would pay a reasonable price. 132   G Kellas, “Natural Gas: Experience and Issues”, in P Daniel, M Keen and C McPherson (eds), The Taxation of Petroleum and Minerals: Principles, Problems and Practice (1st edn, 2010), p 179. 133   Jones and Abul Failat, “Gas Sales and Supply Agreements”. 130

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contract price. Therefore, price review or price re-adjustment clauses are frequently introduced. The intention of the GSA and the roles of its parties will determine which price formula and indexing are used. A seller will be primarily occupied with settling on a price that reflects market value and allows for competitive development, such as investing in offshore gas fields. Given sellers’ desire for pricing predictability to underwrite the development of their production projects, the guidance notes to the AIPN GSA provide that “multiple indices dampen volatility” and accordingly suggest that a basket of indices should be used as it is not as likely to have major fluctuations.134 A purchaser will be primarily concerned with the cost of gas being aligned with that of other open market fuels, and thus that it can be sold at a profit throughout the entirety of the GSA and where selling to a power plant, for example, purchasers would usually opt for fuels that compete with natural gas.135 Price review clauses and reopeners II-8.44 GSAs cater for situations where the agreed gas price formula is not adequately reflecting market condition changes by providing parties with a right to periodically request a price review. There is no standard form for a price review clause (also referred to as price reopener clause). However, they involve a fixed element and an indexation element, which would allow fluctuation of price during the GSA.136 The fixed element would represent the price at the date the GSA was concluded (or the date of the last price review) while the indexation element consists of a formula tied to price changes in certain oil products.137 A price review clause is activated in the instance of a negative and substantial economic impact that differs from that foreseen at the outset of the GSA and which is not the fault of any party seeking to adjust contract pricing terms. Price review clauses are common in continental European GSAs,138 and a simple form would include wording along the lines of “[i]f … economic circumstances in the [buyer’s market] … have substantially changed as compared to that expected when entering into the contract for reasons beyond the parties’ control … and the contract price … does not reflect the value of natural gas in the [buyer’s market] … [then the parties may meet to discuss the pricing structure]”.139

  Guidance notes to the AIPN GSA, p 24.   Ibid, p 24. 136  K Hober, “Recent Trends in Energy Disputes”, in K Talus, Research Handbook on International Energy Law (1st edn, 2014), p 230. 137   Ibid, p 230. 138  Sakmar, Energy for the 21st Century, p 160. 139   Farmer and Sullivan, “LNG Sale and Purchase Agreements”, p 36. 134 135

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It is common for parties to fail to find agreement regarding adjust- II-8.45 ments to pricing mechanisms, even though GSAs frequently outline those factors that should be considered in such instances. Should one party find the amended price disagreeable, the other party will most likely find that price to be to its advantage, leading to a situation of inherent conflict. For this reason, GSAs endorse expert determination or arbitration with the intention of resolving such disagreements, and typically require the party seeking a price to provide a case for price revision.140 Because the parties involved will have different interests regarding price revision, it is often challenging to agree on what mechanisms can allowably trigger a price review clause.141 The result of this is that clauses are written in general and vague language, leaving the risk of disagreement and thus a need for expert arbitration or determination. Parties wishing to request contract sales price reviews must demonstrate the reasoning is in good faith and outside of its control,142 and that a specific gas market143 has seen a material change144 in value that is likely to have a lasting effect.145 One means of addressing the uncertainty resulting from market II-8.46 liberalisation (for example, in European gas markets) is the strategy of determining a price formula. When such a strategy gives one of the contracting parties a percentage or absolute fixed margin, it is considered a netback price formula. When netback price structures are involved, price reviews are allowed more technical guidance in regards to measuring market value and alterations to pricing formulae. It comes as no surprise therefore that disputes relating to price review clauses can be lengthy and costly affairs, particularly if there is a fundamental disagreement between parties as to whether the conditions for determination or arbitration have been met. Because some GSAs allow for restrictions on information disclosure, arbitrations can be potentially even more complicated   See AIPN GSA, Art 15.9.   Beggs, “Term and Sport Sales”, p 155. 142   The requesting party must demonstrate the change in the market is beyond its control. This could be difficult in situations where the requesting party is a state entity or if the market under consideration is not liberalised. See Sakmar, Energy for the 21st Century. 143  The market under consideration will need to have undergone demonstrable change, as indicated by the purchaser. The purchaser has the resources required to provide the necessary evidence, although this is becoming increasingly challenging as the LNG/ gas market becomes more global. The globalisation of the LNG/gas market means the purchaser’s market may have grown or changed for the end-user. 144  This is a subjective term (also “significant” or “substantial”) that could be defined differently by either party. See A Rovine, Contemporary Issues in International Arbitration and Mediation: The Fordham Papers (1st edn, 2014), p 201. 145   Ibid, p 201. The inclusion of this term is to guarantee that price reviews are not triggered by short-term alterations to the market. That said, it is challenging to demonstrate that market fluctuations will have a long-term impact. 140 141

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and antagonistic. Accordingly and since price revision clauses permit the renegotiation of one of the most important terms in a GSA, drafters should ensure that the price review clause provides a clear framework for their mechanism, in particular on when they are intended to apply.146 Price diversion II-8.47 Recently negotiated LNG SPAs now include diversion rights for the purchaser that support maximisation of profit while maintaining flexibility. Such diversion rights allow the purchaser to re-route LNG cargo to destinations hosting higher priced marketplaces.147 However, diversion rights mean the seller may risk being unaware of the final destination of the product until after delivery. For this reason, sellers must have the ability to monitor the purchaser adoption of diversion rights to guarantee the price achieved does not reduce the value of the product.148 This applies in particular when the purchaser is subject to diversion obligations. In the AIPN SPA, there are conditions aimed at ensuring that a seller is no worse position than it would have been in had the diversion not occur.149 Further, the diversion clause requires that the purchaser and the seller agree on how to share any incremental profit gained because of the diversion.150 Such mechanisms complement the purchaser’s increased flexibility rights and allow the purchaser to share in upsides through altering cargo destinations to locations that did not feed into the LNG SPA contract price.151 Negotiations will determine how the upside is split between purchaser and seller will be laid out in the LNG SPA (typically, a 50/50 split). A diversion upside formula is frequently used to determine this split. The formula takes into consideration the actual sales price received (the amount paid to the SPA purchaser by the downstream consumer), as well as any avoided costs due or costs attributed to the diversion, which would require careful drafting as they may affect the final calculation.152 A diversion

  O’Neill, “Gas Sale and Purchase Agreements”, p 156.   See Dyer et al., “Liquefied Natural Gas”, p 122. 148   See also C-K Chyong and R Kazmin, “The Economics of Global LNG Trade: the Case of Atlantic and Pacific Inter-Basin Arbitrate in 2010–2014” (CWPE 1604, Cambridge University 2016) (hereinafter “Chyong and Kazmin, ‘Economics of Global LNG Trade’”) 34, available at www.econ.cam.ac.uk/research/repec/cam/pdf/cwpe1604.pdf (accessed 1 May 2017). 149   AIPN SPA, C 17. 150   Ibid. 151   See Chyong and Kazmin, “Economics of Global LNG Trade”. 152   LXL LLP, 40. 146 147

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formula may read as follows: Diversion Upside = (Actual Sales Price) – (Contract Price) – (Attributed Costs) + (Avoided Costs).153 Sellers must consider in this situation the most appropriate II-8.48 means to ensure the data feeding into the calculation is accurate. It is highly possible that the purchaser will opt to retain some of the information that the seller may require to confirm the calculation is correct. This may be because the purchaser considers this information sensitive or confidential, or indeed may be concerned that disclosure of such data will result in antitrust legislation or competition law infringement. When a purchaser has greater destination flexibility rights or diversion obligations, it is of even greater importance for the seller to ensure accurate data to guarantee there has been no value dilution. Therefore, the relationship between the purchaser and seller is paramount and will affect the accuracy of the formula. Several options can be introduced to mitigate any errors including periodic external audits that support the third party to assess all information, establish regular meetings between parties to evaluate operations and inconsistencies, and predetermine compensation required in instances when a purchaser does not adhere to its diversion requirements.154 Force majeure Should a force majeure event take place, the GSA (or LNG SPA) II-8.49 must make allowances for relief from obligations for all involved parties. In a long-term sales agreement, the force majeure clause would include a definition of the term and thus which events qualify (typically a force majeure event is an event beyond the control of the parties that impacts their delivery on their obligations), a list of examples of allowable events (such as terrorism, strikes, war or natural calamities) and a list of examples of non-allowable events. The AIPN GSA provides options to include force majeure events such as a change in law or failure of the gas transporter to take delivery of and transport the gas.155 The GSA (or LNG SPA) may, with a view to narrow down the scope of a force majeure clause, exclude certain events from qualifying as force majeure events. Examples include changes in the market or demand for gas (or LNG), financial hardship or inability of a party to make a profit

  Ibid, 40: the term “attributed costs” refers to costs the SPA purchaser incurred because of the diversion such as port charges and “avoided costs” refers to costs the SPA purchaser avoided thanks to the diversion. 154   Jones and Abul Failat, “Gas Sales and Supply Agreements”. 155   AIPN GSA, Art1, definition of Force Majeure Event. 153

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or obtaining better terms for the gas (or LNG) from an alternative supplier or purchaser.156 II-8.50 The degree to which the SPA agreement is aligned with the seller’s upstream contracts and the purchaser’s downstream contracts is a basic issue the seller, purchaser and any lenders will be concerned with. Another aspect of interest to all parties is alternative mitigation tools, such as those that provide insurance for all parties to achieve equivalent force majeure relief. The GSA (or LNG SPA) should also define accurately any facilities owned or maintained by the purchaser or seller, and whether these are eligible for relief due to being impacted by a force majeure event. In this case, it is necessary for the purchaser to indicate which terminal destinations they intend to use, regardless of any pre-negotiated destination flexibility. Other GSA (or LNG SPA) terms II-8.51 In addition to the terms discussed above, long-term GSAs (and LNG SPAs) usually incorporate many other relevant terms and boilerplate provisions including: (a) conditions precedents, which are required before the GSA (or LNG SPA) is valid and may include the achievement of particular financial conditions or the securing of appropriate consents;157 (b) representations and warranties (in respect to authority, title, creditworthiness and other warranties relating to the GSA (or LNG SPA));158 (c) liabilities and insurance provisions (dealing with general liabilities including consequential losses and exclusive remedies);159 (d) the particular quantity of gas available for purchase at certain time increments, such as by the day or by the hour; (e) provisions relating to gas specification requirements which will outline the procedure in the event that “off spec” gas is unknowingly or knowingly delivered or accepted. Should it be unknowingly accepted, normally the purchaser is favoured through an indemnity against any potential costs and liabilities, which would include any costs associated with preparing facilities downstream;160 (f) measurement and testing/verification provisions setting out, among other things, standard and principles for measuring and   Ibid; AIPN SPA, Art 13.1.2.2.   See eg AIPN GSA, Art 3. 158   Ibid, Art 4. 159   See eg AIPN SPA, Art 12. 160   LXL LLP, 43. See also implied terms under the 1979 Act, ss 13(1), 14(2), 14(2B) and 15(2). 156 157

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p e t ro l e um sa l e s ag re e m e n t s 291 or calculating quantity, composition and physical properties of the GSA (or LNG SPA), and procedures for verification of calibration;161 (g) assignment provisions, usually to the effect that neither party can assign the agreement or its rights or obligations without the prior consent of the other party, or at all;162 (h) billing and payment (eg invoicing, disputed invoices or payments, late payments, and netting and set-off);163 (i) taxes, charges and duties (eg purchaser’s taxes, seller’s taxes, and exclusions);164 and (j) governing law and dispute resolution provisions.

COLLATERAL SUPPORT IN PETROLEUM SALE CONTRACTS Collateral support in petroleum sales agreements is a rather standard II-8.52 feature. Under Oil SPAs, GSAs and LNG SPAs, particularly those concluded for long terms, purchasers incur substantial payment obligations (and performance obligations are imposed on the seller), for which collateral support may be required. The type of collateral support is often subject to negotiation and dependent on the bargaining power of the parties respectively. It is understandable for both purchaser and seller to want to be assured of the other’s financial capacity to make payments under the agreement. From the seller’s perspective, it would want assurance that the purchaser has the immediate financial capacity to meet its payment obligations and has attained satisfactory credit rating to reassure the same for future obligations.165 Likewise, a parent company guarantee (sister company guarantee) from the purchaser will further reassure the seller that it will receive payment for its sales of petroleum should the purchaser default. A purchaser will request collateral support from the seller to safeguard it in the event the seller fails to perform its obligations (eg delivery obligations), whereby for example the seller would be liable to pay shortfall penalties.166 The same rationale behind the seller’s request for collateral support applies to the purchaser’s request.   See eg AIPN GSA, Art 14.   See eg AIPN SPA, Art 19.1. 163   EFET SPA, s 12. 164   Ibid, s 13. 165  Y Abul Failat and A Lazem, “Financial Collateral in Petroleum Projects: Practical Aspects”, Cayman Financial Review (2015), available at www.caymanfinancialreview. com/2015/10/07/financial-collateral-in-petroleum-projects-practical-aspects (accessed 1 May 2017). 166   Ibid. 161 162

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II-8.53 The AIPN GSA, which is a long-term agreement, provides optional condition precedents requiring either party to evidence its creditworthiness and financial ability to fulfil its obligations.167 This can take the form of a guarantee or standby letter of credit issued by a bank, an on-demand bond issued by a surety corporation, a corporate or government guarantee, or such other financial security as is agreed by the parties.168 Collateral support is also commonly required for short-term sales agreements, including spot market trades, which in practice is often given as letters of credit. In the case of crude oil, for example, the BP GTCs provide that if a form of credit support for the purchaser’s obligations is not agreed or specified in the Special Provisions, the seller is entitled to require the purchaser to provide collateral support.169 The BP GTCs defined credit support as a parent company guarantee, letter of credit or advance payment.170 While the BP GTCs do not dictate the form of the parent company guarantee (the form to be agreed to between the parties), it does set out proforma letters of credit and standby credit.171 It is also possible for a petroleum sale agreement to contain a “performance assurance” provision upon either party determining that the financial condition of the other has become impaired or unsatisfactory (or inadequate for any other reason) to require such party to provide satisfactory security which may include a prepayment, a letter of credit or a parent company guarantee.172 FINAL REMARKS II-8.54 Petroleum sales agreements can take many forms and are accordingly widely based on the features of the underlying commodity and other factors such as the predetermined length of trade, method of transporting the petroleum and whether the trade involves a physical or nominal delivery of petroleum. Long-term petroleum sales agreements tend to be bespoke and designed to provide a practical framework that is suitable for the entire life of the agreement. Such agreements may be depletion-based agreements or supply-based agreements, although there has been a shift towards supply-based agreements in the last years largely influenced by the liberalisation of the market and security of supply requirements.   AIPN GSA, Arts 3.1.4 and 3.2.3; see also AIP SPA, Art 9, Exhibit A, Arts 19 and 20.   Ibid. 169   BP GTCs, s 63.12.1. 170   Ibid, ss 63.12–63.15. 171   Ibid, ss 63.13 and 63.14 and Schedules B and C. 172   See eg EFET SPA, cl 19.2. 167 168

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Equally, care should be taken in drafting and regularly updating II-8.55 short-term contracts, which tend to be standardised as a result of the rapid pace of the spot market. Oil companies also sell on standard terms as a strategy to introduce seller-friendly terms in a format designed to discourage heavy negotiation. Standard terms, however, are sometimes given low priority and only given detailed consideration when a dispute arises. The sales department may be issuing quotations or processing orders using terms that are out of date or unsuited to the relevant transaction. On occasions, however, traders do not even contract on their terms, due to better-trained purchasers who have succeeded in substituting their own. It is important that draftspersons understand the downstream II-8.56 sector and appreciate the intricacies and the components of oil and gas sales transactions to amongst other things ensure an enforceable agreement, containing terms and conditions that are most productive for their client, and allow them to negotiate profitably with counterparties.

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ISSUES OF COMMERCIAL LAW IN THE OIL AND GAS CONTEXT

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CHAPTER II-9 ACQUISITIONS AND DISPOSALSOF UPSTREAM OIL AND GAS INTERESTS Norman Wisely1

INTRODUCTION Notwithstanding the challenging economic climate, the continued II-9.01 trading of oil and gas assets remains of significant importance to international oil and gas companies and the UK Government alike. The significant decline in the price of oil and gas since late 2014 has caused companies to reflect on the future viability of their investments, focus on core assets and seek to streamline their portfolios. As a result, individual assets will continue to change hands.2 This chapter will summarise, and provide an overview of, the legal process involved in the acquisition and disposal of upstream UK oil and gas licence interests, concentrating primarily on acquisitions and disposals by way of an asset sale for a cash consideration. This chapter does not purport to deal with public takeovers, nor to deal with more complex forms of consideration in any great detail. PORTFOLIO MANAGEMENT There are many motivating factors behind oil companies’ decisions II-9.02 to invest in, or dispose of, existing oil and gas interests. Set out

 The author would like to thank Graeme Clubley, Partner, at CMS and Stuart Leslie, Associate, at CMS, for their valuable input and contribution to this chapter. 2  See generally the 2015 Economic Report, Oil and Gas UK; available at www.oilandgasuk.co.uk (hereinafter “2015 Economic Report”) (accessed 24 May 2017). 1

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below are some of the most common reasons. In recent years, as the North Sea has developed into a mature basin, it has become ever more common for oil majors to rationalise their portfolios and divest of a number of non-core assets, non-operated assets or smaller percentage interest holdings.3 Some companies may seek to divest of oil and gas assets because they are costly to operate or in order to minimise decommissioning costs, whilst others may wish to leave the United Kingdom Continental Shelf (UKCS) to concentrate on other, potentially more profitable, jurisdictions, or they may perhaps consider that the time is right to capitalise on a particular asset. Increasingly, some sellers may find themselves in need of cash to finance debts, and if a seller has insufficient cash it may ultimately be forced into a distressed sale or run the risk of insolvency.4 The buyer may be a smaller organisation that is more suited to extracting value from assets in a mature basin than larger companies, who may find it uneconomic due to larger associated overheads. In recent times, an increasing number of private equitybacked businesses and infrastructure funds have sought to invest in UKCS assets to develop fresh portfolios and expand within the sector, capitalising on a low oil price and opportunities to acquire high quality assets.5 Such buyers may wish to acquire assets in a certain geographic “heartland” that they know and understand. Alternatively, the buyer may be seeking to gain a dominant vote in an existing joint operating agreement (JOA) it is party to or it may seek to acquire an oil and gas interest because it feels it can gain more value from an asset under-used and under-explored by the seller. Moreover, a buyer may be motivated by reasons outwith the immediate prospectivity of the interest being acquired, for instance buying in order to secure transportation rights or to acquire data relevant to another area. In addition, purchase of production acreage can finance exploration and purchase of exploration acreage can reduce tax exposure on production profits. Ultimately, for any sale and purchase to occur there needs to be a mutuality of interest between seller and buyer.

  See generally ibid, s 4.2 “Mergers and Acquisitions”.   The significant decline in the price of oil and gas has contributed, at least in part, to the insolvencies of Iona Energy, First Oil and Xcite among others, the first insolvencies of oil and gas companies operating in the UKCS since the administration of Oilexco in 2009. Following this, several small and medium-sized oil and gas companies have announced that they are conducting strategic reviews of their operations and considering sale opportunities and/or corporate restructuring. 5   See generally 2015 Economic Report, s 4.2 “Mergers and Acquisitions”. 3 4

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MAXIMISING ECONOMIC RECOVERY FROM THE UKCS (“MER UK STRATEGY”) The MER UK Strategy,6 which came into force on 18 March 2016, II-9.03 seeks to ensure that oil and gas assets are in the right hands in order to maximise the economic value of hydrocarbons recovered from the UKCS.7 On a practical level, this may mean that where a company cannot by itself ensure the recovery of the maximum value of economically recoverable petroleum, such a company must seek to secure investment from other companies. If such investment cannot be obtained within a reasonable time, the company in question may be obliged to divest itself of its licence interests in order to allow others to develop the interest and recover the maximum value of petroleum. However, the Oil & Gas Authority (OGA) must balance the benefit of economic recovery with the need to maintain confidence of new and current investors, always taking into account market conditions at the relevant time.8 It remains to be seen how the MER UK Strategy will impact acquisitions and disposals in the UKCS, particularly if companies are directed to relinquish their licence interests in order to allow other companies to acquire their interests and proceed with field development. However, at the very least, MER UK is likely to become increasingly relevant to considerations involved in asset trading going forward. ACQUISITION STRUCTURES Other than through being granted an oil and gas licence by the UK II-9.04 Government, there are essentially two distinct ways of acquiring an interest in oil and gas assets: either by purchasing the assets themselves, or through a share purchase of a company which directly or indirectly owns oil and gas interests, usually by way of a purchase of 100 per cent of such company’s shares. Types of asset purchases With an asset purchase the “asset” which the buyer seeks to acquire II-9.05 is the seller’s interests in the relevant licence(s) and a multitude of rights and obligations under the associated field documents, including  The MER Strategy is available for download from www.ogauthority.co.uk/ news-publications/publications/2016/maximising-economic-recovery-of-uk-petroleumthe-mer-uk-strategy (accessed 20 May 2017). 7   See Chapter I-5 for a summary of MER UK. 8   The Energy Act 2016 provides the OGA with regulatory powers and functions, establishing the OGA as an independent regulator in the form of a government company charged with asset stewardship and regulation of domestic oil and gas recovery. 6

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the agreements mentioned earlier in this book.9 At completion of the transfer, the buyer will pay some form of consideration. There are many variations on asset purchases, the principal difference between which essentially relates to the consideration payable for the oil and gas interests in question. These are explained in the following sections. Monetary consideration II-9.06 In this arrangement, the buyer will pay the seller a monetary consideration at completion. Elements of monetary consideration may be deferred or contingent in some cases, for instance, where an element of the consideration is based on field development, first production, future production levels of the asset being acquired or prevailing oil and gas prices.10 Farm-in/farm-out II-9.07 Here, the consideration payable by the buyer is the performance of a field obligation (usually drilling work), whether by way of actual performance of that obligation or reimbursement of the seller’s costs of the operator performing such obligation.11 A farm-in/farm-out might be combined with a “carried interest” whereby, in the event of a drilling success, the buyer will also fund the seller’s share of costs of further work, for example field development, in return for an uplifted repayment post-first production, by way either of a production royalty or net profit interest.12 Earn-in II-9.08 This is often now used interchangeably with a “farm-in” (as described above) or to describe a monetary obligation, as opposed to a physical carrying out of work. Traditionally, however, it specifically refers to circumstances where the farm-in relates to a work obligation under the licence, and where, typically, the OGA is more reluctant to allow parties to “farm out” their interests, meaning that usually the interest may not be transferred until completion of all relevant work obligations.

  See Chapter II-2.   Elements of deferred consideration in share and asset transactions are finding favour recently in the low and/or fluctuating oil and gas price environment where buyers and sellers increasingly struggle to agree on price expectations and value. 11  The seller “farms out” and the buyer “farms in”. See paras II-9.81 to II-9.83 for an analysis of farm-out agreements. 12   This has been a business model adopted by some “non-cash-rich” promote licensees in particular, in order to ensure that they can participate in any potential future field development. See paras I-4.69 to I-4.73. 9

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Swap/exchange An alternative structure is where some or all of the consideration II-9.09 payable by the buyer is the transfer of another oil and gas interest(s) to the seller. Advantages and disadvantages of asset purchase versus a corporate purchase Much will depend on the specific facts and circumstances of any II-9.10 proposed transaction,13 but typical reasons for choosing a share purchase over an asset purchase and vice versa can be summarised as follows: No pre-emption Any pre-emption clauses in UK JOAs or other licence interest II-9.11 documents are unlikely to prevent an acquisition of the relevant party’s shares, the justification being that a JOA or similar agreement should not prejudice a party’s shareholders’ ability to trade their shares. For this reason, a company purchase has the advantage of avoiding any pre-emption restrictions in the licence interest documents, which would be captured in an asset deal.14 If the buyer is proposing to acquire all, or part, of the issued share II-9.12 capital of a private limited company owning oil and gas assets, it will rarely find pre-emption rights directly affecting the seller’s shares in the target.15 As a general rule, therefore, the assignment of shares in private oil and gas companies is far freer of contractual restrictions than the sale of their oil and gas assets. Mechanical simplicity A share sale is, certainly in theory, legally and mechanically simpler II-9.13 than an asset sale, since all that is legally required to transfer title to shares is a stock transfer form and registration in the register of members of the target, as opposed to the suite of assignments, novations and consents required to transfer title to assets. In practice, however, this is not always the case, and share sales can   One of the key structural items is clearly whether the assets which the buyer wishes to buy are neatly contained within a subsidiary of the seller or whether substantial transfers of other assets out of the corporate vehicle into another affiliate of the seller would be required prior to completion. 14   See further at paras II-9.34ff. 15   Provisions of company legislation requiring all private companies to impose restrictions on transfer of shares were repealed in 1980. That said, however, if the target is a publicly listed company, although its shares may prima facie be freely transferred, hurdles will nevertheless be thrown up by (in the case of a UK company) the City Code on Takeovers and Mergers and the Listing Rules of the London Stock Exchange. 13

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be as complex as asset deals. In a share sale, in addition to the sale and purchase agreement, a suite of documentation is usually also required, including a tax indemnity, a disclosure letter and additional documentation attending to the corporate formalities (including board minutes, director resignations and similar). Consents II-9.14 Generally, the governmental and third-party consents required on a share sale will be less extensive than those on an asset sale.16 Operatorship transfer II-9.15 A share purchase will allow the buyer to take operatorship more easily than on an asset transfer. The difficulty with an asset purchase is that the terms of the JOA will often allow the existing co-venturers to appoint one of their number to be operator upon resignation of the existing operator. Moreover, the JOA will provide for the seller to give notice of its resignation, such that the seller needs to resign pre-completion of the asset transfer in order to ensure that it does not remain as operator post-completion of the asset transfer (which may not be permitted under the terms of the JOA or, even if permitted, is undesirable from the seller’s perspective). The seller is thus resigning at a point when the buyer is not a party to the JOA (assuming that it was not already involved in licence operations in the block in question) and could not be appointed operator, unless otherwise agreed by the other co-venturers.17 Accordingly, if operatorship is important to the buyer, and the co-venturers are likely to be resistant to the buyer being appointed as operator, a share sale allows the buyer to assume operatorship more easily, by stepping into the shoes of the existing operator. Due diligence II-9.16 Legal due diligence on a share purchase must be more extensive than on an asset purchase as the buyer, in addition to the oil and gas assets, typically needs to review all other relevant company records including, for example, those relating to employees, property and pensions. Liabilities II-9.17 A share purchase has a disadvantage for the buyer as, on completion, it assumes all historic liabilities of the company, whether or not they   See paras II-9.30ff for further details.   Note, however, that it may be possible to deal with such a provision, depending on the facts and circumstances, by acquiring the asset in tranches and thereby becoming party to the JOA pre-completion of the transfer of the second tranche.

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relate to the oil and gas assets, for instance in relation to pensions, tax, employees, the environment and any other operations carried out by the target. Tax Often the reasons for electing to buy and sell assets by way of a share II-9.18 sale, rather than an asset sale, or vice versa, relate to tax issues. For example, a share sale allows the buyer to assume any corporation tax losses of the company being acquired (something not yet available on an asset sale – although see the proposal made in the Autumn 2017 Budget and discussed further in I-7.65) and likely allows the seller to take advantage of the substantial shareholdings exemption to capital gains tax.18 An asset purchase allows the buyer to take the benefit of existing capital allowances in respect of the assets. THE DUE DILIGENCE PROCESS Seller due diligence Where a seller decides to divest of oil and gas assets, it will need II-9.19 to undertake certain due diligence on the legal agreements relevant to those assets. This should be done at an early stage in order to consider whether any counterparties to such agreements could prevent disclosure of the agreements to prospective buyers, or, more importantly, prevent disclosure of data and information held under such agreements to interested buyers. Early due diligence will also help to establish whether any third parties otherwise have rights to block the deal or have preferential rights to purchase. Any such rights will affect whether the seller can sell the assets at all and/or how any sale will be structured. Confidentiality A seller will review relevant licence interest documents to consider II-9.20 whether the agreements, and any information and data held in connection with such agreements, can be disclosed to potential buyers without the consent of the other parties thereto. If they cannot, and consent of the counterparties to those agreements is required, this would give counterparties early notice (often earlier than commercially intended) of the intended divestiture. Whilst there will almost always be a confidentiality clause in oil and gas agreements preventing disclosure of data and information without consent, there is also often a “bona fide buyer” exception to this,   Taxation of Chargeable Gains Act 1992, s 8.

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meaning that such information can be passed to a prospective buyer upon the seller, in turn, obtaining an undertaking of confidentiality from the intended assignee.19 Assignment II-9.21 Similarly, a seller will want to check the assignment provisions in all affected agreements in order to ascertain the counterparties’ rights with regards to an assignment. Several common provisions can affect transferability of the affected agreements and these are considered below.20 It may be that a right of pre-emption, or difficulties surrounding assignment, could encourage the seller instead to sell by way of a share sale. Additionally, the distinction between assignment (whereby the benefit of the agreement can be transferred) and novation (whereby the benefits and obligations of the seller are transferred) needs to be borne in mind, as ultimately in novating an agreement, the “consent” of all parties is required.21 The “data room” II-9.22 If a sale is initiated by a seller, in order to maximise potential value, many sellers now elect to dispose of their assets by way of an auction process, whereby certain parties selected by the seller will be allowed access to a data room into which all relevant technical, financial, commercial and legal data, and agreements are placed. This will often now consist of a “virtual” data room accessible online for a limited time period. Potential buyers and their advisors will be invited to undertake due diligence on such data and information and to make a bid for the asset(s) or company (usually together with a marked-up sale and purchase agreement). Not surprisingly, legal due diligence is only part of the overall due diligence process conducted by the buyer. Where a share sale is anticipated, any person offering

  Note, however, that in some JOAs this refers to a bona fide buyer of the asset and not the shares of a company, meaning that specific consent may be required in respect of a share acquisition. 20   See para II-9.37. 21  A novation terminates the old contract and constitutes a new contract on the same terms and conditions but with different parties. The practice in the oil and gas industry is to proceed with any transfers by way of novation and it is often assumed that “assignment” means “novation” for the purposes of most assignment clauses and effect is given to the provisions of “assignment” clauses accordingly. However, a clause in a JOA that simply provides for consent to assignment “not to be unreasonably withheld” would in itself arguably not impose any obligation on a party to enter into a novation. 19

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to sell the shares may require to be authorised under the UK financial services legislation.22 Buyer due diligence The level of due diligence carried out by a buyer will vary from deal II-9.23 to deal, depending on whether the buyer has prior knowledge of the asset. Whilst some buyers will elect to carry out a full and detailed legal due diligence, others will carry out a more limited review and seek to rely on extensive warranties and indemnities in the sale and purchase agreement23. However, the latter option is not advisable due to uncertainties surrounding recovery of loss and likely expenses involved. Moreover, the seller will seek to disclose all legal agreements and information against the warranties it gives, in order to limit its responsibility for information already provided to the buyer. In other words, a review of the legal agreements and information provided is necessary and in the buyer’s best interest. As part of this process, it is in both parties’ interests to keep accurate and ongoing records of what has been disclosed to the buyer to avoid later dispute. Investigation of title A seller’s chain of title to the assets needs to be fully checked given II-9.24 that there is no conclusive legal register to determine title to oil and gas assets. Accordingly, a buyer will seek to confirm that the seller is on the licence and has the percentage interest it claims to have under the relevant JOA. In order to do this, the buyer will look for a valid chain of licence assignments and JOA novations from the date of licence award, which in the case of some more mature North Sea assets can be a time-consuming process. If any defects are discovered, then, depending upon their nature, there can be a requirement to remedy defective title by way of correcting historical assignments and novations. This too can be time-consuming and lead to delay. The OGA maintains a website that records the current parties to onshore and offshore licences, and their percentage interests in the different areas thereunder.24 However, this is only a record – it is not conclusive, and should not be used as a substitute for due diligence on title. If the transfer is by way of a share sale, the   Financial Services and Markets Act 2000, s 19(1).   Alternatively, a seller may instruct a legal due diligence upon which a successful buyer may rely. 24  See www.ogauthority.co.uk/data-centre/data-downloads-and-publications/licence-data (accessed 25 May 2017). 22 23

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seller’s title to the shares being sold needs to be checked in addition to the above. Encumbrances, charges, royalties and third-party rights II-9.25 A buyer will typically check for any encumbrances, charges and third-party rights over the assets (and, where relevant, shares) being sold. A search carried out at the UK company registry25 will assist in disclosing the existence of any charges in respect of UK companies and their assets, and allows the buyer to ascertain whether deeds of release and/or certificates of non-crystallisation of floating charges are required. Any overriding royalties over the seller’s interest in a licence will affect the financial value of the interests and, therefore, a buyer will be particularly interested in these. Existence of agreements and main commercial terms II-9.26 Gaining a clear understanding of the main commercial terms of the various relevant agreements will be of utmost importance to the buyer. The level of commercial review undertaken varies from transaction to transaction, and differs according to whether the asset is an older producing field or a newly awarded Exploration Licence. A buyer will require that the seller has the necessary rights under the various agreements and that there are no unduly onerous commercial terms. For example, if a producing asset is being purchased, is the seller party to agreements that allow for the transportation of petroleum produced to shore and for the processing and lifting of such production? On what terms are such agreements and is there anything unduly burdensome that affects the value? What are the JOA voting rights and are they appropriate given the interest being purchased? Is there any evidence of breach of contract or licence obligations by the licensee or others within its group? Are there current or anticipated claims and litigation in connection with the asset? Are there contractual provisions (in addition to pre-emption provisions) that would be breached by the acquisition, for example provisions in agreements for the purchase of seismic data which require the data to be returned, or an additional uplift payment to be made in respect thereof, if control of the target company changes? Are there any contingent liabilities, such as outstanding guarantees and payment obligations falling due on the occurrence of certain specified events?

  See www.gov.uk/government/organisations/companies-house (accessed 25 May 2017).

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Assignment/change of control It is vital that the buyer gains an understanding of the possible II-9.27 rights of pre-emption or grounds for refusal of consent in relation to any asset transfers. If such provisions are ignored, a buyer could undertake significant preliminary work, only to find that the deal is snatched away from it by one, or more, of the seller’s co-venturers with pre-emption or rights of first refusal. On a share sale, the buyer will need to check for any “change of control” clauses in the legal agreements that would affect its share purchase.26 Decommissioning The buyer should be able to understand at an early juncture what II-9.28 (if any) existing agreements are in place for final decommissioning of an oil and gas asset, and what (if any) security it needs to provide to the co-venturers in respect thereof and when such security needs to be provided (bearing in mind that it may also have to provide security to the seller under the sale and purchase agreement). If the provisions in the existing agreements require entry into a trust deed or provision of a bank guarantee or letter of credit, this requires attention at an early stage to avoid delay to the transaction.27 General corporate Irrespective of whether the acquisition is to be an asset sale or a II-9.29 corporate sale, the buyer would, as with any purchase, need to check the corporate capacity of the seller and its ability and authority to dispose freely of the relevant assets or shares. If a share sale, a full corporate due diligence would need to be carried out, including a review of all corporate constitutional documentation and all rights and liabilities otherwise affecting the target company. It is, however, not within the remit of this book to consider further such non-oil and gas due diligence. APPROVALS AND CONSENTS Asset sale In an asset sale, under Model Clause 40(1),28 OGA approval is II-9.30   Even if no change of control provisions are to be found in the JOA or other field agreements, there can be change of control provisions in seismic licensing agreements whereby an additional licensing fee can be payable on change of control of the licensee. 27   See Chapter I-13. 28   For the purposes of this chapter, references to model clauses are those applicable to 29th 26

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required for any transaction involving the assignment or other transfer of benefit under a licence. In practice, OGA approval for offshore licence transfers is now actioned electronically by submitting a standard application to the OGA through an online licensing portal known as “PEARS”.29 The OGA looks at the financial and technical capability of a licensee in considering whether or not to allow such a transfer, and sometimes the OGA will request a letter of support from the proposed assignee’s parent company (where it has one). Given the current trend of smaller oil companies (and funds/private equity) acquiring interests in the North Sea, financial capability is a matter of increasing concern for the OGA. OGA approval for a smaller, less complex deal involving an existing licensee may be obtained in short order; however, if the buyer is new to the UKCS or licence, or if there are questions regarding its financial position, approval may take longer as the OGA will have to verify the buyer fully and consult with various departments, and may require additional information, such as details of the buyer’s corporate structure, financial capacity and operational capability, among other things. Although the OGA has the power to request copies of draft transaction documentation, in practice, this is not used. II-9.31 If the sale involves the buyer assuming operatorship, specific OGA consent is required under Model Clause 24(1). This is commonly dealt with in the same application form, albeit that OGA may pay closer attention to the criteria of financial and technical capability of the buyer.30 The role of the OGA II-9.32 Typically, the purchase of oil and gas interests will, after the buyer has conducted due diligence and entered into a sale and purchase agreement with a seller, involve the following steps:

round Production Licences as set out in the Petroleum Licensing (Production) (Seaward Areas) Regulations 2008. Model clauses applicable to previous licences generally contain similar provisions. 29   Petroleum e-business assignments and relinquishments system; see https://itportal.decc. gov.uk/eng/fox/live/PORTAL_LOGIN/login. In respect of onshore licence transfers, OGA approval should be requested by completing the form available on the OGA’s website. 30  Note that the Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 include provisions relating to the competence and capability of operators appointed to undertake offshore oil and gas activities. Applicants for licence assignments entailing operatorship transfers must be submitted to, inter alia, the OGA in order to assess their safety and environmental competence and capability. Notably, the OGA must confirm that it does not object to the appointment, failing which, three months must have elapsed since the date on which notice was given to the OGA and the OGA must not have objected in writing to the proposed appointment. (Regulation 5(1)).

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ac qui si t i o ns a n d d i s p o sal s 309 (a) the seller will apply for OGA consent to a licence assignment (or for a transfer of a percentage of interest where no licence transfer is needed); (b) the OGA will transmit its consent, which is conditional on the transfer being affected in accordance with (i) the form set out in the Master Deed31; or (ii) the older standard form known as the “Approved Model Form Deed of Assignment”;32 (c) the buyer, the seller and remaining participants create and execute their transfer documentation in accordance with the form set out in the Master Deed or the Approved Model Form Deed of Assignment; (d) the buyer and the seller inform the OGA of execution and completion; and (e) the OGA updates its records.33

It is the execution and completion under (c) that perfects the buyer’s II-9.33 legal title to the assets. Typically, many other agreements also require to be novated simultaneously to the buyer.34 Share sale Although no governmental consent is strictly necessary to buy or sell II-9.34 assets by way of a share sale, attention needs to be given to Model Clause 41(3). This provides that the OGA may revoke a licence if a licensee undergoes a change of control which is not followed by such further change of control as the OGA requests, and within such period of time as the OGA specifies by written notice. “Control” is very widely defined.35 As such, it is common practice in share transactions to obtain a letter of comfort from the OGA prior to completion of such transactions, that the OGA will not seek to exercise such power to order a further change of control. Ultimately, such “comfort” is no more than that and consists of a relatively standard form letter from the OGA stating that it is not presently its intention to exercise such power. This is not legally binding but is usually sufficient for the parties concerned.

  See para II-9.43.   See para II-9.87. 33   The OGA’s records are created only from information passed to the OGA by licensees. 34   See para II-9.84 below with examples of agreements that may require to be novated to a buyer. 35   This is defined with reference to s 416(2), and (4) to (6) of the Income and Corporation Taxes Act 1988. “Control”, for example, includes acquisition of a 33 per cent interest in a licensee. Change of control is defined in Model Clause 41(4) as the acquisition of control by a person who did not previously have control and might even capture intra-group share reorganisations in addition to share acquisitions by third parties. 31 32

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II-9.35 Model Clause 41(3) was referred to by the UK Government in connection with the acquisition of DEA UK by LetterOne Group, an investment company run by the Russian billionaire Mikhail Fridman.36 Whilst Mr Fridman and LetterOne Group were not subject to international sanctions at the point of acquisition, the UK Government was concerned, following Russia’s annexation of Crimea, about the potential implication of sanctions on the ultimate beneficial owners of LetterOne Group and its resulting impact on UK oil and gas supplies. Accordingly, LetterOne Group was obligated to dispose of the assets acquired from DEA UK or risk having its licence interests revoked. II-9.36 Note that the OGA may also revoke the licence under Model Clause 24(2) where it considers that the operator is no longer competent to exercise such function. As such, in the event of a change of control of the operator, similar prior assurance is sought from the OGA that it will not exercise such power to revoke the licence. PRE-EMPTION AND RESTRICTIONS ON ASSIGNMENT AND CONSENTS AND APPROVALS II-9.37 Pre-emption rights are of great importance in oil and gas deals and much attention is rightly focused upon them. A right of pre-emption (typically found in a JOA or unit operating agreement (UOA)) allows co-venturers to block any agreed deal with a third party and thereby acquire a proportionate part of the interest intended to be disposed of to a prospective buyer.37 Pre-emption, right of first refusal or right to negotiate II-9.38 The language used in a “pre-emption” clause is important. Each clause needs to be looked at very carefully, but, generally speaking, it tends to take one of the following forms: (a) an obligation on a party to offer a deal that has been agreed

  The then Department of Energy and Climate Change announced on Monday, 20 April 2015 that “the secretary of state [formerly Ed Davey] has notified DEA UK and LetterOne that he proposes to revoke DEA UK’s North sea petroleum licences unless LetterOne arranges for a further change of control of the DEA UK gas fields in the North Sea”. See The Guardian, “UK government threatens to revoke oligarchs’ North sea oil licences”, 20 April 2015, available at www.theguardian.com/uk-news/2015/apr/20/ed-daveythreatens-revoke-letterone-oligarch-north-sea-oil-licences (accessed 21 May 2017). 37  See para II-2.13 for a discussion of pre-emption rights generally. See also Major, “A Practical Look at Pre-emption Provisions in Upstream Oil and Gas Contracts” (2005) IELTR 117. 36

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ac qui si t i o ns a n d d i s p o sal s 311 with a prospective buyer to its co-venturers (a true right of pre-emption); (b) a right of first refusal – the intent of such a clause is that a seller must offer its co-venturers the interest before agreeing a deal with a third-party prospective buyer. Usually, the seller not then sell to such a third-party prospective buyer on terms more favourable to that prospective buyer than those offered by any co-venturer; and (c) a lesser right on the part of a co-venturer to negotiate with a seller for a period of time, following which the seller may freely assign to a third party irrespective as to price obtained.

Often a pre-emption clause will catch a transfer of assets for cash but may not catch a swap, a share purchase or other variations, so such clauses need to be analysed carefully. In practice, the seller and the buyer will need to consider the impact of any pre-emption clause early on to determine the practical likelihood of a co-venturer pre-empting, and to ascertain whether they need to restructure the proposed deal in any way. If, for example, the proposed deal involves several assets, will the buyer go ahead and purchase the remainder if it is pre-empted on one particular asset? In analysing pre-emption clauses, great care is needed to ascertain the “trigger point” of operation. This is of particular importance as sometimes the trigger point can be at an early stage, before the intended buyer and seller have even agreed the deal in principle, for instance where the seller first considers or intends that it may wish to dispose of the asset. Typically, pre-emption clauses cause more concern to the buyer than to the seller, as it will not want to waste time agreeing a deal only to be pre-empted. The seller may not mind as it will receive the same consideration for the asset on the same terms.38

II-9.39 II-9.40

II-9.41

II-9.42

Master Deed The UK Government became concerned that pre-emption rights II-9.43 under JOAs were discouraging new entrants’ participation in the UKCS, and encouraged the industry to adopt new pre-emption arrangements in order to give buyers increased confidence and clarity. Parties to a JOA that are also parties to the UKCS Master Deed39 are subject to “New Pre-emption Arrangements”, whereby   This will not be the case in the scenario where a proposed deal involves several assets and the purchaser negotiates a right to terminate the deal if a key asset is pre-empted. 39  See www.logic-oil.com/master-deed (accessed 20 May 2017) for a summary of the 38

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existing pre-emption clauses in JOAs, to which they are party, are read and construed in accordance with the New Pre-emption Arrangements set out in the Master Deed. This does not apply to share sales or “swaps” (unless, in respect of swaps, there is already provision for conversion into a monetary amount within the JOA). II-9.44 The New Pre-emption Arrangements provide for two levels of notification: a voluntary seven-day period and an obligatory thirtyday period. If a seller elects to use the voluntary seven-day period and serves a notice of its intention to transfer an interest under a JOA, parties to the JOA will have a seven-day period in which to waive or reserve their rights of pre-emption. If the parties to the JOA have reserved their rights (or otherwise failed to respond to the notice within the seven-day period), they will have a thirty-day period once a pre-emption notice has been given by the seller (post the signing of a sale and purchase agreement) in which to decide whether or not to pre-empt. This has facilitated the speeding up of the deals process. It does not remove the risk that new entrants will contract to buy into an asset, only to find themselves “pre-empted out”, but, under the New Pre-emption Arrangements, if a buyer is particularly concerned, then the seller may serve a notice on co-venturers to “test the water”, even before a sale and purchase agreement has been signed. Co-venturers may therefore waive their right to pre-empt within seven days, or, where a pre-emption notice is served after the agreement to sell has been reached, they must pre-empt within thirty days. This is certainly an improvement on some of the lengthy and complicated JOA pre-emption arrangements with which buyers and sellers were formerly faced.40 The OGA will no longer approve any new JOAs containing II-9.45 pre-emption provisions (in respect of licences granted after 1 July 2002) without justification being provided therefor. As a result, most new JOAs do not contain pre-emption provisions. The unmatchable deal II-9.46 How then can a buyer and a seller seek to avoid the deal being pre-empted by co-venturers? An example often given of how to avoid many pre-emption clauses is by offering non-cash consideration that the co-venturers cannot match. For instance, in a swap/ UKCS Industry Master Deed. 40  Issues can however arise pursuant to the Master Deed pre-emption arrangements centred around the interpretation and application of existing pre-emption and right of first refusal clauses in JOAs in connection with the requirement that such clauses are to be “read and construed” in accordance with the New Pre-emption Arrangements set out in the Master Deed. See cl 3(2) of the Master Deed.

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exchange the co-venturers wishing to pre-empt will not be able to match the consideration offered by the buyer, being an interest in a specific piece of acreage that the co-venturers do not possess. Many JOA pre-emption clauses, however, require the seller to allocate a cash consideration value where non-cash consideration is envisaged. A co-venturer may then pre-empt by paying this cash-equivalent sum. If there is no requirement to allocate a cash consideration, the argument is usually run that the unmatchable deal route around pre-emption has been well within the contemplation of JOA negotiators for years, and could be legislated for in the contract, therefore pre-emption is not applicable with respect to the proposed transfer. The wording of the pre-emption clause will be important in this regard.41 The package deal Another example is the “package deal” whereby the seller offers II-9.47 to sell an apparently indivisible package of assets which cannot be split. The argument here runs that the seller is only willing to dispose of a package of assets for a certain consideration, therefore a co-venturer cannot pre-empt as the pre-emptable interest and all the other assets forming the package are not pre-emptable by the co-venturer. Ultimately, this route can lead to argument, depending on the precise wording of the JOA. The co-venturer may claim that it cannot be denied its rights in this manner and that a fair value must be apportioned to the relevant asset, or the co-venturer may claim that it is entitled to pre-empt the whole package.42 Affiliate route As mentioned previously, share sales are not generally caught by II-9.48 pre-emption rights in UK JOAs. A share sale of the company holding the asset may not always be attractive to the parties for reasons discussed above, but another way of typically avoiding pre-emption is the “affiliate route”. Here, the seller will hive down the relevant interests into a newly incorporated affiliate and then sell that affiliate to a third party by way of a corporate sale. Most JOAs will allow the transfer of the asset to affiliates without triggering the pre-emption clause principally because companies require freedom to re-organise   For example, an ability to pre-empt on “the same terms” is likely to be less challengeable by a co-venturer than an ability to pre-empt “on the same or equivalent terms”. 42   Indeed, often an allocation between different assets in a package will be required for allocation of capital allowances and would be set out in the sale and purchase agreement, leading to difficulties in the seller pursuing such an argument. 41

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their groups for many different commercial and tax reasons, and often this does not have an adverse effect on co-venturers. However, there are some difficulties in a seller opting to take the “affiliate route” to avoid pre-emption. Some JOAs will contain restrictions on this sort of avoidance technique. For instance, whilst transfers to affiliates may be permitted, it may be that if such affiliate ceases to be an affiliate of the transferor within a short period thereafter, the co-venturers may require the transaction to be unwound such that their rights of pre-emption are not fettered. Furthermore, the definition of “affiliate” in the relevant JOA will be important. Frequently, this definition will be linked to the Companies Acts definitions that allow beneficial ownership to be taken into account when considering whether a company is an affiliate of another.43 There is, therefore, often an argument raised that if arrangements are already in place to on-sell that affiliate at the time of giving notice to co-venturers, it is not a true affiliate at all and that this transfer could itself be pre-empted. Clearly, the stronger the deal with a buyer at the time of hive-down the greater likelihood of attack on this basis. Although JOAs will allow transfer to affiliates, often there is a financial capability test whereby the co-venturers can refuse consent to a transfer to a less financially capable affiliate. If the affiliate is a company with no other assets at the time of transfer, an attack on these grounds is also possible.44 Other arguments are also given as to why the affiliate route may be challenged. In particular, in the case of Texas Eastern45 the courts implied certain terms into commercial agreements in order to prevent pre-emption avoidance techniques. However, it is submitted that such a result should be unlikely where there is a well-drafted JOA between commercial parties, since the courts would generally

 Companies Act 2006, s 1159 and in respect of agreements entered into prior to it coming into force the Companies Act 1985, s 736 (as amended by the Companies Act 1989 s 144). 44   One solution is then for the seller (or its parent company) to grant the co-venturers a guarantee of the obligations of the affiliate in order to satisfy such concerns. However, the seller would want to ensure that that guarantee would be released and replaced with the covenant of the buyer upon completion of the share sale. 45   Texas Eastern v EE Caledonia (CA) (1989) unreported. Although the licence interests of the subsidiaries had been split so that it was not easy to see in what proportions the preempting parties should acquire the share capital of the Texas Eastern subsidiary, the Court of Appeal held that there was an underlying commitment to a reasonable solution and that the problem of the proportions in which the shares should be acquired could be likened to that of ascertaining the contract price under a contract for sale at a reasonable price. In short, it implied a term of reasonableness to fill the gaps in the mechanism and to give business efficacy to the contract. 43

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be reluctant to interfere and imply terms not set out in such agreement. Finally, there could be a challenge to a circumvention of II-9.53 the pre-emption provisions by way of the affiliate route or the unmatchable deal route on the grounds of appeal to fiduciary duties.46 An alternative would be to transfer out all other assets which the II-9.54 seller wishes to retain into other members of the group, leaving the existing interest owned by a company with nothing in it other than the interests. This may be more effective, as there is no transfer of relevant pre-emptable assets involved, but clearly involves the buyer taking on additional exposure in acquiring an older company with the associated liabilities and the seller taking on cost and administration, and the potential further legal and tax complications, and associated delay, in transferring assets into other group companies. Consent Even if pre-emption has successfully been avoided or not exercised, II-9.55 or if there is no pre-emption clause at all, JOAs will make provision for the co-venturers to consent to any intended transfer. This often provides that the co-venturers can only withhold consent to any intended disposal of assets on grounds of lack of financial and/or technical capability of the buyer, or the JOA sometimes states more simply that consent may not be unreasonably withheld.47 In both cases this can provide co-venturers with the opportunity to extract guarantees from the buyer’s parent or bank in return for consent, which can make any deal potentially more expensive for a buyer. It is more unusual in JOAs for there to be an absolute discretion on the part of co-venturers. A typical JOA will prohibit the transfer of a licence interest unless II-9.56 the interest in question is an “undivided” interest under the licence and JOA. The idea behind this is to prevent a party from assigning rights without the corresponding obligations (ie a beneficial interest only), and also to prevent it transferring its interest in respect of one part of the licence area while retaining its interest in respect of the remainder. If the latter is what is proposed, specific agreement will have to be reached for the purposes of splitting the JOA so that it will apply as two separate agreements to the two different areas.  On fiduciary duties and joint ventures see G Bean, Fiduciary Obligations and Joint Ventures (1995) (hereinafter “Bean, Fiduciary Obligations and Joint Ventures”). See also P Roberts, “Fault lines in the joint operating agreement: fiduciary duties” (2008) IELR 218. 47   This is an objective test. See British Gas Trading v Eastern Electricity PLC and others [1996] EWCA Civ 1239 (18 December 1996). 46

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This does not prohibit the assignment of part (or a proportion) of the seller’s total percentage interest in the licence and JOA, although some JOAs also provide that a party may not transfer part of its interest if the transfer would result in the assignor or the assignee holding less than a certain specified percentage interest. SALE AND PURCHASE AGREEMENT II-9.57 Following due diligence, the buyer and the seller will negotiate the acquisition agreement setting out the terms of their sale and purchase. The aim of this section is not to give a detailed account of such agreement but rather to note specific points relevant to an oil and gas deal, given that the sale and purchase agreement itself is otherwise no different from a typical sale and purchase agreement for a corporate or business/asset sale and purchase. Here, the focus will principally be upon a sale and purchase agreement in respect of assets for a monetary consideration, albeit that we will touch on other structures. The asset sale and purchase agreement The assets II-9.58 An important issue in any asset acquisition is identification of the oil and gas assets that are being sold and purchased. As mentioned above, under an asset deal, the buyer is not buying any physical assets, but a series of inter-related rights and obligations in the licence(s) and various agreements. Typically, this will consist of an interest in the licence(s) in question and a working interest under the relevant JOA(s) and any associated agreements. If the asset is producing there will be rights under various field agreements, and potentially the buyer may also want (or may have to take) certain of the seller’s rights under product sales agreements. In addition, the buyer will want title to the data owned by the seller in respect of the assets, and where operatorship is being transferred, the buyer will need to take on the rights of, and assets held by, the seller in its capacity as operator. Consideration II-9.59 The asset sale and purchase agreement will state what consideration is payable for the asset and when it is payable. As discussed above, consideration can take various forms. In a straightforward cash-forasset deal, the consideration will be payable at completion, although the seller may look for a deposit payable upon signing which might be retained in the event of a failure to complete the transaction due to the buyer’s fault. Additionally, there may be circumstances where

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the buyer will request a retention and look to defer a portion of the consideration until, for example, the end of the warranty period, so as to protect its position if the asset acquired is not as warranted by the seller. Some of the consideration may also be deferred until the occurrence of a specified event, such as the granting of field development consent or occurrence of certain levels of production. In addition, sometimes the seller itself (as part of sale of exploration acreage, for example) may require the grant of a production royalty or net profit interest so as to benefit in any future upside of the asset. Where the consideration is cash, this will often be adjusted for various reasons. There will be an “economic date”, which is the date at which the II-9.60 buyer has valued the assets. The valuation of oil and gas interests is based on a net present value of projected after-tax net cash flows, from the interest at a specified date and will, therefore, assume that all costs and benefits from this date onwards would accrue to the buyer. Any convenient historic date for which accurate and up-todate figures are available may be used to set the economic date and for interests subject to petroleum revenue tax (PRT) this is historically 1 January or 1 July to coincide with the PRT return periods.48 The end of a PRT period was often used for PRT-paying assets, so as to avoid apportionment of that tax between seller and buyer for any chargeable period. Year end is often used (for both PRT and joint venture billing purposes). The asset sale and purchase agreement will reflect the economic II-9.61 date such that the buyer, upon completion, will be treated as if it has beneficially owned the assets since the economic date (that is, the economic risk and benefit is the buyer’s). As such, there will be a headline consideration which the buyer is willing to pay for the assets as at the economic date which is then adjusted whereby: (a) any receipts (for example, from petroleum sales) received by the seller in the period of time from the economic date to completion are treated as being the buyer’s such that the headline consideration is adjusted downwards; and (b) any expenditure incurred by the seller (for example, operating expenditure under a JOA) in relation to the interests in this period will similarly necessitate an adjustment of the purchase price upwards. Working capital, in respect of the interests at the economic date, is II-9.62 often also added to the consideration, since it is not accounted for  Note that the 2016 Budget “abolished” PRT with effect from 1 January 2016 such that the rate of PRT would be set at 0 per cent but the tax retained for the purposes of calculating tax allowances associated with decommissioning.

48

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in the valuation (which, as mentioned above, is based on future cash flow) – this is effectively the present position of the interests at the economic date, and would include oil and gas stock (in platform, pipeline and terminals), equipment stocks and spares, receivables and payables as at the economic date, and the seller’s liability for any historic “overlifting” or benefit of any historical “underlifting” of production (all as per the relevant operator’s corporate statements, as and when they are produced). II-9.63 Notional interest is added to the various adjustments in order to put the seller and the buyer in the same position that they would have been had completion occurred at the economic date and earned interest on monies received. There will usually be a mechanism postcompletion to allow these adjustments to be accurately calculated and agreed. There is also a broader type of tax adjustment which is common in asset sale agreements and which takes into account the value of all payments and receipts in the hands of the seller and/ or the buyer (as the case may be). For example, if the seller receives payment for a cargo of oil lifted after the economic date, this revenue is for the buyer’s account and the purchase price will be reduced accordingly; however, in calculating the amount of the reduction, it will not be the gross revenues which are deducted, but the actual value of the revenue. This will be its post-tax value. A percentage of the revenue will be lost in corporation tax and since it is the seller that would bear the tax, it is in most cases, therefore, inappropriate for the gross amount to be deducted from the purchase price. II-9.64 The above adjustments to the purchase price are agreed to give the parties a “clean break” going forward, rather than continuing to account to each other in respect of pre- and post-economic date benefits and liabilities. However, to back this up, there are normally indemnities set out in the sale and purchase agreement which will be given in respect of pre and post-economic date activities to deal with the circumstance where a benefit or liability comes to light in the future, but has been omitted from the adjustments calculations. II-9.65 On a share sale, the breadth of adjustments described above is not necessary on the basis that monies paid and received in respect of the relevant asset will flow into the company. It will therefore be necessary to provide for monies going into or out of the corporate entity (or to prevent this happening) in addition to dealing with payment of any intra-group loans etc or, alternatively, ensuring that the acquired corporate entity is in a cash-free position at completion.

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Conditions precedent Since the various consents described above49 need to be obtained II-9.66 before the buyer can acquire the interest, signing and completion under an asset sale and purchase agreement will not be simultaneous and, therefore, there will be a time gap (often referred to as the “interim period”) between the signing of the sale and purchase agreement (or “exchange”) and completion.50 Accordingly, there are usually certain “conditions precedent” stated in the sale and purchase agreement which need to be satisfied before the parties are under an obligation to complete the deal. Typically these are: (a) OGA consents and approvals. In a share deal, this will be the provision of a letter of comfort from the OGA concerning the proposed change of control.51 (b) Waiver by co-venturers of their pre-emption rights. Note, however, that it is possible for the parties to agree that if pre-emption rights are successfully exercised, the whole deal will not fall away and that the buyer shall remain bound to purchase the non-pre-empted part of the assets. (c) Third-party consents. This will include the execution by such third parties of necessary assignments and novations to transfer the rights and obligations under the relevant agreements from the seller to the buyer (or in the case of the Master Deed process, by the UKCS Administrator on their behalf).52 Where executed by third parties, these agreements are in effect held in escrow by the buyer and the seller until completion. (d) There will likely be other items that the parties may add as conditions precedent, for example release of the seller from certain guarantees previously given to third parties or any necessary competition law clearances. The fewer conditions precedent, the greater the certainty that the II-9.67 deal will complete. The seller will want to resist any conditions precedent around anything else not within its control so as to limit the possibility of the deal not completing, such as conditions precedent in connection with the obtaining of finance by the buyer or the buyer being satisfied with further due diligence.

  See paras II-9.37ff.   It may be possible on “simple” asset or share deals to sign and complete on the same day provided that (1) in the case of an asset sale, OGA consent has been received and the transfer documentation is capable of being executed simultaneously with the sale and purchase agreement; and (2) in the case of a share deal, the letter of comfort on change of control can be obtained upfront, avoiding any need for an interim period. 51   See para II-9.34. 52   See paras II-9.89ff for details of the Master Deed execution process. 49 50

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Interim period II-9.68 As described above, there will be a period where the sale and purchase agreement has been signed but the assets will be owned by the seller. As such, the buyer will insist on certain provisions being set out in the sale and purchase agreement restricting what the seller may or may not do with the assets, since pending and subject to completion those assets are effectively held in trust by the seller. A balance must be struck whereby the seller may continue to run the assets in a relatively unfettered manner (bearing in mind that if the conditions precedent are not satisfied the seller will remain the owner) but will be bound to supply certain information to the buyer, and sufficient comfort that it will not do anything to affect adversely the value or existence of the assets. Typically, this will involve provisions including the following: (a) The buyer will want to ensure that the assets continue to be run in the ordinary course and in accordance with good and prudent UK oil and gas field practice. (b) Restrictions will be imposed on the seller’s ability to dispose of, or otherwise encumber, the assets and a positive obligation will be imposed to take necessary steps to protect the assets. (c) The seller will, subject to any relevant co-venturer approvals, be required to make available material information and data to the buyer. (d) The seller will not be permitted to make any material change to the assets, for instance, by amending any relevant asset agreements without consultation with the buyer or approving onerous future work programmes without consultation. (e) Although the buyer may want to exercise the seller’s JOA voting rights in the interim period, this can lead to practical difficulties, as this may constitute a breach of Model Clause 40.53 It may also give rise to difficulties with co-venturers who may be unwilling to allow this (and may indeed also breach confidentiality provisions given to its co-venturers) and/or may give rise to fiduciary duty issues.54 The seller will therefore usually allow only a right of consultation in relation to voting and will agree to take into account any representations made to it by the buyer.  “The Licensee shall not, except with the consent in writing of the [OGA] and in accordance with the conditions (if any) of the consent do anything whatsoever whereby, under the law (including the rules of equity) of any part of the European Union or of any other place, any right granted by this licence or derived from a right so granted becomes exercisable by or for the benefit of or in accordance with the directions of another person.” (Model Cl 40(1)). 54   See Bean, Fiduciary Obligations and Joint Ventures. 53

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ac qui si t i o ns a n d d i s p o sal s 321 (f) Often the seller may have to ensure any existing insurance policies continue in force, although practice varies since this can be contrary to the notion of risk passing to the buyer at signing, albeit that risk may be difficult for a buyer to insure since it has no apparent insurable interest prior to transfer of ownership of the asset.

In a share sale interim period, the buyer will require a longer list of II-9.69 negative covenants from the seller relating to the way it will run the business pending completion. The buyer will not want the seller to do anything that would devalue the company, such as paying cash out to the seller group in dividends or entering into commitments which are outside the usual course of its business. Warranties As with any other transaction, the seller will require to give certain II-9.70 warranties to the buyer as to the assets in order to provide the buyer with a remedy against the seller if these are untrue. If a warranty is untrue, the buyer may have paid too much for the assets and the buyer may look to recover the loss in value resulting from such warranty being untrue. Warranties also encourage the seller to make specific disclosures against them, highlighting at an early stage to the buyer any potential items of concern. There are some items which, in practice, the seller will ordinarily assume risk for pursuant to the warranties, and others where the buyer will normally take the risk. Warranties will vary from deal to deal but examples of the II-9.71 minimum warranties commonly sought are as follows: (a) Title – clearly this is most important to the buyer. Does the seller have title to the assets it purports to dispose of and are the assets encumbered in any way? (b) Default, withdrawal, revocation, surrender – the seller will warrant that it is not in default under the JOA, or has not elected otherwise to withdraw from or surrender its licence, and that no other licensee has undertaken similar action, nor is there any circumstance whereby the licence may be revoked. Similarly, it might warrant that it has satisfied all accrued JOA obligations and has not committed to any expenditure not disclosed. (c) Sole risk/non-consent – the seller would warrant that neither it nor its co-venturers has undertaken or elected not to undertake such operations (which might clearly have an effect on both the interests being purchased and the value thereof). (d) Information/agreements – the seller would warrant that the information and agreements provided to the buyer are

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accurate and complete and that there are no other agreements or information relevant to the interests. (e) Litigation – the seller will warrant to the buyer that it is not involved in any litigation which may affect the interest and that it is not aware of any litigation pending. (f) Assignment/change of control – the seller will often be asked to give a specific warranty that assignment provisions have been disclosed and that there are no other restrictions on its ability to transfer the interests to the buyer. (g) Miscellaneous – various other warranties will be given depending on the matters of importance to the buyer (and the bargaining power of the buyer). For instance, it is not unusual to see warranties that the seller has plugged and abandoned all relevant non-producing wells in accordance with prudent oil and gas field practice, that it has not received any notices regarding compliance with environmental or health and safety legislation, warranties as to available capital allowances and other tax matters, and any other specific matters the buyer wishes to cover. In addition, standard warranties regarding corporate capacity and authority to enter the transaction are normally given by both the buyer and the seller. II-9.72 From a seller’s perspective, it will want to exclude any potential warranties relating to reserves and reservoir performance and also generally anything relating to the physical condition of equipment utilised in joint operations, since these are often potentially large and often unquantifiable and uncertain exposures which the seller will be unwilling to take risk on. As in any transaction, the seller will want to restrict the warranties it gives to being as specific and narrow as possible in order to allow for disclosure against those warranties prior to signing. II-9.73 Much negotiation will be spent on agreeing appropriate caps, time limits and other restrictions on warranty claims and the disclosure letter (where the seller will normally try to disclose all documentation available in the data room), as for any other non-oil and gas asset deal. As for any transaction, bargaining power usually dictates the final position on warranties. II-9.74 The warranties schedule of a share sale agreement will contain a section of statements, similar to the above, relating to the target company’s oil and gas interests. But there will also be warranties relating to all other aspects of the company being acquired, for example its real property, employees, pension schemes, accounts, tax affairs, intellectual property, corporate activities since the valuation date, other property, debt position, and so on.

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Indemnities and decommissioning As for any other corporate or asset deal, indemnities may be set out II-9.75 in the sale and purchase agreement to cover any particular areas of concern for the buyer such that the buyer will have greater comfort that it can fully recover its loss than under a warranty. For instance, where a particular matter is disclosed in connection with a warranty requested by the buyer (for instance, the existence of litigation), the buyer may wish to add a specific indemnity to the sale and purchase agreement to cater for this in order to allow for full recovery of any loss. In addition, the seller will typically expect the buyer to indemnify II-9.76 it in respect of any decommissioning or environmental liability so as to effect, in so far as possible, a “clean break” from the interests. Such matters are of importance to the seller as liability can potentially be attributed to it many years after selling the relevant interests.55 This can be the case even in a corporate sale.56 Decommissioning liability is a particular concern for sellers. The II-9.77 Secretary of State is typically reluctant to allow a formal release of a seller from Section 29 notices where the incoming buyer is less financially capable.57 Even where the Secretary of State releases a seller post-completion of a transfer of interests to the buyer, he/she may still, under section 34 of the Petroleum Act 1998, require the seller (or an associated company) to prepare an abandonment programme and fulfil its abandonment obligations. As such, many sellers (and their affiliates) face potential exposure to decommissioning liabilities post-exit from the relevant asset. Given the size of potential liability, most sellers are simply not willing to accept an indemnity from the buyer in respect of this risk, given that an indemnity is only as good as the future financial capability of the party providing it, and will instead often seek specific security in respect of this potential liability from the buyer; a parent company guarantee, or more typically, the provision of an annual renewable letter of credit. This can cause difficulties for the buyer as it may (depending on the JOA and any field decommissioning security agreement in place) also be required to post security to its new co-venturers in respect of future decommissioning costs. As such, the buyer could potentially have to post security twice in respect of one liability.58

  See Chapter I-13.   As the provisions of s 29 of the Petroleum Act 1998 could give rise to liability in respect of decommissioning on the part of (previous) “affiliates” for failure to comply with that section. 57  See paras I-12.43 to I-12.57 for a summary of notices issued under s 29 of the Petroleum Act 1998. 58   One solution is for the buyer and the seller to endeavour to pull the JOA co-venturers, 55 56

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II-9.78 While the recent decommissioning relief deeds59 entered into between the UK Government and industry have assured availability of tax relief on decommissioning expenditure and allowed buyers to post security for decommissioning on a “post-tax” basis (potentially reducing the amount of security required by between 50 per cent and 75 per cent), the lower oil price has seen projected dates for decommissioning move further forward, necessitating increasing amounts of security.60 More recently, as a result of the lower oil price and the increasing maturity of the North Sea basin, it is apparent that in order to achieve the sale of certain North Sea assets, particularly in circumstances where buyers are perceived to be less financially capable than sellers, sellers may require to retain liability for decommissioning in whole or in part. This has led to a number of innovative deal structures in order to facilitate transactions in a low oil price environment. Some examples of deal structures seen in the UKCS designed to address decommissioning liabilities are as follows: (a) A sale of the asset and re-transfer to the seller at the point of decommissioning. This may be in the form of an outright sale or a sale and leaseback and is simplest for assets where the seller holds a 100 per cent beneficial interest (otherwise existing co-venturer consent would be required). A benefit here is that the seller may be better placed to undertake decommissioning than the buyer (for example by using existing experience and efficiencies of scale). (b) The seller being liable for some or all of its (transferred) percentage share of decommissioning of the assets, but simply paying the cost at end of field life rather than requiring an asset re-transfer. While this is the simplest approach, the seller will lose control over decommissioning spend, unless it caps its liability or seeks contractual control over decommissioning activities. (c) The seller transfers decommissioning liability to the buyer but the seller provides interim credit support in order to secure the costs of decommissioning at a field/co-venturer level and obtain back-to-back security from the buyer where the buyer cannot meet the co-venturers’ security credit requirements. the seller and any other historic asset owners that may require or be entitled to security into one decommissioning security agreement whereby security can be posted for the benefit of all beneficiaries. See generally Chapter I-13 for further detail on decommsisoning security issues in oil and gas acquisitions and disposals and see also for example AlderseyWilliams, “The Decommissioning Cost Provision Deed: Facilitating Asset Transfers on the UKCS” (2008) IELR 169. 59   See Chapter I-13 for detailed discussion on decommissioning relief deeds. 60   See Chapter I-13.

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ac qui si t i o ns a n d d i s p o sal s 325 Here, the seller would take the credit risk of the buyer’s backto-back security being weaker than its own, knowing that it may be at risk of being liable to co-venturers for the buyer’s share in any default.

Key considerations will apply in each of these structures. From a II-9.79 seller’s perspective, depending on the structure, it may be important for it to have a form of continuing interest in the asset in order to oversee future capital expenditure and significant developments that impact decommissioning, including, among others, the addition of new facilities, drilling of wells, interim decommissioning, third party tie-ins, transportation and processing arrangements via the transferred infrastructure and ease of termination of field agreements in a hand-back scenario. However, should extensive continuing administration be required on the part of the seller, this removes one of the primary reasons for selling in the first place, namely the overheads and time dedicated to the relevant asset in the seller’s portfolio. Even where the sale price is small or negative, the seller may II-9.80 benefit from the “time value of money” that is gained by delaying its decommissioning spend and reallocating its resources elsewhere in the meantime. There is also a hope that by extending field life, the decommissioning industry will be more developed at the time decommissioning takes place, resulting in cost savings from the application of new technology and greater economies of scale. Similarly, it will be in the buyer’s interest to extend field life and receive revenues from ongoing production for as long as economically viable, knowing that it will not be responsible for costs of decommissioning the infrastructure at end of field life. FARM-OUT AGREEMENTS The reasons for farming out oil and gas interests principally relate to II-9.81 the sharing of risk and, in some cases, accelerating exploration work. Sellers will often principally want to farm out interests to reduce exposure to well costs and/or to ensure that minimum licence work commitments are met.61 More often than not, the farm-in obligation assumed by the buyer tends to be in respect of drilling or paying for the drilling of exploration or appraisal wells, although farm-outs in respect of field development work are becoming slightly more frequent than they once were.

 For example, the buyer may have access to a drilling rig not available freely to the seller. Tax considerations are also important – for example, a farm-out of undeveloped acreage is deemed to be for zero consideration for capital gains tax purposes under the UK tax regime.

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II-9.82 Farm-out agreements differ from asset sale agreements for monetary consideration in several respects. Key differences are: (a) Seller retention of interest. In a farm-out agreement, the seller will always retain an interest in the asset that is the subject of the farm-out. A typical example would be where the seller holds a 50 per cent share in an asset and agrees to sell a 20 per cent share in return for the buyer paying for a 50 per cent share of the costs of drilling an exploration well.62 Here, the seller will retain a 30 per cent interest. (b) Nature of the consideration. Rather than pay a monetary sum at completion, the buyer will assume either an obligation to perform certain work (for example, drilling) or pay a specified share of the costs of the operator in performing such work. Where the buyer’s obligation is to drill a well, it will likely want to be appointed operator under any JOA in place, or otherwise obtain equivalent rights and protections in respect of any other co-venturers. From a regulatory perspective, if the buyer’s obligation is to drill a well and it is not appointed operator pursuant to the licence and JOA, it will require to be appointed as “well operator” for the purposes of the Offshore Installations and Wells (Design and Construction, etc) Regulations 1996.63 (c) Timing of “completion”. Transfer of the interest (ie completion) may occur at a different point, depending on the outcome of negotiations. From a buyer’s perspective, it will ordinarily want to have the earned interest transferred to it as soon as possible and before commencement of the work to be performed. This has advantages to it in terms of becoming party to the JOA and enjoying, for example, the protections, information and voting rights thereunder. The seller may be more reluctant to transfer the interest “upfront” prior to performance of the obligations since if the buyer does not perform/pay, it may want to require a return of the interest to it, which can entail complexity and uncertainty.64 The seller may therefore insist that the interest is only transferred following performance of the relevant farm-in obligations. In that case, the buyer would want (at least) to negotiate JOA-type provisions into the farm-out agreement and also regulate the position as to what  The buyer would therefore bear “its” acquired 20 per cent share of well costs and “carry” the seller’s remaining 30 per cent share. In oil industry terminology, the ratio of percentage costs borne to interest acquired is known as the “promote”, in this example a 2.5/1 promote. 63   See s 2 and Pt IV thereof. 64   For example, regulatory and co-venturer approvals would be required. 62

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ac qui si t i o ns a n d d i s p o sal s 327 happens if, for whatever reason, regulatory or co-venturer consent is not forthcoming following well completion.

One of the key areas for negotiation in a farm-out agreement is the II-9.83 nature of the obligation on the buyer. For example, the following items are often the focus of the negotiation of the farm-out agreement: (a) Where specifically is the well to be drilled? (b) Is there an agreed well programme and budget? (c) Who bears the cost of any budget/cost overrun? (d) Which obligations/costs is the buyer responsible for in its “promote” share? For instance, does it include rig mobilisation, demobilisation, surveys, testing, logging, coring, capping, completing, side-tracking and any liabilities arising as a result of drilling the well (for example, pollution), and so on? (e) Is the buyer’s monetary obligation (at least in respect of the “carried” element of costs) capped in any way? (f) What happens if the well cannot be drilled in accordance with the well programme – for example, if geological reasons prevent target depth from being reached? Is there an obligation to drill a substitute well? Can the buyer still deem completion to have occurred if, for example, a minimum spend has been achieved? COMPLETION With an asset purchase (and/or farm-in), the closing documents II-9.84 necessary to transfer legal title in the assets to the buyer will include a licence assignment and almost certainly one or more JOA (or bidding agreement) novations. There may also be novations for UOAs, transportation and processing agreements, petroleum sales agreements and all other project contracts and, in some cases, a working interest assignment.65 A novation will release the assignor from its liabilities under the II-9.85 relevant agreement(s) and substitute the assignee in place therefor, as if the assignee had always been party to the relevant agreement(s). The allocation of such liability between the assignor and assignee will, however, be governed by the sale and purchase agreement. For  The working interest assignment is the conveyance of the beneficial interest in the relevant asset set out the sale and purchase agreement. This was historically used for stamp duty purposes as the stampable document. The common view is that this is no longer strictly required given standard wording in the licence assignment and novations, but it can be useful in some circumstances to evidence completion of the transfer of the interest, particularly where there is no need for any novation of a JOA.

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the co-venturers, on and from the execution of the novation, they can look to the assignee in respect of all obligations and liabilities pursuant to the relevant agreement(s). II-9.86 Stamp duty is no longer payable on transfers of oil and gas assets, although if any transfer involves an interest in UK land, it is potentially subject to stamp duty land tax.66 For example, asset transfers involving “interests” in onshore pipelines and terminals and onshore oil and gas licence transfers may potentially be subject to stamp duty land tax (or land and buildings transaction tax), although the position as regards to onshore licences is not altogether clear.67 Formerly, it was common to execute a stamp duty agreement, where the sale and purchase agreement and/or the working interest assignment was to be executed and held outside the UK for the purposes of avoiding paying the ad valorem duty on the conveyance or transfer on sale. Note that stamp duty is payable in respect of share transfers, currently at a rate of 0.5 per cent of the consideration.68 II-9.87 As noted previously, a licence transfer may be affected in the form set out in the Master Deed or by using the Approved Model Form Deed of Assignment.69 The JOA and any other agreements should be novated at the same time as any licence transfer in order to ensure that the assignee steps into the shoes of the assignor in respect of the assigned interest and the rights and responsibilities attached thereto. The transferee will covenant with the continuing co-venturers that it will undertake the obligations in respect of the transferred interest, and the continuing co-venturers will accept such substitution and will release the transferor from its obligations. II-9.88 As mentioned previously, assignment documents will be negotiated and signed by the counterparties in the interim period under the sale and purchase agreement such that the buyer and the seller can execute at completion and “complete” the deal. The Master Deed II-9.89 In addition to the “New Pre-emption Arrangements” described above, the Master Deed70 also introduced “New Transfer Arrangements”.   Note that stamp duty land tax was replaced in Scotland by land and buildings transaction tax, effective from 1 April 2015. 67   See H Jones, S Greaves and J Phelan, “Oil and Gas Licences – QED? Stamp Duty Land Tax Issues in Transfers of UK Oil and Gas Licences” (2006) IELTR 125 for a discussion. 68   Stamp Act 1891, s 55. 69   A copy of the Approved Model Form Deed of Assignment can be found on the OGA website at www.ogauthority.co.uk/licensing-consents/licensing-system/licence-assignments (accessed 20 May 2017). 70   See para II-9.43. 66

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Under these arrangements, a seller can elect to use a document known as an “execution deed” in order to effect licence assignments, novations of JOAs and any other agreements that require to be novated to the buyer in connection with an asset deal.71 The UKCS Administrator is appointed as attorney to execute execution deeds on behalf of the counterparties to the various agreements that are “Contracting Parties”.72 A seller will issue “Notices of Transfer” to such counterparties together with the draft execution deed and a form of “Consent to Transfer”. These counterparties will each return a “Consent to Transfer” duly signed by them authorising the UKCS Administrator to execute the execution deed on their behalf. Whilst Notices of Transfer and Consents to Transfer were originally prepared and executed by Contracting Parties in hard copy, this process is now administered electronically by way of “Master Deed Online”.73 The “New Transfer Arrangements” have a twin benefit in that the II-9.90 standardisation of the transfer process ensures that asset transfers are not delayed through prolonged negotiation of the novation agreement(s). Gone (to a large extent) are the days of quibbling over the small print in the novation agreements and dealing with conflicting drafting requests from co-venturers. Secondly, the fact that Consents to Transfer require only one signature avoids any associated delays with having licence assignments (and sometimes novations) signed as deeds, often necessitating execution by directors/ secretaries of the counterparty and/or the use of a company seal. In a UKCS acquisition/divestment, it is entirely the decision of II-9.91 the seller whether or not to use the “New Transfer Arrangements”. Indeed, often a seller may elect not to use the Master Deed transfer process and revert to the “traditional” assignment and novation process where, for example, there are very few other counterparties to the relevant agreements, meaning that the use of the Master Deed process (and therefore having the Administrator sign on behalf of only one other counterparty, for example) would only serve to add an additional layer of administration and expense to a given deal. Finally, once Notices of Transfer have been sent, and Consents II-9.92 to Transfer received, the seller will issue all documentation to the UKCS Administrator to execute on behalf of all relevant Contracting   The form of the execution deed is detailed in the First Annex to Sch 2 of the Master Deed. There is also a short form version of the execution deed that is commonly used in connection with UKCS asset transfers and which incorporates by reference the standard wording set out in the First Annex to Sch 2 of the Master Deed. 72   That is, parties to the Master Deed. 73   See www.logic-oil.com/master-deed/online (accessed 1 May 2017). 71

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Parties. The seller will then receive and hold the originals, and the seller and the buyer can, with certainty, confirm their completion date, knowing that it cannot be delayed by a slow, or deliberately awkward, third party. II-9.93 The scale of the assets involved in acquisitions and disposals of upstream oil and gas interests and the scale of the potential liabilities mean that these are complex transactions. Accordingly, it is vital that the buyer and the seller and their respective professional advisors give due attention at an early stage to the preparation and structure of any sale or acquisition in order to minimise cost and delay at a later stage.

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CHAPTER II-10 FINANCE, SECURITY AND INSOLVENCYIN THE UPSTREAM OIL AND GAS SECTOR Jenny Allan and Sian Aitken

INTRODUCTION Upstream exploration and production (E&P) companies will II-10.01 ordinarily require access to a variety of sources of finance, and for different purposes, throughout their lifecycle. Numerous equity and debt finance options can be utilised by such companies, including some forms of financing which are quite specific to upstream E&P activities. However, financing options which are actually available to a specific company will be limited depending on the company’s own circumstances, with relevant factors being the status of the company (where the main considerations are its balance sheet and management experience) and the oil and gas assets it holds (their size, geographical location, technical quality, operator and/or development phase).1 At a basic level, where one or more sources of finance are available, and all other things being equal, a company will be looking to balance the basic cost of the financing against the level of control over the company sought by the finance providers.2 In this chapter, we will look firstly at the main purposes for II-10.02 which finance is sought by an upstream E&P company and a typical lifecycle of finance options for such companies from inception, followed by an examination of the key financing options available to upstream companies in more detail, as well as further detail of how finance providers take security for their investment. The primary   Other factors also relevant to potential lenders or equity providers are discussed at para II-10.07. 2   Including security required, and control over the company’s business – specifically its oil and gas assets and cash flows – discussed further at II-10.65. 1

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focus will be on financing options which are more unusual or specific to the UK upstream oil and gas industry, rather than finance options available to companies doing business in the UK generally. II-10.03 Additionally, as the recent low oil price environment has resulted in some high-profile insolvencies in the upstream oil and gas sector, we will also look at some of the specific legal and commercial issues faced by the oil and gas industry for upstream E&P companies nearing or actually entering insolvency proceedings. PURPOSE OF FINANCE II-10.04 Debt facilities or equity capital may be required by an upstream oil and gas company for one or all of the following purposes: • to acquire new assets by way of acquisition, farm-in or otherwise;3 • to pay exploration, development and operating costs (capex and opex), in particular to meet cash calls under JOAs or other field development agreements;4 • to meet the financial viability and financial capacity criteria required by the OGA for bidding in licensing rounds;5 • to pay decommissioning costs or otherwise provide decommissioning security (by way of cash, guarantee, bond or letter of credit);6 • provide payment or performance security to third parties, which may be required under field development or other contracts; and/or • for general cash flow purposes eg bridging finance to cover short-term capital gaps, until an alternative (longer-term) new source of financing can be procured. II-10.05 In particular, where a company is seeking investment for the purposes of financing development costs all the way to first oil (production) on a field, the costs involved can be considerable. Large investments are required, which may come from a variety of sources, which are examined in more detail hereafter. Lifecycle of finance options for oil and gas companies II-10.06 By way of brief demonstration, a “finance lifecycle” of an oil and gas E&P company may often involve the following stages. Each phase’s   For a discussion of key issues in acquisition and disposal of assets, see Chapter II-9.   See further the discussion in Chapter II-2. 5   See further the discussion in Chapter I-4. 6   Discussed in Chapter I-13. 3 4

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financing option may sometimes then be refinanced via the subsequent phase, with the overall cost of financing (and level of finance provider control) ideally reducing as phases are progressed, with the overall company portfolio and balance sheet increasing. A suggested mapping of lifecycle stage and potential finance source is shown in Table II-10.1. Table II-10.1  Lifecycle and Finance Source Stage

Finance sources

Start up/exploration asset(s):

Equity

Single field development:

Equity, with possibly project finance or small ReserveBased Lending (RBL) facility

One or a few producing fields

Small RBL facility, possibly with equity/mezzanine debt

More producing fields + Larger RBL facility, possibly permitted development assets with equity/mezzanine debt Large portfolio of producing Corporate (on balance sheet) development and exploration facility assets

FINANCING: RISK FACTORS It is relevant to consider some of the primary risk factors relevant II-10.07 to any party considering providing finance to an upstream E&P company, and some key mitigants that may be implemented or taken into account in their decision-making process, as outlined in Table II-10.2. Obviously, not every issue or mitigant may be relevant to every upstream E&P company seeking finance.7 Additionally, depending on the structure of a financing II-10.08 arrangement, where repayment is structured to resemble something approaching a royalty arrangement, including net profit interest (NPI), or a production-sharing arrangement, there may be potential exposure to decommissioning liability or ring fence corporation tax and supplementary charge. This is in addition to a possible requirement for such a financing to require OGA consent.

  There may also be other issues specific to that company that may also sway the ultimate investment decision, and the commercial terms that result.

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Table II-10.2  Risks and Mitigants Possible risks

Possible mitigants*

Liquidity risk

Cash reserves or strong sponsor support A mix of junior, mezzanine, senior and/or second-lien financing as part of the proposed structure may also help risk to be spread more appropriately An up-front equity covenant may now also be a requirement for new bank debt† Forward-looking group liquidity testing

Contractual/counterparty risk (general)

Legal diligence and financial diligence

Increased costs or development delays

Previous track record/experience of borrower and operator team

Poor performance of assets

Technical diligence (external or internal engineer reporting, or both)‡

Commodity prices or exposure to foreign currency movements

Commodity and foreign exchange hedging

Country risk (also referred to as “political risk”)

Spread and diversity of portfolio (primarily geographically, type of hydrocarbon asset, stage of development/ production and/or between operators)

Social and environmental risk

Company can demonstrate best practice environmental and social policies

Abandonment

Abandonment provisioning

Investment exit risk, syndication risk (where a loan facility requires to be syndicated), refinancing risk

General market liquidity for financing of well-structured finance deals or investment in the sector

  All mitigants may be applicable to one or more risks   Such a covenant may require a proportion of the financing required to come from an equity source and eg bank lenders will only agree to provide up to [X]% of the total amount of finance required for the overall development costs. ‡   More recently, at the time of writing for RBL facilities, multiple technical bank roles may be taken (historically for UKCS RBL financings, there would be one or, at most, two technical banks) so that a balance between different lenders and their respective technical views on market can be taken into account. * †

SOURCES OF FINANCE General equity and debt capital options II-10.09 The same sources of equity and debt finance available to companies in general in the UK are available to upstream E&P companies.

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Finance can be provided by specialist private equity funds, sovereign wealth funds or hedge funds, by way of subordinated or junior or mezzanine loans, second lien debt, loan notes or subscription for shares (ordinary or with preference rights attaching).8 Equity finance can also be raised by way of convertible bonds (bonds which are ultimately convertible to share capital), high-yield bonds or other specialist bonds eg on the Norwegian bond market. Bank lenders may also provide second lien, mezzanine or junior debt, the cost of which in either case will generally be higher (to reflect higher risk taken) than on any underlying senior debt eg a senior secured RBL facility. New equity capital can be generated by a company from various sources, but essentially will be effected by way of new investment from existing or new investors in the company. Equity finance is the key source of finance sought by “early stage” E&P companies, involved in exploration, appraisal and early development activities, and for whom debt finance is not yet an easily available option. They are also less likely to have significant (if any) internally generated capital or retained earnings that can potentially be applied to meet some of the costs involved in early stage E&P activity. Capital raising by way of public share issue is also an option for E&P companies, either by way of Main Market (LSE) or, much more commonly for suitable E&P companies since its introduction in 2004, by way of AIM listing in the UK market. Equity fundraising on international markets is also possible, although less common. Generally only larger E&P companies may consider issuing convertible or high-yield bonds as part of a capital raising exercise. Such bonds may be publicly listed, but more usually will be privately placed, with specialist private equity investors. In market terms, due largely to the recent sustained low oil price environment, public equity markets had moved away from upstream E&P investments within the UK. However, this is (at the time of writing) beginning to improve.9 Reduction in availability of sources of equity has also been reported to have resulted in an increase in net debt/leverage within upstream companies (of varying sizes) operating in the UKCS.10 Private equity remains a significant source of capital for the sector, such that private equity finance of some form. will now commonly

II-10.10

II-10.11

II-10.12

II-10.13

II-10.14

 A useful glossary of financial terms is available on the Financial Times website; see http://lexicon.ft.com (accessed 24 April 2017). 9   See further Oil & Gas UK’s “Business Outlook 2017”, available for download at http:// oilandgasuk.co.uk/businessoutlook.cfm (accessed 30 April 2017). 10   From a sample group of companies questioned – see further Oil & Gas UK’s “Economic Report 2016”, available for download at http://oilandgasuk.co.uk/economic-report-2016. cfm (accessed 30 April 2017). 8

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be put in place alongside a senior secured debt facility, such as an RBL, in order to provide the overall capital needed by an upstream company for a large development. Farm-out II-10.15 One of the primary methods of financing development of an asset for which the company has insufficient capital (and limited access to, or appetite for, procuring additional debt or equity capital) is to effect a farm-out, discussed in more detail at para II-9.81. However, this structure also involves the permanent disposal of a part of the company’s licence interest in the applicable field, and the consequent loss of eventual “upside” in that proportion of licence interest disposed of. Net profit interest or royalty II-10.16 NPI arrangements have become relatively uncommon at the time of writing. A transaction that is referred to as an NPI may also, on examination of its structure, in fact be a forward purchase or streaming arrangement. II-10.17 A true NPI arrangement ordinarily involves a licence holder disposing of some or all of its interest in a particular field to a third party (thereby disposing of related JOA liability which it may have been unable to finance). The third party receives the licence interest thereby transferred, and the original licence holder receives (in return) a right to regular future payments which are calculated by reference to the output from the field. This is distinguishable from a farm-in, where the “purchaser” receives a licence interest in return for taking on an element of development costs from the “seller”, rather than the seller also receiving an entitlement to ongoing receipts (potentially akin to a royalty) from the disposed interest. II-10.18 An NPI was more traditionally used for already-producing fields (and the purchasing third party is thereby not taking on any development risk). However, an NPI was also a possible option for a development asset, but would involve the purchaser of the interest to take on development risk (and cost), as well as granting the NPI. II-10.19 A royalty arrangement will ordinarily involve a party acquiring a right to receive revenue linked to production from a specific asset, with no liability for the ongoing costs. It can also (or instead) involve a physical right to a share of the oil and gas produced.

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Prepayment facilities A prepayment facility provides for a party (the offtaker) to advance II-10.20 an amount of cash to the borrower (typically structured as a loan), which will ordinarily then be used to pay for costs on a specific asset (ordinarily, but not exclusively, for producing assets). The loan facility will usually be “repaid” by reference to proceeds from production, which can also be effected by way of set-off against a set volume of oil and/or gas over time delivered to the facility provider (receiving such volumes in its capacity as offtaker). The facility may be structured to be repayable whether or not the field produces (in this case, no field risk is taken by the facility provider, and thereby facility is more akin to a “true” loan), or otherwise may only be repayable from proceeds of production (where field risk is taken by the facility provider). Prepayment facilities are often provided by the oil and gas “majors”, or commodity trading houses, both being parties who are keen to secure long-term offtake contracts and consequently will advance capital to upstream E&P companies at an early stage in the development cycle in order to do so. Prepayment facilities will ordinarily be secured, particularly if the facility provider is taking field risk. Streaming or forward purchase A streaming or forward purchase facility in the UK oil and gas II-10.21 sector11 is a quasi-equity investment and involves the applicable investor making an upfront payment to a company, and in return they will be entitled to receive a fixed portion of the future production of specific field assets, generally until such time as the relevant assets cease production. Streaming arrangements are still relatively uncommon in the II-10.22 UKCS, although they can be quick and simple to document and implement and can represent an easy and quick source of capital; the streaming investor will, however, likely want to perform diligence on the underlying assets prior to advancing funds. Commercially, the agreements themselves will normally be less restrictive on the company operationally than a traditional debt finance product, such as an RBL, which is considered further at para II-10.35. Where the facility relates to a UKCS licence, then depending on how the streaming facility is documented and structured, it may require OGA consent (under the terms of the applicable licence), which will often be sought anyway if there is any doubt.

  Different forms of streaming facility exist in eg the mining sector.

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Project finance II-10.23 Project finance is, at its basic level, a loan facility advanced to pay for development of an asset (project) by a special purpose vehicle, where the source of repayment for that facility (and effectively the security provided for it) will be the future cash flows arising from the project. True project finance is no longer available in upstream E&P financing in the UK, having been historically a method by which upstream development assets were more commonly financed, particularly in the early days of the UKCS. The key equivalent in the market now (developed out of project finance origins) is a reserve-based lending (RBL) facility, discussed in more detail at paras II-10.35 to II-10.36, although depending on the nature of the assets in the RBL facility, the underlying loan agreement itself may have significant “project finance” characteristics.12 II-10.24 A common feature of “ordinary” project finance worth mentioning is the use of direct agreements (or “step-in agreements”), which are agreements between a lender, a company and a third-party project contractor which regulate certain matters regarding the applicable underlying project contract. A key concept within such a direct agreement is usually the (optional) right for the lender to procure a “step-in” to the contract in certain circumstances, either itself, or through a separate entity, who will generally either be a representative of the lender, or a third-party purchaser of the asset. However, direct agreements are, to date, not something which contracting parties on UKCS development assets (primarily JOA counterparties) have been willing to provide to a lender of an upstream E&P company.13 This point has been a primary factor in preventing lenders to upstream E&P companies from having any chance of relying on the “project finance” exception (within Section 72E of the Insolvency Act 1986), which (if it had applied) would allow such lenders to appoint an administrative receiver on enforcement of applicable floating charge security.14 Export finance II-10.25 Export finance can be provided to UK companies through either direct financing or finance support (for example, by way of providing credit insurance, loan guarantees or overseas investment insurance).   For a highly recommended source of further information on project finance generally, see G D Vinter, Project Finance (4th edn, 2013). Commercially, the level of controls in the loan agreement will usually depend on the number of assets in the borrowing base, and how many out of that are producing already. 13   For an examination of the background to this situation, see ibid, para 19-006. 14   See (1870–71) LR 6 Ch App 462. 12

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Historically it has not commonly been used by UK-based E&P companies,15 and is more readily available to exporting goods and service companies; however it remains a useful finance option available for upstream service companies.16 Carry financing Carry financing is a method of financing a development (similar to II-10.26 farm-in) whereby the licence holder may agree to dispose of a share of a licence on condition that the incoming party (the “carrying party”) will fund (“carry”) the development costs applicable to both (1) the interest thereby acquired; and (2) the interest retained by the original licence holder (the “carried party”). This may be treated as a loan or equity for tax purposes depending on how it is structured. Sometimes the agreed terms will provide that the carrying party will be repaid out of the carried party’s receipts from production, following first oil on the asset. Once the carrying party has been repaid in full (including interest), then – subject to any other applicable agreements – production will be shared as normal thereafter, in accordance with each parties applicable share in the licence, and the applicable JOA. Carry financing is now very rare within the UKCS. Corporate debt facilities Corporate debt facilities, also “on balance sheet” debt, are usually II-10.27 sought by borrowers by way of an ordinary revolving credit facility. In practice, such facilities will be available only to oil and gas majors, some of the largest independent oil and gas companies, or national oil companies, ie companies with a large balance sheet capable of supporting such facilities at a corporate level.17 Debt facilities for such companies can be approved by banks II-10.28 based solely on the financial status of that company, as demonstrated

  Export finance was, however, recently discussed as a possible option for Premier Oil for the Sea Lion development project (Falklands): N Thomas, “Premier Oil reports progress on refinancing as 2016 result disappoints”, Financial Times, 9 March 2017, available at www.ft.com/content/bac23852-b203-3bd4-bb20-ddfb11e6b1e3 (accessed 10 September 2017). 16  For a recent example, see www.gov.uk/government/news/ukef-supports-ge-oil-gascontract-with-major-energy-project-in-ghana (accessed 30 April 2017) in respect of financing (including direct lending) provided to an Eni Vitol SPV in support of GE Oil and Gas, for the purposes of securing a contract on the Offshore Cape Three Points project in offshore Ghana (January 2017). 17   Such facilities may also be available to subsidiaries of such entities, potentially subject to credit support being offered by the parent company on whose balance sheet the lenders wish to rely for credit risk purposes. 15

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by its balance sheet or cash flow projections. In a default scenario, the banks can seek recovery by enforcing security and realising value from the borrower’s development or producing assets, however such facilities are ordinarily expected to be repaid from existing cash flows alone, and not specific assets or cash flows. For this reason, depending primarily on the financial strength of the borrower company, corporate debt facilities may be unsecured.18 Other options: vendor finance and “consortium financing” II-10.29 Recent financial pressures on some E&P companies, due largely to contraction in the availability of bank debt (to participants who would formally have had fairly easy access to it), or occasionally where companies are already heavily indebted with bank debt and are consequently unable to procure further loans for pending developments, have led to some more novel proposals from E&P companies (for the sector, if not generally) for the financing of development assets through to production. II-10.30 As options for consideration these have, in particular, included discussions of vendor finance (also referred to as “industry participant financing”)19 and “consortium financing”. II-10.31 Vendor finance involves a company seeking to agree finance terms (or quasi-finance terms) with some or all of the service companies who will be involved in the development of an oil and gas asset. Such companies (particularly where they have already won a works contract for the development, or are seeking to do so) will obviously have a strong interest in the development, and consequently their contract, proceeding. However, such structures may involve the service companies taking on an element of “development completion risk”, as the structure may involve a proposal for repayment of their “loan” to be triggered only when first oil occurs on that development. These arrangements, where structured as financing, are fairly novel in the upstream oil and gas sector but are becoming more widely discussed as a funding option for appropriate developments.   Not always – where security is required, it may be taken by way of floating charge only, or floating charge plus security over shares in certain group companies, or may include some or all of the typical security provided for an RBL, further details of which are at paras II-10.65 et seq. 19  A recent example of an E&P company seeking such financing terms is detailed in N Thomas, “Premier Oil seeks project funding from oilfield services groups”, Financial Times, 5 March 2017, available at www.ft.com/content/a3018a9e-0017-11e7-96f83700c5664d30 (accessed 30 April 2017), which also details an existing example of financing provided by Schlumberger to Sound Energy for capex on three appraisal wells in Morocco. 18

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With service companies under pressure from decreasing investment II-10.32 in the UKCS, a sustained lower oil price environment and consequent reductions in fees achieved in the market, the deferral of payment and/or bearing an element of completion risk on the project is potentially shifting some of the traditional risks borne by E&P companies onto their service providers. Vendor finance or related terms may however also be used to refer to a payment structure that is essentially just ordinary deferred payment terms, with interest for late payment (and with no general development completion risk). Additionally, any form of vendor financing for a field development can become difficult to structure and agree where only some JOA participants are actively interested in implementing it. “Consortium financing” is a proposal not yet known to have II-10.33 been implemented in the market, but which has been proposed as a possible new collective financing structure option recently.20 The proposal involves field partners in a JOA actively seeking collective financing terms (ie based on their combined interests and, as far as possible, on their combined balance sheet  strength) for the development of the asset to which the JOA relates, on the basis that it is potentially more likely that investors and lenders in the market may then be more interested in lending funds to the “consortium” for purposes of that development. However, the combined strength and joint interests of the II-10.34 “collective” of JOA parties in such financing would need to be balanced by any investor against (among other risks from exposure to such additional parties) the increased exposure to the applicable asset. Whether or not the proposed financing involved recourse to other assets of the participants is not clear, as is whether proposed participants would be happy to put any of their assets at risk on behalf of their JOA partners. RBL facilities Currently, as touched on previously in this chapter, the primary form II-10.35 of debt financing for small and medium-sized E&P companies for UKCS upstream oil & gas developments remains an RBL facility, also referred to as a “borrowing base” facility.21 An RBL is a specialised

  As discussed in “A Sea Change: the future of the North Sea Oil & Gas”, report issued by PWC, available at www.pwc.co.uk/industries/oil-gas/insights/the-future-of-the-northsea.html#whatcanbedone (accessed 30 April 2017). 21   For further reading on RBL’s history and structure generally, see N Ross-McCall and H Thomas, “Reserve-Based Lending”, in H Thomas and A Skinner (eds), Energy and Resources Financing (2015), and N Ross-McCall, “Upstream Financing”, in T Daintith, G Willoughby and A Hill, United Kingdom Oil and Gas Law (3rd edn, looseleaf, 2000–date). 20

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form of asset-based finance, unique in the oil and gas sector, and is structured most often as a revolving credit loan facility. In general terms, a revolving credit facility provides for amounts to be drawn under the facility that can then be repaid from cash flows, and then redrawn again, on a rolling basis and subject to a cap of the available facility.22 The facility provided may typically also include ancillary facilities required for such operations of companies, including bonding and letter of credit facilities, which can in particular be required for meeting either contractual credit support obligations or decommissioning security agreement obligations.23 II-10.36 The size of the facility available to the borrower will vary over the term, by reference to changes in the value of the borrower’s oil and gas reserves, as discussed in more detail at paras II-10.54 to II-10.60. In this context, as well as for general corporate debt facilities, a “borrower” may mean the whole of a borrower’s corporate group, some or all of whom may be borrowers (entitled to draw loans) or guarantors (whether or not also borrowers) under the facility terms. Syndication II-10.37 RBL facilities (as well as corporate debt facilities) will usually be provided by a syndicate (group) of banks, through a single facility agreement, where each bank contributes part of the overall capital, thus making up a larger loan amount than a single bank could itself advance.24 The entities within the syndicate are likely to change over time, as some exit (usually through sale of their loan on the secondary market to another existing or new member of the syndicate) or enter the syndicate (by accession to the finance documents). Exit and entry of syndicate members can often take place at the point of amendment to or increase of the underlying facilities, where eg some current lenders to the company may not wish to (or, for bank strategy reasons, be able to) approve the changes required, and they then have to exit as a result – allowing new incoming lenders to take their place. II-10.38 Certain banks in the syndicate will take specific “roles” in the financing, most commonly being mandated lead arrangers/lead arrangers, agent, account bank, security trustee, technical bank and,  The available facility under an RBL is linked to the borrowing base mechanism, described further at para II-10.54. 23   For further discussion of decommissioning security requirements, see Chapter I-13. 24   The syndicate may be put in place at initial closing of the financing, and will usually be coordinated by one or more “mandated lead arranger” banks, or through “sell down” post financial close. Re syndicated lending generally, and the roles of lenders in the syndicate, see further A Malek and J Odgers (eds), Paget’s Law of Banking (14th edn, 2014), Chapter 12 (Syndicated Lending) and A Mugasha, The Law of Multi-Bank Financing (2007), paras 1.31 to 1.34. 22

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less commonly, modelling bank. There will often be more than one bank in each role, other than security trustee which will be a single lender who holds security on trust for the other relevant finance parties. Smaller loan facilities may be provided by a single bank on a II-10.39 ”bilateral” basis, but this is less common given the size of loan facility typically required by an E&P company. The finance documents Loan Agreement. This is the key document in both RBL and any other general corporate loan facility and is typically the agreement on which there will be most negotiation between the borrower and its lenders. The agreement itself will generally be based on a specially adapted Loan Market Association (LMA) form of facility agreement.25 The loan agreement will often also include the standard LMA guarantee clauses, such that cross guarantees will be given from each relevant group company in the borrower’s corporate group in respect of the underlying obligations of the borrower to the parties providing finance. In the case of an RBL facility, all group companies that hold, either directly or indirectly, “borrowing base” assets will generally be required to be guarantors, if not borrowers, in the loan agreement. The upside of using LMA documentation is the inclusion of key market-recognised terms, in particular in relation to mechanical provisions around interest calculation, tax gross up and the roles and responsibilities of various parties in a syndicated loan. Additionally, lenders considering coming into the syndicate will generally be more easily able to recognise and review a loan agreement based on an LMA form. The negotiation and documentation process will usually be led (on the bank side) by the key lenders arranging the facility, commonly called the mandated lead arrangers (MLAs). Once agreed between the company and the MLA, the loan agreement can be circulated to other lenders wishing to participate in the facility. Key provisions from the borrower’s perspective in the negotiations on the loan agreement (aside from the usual commercial factors such as facility size and pricing) include certainty of availability of funds and the level of controls applicable to its business and assets. Controls are particularly relevant regarding matters where the company will need consent from a proportion of or all of the lenders

II-10.40

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 For more information on LMA documentation, or copies of the current form LMA facility agreements and other documents (including their “Users Guide to Form of Facility Agreement for Leveraged Acquisition Finance Transactions”), see www.lma.eu.com (accessed 30 April 2017).

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from time to time, and the mechanics of obtaining consents and waivers will be carefully considered, including provisions governing where some of its lenders do not wish to consent. Contractual controls within the loan agreement over field assets and contracts will generally be restricted (“ringfenced”) to field interests which are within the “borrowing base”, allowing a greater degree of freedom as regards dealings relating to field interests that are not within the borrowing base. However, overarching liquidity testing, to avoid a company potentially over-extending itself in terms of expenditure across its asset base, and the resulting cash flow difficulties that would involve, is generally always incorporated now – particularly following various recent high profile insolvencies of UK-based E&P companies. As noted at II-10.23, certain RBL facilities may have strong “project finance” characteristics, and the strength and nature of bank controls can vary widely from facility to facility. Overall this makes RBL a very flexible product suitable for use with a wide variety of companies and field assets, and the market is constantly evolving.26 It is also noted that similar company business and asset “controls” as seen in RBL facilities will also appear (or may be requested, even if ultimately negotiated down or out completely) in many of the other available forms of financing for E&P companies. Intercreditor agreement. This is the agreement between creditors as to ranking of debt/claims (pre and post insolvency event) and security, which will also govern actions that can be taken by the different classes of creditor relative to their respective claims and finance/security documents. The terms of this agreement can vary widely depending on the nature of the other creditors and what can be agreed in terms of permitted payments and ranking with the senior lenders. The agreement will likely also cover subordination of intra-group loans, and any other creditors who have agreed to some subordination of their claims, debt and/or security with the senior lenders, and possibly also with other mezzanine or equity type lenders providing finance to the borrower. The intercreditor agreement will usually involve complex provisions regulating the relationship between multiple finance providers, and so a significant degree of negotiation may be involved between multiple parties. For these reasons, parties will ordinarily seek to agree key outline terms   See “RBL: reserve judgement”, 8 (2015) JIBFL 518 and N Ross-McCall, “Reserve-based lending facilities comparative study – debt and alive”, available at www.cms-lawnow. com/ealerts/2016/08/reservebased-lending-facilities-comparative-study--debt-and-alive (accessed 2 May 2017) for further details of recent trends and developments in key RBL terms.

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for an intercreditor agreement as early as possible (and before the agreement is drafted). An intercreditor agreement will not ordinarily require to be registered in the UK separately from any security it ranks. A notable exception occurs where an intercreditor agreement contains ranking provisions that regulate the ranking of a floating charge or charges created by a Scottish company. Such agreements are generally considered to be registrable under Section 466 of the Companies Act 1985 as an “instrument of alteration” of the affected floating charges. Account bank agreement. As for “ordinary” project financing, an account bank agreement may be involved in order to detail accounts that will be opened and maintained, which bank will hold the accounts, how they will be operated, who can instruct withdrawals – generally providing that they will be operated in accordance with the loan document. Security documents. The typical suite of security documents for RBL financing, many of which may also be relevant to any other form of financing in which the finance provider requires security for its investment, are discussed in more detail at paras II-10.65 to II-10.68. Fee letters. Separate fee letters are used to document fees payable to individual RBL lenders in respect of their respective roles in the RBL financing (documenting these separately with the borrower keeps their respective fees confidential, as far as is possible, vis-à-vis the other RBL syndicate lenders). Hedging or other ancillary documents. Hedging may often be a requirement of the RBL facility (for commodity price exposure) and can be used to increase the value of the borrowing base (and consequently the loan facility) available to the company. One or more of the lenders providing RBL facilities27 may also provide additional facilities to a borrower, as may be permitted by the loan documentation, in particular including treasury services (for example, foreign exchange and commodities price hedging, and deposits). Providers of hedging may also benefit from a share in the security for the RBL facility, although ranking of payments and claims on insolvency may vary, as well as voting rights in respect of their hedging exposure. The issue of voting rights is more relevant to true thirdparty non-lenders (providing only hedging and not participating in

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  Occasionally, hedging will be procured with an external provider who is not in the RBL syndicate, if permitted by the RBL loan documents. An apparent recent reduction (at time of writing) in the number of traditional RBL lenders able to offer commodity hedging as part of an RBL financing has resulted in a more limited pool available to companies looking for hedging services.

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the debt provided to the company), who have no consequent voting rights on any consent issues under the loan agreement, and may seek them through negotiation under the intercreditor agreement instead. The “borrowing base” mechanism and financial covenants II-10.54 Under the terms of the loan agreement, the value of the company’s oil and gas reserves within the “borrowing base” is essentially recalculated at regular intervals by the lenders, ordinarily every six months, with additional recalculations possible on the occurrence of certain trigger events (including acquisitions or disposals of upstream oil and gas assets into the proposed borrowing base portfolio held by the borrower, or the unwinding of any hedging which was supporting the previous borrowing base valuation). The “borrowing base assets” will not generally include the entirety of a company’s field interests, as some assets will be intentionally excluded (which allows the possibility of financing such assets elsewhere, and typically includes all exploration and some development assets). II-10.55 Contractual controls exerted over the company’s assets within the finance documents will generally extend over borrowing base assets only, such that the company can (subject to the ongoing overall liquidity testing of the group) deal with all “non borrowing base assets”, and any proceeds derived therefrom, more freely. II-10.56 The recalculation (“redetermination”) of the net present value of the borrower’s reserves is done by reference to agreed cover ratios, and based on economic and technical assumptions28. These redeterminations will normally be calculated by the lender or lenders in the Technical Bank role,29 and subsequently approved by the requisite majority of other lenders as may be required by the terms of the agreed loan agreement. II-10.57 The ongoing debt availability (up to the cap of the maximum available facility at the time) is usually calculated using the latest redetermination, by reference to the lower of two methods of valuing the borrowing base assets, being (at a basic level, and as the same may be limited by the “Reserve Tail” date, discussed further below): • Loan Life Cover ratio (LLCR): the net present value used in calculation of this ratio includes cash flows from the borrowing base assets over the whole of the RBL’s term; and

 Assumptions will generally be set set on day 1, although they may be updated from time to time in accordance with the terms of the RBL loan agreement, in particular re the agreed oil and gas “price deck” (long-term commodity price assumptions), which may be the subject of significant debate between individual lenders and the borrower. 29   See para II-10.37 re lender roles. 28

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f i na nc e , se c ur i t y an d i n s o lve n cy 347 • Project/Field Life Cover ratio (PLCR/FLCR): in the calculation of this ratio, the net present value used is for the full life of each borrowing base asset’s cash flows, including any abandonment (and decommissioning) costs.

The “Reserve Tail” date is an additional measure built into an RBL II-10.58 facility, included for additional protection by the lenders against exposure to borrowing base assets that are nearing the end of their economic lifespan. This is a point at which cashflows from such assets are reducing, but provisioning for abandonment and environmental liabilities are potentially increasing. The reserve tail mechanism is intended to ensure that the loan should always be repaid at a point at which at least a certain percentage (usually 25 per cent) of the oil and/or gas reserves are still available from producing assets. It is essentially a cut-off date (set in advance of the actual anticipated cessation of production) for the assets included in the “borrowing base”, on which the RBL is sized, such that each asset in the RBL borrowing base will be included for a period that is shorter than its actual anticipated lifespan. This mechanism will also help at the outset to determine the proposed available term of the facility.30 The net present value of the cashflows from the borrowing base assets will be calculated by the lenders by application of a suitable discount rate (typically 8–10 per cent). Technical assumptions on which the borrower base size is deter- II-10.59 mined will be decided with the applicable “technical banks” in the RBL. Production profiles for a borrower’s assets (based on approved reserves reports and technical bank input) will be agreed with the technical banks and inputted, along with multiple other assumptions and data, into the financial model that ultimately underpins the size and structure of the final RBL facility. All UK-led RBLs will now also include as standard a (forward- II-10.60 looking) group wide liquidity test and related covenant, in order for lenders to have visibility on the future cashflow and liquidity position for the wider borrower group. This test started to be incorporated as standard following various high-profile insolvencies, some of which arose from overexposure to significant expenditure on non-borrowing base assets. Repayment Mandatory prepayment can be triggered by RBL borrowing base II-10.61 recalculation discussed above (where the facility is resized under a  The typical term of an international RBL facility in the UK market will generally be between five and seven years, occasionally shorter, although it will often be refinanced prior to the end of the term.

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recalculation and the outcome is lower than the debt then drawn). Otherwise the facility will ordinarily also include a scheduled amortisation profile, to ensure regular reduction of the original maximum facility amount, and be repayable in full on expiry of the term, if not already refinanced by then (which is common). II-10.62 The amortisation profile will usually be sculpted by the lenders to reflect when the company is projected to be receiving (by then) sufficient income from production to allow that reduction in facility size, without adversely affecting its liquidity. II-10.63 Other more usual commercial lending triggers can result in (additional) mandatory prepayments being required (in part or in full, depending on the circumstances), including a change of control of the borrower. A “cash sweep” (amounts of excess net cash flow must be applied at regular intervals in early prepayment of facilities) may also be included, if required by the lenders. Account controls II-10.64 The lenders will usually require a suite of project accounts, and will oblige the company to pass all revenues from assets (either all assets of just borrowing base assets) through such accounts. “Cash waterfall” provisions will usually be applied to the revenue holding accounts at regular intervals (such that cash will only be released from those accounts in accordance with a set order of payment/ transfers required by lenders). Again, there can be wide variation in the level of control required over the accounts between facilities, depending largely (as for other lender controls that frequently vary between RBL facilities) on the number of assets in the borrowing base, and how many of those are already producing.31 SECURITY II-10.65 Providers of finance (by way of RBL, equity or otherwise) to oil and gas E&P companies often seek to take security (or other credit support) for repayment of the loan in a variety of ways, which may include some or all of the following: • a guarantee from a sponsor entity, or cross guarantees from all subsidiaries of the main borrower entity;32

 Accounts over which the lenders exercise full control will generally be blocked and subject to fixed charge security – see para II-10.82. 32   Not a security interest of itself, but included as a form of credit support. A guarantee may be documented within a loan agreement (if any), or separately, and will ordinarily have the same governing law as the main financing agreement. 31

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f i na nc e , se c ur i t y an d i n s o lve n cy 349 • floating charges (which may be governed by English33 and/or Scots law) from all borrower and guarantor entities; • English law debenture (which will generally contain fixed charges, floating charges and/or assignments in security of multiple assets);34 and/or • English law share charge (or Scots law shares “pledge”)35 over the entire issued share capital in some or all borrower and guarantor entities.

Various factors affect what security will be taken, including what II-10.66 assets are available for securing, the nature of the facilities provided and the credit status of the company/company group. As noted above, a light touch corporate loan facility, for example, II-10.67 may be secured by either a group cross guarantee and/or floating charges alone, with no specific fixed asset security taken. In the case of a major company, no security may be required at all, as the lenders will rely on the balance sheet strength of the borrower (or its group) alone. Where security is required, what security documents which will be II-10.68 put in place will reflect what assets the lenders require to be secured, and the governing law applicable to such assets. All security granted by a company registered in the UK, which is within the classes of charge to which Section 859A of the Companies Act 2006 applies, should be registered with the registrar of companies at the appropriate Companies House.36 Such registration is usually required to be submitted within 21 days of “creation”37 of the charge.   “English law” as referred to in this part of the chapter applies throughout England and Wales; for drafting brevity “England” and “English” are used here to refer to the jurisdiction of England and Wales/English and Welsh matters. 34  What is here referred to as a “debenture” may also in practice be referred to as a “security agreement”, a “fixed and floating security agreement”, a “deed of charge and assignment” or another name. It is a composite security document under English law typically containing fixed charges, legal or equitable assignments in security and a floating charge – it can also contain legal mortgage over real estate assets under English law, although it would be unusual for upstream oil and gas companies to have such assets. 35   See further at para II-10.88 re Scots law on security over shares. 36  Companies House, Cardiff for companies and limited liability partnerships (LLPs) registered in England and Wales, and Companies House, Edinburgh for companies and LLPs registered in Scotland. Security requirements for entities registered outwith the UK, or that are not otherwise companies or LLPs for UK law purposes, are outwith the scope of this chapter. In the case of overseas companies, or security over any overseas assets, local jurisdictional legal advice will be sought by the finance provider before taking, perfecting or registering such security. 37   Section 859A(4): “‘The period allowed for delivery’ is 21 days beginning with the day after the date of creation of the charge (see Section 859E), unless an order allowing an extended period is made under Section 859F(3).” Registration is not compulsory, however failure to register a charge will result in such charge becoming void against a liquidator, 33

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II-10.69 Some of the key forms of security taken in upstream E&P finance arrangements will now be examined in more detail. In general: • a security interest under English law may be taken by way of floating charge, fixed charge or mortgage (and “mortgage” here includes an assignment in security of a licence interest or contractual rights, or an legal or equitable mortgage of shares).38 As noted above, the typical English law security package may include a debenture (fixed and floating security agreement) containing, as well as fixed charges and assignments, an English law governed floating charge;39 • a floating charge can also be granted over Scottish assets or by Scottish registered companies.40 There is no legal equivalent to a “fixed charge” under Scots law and the form of security appropriate under Scots law depends on the asset to be secured.41 Security over licences II-10.70 Any security interest (including a floating charge) which affects (purports to secure) a UKCS licence interest is generally prohibited by the model clauses, unless specific government consent is sought. However, since its original iteration in 2004, the Open Permission administrator and any creditor of the company, as well as the amount secured thereby falling immediately due and payable (Section 859H, Companies Act 2006), although the courts may extend the period for delivery on various grounds (Section 859D, Companies Act 2006). 38   Pledge and lien are also possible forms of security under English law, but are outwith the scope of this chapter, as they are not generally used as a form of English law security over upstream assets. 39  A floating charge governed by English law has been held to be a valid security (according to English law) over Scottish assets, as well as English and Welsh assets – see Re The Anchor Line (Henderson Brothers) Limited (No 2) [1937] Ch 483, however this is understood to be subject to certain conditions, and commercial practice has evolved for lenders to commonly take both English and Scottish floating charges as a “belt and braces” approach, even if potentially not technically necessary. 40  Scottish companies can create floating charges pursuant to the Companies (Floating Charges) (Scotland) Act 1961, unlike English law where the concept developed as part of the law of equity. Key differences exist between English and Scottish floating charges, the main one being that a Scots law floating charge cannot generally be crystallised into a fixed charge other than by statutory process (ie appointment of an administrator), unlike English law which allows automatic crystallisation into fixed charge at an earlier stage (if agreed contractually). It is not considered strictly necessary for an English company to grant a Scots law floating charge as well as the usual English floating charge/debenture, although it is often done in practice where the company has assets in Scottish waters. 41  For a useful summary of the key differences between taking security under English and Scots law, as well as other comparative considerations between English and Scots law relevant to finance transactions generally, see J Hardman, “Demystifying Scots law: Scottish aspects of debt finance transactions”, 1 (2016) JIBFL 38.

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(Creation of Security Rights over Licences)42 permits the charging of a licence interest by way of a security, in certain circumstances and only in relation to specific forms of security. One of the conditions of this Open Permission is that notice of any security interest so granted thereunder shall be provided to the OGA within 10 days of grant of such security, details in such notice to include: • size of the loan secured; • licences affected; and • identity of the secured party. The Open Permission excludes the grant of any security interest II-10.71 where “under the terms of the security or by operation of law, the licensee’s interest in the licence is assigned on entering into that security”. This is further clarified (pursuant to a footnote in the Open Permission) that it applies, “inter alia, to forms of security governed by the law of Scotland which contain an assignation in security”. An assignation in security is a form of security over incorporeal moveables under Scots law, that in order to be constituted as a security interest requires actual transfer (assignation) of the rights under the licence to the applicable secured party, and is therefore excluded from the scope of the Open Permission. Under English law, a fixed charge can be taken over the licence II-10.72 rights without an actual transfer (assignment) of the grantor’s licence rights being required, and a provider of finance will in some case seek to take such fixed charges over licence interests under the terms of the Open Permission (usually included in an overall debenture/ security agreement containing multiple security clauses). As noted above, there is currently no equivalent under Scots law II-10.73 to an English fixed charge and consequently there is considered to be no safe method (other than floating charge) that complies with the terms of the Open Permission by which security can be taken over UKCS licences in Scottish waters. Therefore, in practice, the form of security interest which is generally taken over UKCS licences based in Scottish waters will usually be a floating charge, and the form of security interest taken over UKCS licences based in English waters may be either a floating charge or a fixed charge. Whether a fixed charge is required over English licences will be a matter for commercial agreement. Even if the finance provider only takes a floating charge, the underlying finance documents may also restrict disposal of any licence interest without express consent, so that the licences (or certain licences related to the financing, eg borrowing

  Granted pursuant to Petroleum Act powers, on 6 February 2012, by Secretary of State (replacing the original open permission granted in 2004).

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base asset licences in the case of an RBL facility) cannot freely be disposed of in the ordinary course of business anyway. II-10.74 On enforcement of any security over a UKCS licence originally granted under the Open Permission (or otherwise consented to by the OGA), consent of the OGA will still be required to the enforcement action over the licence proposed, and this and other points on enforcement of such security are considered in more detail at paras II-10.93 to II-10.122. II-10.75 Any security which does not fall within the terms of the Open Permission will be subject to the advance consent of the OGA, or otherwise the grant of such security will constitute a breach of the terms of such licence.43 Security over rights under contracts and insurances II-10.76 A provider of finance may also seek fixed (or floating) security over contractual rights under certain contracts, key ones being: • JOAs/operating agreements/similar upstream oil and gas contracts; • offtake agreements (if any); • hedging agreements; • insurances; • intercompany loan agreements (or other subordinated/ investment agreements); and/or • specific other agreements (eg acquisition agreement). II-10.77 Security over contractual rights may be taken by way of fixed charge or mortgage (assignment) under English law, or by assignation in security if such rights are governed by Scots law. Notice to the applicable counterparty may be required to be given (and acknowledgment requested) following grant of the security, largely depending on the form of security sought. Alternatively, a provider of finance may take a floating charge and rely on that alone as regards security over all contractual rights and/or insurances. II-10.78 For RBL facilities, although requirements will always vary due to the variety of borrowers and assets, it is at the time of writing relatively common in the market for lenders to require fixed charges or assignments of rights under insurances, intercompany loan agreements and any hedging agreements entered into. II-10.79 It is less common for RBL lenders to require specific (or even generic) fixed charges or assignments of rights under project

  See eg cl 40(1) (Restrictions on Assignment) of the Petroleum Licensing (Production) (Seaward Areas) Regulations 2008.

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contracts, such as JOAs. This is at least partly because there may be consent requirements under such contracts, which mean a charge or assignment may not be effective in the absence of express consent.44 Occasionally, the issue of consent will be dealt by the inclusion in the applicable security document of a version of the “excluded assets” concept. Such drafting can potentially help to reserve the position regarding any project contracts or other agreements to which the company is a party, which contain restrictions on the grant of fixed or floating security, but which the secured party has attempted to take security over anyway. The concept may be drafted such that those assets are either excluded from any or all of the security documents assignment, fixed charge or floating charge provisions, in order to avoid triggering a breach of the underlying contract terms. An alternative approach (less common at the time of writing) II-10.80 for security over field project contracts (including JOAs) is to provisionally allow exclusion, but only where (1) the borrower has undertaken to seek consent from the applicable counterparties for the attempted charged or assignment and (2) within a certain time period, the borrower has failed to get such consent. This may positively require the borrower to demonstrate they are actively seeking such consents, from potentially multiple counterparties, after the closing of the financing.45 Other assets which may form part of the “excluded assets” concept may, for example, include assets held by the company solely in its capacity as operator of the underlying field.46 Insurance proceeds (under a variety of possible policies) are likely II-10.81 to be a significant asset of an upstream E&P company. As noted above, in a typical RBL financing, the borrower will be required to assign in security all (non-third party) relevant insurance policies which it holds as part of the security package offered for a financing. Depending on the level of control sought by the applicable lenders, the borrower may be able to agree de minimis levels below which they can receive insurance proceeds and apply them freely without having to always pass them through blocked bank accounts, and/or apply them in mandatory prepayment.   Newer forms of JOA will generally allow an assignment in security, even if such security is not regularly taken by secured lenders. It will tend to be explicit in JOA permission to assign in security clause that any security created is expressly subordinated to the rights of the JOA counterparties. 45   For further reading on the development of the “excluded assets” concept in leveraged finance transactions in general, see A C Ingerslev and N Benham, “All-asset security on leveraged financings: the scope of ‘excluded assets’”, JIBFL (Dec 2016) 635. 46  Ordinarily, as such assets will not be held by an operator in its own capacity but as agent for each of the applicable JOA parties pursuant to the Operating Agreement, arguably such a provision is unnecessary – see further the discussion at para II-2.37. 44

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Security over accounts II-10.82 Where fixed security over bank accounts is to be included as part of the security package, those accounts will generally be opened in England.47 Some or all of a borrower’s accounts are likely to be subject to contractual controls and restrictions contained within the underlying finance documents, including the security documents, loan agreement and account bank agreement (if any). II-10.83 To constitute a valid fixed charge, an account will be required by the party providing finance to be “blocked”, ie any withdrawals will be under their control at all times, in order to avoid falling foul of the requirement to have sufficient “control” over the assets subject to fixed charges and to avoid any risk of such charge (on enforcement) being interpreted instead as floating.48 In practice, this test is unlikely to be met for typical RBL proceeds or collection accounts (where the lenders may typically allow the company to operate the accounts to some degree) and so security over them is likely to be interpreted as floating. II-10.84 A separate account bank agreement may also often be required, with the bank providing account bank services for the purposes of the loan facility. This agreement will contain largely administrative provisions regarding the management of the accounts by the account bank, with the account “controls” from the company’s perspective generally being documented in the main loan agreement (or, where multiple creditor groups require to be involved in “cash waterfall” provisions, potentially in the intercreditor agreement). Security over shares English registered private limited company II-10.85 Security over shares in a limited company under English law can be taken either by way of fixed charge or mortgage. Both equitable and legal mortgages are possible, although a legal mortgage is very  In practice, bank accounts which are to be subject to a fixed security interest will generally be established with a bank branch in England, rather than Scotland, even if the borrower group is based in Scotland. This is due to practical legal difficulties with taking effective “fixed security” (or its nearest legal equivalent) over bank accounts which are established in Scotland and consequently ordinarily considered to be governed by Scots law. 48  The key question in determining whether a charge is fixed or floating is not the intention of the parties but the nature and sufficiency of “control” the secured party has over the charged assets. See Ashborder BV v Green Gas Power Ltd [2004] EWHC 1517 (Ch), where “fixed charge assets” could be freely disposed of in the ordinary course of business (without secured party consent) such that the charge was held to be a floating charge and not fixed. See also National Westminster Bank plc v Spectrum Plus Ltd and ors [2005] UKHL 41. 47

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uncommon in practice, due to the requirement from the outset to transfer the shares into the name of the secured party.49 In most circumstances, the companies involved in E&P activities II-10.86 requiring to grant share security will be private limited companies, having certificated shares. Methods of taking security over other forms of UK company shares (including CREST) are therefore outwith the scope of this chapter. Typically, the document taking security over shares in an English II-10.87 E&P company will be expressed as a “charge”, although the terms of the charge document may require delivery of executed but undated stock transfer forms and the original share certificate(s), and will contain provisions around completion of transfer of the shares should the lender require it (pre or post enforcement of the security). The form of security is therefore more akin to an equitable mortgage of shares (even if called a charge in name), rather than just a fixed charge on the shares (as it involves provisions anticipating transfer of the asset into security). Scottish registered company Shares in a Scottish registered company are technically “incorporeal II-10.88 moveable” property under Scots law,50 and taking security over such shares will be done by way of a “pledge”51 of those shares in favour of the secured party, which requires (in order to be properly constituted) the actual transfer of the shares into the name of the secured party (or their nominee). This involves the full execution of stock transfer forms, and the writing up of the register of members of the company to reflect that transfer of shares into security. It is not possible to take fixed security over shares under Scots law without effecting this transfer, and consequently some lenders can be reluctant to perfect such security, due to concerns over potential tax degrouping and environmental or decommissioning liabilities.52  Security by way of pledge or lien under English law is also technically possible, but commercially unlikely and so not covered in this text. 50   W Gordon, “Donation”, Stair Memorial Encyclopaedia (Reissue, 2011) at 7 (Delivery) and para 36 (Incorporeal moveables). 51   In practice, the applicable security is technically an assignation in security (rather than a pledge), although is almost universally referred to in practice and drafting as a shares “pledge”. The security document itself may refer to the shares being “pledged” and/or “assigned”. The law regarding security over incorporeal moveable property is under review in Scotland generally at the time of writing – see further at note 53; also Scottish Law Commission’s Discussion Paper on Moveable Transactions (DP 151) (June 2011) at 4.9 and 5.13, and Farstad Supply A/S v Enviroco Ltd [2011] UKSC 16. 52  The requirement to transfer shares into the name of the lender has been the source of some debate within Scotland, ongoing at the time of writing. Since the introduction via the Small Business, Enterprise and Employment Act 2015 of a new Part 21A to the Companies Act 2006, requiring UK companies and LLPs to hold and maintain a register 49

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Security over real estate II-10.89 Occasionally, an upstream oil and gas company may have onshore real estate assets (for example, property in the form of the company’s offices), which may be suitable for forming part of the security assets, either by way of mortgage or charge (in England) or standard security (in Scotland). This is commercially unusual, however, and is therefore not covered in detail in this chapter.53 Financial collateral arrangements II-10.90 Also worthy of mention in this context are the Financial Collateral Arrangements (FCA) Regulations,54 which are potentially relevant to any security granted by an upstream E&P company,55 although not commonly relied on in practice. The FCA Regulations were introduced in 2003 in order to attempt to harmonise across the EU a framework for taking financial collateral, with the intention of making it simpler to implement and enforce. A security interest which qualifies under the regulations does not need to be notified or registered anywhere (eg at Companies House), and further provides certain rights to the holders of qualifying “security financial collateral arrangements” to appropriate the applicable security asset without resorting to court order or other additional enforcement process.56

of people with “significant control” (referred to generally as the PSC Register), there has been uncertainty as to whether a party holding Scottish company shares in security would be considered a PSC for the purposes of the regime. Such information also requires to be filed with the applicable Companies House. Additionally in Scotland, the laws governing security over incorporeal moveables (including shares) is currently under review, having been acknowledged as “considered to be outmoded and not fit for the requirements of modern commerce”; see Scottish Law Commission, “Ninth Programme of Law Reform”, Report no 242, Discussion Paper on Moveable Transactions (DP 151) (June 2011). Responses to the discussion paper were processed and a draft Bill was published by the commission in July 2017. 53  For further information regarding security over real estate generally, see Law of Property Act 1925 ss 52(1), 205(1)(ii), (ix) and Lord Mackay of Clashfern (General Editor), Halsbury’s Laws of England (4th edn, 2003 reissue), at 483 (Legal mortgages), for property in England and Wales, and Conveyancing and Feudal Reform (Scotland) Act 1970 (1970 c 35) Part II (the Standard Security), for property in Scotland. 54   Financial Collateral Arrangements (No 2) Regulations 2003 (SI 2003/3226). 55  For further background on the legislative development of the regulations, and their implementation, see PLC Finance, “Financial Collateral Arrangements” available at https://uk.practicallaw.thomsonreuters.com/8-212-1954?__lrTS=2017043015195509 3&transitionType=Default&contextData=(sc.Default)&firstPage=true (accessed 8 May 2017). 56  In addition, certain insolvency law provisions are disapplied in relation to assets subject to a security financial collateral arrangement, in particular regarding the ordinary order of payment of creditors, and the potential for avoidance of the security financial collateral arrangement by a liquidator or administrator is more limited – Regulation 8, FCA Regulations.

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Certain types of security interest (including floating charge)57 II-10.91 granted by E&P companies may qualify as security financial collateral arrangements under the FCA Regulations, and additional provisions may be included within the security documents to refer to the FCA Regulations in order to regulate how assets that may be subject to them will be dealt with on enforcement.



Assets in other jurisdictions For companies established in other jurisdictions where security is II-10.92 required, local advisors will be engaged to advise on the appropriate form of security and any perfection requirements. INSOLVENCY AND RESTRUCTURING As has been discussed at various points within this book, the II-10.93 worldwide oil and gas market has been under considerable pressure since mid-2014, with sub-US$100 crude oil prices since that date and prices having plateaued at approximately US$40–60 since mid-2015. However, despite this turmoil, there have been relatively few formal insolvencies of UKCS-focused E&P companies over this period. Whilst to some extent this may be due to such companies having sufficient financial reserves and taking significant steps to cut costs, it is no doubt also because there are certain aspects of insolvency regulation and process which do not sit particularly well within the regulatory framework governing E&P companies. Following the global banking crisis of 2007–8, during which time II-10.94 a number of financial institutions failed or had to be rescued by Government, it was recognised that the standard insolvency regimes applicable to corporate entities was unsuitable when applied to banks and building societies. For this reason, a specialist regime was introduced with a view to stabilising the position pre-insolvency and dealing with bank customers timeously, within the regulatory framework governing such financial institutions. There are other examples of specialist insolvency regimes (for example in relation to railways and energy providers) but to date, at least, there is no such specialist regime for E&P companies. This presents lenders, directors, insolvency practitioners and the regulatory bodies with various issues. These will be discussed in the following part of this chapter.

 Although the FCA Regulations require the collateral taker to have “control” or “possession” of assets subject to a floating charge in order to qualify, which is unlikely to exist under the terms of a standard floating charge.

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Administration II-10.95 As noted above, debt finance is typically secured by way of an English law debenture containing a floating charge and/or a Scots law floating charge securing the whole or substantially the whole of the assets owned by the borrower company. For floating charges created prior to 15 September 2003,58 enforcement may be by way of the appointment of an administrative receiver or Scottish receiver, but in most instances the debenture or floating charge will be created after this date and therefore the appointment of an administrator is more likely.59 This chapter is not a comprehensive guide to insolvency appointII-10.96 ments and regimes and therefore aspects of appointment and administration procedure that have no specific bearing on E&P companies is not discussed. The focus is on the specific issues which arise in the insolvency of an E&P company due to the nature of the assets held, the manner in which such assets are held, the regulatory framework within which E&P companies operate and the various stakeholders who have an interest in the ongoing business of the company in administration. The chapter is also restricted to insolvency procedures available to UK registered companies (or companies with a centre of main interests in the UK, which would permit an insolvency appointment in the UK pursuant to the Council Regulation (EC) 1346/2000 on insolvency proceedings or the Regulation (EU) 2015/848 of the European Parliament and of the Council of 20 May 2015 on insolvency proceedings (recast)) rather than dealing with the multitude of international insolvency processes or non-insolvency restructuring solutions such as a UK-based scheme of arrangement. II-10.97 In an administration, an insolvency practitioner takes control of the business and assets of the company and uses their far-reaching powers to decide whether to trade the business, sell it as a going concern, sell specific assets, restructure operations or pursue many

 Section 72A of the Insolvency Act 1986, introduced by the Enterprise Act 2002, restricts the appointment of administrative receivers and Scottish receivers. 59   Section 72B-H lists six exceptions to the prohibition of appointment of administrative receivers. This includes at s 72E a project finance exception. The appointment of an administrative receiver is not prohibited by s 72A to a project company of a project which is a financed project (whereby the project company incurs, or is expected to incur, a debt of at least £50 million for the purposes of carrying out the project) and includes step-in rights (as defined in Sch 2A Insolvency Act 1986). Consideration should be given as to whether the company in question and the funding arrangements will permit the appointment of an administrative receiver notwithstanding creation of the floating charge post 15 September 2003. 58

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other options available in order to achieve one of the statutory objectives of administration. These statutory objectives are: (a) rescuing the company as a going concern, or (b) achieving a better result for the company’s creditors as a whole than would be likely if the company were wound up (without first being in administration), or (c) realising property in order to make a distribution to one or more secured preferential creditors.60 One of the key features of the administration procedure is the II-10.98 moratorium against certain legal proceedings, which assists the relevant insolvency practitioner in achieving his stated objective. It prevents creditors from, among other things, winding up the company, enforcing security, exercising a right of forfeiture (or irritancy in Scotland) in relation to a lease and raising any legal proceedings against the company without either the consent of the administrator or the permission of the court.61 While the moratorium is in place, the administrator is able to make strategic decisions and take actions which, if the moratorium did not apply, would not be possible due to creditor pressure. The moratorium does not prevent a creditor from taking any II-10.99 action pursuant to rights under a contract (unless such action requires the use of a legal process), including termination of the contract for reason of breach by the company in administration.62 Default provisions, including any rights of forfeiture under a JOA, are therefore typically not affected by the moratorium.63 Similarly, the statutory provisions permitting the Secretary of State for the Department of Energy and Climate Change (via the OGA) to partially revoke a Production Licence by reason of the company’s insolvency is not affected by the moratorium.64 This restriction on the scope of the moratorium is likely to have a significant impact on the administrator’s ability to trade an E&P company during the course of an administration and the cost of doing so. Co-venturers under a JOA with value to the administration are likely to become ransom creditors, as the administrator will not wish to risk the possibility of forfeiture and so will wish to avoid defaulting on the JOA and may rectify defaults which arose prior to the administration appointment. It also means that the OGA is a significant stakeholder   Para 3(1) of Sch B1 of the Insolvency Act 1986.   Paras 42–44 of Sch B1 of the Insolvency Act 1986. 62   Re Olympia & York Canary Wharf Ltd [1993] BCC 154. 63   For further discussion on default and forfeiture and the anti-deprivation rule in insolvencies please see paras II-2.54 to II-2.91. 64   Section 77 (Part 4) and Sch 3 of the Energy Act 2008. 60 61

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in the administration process and early and continued engagement is necessary in order to ensure that the risk of licence revocation is abated. This is discussed further below. Expenses of the administration II-10.100 As a general principle, the costs of an administration process are paid out of the assets of the company. Paragraph 99(3) of Schedule B1 of the Insolvency Act 1986 provides that the administrator’s remuneration and expenses are payable in priority to any floating charge debt. The order of priority of expenses is then further specified with the Insolvency (England and Wales) Rules 201665 (for English and Welsh administrations) and the Insolvency (Scotland) Rules 198666 (for Scottish administration). The wording of the rules differs between the English and Welsh rules and the Scottish rules, but the general principles are the same for each jurisdiction. The expenses that rank first in priority are those incurred by the administrator in performing their functions in the administration of the company. II-10.101 In an administration in which the administrator trades the business of the relevant company, any costs incurred in trading will therefore rank in priority to the administrator’s own remuneration and any sums payable to floating charge creditors. II-10.102 The question as to what does and what does not constitute an expense of an administration has been the subject of several cases in recent years.67 Such cases have principally dealt with payment of rent and, as at the date of writing, there have been no reported cases regarding oil and gas specific expenses. In this sector, the quantum of certain liabilities has the potential to be at a level which would greatly reduce or eliminate any recoveries were they to be payable as an expense. Decommissioning liabilities arising post-appointment of administrators are likely to be of particular concern as these can be significant and payment thereof is of no benefit to the administration process as the decommissioned asset will have little or no value to realise. Ongoing liabilities under JOAs may also be significant and, depending upon the nature of the asset and the stage at which operations are, this may render the asset a liability rather than an asset of value. II-10.103 Applying the reasoning set out in the Pillar Denton decision, the court firstly considered whether the sums in question were provable

  Rule 3.51.   Rule 4.67 as applied to administrations by Rule 2.39B. 67  See Goldacre (Offices) Ltd v Nortel Networks UK Ltd [2009] EWHC 3389 (Ch); Leisure (Norwich (II) Ltd v Luminar Lava Ignite Ltd [2012] EWHC 951; and Pillar Denton Ltd and ors v Jervis and ors [2014] EWCA Civ 180 (24 February 2014). 65 66

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debts. In that case the English Insolvency Rules in force at that time68 made specific provision for landlords proving for rent and other periodical payments in an administration69 and therefore it was clear that the rental payments were provable debts. No such specific provision exists for decommissioning liabilities or JOA liabilities. However, the rules do contain a definition of “debt” which includes “any debt or liability to which the company may become subject after [the date upon which the company enters administration] by reason of any obligation incurred before that date”.70 Applying this test, it is clear that both decommissioning liabilities and JOA liabilities arising following the appointment of administrators pursuant to contractual arrangements entered into prior to the appointment of administrators will constitute a provable debt. Applying the reasoning set out in the Lundy Granite Co ex parte II-10.104 Heavan71 case, a provable debt cannot be considered an expense of the administration, unless the so-called “salvage principle” applies. The court described this as follows: “if the company for its own purposes, and with a view to the realisation of the property to better advantage, remains in possession of the estate, which the lessor is therefore not able to obtain possession of, common sense and ordinary justice require the court to see that the landlord receives the full value of the property”.

In the case of decommissioning liabilities, it is arguable that this II-10.105 principle does not apply, as decommissioning liabilities are not incurred as a result of the beneficial use or retention of property by the administrators. In relation to ongoing JOA liabilities, the position is less clear. Where the administrators are seeking to sell the company’s interest in a JOA for value, the salvage principle would dictate that any liabilities arising pursuant to that JOA would rank as expenses of the administration. However, in relation to JOA interests which are not readily marketable (for example where there has been and continues to be a default under the JOA) the position is less clear. The standard practice in relation to rent liabilities following the Pillar Denton decision is to pay rent for the period of occupation of the property as an expense but then to notify the landlord upon vacation that ongoing rent will not be paid as an expense but rather will rank as an ordinary claim. Applying this to JOA liabilities, whilst administrators are unable to physically “vacate” a field, the equivalent step may be writing to JOA co-venturers advising that   Insolvency Rules 1986.   Rule 2.87. 70   Rule 14.1 of Insolvency (England and Wales) Rules 2016. 71   (1870–71) LR 6 Ch App 462. 68 69

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the administrators are not seeking to realise the JOA interest for the benefit of the administration. However, this approach (either in relation to JOAs or any other similar contractual right or asset) has not at the time of writing been tested in the courts. Environmental and health and safety considerations II-10.106 Administrators, and other insolvency practitioners, recognise the particularly hostile working conditions in relation to the oil and gas industry as well as the significant environmental impact of offshore operations, and the regulatory framework within which companies in this industry must operate in order to comply with health and safety and environmental obligations can be daunting.72 Of particular concern (as well as any negative publicity which failure to comply with such obligations may attract) is whether any personal liability for failure to comply with health and safety and environmental obligations arises. II-10.107 Whilst each case will be determined by reference to the relevant regulatory provisions, the general principle is that personal liability for failure to comply with health and safety and environmental obligations only attaches where the insolvency practitioner has knowingly or negligently caused or permitted the breach to occur. Nevertheless, in relation to heavy industry connections generally, practitioners are typically cautious about taking appointments due to the risk of unwittingly causing or permitting such a breach and being held to be personally liable for rectification or criminal sanctions which certain breaches carry. II-10.108 To some extent, practitioners can protect against certain liabilities by, for example, seeking an indemnity from their appointor (most likely where the appointment was by a qualifying floating charge holder) and/or delegating the responsibility for compliance with relevant regulations to the officers of the company pursuant to para 64 of Schedule B1 of the Insolvency Act 1986. However, where criminal sanctions are available, the benefit of such indemnity or delegation is likely negated. II-10.109 Administrators will therefore often seek to realise valuable assets via an accelerated sale (negotiated wholly or largely prior to the appointment of the administrator and concluded immediately or very shortly following such appointment) and to end any ongoing liability in relation to non valuable assets by allowing defaults under the relevant JOA to occur or to continue and to encourage co-venturers to exercise their right of forfeiture as quickly as possible. This

  For a discussion of Health and Safety Law upon the UKCS, see Chapter I-10. For an account of Environmental Law and Regulation, see Chapter I-11.

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strategy greatly reduces the period of time that the administrator is in control of the relevant asset. However, it is not always possible to achieve this. There may be multiple JOAs to which the company is a party, with a huge number of co-venturers. Negotiating transfers of a significant number of JOA interests to different purchasers, with consents required from the variety of co-venturers and with the company’s financial position potentially worsening and creditor pressure mounting, is a not-insignificant task. Where assets have little or no value, co-venturers may be unwilling to invoke forfeiture provisions if this would have the effect of increasing their own liability in relation to that non-performing asset. Liquidation as an alternative to administration The prospect of certain debts being classed as expenses of the administration in priority to floating charge debt and concerns in relation to health and safety and environmental liabilities could to some extent be addressed (in England and Wales, but not, as explained below, in Scotland) by the appointment of a liquidator to the company rather than an administrator (or by moving from administration to liquidation within a very short time following the administration appointment pursuant to para 83 of Schedule B1 of the Insolvency Act 1986). To the extent that there are no assets of value to realise in an administration, or where such assets have been realised immediately following administration appointment (or have been forfeited to co-venturers following default under the relevant JOA), disclaimer of the assets (or remaining assets, as the case may be) would bring any liability on the part of the insolvency practitioner to an end. Section 178 of the Insolvency Act 1986 provides that by the giving of the prescribed notice, a liquidator of a company being wound up in England and Wales can “disclaim onerous property and may do so notwithstanding that he has taken possession of it, endeavoured to sell it or otherwise exercised rights of ownership in relation to it”. This section specifically provides that any unprofitable contract and any property which is unsaleable or not readily saleable or gives rise to a liability to pay money or perform any onerous act will be considered to be “onerous property” for the purpose of this section. Disclaimed property will effectively become ownerless and fall to the Crown as bona vacantia. Any ongoing liability on the part of the company in liquidation would end and it would be for the Crown to determine how such assets should be dealt with. Section 178 does not apply to companies being wound up in Scotland. For several years following enactment of the Insolvency Act 1986, it was unclear whether a similar ability to disclaim

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onerous property arose in Scotland from common law principles, but the decision in Re The Scottish Coal Company Limited (In Liquidation)73 confirmed that liquidators in Scotland did not have such a right. II-10.115 Scottish practitioners are potentially further disadvantaged by the lack of Official Receiver in Scotland. In circumstances whereby no insolvency practitioners in private practice are willing to take an appointment to a distressed company (due to concerns over health and safety and environmental liabilities or concerns that the expenses of the insolvency will be so high as to exceed any realisable asset value and prevent the insolvency practitioner from being fully remunerated for time incurred carrying out their functions), companies being wound up in England and Wales may be dealt with by the Official Receiver. This is a civil servant within the Insolvency Service. There is no equivalent for Scottish companies and so creditors or directors wishing to appoint an insolvency practitioner to a company are required to persuade an insolvency practitioner in private practice to accept the appointment. II-10.116 The issues highlighted in this chapter demonstrate that an insolvency appointment to an E&P company is not without its challenges, and insolvency practitioners have in some cases been reluctant to take an appointment for these reasons. This presents secured creditors with a challenge in the event of default of facilities. The ultimate sanction of enforcement of floating charge security may not be one which the secured creditor can invoke. Alternative consensual solutions outwith the confines of formal insolvency (such as sale of assets, equity investment, additional funding or refinance) are likely to be pursued and exhausted with a view to avoiding enforcement. This is not without its risks for the directors of the company. If the directors are of the view that the company cannot avoid insolvent liquidation, the provisions of the Insolvency Act 1986 concerning wrongful trading74 will be of concern to directors who do not wish to risk being held as personally liable for debts incurred after that conclusion was reached. The directors may seek to make a formal insolvency appointment as soon as possible, while the secured creditor wishes to pursue a non-insolvency strategy. The directors can resolve to make their own administration appointment75 but this requires the consent of an insolvency practitioner to act as administrator, which, for the reasons discussed above, may be impossible to obtain. Directors of English or Welsh companies may resolve to   (12 December 2013) ([2013] CSIH 108). The decision overturned Lord Hodge’s Outer House decision: (11 July 2013) ([2013] CSOH 124). 74   Section 214. 75   Para 22, Sch B1 of the Insolvency Act 1986. 73

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petition to wind the company up and appoint the Official Receiver. This approach is untested for E&P companies at the time of writing, but it would likely present challenges for co-venturers under any JOA and for the OGA in terms of regulatory requirements. Acquisition of assets from insolvency practitioner For an account of acquisitions and disposals of upstream assets, see II-10.117 Chapter II-9. The principal differences between solvent sales and sales by an insolvency practitioner are: • • • • • • • • •

limited or no disclosure exercise; limited or no warranties; assets “sold as seen”; risk of title claims (retention of title, or assets subject to lease or hire purchase agreements) often borne by purchaser; purchaser granting indemnities to seller in relation to thirdparty title claims; limited or no indemnities by seller to purchaser; likelihood of extremely tight timescales (particularly in the event of a pre-pack or accelerated sale); potential difficulties obtaining consent of fixed charge security holders;76 and TUPE77 liabilities and risk of employee claims.

The overriding principle is that the purchaser must satisfy themselves II-10.118 as to title, quality of assets, assignability of contracts and potential claims, within a relatively short period of time and with limited information and access to assets. The consideration payable will usually be significantly lower than in solvent sales due to the added risk. Company voluntary arrangements In some recent insolvency cases within the E&P sector,78 the admin- II-10.119 istrators have proposed a company voluntary arrangement79 prior to bringing the administration to an end and selling shares in the company, rather than effecting a sale of business and assets, as is more typical. Where the corporate entity has an intrinsic value (for example, II-10.120 where it carries certain tax losses, which can be applied by a purchaser against profits, or where there is another unassignable   See para 71 of Sch B1 of Insolvency Act 1986.   Transfer of Undertakings (Protection of Employment) Regulations 2006. 78   For example, Oilexco North Sea Limited and Iona Energy Company (UK) Limited. 79   Section 1(3)(a) of the Insolvency Act 1986. 76 77

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right or interest which has not been terminated by reason of the insolvency), a share acquisition may be more attractive to prospective purchasers than an acquisition of assets. However, it is unlikely that the purchaser will wish to inherit any pre-sale debts of the company and therefore a company voluntary arrangement (CVA) is a useful mechanism by which to return the company to a solvent position in advance of a share sale. In such transactions, the following key considerations will be taken into account: • Who has authority to sell the shares? Where share security is in place,80 the appointing charge holder can exercise rights of sale in order to realise the value in the shares; • Will the sale of shares result in any revocation of licence(s) by the OGA? Advance clearance for the sale should be sought; • What change of control provisions are there within any key contracts, in particular any JOAs still in place?; and • What is to be offered to ordinary creditors by way of repayment of debt? A CVA proposal (or any modification of it) must be approved at least 75 per cent (by value) of the company’s creditors who vote on the proposal at a meeting of creditors.81 In addition, no more than 50 per cent (by value) of any creditors who vote against the proposal (or a modification of it) can be creditors who are unconnected with the company.82 Therefore, the proposals need to be sufficiently attractive to ordinary creditors in order to obtain the necessary creditor approval. Finance and insolvency: market developments – conclusions II-10.121 We have examined many of the key sources of financing available to upstream E&P companies, and noted some of the more innovative forms of finance that continue to develop as the market changes and adapts to the continued lower oil price environment. RBL facilities remain one of the primary sources of debt finance for upstream E&P companies with a range of asset bases, having flexible terms that are able to vary across a relatively wide spectrum, depending on the nature of the company and underlying field interests involved. Liquidity in the market for well-structured RBL facilities, for the right assets, is improving at the time of writing, often with comple-

  See the discussion on Security over Shares at paras II-10.85 to II-10.92.   Rule 15.34 of the Insolvency (England and Wales) Rules 2016 and rule 1.16A(2) of the Insolvency (Scotland) Rules 1986. 82   Rule 15.34(4) of the Insolvency (England and Wales) Rules 1986 and rule 1.16A(4) of the Insolvency (Scotland) Rules 1986. 80 81

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mentary investment from private equity, to help companies meet newer equity ratio requirements. Formal insolvencies in this market have been relatively few and II-10.122 far between, which may be surprising given the financial pressures on E&P companies in the years since 2014. However, the unique challenges which secured creditors, insolvency practitioners, company directors, co-venturers, the OGA and other interested parties face in dealing with the formal insolvency of an E&P company has likely impacted decisions in relation to security enforcement. Where consensual solutions can be achieved (deferred repayments, or the solvent disposal of assets in a structured manner) without the need for formal insolvency, this has been viewed as the better outcome for all stakeholders. Nevertheless, the few high-profile insolvency cases there have been demonstrate that the issues are not insurmountable. Collaboration with regulatory bodies and co-venturers is key to successfully realising the assets of the insolvent company for the benefit of creditors and, in some instances, bringing the corporate entity back to a solvent position (albeit with a much-reduced asset base).

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CHAPTER II-11 COMPETITION LAWAND THE UPSTREAM OIL AND GAS BUSINESS Judith Aldersey-Williams

WHY COMPETITION LAW MATTERS II-11.01 Competition law is a serious matter: operators and contractors are quite right to be wary of breaching the prohibitions as the consequences can be significant. Both the UK and EU1 authorities have significant powers to fine parties up to 10 per cent of their annual worldwide group turnover.2 Since fines are relatively rare, in practice a more significant sanction is likely to be the fact that agreements which breach the prohibition are void and unenforceable.3 Increasingly, there is also the threat of damages actions from third parties who claim to have been the victims of anti-competitive conduct.4   In the absence of a clear conclusion as to the form Brexit will take, this chapter proceeds on the basis of the law as at 1 January 2017 and does not address the question of how UK competition law may change following Brexit. 2   For more information on fining policy see the EU Guidelines on the method of setting fines imposed pursuant to Art 23(2)(a) of Regulation No 1/2003 [2006] OJ C210/2, available for download at http://ec.europa.eu/comm/competition/antitrust/legislation/ fines.html (accessed 29 December 2016) and the OFT Guidance 423, OFT’s Guidance as to the appropriate amount of a penalty (2004), originally published by the Office of Fair Trading (OFT) and adopted by the Competition and Markets Authority (CMA) Board, available for download from www.gov.uk/government/uploads/system/uploads/ attachment_data/file/284393/oft423.pdf (accessed 29 December 2016); see also C Kerse and N Khan, EC Antitrust Procedure (6th edn, 2012), Chapter 7. 3  See R Whish and D Bailey, Competition Law (8th edn, 2015) (hereinafter “Whish, Competition Law”), at 337. 4  Third parties who suffer a loss as a result of a breach of EU competition law have a direct right in damages: see Joined Cases C-299 to 298/04 Manfredi v Lloyd Adriatico Assicurazioni, [2006] 5 CMLR 17. Early attempts to claim damages hit a number of 1

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Although there is no power to fine employees or directors for II-11.02 breach of competition law, the Competition and Markets Authority (CMA) can apply to have a company director disqualified for up to 15 years if his company is found to have infringed competition law in situations where his conduct is considered to make him unfit to act as a director.5 Senior managers responsible for cartel activity by their company may also be prosecuted and if convicted can be sent to prison for up to five years.6 However, case law suggests that a company will rarely be able to sue its own employees who have engaged in anti-competitive conduct for the resulting losses to the company.7 In addition to their powers of enforcement, it is important to bear II-11.03 in mind that the authorities have extensive powers of investigation and can even give rewards for whistle-blowing regarding cartels.8 hurdles (see Crehan v Inntrepreneur Pub Co [2007] 1 AC 333) but the way has now been eased in the UK by a series of statutory developments. Section 47A Competition Act 1998 (introduced by the Enterprise Act 2002) gave the Competition Appeals Tribunal (CAT) the power to hear damages actions following on from CMA or European Commission decisions without the need to re-litigate the infringement, and the Consumer Rights Act 2015 gave the CAT power to hear stand-alone claims as well as introducing new procedures for fast-track claims, collective proceedings, collective settlement and voluntary redress schemes. The result has been more than 40 damages cases brought as at the time of writing. Further amendments will follow in 2017 from the implementation in the UK of the EU Antitrust Damages Directive, available for download at http://ec.europa.eu/ competition/antitrust/actionsdamages/index.html (accessed 4 January 2017). See further in relation to damages and other related issues CMA Guidance 55, Competition Law Redress: A guide to taking action for breaches of competition law (2016), available for download from www.gov.uk/government/publications/competition-law-redress-cma55 (accessed 29 December 2016). 5   See sections 9(A) to (E) of the Company Directors Disqualification Act 1986 and the OFT’s Guidance 510, Director Disqualification Orders in Competition Cases, originally published by the OFT and adopted by the CMA Board, available for download from www.oft.gov.uk/shared_oft/business_leaflets/enterprise_act/oft510.pdf (accessed 29 December 2016). The first such disqualification order was obtained in December 2016; see www.gov.uk/government/news/cma-secures-director-disqualification-for-competitionlaw-breach (accessed 10 January 2017). 6   Enterprise Act ss 188–189 and CMA’s Guidance 9, Cartel Offence Prosecution (2014), available for download from www.gov.uk/government/publications/cartel-offence-prosecution-guidance (accessed 29 December 2016). 7  In Safeway Ltd & Others v Simon Twigger & Others [2010] EWCA Civ 1472, the Court of Appeal ruled that a corporate undertaking, upon which the OFT had imposed a penalty for breaches of competition law, could not sue its former directors, officers or employees for damages equivalent to that penalty or the costs of the OFT investigation that the claimant had had to bear. The Court of Appeal held that such liabilities were intended, under the relevant statutory scheme of the Competition Act 1998, to be personal to the corporate undertaking and any claim against its directors or employees was barred by the maxim ex turpi causa (ie a claimant cannot recover for the consequences of his own criminal or quasi criminal act). 8  See www.gov.uk/government/publications/cartels-informant-rewards-policy (accessed

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Even if a company is ultimately found to have committed no offence, an investigation may cause significant disruption to business and create a drain on management time and resources. For instance, in May 2007, in a joint operation by US, UK and EU competition authorities, eight executives, including three from the UK, were arrested in the USA while “dawn raids” were carried out on a range of business and residential addresses in the UK and elsewhere – all of this activity was directed at uncovering a cartel in the market for marine hose used to transfer oil.9 This investigation ultimately led to the prosecution and imprisonment of three executives and fines on the companies involved totalling over 131 million euros.10 In 2008, the European Commission fined E.ON Energy AG (hereinafter “E.ON”) 38 million euros because a seal affixed by Commission inspectors to secure documents was broken during an inspection carried out at the premises of E.ON in May 2006. E.ON denied breaking the seal, but could not explain the reason for it being broken.11 II-11.04 Briefly, the authorities may, among other things: • obtain interim injunctions to stop harmful conduct while investigations are carried out; • on completion of investigations, order the conduct to cease permanently; • arrive unannounced at business premises, search for and take copies of documents, question staff and remove computers; • search home premises; • fine or, in the UK, even imprison persons who interfere with their investigation for up to two years.12 29 December 2016). 9   For further information see OFT, Press Release 70/07, “OFT launches criminal investigation into alleged international bid rigging, price fixing and market allocation cartel”, available for download from http://webarchive.nationalarchives.gov.uk/20140402142426 and www.oft.gov.uk/news-and-updates/press/2007/70-07 (accessed 29 December 2016). 10  See OFT, Press Release 72/08, “Three imprisoned in first OFT criminal prosecution for bid rigging”, available for download from http://webarchive.nationalarchives.gov. uk/20140402142426 and www.oft.gov.uk/news-and-updates/press/2008/72-08 (accessed 29 December 2016), and Commission press release, “Antitrust: Commission fines marine hose producers €131 million for market sharing and price-fixing cartel”, available for download from http://europa.eu/rapid/pressReleasesAction.do?reference=IP/09/137&for mat=HTML&aged=0&language=EN&guiLanguage=en (accessed 29 December 2016). Part of the Commission’s decision was subject to appeal to the General Court and then the Court of Justice, resulting in some reduction in fines: Judgment 14/07/2016: Parker Hannifin Manufacturing and Parker-Hannifin v Commission, Case T-146/09 RENV. 11  For further information see “Commission fine on E.ON for breach of seal during inspection – guide”, available at www.eubusiness.com/topics/competition/eon-fine-guide (accessed 29 December 2016). 12  See ss 25–29 of the Competition Act 1998; also OFT Guidance 404, Guidance on

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However, competition law is sometimes used to justify behaviour II-11.05 which, on analysis, turns out to have nothing to do with competition law concerns. Often this results from poor understanding and an excess of caution. A basic understanding of competition law is therefore a useful tool to challenge such behaviour. This is particularly important in the context of the introduction of the Maximising Economic Recovery (MER UK) Strategy,13 with its focus on collaboration, as the cornerstone of regulation of the oil and gas industry on the United Kingdom Continental Shelf (UKCS). It is important to note that compliance with the requirements of MER UK is no protection against an allegation of breach of competition law, but neither should unwarranted fear of allegations of anti-competitive conduct chill legitimate collaborative activity, as this may put companies in breach of their MER obligations.14 One of the difficulties of competition law is that the analysis is II-11.06 not simply a legal one. The rules are not “bright-line” legal requirements to which there is always a straightforward yes/no answer. Invariably, an analysis of the competition law position requires an understanding of the market position of the parties. This is fundamentally an economic issue, and requires advisors to be provided with facts and information which businesses often do not have readily available and commercial clients are certainly not used to having to provide to their lawyers. In addition to analysing the object and effect of the agreement and any restrictions it contains on competitors and customers, competition advisers will need to consider more “political” issues: such as whether competitors or customers are likely to complain or whether this is a particularly high-value or high-profile contract likely to attract the attention of the authorities. It is not possible in one chapter to give a complete account of II-11.07 competition law in the UK. The purpose of this chapter is to give a brief overview of competition law to enable general practitioners to determine when specialist advice may be necessary. THE BASIC PROHIBITIONS Both UK and EU competition law are based on the same two prohi- II-11.08 bitions. The EU prohibitions are found in Articles 101 and 102 of the Powers of Investigation, 2004, originally published by the OFT and adopted by the CMA Board, available for download from www.oft.gov.uk/shared_oft/business_leaflets/ ca98_guidelines/oft404.pdf (accessed 29 December 2016). 13   See Chapter I-5. 14   See further below at para II-11.55 et seq.

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TFEU15 and the equivalent UK prohibitions are found in Chapters I and II of the Competition Act 1998. The prohibitions are against (1) anti-competitive agreements and practices (Article 101/Chapter I); and (2) abuse of dominance (Article 102/Chapter II). II-11.09 Anti-Competitive agreements and practices will be discussed further at paras II-11.18 to II-11.20. Anti-competitive agreements II-11.10 Article 101/Chapter I prohibits arrangements between undertakings16 which: • affect trade in the EU/UK (as appropriate); and • have as their object or effect the restriction of competition in the EU/UK. II-11.11 Examples of anti-competitive agreements include classic pricefixing17 and market-sharing agreements,18 and some less obvious ones, such as customer boycotts, some trade association rules19 and exclusive purchasing or supply agreements.20 Agreements may also be anti-competitive if they apply dissimilar conditions to equivalent transactions with other trading parties, thereby placing them at a competitive disadvantage or if they make the conclusion of contracts subject to acceptance by the other parties of supplementary obligations which, by their nature or according to commercial usage, have no connection with the subject of such contracts.21 Mergers may in some cases fall within Article 101 where they significantly impede competition. The issue of merger control is outside the scope of this chapter.22 II-11.12 Agreements do not have to be formal written contracts to fall  Treaty on the Functioning of the European Union (TFEU), formerly known as the Treaty establishing the European Community. 16   An undertaking for competition law purposes is any legal or natural person engaged in economic activity, including individuals, companies, state bodies and trade associations. However, corporate groups are viewed as a single entity for these purposes. 17   That is, agreements which distort competition by directly or indirectly fixing purchase or selling prices or other trading conditions. 18   On which see Whish, Competition Law, at pp 565–566. 19   See eg OFT Guidance 408, Trade associations, professional bodies and self-regulating bodies (2004), originally published by the OFT and adopted by the CMA Board, available for download from www.gov.uk/government/uploads/system/uploads/attachment_data/ file/284404/oft408.pdf (accessed 4 January 2017). 20   See eg C-393/92, Almelo and Others v Energiebedrijf Ijsselmij [1994] ECR I-1477. 21   Competition Act 1998 s 2(2). 22   For a general discussion, see Whish, Competition Law, Chapters 20, 21 and 22; and for an account directed specifically towards cross-border mergers and acquisitions in the energy sector, see P Cameron, Competition in Energy Markets: Law and Regulation 15

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within the prohibition23 – oral agreements, gentlemen’s agreements,24 rules and recommendations of trade associations,25 and concerted practices26 can all fall within the prohibition. Agreements which fall within the Article 101/Chapter I prohi- II-11.13 bition are void and unenforceable, although if the anti-competitive clauses can be severed from the remainder of the agreement under the governing law of the contract then the rest of the agreement may survive.27 There is an exclusion under both EU and UK law for agreements II-11.14 of minor importance, although it is unlikely that many agreements in the oil and gas sector will fall within these de minimis exclusions. The European Commission’s Notice on Agreements of Minor Importance28 sets out the European Commission’s view that agreements between undertakings which affect trade between member states do not appreciably restrict competition within the meaning of Article 101 if: • the aggregate market share of the parties to the agreement (and their affiliates) does not exceed 10 per cent on any of the relevant markets affected by the agreement where the agreement is made between competing undertakings (ie undertakings which are actual or potential competitors on any of the markets concerned),29 or • the market share of each of the parties to the agreement (and their affiliates) does not exceed 15 per cent on any of the relevant markets affected by the agreement where the agreement is made between non-competing undertakings (ie undertakings which are neither actual nor potential competitors on any of the markets concerned).30 in the European Union (2nd edn, 2007) (hereinafter “Cameron, Competition in Energy Markets”), Chapter 14. 23  Although they may be, and even documents in the nature of compromise agreements may fall within the prohibition in certain circumstances: see Re Penney’s Trade Mark [1978] OJ L60/19. 24   Case 41/69 ACF Chemiefarma NV v Commission [1970] ECR 661. 25   See para II-11.10. 26  Case 48/69, ICI v Commission (The Dyestuffs Case) [1972] ECR 619. See also the discussion at Whish, Competition Law, pp 117–120. 27   Case 319/82, Société de Vente de Ciments et Bétons de l’Est SA v Kerpen & Kerpen GmbH und Co KG [1983] ECR 4173. 28  Commission Notice on agreements of minor importance which do not appreciably restrict competition under Article 101(1) of the Treaty establishing the European Community (hereinafter “Notice”) OJ 2014 C291/01. 29   Notice, Art 8(a). 30   Notice, Art 8(b). In both cases, these thresholds are reduced to 5 per cent where competition on the relevant market is restricted by the cumulative foreclosure effect of parallel networks of agreements having similar effects on the market – the agreements under

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II-11.15 An agreement containing any of the restrictions set out in para 13 of the Notice on Agreements of Minor Importance does not benefit from the exemption. These include: • in the case of an agreement between competing undertakings a provision which directly or indirectly fixes prices, shares markets or limits production, or • in the case of an agreement between non-competing undertakings a provision which: • limits a buyer’s ability to determine its resale price (except that a supplier may impose a maximum resale price or recommend a resale price, provided that pressure or incentives from the parties to the agreement do not result in that becoming a fixed or minimum price); or • restricts the territory into which or the customers to which a buyer may sell the contract goods, subject to certain exceptions; or • restricts active or passive selling by authorised distributors to end-users or other authorised distributors in a selective distribution network; or • restricts, by agreement between a supplier of components and a buyer who incorporates those components in its products, the supplier’s ability to sell the components as spare parts to end-users or independent repairers not entrusted by the buyer with the repair or servicing of its products. II-11.16 The CMA is required to have regard to the Commission’s notice and as a matter of practice the CMA is unlikely to find that an agreement falls within either Article 101 or the Chapter I prohibition when it is covered by the Notice. However, even agreements which exceed these thresholds may be found to have no appreciable effect depending on factors including the content of the agreement and the structure of the market, such as entry conditions or the strength of buyer power. The CMA have confirmed that, where an agreement does not have the object of restricting competition, its effect will be judged within its full market and economic context.31 Agreements which on the face of it fall within the prohibition may II-11.17 also be exempt if they meet certain criteria set out in Article 101(3), which many petrol stations are affiliated to particular oil companies might constitute such a series of parallel networks: Notice, Art 10. 31  OFT Guidance 401, Agreements and concerted practices, originally published by the OFT and adopted by the CMA Board, available for download from www.gov.uk/ government/uploads/system/uploads/attachment_data/file/284396/oft401.pdf at para 2.14 (accessed 4 January 2017).

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discussed at para II-11.32. Formerly, it was necessary to obtain an individual exemption from the authorities for such agreements or to fall within a so-called “block exemption” for certain categories of agreement. Now,32 individual exemptions are no longer granted – the exemption applies automatically if the criteria are met, but it is up to the parties and their lawyers to decide whether they meet the criteria and ultimately any such decision may be challenged through the courts by an aggrieved party. However, the block exemption system continues in place, and in practice many agreements – for instance, most vertical agreements,33 research and development agreements34 and specialisation agreements35 – will continue to benefit from these exemptions. The criteria to be met for an individual exemption are that the agreement • contributes to improving the production or distribution of products or to promote technical or economic progress; • allows consumers a fair share of the resulting benefit; • imposes only restrictions which are indispensable to the attainment of the above listed objectives; • does not afford the possibility of eliminating competition in respect of a substantial part of the products in question.36 Abuse of dominance Article 102/Chapter II prohibits conduct which

II-11.18

• amounts to the abuse of a dominant position and • affects trade in the EU/UK (as appropriate). In order to fall within this prohibition, a business must have a II-11.19 dominant position. This will usually involve the business having a significant market share, but this is merely evidence of dominance.37 The key to a dominant position is not market share per se but  That is, since the coming into force on 1 January 2004 of the Council Regulation of 16 December 2002 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty, Regulation 1/2003 (hereinafter “the Modernisation Regulation”) [2003] OJ L1/1. 33   See Commission Regulation 330/2010 [2010] OJ L102/1. See further below at paras II-11.52 to II-11.54. 34  See Regulation 1217/2010 on Research and Development Agreements 2010 [OJ] L 335/36. 35   See Regulation 1218/2010 on Specialisation Agreements [2010] OJ L335/43. A specialisation agreement is, broadly speaking, one whereby one or more of the parties agrees either to refrain from producing a product or products, or to produce products jointly. 36   See Art 101(3) of the Treaty of Rome; s 9 of the Competition Act 1998. 37  For a detailed account, see Whish, Competition Law, Chapter 1, particularly at pp 26–47. 32

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having market power, which in essence means that the business can act in the marketplace without fearing that its competitors will take custom from it or that its customers will turn to other products or services.38 In order to measure market power, it is necessary first to determine on which market a business is active (discussed further at paras II-11.23 to II-11.24, below) and then what market share it has. Market share is an indicator (although not a foolproof one) of market power. Generally, a company with a market share of over 40 per cent may have a dominant position depending on the structure of the market, while a company with a market share of over 50 per cent will generally be presumed to have a dominant position unless the contrary is shown.39 II-11.20 It is important to note that the prohibition does not make it illegal to have a dominant position, but only to abuse it. Abuses of dominance may take many forms, but include imposing unfair prices/conditions, operating loyalty rebates, refusing to supply a particular customer and making the purchase of one product or service conditional on taking another product or service (“tying”). A business may also have a dominant position in relation to the purchase of particular types of goods or services.40 There are fewer exclusions available in relation to the Article 102/Chapter II prohibition than in relation to the Article 101/Chapter I prohibition, and no exemptions. UK OR EU JURISDICTION – WHAT DIFFERENCE DOES IT MAKE? II-11.21 The Competition Act 1998 requires the UK authorities to interpret the UK prohibitions consistently with EC law,41 and therefore interpretation of the two prohibitions should be broadly similar under both regimes. As we have seen,42 both carry significant sanctions for breach including substantial fines, but there are important differences between the two systems, concerning, for instance:   See eg OFT Guidance 415, Assessment of Market Power (2004), originally published by the OFT and adopted by the CMA Board, available for download from www.gov.uk/ government/uploads/system/uploads/attachment_data/file/284400/oft415.pdf (accessed 4 January 2017), at 3.1: “Market power can be thought of as the ability profitably to sustain prices above competitive levels or restrict output or quality below competitive levels.” For a discussion of various definitions which have been used from time to time, see S Bishop and M Walker, The Economics of EC Competition Law: Concepts, Application and Measurement (2nd edn, 2002), at para 3.04. 39   See Case 62/86, AKZO Chemie BV v Commission [1991] ECR I-3359. 40   For a full account of these practices see Whish, Competition Law, Chapters 17 and 18. 41   See the Modernisation Regulation, Regulation 1/2003, Art 1. 42   See para II-11.1. 38

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procedures for dealing with complaints; investigative powers; the scope of exclusions for agreements of minor importance; the EC concern about agreements which put up barriers to a single market.

In addition, the political priorities of the competition authorities in II-11.22 the two jurisdictions may be different, leading to different risks of intervention in relation to certain activities. So how do you decide whether your contract or business activity II-11.23 is likely to fall under the jurisdiction of the UK or EC authorities? The key is whether there is any actual or potential effect on trade with other EU/EEA countries (EU rules apply also in the EEA).43 For instance, any agreement concerning the distribution of oil or gas is likely to have such an effect (however small) because oil is sold onto an international commodity market, and gas is sold onto an increasingly European market as a result of the interconnector between the UK and Belgium and the various pipelines which can divert gas between the UK and continental Europe.44 However, there may be some de minimis exceptions such as an agreement by one offshore field to supply fuel gas to a neighbouring offshore field. Equally, a transport and processing agreement (TPA) between a new satellite field and a nearby host operator is unlikely to affect trade between member states since there was never any prospect of using an export route to another country, but a TPA for a major new discovery may do so, if the owners could have chosen an export route to Norway or the Continent. Many offshore service and supply contracts could be performed by a supplier from Norway or Denmark as easily as by a UK supplier, and therefore they also may be thought to affect trade between member states. Onshore contracts may or may not affect trade depending on the nature of the goods or services concerned and the likelihood of their being supplied from outside the UK. It should be noted that an agreement between two or more parties outside the EU can have an effect in the EU (for instance a cartel between a US manufacturer and an Asian manufacturer of particular goods supplied into the EU market).45

 See the Commission’s Notice on guidelines on the effect on trade concept OJ 2004 C101/101 and equivalent UK guidance: OFT Guidance 401, Agreements and concerted practices, originally published by the OFT and adopted by the CMA Board, available for download from www.gov.uk/government/uploads/system/uploads/attachment_data/ file/284396/oft401.pdf and http://oft.gov.uk/shared_oft/business_leaflets/ca98_guidelines/ oft401.pdf (accessed 4 January 2017). 44   See para II-11.37. 45  The global reach of cartels has been identified as a major impediment to the imple43

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EU Members as at Austria, Belgium, Bulgaria, Croatia, Cyprus, 1 January 2017: Czech Republic, Denmark, Estonia, Finland. France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden and the UK. EEA Members as at EU member states plus Norway, Iceland and 1 January 2017: Liechtenstein. II-11.24 Under the EU rules, agreements are unlikely to affect trade between member states if the aggregate market share of the parties on any relevant market in the EU does not exceed 5 per cent, and the aggregate annual Community turnover of the parties (in horizontal agreements) or of the supplier (in vertical agreements) in the products concerned does not exceed 40 million euros.46 II-11.25 If in doubt, it is probably safer to assume that EU law applies since if a European exemption applies parties will have a parallel exemption under UK law and, to date, the European Commission has shown more interest in the oil and gas sector than has the UK. DEFINING THE RELEVANT MARKET II-11.26 In order to analyse the impact of an agreement in competition terms, it is necessary to conduct market analysis which aims at answering the following questions:47 • What is the product market? This will include the particular product or service being provided under the agreement and any other goods or services which the customer views as a substitute for that product or service. In other words, if the price of the particular product or service went up by, say, 5 per cent, to what alternative would the customer turn? If there is such an alternative, it is likely to form part of the market. • What is the geographic market in which it is provided? In determining the geographic market, the authorities will look at the area from which customers usually purchase the mentation of competition law and policy and has led to increased co-operation between anti-trust authorities: see Whish, Competition Law, 495–518. 46  See the Commission Notice – Guidelines on the effect of Trade Concept (2004) C101/07. 47   See the Commission’s Notice on Market Definition, (2001) C 38/13, and OFT Guidance 403, Market Definition, (2004), originally published by the OFT and adopted by the CMA Board, available for download from www.gov.uk/government/publications/marketdefinition (accessed 4 January 2017) and Whish, Competition Law, at pp 26–47.

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•

relevant goods and services. The growth of e-commerce and the global procurement marketplace may expand the market for some goods and services but the authorities will be interested in concrete examples of trade flows, not just theoretical options. What are the parties’ market shares on the product and geographic market identified under the first two points above, and, if the market is confined to the UKCS, what are their shares in the EU and worldwide? Who are the principal competitors and what is their turnover and market share in the UKCS, EU and worldwide? How easy would it be for a new competitor to enter the market? What are the barriers to entry – for instance, start-up costs, research and development issues, distribution network, intellectual property rights and reputation? Who are the customers for this product/service – for instance, operators, major contractors or small service companies? This will determine the degree of “buyer power” which may counterbalance any perceived power of the parties to the agreement.

Example of market definition For example, if an operator were to enter into a restrictive contract with a contractor for the supply of remotely operated vehicles (ROVs) for rig positioning, what would be the relevant market? The first step would be to consider all suppliers of ROVs for rig positioning, but one would also have to consider whether there are any other ways of checking rig position accurately? If so, and these are comparable in cost and quality, such that the operator would turn to them if the cost of using ROVs increased by, say, 5 per cent, then they too will be part of the market. What if another supplier has ROVs but has traditionally used them only for seabed surveys – if the prices were attractive could that supplier adapt its business? If it could enter the market within, say, a year, then it may be a potential competitor, and will be considered when assessing the market power of the ROV contractor, although it has no current market share on the rig positioning market. The following potential product markets have been identified by II-11.27 the European Commission in its merger decisions relating to the upstream oil and gas sector: • The market for exploration for oil and gas reserves (essentially the market for licences/concessions available to IOCs) – this market is global and not divided between oil and gas, as an

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uk o i l a nd gas l aw vo l u m e i i operator cannot be certain what type of hydrocarbons will be found until it explores;48 The market for the development, production and upstream wholesale supply of crude oil which is generally worldwide.49 (Although in Rosneft/TNK50 the Commission considered that for certain landlocked EEA countries, the market for the supply of crude oil could, from the demand side, be viewed as limited to the production of a single supply pipeline such as the Druzhba pipeline; this clearly does not apply in the case of the UK.); The market for the development, production and upstream wholesale supply of natural gas to large importers/wholesalers, which is narrower in geographic scope, given the constraints of gas export. The Commission has not committed itself firmly on this point as it has not proven necessary to its decisions. In the Statoil/Hydro decision,51 the options it considered (though ultimately left open) were (1) the EEA (2) an area comprising those EEA countries in which gas from the Norwegian continental shelf was sold or (3) each individual country to which the parties sold gas. In Gazprom/ Wintershall/Target Companies, the Commission commented that markets could be defined as national due to limited interconnection infrastructure or lack of available cross border capacity,52 but conceded that both competitors and customers agreed that the market probably consisted of at least Germany, Belgium, the Netherlands, Norway and the United Kingdom;53 The liquefaction of liquefied natural gas (LNG) for which the geographic market would be the Atlantic Basin or wider;54 The wholesale supply of LNG by vessel (on the basis that prices of LNG and pipeline gas are different and that to some extent the uses are different with LNG having a greater use to ease seasonal demand spikes) possibly further subdivided into long-term and spot sales, which would be either national

  Most recently summarised in Decision M7631 of 2 September 2015 Royal Dutch Shell/ BG Group 1. 49   Ibid. 50   Decision M6801 of 8 March 2013 Rosneft/TNK. 51   See Decision M4545 of 3 May 2007 Statoil/Hydro. 52   See also Decision M7316 of 10 September 2014 DNO/Marathon where the Commission noted that while EEA-wide from a demand-side perspective, from a supply-side perspective the scope of the market might be limited to the relevant pipeline systems and therefore be rather regional or national. 53   Decision M6910 of 3 December 2013 – Gazprom/Wintershall/Target Companies. 54   Note 48, ibid. 48

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or encompass the entire EEA as well as Russian and Algerian imports;55 The four separate markets for the upstream transportation of crude oil, transportation of natural gas, processing of crude oil and processing of natural gas for which the relevant geographic markets are in each case the UK North Sea, possibly divided into the Northern North Sea and Southern North Sea at the 55 degree N line of latitude;56 The transportation of LNG by vessel;57 The market for natural gas storage, potentially divided into pore and cavern storage and between storage for H-gas and L-gas;58 The markets for the trading of crude oil and petroleum products which would be at least EEA wide and possibly worldwide in geographic extent;59 The market for the trading of natural gas at natural gas trading hubs; The markets for goods and services necessary for exploration and production of oil and gas which tend to be at least EEA wide or potentially global – see for instance subsea production systems (Christmas trees, manifolds and control systems being separate product markets) in DNO/Marathon.60

HORIZONTAL AND VERTICAL AGREEMENTS Horizontal agreements are agreements with one’s trade competitors. II-11.28 The potential for such agreements to manipulate fair competition is obvious and they have traditionally been viewed with greater suspicion by the competition authorities than have vertical agreements.61 Some of the principal types of horizontal agreements in use in the industry are joint operating agreements (JOAs), joint

 Decision M6477 of 16 May 2012 BP/Chevron/Eni/Sonangol/Total/JV and Decision 7631 of 2 September 2015 Royal Dutch Shell/BG Group; see note 48 ibid. Note however that these market definitions are not definitive as on any analysis there was no substantive issue. 56   Note 48, ibid. 57   Note 53, ibid. 58   Ibid. 59  Decision M7318 – Rosneft/Morgan Stanley Global Oil Merchanting Unit of 3 September 2014 subsequently confirmed in Decision 7631 Royal Dutch Shell/BG; see note 48. 60   Note 52, ibid. 61   The Commission’s approach to horizontal agreements can be seen in its “Guidelines on the applicability of Article 101 of the Treaty on the Functioning of the European Union to horizontal co-operation agreements”, [2010] OJ C11/1. 55

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procurement contracts and joint sales contracts and these are considered in more detail at paras II-11.30 to II-11.42. II-11.29 A vertical agreement is one between two or more parties, each of which acts at a different level in the supply chain for the purposes of the agreement – even though they may be at the same level of the chain in other contexts – and which relates to the conditions under which goods or services may be purchased, sold or resold. A vertical agreement would include an agreement between an operator and a contractor, or a contractor and a sub-contractor. Procurement contracts entered into by individual operators are the most common type of vertical agreement in the industry although an agreement by a single licensee for the sale of gas or oil is also a vertical agreement. Generally, vertical agreements raise fewer competition issues than the horizontal agreements. However, see paragraphs II-11.56 to II-11.58 for an analysis of vertical agreements and when they may cause competition problems. COMMON COMPETITION ISSUES IN UPSTREAM AGREEMENTS Joint operating agreements and unit operating agreements II-11.30 As we have already seen, because of the enormous risks and capital involved in oil and gas development, oil companies spread their risk by taking different levels of interest in different fields and developments.62 This does require co-operation between companies which are competitors in other markets but if it were not possible to share risks in this way, development would be significantly restricted. A JOA is necessary in order to regulate the sharing of risk and reward. However, JOAs in themselves do not often raise significant competition concerns as they do not restrict competition to any appreciable extent. First, JOAs rarely restrict the parties in relation to matters outside the joint development itself – licensees are entirely free to engage in other joint ventures (JVs) with other parties; their co-operation is restricted to the specific area covered by their licence, which is unlikely in itself to represent a significant share of any oil or gas market. Second, joint development does not necessarily entail joint sale of the products of development. In the case of JOAs, the parties are keen to ensure for taxation and liability reasons that their JOA is not treated as a partnership, and therefore for this reason, even before the impact of competition law concerns was felt, it has been standard practice for JOAs to stipulate that each licensee owns its share of production separately and for the JOA not to encompass   See para II-12.1.

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the sale of that production. In terms of competition analysis, a JV to develop an oil or gas field is therefore unlikely to have an appreciable impact on competition. Even if it did, it would be likely to benefit from an exemption under Article 101(3). Even though there are no restrictive clauses in most JOAs, II-11.31 the mere existence of the JOA may give rise to concerns that the exchange of information could itself constitute a breach of Article 101. The exchange of information between competitors which leads to market co-ordination (on commercial strategy, on pricing, on sharing out of customers etc.) or which could lead to competitors adopting similar approaches to the market is regarded as a violation of Article 101(1). The exchange of collated and aggregated statistical information II-11.32 (most easily justified when it is of historic relevance) and technical information is permitted as this will rarely have commercial implications. In a JOA this means that the sharing of information on operational and maintenance issues with partners should be non-controversial. However, information on price, on raw materials, production statistics, supplier arrangements, sales figures, terms of business, customer details, business strategy and input cost information have been prohibited in certain contexts. In reality, in cases of jointly owned facilities there will inevitably be exchanges of information falling within some of these headings in so far as it relates to the JV. If the overall arrangement falls within Article 101(3), then these exchanges are likely to fall within the exemption also. However, any information exchange should be kept to the minimum necessary. The licensees will inevitably receive information about production levels and plans for development of the field. They will also inevitably have information on their competitors’ costs in relation to the production from the JV (as each party will take its proportionate share of the venture’s costs) – the concern would ordinarily be that this would enable the licensees to predict their partners’ sale prices and therefore choose not to compete hard with them on price, but the production costs from one venture will in most cases represent only a small proportion of any licensee’s overall costs and therefore will not necessarily give any indication as to the prices at which they will be prepared to sell their production. In any event, on a commodity market, the cost of production of a single seller has only an indirect impact on sale price. There will rarely be any justification for sharing information as to prices received for production. One area where concerns do arise is in relation to “federal” II-11.33 contracts under which operators enter into contracts for the supply of services to a number of JVs which they operate – operators may be concerned that they would be giving an anti-competitive advantage to their co-venturers by revealing to them the costs under

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these contracts, as they will also apply to other JVs to which those co-venturers are not party. The co-venturers on the other hand will legitimately query how they can be asked to pay their share of costs if they are not allowed to approve and audit those costs. These issues may be addressed by limiting rights of access to this information to audit rights only. Problems may also arise with regard to decisions to re-inject or shut in which have an appreciable effect on production, as these may amount to a joint decision to limit production. Generally, however, such decisions are taken only where, for operational reasons, such a decision is unavoidable. II-11.34 Unitisation and unit operating agreements (UUOAs) raise similar issues to JOAs. Bidding agreements or Area of Mutual Interest Agreements (AMIs), however, may raise more concerns as they may contain clauses preventing parties from bidding for assets in a particular area except through the consortium. This constitutes a restriction on competition and must therefore be analysed for compliance with competition law. In most cases, the area and duration are likely to be limited and the effect on competition is unlikely to be appreciable, given that the market for licences is global. Joint procurement II-11.35 In one sense, all procurement by JVs is joint procurement as it is carried out by the operator on behalf of, and often expressly as agent for, the co-venturers under the JOA. However, so long as this is limited to procurement required for the development then, as discussed above in relation to JOAs, it is unlikely to raise any competition concerns – it is an inevitable consequence of the joint development. Joint procurement by neighbouring fields has been encouraged by various industry initiatives such as CRINE and often relates to logistics such as use of support vessels, supply vessels or helicopters. Rig-sharing initiatives are also common. Such joint purchasing is likely to produce economies of scale and may even enable the development of previously uneconomic fields. It is unlikely to be a problem under competition law unless the purchasing consortium reaches a size where it would be dominant in the relevant purchase market or the consortium imposes exclusive selling obligations on its chosen suppliers. For EU purposes, where the market shares of the parties on the purchasing market are less than 10 per cent and their share of the affected downstream market is also less than 10 per cent the agreement is unlikely to fall within Article 101 at all, and if such shares are in each case less than 15 per cent the agreement is likely to fall within Article 101(3).

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Joint selling of oil and gas Generally, joint selling arrangements have not been viewed sympa- II-11.36 thetically by the competition authorities. The principal concerns of joint selling arrangements are that: • they can facilitate the exchange of commercially sensitive information between the participants which could lead to a co-ordination of their behaviour within the market; • price competition can be reduced since the group will collectively set prices for the goods or services sold, and customers are unable to negotiate with suppliers on an individual basis and exploit price differentials between the various suppliers. This will be exacerbated if the group collectively holds a large market share; • the collective setting of other trading terms in the joint selling arrangement can also distort competition. The participants of the group may be limited in the range or specification of goods or services offered, the length of agreements, ancillary products or services offered; • smaller suppliers can be foreclosed from the market because of the power of the selling group; • some joint arrangements require their members to abide by quotas, limit the development of new capacity of members, require members to notify each other when they intend to increase output or require some element of market allocation – all these elements will distort competition within a market as a result of the co-ordinated and prescribed behaviour of the participants; • a combination of the above elements between participants in a joint selling group can be the basis of a wider industry cartel. Oil is sold onto a commodity market and is movable around the II-11.37 world. Co-venturers in a particular development generally sell on an individual basis. Joint sales rarely occur except in the case of small accumulations which are unlikely to represent an appreciable restriction on competition, and individual sales rarely include any clauses restrictive of competition. Gas sales agreements are a different matter. Gas is not a commodity to the same extent. In order to reach the ultimate consumer, it must be transported through a pipeline system (or, increasingly, be shipped in liquefied form). In the absence of a fully integrated global distribution system, gas field owners have traditionally looked for a long-term contract for sale of their gas to a gas distributor. In the absence of such a contract any single co-venturer may veto a development. Although gas is owned separately and therefore, in theory, each seller could contract separately, there are a number of difficulties with this:

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• the difficulty of negotiating lifting and gas balancing agreements; • the need for consistency as regards technical considerations such as landfall, pipeline size, production profile and processing arrangements; • the impact of swing factors, liquidated damages or other shortfall arrangements on the management of production; • the need to offer economic volumes and ease of administration to buyers. II-11.38 These factors have meant that joint selling was traditionally the norm in the UK. (Although each seller had an individual agreement with the buyer for the sale of its individual share of production, these contracts were negotiated on behalf of the co-venturers by the operator and were usually all on identical terms – from the competition law perspective, this constitutes joint selling.) This situation has altered as competition law concerns have come to the fore. The tendency to use long-term depletion contracts is also changing as the market for gas becomes more fragmented and shorter-term contracts become available, especially for small volumes. Competition decisions on oil and gas II-11.39 Joint gas sales agreements benefited from a specific exemption from the old UK competition regime under the Restrictive Trade Practices Act 1976, and retained a transitional exemption until 2005. No such exemption exists under the Competition Act or EU law and therefore joint selling of gas by co-venturers will in many cases fall within the prohibition on anti-competitive agreements. II-11.40 There are no published decisions of the UK or EU authorities on the application of competition law to gas sales agreements and so one must turn to press releases to determine the European Commission’s approach. The first decision in this area was the Britannia decision.63 In this case, a consortium of gas field developers jointly developing the Britannia gas condensate field in the UKCS sought negative clearance, or exemption, from the Commission for the practice of joint selling of their gas. The only interconnector operational at the time was between the UK and Ireland, and the Commission was satisfied that this was essentially a security of supply measure, designed to back up production in Ireland. In essence, therefore, the only market for gas produced on the UKCS was the UK. The Commission therefore took the view   Commission Press Notice, “The Commission Clears a Notified Agreement Concerning the Britannia Gas Field”, (1996) O.J. C291/10.

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that the agreement had no effect upon trade between member states and did not issue a formal decision (since it took the view that at the time the arrangement did not fall within the jurisdiction of EC competition law), but only a brief press release. However, a very different outcome would have resulted if the Commission had taken the view that it had jurisdiction. It has been indicated in a commentary on competition law written by Commission officials that, in this case, the Commission did conclude that the joint selling arrangement would have amounted to a restriction of competition within the scope of Article 101 if there had been jurisdiction, despite the parties being able to withdraw from the arrangement at will.64 In 1995, the JV agreement for the construction and operation of II-11.41 the UK-Belgium gas interconnector received a comfort letter from the Commission.65 The project as a whole was found to be pro-competitive, especially because it linked markets which previously for technical reasons were generally isolated. The joint venture company co-ordinated the activities of the participants in the construction and operation of the interconnector, but the marketing and use of the capacity of the pipeline remained substantially within the individual companies’ control. Ownership and capacity were shared in defined proportions. Capacity holders were free to provide transport capacity to others by assignment and by sublease. The Commission found that there was no indication that the market for the assignment and sublease of such capacity would not be competitive. As part of the arrangements, the JV company was, however, permitted to market spare transport capacity on behalf of the partners, which could lead to joint selling by the JV partners. The Commission found that such joint selling would occur only in limited circumstances (presumably because the parties would ask Interconnector UK Ltd (IUK) to market on their behalf only scraps of capacity). Nevertheless, this restriction could have been of significance given the fact that the JV partners, at least in the interconnector’s initial phase, would have 100 per cent of the relevant market for the transport of piped gas across the Channel. Despite finding this aspect of the joint venture to be a restriction of competition falling within Article 101(1), the Commission concluded that overall the pro-competitive effects of

  European Commission, XXVIIth Report on Competition Policy, Part Two (Report on the application of the competition rules of the European Union) (1997), at p 137. 65   Commission Press Notice IP/95/550, 1 June 1995, “The Commission Gives its Approval to a Joint Venture that will Contribute to the Integration of the European Gas Market”, available for download from http://europa.eu/rapid/pressReleasesAction.do?reference=IP/ 95/550&format=HTML&aged=1&language= en> (accessed 4 January 2017). 64

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the JV outweighed the limited restrictions associated with it and thus issued a comfort letter.66 II-11.42 In April 2001, the Commission decided to close its examination in the Corrib case, relating to the Corrib gas field off the west coast of Ireland, following the decision of the field owners to withdraw their application for an exemption to market the Corrib gas on a joint basis.67 The Commission had been expected to refuse the request for an exemption. During the notification process, the Commission had expressed a number of concerns and had questioned whether joint marketing of gas brought about any or sufficient economic benefits which would justify an exemption being granted. Competition Commissioner Mario Monti stated: “This case also confirms the Commission’s general policy not to tolerate joint selling, unless compelling reasons are provided as a justification.” II-11.43 In June and July 2001, the Commission issued statements of objections68 to all the companies producing gas in Norway, on the grounds that the joint sale of Norwegian gas carried out through the Gas Negotiation Committee (known as the GFU) was in breach of Article 101(1), as it fixed, among other things, the price and quantities of gas sold. The Commission welcomed the announcement by the Norwegian Government to discontinue the GFU joint sales. In its press release the Commission states, “As the European gas market is progressively being liberalised, it is of paramount importance that producers sell their gas individually so that those customers that can already choose their supplier benefit from real choice and competitive prices.” In 2003, a similar joint investigation by the Commission and the Danish competition authorities into similar behaviour by the incumbent Danish gas supplier, DONG, and its main gas producers   In a later enquiry, also closed without a formal decision, the Commission investigated why the interconnector reversed flow to export gas to the Continent during a period when UK prices were higher than on the Continent. They found no evidence of collusion between the shippers: the cause of the reversal was rigidities in the nomination and flow transition procedures in the pipeline but IUK and its members had agreed alterations to their rules to make these processes more flexible and to increase transparency. See Commission Press Notice IP/02/401, 13 March 2002, “Commission closes investigation into UK/Belgium gas interconnector”, available for download from http://europa.eu/rapid/ pressReleasesAction.do?reference=IP/02/401&format=HTML&aged=1&language=EN& guiLanguage=en (accessed 4 January 2017). 67  See Commission Press Notice IP/01/578 20, April 2001, “Enterprise Oil, Statoil and Marathon to market Irish Corrib gas separately”, available for download from http:// europa.eu/rapid/pressReleasesAction.do?reference=IP/01/578&format=HTML&aged=1 &language=EN&guiLanguage=en (accessed 4 January 2017). 68  See Commission Press Notice IP/02/1084, 17 July 2002, “Commission successfully settles GFU case with Norwegian gas producers”, available for download at http://europa. eu/rapid/pressReleasesAction.do?reference=IP/02/1084&format=HTML&aged=1&langu age=EN&guiLanguage=en (accessed 4 January 2017). 66

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(acting through a consortium known as DUC) was settled when the producers in DUC agreed to market their production individually and DONG released the producers from their obligation to offer all gas first to DONG.69 Of the above cases, only the UK-Belgium interconnector decision II-11.44 related to joint selling of transportation, all the others concerning arrangements for the joint sale of gas. To date, there have been no other reported cases concerning the joint sale of capacity within an upstream gas pipeline or of processing services in relation to gas.70 The downstream situation is complicated by the existence of the Gas Directive, part of the European Commission’s liberalisation measures, which is outside the scope of this chapter.71 Conclusions on joint selling of oil and gas The Commission’s guidelines and case law make it clear that, in its II-11.45 view, joint selling will always fall under Article 101(1). However, joint activities falling short of joint selling may not fall within Article 101(1) where the parties’ market share is below 10 per cent. Above 10 per cent, the impact of the joint activities would need to be considered on a case-by-case basis to determine, for instance, whether they allow the exchange of sensitive commercial information (particularly on market strategy and pricing) or if they influence a significant part of the parties’ final cost so that the actual scope for price competition at the final sales level is limited. The Commission’s press releases on the Corrib Field in the Irish Sea and on the Norwegian GFU arrangements give us a clear signal as to the Commission’s approach: it will be difficult to convince the Commission that joint selling is essential. They may be prepared to permit some technical and production-related issues to be determined jointly but it is difficult to see why, in many instances, pricing negotiations could not take place separately.

 See Commission Press Notice IP/03/566, 24 April 2003, “Commission and Danish competition authorities jointly open up Danish gas market”, available for download at http://europa.eu/rapid/pressReleasesAction.do?reference=IP/03/566&format=HTML&ag ed=1&language=EN&guiLanguage=en (accessed 4 January 2017). 70   There are a number of other European cases, settled informally, in relation to gas distribution – these largely concern the Commission’s efforts to eradicate territorial restrictions in gas sales contracts in order to create a single market in gas. 71  For a discussion of the downstream position see Cameron, Competition in Energy Markets, Chapter 13. 69

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Transportation agreements – joint supply or purchase of capacity II-11.46 Transportation agreements raise three potential issues under competition law: • first, joint decisions of the infrastructure owners and/or shippers with regard to tariffs and other matters raise issues of joint selling similar to those raised by joint sales of oil or gas; • second, depending on the definition of the relevant market, infrastructure owners may be found to be in a dominant position and the infrastructure to amount to an “essential facility” which, under EU case law, imposes obligations on the owners to provide access on fair, transparent and non-discriminatory terms; • third, joint purchasing of capacity by the shippers may raise issues similar to joint procurement of other services as mentioned above, aggravated by the fact that the shipping takes place outside the scope of the JV, occurring after the point at which each party takes ownership of its individual share. It is therefore more analogous to joint purchasing by neighbours. II-11.47 Discussions on joint selling of capacity in oil and gas pipelines and processing facilities may crudely be separated into those which do not affect price setting (chiefly technical issues) and those which either directly fix prices (direct discussions on tariffs to be quoted and/or agreed) or indirectly lead to the setting of tariffs (discussion of acceptable margins, cost influences etc.). Insofar as discussions, either directly or indirectly, concern the fixing of prices, then, whatever the parties’ market shares, the starting point is that the arrangements contravene Article 101(1). Very strong justification would have to be found to allow this to continue. II-11.48 It has been suggested that the specialisation block exemption72 might apply to these sales. The definitions of “product” and “production” in this block exemption are wide and, as well as covering the sale of gas, would appear to include the provision of transportation and processing services. Although Article 4(a) of the block exemption expressly states that the exemption provided for by the block exemption does not apply to specialisation agreements which, directly or indirectly, have as their object the fixing of prices to third parties, there is an exception where, in the context of a joint production venture which jointly distributes, the parties agree provisions which fix the prices that the production joint venture charges to its immediate customers. One might argue that joint sale of trans  Regulation 1218/2010, referred to at para I-11.17.

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portation capacity is analogous to the joint distribution of products by a group of manufacturers who have pooled their resources to make a product more efficiently than each is able to do on his own. However, there is no evidence to date that the specialisation block exemption has successfully been used to cover either the sale of gas by joint venturers or the construction and operation of infrastructure on which capacity is then jointly sold.73 Even if this block exemption could be used to justify joint selling, Article 3 of the block exemption provides that agreements complying with the requirements of the block exemption will be exempt from Article 101(1) only where the combined market share of the parties does not exceed 20 per cent of the relevant market. Insofar as discussions neither directly nor indirectly fix prices, II-11.49 nor do they include discussion of other sensitive commercial information, then the activities of the sellers will be presumed not to fall within Article 101(1) at all if the co-venturers’ market shares are, in aggregate, below 10 per cent of the relevant market and may merit an exemption above that level. However, the market for transportation services is particularly difficult to determine. There is no case law on market share of offshore transportation and processing in the context of Article 101. As noted above,74 in its merger decisions, the European Commission has assessed market shares in transportation of gas and oil by looking at the shares of capacity of each individual owner in all pipelines in which it has an interest, in each of the Northern North Sea and Southern North Sea. It has also looked at total ullage in all pipelines in such areas in which each owner has an interest, on the assumption that each owner has a veto over new business and therefore each owner effectively controls all ullage and not just their own share. While this analysis may be adequate for merger purposes, if a particular agreement was challenged under Article 101 it seems likely that a different approach would be taken. From the perspective of one offshore field, needing to transport its gas to the beach, the overall share of the owners of the nearest pipeline in other infrastructure in the Northern North Sea is of no relevance; all that affects its negotiations is whether it has any alternative method of exporting its gas; therefore the geographic market in that instance would seem to be essentially the same as the product market. In other words, it would consist of the potential export   In the DONG case referred to at para II-11.43, DUC attempted to argue that a previous block exemption for specialisation agreements covered their joint distribution activities; the press release states that DG Competition disagreed with the assessment of the parties and they – whilst maintaining their legal position – agreed to cease their joint marketing efforts. 74   See para II-11.27. 73

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routes which are economic for that field and in that limited market, market shares of any pipeline owner will likely be significant. II-11.50 There is a grey area in between the two categories of terms described above, and the practice has been used in some cases of making an initial joint offer with an indicative tariff or range of tariffs and then agreeing all other terms, at which point the parties separate and conclude final tariff terms which are inserted in separate but otherwise identical contracts. The validity of this approach has not, so far as we are aware, been tested before the competition authorities, but it is certainly preferable to agreeing prices jointly. II-11.51 The question of dominant position in relation to control of oil and gas infrastructure has not been the subject of a decision by the EU authorities, although analogies could be drawn to cases in other sectors, such as those involving port facilities.75 As the market has been defined by the European Commission in its merger cases, it seems unlikely that any such dominant position would be found in relation to a particular pipeline. However, as mentioned above, the methods employed by the European Commission (an aggregation of UK capacity or ullage of individual pipeline owners split between the Northern North Sea and the Southern North Sea) may not represent a useful or accurate indicator of market power in the case of a complaint over access to an individual pipeline. A more useful indicator of market power, particularly in relation to small accumulations, would be to look at market power on a more localised and individual basis, based on the geographical/economic/market context in which the pipeline and the relevant pipeline owners operate. If a subsea tie-back to a particular platform is likely to be the only means of export for a satellite field, then the owners of that potential host platform may be considered to be collectively dominant and the platform may be considered to be an “essential facility”. If the owners were found to be in a dominant position, then compliance with Article 102 would require that access to the infrastructure must be offered on terms that would not be considered to be an abuse, ie access must be offered on reasonable terms and must not be unreasonably refused. II-11.52 In practice, the focus of the debate over refusal of access to infrastructure has shifted to the Infrastructure Code of Practice (ICOP)76,

  For instance, port fees may in some cases be analogous to tariffs applied for access to infrastructure: for a discussion on recent cases on allegedly excessive port fees as abuse of a dominant position see M Lamalle, L Lindstrom-Rossi and A Teixeira, “Two important rejection decisions on excessive pricing in the port sector”, 3 (2004) ECCPN, at 40. See also the investigation into the port of Piraeus for alleged abuses of dominant position: P Aivatzidis, “Can Piraeus Keep Everyone Happy?”, 360 (2007) Fairplay, at 19 to 20. 76  The ICOP is available from the Oil & Gas UK website at http://oilandgasuk.co.uk/ 75

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developed by the Department of Energy and Climate Change (DECC) and Oil & Gas UK (and their predecessors) among others, in response to the perceived difficulty of obtaining access on fair and transparent terms to existing infrastructure, and now sponsored by the Oil and Gas Authority (OGA). Particularly for smaller discoveries, the cost of infrastructure access could be the critical factor in marginal economics of development. The Code requires tariffs to be fair, reasonable and non-discriminatory, but there is little guidance on how these principles will be applied in practice. Moreover, it is voluntary and there is no penalty for failure to comply with it, other than the risk that a party may institute the procedure established by the ICOP in order to ask for terms to be imposed by the OGA using its statutory powers (or, in future, that the failure to offer reasonable terms may be deemed a breach of the obligation to maximise economic recovery).77 On the other hand, there are considerable costs and risks to using competition law in this situation. In its Guidance on Disputes over Third Party Access to Upstream Oil and Gas Infrastructure, the OGA states: “Although the CMA has not issued specific guidance on the application of [the Competition Act 1998] to upstream oil and gas infrastructure (including on the definition of the relevant market), it considers that infrastructure owners are unlikely to have breached the Chapter II prohibition on abuse of a dominant position where they have had due regard to the Secretary of State’s principles for setting terms … in arriving at the terms that they offer to, and agree with, third parties.”78

Therefore, although there is nothing to prevent a party bringing a II-11.53 claim under Article 102 to the CMA, the CMA may well take the view that if the Code has been applied, it would not be an appropriate use of their resources to investigate further. On the other hand, the CMA’s advice on the Code stated clearly that it reserved the right to respond if a complaint was received about the way the Code operated in practice. Because  of the  obligations of national authorities with regard to the implementation  of  EC competition law under the Modernisation Regulation,79 the CMA would need to

product/code-of-practice-on-access-to-upstream-oil-and-gas-infrastructure-on-the-ukcontinental-shelf (accessed 4 January 2017). The ICOP is also discussed extensively in Chapter I-7. 77   See para II-11.67. 78  OGA, Guidance on Disputes over Third Party Access to Upstream Oil and Gas Infrastructure, available at www.ogauthority.co.uk/media/2712/oga_guidance_disputesover-third-party-acccess-to-upstream-infrastructure.pdf (hereinafter “OGA Guidance”), at para 24 (accessed 4 January 2017). The Guidance is discussed further in Chapter I-7. 79   Regulation 1/2003.

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engage in  a proper  investigation of any complaint which appeared well founded, and there is the possibility that the CMA would engage more fully with this issue than they have done to date. II-11.54 Issues regarding exchange of commercial information also arise in relation to joint selling of infrastructure capacity. The type of information which would fall into the “commercially sensitive” category can usefully be considered by reference to what would be commercially confidential information, were the co-venturers in fact selling on a divided rights basis, and therefore very conscious of their position as competitors. This may include: tariff terms with customers (including formulae and indexation provisions); volume of capacity in any contract (which raises some interesting questions about the role of the operator in dealing with nomination/allocation); specific terms of business not common to the operation of the pipeline; marketing strategies/business planning, for example what customers are being approached on what terms, and the state of current negotiations; pricing policy (for example in terms of the owner’s group’s approach to acceptable rates of return); other information, which in normal conditions of competition, a co-venturer would regard as confidential because to share it with a competitor would be to give that competitor an advantage over the co-venturer, or could lead to collusion. Benchmarking or industry data-gathering exercises? II-11.55 The industry has a long history of collaboration, benchmarking and trade association activity designed to increase the efficient exploitation of the hydrocarbon resources of the UKCS, and this approach is now part of the regulatory regime as a plank of the MER Strategy to which industry participants are bound.80 However, it is very important not to be complacent about the potential competition law implications of these activities. Exchange of information between competitors can be anti-competitive because it can result in concerted practices or reveal a competitor’s commercial strategies. As such, great care needs to be taken over the exchange of industry data. Table II-11.1 sets out some of the factors which determine whether an exchange is likely to be permitted.  Collaboration can be seen at every level in the industry: from licence-holding and JOA arrangements to the very way that the Government has traditionally regulated: by persuasion, committees and initiatives, rather than by direct rule. The Government has actively encouraged the sharing of information through such initiatives as UKDEAL and its involvement in groups like PILOT, and the OGA is expanding such initiatives. Nor is such information-sharing of purely technical material: consider, for example, the requirement to share key elements of commercial information in access to infrastructure situations, discussed at Chapter I-6. Collaboration is seen as one of the industry’s great strengths and crucial to its ongoing success.

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Table II-11.1  Risk Matrix for Information Exchange Safe

Dangerous

The relevant data is available publicly in any event

The relevant data is confidential

The relevant data is entirely technical

The relevant data is commercial

The data will be published in an aggregated form or it will be published anonymously and in such a way that no individual company’s data will be identifiable

The data will not be aggregated and the source of the data will be identified/identifiable

The data will be available only to regulatory authorities or to an industry task force set up to deal with a specific public interest issue

The data will be circulated freely around the industry

The data will be available only to potential customers

The data will be available to competitors

The data is historic

The data is current or relates to future plans

Vertical agreements – are they ever a problem? Many procurement contracts between an operator and a contractor II-11.56 contain no restrictions on competition at all. If there are any restrictions, particularly in the form of tying up large parts of the market or the capacity in the industry for a particular product or service for an extended period, then it will be necessary to consider whether the agreement will fall within a block exemption or qualify for an individual exemption. The EU has issued a block exemption for vertical agreements,81 which under UK competition law applies also to agreements where the UK authorities have jurisdiction. It  See Commission Regulation 330/2010 on the application of Article 101(3) of the Treaty on the Functioning of the European Union to categories of vertical agreements and

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applies only where the parties have market shares not exceeding 30 per cent.82 It has a number of other restrictions, the principal ones relevant in this context being those set out at para II-11.58. II-11.57 Because some of the limits to the exemption are technical and their interpretation is not yet fully understood, it is always best to have any vertical agreement reviewed by a competition lawyer if it restricts competition, ie if it places any restrictions on the ability of the parties to do business with third parties. Examples of restrictions would include: any limitations on the persons to whom, territories in which, or prices at which goods may be on-sold; or provisions which directly or indirectly (eg through the use of pricing incentives) oblige a seller to sell all of its production of a particular product to the buyer, or a buyer to buy most or all of its requirements of a particular product only from the seller; or clauses requiring a seller to offer the buyer the best prices it offers other customers or to allow the seller to match prices offered to the buyer by other sellers. II-11.58 Which vertical agreements may cause problems? • Price fixing agreements are not given the benefit of the block exemption (although maximum resale prices are allowed, as are recommended minimum prices where these are not binding);83 • Vertical agreements entered into by dominant companies may be exempted under Chapter I/Article 101 but still infringe the Chapter II /Article 102 prohibition; • Market shares over 30 per cent – agreements cannot benefit from the block exemption and will need to be analysed to see if they qualify for individual exemption; • Agreements where non-compete clauses on the buyer are for indefinite periods or for more than five years (including clauses which are tacitly renewable beyond five years) or where non-compete obligations survive termination of the agreement;84 • Any restriction on the territory or customers to which the buyer can sell (with certain exceptions); • Agreements between competitors (with certain exceptions); • Agreements involving associations of businesses (with certain exceptions); concerted practices (2010) OJ L102/1 and the related Guidelines on Vertical Restraints (2010) OJ C130/1. 82   Regulation 330/2010 Art 3. The relevant market share for the purchaser is its share on the purchasing market, not the downstream market. 83   Regulation 330/2010, Art 4(a). 84   For these purposes, EU law treats any contract for the purchase of 80 per cent or more of an undertaking’s requirements as a non-compete obligation.

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c omp e t i t i o n l aw 397 • Agreements whose primary object is the assignment or licensing of intellectual property.

The interaction of MER UK and competition law. Collaboration forms one of the core policy themes under MER: II-11.59 its importance was emphasised in the Wood Review and section 9A of the Petroleum Act 1998 (as amended) defines the “principal objective” as being the objective of maximising the economic recovery of UK petroleum, partly through “collaboration among [relevant] persons”. Consequently, it has been correctly stated that collaboration has been “elevated from being a matter of general practice to a statutory obligation”.85 It was quickly identified by the industry that this new focus on II-11.60 collaboration becomes fraught with difficulty where the outcome of that collaboration risks being deemed anti-competitive. Examples of projects conducive to MER UK which could give rise to such issues86 include: • exchange of commercially sensitive information between a number of joint ventures in a region with a view to developing a regional plan; • an agreement between a number of joint ventures to use a particular export route in order to render their developments and/or that export route viable; • setting of industry standards for particular goods to minimise “bespoking” and reduce costs; • joint purchasing of goods or services by a number of operators to reduce costs; • sharing of data on proposed shutdowns in order to minimise impacts on production; • benchmarking of data on production efficiency. A particular issue arises for the industry in relation to the exchange of II-11.61 information on future reserves because of the Commission’s guidance on horizontal co-operation agreements.87 This guidance notes that Article 101 outlaws agreements the object or effect of which is to  Oil & Gas Authority, Competition and Collaboration, available for download from www.ogauthority.co.uk/news-publications/publications/2016 (accessed 4 January 2017) (hereinafter “OGA, Competition and Collaboration”). 86   Note that it not suggested that any of these scenarios constitute an infringement but merely that an analysis of the competition law issues raised would be required. 87   Commission Notice – Guidelines on the applicability of Article 101 of the Treaty on the Functioning of the European Union to horizontal co-operation agreements of 14 January 2011 (2011/C11/01) available for download from http://eur-lex.europa.eu/legal-content/ EN/ALL/?uri=CELEX:52011XC0114(04) (accessed 4 January 2017). 85

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restrict competition and that restrictions “by object” are those which by their very nature have the potential to restrict competition. Where an anti-competitive object is established it is not necessary to consider the actual or potential effects of the agreement on the market. However, the Commission notes that it is the settled case law of the Court of Justice that in order to determine whether an agreement has an anti-competitive object, it is necessary to consider its content, its objectives and its economic and legal context. Exchanging information on companies’ individualised intentions concerning future conduct regarding prices or quantities is particularly likely to lead to a collusive outcome. Such exchanges may allow parties to arrive at a common higher price level without triggering a price war. Moreover, it is less likely that information exchanges concerning future intentions are made for pro-competitive reasons than exchanges of actual data. Information exchanges between competitors of individualised data regarding intended future prices or quantities should therefore be considered a restriction of competition by object. In essence, the Commission is highly suspicious of such exchanges and finds it hard to envisage that they could fulfil the conditions of Article 101(3). The difficulty of this analysis is that it ignores the “legal and economic context” which the Commission earlier noted should be taken into account.88 In the context of the offshore oil and gas industry, while it is difficult to see any justification for the exchange of pricing information, exchange of information regarding future production may be essential to the efficient development and utilisation of infrastructure, and the resulting maximisation of economic recovery, and should not be considered automatically suspect. However, companies may be cautious about pursuing such exchanges in the absence of some guidance on the issue in the particular context of offshore exploration and production, which could perhaps be given by the Competition and Markets Authority in the form of informal guidance.89 II-11.62 In its letter to the Secretary of State at DECC in December 2015,90

 And indeed, this approach of the Commission has been criticised by the European Court in its judgments in cases including Groupement des cartes bancaires (CB) v European Commission (C-67/13 P), available for download at http://curia.europa.eu/ juris/liste.jsf?num=C-67/13&language=en (accessed 4 January 2017) and Judgment of the Court (Second Chamber) of 19 March 2015, Dole Food Company, Inc. and Dole Fresh Fruit Europe v European Commission (C-286/13 P), available for download at http:// curia.europa.eu/juris/liste.jsf?language=en&num=C-286/13 (accessed 4 January 2017). 89  A possibility which was envisaged in the CMA’s letter to DECC, note 90 infra, at para 12. The CMA’s guidance on informal opinions is available for download at www. gov.uk/government/publications/guidance-on-the-cmas-approach-to-short-form-opinions (accessed 4 January 2017). 90  Available for download at www.gov.uk/government/publications/energy-bill-cmarecommendations-to-ministers (accessed 4 January 2017). 88

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advising on the Energy Bill, the Competition and Markets Authority (CMA) noted that the OGA was bound to act in accordance with competition law91 and emphasised the need for the OGA to ensure that it did not, even inadvertently, encourage or facilitate breaches of competition law. The CMA noted that the Energy Bill’s provisions (particularly the OGA’s obligation to promote collaboration and its powers to attend meetings and gather information) would potentially create circumstances in which the OGA could facilitate anti-competitive exchange of information among undertakings active in the sectors it regulates. While accepting that this was not the intention of the Government, and that the Bill’s provisions contained protections for commercially sensitive information, the CMA noted that the circumstances could facilitate sharing of such information by others which, if it occurred, could dampen competition or encourage other breaches of competition law. The CMA referred specifically to exchange of future pricing intentions or capacity utilisation information (but regrettably did not consider the issue raised above regarding the necessity, in some contexts, to exchange reserves data, in order to determine the most economically productive regional development plan or use of infrastructure). The duty to promote collaboration could also give rise to a risk of anti-competitive agreements being entered into. However, the CMA acknowledged that agreements on technical and operational matters with no material commercial implications and agreements that give rise to significant efficiencies were unlikely to raise concerns under competition law, and work to improve production efficiency would be expected to fall into this category. Finally, noting that unwarranted caution about the potential application of competition law to beneficial activity risks chilling legitimate activity, the CMA noted that it can, in cases raising novel competition issues, issue short form opinions. In other cases, it would be up to the OGA to ensure that it carried out an assessment of agreements of which it becomes aware to ensure that the benefits outweigh any restrictions on competition. The CMA also counselled that the OGA should be careful in exercising its powers not to favour particular players or create barriers to entry, whether through technical standards, levels of levies and fees or in its licence award processes. The concerns of both the CMA and industry in this regard were II-11.63 recognised in the MER UK Strategy,92 which provides that the obligations it describes must be read subject to the Safeguards that  The CMA also noted that the OGA could be at risk of being found in breach of the UK’s duty of sincere co-operation under Art 4(3) of the TFEU. 92  Available for download at www.ogauthority.co.uk/regulatory-framework/mer-ukstrategy (accessed 4 January 2017). 91

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also form an integral part of the Strategy. The first such Safeguard provides that no obligation imposed by or under MER UK permits or requires any conduct which would otherwise be prohibited by or under any legislation – including competition law, which is expressly mentioned. II-11.64 In its publication Competition and Collaboration93 the OGA has urged industry to consider the benefits of collaboration when determining how to act in light of competition law. The OGA has also attempted to offer some assistance to industry when navigating this area by drawing attention to certain exemptions and exceptions that exist under the competition law rules, principally those relating to pro-competitive outcomes, de minimis arrangements and block exemptions. • An agreement or conduct that might otherwise infringe competition law prohibitions may be excepted if it can be shown to produce pro-competitive benefits that are shared with consumers. Those benefits must outweigh any anticompetitive impacts and the measures must be no more restrictive than necessary to achieve those benefits.94 The OGA is of the view that in a highly competitive market, such as that for the exploration for crude oil and gas, any project which is intended to increase supply should, in turn, contribute to a reduction in prices for those products and, ultimately, reduce the prices paid by consumers. On that basis, the OGA considers there “is little reason to believe that ultimately consumers will not benefit from the development and production of such additional resources”. The OGA makes a number of points in relation to the assessment of efficiency gains: • When evaluating gains, it is important to consider the “counter-factual”, ie what the result would be if the proposed activity did not take place. For instance, could one operator afford to act by itself on a particular issue or would the project simply not proceed if it was not done jointly? • The particular nature of the oil and gas market and the problems peculiar to it must be taken into consideration. • Efficiencies may emerge from the development of new production technologies and methods, from synergies resulting from the integration of existing assets, from collaboration that allows for better planning of production, reducing the need to hold expensive inventory  OGA, Competition and Collaboration.   See paras II-11.16 and II-11.17 above.

93 94

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c omp e t i t i o n l aw 401 or allowing for better capacity utilisation, or through quality improvements. • The creation or improvement of tangible and intangible infrastructure on which the EU economy depends is a relevant benefit, and if parties can show that the infrastructure could not be built at all without their collaboration then the agreement may fall outside the scope of Article 101 entirely, subject to the appropriate competitive safeguards being in place. • The OGA goes on to highlight that where competitors have low market shares, there may not be an appreciable impact on competition,95 and notes that in 2015, total UK production of both oil and gas accounted for only 1 per cent of global supply, and UK gas production accounted for 17 per cent of European gas production (excluding Russia) and less than 10 per cent of total European gas demand. • Finally, the OGA reminds industry of those exemptions applying generally to any agreement where certain requirements are met. These block exemptions are available for particular categories of agreement, such as technology transfer agreements and research and development (R&D) agreements (both of which are relevant to the OGA’s Technology Strategy). These agreements will be exempt so long as they do not contain any “hard-core” restrictions such as price fixing, market sharing or limitations of output or sales, or any excluded restrictions such as “no-challenge” clauses for intellectual property rights. In order for the R&D exemption to apply, all the parties must have full access to the final results of the R&D for the purposes of further R&D and exploitation.

The OGA is firmly of the view that “[competition] considerations II-11.65 should not be used as an excuse not to comply with the obligations set out in the MER UK Strategy, unless they are well-founded”.96 However, the TFEU and Competition Act regimes are based on the principle of self-assessment. The onus of determining whether an agreement or conduct is competition law compliant rests with the individual business. The fact that an agreement is sanctioned by the OGA does not necessarily prevent it from falling foul of national or European competition law.97 Therefore, while the OGA highlights certain factors for industry to consider, it acknowledges that the

  See paras II-11.13 and II-11.14 above.  OGA, Competition and Collaboration, para 22. 97  As noted by the CMA in its letter (see note 90) and acknowledged by the OGA in Competition and Collaboration (note 85). 95 96

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ultimate decision (and ultimate responsibility) remains solely with the individual business. II-11.66 Businesses have different approaches to risk, particularly in an area such as competition law where the rules are not always readily capable of application to particular sets of circumstances. Some companies (particularly, perhaps, those which have been subject to investigation by competition authorities in the past and have experience of the amount of management time and expense which an investigation may eat up, even if ultimately there is no finding of infringement) will err on the side of caution when assessing the risk of infringement. However, against that risk they will now need to balance the risk of being found to have failed in their obligation to maximise economic recovery and being made subject to sanctions. In any dispute with the OGA as to whether an activity is MER-compliant, or is indeed contrary to competition law and therefore cannot be required of a relevant person, it is likely that the relevant person affected will need to provide evidence justifying its view that the activity is an infringement of competition law and therefore it should not be required to undertake it. This will in turn require it to conduct substantive analysis of the competitive impacts of the activity, whereas in the past it might have taken the easier option of simply declining to take part. II-11.67 The area where the industry is likely to encounter the most apparent conflict between MER UK obligations and competition law appears to arise in the area of development and utilisation of infrastructure, and, in particular, where there is a request for the exchange of information regarding future production intentions. As noted above, information regarding future production quantities is treated in the Commission’s guidelines as a restriction by object, and it appears that the Commission is loath to accept that there could ever be a justification for such an exchange. However, the Commission’s own guidelines also accept that the economic context must be taken into account, and it would be deeply regrettable if concerns over the exchange of such data prevented the development of some fields taking place or resulted in the premature decommissioning of existing infrastructure. What, then, is the industry to do? Potential solutions which have been used in the past include the use of publicly98 available estimates of future production such as those issued by Wood Mackenzie in place of the parties’ own estimates, or the use of independent third parties to receive such data from the parties and produce aggregated and anonymised results; however, these approaches may not be sufficient in cases where parties

  Or quasi-publicly available, as payment for a subscription service may be required.

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need accurate individual field profiles in order to agree significant investment or alter their behaviour in other material respects. If these solutions are not practicable then the parties may need to carry out a substantive analysis of the competition risks – given the Commission’s guidance, this is an area where a short-form opinion from the CMA, available to the industry as a whole, based on a suitable real-life case study, would be extremely useful.

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CHAPTER II-12 LAW AND TECHNOLOGY IN THE OILFIELD Martin Ewan

THE IMPORTANCE OF INNOVATION II-12.01 The United Kingdom Continental Shelf (UKCS) passed the point of peak oil production in 1999 and is in decline.1 The core areas of the UKCS – the southern, central and Northern North Sea – are mature; the area is well explored; and those prospects that remain are both smaller and more difficult economically to exploit. Up to 5 billion boe within known discoveries are currently considered commercially unviable for development,2 with around 40 per cent of these reserves being “unconventional”. This means that they are highpressure high-temperature (HPHT), heavy oil or in deep water – and therefore extremely technically challenging to extract. II-12.02 For a number of reasons, the UKCS is also a relatively expensive place in which to operate. UKCS projects must compete for priority and project funding on a global basis and factors including fiscal and regulatory policy, the harsh natural environment3 and the highly complex facilities and skilled personnel required to operate offshore all contribute to a relatively high industrial cost base.4   Albeit that Oil & Gas UK (OGUK) considers the range of total estimated recoverable potential of the UKCS to nevertheless stand at 10–20 million boe – a worthy prize, as per OGUK Economic Report (2016), at p 24, available for download at http://oilandgasuk. co.uk/economic-report-2016.cfm (accessed 1 April 2017) (hereinafter “OGUK Economic Report (2016)”). 2   As estimated by Wood Mackenzie in OGUK Economic Report (2016), at p 26. 3   See para II-12.01. 4  The conditions created by the recent oil price drop has seen the industry achieve improved cost control, with unit operating costs dropping from as high as $30/boe in 2014 to $16/boe by the end of 2016, as per OGUK Economic Report (2016), at p 38. 1

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For the foregoing reasons, innovation focused on the twin II-12.03 pressures of technical challenge and cost containment is necessary to drive the next generation of North Sea activity. Examples of current activity include developments in subsea technology and automated (usually unmanned) platforms to reduce costs;5 the use of 4D seismic to identify precision-drilling opportunities to access small pockets of by-passed hydrocarbons, thereby increasing recovery from, and deferring the decommissioning liabilities of, existing fields; and developing techniques for exploiting the types of unconventional reserves mentioned previously. In the frontier province of the Atlantic Margin, the focus has been on improved seismic imaging technology (many prospects lie below dense, basaltic sills) and on the adaptation of deepwater operations developed for the Outer Shelf of the Gulf of Mexico and for West African and Brazilian waters to the more hostile conditions of the North Atlantic. Over the last 50 years, innovation has been at the heart of the II-12.04 development of the North Sea, and innovation, both in processes and technology, remains the dominant prerequisite to slowing the basin’s rate of decline and ensuring its future. Set against the backdrop of Sir Ian Wood’s MER agenda, technology is all the more crucial and assumes a central role on any oil company’s corporate agenda.

THE COMMERCIAL CHALLENGE FOR INNOVATORS It is axiomatic that innovation in any industry is challenging. Those II-12.05 engaged in technological innovation are by definition operating at the outer edge of their discipline and seeking to solve hitherto unresolved problems. But there are also significant commercial challenges which compound the technical ones. In sectors where innovation is demand-led (ie driven by customer requirements rather than academic investigation), there may be multiple competing efforts, each seeking to solve the same practical technical problem. As a result, in the early stages of development, there may be a variety of technical solutions or basic product designs for the same task. Only one – or at best a few – of these will ultimately succeed in the commercial marketplace. There is, therefore, a distinct “first-mover” advantage for technical II-12.06 innovators. The first viable product which achieves broad field acceptance tends to benefit from (1) network effects (whereby both the innovator’s suppliers and customers build experience of the product and adopt congruent behaviours which make them reluctant

  By eliminating the need for a permanent presence on board, health and safety risk is also reduced.

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to change to an alternative); (2) learning curve effects (the innovator’s staff become the leaders in the field, and its solutions benefit from the lessons learned in earlier operations); and, potentially – although because of the comparative size of the oil and gas target customer market this is of less importance than for many consumer products – (3) economies of scale. If an innovative company misses the window of opportunity to become the dominant, or at least a significant, supplier, then, regardless of how technically superior its solution might be, it will be extremely hard to dislodge the incumbent to achieve commercial success. II-12.07 In order to prove the viability of a product, the innovator must carry out field testing to an appropriate standard. With this requirement in mind, it is perhaps worth pausing to consider the contracting structure of the upstream oil and gas industry in the UK, which over the past 30 years has developed a tiered nature. Operators directly undertake relatively few operations; rather, they contract the operations to what can best be described as the oligopoly of “tier one” contractors that emerged from the major consolidation of the service sector in the early 1990s. These tier one contractors each offer a broad (and generally the entire) range of services needed for a particular function. For example, the tier one contractors in the drilling and well operations sector are each capable of providing all necessary services and products required to drill a well, mostly from their own internal resources. Only those products and services which are infrequently required, or are so highly specialised as to be uneconomic to develop internally, are purchased from second tier suppliers. II-12.08 Operators are therefore increasingly accustomed to the “one-stop shop” approach offered by the tier one contractors, with all the service benefits of co-ordination and interoperability which that implies. However, the side effect of this structure is that these tier one contractors can act as a gateway to the operators, filtering customer requirements that might otherwise drive innovation and passing to second tier suppliers only those requirements that they themselves are unwilling or unable to deliver. II-12.09 The practical difficulties faced by an innovative small company in gaining the field trial experience which is crucial to proving a concept can be significant – even fatal. The author is aware of technological innovations that have left the UK not because they were not of value to UKCS operations, but because their developers were unable to gain the early field experience necessary to commercialise the product. It is also notable that many innovative start-ups choose to exit by way of trade sale to a first-tier contractor, rather than to pursue development of a global presence themselves. Of course, many of the tier one contractors are also hotbeds of innovation themselves, possessing both the financial resources to

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attack big problems and the necessary access to both field testing and markets. These challenges are, of course, commercial rather than legal, II-12.10 but the practising lawyer will recognise the importance of not only preserving the value of innovation through effective protection of intellectual property rights, but also obtaining appropriate contractual protection against the backdrop of these fundamental industry dynamics. THE LEGAL PROTECTION OF OILFIELD TECHNOLOGY: AN OVERVIEW OF INTELLECTUAL PROPERTY The legal protection of technology is largely the province of intel- II-12.11 lectual property (IP) law. More specifically, it is the areas of patents, copyright and confidential information6 which form the bedrock of law in this area.7 For ease of reference, a note of the main features of each topic follows, together with examples of its application to the industry. Patents Patents are potentially the most commercially valuable species of II-12.12 IP, as they provide a monopoly to the holder to exploit the relevant invention, process or use for a particular period of time (up to 20 years in the UK).8 A patent holder has the right to stop others from making, using, importing, disposing of or offering for disposal the patented subject matter.9 In order to obtain a granted patent, the Patent Office (now II-12.13 operated as part of the Intellectual Property Office) must be satisfied   Although not strictly a species of “property” right, the area of confidential information has come to be accepted under the heading of IP law. For an academic analysis of the nature and results of the distinction, see W Cornish, D Llewelyn and T Aplin, Intellectual Property: Patents, Copyright, Trade Marks and Allied Rights (8th edn, 2013), paras 8.50 et seq. 7  The focus of this chapter is technology developed for application in the oilfield, and therefore the law of trade marks and of designs, although significant branches of IP law in their own right, are excluded from consideration, as being of comparatively little practical relevance. The application of database rights, in terms of the Copyright and Rights in Databases Regulations 1997 (SI 1997/3032), is an area which has thus far made little obvious impact on the industry (despite the fact that it could be tremendously relevant, in terms of its application to seismic data, for example). For this reason – and as it is largely analogous to copyright in its approach – a specific treatment of this area within this chapter was also deemed otiose. 8   Patents Act 1977, s 25(1). An as-amended version of the Act can be downloaded from http://legislation.gov.uk/ukpga/1977/37/contents (accessed 1 April 2017). 9   Patents Act 1977, s 60. 6

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that the subject matter of the patent application: (1) is novel10 (ie not copied or already existing in the public domain); (2) displays an inventive step11 which is not an obvious development to someone skilled in the relevant art;12 (3) has a practical/industrial use;13 and (4) is not one of the statutorily excluded subjects.14 II-12.14 A patent holder (or applicant) has the option of exploiting the patent itself (eg by manufacturing and selling the relevant product or utilising the relevant process); or of licensing the patent to a third party15 (eg in return for payment of royalties); or of selling the patent. As an item of incorporeal moveable property, assignation/ assignment is the mechanism of disposal and a patent can also be offered in security.16 II-12.15 It is important to remember that, notwithstanding various international co-operative measures, a patent is fundamentally a national instrument, offering protection only in the jurisdiction of grant. The European patent system, which provides a mechanism by which a single patent application may be filed at the European Patent Office under the European Patent Convention to obtain patents in various signatory states, does not produce a “European” patent enforceable throughout the EU – but rather a set of national patents, each in the specific designated jurisdictions. Similarly, the “international patent system”, established under the Patent Co-operation Treaty,17 allows a single application to provide initial protection in relevant states, but individual national applications must be made during the national/regional phase.18 II-12.16 The Patent Office does not maintain industry-specific statistics which would show the level of usage made by the oil industry of the patent system, but reported cases illustrate clearly that expensive and complex patent disputes are fought – particularly by and between oil service companies determined to protect their own patents and/ or prevent a competitor from obtaining the state-backed monopoly which a patent constitutes. These can cover a wide variety of industry technologies, including heat-insulated pipe-in-pipe assemblies for use   Ibid, s 1(1)(a).   Ibid, s 1(1)(b). 12   Ibid, s 3. 13   Ibid, s 1(1)(c). 14   Ibid, s 1(1)(d). 15   Ibid, ss 30(4) and 31(4). IP licensing is discussed below in more detail at paras II-12.48ff. 16   Patents Act 1977, ss 30(2) and 31(3). 17   The Patent Co-operation Treaty of 19 June 1970. The Treaty is available for download in its as-amended form at www.wipo.int/pct/en/texts/articles/atoc.htm (accessed 1 April 2017). 18   Part II of the Patents Act 1977 governs European and international patent applications. 10 11

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on seabed pipelines,19 roller-cone drill bits20 and offshore accommodation modules.21 Copyright Although the terms “literary” and “artistic” works may not intui- II-12.17 tively seem particularly relevant to the oil industry, it is through these headings that the main application of copyright law flows into the activities of the North Sea. Copyright will exist in almost any document, whether an instruction manual, a field report, a purchase specification – all of which tend to fall within the category of “literary work”;22 and almost any technical drawing, photograph, diagram or schematic – all of which tend to fall within the category of “artistic work”.23 Unlike some overseas jurisdictions, no formal registration process is required to create copyright in the UK – all that is needed is that the relevant work be recorded24 in some semi-permanent form. This usually means being written down or electronically recorded. The only major prerequisites to an item being protected by II-12.18 copyright are that it is: (1) original25 (ie not copied from somewhere else) and (2) substantial enough to constitute a “work” (this latter prerequisite is qualitative, rather than quantitative, but case law26 suggests that something more than a single word is required to be a “literary work”). Once a work has been created, a copyright holder has the right to II-12.19 authorise or prohibit any copying of it,27 including issuing copies28 or renting or lending the work to the public.29 The copyright holder therefore has the option of exploiting the copyright itself (eg by reproducing the training materials and selling them with training services; or by reproducing technical manuals and selling them); or of licensing the copyright to third parties. Licensing to third parties

  ITP SA v Coflexip Stena Offshore Ltd 2004 SLT 1285.   Halliburton Energy Services Inc v Smith International (North Sea) Ltd [2006] RPC 2. 21   Consafe Engineering (UK) Ltd v Emtunga UK Ltd [1999] RPC 154. 22  Copyright, Designs and Patents Act 1988, s 3(1). An as-amended version of the Act can be downloaded from http://legislation.gov.uk/ukpga/1988/48/contents (accessed 1 April 2017). 23   Copyright, Designs and Patents Act 1988, s 4. 24   Ibid, s 3(2). 25   Ibid, s 1(1). 26   Exxon Corporation and others v Exxon Life Insurance Consultants International Ltd [1982] Ch 119. 27   Copyright, Designs and Patents Act 1988, s 17(1). 28   Ibid, s 18. 29   Ibid, s 18A. 19 20

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can be either explicit or implied and is discussed below in more detail.30 II-12.20 The wealth of items in which copyright can subsist means that this is an area which frequently raises questions of infringement (often being quite involuntary and innocent). For example, due to the mobility of employees and contractors in the industry, training manuals showing best practice often find their way from company to company. The author has seen situations where training materials produced by one company have been copied by another and incorporated into its training programme; and where materials produced by various links in the supply chain, such as manufacturing drawings or recommended maintenance procedure specifications prepared by original equipment manufacturers, have similarly been taken by individuals for use in subsequent jobs. In many cases, the individuals concerned have no idea that their actions may be breaching copyright and creating liabilities for them and/or their employer. There is often a tacit inclination to believe that the materials are able to be used without restriction, either due to them being in the public domain or due to the prevalence of the practice of copying. In any event, significant liabilities can arise as the result of this practice and companies which do not adequately address the education and actions of their workforce may face hefty damages claims and even potential criminal liability.31 II-12.21 The fact that a large number of skilled engineers in the industry are all drawing on a collective pool of ideas, experience and principles to meet their current challenges also illustrates one of the important – yet often fine – distinctions of copyright law. As a point of principle, the law will not protect someone’s mere idea. It will only protect the specific expression of that idea in a tangible form (whether that tangible form might be a written document, a drawing or whatever). It is nevertheless extremely difficult to define exactly where the dividing line is between a work which the law ought to protect from illegitimate copying and the “common stock” of concepts (whether engineering, physical, geological, seismological or otherwise) which might incidentally be expressed in technical specifications or drawings, and which should be capable of future application or development, without risk of infringement. II-12.22 Overseas judgments have been quoted with approval to the effect that “the law does not prevent one [engineer] from following in the footsteps of a colleague; [but] it does prevent him from copying the plans of his colleague so as to enable him to follow in those footsteps;   See paras II-12.48ff.   The topic of IP infringement, whether incurring civil or criminal liabilities, is outwith the scope of this chapter.

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and it does prevent him from physically reproducing those footsteps and thereby following them”.32 Thus, it would be perfectly legitimate for an individual engineer to inspect drawings or a tool in operation and, having appreciated the principles by which it operates, to return to his own drawing board to design his own tool, provided that the new design does not reproduce a substantial part of the original. The dividing line is often unclear and, as ever, the individual facts and circumstances will play a defining role. Copyright in software Another facet of the breadth of copyright is that it is also the II-12.23 principal method by which the law has chosen to protect software.33 The significance of software to the oil industry (and indeed almost any modern industry)34 does not require to be asserted. Software is ubiquitous, supporting not only almost every conceivable aspect of business, but also being embedded into the tools and equipment of the industry. It seems natural that copyright should afford protection to the expression of some concept in a programming language, but a computer program in any form is deemed to be a “literary work”35 and therefore capable of protection in the same way, and subject to the same conditions as any other. In the case of an article or a book, the concept of “copying” II-12.24 (which is the key act restricted by copyright) connotes something along the lines of a photocopy. However, the statutory restriction is much broader and specifically refers to “storing the work in any medium by electronic means”.36 Thus, when a program is uploaded or run on a PC, it is being copied – even although there is no discrete “pirate” copy being produced in the way that one might otherwise tend to conceptualise copying. Unlike a book, however, the making of entire, “necessary” back-up copies is permitted by statute.37 The concept of licensing38 is used (either explicitly or impliedly) to permit the legitimate licensee to use the software in the normal course of the operations for which it was obtained from the licensor. Within a limited number of statutory constraints, the licensor may, as a matter of contract, set such limitations on the use of the licensed software   Jones v Tower Hamlets [2001] RPC 23, at 418.  The vexed question of whether and to what extent software might be patentable is outwith the scope of this book. 34  As recognised by Recital (3) to the EU Directive on the legal protection of computer programs (2009/24/EC): “computer program technology can accordingly be considered as being of fundamental importance for the Community’s industrial development”. 35   Copyright, Designs and Patents Act 1988, s 3(1)(b). 36   Ibid, s 217(2). 37   Ibid, s 50A. 38   Licensing is discussed further at paras II-12.48ff. 32 33

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as it feels commercially appropriate; typically by limiting the number of copies that can be installed, or the number of contemporaneous users, or the business locations at which the licensee is entitled to use the software. II-12.25 The mobility of the workforce within the oil industry and the ease with which perfect digital copies of applications can be transported (eg on laptops or even memory sticks) gives rise to similar risks as have already been noted above in relation to the copying of training manuals and so on. Unlicensed duplication of software and its relative documentation or manuals is widely understood to be illegal and tends, once discovered, to be self-evident. In reality, the market for “bootleg” technical software, and particularly specialised software such as that used in geo-science and petroleum engineering, is small in comparison with, for example, an office application. The author is not aware of criminal sanctions ever having been applied in respect of the unauthorised distribution of oilfield applications. In any event, most licensors now protect their products using software-based licence-management systems (eg public-private key encryption). Confidential information II-12.26 The third pillar of IP law highlighted, the law of confidentiality, is frequently the only route by which investment in intangible innovations, and particularly novel or improved processes, can be protected. For example, knowledge of optimal formulations of mud for drilling the formations encountered in a particular area may result from long (and costly) experience. With non-productive time reaching as much as 40 per cent39 in some drilling operations, a track record of success can justify a premium price and a mud contractor would not wish such information to be shared with its competitors. It is analogous to a secret recipe. II-12.27 Such information is often called “know-how”. Although this term is widely used to describe confidential commercial information, particularly that of a practical or technical nature, it has no statutory basis in UK law. The nearest thing to a statutory definition to be found in UK law is in the context of competition law, specifically in the Technology Transfer Block Exemption.40 European law defines “know-how” as “a package of non-patented practical information,  C Berry, “Drilling Failure Costs Quickly Add Up”, 61(8) (2009) SPE Journal of Petroleum Technology. 40   Regulation 316/2014 on the application of Art 101(3) of the Treaty on the Functioning of the European Union to categories of technology transfer agreements ([2014] OJ L93/17) (hereinafter “Block Exemption”). 39

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resulting from experience and testing which is secret, substantial and identified”.41 “Secret” means that the information is “not generally known or easily accessible”;42 “substantial” means that the information is “significant and useful for the production of the contract products”;43 and “identified” means that the information is “described in a sufficiently comprehensive manner so as to make it possible to verify that it fulfils the criteria of secrecy and substantiality”.44 In general, however, know-how has been dealt with under the II-12.28 common law of confidentiality. This has a number of implications. In contrast with patents, there is no recognised proprietorial right in the knowledge embodied in the know-how. Certainly the expression of such knowledge in writing or drawing may be protected by copyright but, unlike patents, the knowledge itself is neither owned nor protected. In consequence, there is no monopoly right of exploitation and any person independently developing similar know-how may use or disseminate it freely. That said, in circumstances where know-how is properly controlled and a duty of confidentiality can be established, the law of confidentiality can potentially come closer than copyright to protecting the essential idea, rather than the mere expression of it. The substance of the law in both Scotland and England is the same.45 II-12.29 In order for the law to protect a piece of information as confidential information, the information in question must have “the necessary quality of confidence about it, namely, it must not be something which is public property and public knowledge”46 and it must be disclosed “in circumstances importing an obligation of confidence”.47 The fact that a concept is relatively simple will not, of itself, prevent it from constituting protectable confidential information; the concept must, however, be sufficiently developed and be capable of identification with reasonable particularity.48 Further, for a right of action to be established in relation to such a piece of confidential information, there must be “unauthorised use … to the detriment of the party

  Block Exemption, Art 1(1)(i).   Ibid, Art 1(1)(i)(i). 43   Ibid, Art 1(1)(i)(ii). 44   Ibid, Art 1(1)(i)(iii). 45   Lord Advocate v Scotsman Publications Ltd 1989 SC (HL) 122, per Lord Keith at 164. 46   Saltman Engineering Co Ltd v Campbell Engineering Co Ltd [1948] 65 RPC 203, per Greene M R at 215. 47   Coco v A N Clark (Engineers) Ltd [1969] RPC 41, per Megarry J at 47. 48  See the submissions made by Counsel in Pine Energy Consultants Ltd v Talisman Energy (UK) Ltd [2008] CSOH 10, per Lord Glennie, at para 21. The case concerned the development of the Beatrice oilfield into an industrial deep water offshore wind farm. 41 42

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communicating it”.49 It is clear, therefore, that know-how can only be protected for so long as it remains confidential and that, to the extent that it is disclosed, such disclosure must at least imply circumstances of confidentiality. Explicit agreement, such as by way of a confidentiality or non-disclosure agreement,50 is the most unambiguous way to establish the relationship of confidence (and certainly the most advisable), but the law will imply an obligation of confidence where the discloser and recipient are in a fiduciary relationship and in any other situation where the infamous “reasonable man” would realise that an obligation of confidence in the circumstances is equitable. II-12.30 There is extensive case law on the circumstances that import the obligation, particularly in the case of disclosure or use of know-how by employees, ex-employees and consultants.51 In general, during the term of employment, an employee’s implied duty of fidelity will protect the employer’s interest in both the confidential information given to the employee and that which the employee generates in the course of his work. The law seeks to balance the rights of individuals freely to exploit acquired knowledge and skills,52 which inevitably means that an employer will find it more difficult to pursue an ex-employee than a current one; and that leads most to implement contractual restrictive covenants in addition to whatever protection arises naturally at law. II-12.31 The area of commercial trade secrets law is poised for an update, as we await the implementation of the Trade Secrets Directive53 into UK law. The UK is obliged to implement the Directive by 9 June 2018. Because most of the principal terms of the Directive do not diverge greatly from current domestic UK law54 and because within the corporate arena it is generally desirable to align the protection afforded to cross-European operations, it seems likely that the UK Government will prepare an implementation Bill in the coming months, notwithstanding Brexit.

  Coco v A N Clark (Engineers) Ltd [1969] RPC 41, per Megarry J at 47.  Oil & Gas UK has published a model form of confidentiality agreement – Industry Model Form: Confidentiality Agreement (January 2009). Despite the laudable intention of reducing the administrative burden on companies seeking to agree relevant contractual terms, the document has yet to achieve wide industry currency in practice. 51   See eg Faccenda Chicken Ltd v Fowler [1986] 1 All ER 617. 52   See eg the opinion of Cross J in Printers & Finishers Ltd v Holloway [1965] 1 WLR 1. 53  Directive (EU) 2016/943 on the protection of undisclosed know-how and business information (trade secrets) against their unlawful acquisition, use and disclosure. 54   For example, Art 2 defines a “Trade Secret” under EU law as information which (1) is secret in the sense that it is not generally known among or readily accessible to persons within the circles that normally deal with the kind of information in question; (2) has a commercial value because it is secret; and (3) has been subject to reasonable steps by the person lawfully in control of it to keep it secret. 49 50

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The Directive seeks to harmonise the civil means through which II-12.32 victims of unlawful trade secret appropriation can seek remedy, such as (1) halting the unlawful use and/or further dissemination of trade secrets; (2) removing from the market goods which have been manufactured on the basis of an illegally acquired trade secret; and (3) compensatory damages.55 Until the draft wording of the UK implementation Bill is published, it is premature to go into greater detail. Ownership of intellectual property: employee versus contractor Unless the company has a process in place for identifying and II-12.33 recording valuable know-how, it may reside exclusively inside the minds of the workforce. This means that the ex-employee is a particular risk point in relation to confidential information. Not only does he represent a more likely source of dissatisfaction with the business and therefore of information “leakage”, but, as noted in para II-12.30, the legal protection of confidential information afforded to a business as an employer (in terms of the implied obligation of good faith in an employment relationship) is in practical terms stronger than that afforded to a business as an ex-employer (by reason of the law’s reluctance to prejudice an ex-employee’s legitimate right to utilise the general skills, knowledge and experience which someone in his position would have acquired, in order to earn a living).56 The general position is that the first owner of an IP right will be II-12.34 the person who created it. However, if that person created the item in the course of employment, then the ownership will usually vest in the employer.57 Due to the prevalence of non-employee contractors (ie persons working not under contracts of service, but contracts for the provision of services) in the industry, there is a key risk exposure for companies where they engage a contractor to create an item comprising IP. The author has seen countless cases where a contractor has been engaged to design or contribute to a tool, a piece of software or some other work, has been well paid for so doing, but has not been engaged on contractual terms which transfer the ownership of the IP to the company who engaged and paid him. In those circumstances, the contractor will retain any copyright which he created. Depending on the surrounding factual matrix, the law will usually imply a licence from the contractor to the company, but the scope of that licence may not include all the uses to which the  http://ec.europa.eu/growth/industry/intellectual-property/trade-secrets_en (accessed 9 April 2017). 56   Faccenda Chicken Ltd v Fowler [1986] 1 All ER 617. 57   Copyright, Designs and Patents Act 1988, ss 11(2) and 215(3). 55

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company intends to put the IP (especially if it intends to develop it further) and it will have no right of ownership which it could otherwise sell to realise value. Companies which have engaged the services of a contractor are often horrified to find that the contractor is free to use the product of that work to compete with them. II-12.35 Companies should therefore ensure that, where a contractor is to be engaged and any IP is possibly going to be generated by him, the contract contains assignation/assignment provisions in favour of the commissioning company. In order to be effective, an assignation/ assignment of copyright requires to be in writing and signed by the assignor,58 so, while a more limited licence of the relevant rights may be implied by the law, without such an express written contractual provision no ownership will pass.59 The position in relation to inventions has a small degree of added II-12.36 complexity. In addition to the employer owning any rights in inventions created in the course of employment, the employer will also own the rights in inventions created in the course of a task outwith the course of employment if the task was specifically assigned to the employee, or where the employee held a sufficiently senior position, so as to be assessed as having a “special obligation to further the interests of the employer’s undertaking”.60 Further, any purported assignation/assignment of rights in future inventions by an employee in favour of an employer is unenforceable. Such assignations/assignments of inventions therefore need to be agreed and documented on an individual case-by-case basis – and only once the relevant rights have been created. II-12.37 Companies should also be aware that there is a non-excludable statutory right for an employee to obtain “compensation” where: (1) he creates an invention which is successfully patented by the employer; (2) the patent is of outstanding benefit to the employer; and (3) it is just that such compensation payment be made.61 CONTRACTING STRUCTURES AND TRENDS Collaborations62 II-12.38 When used in connection with technology development, the term   Ibid, s 90(3).   Only design rights vest automatically in the commissioning party. 60   Patents Act 1977, s 39(1)(b). 61   Ibid, s 40. 62  The interaction of two or more parties in a collaboration (or a licensing transaction) raises the possibility that there may be competition law implications for them in relation to their project and/or their joint commercialisation of the project outputs. For a discussion of competition law, see Chapter II-11. 58 59

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“collaboration” is usually used to denote a structure where the contractual counterparties are each contributing some material effort to the development of the technology in question. In situations where one party is contributing capital only (ie effectively paying for the other to develop technology), the relationship might more accurately be characterised as a “commissioned development” or “contract research” agreement. However, often for cosmetic reasons of the paying party, even this type of situation is designated as a “collaboration”. The exact structure of a collaboration can vary from an intense and binding interaction between the counterparties (such as a corporate joint venture) to a bare sub-contract relationship of relatively short duration. The defining feature is simply the co-operation (in some form) of the counterparties towards a particular technical project goal. A collaboration can be put in place in order to capitalise on the II-12.39 synergistic competences of the counterparties (eg where experts in chemical polymers collaborate with drillers of heavy oil to use their combined expertise to develop an enhanced oil recovery process) or in order to compensate for a shortage of resources or skills of a party (eg where a university department’s specialist and expensive laboratory equipment and academic team are engaged to develop new seismic techniques). There is currently no such thing as a model technical collaboration II-12.40 agreement for the UKCS and they are therefore still quite bespoke creatures of contract. However, there are certain key features which should almost always be covered including: • definition of the project aim and a detailed project scope; • who has responsibility for carrying out which parts of the project scope; • who has responsibility for paying for (and who will own) equipment or other tangible items required by the project scope; • what happens if the project aim is not achieved (either for technical reasons or because the parties fall into dispute); • how the resultant IP (“foreground IP” or “project IP”) is to be owned and exploited by the parties; • how the IP owned by each party at the start of the relationship (their respective “background IP”) is to be documented and regulated, in order to enable effective exploitation of the foreground IP, without infringing or otherwise prejudicing the background IP; and

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• what (if any) indemnity cover should be provided in relation to the background IP provided by each party.63 II-12.41 Of course, each of the key features above could be broken down into a multitude of sub-issues and complexities; and the relevant agreement should additionally make all usual “boilerplate” provisions for two parties interacting in a project, such as confidentiality obligations, dispute resolution provisions, choice of law and so on. II-12.42 Two issues typically relevant to collaborations (and which have broader application when dealing with technology) are the topics of (1) joint ownership of IP; and (2) indemnities in respect of potential IP infringement. Joint ownership II-12.43 Intuitively, joint ownership is regarded by many collaborators as being a fair outcome. However, many parties do not fully appreciate the restrictions and difficulties which may apply to co-owners. For example, a co-owner of copyright will not be entitled to exercise the jointly owned rights without the consent of the other co-owner(s). The precise rights and freedoms of co-owners vary as between the different species of IP rights, but generally: • a co-owner will not have the right to assign its title to IP (or license the IP) to any third party, without the consent of the other co-owner(s); and • a co-owner is unable to bring an action for infringement to prevent unlawful use of the IP without the other co-owner(s) being a party to the proceedings. II-12.44 This can produce situations which are quite contrary to the commercial expectations of the parties. For example, consider a scenario where: (1) two companies collaborate to develop a patented product and agree that the rights in such patent will be owned by them jointly; (2) the parties are then unable to agree the terms upon which the IP should be licensed or assigned to a third party; and (3) one of the parties is a technical design specialist, while the other is a manufacturer. In that scenario, the party who has the ability to manufacture the products themselves may have the right (as co-owner) to do so; while the other co-owner who does not have such in-house capability is (factually) unable to self-produce and also (legally) unable to license to any third party. II-12.45 If joint ownership is nevertheless desired, the contract could explicitly provide for wide rights of exploitation for each co-owner   Discussed further at paras II-12.46ff.

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(effectively a cross-licence structure which broadens the natural implications of co-ownership at law). Alternatively, if a structure in keeping with the intuitive appeal of joint ownership is sought, it is generally preferable to provide for one party to own the IP, with the other receiving an irrevocable (royalty-free) licence, both subject to terms which explicitly set out the rights and obligations of the parties. In this situation, however, the issue of insolvency risk of the licensor should be considered. Indemnities In the commercial licensing of IP, it is relatively common for the II-12.46 licensee to seek an indemnity from the licensor in respect of any infringement of a third party’s IP.64 In a simple licensing transaction, the rationale is clearly illustrated. If Company A has a design for a tool, which it wishes to license to Company B to manufacture and sell within a particular geographical market, in return for a royalty on each product sold, then Company B (as licensee) will want a certain level of contractual comfort that Company A has good title to the design rights and has not simply copied them from a third party. Otherwise, Company B could find itself on the receiving end of an infringement claim from the third party in respect of its manufacturing and sales activities. Indemnification is the common mechanism by which this objective is achieved.65 In the situation where Company A and Company B are collabo- II-12.47 rating to develop a product and each is contributing respective background IP, the same principle arises. Before either counterparty invests significant time and effort incorporating that background IP into the foreground IP to be produced in terms of the collaboration, it will want some comfort that the outputs will be free from third-party challenge and available for the parties’ exploitation without undue restriction. Reciprocal indemnities in respect of any third-party infringement claim are therefore usually negotiated in some form, although a practical view may be taken where the bulk of the IP is coming from one party, rather than the other, or where sensible verification (due diligence) of the provenance of the relevant IP is possible. In collaborations which are not being carried out for payment or are otherwise not on a full commercial basis, there are sometimes no indemnities given and each party collaborates on an “as-is” basis. In that situation, thorough due diligence is even more important.   For a discussion on the appropriate contractual treatment of the risks of “alleged” (cf. proven) infringement, see para II-12.61. 65  The treatment of IP indemnities under the LOGIC regime is referred to at paras II-12.60ff. 64

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IP licensing II-12.48 As noted at para I-4.04, a licence is a permission authorising an activity, the conduct of which would otherwise be unlawful. In the context of IP licensing, it is essentially an undertaking by the holder of the relevant right (as licensor) not to pursue the licensee in respect of activities which would otherwise constitute infringement of the relevant IP right (provided, of course, that the remaining terms of the licence agreement are adhered to). Thus, a patent holder may license a party to manufacture its patented product in return for certain royalty payments. Without the licence, the actions of the licensee would infringe the patent and be actionable. II-12.49 The nature and extent of licences can vary greatly. Most readers will be familiar with software licences which provide a neat example of how licensing operates. In order to run a piece of software, a computer requires to copy the code. Thus, in the absence of the concept of a licence, running the software would infringe the copyright in the software. In the absence of a contractual agreement, the law will often imply a licence as a matter of implied contract, but the terms of that implied licence may well not be extensive. In most circumstances – and certainly in any situation where valuable consideration is involved – it is prudent to put in place explicit contractual terms outlining the extent of the licence. II-12.50 Typical issues when considering a licence of IP include the following: • identification of the parties (individual companies or corporate groups); • specification of the IP rights which are being licensed (present or future); • specification of the scope of the licence (the permitted activities which are covered; the geographical region, etc); • specification of the price or a mechanism for calculating the price (whether in lump sum or royalty form); • the nature of the licence (eg revocable versus irrevocable; exclusive versus non-exclusive versus sole); • termination/duration of the licence; • provision for dealing with any claims of IP infringement by third parties or any claims alleging that the licensed IP infringes any third-party rights; and • indemnities in respect of IP infringement.

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LOGIC contracts Introduction Since their introduction as part of the CRINE66 response to the II-12.51 market downturn of the mid-1990s, the standard form contracts67 published by LOGIC (CRINE’s successor, and now part of the industry forum, Oil & Gas UK) have been widely adopted and adapted in the UKCS.68 The purpose of this suite of documents is to reduce the cost of negotiating contracts for the supply of various goods and services by providing “a commonly known and understood foundation around which the [parties] can build their particular requirements”.69 The approach to the management of IP adopted in the LOGIC II-12.52 contracts is straightforward. These provisions may be divided into three parts: (1) ownership and retention of title to existing (background) IP; (2) title to and licensing of (foreground) IP developed in the course of the contract; and (3) indemnification against infringement of third-party IP.70 In line with LOGIC’s objective of building a well-understood foundation, these provisions are essentially identical across the suite of contracts. Background IP Existing (background) IP is intended to be retained by the party II-12.53 providing it. The scope of such IP is stated to extend to “any patent, copyright, proprietary right or confidential know how, trade mark or process provided”. Care is taken to restrict the scope of any implied licence for each party to use the other’s background IP by stating that “[the other party shall not] have the right of use [of background IP], other than for the purposes of the CONTRACT,71 whether directly or indirectly” and that “the intellectual property rights in such [background IP] shall remain with the party providing [it]”. Whilst this wording clearly extends to and provides a strong   “Cost Reduction in the New Era”, part of the Oil & Gas Industry Task Force (OGITF) established in 1998 as an industry/Government initiative in recognition of the dramatic fall in oil prices, the maturing of the UKCS and the urgent need to reduce the cost base of activity in the basin. 67   Available for download from www.logic-oil.com/content/standard-contracts-0 (accessed 1 April 2017). 68   See Chapter II-5. 69   See eg LOGIC, Guidance Notes for General Conditions of Contract for Well Services (2nd edn, March 2001), p 1. 70   See eg LOGIC, General Conditions for Construction (2nd edn, October 2003), cl 20: “Patents and Other Proprietary Rights”. 71  “CONTRACT” is defined (through Section I – Form of Agreement) as including the published general conditions (Section II(a)), any bespoke special conditions (Section II(b)) and a set of sections appropriate to the type of contract. 66

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contractual basis for the protection of recognised forms of intellectual property (patents, copyright and trade marks), it is less clear whether it fully protects know-how and process, which, as we have mentioned, may underlie innovations that a party would wish to protect. Confidentiality is addressed separately from patents and proprietary rights.72 An obligation is placed on the contractor to mark confidential information clearly as such, although there are carve-outs for information relating to the contractor’s pricing and trade secrets, which are deemed confidential. Practically, however, contractors would be advised to mark as confidential all information of value disclosed to their clients. As noted above, the law of confidential information requires that disclosure of know-how or trade secrets be controlled. However, rig site operations generally involve contact with numerous other contractors, some of which may well be competitors. The requirement to maintain confidentiality gives rise to clear practical difficulties and leakage of know-how – particularly know-how related to process optimisation – is almost inevitable. By way of example, the matching of drill bits and drilling parameters to maximise rate of penetration through a given formation while minimising the risk of vibration damage is valuable know-how for a directional drilling contractor, but impossible to keep “secret” from the drill crew, mud logging contractor and many others involved. Legally, the difficulty lies in the fact that there is neither a contractual nexus between the various contractors working side by side at a rig site73 nor a clear duty of care owed by one contractor to another in relation to the protection of confidence, under which a claim in tort/delict might be made. This issue is one which the law and current practice seem unable to tackle effectively. Maintaining the secrecy of certain operational information would be practically unworkable (as in the drilling example scenario above), while agreeing confidentiality agreements among all the contractors on a work site would also be prohibitively administratively burdensome. Industry practice therefore appears to accept this risk in principle.74 The LOGIC provisions permit the client to disclose confidential   See eg “Confidentiality”, LOGIC, General Conditions for the Supply of Major Plant and Equipment (3rd edn, December 2015), cl 24. 73   Although they will each have a contract with the operator, the contractors will not have any contract with each other. 74  The same problem existed previously in relation to mutual hold harmless obligations and has (to a large extent) been addressed by the Industry Mutual Hold Harmless Deed, discussed at paras II-6.58 to II-6.76, which seeks to implement reciprocal obligations among the contractors. Perhaps a similar solution will ultimately evolve in relation to confidentiality. 72

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information to, and to authorise its use by, a wide group of associated companies75 and third parties. Notwithstanding that the latter right is subject to the consent of the contractor (not to be unreasonably withheld or delayed) and restricted “to the extent necessary for the execution and maintenance of the project in connection with which the WORK is to be performed”. This arrangement tends to favour the client. There is no explicit obligation that any such disclosure be made under conditions of confidentiality; and, in respect of disclosures to affiliates, there is not even a requirement that the disclosure to such affiliate is necessary for the performance of the contract. While there are circumstances where it is perhaps appropriate for the proprietary information of the contractor to be made available to others – for example, copyright engineering drawings may be needed to repair or maintain equipment, or an operator may require to explain some novel approach to its co-venturers in order to gain Joint Operating Committee (JOC) approval to its adoption – the LOGIC terms go beyond what is often required to protect the operator’s interests. Contractors are well advised to consider carefully how such contract terms will impact on their specific activities. Foreground IP Foreground IP is addressed in a more satisfactory manner. II-12.58 Developments leading to a potential patent or other registrable right made by either party which are enhancements of its existing IP or based wholly on that party’s “data, equipment, processes, substances and the like” in its possession at the date of commencement of the contract vest in that party. Where developments are made jointly, any potential patents or other registrable right vests in the party or parties specified.76 Non-registrable foreground IP, and particularly copyright, is II-12.59 addressed within the ambit of the provisions dealing with ownership. While following the same general pattern, these differ among the various LOGIC contracts, with those dealing with design and construction being (quite naturally) more extensive than the services contracts.77 In general, however, copyright in documents prepared

  Members of the COMPANY GROUP, which is widely defined and includes the client, its co-venturers under any joint operating, unitisation or similar agreement (eg a joint bidding or area of mutual interest agreement) relating to the operations in respect of which the contract is let, and its and their affiliated companies, which itself extends to the entire company group. 76   The party in question being designated in Appendix 1 to the Form of Agreement. 77   Compare LOGIC, General Conditions of Contract for Marine Construction (2nd edn, October 2004), cl 19 with LOGIC, General Conditions of Contract for Well Services (2nd edn, March 2001), cl 16. 75

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for the purposes of or within the scope of the work to be undertaken under the contract vests in the client on their creation. Indemnities II-12.60 The third aspect of the LOGIC IP provisions deals with indemnity for infringement of a “patent or proprietary or protected right” arising out of the performance of the contract. Mutual cross-indemnities are granted, with each party holding harmless and indemnifying the other against third-party claims for infringement arising from the use of IP that it has provided or, in the case of the client, instructions given. II-12.61 Somewhat surprisingly, there is no right for the indemnitor to take over, be enjoined in the defence of, or manage any action for alleged infringement. For example, a third-party patent holder of a downhole tool could choose to pursue an infringement action against not only the contractor supplier of the allegedly infringing product, but also its user, which could be the operator’s personnel and/or the personnel of another contractor on the rig site. Given the threat of disruption and the large losses (whether in terms of production or delayed operations) which could flow from this and the fact that, in terms of indemnities granted elsewhere in the LOGIC contracts in respect of consequential loss,78 such losses would not be recoverable, an operator faced with the threat of infringement action might be tempted to choose to pay a settlement, knowing that it is fully indemnified by the supplier, even if the case for actual infringement were weak. In many cases, it has been the ongoing and largely reciprocal relationships between the contractor and operator community in the UKCS which have prevented such damaging short-term actions. However, as economic conditions harden and as further new entrants enter the basin, the accepted conventions may change. With that in mind, it is advisable to consider how the risk of “alleged” infringement should be handled. Options could include applying the indemnity only to “proven” infringements and/or including a “conduct of claims” provision, which allows the indemnitor an appropriate degree of control over the (alleged) infringement proceedings to protect their interest. CONCLUSION II-12.62 The UK’s national interest in maximising domestic hydrocarbon recovery, which, in turn, feeds into issues of energy security and  See eg “Consequential Loss”, LOGIC, General Conditions for the Supply of Major Plant and Equipment (3rd edn, December 2015), cl 23. Consequential loss is further discussed at paras II-6.77 to II-6.82.

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global competitive advantage,79 is clear. The Wood Report of 201480 recognised the role of technology as a critical enabler of the MER UK strategy. As a result of the Wood Review, the Oil & Gas Technology Centre II-12.63 was established in Aberdeen in late 2016 as an industry-led hub for research and innovation.81 It is underpinned by £180 million of public funding from the UK and Scottish Governments through the Aberdeen City Region Deal, which is to be matched by industry for the development of critical technologies. Since December 2016, the OGA’s Asset Stewardship Expectations II-12.64 have explicitly included technology,82 requesting that UKCS licence holders submit Technology Plans covering their use of new and existing technologies to address MER UK opportunities. The OGA thereby has specific oversight to ensure that UKCS licence holders employ optimal technologies for the recovery of hydrocarbons and, with cross-industry visibility, has committed to helping operators identify best practices and facilitate collaboration. Of course, the success of all of these initiatives is dependent on the II-12.65 technical expertise of our engineers and ensuring that their efforts are appropriately protected and efficiently exploited. These structural industry schemes will play a part in the next chapter of the North Sea – but an enhanced commitment to collaborative working and investment (including sensible contractual risk allocation) among all levels of the supply chain community is what would really make the difference. Educating and engaging the engineers, commercial managers and lawyers of tomorrow in this phenomenal industry must be a priority. We are well-placed to be at the dawn of a new boom in applied technology development in areas as diverse as asset integrity, subsea engineering, data analytics, materials design and robotics. It will be fascinating.

  See Chapter I-3; see also M Porter, The Competitive Advantage of Nations (1990).  See www.gov.uk/government/groups/wood-review-implementation-team#the-wood-review (accessed 9 April 2017). 81   See https://theogtc.com (accessed 9 April 2017). 82   See www.ogauthority.co.uk/exploration-production/asset-stewardship/expectations (accessed 9 April 2017). 79 80

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CHAPTER II-13 ASPECTS OF LAND LAWRELATIVE TO THE TRANSPORTATION OF OIL AND GAS IN SCOTLAND Roderick Paisley

II-13.01 Oil and gas companies have a product that requires physical transportation from source to customer to enable it to be exploited to any extent. From the wellhead to the filling station, oil companies require rights to enable this transportation. At the various stages of the journey the rights are of different natures, largely because of changes in the state of the substance to be transported and alterations in the nature of the legal rights held by other parties. Final distribution of oil to filling stations almost invariably involves the use of the public right of highway in that the oil is transported in tankers passing along public roads. Final distribution of gas frequently involves pipelines laid in public roads by means of statutory right.1 However, up to the stage of refining, petroleum in its various forms is kept off the public roads and the large pipelines used are not laid under public roads: instead, they are laid on routes that pass across the countryside. This chapter will look at the nature of the rights required by the oil and gas companies to convey their product along pipelines passing through land in private ownership. This situation occurs throughout those parts of the world where private ownership of land is recognised. Scotland does not generally recognise the   An express statutory right is granted to gas transporters to break open streets in terms of the Gas Act 1986, Sch 4, para 1 (as applied to Scotland by para 7). It is a highly surprising omission from the Gas Act 1986 that it provides expressly for the breaking open of streets to install gas pipes but makes no express provision for the subsequent use thereof. The existence of the right for subsequent use is undoubted but its nature is obscure. See the Australian case Madden v Coy [1944] VLR 88 applying the Drainage of Land Act 1928 (Vic).

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notion of leasehold servitudes, however the principles in this chapter may be applied mutatis mutandis to jurisdictions in which all land is owned by the state and private parties have limited rights to use land or leasehold rights. Specialities and local variants as to land rights may exist in various jurisdictions but the general pattern is broadly the same. In Scotland and England, where the petroleum originates below the North Sea, the part of the transportation process which involves oil and its derivatives traversing land in private ownership is the geographic part of the journey between the point at which oil comes on shore to the point at which it reaches the refinery. As private ownership in land may begin at the outer edges of the territorial sea,2 it is possible for oil pipelines to encounter private property some 12 miles before they reach dry land.3 As a postscript to this introduction, one should note that a study II-13.02 of Scots law has particular advantages for oil and gas lawyers. As a “mixed” jurisdiction, Scotland stands between the civilian and common law traditions. The mixture of traditions has facilitated the development of sophisticated solutions to difficult legal problems in the oil and gas industry.4 Albeit by no means perfect, Scots law has much to offer lawyers from other jurisdictions wishing to develop their land law rules to facilitate the use of pipelines for the petroleum industry. Consequently, in this chapter the primary illustrations and authority for the legal propositions under discussion will be drawn from Scots law, with the similarities to, and differences between, certain other legal systems being highlighted when appropriate. NO SEPARATE CODE OF OIL AND GAS LAW Despite the existence of textbooks on the topic, “oil and gas law” II-13.03 is not a hermetically sealed division of civil law to which only special rules apply. Broadly speaking,5 oil and gas companies have no greater right to enter the lands of third parties to transport their products than any other commercial enterprise possessing limited compulsory purchase powers. In the main,6 a landowner has a right   For example, Lord Advocate v Wemyss (1896) 24 R 216, (1899) 2 F (HL) 1.   Territorial Sea Act 1987, s 1 applies to the territorial sea adjacent to the United Kingdom of Great Britain and Northern Ireland. 4  The mixture is not consistent in every field of land law. While it may be argued that the law of commercial leases and fixtures has been influenced by English law, the law of ownership and servitudes remains principally civilian. 5   For limited exceptions, see orders and agreements relating to the storage and transport of gas: Gas Act 1965, ss 4–5, 12 and 13. 6   The most general exception – the public right of access across open land created by the Land Reform (Scotland) Act 2003 – permits only passage and has no application to oil and gas transport. 2 3

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to preclude uninvited access to his lands as a trespass. In principle, if an oil or gas pipeline is laid in the landowner’s property without his consent, he may have it removed.7 While his property right subsists and remains unencumbered by derivative rights, he can prevent others building on his land even if it can be shown that such building would be in the national interest. This is why oil and gas lawyers require an understanding of land law. To enable the laying of a pipeline and the passage of materials through that pipeline the oil and gas companies must obtain a right from the landowner. In certain circumstances,8 where the landowner refuses to grant the right, it may be obtained under statutory compulsion, a process that usually requires a demonstration that the right conforms to the stated statutory purpose and is necessary. The process of compulsory acquisition usually involves the payment of compensation to the landowner. Many compulsory purchase statutes do not include a power to acquire new rights and, as such, are unsuitable for use in the creation of new pipeline systems.9 Whatever the case, the right sought by an oil and gas company must be one known to the general law. For example, in Scotland, the right must be a right of ownership, a lease or a servitude. These rights are the “products” that the Scottish legal system makes available for parties who wish to deal in land within the jurisdiction: oil and gas companies cannot simply decide to use another right with which they are familiar in another state. This limited choice is known by land lawyers as the numerus clausus principle: the principle of the “closed list”. What it means in practice is that the right used by an oil and gas company to transport oil in Scotland is not a right of a nature unique to oil and gas companies. Put another way, oil and gas companies must abide by the local land law in all the particular legal systems in which they operate. II-13.04 In addition to this, many oil and gas lawyers are familiar with the negotiation of contracts but the right required by the oil and gas company to transport their product is much more than a mere contract. A contract simply imposes a personal obligation on the parties who enter into the agreement. Except in unusual circumstances,10 it will not bind a person who purchases land   Kerr v Brown 1939 SC 140; Cheever v Jefferson Properties Ltd (1995); R Paisley and D J Cusine, Unreported Property Cases (1993) (hereinafter “Paisley and Cusine, Unreported Property Cases), p 439; cf. Anderson v Brattisanni’s 1978 SLT (Notes) 42. 8   For a general overview of the law, see J Rowan Robinson, Compulsory Purchase and Compensation (2nd edn, 2003). For detail as to oil and gas, see the statutory provisions at note 20 below. 9   Sovmots Investments Ltd v Secretary of State for the Environment [1979] AC 144. 10   A company can always expressly agree to be bound by the contract originally entered into by another company. This is known as “novation”. It is sometimes encountered when 7

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from the original landowner who entered into the contract, even if the contract in express terms purports to bind such a party.11 Furthermore, a contract is vulnerable to the insolvency of the contracting party. A contract therefore carries the risk for an oil company that the personal right created in it is only as strong as the party with whom the oil company has contracted. Except where the contracting party has a covenant equivalent to that of the Government, such a state of affairs is inadequate for most oil companies as they may invest vast sums in developing extensive pipelines and distribution networks which will in all likelihood be expected to be in existence for a considerable period of time. Instead of a mere contract, the right required by an oil and gas company to sustain a major pipeline requires to be a “real right”. This is a right that is enforceable not only against the granter, but also against his successors and against the rest of the world even though these parties were not signatories of any agreement. Furthermore, these real rights are needed in respect of every part of the pipeline because the chain of rights is only as strong as the weakest link. It is clear therefore that every major pipeline development involves considerable work for oil and gas lawyers who specialise in land law. It is on their work that the subsequent uninterrupted and efficient working of the pipeline will rely. The responsibility is great. A final footnote is required for those who deal with trans-border II-13.05 pipelines. The fact that a real right has been obtained will not protect the pipeline from the instability of a state. A real right is enforceable against the world because it is a right recognised by a particular legal system. If that legal system collapses, or the relevant legal rules are altered by a new regime so that the pipeline is expropriated, then no real right will serve to protect the interests of the oil and gas company.12 Those lawyers who practise in the United Kingdom may legitimately expect this last comment to have little immediate relevance to pipelines crossing the border between the

a purchaser decides to renew the security and maintenance contracts held respectively by a security company or a tradesman in respect of newly purchased premises. 11   H J Banks and Co Ltd v Shell Chemicals UK Ltd, Lord Clarke, 8 September 2005, CA11/05 [2005] CSOH 123, available on Court of Session website and noted at 2005 GWD 29–557. 12  Cf. Burmah Oil Co (Burma Trading) Ltd v Lord Advocate 1964 SC (HL) 117, where Scottish companies pursued a successful common law claim for compensation against the Crown for the lawful destruction of oil installations in Burma (including oil wells and pipelines) by British forces to prevent them falling into the hands of the advancing Japanese army. The claim could be brought only because the Scottish legal system and the United Kingdom as a state both remained intact after the Second World War. In any event, these particular rights to receive compensation were extinguished by the War Damage Act 1965.

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stable democratic nations of Scotland or England. However, oil and gas transport is part of an international industry and the very same lawyers may find they have to advise on pipelines in less stable parts of the world. REAL RIGHTS II-13.06 Oil and gas lawyers cannot simply dream up a new real right to suit their own purpose. To install a pipeline across land in private ownership they must choose from the limited number of real rights recognised by the relevant legal system. In Scotland, as in many other legal systems, the three most suitable real rights are: (1) ownership; (2) lease; and (3) praedial13 servitude. Of all of these, the primary real right employed for pipelines is praedial servitude; these are generally known by the abbreviated term “servitudes” because, as a general rule, no other form of servitude is known to the law of Scotland.14 In common law jurisdictions such as England, India, most other jurisdictions within the British Commonwealth and many American states, the equivalents of praedial servitudes are “easements”. Why servitudes are the most suitable of the three real rights on offer will be explored below as the limitations of the other rights are outlined. It should be noted, however, that the right of servitude is not one which is completely suited to oil and gas transportation and some of the more important limitations are also noted below. II-13.07 An oil and gas company will wish to obtain rights from each and every proprietor who owns land along the route of the pipeline. This in itself involves a massive effort of co-ordination and expertise as property lawyers seek to ensure that there is no gap left between the geographic areas covered by the rights granted. Parties such as tenants or security holders who are entitled to derivative real rights affecting the land in question will require to consent to the grant of the servitude,15 otherwise they will not be bound by the grant of the servitude.16 Frequently, however, landowners who envisage that they might wish to grant a pipeline servitude at some time in   The term “praedial” denotes a link to a plot of land known as the “dominant tenement” or “benefited property”. 14   Historically, a real right known as a proper liferent was regarded as a form of personal servitude but this classification has been abandoned almost completely. 15   Viz the principle recognised in Buchan v Sir William Cockburn (1739) Elch “Clause” 2; M 6528. For application to servitudes, see D J Cusine and R R M Paisley, Servitudes and Rights of Way (1998) (hereinafter “Cusine and Paisley, Servitudes and Rights of Way”), para 5.20. 16   This general principle is found across jurisdictions, eg the South African position noted in C G van der Merwe and M J de Waal, The Law of Things and Servitudes (1993) (hereinafter “Van der Merwe and de Waal, Law of Things and Servitudes”), at para 269. 13

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the future will reserve an express power to do so when they grant a lease or security over land. In this way the problem of obtaining the consent of a tenant or creditor is elided. There is no requirement in Scots law17 that a real right of the same nature is used for every patch of land all the way along the length of the same pipeline.18 It is possible that most of the pipeline could be supported by servitudes, smaller areas by leasehold rights and some remaining areas by rights of ownership. However, for the sake of consistency it is best for an oil or gas company to seek to establish the pipeline by a chain of similar, if not identical, real rights all the way along the pipeline. The creation of a servitude by positive prescription may assist in cases where mistakes are made and gaps exist between the servitude rights expressly created to support parts of the pipeline.19 The rights that an oil or gas company has in land are primarily II-13.08 aimed at enabling it to carry out its business. A subsidiary, albeit only marginally less important, function of the property rights is to enable the oil and gas company to raise finance by using the property and rights as security. Invariably finance is raised from banks and other financiers by offering the funder a security over the rights in land,20 various forms of securitisation21 or by pledging the shares of the company to the bank. For this reason the rights require to be “institutionally acceptable”, meaning that the terms of the rights are what a bank would accept and can pass on to a purchaser if the bank is forced to call up the loan and sell the assets of the debtor company or even sell the entire debtor company as a going concern. Albeit the major oil companies have some of the best covenants in the world, it is not unknown for minor players in the oil and gas market to fail. One final point requires noting at this juncture. In any state with II-13.09 a history of oil and gas exploration and transport it will inevitably be the case that the legislature will have enacted a limited number of statutes specially to deal with pipelines and the oil and gas industry

  Cusine and Paisley, Servitudes and Rights of Way, para 17.39. English law is to similar effect: Todrick v Western National Omnibus Co [1934] Ch 561. See also Moody v Steggles (1879) 12 Ch 261, at 267, per Fry J. 18   This requirement appears to exist in certain legal systems such as Sri Lanka, following (and perhaps misunderstanding) an old rule of Roman Dutch law: J Voet, Pandects, 8, 4, 19. See eg Cornelis v Fernando (1962) 65 NLR 93; G L Peiris, The Law of Property in Sri Lanka, vol 3: “Servitudes and Partition” (2nd edn, 2004), pp 3–5. 19  Prescription and Limitation (Scotland) Act 1973, s 3(2); Title Conditions (Scotland) Act 2003, asp 9, s 77. 20   The forms of security available in Scotland are a standard security (a fixed security) and a floating charge (a security that can affect the assets and undertaking of the company as it exists from time to time). 21   These may involve complex legal structures. 17

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in general. That is certainly the case in the United Kingdom.22 Oil and gas lawyers are also familiar with a relatively large body of detailed regulation specially enacted for their industry. Albeit parts of the legislation enable compulsory acquisition of real rights23 and regulate the passage of oil and gas through pipelines,24 none of the statutes in Scotland creates a generally applicable right for oil companies to transport oil and gas in pipelines through the land of other parties. It is all the more the case that landowners are not simply obliged to accept that a pipeline can be laid across their property just because it is in the national interest or profitable for oil and gas companies. OWNERSHIP II-13.10 Ownership is a real right frequently used by oil and gas companies for structures such as refineries, offices and transport yards. It is also used for smaller areas situated along the length of pipelines, such as sites of monitoring equipment. The benefit is that a right of property confers a right of exclusive occupation on the owner. It remains a theoretical possibility that an oil and gas company might wish to own the entirety of the strips of land in which a pipeline is laid. This is the approach that was almost universally adopted by the constructors of railway lines in the nineteenth century, as the tracks were usually laid on a strip of ground owned by the railway network. The benefit of this approach is that an oil company will have a greater control over the pipeline and, after acquisition, can largely deal with it as it wishes. After laying the pipeline in its own ground, the oil company will retain the ownership in the structure of the pipeline even if it is regarded as a fixture and accedes to the ground. II-13.11 There are, however, drawbacks to this approach of seeking ownership of a strip of ground. First, it is relatively costly. Ownership of land is always more expensive than the obtaining of a limited right. Second, many landowners do not wish to sell such a right as thereby they lose all rights in the land and their estates on either side  For example, Gas Act 1965; Offshore Petroleum Development (Scotland) Act 1975; Gas Act 1986; Petroleum Act 1987; Gas Act 1995; Petroleum Act 1998; Utilities Act 2000, Pt V. 23  For example, Offshore Petroleum Development (Scotland) Act 1975; Petroleum Act 1998, s 7 (ancillary rights); Petroleum Act 1987, s 27 (compulsory acquisition of rights); Gas Act 1965, ss 12–13 (the right to store gas underground and related rights and compulsory purchase of rights as respects well, boreholes and shafts in storage area and protective area). Other legal systems provide similar compulsory powers, eg Louisiana: Exxon Pipeline Co v LeBlanc, 763 So 2d 128 (La App 1 Cir 2000) (expropriation of pipeline servitude). 24   For example, Petroleum Act 1998, Pt III. 22

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are separated by a long, narrow strip. Third, ownership itself attracts certain liabilities which can sometimes be avoided by the use of a more limited right. For example, where a statute imposes liability on the “occupier” of a piece of land,25 an owner will almost invariably fall within that definition but the holder of a lesser real right, such as a servitude, may not. Much will depend on the nature of the possession attendant upon the exercise of the relevant derivative real right.26 Fourth, ownership is perpetual and the oil company will be left with ownership of a strip of land long after the pipeline has ceased to be used, unless it can dispose of the ownership to others. As the remnants of the closed local railway lines demonstrate, such unusually shaped properties are not particularly attractive even to the adjacent landowners. Ownership cannot be lost by abandonment in Scotland. LEASEHOLD RIGHTS Oil companies frequently make use of leases in relation to premises II-13.12 for offices and other business facilities. This makes business sense in that there is usually no initial capital outlay for the premises and, instead, an annual return is paid to the landlord in the form of rent. Unlike a property right which is perpetual, the lease will have a finite term.27 It is possible for facilities, such as pumping stations or refineries, located along the route, or at the end of pipelines, to be held on leasehold tenure. The benefit is that the tenant is entitled to exclusive possession. He can exclude everyone – even the landlord28 – from entering the subjects during the period of the lease. Of course, the lease may make some specific exceptions to this and permit to the landlord rights of entry for the purposes of inspection and survey to enable the landlord to check that the terms of the lease are being complied with. If the reservations are so extensive as to derogate materially from the right afforded to the tenant it is possible to argue that no real right has been granted to the tenant.29 It is relatively rare, albeit not unknown, for a major oil   For example, Occupiers’ Liability (Scotland) Act 1960 applied to a servitude of way in Cooper v Strathclyde RC, July 1993, IH, unreported but noted briefly at 1993 GWD 31–2013, available on LEXIS. For England and Wales, see Occupiers’ Liability Act 1984. 26   Rule v Hazlehaw Properties Limited and Scottish Power UK PLC [2017] SC GLA 1, unreported, available on the Scottish Courts website. 27   Since 9 June 2000 the maximum duration for a lease in Scotland is 175 years: Abolition of Feudal Tenure etc (Scotland) Act 2000, s 67. The 175-year maximum does not apply to leases existing prior to that date. 28   J Rankine, The Law of Leases in Scotland (1916), Chapter X. 29   TCS Holdings Ltd v Ashtead Plant Hire Co Ltd 2003 SLT 177; South Lanarkshire Council v Taylor 2005 1 SC 182. 25

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and gas pipeline to be supported by a lease, but leases are relatively common for small pipelines.30 A benefit of a lease is that it can be held wholly separately from any other land (and in that respect it is akin to a personal servitude): unlike a praedial servitude, there is no necessary requirement that the holder of the right is the owner of any other plot of land. The land subject to a lease remains owned by the landlord. Consequently, any fixture placed in the ground will become owned by the landlord31 albeit subject to the lease which probably will contain a right of removal on the part of the tenant. II-13.13 Commercial leases comprise a specialist area and only a very brief overview in the context of the oil and gas industry is offered here.32 Unlike many jurisdictions such as England and Wales, in Scotland there is a general absence of landlord and tenant legislation in the commercial sphere. Consequently, the terms of a lease in Scotland assume great importance. A well-drafted lease should contain provisions permitting the landlord to control the use of the leased land to some extent. In addition, there will be detailed provisions in terms of which the tenant insures the buildings if these were originally provided by the landlord. The tenant will be obliged to comply with all relevant statutory requirements and to indemnify the landlord for damage to land caused by the activity of the tenant.33 These provisions are important in situations where pollution could be caused to the underlying or adjacent land because of an oil or gas leak. As the lease will inevitably come to an end at some time, the lease should contain detailed provisions as to the final removal of the pipeline structure and land restoration. During the period of the lease the landlord is free to transfer his property right to others albeit that, in some cases, the tenant will seek a right of pre-emption enabling the tenant to acquire his landlord’s interest on such occasion at a price determined by a formula set out in the lease. Unless suitably drafted, the effect of such a pre-emption may link the price payable to the covenant of the tenant and the oil company potentially may end up paying more if it is a successful company. By contrast, the transfer of the tenant’s interest in the lease is likely to be limited by   See eg Lease between The Provost, Magistrates and Councillors of the Burgh of Falkirk and The Scottish Gas Board dated 28 September and 12 October 1970 and recorded GRS (Stirling) (Book 2276) (Folio 103) on 4 September 1972. The right to lay pipes is contained in Clause (Fourth) on page second. 31   Shetland Islands Council v BP Petroleum Development Ltd 1990 SLT 82. 32   For Scotland: R Rennie, Leases (2015); A McAllister, Scottish Law of Leases (4th edn, 2013); D Cockburn and R Mitchell, Commercial Leases, (2nd edn, 2011); M J Ross and D J McKichan, Drafting and Negotiating Commercial Leases in Scotland (2nd edn, 1993). For England: Lord Mackay of Clashfern (General Editor), Halsbury’s Laws of England (4th edn, 2006 reissue), vols 27(1)–(3). 33   Cf. the issues of indemnities discussed at para II-13.24. 30

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a provision conferring on the landlord some power of approval, perhaps even an absolute veto, as to the proposed assignee. Clearly a landlord will not wish a lease of a major oil installation to be transferred to a company with little expertise in the oil and gas industry or a company with a substantially lesser covenant than its existing tenant. A lease requires a continuing return to a landlord in a form of rent and it is common in long leases to find a mechanism in the lease enabling periodic rent review. This enables the passing rent to be reviewed from time to time to prevent it from being devalued by the effects of inflation. SERVITUDES The primary real right for supporting oil and gas pipelines is II-13.14 a servitude of pipeline. Albeit there was little authority for the existence of these servitude rights at common law,34 there has been recent retrospective legislation confirming that they always have been recognised by Scots law.35 A servitude of pipeline, when suitably and appropriately drafted, enables not only a pipeline to be laid in land owned by someone else but also oil and gas to be transported through that pipe for commercial purposes.36 Most existing deeds, however, are not sufficiently extensively drafted for the use thereof to be altered to transmit other products such as carbon dioxide unless this is ancillary to oil and gas transportation. Clearly, a wholesale alteration of the use of an oil or gas pipeline to facilitate an entirely different industry by the transport of waste gases is likely to be outwith the terms of most existing deeds of servitude. When appropriately drafted, a deed of servitude will comprise a vast array of provisions additional to the basic right of oil and gas transportation. This additional material includes provisions relating to (1) rights to repair, maintain, renew and upgrade the pipeline; (2) rights of access for installation, repair, removal and all other necessary purposes, including a right to take all necessary equipment and personnel along the designated routes of access; (3) patrolling,37 surveying and inspection rights, including, perhaps, rights of overflight with helicopters or fixed-wing aircraft (to enable ease of inspection and   Viz Labinski Ltd v BP Oil Development Ltd, 24 January 2003, IH, and 18 December 2001, OH, both available on Scottish Courts website. See also Assessor for Strathclyde Region v BP Refinery Grangemouth Ltd 1983 SC 18. 35   Title Conditions (Scotland) Act 2003, s 77. 36   In all cases the terms of the deed should be consulted to ascertain that there are no special limitations or restrictions, eg limitations on pressure, chemical composition or temperature of contents. 37   For example, the Texas cases Gulf Pipe Line Co v Thomason (1927, Tex Civ App) 299 SW 532 and Gulf Pipe Line Co v Kaderli (1927, Tex Civ App) 299 SW 534. 34

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security checks); (4) a right to preclude building or invasive activity such as the growing of trees or the parking of vehicles on the surface of the land immediately above and beside the pipeline; (5) obligations on the oil company to keep the pipeline in a good state of repair conform to all relevant regulations; (6) indemnities relating to potential pollution and damage to adjacent land; (7) rights of general access to various points along the length of the pipeline from the nearest public road and specific rights of access over adjacent ground to carry out emergency repairs;38 (8) rights to install markers, safety equipment and other necessary equipment at various points along the pipeline; (9) provisions precluding the removal of vertical or lateral support for the pipeline; (10) arbitration or other dispute resolution provisions to ease the swift resolution of disputes without recourse to the courts;39 (11) provisions enabling any works to be carried out not only by the oil and gas company but also by authorised contractors and agents; and (12) provisions for the abandonment of the pipeline. The whole aim of these additional rights is to ensure that the oil and gas company can comply with any obligations imposed on it by general regulation, safety concerns and licensing requirements while providing an appropriate measure of protection for the landowner. No matter how extensive the drafting, there is considerable difficulty in providing for increased regulatory burdens. The general rule is that the servitude may not become more onerous for the servient proprietor as a consequence of these increased regulations unless, of course, the deed envisages that this may occur.40 II-13.15 There is no statutory form for such a deed but a form of servitude deed has evolved from years of use and has become well established throughout the oil and gas industry. Albeit a deed of servitude used in Scotland will have certain aspects relevant only to the peculiarities of Scottish land law, the basic terms reflect what is required anywhere else in the world and the terms would be readily capable of understanding by an oil and gas lawyer practising in other jurisdictions. Each jurisdiction, however, will have its own registration requirements in terms of which the deed may require to be registered in a public register. In Scotland that register is the Land Register of Scotland or, in some cases, the older Sasine Register but the Scottish provisions for pipeline servitudes are relatively lax. Indeed, registration for such servitudes is permissive and not mandatory.41

  For example, the Canadian case: Alliance Pipeline Ltd v Seibert [2003] 25 Alta LR (4th) 365, Alberta Court of Queen’s Bench, Topolniski J. 39   See generally Chapter II-15. 40  Erskine, Institute, 2, 10, 41 referring back to 2, 9, 34. 41  Title Conditions (Scotland) Act 2003, s 75(3)(b). For England: Halsbury’s Laws of 38

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Benefits of deeds of servitudes The benefits of such a deed of servitude are many. First, servitudes confer on oil and gas companies a real right to transport their products across the lands of others. It is a right enforceable against the rest of the world including successors of the original granter.42 Consequently, the oil and gas companies do not need to purchase the underlying land. They acquire only such rights as they require and no more. Second, the landowner, typically a farmer, retains ownership of the ground. Albeit restrained from some of the more invasive building or farming activities by express43 or implied44 terms of the servitude, he is still able to cultivate the surface to some extent.45 He can pass over to his land on either side of the pipeline without having to retain access rights to do so. Agricultural production is not unduly hampered. Claims for compensation for disruption are thus minimised. Third, when the use of the pipeline comes to an end, the oil and gas company can remove the pipe or abandon it if the servitude deed so allows. Provided the terms of the servitude deed permit this, the right of servitude, albeit potentially perpetual, may be abandoned whenever the pipeline ceases its economic lifetime. Alternatively, there may be provision to install a replacement pipeline. In still other cases there may be provision to divert the pipeline to a different use. This, however, appears to be rare in practice. Fourth, the deed provides a focus for the rights and responsibilities of the two persons who have an interest in the land in question. Broadly speaking, the deed should make provision for all foreseeable

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England: Equitable Interests in Land: Restrictive Covenants, (4th edn, 2003 reissue), vol 16(2), para 613ff. 42   Cusine and Paisley, Servitudes and Rights of Way, para 1.62. 43   For example, the Canadian case Canadian Western Natural Gas Co v Empire Trucking Parts (1985) Ltd [1998] 61 Alta LR (3rd) 1, Alberta Court of Queen’s Bench, Moshansky J: oil and gas pipeline servitude prohibiting erection of structures held to include cars and vehicles placed on surface in addition to a wall, fence or means of storing trucks. They were therefore to be removed as interfering with access to pipeline. 44   Central RC v Ferns 1979 SC 136 (loading of soil and material on top of pipeline); Hamilton-Gray v Sherwood, Sheriff Court, 27 August 2002, K Reid and G Gretton, Conveyancing (2002), p 6, noted in (2002) 59 Greens Property Law Bulletin 7 (building of wall on top of pipeline); Louisiana: El Paso Field Service, Inc v Stephen Minvielle, 867 So 2d 120 (La App 3d Cir, 2004) (owner of servient tenement interdicted from engaging in crawfish operations in a pond over the route of a servitude of underground gas pipeline); Missouri: Southern Star Central Gas Pipeline, Inc v Murray 190 SW 3d 423 Mo App SD, 2006 (court ordered removal of trees that hindered helicopter inspection and potentially could cause root damage to pipeline but court refused to order removal of a mobile home within 5 feet of the pipeline). 45   For example Ohio: Besser v Buckeye Pipe Line Co (1937) 57 Ohio App 341, 13 NE 2d 927; Industrial Gas Co v Jones (1939) 62 Ohio App 553, 24 NE 2d 830, Missouri: Bahler v Shell Pipe Line Corp (1940, DC Mo) 34 F Supp 10.

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events and seek to set out a means for resolution of disputes. The aim is to avoid litigation and the public airing of disputes. If it is intended that more than one party will have servitude rights in respect of the pipeline, it is prudent to provide for the regulation of the relationship between those parties. II-13.20 Fifth, it is inevitable that a deed of servitude cannot foresee everything. In such a case where there is no provision within the deed, the general law of servitudes will apply.46 The parties therefore have the comfort of knowing that there is no absolute “black hole” in the legal arrangements they have set up and reference can be made to the general principles of servitudes to supply an answer to their queries. In Scotland there is also a recognition that the provision in any deed of servitude may be overtaken by events and become unreasonable in the light of new circumstances. In such a case the landowner and any other against whom the servitude is enforceable47 is permitted by statute to apply to the Lands Tribunal for Scotland to seek variation or discharge of the servitude.48 Under current legislation, such a variation or discharge of a servitude will be permitted if it is “reasonable” to grant the application.49 In theory such statutory provisions may be used to require the re-routing of a pipeline.50 However, given the probable disruption of transport and production consequent upon such an operation and the attendant costs, it appears to be unlikely that such an application would succeed as regards a large pipeline except in very special situations. In any event, such applications for variation are usually used as part of the process to obtain a negotiated settlement. Limitations of servitudes II-13.21 Servitudes are a class of rights developed originally in Roman times.51 English easements have been developed largely from Roman  For Scotland: Cusine and Paisley, Servitudes and Rights of Way; Louisiana: A N Yiannopoulos, Louisiana Civil Law Treatise, vol 4: “Predial Servitudes” (3rd edn, 2004); England: C Sara, Boundaries and Easements (3rd edn, 2002); C J Gale, Easements (16th edn, 1997); South Africa: van der Merwe and de Waal, Law of Things and Servitudes; Australia: A Bradbrook and M Neave, Easements and Restrictive Covenants in Australia (2nd edn, 2000). 47   This excludes the person benefited by the servitude. Consequently, that person cannot apply to have the servitude re-routed or extended. A possible way forward in such a case is for the deed to have been drafted with express powers to effect a re-routing or extension. 48   Title Conditions (Scotland) Act 2003, Pt 9. 49   Ibid, s 98. 50   All the reported cases relate to re-routing of servitudes of access but the principles applicable are identical. See eg George Wimpey East Scotland Ltd v Fleming 2006 SLT (Lands Tr) 2. See K Reid and G Gretton, Conveyancing (2005), pp 7–8 and 102. 51   Digest, Book 8; Voet, Pandects, 8, 1, 1–8, 6, 14; R Elvers, Die Römische Servitutenlehre (1856). 46

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notions to the extent that it is true to say that easements are derived from servitudes and not servitudes from easements.52 The fact that servitudes are still used today is testament to the stability and flexibility of the basic structure of Scottish land law based on these civilian foundations. However, the historical origins are still reflected in some characteristics of servitudes that, as yet, have not been sufficiently well adapted to modern social or economic conditions. It would be fair to say that there are certain limitations inherent in the concept of servitude that are not ideally suited to the oil and gas industry. Exclusion of the owner The right of servitude held by the benefited proprietor co-exists with II-13.22 the property right of the burdened proprietor. A basic principle of the law of servitudes is that the two rights simultaneously affect the same thing and the owner of the burdened property is excluded only to the extent that the proper exercise of the servitude requires.53 A further basic principle is that no servitude can be inconsistent with the underlying property right of the burdened proprietor.54 Albeit there is some obscurity in the application of this principle to particular cases; a major factor is the degree to which the burdened proprietor is physically excluded from the use of the burdened property: the greater the degree of exclusion, the greater chance that the purported servitude will be regarded as inconsistent with the servient tenement. For this reason the device of servitude cannot be used by oil companies to construct and exclusively occupy refineries, offices or other large buildings and complexes on the servient tenement.55 Similarly, any attempt to create a servitude of storage for the purposes of installation of large-scale oil or gas tanks would probably be unacceptable.56 However, the application of this principle   C Sara, Boundaries and Easements, p 214, para 11.11; W W Buckland and A D McNair, Roman Law and Common Law: A Comparison in Outline (2nd edn, 1952), p 142. 53  Erskine, Institute 2, 9, 34; Bell, Prin, s 987; Rattray v Tayport Patent Slip Co (1868) 5 SLR 219, per Lord Deas at 219. 54  The common law rule was established in Dyce v Hay (1852) 1 Macq 305 and is repeated for expressly created servitudes in Title Conditions (Scotland) Act 2003, s 76(2). For further discussion see Moncrieff v Jamieson 2005 1 SC 281; Johnson, Thomas and Thomas (a Firm) v Smith 2016 GWD 25-456. 55  This would be inconsistent with the underlying right of property and thus repugnant with ownership: Wright v Logan (1829) 8 s 247, at 249 in the sheriff’s note; Pickard v Somers (1932) 48 Sh Ct Rep 237, at 240, per the Dean of Guild; Title Conditions (Scotland) Act 2003, s 76(2). For a similar principle in England: Luther, “Easements and Exclusive Possession”, 16 (1996) Legal Studies 51–62. 56  Cusine and Paisley, Servitudes and Rights of Way, para 3.16; Moncrieff v Jamieson 2004 SCLR 135, Lerwick Sheriff Court (Sheriff Colin Scott Mackenzie), 2005 SLT 225. 52

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to servitudes of pipeline is uncertain even though the practical and intended effect of the construction and operation of a gas and oil pipeline is that the burdened proprietor will be physically excluded from the area within the pipeline.57 Admittedly, total exclusion of the burdened proprietor is recognised in the context of other servitudes such as those relating to inundation and dam,58 septic tank59 and, to a smaller physical extent, water and drainage pipes. There is clearly an acceptance of total exclusion of the burdened proprietor in these traditionally accepted servitudes and it remains to be seen if this will be extended to servitudes relative to oil and gas pipelines. Safety and security concerns alone would indicate that such an extension is desirable as it would be wholly unsafe if the oil and gas company could not exclude the landowner from accessing or using the pipeline. The lack of any challenge to oil and gas pipeline servitudes on this basis suggests that it has been so extended at least in practice if not by the courts. The cynic might simply suggest that the point has never occurred to anyone.

Cf. the more favourable position of common law jurisdictions as developed by a Scottish judge by reference to Scottish authority: Attorney-General of Southern Nigeria v John Holt & Co Ltd [1915] AC 599 (PC (S Nigeria)), per Lord Shaw of Dunfermline at 617, citing Dyce v Hay (1852) 1 Macq 305, per Lord St Leonards LC. 57   Viz a case in which the House of Lords considered that this matter was so fundamental that it construed a deed of servitude as conveying a property right: Glasgow Corporation v McEwan (1899) 2 F (HL) 25. 58   A right of storage in the form of a servitude is recognised as regards the storage of water for power generation and it seems a small step from that to permit the storage of gas or oil for power generation. For servitudes of water storage for power generation, see Gairlton v Stevenson (1677) M 12769; Carlile v Douglas (1731) M 14524; Bruce v Dalrymple (1731) Elch Serv No 2; 5 Brown’s Supp 220, commented on in Erskine, Institute 2, 9, 4, note; Gray v Maxwell (1762) M 12800; Christie v Wemyss (1842) 5 D 242; Scottish Highland Distillery Co v Reid (1877) 4 R 1118; Williams’ Trs v Macandrew and Jenkins 1960 SLT 246. See also the similar position in South African law: Fourie v Marandellas Town Council 1972 Rhodesian Law Reports 164. 59   See eg McLellan v Hunter 1987 GWD 21–799; Todd v Scoular 1988 GWD 24–1041; Clark v Craig, unreported, Stonehaven Sheriff Court, 12 February 1993, case ref A149/91, noted in Cusine and Paisley, Servitudes and Rights of Way, paras 1.41, 1.71 and 3.50; Buchan v Hunter in Paisley and Cusine, Unreported Property Cases, p 311. This mirrors development in other mixed jurisdictions such as Québec: Gustave Rochon c Suzanne Charron, 2 May 2002, Cour Du Québec, QCCQ 705-22-003035-001, available at www.canlii.org (accessed 10 September 2017). For common law jurisdictions: Wong Kwok-chiang and Others v Longo Construction Ltd and Another (1987) Hong Kong Law Reports 345; Callan v McAvinue, unreported, Irish High Court, Pringle J, 11 May 1973, noted in P Bland, The Law of Easements and Profits à Prendre (1997), para 5-22; Lackey v Joule, App, 577 SW 2d 114. See also Professor McDonald’s Conveyancing Opinions (ed C Waelde) (1998), Opinion 22, pp 94–97.

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Dominant tenement – basic principles A praedial servitude cannot exist in its own right. It must exist II-13.23 together with and for the benefit of another piece of land known as the “dominant tenement” or the “benefited property”.60 The owner of that land is entitled to use the servitude but only for the purpose of benefiting that particular land.61 The same rule applies in common law systems such as England62 and Canada63 and in mixed jurisdictions such as South Africa.64 In a number of jurisdictions throughout the world65 there has been modest relaxation of the rule but, typically, the relaxation is granted on an equitable basis to remedy problems arising from an existing state of affairs. No lawyer advising in relation to the laying or use of a major pipeline should confidently rely on such a relaxation being granted in advance. The effect of the rule limiting use to a particular dominant tenement is most easily illustrated by reference to a servitude of access. The owner of a plot of land benefited by a servitude of access may use the access servitude to take access to the benefited property. He cannot use the access servitude to gain access to any other property even if the other property is adjacent to the benefited property. For pipelines, this means that a servitude of pipeline held by an oil and gas company cannot exist in its own right. It must benefit other land owned by that same oil and gas company. The pumping station and refineries at each end of the pipeline are obvious candidates for the role of these benefited properties. In addition, certain deeds are drafted so that small areas of ground located along the route of the pipelines and used for safety equipment linked to the pipeline are also owned by the oil and gas companies and these are also designated as benefited properties. In addition, at least in so far as Scots

  Lord Blantyre v Waterworks Commissioners of Dumbarton (1886) 15 R (HL) 56 at 57, per LC Halsbury. 61   Irvine Knitters Ltd v North Ayrshire Co-operative Society Ltd 1978 SC 109; Scott v Bogle, 6 July 1809, FC. 62   Skull v Glenister (1864) 16 CB (NS) 81; Peacock v Custins [2001] 2 All ER 827, [2001] 13 EG 152, CA; Macepark (Wittlebury) Ltd v Sargeant [2003] 2 P & CR 12 (Gabriel Moss, QC, Deputy High Court Judge). 63   Friedman v Murray [1952] OWN 295, [1952] 3 DLR 159 (HC), affirmed [1953] OWN 486; [1953] 3 DLR 313 (CA); Liscombe v Maughan (1928) 62 OLR 328, [1928] 3 DLR 397 (CA). 64  Voet, Pandects, 8, 4, 13; Berdur Properties (Pty) Ltd v 76 Commercial Road (Pty) Ltd 1998 (4) SA 62 (D). 65  For example, Germany: BGB § 1019, V Zivilsenat Urt V 5 Oktober 1965 1 SJ (Kl) w K (Bekl) V ZR 73/63. Entscheidungen des Bundesgerichtshof in Zivilsachen, 44, 171; Washington: Brown v Voss 105 Wash 2d 366, 715 P 2d 514 (1986); E Samuels, “Stories Out of School: Teaching the Case of Brown v Voss”, 16 (1995) Cardozo Law Review 1445. 60

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law is concerned, the servitude must benefit the right of ownership in the dominant tenement. In contrast to English law,66 Scots law does not recognise that a servitude may be constituted in favour of a leasehold right alone.67 However, a servitude of pipeline created in favour of the property right in a benefited property may be exercised by the tenant in that benefited property provided the terms of the relevant lease include the right to the pipeline. Application of the basic principles II-13.24 These general principles relative to the existence of a dominant tenement can cause some surprises when applied to oil and gas pipelines. First, an oil and gas company that owns no land clearly does not own a dominant tenement and, by definition, cannot hold a servitude of pipeline. The oil and gas company itself cannot constitute the dominant tenement just because it is a company that owns some property such as moveable property or leases.68 Moveable property – such as oil or gas itself – cannot be the dominant tenement in a servitude. As already mentioned, it is not sufficient for the oil and gas company to hold a lease of a refinery or other premises and purport to constitute the servitude in favour of that lease. Instead, the oil and gas company must ensure that the landlord of the leased premises is entitled to the servitude and that the lease in favour of the oil and gas company includes the right to enjoy the pipeline. Of course, this immediately exposes the landlord as dominant proprietor to all the counter obligations in the servitude deed (known as “servitude conditions”)69 – such as the obligations relating to repair, maintenance and the indemnities relating to pollution. A lawyer acting for the landlord will wish to ensure that the lease to the oil and gas company will make provision to offset the liabilities, as it is unlikely that the burdened proprietor in the deed of servitude will accept that these obligations are enforceable only against the party operating the pipeline. The lawyer acting for the landlord will also be acutely aware that the value of these indemnities is measured by the covenant of the oil company. This will cause the landlord to be particularly careful about the assignation70 provisions in any lease,  For example, Macepark (Wittlebury) Ltd v Sargeant [2003] 2 P & CR 12 (Gabriel Moss, QC, Deputy High Court Judge). 67   Safeway Food Stores Ltd v Wellington Motor Co (Ayr) Ltd 1976 SLT 53; Cusine and Paisley, Servitudes and Rights of Way, para 2.12. 68   Cf. the approach of English law which is scarcely justifiable on principle: Re Salvin’s Indenture [1938] 2 All ER 498; H W Wilkinson, Pipes, Mains, Cables and Sewers (6th edn, 1995), pp 5 and 21. 69   Cusine and Paisley, Servitudes and Rights of Way, Chapters 13 and 14. 70   In English law this is known as “assignment”. 66

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as he will not wish a satisfactory tenant to be replaced by one with a substantially lesser covenant. If the tenant company in question becomes insolvent then the indemnities may turn out to be worthless and the landlord will be stuck with the liabilities to the servient proprietor in the pipeline servitude. In this regard a landlord may seek a guarantee or a performance bond from a third party such as a parent company which has a substantial covenant. Second, the deed of servitude requires to identify the benefited II-13.25 property to enable it to be distinguished from all other land. The very best a land lawyer can hope for is for the deed to contain a plan identifying exactly the location and extent of the dominant tenement. However, many deeds fall short of this ideal. Many deeds contain a written description of the property and some even contain a very general description of the property benefited. What is the minimum standard that is acceptable? In this regard, Scots law is rather lax and admits the possibility that extrinsic evidence may be used to identify the benefited property where the deed itself lacks the relevant information.71 This means that a general and rather unspecific phrase used in a deed of servitude may be explained by evidence showing that in fact a certain property is benefited by the servitude and was intended to be so benefited when the servitude of pipeline was created. Many deeds of servitude identify the dominant tenement as “the assets and undertaking” of the relevant oil and gas company. This is indeed rather vague but it appears to be acceptable to interpret this language by showing that as at the date of the grant of the relevant servitude this “undertaking” did indeed include the property right in a plot of land owned by the oil and gas company and actually benefited by the pipeline. It should be made clear, however, that even such a general phrase probably cannot be used to claim that the benefited property includes land acquired by the oil and gas company after the deed of servitude was entered into.72 Furthermore, such a vague and general phrase may hinder registration of the deed in the Land Register of Scotland. Third, once a plot of land is created as the dominant tenement in II-13.26 a particular servitude of pipeline it will remain so until the servitude is discharged or limited in a manner that excludes the particular plot of land. The oil and gas company cannot transfer the benefit of the servitude to another plot of land without acquiring a fresh   For example,  Lean v Hunter 1950 SLT (Notes) 32.   There is slight authority in favour of the possibility in Scotland. See Cusine and Paisley, Servitudes and Rights of Way, para 2.43, discussing North British Railway v Park Yard Co Ltd (1898) 25 R (HL) 47. The position in English law appears to be more strict and more principled: London & Blenheim Estates Ltd v Ladbroke Retail Parks Ltd [1993] 4 All ER 157; Voice v Bell [1993] EGCS 128, (1993) 68 P & CR 441.

71 72

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grant of servitude. It cannot expand the lands benefited by the servitude without acquiring a fresh grant of servitude in suitably expansive terms. All of this tends to limit the usefulness of servitudes of pipeline where the network of pipelines is growing and new installations are being created. Furthermore, an oil or gas company owning a benefited tenement will find that if it transfers that tenement to another company the benefit of the servitude will automatically transfer with the ownership of the land. This may be precisely the opposite of what the oil company intends. However, the basic characteristic of a servitude as an inseverable pertinent of the benefited property means that the benefit of the servitude of pipeline cannot be retained separately from that land. Clearly the flexibility of servitudes may not be so great as to accommodate all the land transactions that an oil and gas company may wish to carry out. II-13.27 Fourth, any servitude requires that a dominant tenement is identified in respect of that right but also that the servitude actually is for the benefit of the dominant property. This is known by land lawyers as the utilitas or praedial utility of the servitude.73 It is accepted in Scotland that this requirement is sufficiently flexible to include a business run on the dominant tenement. The benefited property must be sufficiently close to the pipeline for such utility to be demonstrated. This aspect of utility is known as the requirement of vicinity.74 However, with a very long pipeline the existence of such utility and vicinity is at least questionable.75 In many cases the pipeline appears to exist in its own right with no manifest utility to any plots of land, even if they are located at both ends of the pipeline. Certainly, in some particular cases the notion of utility is reversed from what is required for servitudes. For example, where small plots of land are retained along the route of the pipeline and these plots of land contain pumping stations or other safety equipment linked to the pipeline, it would seem that the plots of land are there to serve the pipeline and not vice versa. This point also holds good in England and other common law jurisdictions. In those legal systems, an easement must “accommodate” a dominant tenement.76 This is effectively a formulation similar, if not functionally identical, to the civilian requirement of utilitas.77   Digest, 8, 1, 8; Voet, Pandects, 8, 1, 1–2; Cusine and Paisley, Servitudes and Rights of Way, para 2.49. 74  Erskine, Institute, 2, 9, 33. 75   Cf. the more optimistic view expressed in Cusine and Paisley, Servitudes and Rights of Way, para 12.176. 76   Re Ellenborough Park [1956] 1 Ch 131 at 163, per Evershed MR; Huckvale v Aegean Hotels Ltd (1989) 58 P & CR 163 at 168, per Nourse LJ. 77  C Seebo, Servitus und Easement: Die Rezeption des römischen Servitutenrechts in England (2005), pp 127–151. 73

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Fifth, the benefited proprietor can communicate the use of the II-13.28 pipeline only to parties having a legitimate link with the relevant dominant tenement.78 This means that an oil and gas company cannot permit a third party to use the pipeline where that third party has no link whatsoever with the benefited property.79 Where a right to use a servitude is dressed up to comply with this rule by adding therein a right to use the relevant dominant tenement, the whole right may be struck down as a sham if there is no substance to the right to use the dominant tenement.80 This rule potentially has major implications for any system of pipelines where the operator seeks, or is obliged to accept, transportation of oil and gas belonging to third parties who have no rights other than the ownership of the oil and gas itself.81 Sixth, the servitude of pipeline cannot itself form the dominant II-13.29 tenement for servitudes of access over adjacent fields along the length of the pipeline even if these rights of access are required to take access to parts of the pipeline from the nearest public road. This follows from the basic point, noted above,82 that a servitude is a pertinent of a right of ownership: a mere servitude cannot form the dominant tenement for another servitude. In such cases it seems preferable to create these access rights by means of separate leases from the adjacent landowner: it will be remembered that a lease requires no benefited tenement and the user clause of such a lease may restrict its use to one of access for the purpose of the pipeline. It is possible, however, to constitute such access rights as rights ancillary to the servitude. As such, the ancillary rights will be part of the servitude itself and will be real rights. Seventh, the operator of the pipeline may wish to create some II-13.30 negative restraints on the burdened landowner to prevent him from building on land immediately above and adjacent to the site of the pipeline. In some cases these negative restraints may legitimately be argued to be inherent in the positive servitude to convey oil and gas along the pipeline. For example, it is easy to imply the negative restraint not to build on top of the pipeline with structures of such a weight that they will crush the pipeline or render access to it more costly. However, this line of reasoning is more difficult to sustain where the strip on either side of the pipeline is very wide

  Cusine and Paisley, Servitudes and Rights of Way, para 1.57.   Murray v Mags of Peebles, 8 Dec 1808, FC; Stewart v Stewart (1788) Hume 731. 80   Viz the Canadian case Jengle v Keetch (1992) 89 DLR (4th) 15. 81   Viz the definition of “owner” in Petroleum Act 1998, s 27 and the acquisition of rights to use controlled petroleum pipelines in Petroleum Act 1998, s 17F. See also Gas Act 1995, s 19 (acquisition of rights to use pipeline systems). See further Chapter I-6. 82   See text at note 60 above. 78 79

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and the activity on the strip does not amount to any obstruction to the conveyance of the oil and gas. Certainly, in both England83 and Scotland, such negative restraints will not be implied just because a sterilised zone on either side of the pipeline is required in terms of applicable regulation. In such cases the negative restraint may require to be set up by other legal devices known as real burdens in Scots law.84 The equivalent device in common law jurisdictions is the restrictive covenant. In Scotland the registration requirements for real burdens are more exacting than those for pipeline servitudes.85 The concept of personal servitude II-13.31 One method of avoiding the drawbacks in servitudes as presently known to the law of Scotland would be to develop the device of “personal” servitude. The equivalent in common law jurisdictions is the easement “in gross”.86 Despite the use of the word “personal”, this form of servitude is a real right. The significant difference from traditional “praedial” servitudes is that such a right can be held, exercised and transferred without reference to a dominant tenement. As yet, such a device has not generally been recognised in Scots law87 albeit that there are a number of devices known as statutory wayleaves that bear some resemblance to personal servitudes.88 The severance of a servitude from any dominant tenement will serve to elide the limitations outlined above which arise directly from this requirement of praedial servitudes. However, the further requirement that a servitude should not be inconsistent with the underlying property right will presumably apply to personal servitudes also. Clarification is needed to confirm the legitimacy of the exclusive   Hayns v Secretary of State for the Environment (1978) 36 P & CR 317 (sight lines required in terms of modern planning requirements not to be implied within an easement of road). 84   See Title Conditions (Scotland) Act 2003. 85   See the double registration requirements for real burdens in Title Conditions (Scotland) Act 2003, Pt 1 and the exemption of pipeline servitudes from double registration in Title Conditions (Scotland) Act 2003, s 75(3)(b). 86   This is not recognised in all common law jurisdictions: Sturley, “Easements in Gross”, 96 (1980) LQR 556; Sturley, “The Land Obligation: An English Proposal for Reform”, 55 (1982) S Calif L Rev 1417. 87   R R M Paisley, “Personal Real Burdens” (2005) Jurl Rev 377. 88  See eg orders and agreements relating to the storage and transport of gas: Gas Act 1965, ss 4–5, 12 and 13; necessary wayleaves for electricity supply: Electricity Act 1989, Sch 4, para 6(6)(a) and (b); and rights acquired by agreement or court order for telecommunications: Telecommunications Act 1984, Sch 2, paras 2–6. See eg William Tracey Ltd v Scottish Ministers 2016 SLT 1049; Auquhirie Land Co Ltd v Scottish Hydro Electric Transmission Plc, unreported, 10 August 2016, available at www.lands-tribunal-scotland. org.uk (accessed 10 September 2017). 83

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possession necessarily attendant upon oil and gas pipelines. In addition, it may be prudent to vary the law of fixtures to preclude accession to the underlying land and to enable ownership of the pipeline structure to rest with the oil company. CONCLUSION The above discussion will show that land law issues have an impact II-13.32 on the business of oil and gas lawyers to a degree which is far greater than expected by many in that industry. The potential effect of the rules of land law is far reaching and cannot be ignored. Oil and gas companies should always employ specialist lawyers to deal with land law issues. Furthermore, those lawyers who work for oil and gas companies in relation to other matters such as safety compliance, contracts negotiation or licensing should always have regard to the underlying land law rights and the ability of the oil and gas companies to comply with obligations placed upon them.

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CHAPTER II-14 SELECTED EMPLOYMENT LAW ISSUES IN THE OIL AND GAS INDUSTRY Sarah Arnell1

II-14.01 This chapter focuses on four issues of employment law of current relevance to the oil and gas industry. The first subject, the distinction between an employee, an independent contractor and a “worker”, applies as much to those who work in the industry onshore as to those who work offshore, be it within the United Kingdom Continental Shelf (UKCS) or further afield. The second, the application of British employment legislation, when a worker is working overseas (“overseas” meaning outside Great Britain and beyond the UKCS), at the time when the event giving rise to a claim occurs, is likely to arise both in the case of offshore workers working overseas as well as in relation to someone who is office based but overseas. The final two subjects, application of the Working Time Regulations 1998 and dismissal of employees at the request of a third party, in the form in which they are considered here, are particular to offshore employment, “offshore” meaning within the UKCS with respect to the Working Time Regulations and with respect to dismissal of employees, within the UKCS or further afield. THE DISTINCTION BETWEEN AN EMPLOYEE, AN INDEPENDENT CONTRACTOR AND A “WORKER” II-14.02 As with any other industry, people engaged to work within the oil and gas industry will be operating under a variety of legal arrangements. The most basic distinction to be drawn is between employed   The author would like to thank R G Christie, retired employment judge, for his helpful comments on a draft of this chapter. Any errors are, of course, the author’s own.

1

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persons (who work under a contract of service) and the self-employed (who work under a contract for services). It is necessary to identify and categorise these legal arrangements when the legal rights and responsibilities of the parties are called into question. For instance, some statutory employment protection rights are only available to employees, and sometimes only certain categories of employee. Thus a claim of unfair dismissal is generally only open to an employee who held that status for a continuous period of two years;2 the right to claim redundancy is only open to an employee with at least two years’ continuous employment;3 protection for those on fixed-term contracts is available only for employees; as, likewise, are those rights which could collectively be called “family rights”, such as maternity leave and paternity leave, as well as protections afforded by the TUPE Regulations.4 Further, at common law, certain terms are implied into contracts of employment (such as the duty to maintain mutual trust and confidence) which are not implied in other work arrangements.5 Within the category of the self-employed, there is now also the II-14.03 possibility that a person may be classed as a “worker” for the purposes of certain pieces of employment legislation.6 “Worker” has been described as “an intermediate class of protected worker, who is on the one hand not an employee but on the other hand cannot in some narrower sense be regarded as carrying on a business”.7 Some casual workers who are unable to establish the necessary in order to be termed an employee8 may be classed as “workers”. Within the oil and gas industry there will also be a large number of II-14.04 persons who have been taken on by the end-user through an agency and who will therefore be legally categorised as “agency workers”.9 As we shall see, depending upon the circumstances, an agency worker may be either an employee or an independent contractor. But  See the Employment Rights Act 1996 (ERA 1996), s 108(1). There are a number of important instances where no qualifying period is required: see eg A Emir, Selwyn’s Law of Employment (16th edn, 2016) (hereinafter “Emir, Employment”), at para 17.80; and I Smith and A Baker, Smith and Wood’s Employment Law (12th edn, 2015) (hereinafter “Smith and Baker, Smith and Wood’s Employment Law”), at p 555. 3   See the Employment Rights Act 1996 s 155. 4  Transfer of Undertakings (Protection of Employment) Regulations 2006 as amended. For an overview of all these rights see Emir, Employment, Chapter 20. 5  See eg Smith and Baker, Smith and Wood’s Employment Law, at p 154ff; Emir, Employment, at para 10.8ff. 6   See paras II-14.19 to II-14.30. 7   Byrne Bros (Formwork) Ltd v Baird and Others [2002] ICR 667, per Mr Recorder Underhill QC, at para 17. The same case is authority for the proposition that “business” is for these purposes defined narrowly, in the sense of a business undertaking. 8   On which see paras II-14.05 to II-14.09. 9   The status of agency workers is considered in greater detail at paras II-14.10 to II-14.18. 2

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irrespective of that categorisation, a number of important statutory protections – equality law,10 for example – applies to employees, workers and agency workers alike. Employees II-14.05 An employee is defined in Section 230(1) of ERA 1996 as “an individual who has entered into or works under … a contract of employment”, which itself is defined (by Section 230(2) of the 1996 Act) as “a contract of service or apprenticeship, whether express or implied, and (if it is express), whether oral or in writing”. II-14.06 The statutory definitions thus provide little assistance in helping determine the circumstances in which a contract of employment exists. The courts have therefore formulated a number of tests which have been used at different times to determine this question. Traditionally, the courts utilised a test directed towards the degree of control exercised by the employer over the employee as to what the employee is to do and how he is to do it.11 However the current position12 would appear to be that while control continues to be a necessary criterion, it is no longer sufficient in itself. The courts use a multiple test whereby they take into consideration all the relevant features of the working relationship, including control.13 This multi-factor approach was taken in Ready Mixed Concrete (South East) Ltd v Minister of Pensions and National Insurance,14 where MacKenna J held that there were three conditions for a contract of service: the employee undertakes to provide his own work or skill to the employer in return for a wage or other payment; the employee agrees to be subject to the employer’s control to a sufficient degree to create such a relationship; and the other provisions of the contract are consistent with it being a contract of service. II-14.07 The courts and tribunals will decide the question of employment status according to the substance of the contract, rather than according to the label given to it by the parties.15 The courts main consideration is to establish the true intention of the parties, at the   This is now found mainly in the Equality Act 2010.   See Bramwell LJ in Yewens v Noakes (1880) 6 QBD 530. 12   For a more detailed exposition of the current position, see Emir, Employment, at paras 2.36 to 2.55. 13   See eg Market Investigations v Minister for Social Security [1969] 2 QB 173. Control in this context may amount simply to control over the background arrangements for the work: see eg Walker v Crystal Palace Football Club Ltd [1910] 1 KB 87, CA; or, at the very least, the theoretical right to control the employee (Gibb v United Steel Companies Ltd [1957] 2 All ER 110). 14   [1968] 2 QB 497. 15   Ferguson v John Dawson & Partners (1976) 1 WLR 1213. 10 11

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time the contract was created, normally as evidenced by the terms of the contract.16 However an argument that the express contractual provisions did not in fact represent or reflect the true contractual position, ie the intention of the parties at the time the contract was created, has been successful.17 The Supreme Court has held that the essential question was: “what was the true agreement between the parties?”18 To answer this question, all the circumstances of the case will need to be considered, of which the written contract is only part.19 It is not necessary to show that the parties had a common intention to misrepresent the true nature of their respective obligations in order for the court or tribunal to find that part of the contract was a sham.20 Employment tribunals have since relied on the Autoclenz Ltd v Belcher decision in ignoring the terms of the contract where they are clearly inconsistent with the reality of the actual working arrangements, and have instead given effect to the reality of the working arrangements in determining status.21 Evidentially, therefore, the focus has moved to the manner in which the contract is actually performed and on the actions of the parties. For a contract of employment to exist there requires to be II-14.08 mutuality of obligation. This is generally interpreted by the courts and tribunals to be the legal obligation to undertake work on the part of the individual and the legal obligation to provide work on the part of the employer.22 In cases determining the status of what appears to be casual workers, the courts have distinguished between the general position and specific engagements. A minimum of mutual obligation is required when looking at whether there is a contract of employment in relation either to the specific engagement or the general position.23 The necessary legal obligation to provide work and to accept work will be harder to establish in relation to the general engagement. In Nethermere (St Neots) Ltd v Taverna & Gardiner,24 the applicants were homeworkers. It was held by the

  Carmichael and another v National Power plc [2000] IRLR 43 (HL).   Autoclenz Ltd v Belcher [2011] ICR 1157. 18   Ibid. See eg EAT decision Knight v Fairway and Kenwood Car Service UKEAT/0075/12/ LA and the decision of Aslam v Uber BV [2017] IRLR 4. 19   Autoclenz Ltd v Belcher [2011] ICR 1157. 20   Ibid – and in this regard the Court of Appeal’s decision of Consistent Group Ltd v Kalwak [2008] IRLR 505 has been doubted. 21  See eg Aslam v Uber BV [2017] IRLR 4; Dewhurst v Citysprint (UK) Ltd (Case No.2202512/16). 22   See however Cornwall CC v Prater [2006] 2 All ER 1013. 23   In the context of casual workers, see Nethermere (St Neots) Ltd v Taverna & Gardiner [1984] IRLR 240, Clarke v Oxfordshire Health Authority [1998] IRLR 125, and Carmichael v National Power [2000] IRLR 43. 24   [1984] IRLR 240. 16 17

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Court of Appeal that the Employment Appeal Tribunal (EAT) had been entitled to find that the regular giving and taking of work over the course of four years had created mutual obligation such as to create a contract of employment in the circumstances. This is to be contrasted with Carmichael v National Power.25 Here, the applicants received letters offering them employment “on a casual, as-required basis”. They were offered and performed work as and when it arose. They were not obliged to take the work and the company did not guarantee that the work would be available. In these circumstances the House of Lords held that there was not the irreducible minimum of mutual obligation necessary to create a contract of service. It should be noted, however, that what has been taken by the courts to amount to mutual obligation has varied throughout the reported cases. Although it has often been taken as the obligation to provide work and the obligation to undertake work, as in Nethermere and Carmichael, in the Ready Mixed Concrete case,26 it is less than that; it is the employee’s obligation to undertake work and the employer’s obligation to pay him remuneration for that work. This lesser obligation is easier to find in a specific engagement, as can be seen in the case of Cornwall CC v Prater.27 In this case the Court of Appeal found that there was the requisite mutuality of obligation within each contract between the Council and a home tutor, over a ten-year period, such that each contract was a contract of employment. The Court took the mutual obligations to be the obligation on the home tutor to teach the pupil and the obligation on the Council to pay the tutor for the teaching. It is suggested therefore that these two competing interpretations of the minimum obligations incumbent upon each party to establish a contract of employment can bring about quite different results. It should also be noted that as a result of the Supreme Court’s decision in Autoclenz Ltd v Belcher,28 even if there is an express clause stating that there is no mutuality of obligation, this will not always prevail.29 II-14.09 The requirement for personal service is also essential, subject to the caveat that the legal device known as a substitution clause, which allows the individual to substitute his services for that of another, does not invariably mean the contract is not a contract of

  [2000] IRLR 43.   Ready Mixed Concrete (South East) Ltd v Minister of Pensions and National Insurance [1968] 2 QB 497. 27   [2006] EWCA Civ 102. 28   Autoclenz Ltd v Belcher [2011] ICR 1157. 29  In Autoclenz Ltd v Belcher [2011] ICR 1157, there was an express clause that stated that the worker was under no obligation to do the work and the employer had no obligation to provide work. 25 26

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employment. Much will depend upon the wording of the clause. The Court of Appeal held that there was no obligation of personal service, and therefore no contract of service, in Express & Echo Publications Ltd v Tanton,30 where the contract contained a substitution clause expressed in broad terms: the driver could appoint a substitute at his own expense when he was “unable or unwilling” personally to perform the services. However, in MacFarlane v Glasgow City Council,31 a more limited delegation, where two gymnastics coaches were entitled to have their classes taken by a substitute (who had to be chosen from an approved list drawn up by the Council and paid directly by the Council) if they were “unable” to take classes, was held not to negate the element of personal service. So there now appears to be significance in whether the substitution clause states that a substitute could be used where the individual was “unable” to work (such as where he is unwell) or says that a substitute could be used where the individual was “unable or unwilling” to work.32 The former does still mean there is a personal obligation to do the work because the individual must do it if he can. In Boss Projects v Bragg,33 the contract gave absolute discretion to the claimant to substitute or delegate his workload or to hire assistants for which the claimant was solely financially responsible. However the evidence showed that the contractual provisions did not represent the true relationship of the parties. The EAT found that the substitution clause was never intended to be used by either party, and so despite the express contractual provisions, the EAT found that the claimant was not an independent contractor.34 The principles relating to the requirement for personal performance have since been summarised by Sir Terence Etherton MR in Pimlico Plumbers Ltd v Smith.35 In addition to the positions already dealt with above, a right of substitution limited only by the need to show that the substitute is as qualified as the contractor to do the work, whether or not that entails a particular procedure, will generally be inconsistent with personal performance. Whilst the right to substitute only with the consent of another person who has an absolute and unqualified discretion to withhold consent will be consistent with personal performance.36   [1999] ICR 693.   [2001] IRLR 7, EAT. 32   James v Redcats (Brands) Ltd [2007] ICR 1006. 33   2013 WL 6536645. 34  This should however be distinguished from the position where such a substitution clause as existed in Boss Projects is simply never actually exercised. This will not in itself render such a clause invalid. 35   [2017] EWCA Civ 51. 36   Pimlico Plumbers Ltd v Smith [2017] EWCA Civ 51, at para 84. 30 31

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Agency workers II-14.10 It is common within the oil and gas industry for persons to be engaged to provide their services through an employment agency. This is a company that supplies persons to hirers (hereinafter referred to as the “end-user”), often on a temporary basis. Although the work is done for the end-user, the contract is between the agency worker and the employment agency and it is normally the agency that pays the agency worker’s wages. The contract between the two parties will normally stipulate the terms and conditions of work, such as remuneration, notice, annual leave and so forth. It usually also explicitly states that it is not a contract of service but a contract for services, although the label given to the contract by the parties is not determinative.37 The issue that therefore arises, often within the context of an unfair dismissal claim, is whether the agency worker is an employee and, if so, who the employer is. II-14.11 McMeechan v Secretary of State for Employment38 established that there can exist a contract of employment between the agency and the agency worker during the course of a particular assignment even where the general terms of engagement with the agency specifically state that the agency worker is self-employed. Each case will depend on its own facts. In order for there to be a contract of employment between the agency and the agency worker for a particular assignment, there needs to be a minimum of mutual obligation on the part of both parties to the contract,39 and a degree of control by the employer over the employee.40 II-14.12 There is now also the possibility of an implied contract of service existing between the agency worker and the end-user. This opportunity was first introduced by the Court of Appeal in the cases of Franks v Reuters Ltd41 and Dacas v Brook Street Bureau (UK) Ltd.42 In Dacas, Mummery LJ and Munby LJ43 made the obiter remarks that the degree of control over the person’s work was crucial in  See McMeechan v Secretary of State for Employment [1995] ICR 444 in para II-14.11 below. 38   [1995] ICR 444. 39   Montgomery v Johnson Underwood Ltd and Another [2001] ICR 819. For a discussion of the meaning of “mutual obligation”, see paras II-14.08 to II-14.14. 40   Montgomery v Johnson Underwood Ltd and Another [2001] ICR 819. These requirements were first articulated in Ready Mixed Concrete (South East) Ltd v Minister of Pensions and National Insurance [1968] 2 QB 497, discussed at para II-14.06. See also Dacas v Brook Street Bureau (UK) Ltd [2004] ICR 1437, discussed at paras II-14.12 to II-14.16. 41   [2003] EWCA Civ 417. 42   [2004] EWCA Civ 217. 43  Sedley LJ did not agree with what the majority said about an implied contract of service. 37

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determining the existence of an implied contract of service and each case should be determined on its own facts. In Cable & Wireless v Muscat,44 the Court of Appeal found that II-14.13 an implied contract of employment existed between the employee and the end-user. What appears to be key to this decision is that the employee had originally been directly employed by the company (Exodus Ltd). He was then required to provide his services through a limited company and to contract through an agency with the company who had taken over Exodus. The Court of Appeal held that a contract of employment would only be inferred where it was necessary to give business reality to the relationship between the parties and where both the irreducible minimum requirements of mutuality and control by the end-user were present. It did not matter that remuneration was paid indirectly through the agency, so long as it was provided by the end-user. The limitations to finding such an implied contract were clearly II-14.14 enunciated by the EAT45 and approved by the Court of Appeal46 in James v Greenwich Council. The Court of Appeal and the EAT sought to curtail the significance and consequence of Dacas and Cable & Wireless. This trend continued in the EAT decision of Craigie v London Borough of Haringey.47 In James v Greenwich Council the EAT upheld the employment II-14.15 tribunal’s decision that there was no implied contract, on the basis that no mutuality of obligation existed. Mrs James was an agency worker who had worked for Greenwich for five years. She argued that an implied contract had arisen. The EAT contrasted the facts of Dacas with those of Cable & Wireless. It found that in Cable & Wireless, although on paper the applicant was providing his services through an agency, effectively nothing had changed from the period when he was an employee, except that the money was paid by the agency rather than directly. The EAT considered the Court of Appeal in Cable & Wireless to be saying effectively that the contracts comprising the agency arrangements did not reflect the reality of the relationship. The EAT also took the opportunity to observe that the Court of Appeal in Cable & Wireless and Mummery LJ in Dacas had emphasised the requirement to question whether it was necessary to imply a contract, in the EAT’s opinion, in order to give business

  [2006] IRLR 354.   James v Greenwich Council [2006] UKEAT 0006/06/1812. 46   James v Greenwich Council [2008] ICR 545. 47  [2006] UKEAT 0556/06/JOJ. What seemed to be particularly fatal to Mr Craigie’s argument was that the Council could at any time tell him not to come to work and he himself could decide at any time not to go into work. 44 45

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reality to a transaction.48 The EAT then made a number of observations which were subsequently approved by the Court of Appeal, which included the opinion that when the triangular arrangements between the agency, the agency worker and the end-user are genuine and accurately represent the relationship between the parties (which is likely to be the case when there is no pre-existing contract between worker and end-user), then it will be a rare case where there will be evidence entitling the tribunal to imply a contract. It continued, II-14.16

“If any such a contract is to be inferred, there must subsequent to the relationship commencing be some words or conduct which entitle the Tribunal to conclude that the agency arrangements no longer dictate or adequately reflect how the work is actually being performed, and that the reality of the relationship is only consistent with the implication of the contract. It will be necessary to show that the worker is working not pursuant to the agency arrangements but because of mutual obligations binding worker and end user which are incompatible with those arrangements.”49

II-14.17 The EAT stated that the mere passage of time does not justify the implication of a contract. The Court of Appeal expressly approved the decision of the EAT. The Court of Appeal held that the reality of the situation was an agency relationship and that the express contracts reflected that; there was no need to imply a contract of employment. The Court of Appeal expressly approved the test applied by the EAT. The EAT had asked itself whether, in the absence of an express employment contract, an implied contract of employment between the worker and the end-user may be deduced from the conduct of the parties and from the work done. The Court of Appeal said that there were no grounds for treating the express agency contracts as anything other than genuine contracts. Thus, control by the end-user over the agency worker’s work and the existence of mutuality of obligation between the end-user and the agency worker will not be enough to establish an implied contract of employment between those parties.50 The question is whether it is necessary to imply a contract of employment.51 The   See also Heatherwood and Wexham Park Hospitals NHS Trust v Kulubowila & Ors 2007 WL919521 (EAT), in which the EAT followed the approach in Cable & Wireless, James and Craigie, ie the requirement for mutuality of obligation and the test being whether the reality of the relationship was consistent only with the implication of a contract of employment and whether therefore it was necessary to imply such a contract between the agency worker and the end-user. 49   [2006] UKEAT 0006/06/1812, at para 58. 50  See Wood Group Engineering (North Sea) Ltd v Robertson, Appeal No. UKEATS/0081/06/MT, 2007 WL 2186972. 51   Ibid. The Court of Appeal has reiterated this as the correct approach in Smith v Carillion, Case No. A2/2014/0395/EATRF, [2015] EWCA Civ 209; [2015] IRLR 467. 48

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EAT found that the employment tribunal (ET) had been justified in finding a contract of employment to be necessarily implied in the case of Harlow DC v O’Mahony.52 The ET had found it necessary to imply a contract of employment to reflect the reality of the relationship between the end-user and the agency worker, as it developed. The factual features that justified this were a high degree of control by the end-user over the agency worker; contact between the claimant and the agency was virtually non-existent bar the agency paying his wages, as the tribunal saw it, as agent for the end-user; and the claimant communicated directly with the end-user about holidays; sickness absence; pay increases; overtime; and grievances.53 It seems, then, that within the oil and gas industry, the finding II-14.18 of an implied contract between an agency worker and the end-user company would be a rare occurrence. On the current balance of authorities, it may happen in a situation where the agency worker had previously been an employee of the end-user company and was then required to change status to a company which provided its services through an agency. It may also happen in a situation where there is a high degree of control, mutuality of obligation, but also something more, that makes it necessary that a contract of employment be implied to adequately reflect the reality of the relationship that has developed since the original appointment of the agency worker. Direct negotiations between the agency worker and the end-user that have resulted in important variations to the terms of his original appointment have been held to be enough. The definition of “worker” The term “worker” is used in a number of pieces of employment II-14.19 legislation, most notably the Working Time Regulations 1998;54 Pt II (protection of wages) and Pt IVA (protected disclosures) of ERA 1996; the National Minimum Wage Act 1998; Section 10 of the Employment Relations Act 1999 (right to be accompanied at disciplinary and grievance hearings); and the Trade Union and Labour Relations (Consolidation) Act 1992 (which consolidates all relevant law on trade unions and labour relations). Thus many of the most

  Appeal No. UKEAT/0144/07/LA; 2007 WL 3001900.   See also National Grid Electricity Transmission Plc v Wood, Appeal No. UKEAT/0432/07/ DM, 2007 WL 3002010, where something less than this justified the finding by the ET that it was necessary to imply a contract of employment between the agency worker and the end-user. Direct negotiations between the end-user and the agency worker were again key, however. 54   Discussed in greater detail at paras II-14.44 to II-14.82. 52 53

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valuable statutory protections turn on the question of how this term is defined. II-14.20 A worker is defined in Section 230(3) of the Employment Rights Act 1996, the Working Time Regulations 1998 and the National Minimum Wage Act 1998 as an individual who works under or who has worked under (a) a contract of employment or “(b) any other contract … whereby the individual undertakes to do or perform personally any work or services for another party to the contract whose status is not by virtue of the contract that of a client or customer of any profession or business undertaking carried on by the individual …”55

II-14.21 Therefore, an employee is included within the definition of the term “worker”. However, a worker can also be the intermediate class of protected worker described earlier: one who is not an employee, but who cannot be regarded as carrying on a business.56 II-14.22 The anti-discrimination protections offered by the Equality Act 2010 are also available to persons with this status. This is because although the 2010 Act does not make use of this term, it provides its protections to those who are in “employment” which includes “employment under a contract of employment, a contract of apprenticeship or a contract personally to do work”.57 Although Section 83 of the Equality Act does not have the added requirement that Section 230 of the ERA 1996 Act has – that the party for whom the work is being done must not be a client or customer of any profession or business undertaking carried on by the individual whose status is being determined – the Supreme Court has stated that the same distinction between two kinds of self-employed people apply in both situations.58 II-14.23 In Byrne Bros (Formwork) Ltd v Baird and Others,59 the applicants were builders who provided their services to the company under a subcontract. They claimed holiday pay for the holiday period between Christmas and New Year under the Working Time Regulations. The issue was whether they were workers for the

  The definition of “worker” in Pt IVA of ERA 1996 is extended further than s 230, as is the definition of “worker” for s 10 of the Employment Relations Act 1999. The definition in the Trade Union and Labour Relations (Consolidation) Act 1992 is similar to s 230 of ERA 1996, but not identical. 56   See para II-14.03. 57   Equality Act 2010, s 83. 58   Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730. The Court of Appeal recognised that the two definitions are to be given the same meaning in Windle and another v Secretary of State for Justice [2016] EWCA Civ 459; [2016] ICR 721. 59   [2002] ICR 667. 55

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purposes of the Regulations. This in turn revolved around the twin questions of whether they personally performed work or services and whether they were carrying on a business undertaking. With regard to the provision of a personal service, the EAT found II-14.24 that the contracts did require the men to personally perform work or services for the contractors. One of the clauses of the contract allowed a limited power to appoint substitutes, but only where the worker himself was “unable” to provide the services. The EAT distinguished Express & Echo Publications v Tanton60 and followed MacFarlane v Glasgow City Council,61 stating that the authorities had established that a limited power to appoint substitutes was not inconsistent with an obligation of personal service.62 In considering the question of whether the builders were carrying II-14.25 on a business undertaking, the EAT assessed the policy behind subpara (1)(b) of Reg 2 of the Working Time Regulations 1998. It felt that it was to extend the benefit of protection to workers who were in the same need of that type of protection as were employees, ie workers who were required to work excessive hours. Therefore the EAT concluded that the essence of the distinction was, on the one hand, workers whose degree of dependence was essentially the same as that of employees and, on the other, contractors who had sufficient independence to be treated as being able to look after their own interests in the relevant respects. The EAT considered selfemployed labour only sub-contractors in the construction industry to be a good example of the kind of person the regulation was trying to protect. Though nominally free to move from contractor to contractor, in practice they work for long periods for a single employer as an integrated part of his workforce; their specialist skills may be limited; they supply little or nothing by way of equipment; and undertake little or no economic risk. These factors, and the contract’s general requirement for personal performance, led the EAT to conclude that over the entire period, including the holiday period, there was a contract under which the men were working for the contractors. The second requirement under Section 230(3)(b) – that the party II-14.26 for whom the work is being done must not be a client or customer of any profession or business undertaking carried on by the putative worker – has been further clarified by the courts since the Byrne Bros case. In Bates van Winkelhof v Clyde & Co LLP (Public Concern at   [1999] ICR 693.   [2001] IRLR 7. 62   See the discussion at para II-14.09. See also James v Redcats 2007 WL504779 (EAT), where the EAT found personal service although the claimant had the right to subcontract her work when she was unable to do the work herself. 60 61

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Work intervening),63 the Supreme Court distinguished between two kinds of self-employed people: “people who carry on a profession or a business undertaking on their own account and enter into contracts with clients or customers to provide work or services for them”64 (“the truly self-employed”)65 and “people who provide their services as part of a profession or business undertaking carried on by someone else”66 (“employees in the extended sense”).67 It is the latter that are “workers”. Judgments on the definition of “employment” under Section 83(2)(a) of the Equality Act 2010 have relevance as well as decisions based expressly on the definition of worker for the purposes of Section 230 of the 1996 Act. In Hashwani v Jivraj (London Court of International Arbitration intervening),68 a discrimination case referred to by Baroness Hale in Bates van Winkelhof, Lord Clarke said: “The essential questions … are … those identified in paras 67 and 68 of Allonby [2004] ICR 1328, namely whether, on the one hand, the person concerned performs services for and under the direction of another person in return for which he or she receives remuneration or, on the other hand, he or she is an independent provider of services who is not in a relationship of subordination with the person who receives the services. Those are broad questions which depend upon the circumstances of the particular case. They depend upon a detailed consideration of the relationship between the parties … The answer will depend upon an analysis of the substance of the matter having regard to all the circumstances of the case.”69

II-14.27 So whether the person doing the work is in a position of subordination will be a relevant consideration, though Baroness Hale in Bates van Winkelhof70 warned against treating its presence or absence as an “infallible touchstone”71 for distinguishing between the two types of self-employed. This echoes the EAT’s focus in Byrne   [2014] ICR 730.   Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730 per Baroness Hale, who gave the leading judgment, at para 25. 65  This term was used by Underhill LJ in Windle and another v Secretary of State for Justice [2016] EWCA Civ 459, at para 11. 66   Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730 per Baroness Hale, at para 25. 67  This term was used by Underhill LJ in Windle and another v Secretary of State for Justice [2016] EWCA Civ 459, at para 11. 68   [2011] ICR 1004. 69   Hashwani v Jivraj (London Court of International Arbitration intervening) [2011] ICR 1004, per Lord Clark, at para 34. 70   Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730. 71   Bates van Winkelhof v Clyde & Co LLP (Public Concern at Work intervening) [2014] ICR 730 per Baroness Hale, at para 39. 63 64

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Bros of the degree of dependence the worker was subject to. Also relevant will be whether it is felt that the person is integrated into the business of the putative employer.72 The existence of mutuality of obligation and its significance in II-14.28 determining whether a person is a “worker” has been debated by the courts and tribunals.73 Its absence is relevant to consider along with all the other circumstances of the particular case.74 Underhill LJ in Windle v Secretary of State for Justice,75 referring to Quashie v Stringfellow Restaurants Ltd,76 a case, it is relevant to note, that dealt with whether the claimant was employed under a contract of service, nevertheless felt that the words of Elias LJ applied also to workers/ employees in the extended sense: “However, whilst the fact that there is no umbrella contract does not preclude the worker being employed under a contract of employment when actually carrying out an engagement, the fact that a worker only works casually and intermittently for an employer may, depending on the facts, justify an inference that when he or she does work it is to provide services as an independent contractor rather than as an employee.”77

II-14.29

Underhill LJ rejected the submission from the claimants that the II-14.30 absence of mutuality of obligation between engagements was irrelevant when considering if a person was an employee in the extended sense. Underhill LJ felt that as a matter of common sense the lack of mutuality of obligation tended to indicate a lack of subordination which was incompatible with employee status even in the extended sense. This is quite a different position from that taken previously in James v Redcats78 where Justice Elias opined that mutuality of obligation arises as a material issue principally when an employer employs a worker intermittently, and the question is whether there is a continuing contractual relationship between the parties in the

  Cotswold Developments Construction Ltd v Williams [2006] IRLR 181; Windle and another v Secretary of State for Justice [2016] EWCA Civ 459; [2016] ICR 721; Pimlico Plumbers Ltd v Smith [2017] EWCA Civ 51. 73  Mutuality of obligation between contracts was stated by Justice Elias in James v Redcats (Brands) Ltd [2007] ICR 1006, to be irrelevant. See first edition of this book at para 10.22. 74   Windle v Secretary of State for Justice [2016] EWCA Civ 459; [2016] ICR 721. See also Capita Translation and Interpreting Limited v Mr R Siacuinas (Debarred), Ministry of Justice, Appeal No. UKEAT/0181/16/RN; 2017 WL 00737371. 75   [2016] EWCA Civ 459; [2016] ICR 721. 76   [2012] EWCA Civ 1735; [2013] IRLR 99. 77   Quashie v Stringfellow Restaurants Ltd [2012] EWCA Civ 1735; [2013] IRLR 99, per Elias LJ, at para 12. 78   [2007] ICR 1006. 72

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period when the worker is not carrying out work.79 Justice Elias felt that mutuality of obligation between jobs was irrelevant when what was in issue was the legal status at the point when the person actually was carrying out work,80 before concluding that “if casual and seasonal workers were to be denied worker status when actually working because of their lack of such status when not working, that would remove the protection of the minimum wage and other basic protections81 from groups of workers most in need of it”.82 This inclusion of considering the existence or otherwise of mutuality of obligation when determining if a person has the status of worker during a particular assignment, will arguably make it more difficult to establish worker status in the oil and gas context as much as in any other. THE APPLICATION OF BRITISH EMPLOYMENT LEGISLATION II-14.31 Orders have been made extending the majority of British employment legislation to offshore employment.83 This includes ERA 1996;84 the National Minimum Wage Act 1998;85 the Trade Union and Labour Relations (Consolidation) Act 1992;86 and the Equality Act 2010.87 II-14.32 The oil and gas industry is an industry where individuals will frequently move from country to country for their work with a particular employer, depending upon where the work is at that time, even where the employer itself is a British-registered company. It is also common for British offshore workers within the oil and gas industry who are resident in the UK to be contracted to a foreign

  [2007] ICR 1006, at para 78.   [2007] ICR 1006, at para 83. 81   These were not specified by Justice Elias but include the protections discussed at para II-14.19. 82   [2007] ICR 1006, at para 84. 83  “Offshore employment” here has the meaning contained in s 201 of ERA 1996: employment for the purposes of activities –   (a)  in the territorial waters of the United Kingdom,   (b)  connected with the exploration of the seabed or subsoil, or the exploitation of their natural resources, in the United Kingdom sector of the continental shelf, or   (c)  connected with the exploration or exploitation, in a foreign sector of the continental shelf, of a cross-boundary petroleum field. 84  Except time off work for public duties. See Employment Protection (Offshore Employment) Order 1976 (SI 1976/766), as amended by the Employment Protection (Offshore Employment) (Amendment) Order 1981 (SI 1981/208) and the Employment Relations (Offshore Employment) Order 2000 (SI 2000/1828). 85   National Minimum Wage (Offshore Employment) Order 1999 (SI 1999/1128). 86   Employment Protection (Offshore Employment) Order 1976 (SI 1976/766), as amended. 87   Equality Act 2010 (Offshore Work) Order 2010/1835. 79 80

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registered company, even though their colleagues who work in the office may be employed by a parent company that is a British company. The employee may then find themselves neither working in the UK, nor employed by a British company. For the employer this means that no National Insurance payments have to be made in relation to that employee. For the employee, however, it can mean that they are unable to invoke British employment legislation. In the combined cases of Lawson v Serco Ltd, Botham v Ministry II-14.33 of Defence and Crofts v Veta Ltd88 the applicants were respectively a British national employed by a company registered in England as a security supervisor at an RAF base on Ascension Island (a dependency of the UK overseas territory, St Helena); a British national employed by the Ministry of Defence as a youth worker at various military bases in Germany (as part of the civil component of the British Forces in Germany he was treated as resident in the UK for tax and National Insurance purposes); and an airline pilot who was based at Heathrow and lived in the UK, but was employed by a company which was, along with its parent company (a Hong Kong-based airline), incorporated in Hong Kong. All three applicants were seeking to establish the jurisdiction of employment tribunals in Great Britain in order to invoke Section 94(1) of ERA 1996 and claim unfair dismissal. As the House of Lords summarised, in the cases of Lawson and Botham, the employer and employee both had close connections with Britain but all the services were performed abroad. In Crofts, the employer was foreign but the employee was resident in Britain and although his services were peripatetic, they were based in Britain. The 1996 Act contains no provision as to its territorial scope. II-14.34 Previously, Section 196 had provided that ordinarily working in Great Britain was the appropriate criterion for determining territorial scope of the legislation. This section had, however, been repealed. Nevertheless, Lord Hoffmann used it as the starting point for his judgment but, whereas Section 196 had placed decisive importance on the place where the employee ordinarily worked according to the contract of employment, Lord Hoffmann felt that there had been a change in attitude since that section was enacted. What was now relevant in a standard case, he held, was where the employee was working at the time of his dismissal. If he was working in Britain at the time he was dismissed, then Section 94(1) could be invoked. With regard to peripatetic employees, Lord Hoffmann felt that the II-14.35 unfair dismissal provisions of ERA 1996 applied if the employee was

  [2006] ICR 250.

88

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based in Great Britain. As to when Section 196 applied, he felt it was still common sense to treat the base of a peripatetic employee as his place of employment for the purposes of ERA 1996, but rather than focusing on the terms of the original contract (which Section 196 had insisted upon), how the contract was being operated at the time of the dismissal was now more relevant. Lord Hoffmann considered that employees of a foreign airline could also be based in Great Britain and this was the factual position of the applicant in Crofts. II-14.36 With regard to expatriate employees, Lord Hoffmann opined that it would be unusual for an employee who worked abroad and who was based abroad to come within the scope of British labour legislation but that there would be some who did. The employee would have to be working for an employer based in Britain, but there would need to be more than this. The fact that the employee was British or recruited in Britain would not be enough. Something more may be that the employee was posted abroad by a British employer for the purposes of a business carried on in Great Britain, in the sense of a representative of the business conducted at home (rather than just working for a business that is conducted in a foreign country that belongs to British owners), for example a foreign correspondent on the staff of a British newspaper. Another example would be an expatriate employee of a British employer who is operating within what amounts for practical purposes to an extra-territorial British enclave in a foreign country. This later example, Lord Hoffmann held, was the position of the applicants in Botham and Lawson. If there were any other situations where Section 94(1) applied to expatriates, Lord Hoffmann said, they would need to have equally strong connections with Great Britain and British employment law. II-14.37 The EAT applied Lawson in Anderson v Stena Drilling Pte Ltd.89 The claimant in Anderson was from Aberdeen and was domiciled in Scotland. He had originally been employed by a company registered in Scotland but his employment was transferred to the respondents, a company registered in Singapore, so that UK tax and National Insurance did not have to be paid in relation to his employment. The claimant worked on an oil rig that was situated in far eastern waters. The operations of the rig were controlled by a UK company which was based in Aberdeen. At the time of his dismissal the claimant resided in Thailand and after the dismissal he returned to Scotland. The claimant sought to invoke Section 94(1) of ERA 1996, the right not to be unfairly dismissed. It should be noted at this point that the claimant does not come within the definition of someone working

  2006 WL2524780.

89

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in “offshore employment” in Section 201 of ERA 1996,90 to which the 1996 Act was extended,91 the definition itself which contains a territorial restriction by virtue of that particular definition. At first glance it would seem that, if a person who is working on an offshore oil rig does not come within that definition, and ERA 1996 was specifically extended to cover “offshore employment” and that was the definition given to “offshore employment”, then that person should not be able to invoke the ERA provisions on unfair dismissal. However, Mr Anderson was taken simply to be an employee, like any other, so this issue and the definition of offshore employment was never considered. The EAT held that there was no link between the claimant and II-14.38 Scotland, for the purposes of Section 94(1), which therefore could not be invoked by the claimant. The Honourable Lady Smith looked at the territorial jurisdiction92 of the employment tribunal purely in terms of unfair dismissal generally, and therefore relied heavily on Lawson. She felt that the claimant was a peripatetic employee. She found that it had not been established that the claimant’s base was in Britain at the time of his dismissal. In the Crofts case, although the part carried out in Britain was small, it was a regular, established and significant feature of the applicant’s work pattern that could properly be regarded as making Britain his base. However in this case, there was very little connection to Britain. The claimant was really only able to point to the fact that co-subsidiaries of his employers which were involved in the operations of the rig on which he worked were based in Scotland. He could not point to part of his work occurring within Britain. Further, the claimant was not an expatriate worker as his employers were not registered in Britain and did not carry on business in Britain. Therefore, although the employee himself might have felt that he had a strong connection with Britain the reality of the situation was that there was no connection with Britain when it came to his employment. In Ravat v Halliburton Manufacturing & Services Ltd93 the II-14.39 Supreme Court sought to extract a set of principles to apply to cases   See the definition at para II-14.31.   See para II-14.31. 92   Throughout the judgment the Honourable Lady Smith refers to the issue as being one of jurisdiction of the EAT. Where there is a foreign element involved in a case, jurisdiction is established according to the applicable rules of the conflict of laws. The Civil Jurisdiction and Judgments Act 1982, as amended, may apply when a British court or employment tribunal is determining whether it has jurisdiction, where the contract of employment has the necessary connection with the territory of at least one contracting states of the 1980 Rome Convention on the law applicable to contractual obligations. The issue before the EAT in Anderson was, in fact, the scope of application of the ERA. 93   2012 SC (UKSC) 265. 90 91

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where the employee is not employed in Great Britain. The categories identified by Lord Hoffmann in Lawson were stated to be merely examples of exceptions to the general rule. There were other factual situations that could arise that would fall within the exception. One example can be seen in the earlier case of Duncombe v Secretary of State for Children, Schools and Families.94 The starting point is that the employment relationship must have a stronger connection with Great Britain than with the foreign country where the employee works such that although the employee was working abroad, Parliament must have intended that Section 94(1) should apply to them. It is a question of fact and degree as to whether the connection is sufficiently strong to overcome the general rule that the place of employment is decisive.95 The connection between the circumstances of the employment and Great Britain and with British employment law must be sufficiently strong to enable it to be said that it would be appropriate for the employee to have a claim for unfair dismissal in Great Britain.96 II-14.40 The facts in Ravat were as follows. Halliburton Manufacturing & Services Ltd, a British company and a subsidiary of Halliburton Inc (an American corporation), employed Ravat as an accounts manager. He lived in England but worked on a commuter basis in Libya, working 28 days in Libya and 28 days at home. The work Ravat did was for the benefit of another of Halliburton Inc’s subsidiary companies in Germany. Ravat’s contract terms preserved the benefits for which he would have been eligible had he not worked outwith the UK, and his employer had assured him that his contract would remain governed by British employment law. Ravat was dismissed by reason of redundancy as a result of a decision made by a manager in another of Halliburton’s British subsidiaries, who was based in Cairo, and Ravat sought to invoke the unfair dismissal legislation in a Scottish ET. The Supreme Court held that the ET had jurisdiction to hear Ravat’s claim. Ravat did not come within any of the three categories identified by Lord Hoffmann in Lawson. Because Ravat was not truly expatriate the Supreme Court felt that the degree  [2011] 4 All ER 1020. This case was brought by a teacher employed by the UK Government in a German European school. He was employed under a contract governed by English law in an international enclave that had no particular connection with the country in which it happened to be situated. The employee did not pay local taxes. (Further it was felt that it would be anomalous if a teacher who happened to be employed by the British Government to work in the European School in England were to enjoy different protection from the teachers who happened to be employed to work in the same sort of school in other countries.) 95   Ravat v Halliburton Manufacturing & Services Ltd 2012 SC (UKSC) 265 per Lord Hope, at para 28. 96   Ibid, at para 29. 94

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of connection between his employment and Great Britain did not have to be as strong. Halliburton’s business was based in Britain; Ravat had been sent to Libya to pursue its business purpose which was to provide services to the oil industry. Ravat’s work was for an associated company. Ravat’s home was in Britain. Therefore Halliburton had chosen to treat Ravat as a commuter and accordingly all the benefits for which he would have been eligible, had he worked in Britain, were preserved. The documentation Ravat was given indicated that it was the appellant’s intention that the relationship should be governed by British employment law. The court found this was borne out in practice, as matters relating to the termination of Ravat’s employment were handled by the appellant’s human resources department in Aberdeen. This, the court felt, all pointed strongly to British employment law as the system with which Ravat’s employment had the closest connection. In light of Ravat, the factual set-up that existed in Anderson v Stena Drilling would still be dealt with in the same way today. There will, therefore, be a significant number of offshore workers II-14.41 who, although they are employees, do not have a sufficiently strong connection to Britain to be protected from unfair dismissal. The fear for these offshore employees who are domiciled in Britain and are only not working or living in Britain because their work has taken them abroad is not only that British employment legislation cannot be invoked but that there are no employment protection provisions which they can invoke in the circumstances. In Anderson, there was a suggestion that the claimant may have been able to invoke employment legislation in Malaysia, since the Malaysian authorities had been deducting tax from his income, but this was by no means a certainty. Lady Smith did not rule out the possibility that a person’s place of work or his base could, for jurisdiction purposes, be on an oil rig, or at least at that oil rig’s base. Consequently, some offshore workers will have to rely on the applicable foreign employment law, which may not provide satisfactory protection. Not only that but it could be quite difficult and costly for such offshore workers to establish what the applicable law is, and then seek to enforce it in the foreign country. It would not be surprising if an offshore worker in that position were deterred from taking any action at all. Another common situation where British employment law cannot II-14.42 be invoked in which an oil worker may find himself is where he is domiciled in the UK, has been working in the UK for some considerable time (say the last 20 years) but is then sent off to another country to work for two years and is dismissed perhaps 18 months into this period in the new country. The employee could try to establish that he was an expatriate employee, ie that he was posted abroad by a British employer for the purposes of a business carried on

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in the UK, in the sense of a representative of the business conducted at home. However in the situation described, the individual could very well be employed by a subsidiary company of the UK parent company and that subsidiary may be foreign registered, purely for tax and National Insurance reasons. The question then will be whether, on the facts, the employment relationship has a stronger connection with the UK than with the foreign country where the employees works, such that it would be appropriate for the employee to have a claim for unfair dismissal in the UK. Ravat has established that the situation does not need to fall within the categories identified in Lawson. However there would need to be facts that point to a closer connection to the UK than anywhere else. It seems unlikely that this could be established. A simple intention that the period of time in the foreign country be temporary and short term as a factor in itself would not be sufficient.97 In such a case the employee could perhaps be considered as a peripatetic employee. As we have seen in Lawson, for peripatetic employees the determinant issue is where they are based. At the time of his dismissal, the individual’s base could well be said to not be the UK. Lady Smith took from Lawson that part of the work had to occur in the UK; even if it was small, it should be a regular, established and significant feature of the individual’s work pattern. Could the fact that the individual had worked for 20 years in the UK prior to his work in another country be said to be an established and significant enough feature of the work pattern to say that his base was the UK? What about the requirement that working in the UK be a regular feature? Would this depend on whether the individual was to go back to work in the UK after his time in the other country? It seems unlikely that this individual’s base would be held to be the UK at the time he was dismissed. The consequence is that the statutory protection is not available to the employee. He would have to invoke the applicable foreign employment law which again could be difficult and costly. It seems harsh that an employee with such a long-standing employment connection with the UK should lose that connection and the accompanying rights as a result of a relatively short overseas work placement. II-14.43 The above cases dealt with the right not to be unfairly dismissed, however the reasoning will equally apply to other employment legislation unless there is some other specific provision as to its application. The Court of Appeal in R. (on the application of Hottak) v Secretary of State for Foreign and Commonwealth Affairs,98 a  See Jeffery v British Council [2016] IRLR 935, where there was an intention that the teachers were to be in the foreign country short term. However there were a number of other more significant factors pointing to a closer connection to the UK. 98   [2016] 1 WLR 3791. 97

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discrimination case, held that territorial jurisdiction for the application of the Equality Act 2010 is the same as for unfair dismissal legislation. The Court applied the Lawson line of authorities. However it should be noted that those employment rights which derive from EU law and which have direct effect, will be given effect to by employment tribunals even where the work is performed by a foreign national outside Great Britain, because it is the duty of the ET to give effect to directly effective EU rights.99 The work will however need to have taken place within the EU.100 Most equality rights are derived from EU law so although the territorial application of the Equality Act 2010 has been held to be the same as the unfair dismissal legislation in the ERA 1996, in practice, workers who have little connection with the UK will be able to invoke EU anti-discrimination rights,101 at least whilst the UK is still part of the EU. APPLICATION OF THE WORKING TIME REGULATIONS 1998 The Working Time Regulations 1998 implemented Council Directive II-14.44 93/104/EC, which set out minimum health and safety requirements for the organisation of working time. When the Regulations first came into force in 1998, neither they nor the Directive covered offshore working. However, the Directive was amended by Council Directive 2000/34/EC, to include “offshore work”. Directive 93/104 is stated at Article 1(3) to apply to “all sectors of activity, both public and private, within the meaning of Article 2 of Directive 89/391/ EEC …”. Article 2 of Directive 89/391/EEC states: “This Directive shall apply to all sectors of activity, both public and private (industrial, agricultural, commercial, administrative, service, educational, cultural, leisure etc).” The amending Directive of 2000 inserted a definition of “offshore work” to the original set of definitions. It now reads:

  Bleuse v MBT Transport Ltd [2008] ICR 488; [2008] IRLR 264 – where the Working Time Regulations 1998 were invoked by a German employee who worked in Europe but not in the UK, to allow him to make a claim for holiday pay against his British employer. 100   Dhunna v Creditsights Ltd UKEAT/0246/12. See also Wittenberg v Sunset Personnel Services Ltd and Others UKEATS/0019/13, where Lady Stacey gave a preliminary view that for EU-derived employment rights to be relied on, the work would need to be carried out within the EU. 101  In Mangold v Helm [2006] All ER (EC) 383, it was held that non-discrimination is a fundamental principle of EU law which can therefore be applied against private individuals as well as the state. Thus, EU anti-discrimination rights can be asserted as against private employers as well as public sector employers. 99

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“‘offshore work’ shall mean work performed mainly on or from offshore installations (including drilling rigs), directly or indirectly in connection with the exploration, extraction or exploitation of mineral resources, including hydrocarbons, and diving in connection with such activities, whether performed from an offshore installation or a vessel”.

II-14.45 The UK implemented the amending Directive 2000/34 by the Working Time (Amendment) Regulations 2003.102 These entered into force on 1 August 2003. A definition for “offshore work” in identical terms to that set out at para II-14.44 was incorporated. It should be noted, however, that although the Regulations apply to offshore workers, there is also a specific exclusion in Reg 18 of those workers to whom the Merchant Shipping (Hours of Work) Regulations 2002 apply.103 These Regulations were passed to implement Council Directive 1999/63/EC (the Seafarers Directive).104 Those who fall within the definition of the Seafarers Directive are found in cl 1: “seafarers on board every seagoing ship, whether publicly or privately owned, which is registered in the territory of any Member State and is ordinarily engaged in commercial maritime operations”. A “seafarer” is defined in cl 2 as “any person who is employed or engaged in any capacity on board a seagoing ship” to which the Directive applies. So, although the Working Time Regulations will apply, for instance, to divers who operate from a vessel and in connection with the exploration, extraction or exploitation of mineral resources, there will be many other workers on vessels who perform work connected with offshore activities to whom the Working Time Regulations will not apply. The Working Time Regulations have applied to offshore work done in the UKCS since 1 August 2003.105

  SI 2003/1684.   Merchant Shipping (Hours of Work) Regulations 2002 (SI 2002/2125). This provision was substituted into the Working Time Regulations by the Merchant Shipping (Maritime Labour Convention) (Hours of Work) (Amendment) Regulations 2014/308. 104  This Directive, implemented in the UK by the Merchant Shipping (Hours of Work) Regulations 2002 (SI 2002/2125) contains specific provisions regarding hours of work, rest and paid annual leave for seafarers. 105  In the case Transocean International Resources Ltd & Others v Russell & Others, Case no S/104056/04, the ET held that the 2003 Regulations applied to offshore work done on the UKCS. This decision was upheld on appeal to the Employment Appeal Tribunal (Unreported, appeal no EATS/0074/05/MT) and the employers took the decision not to appeal to the Court of Session. While the Transocean case was being litigated, the Working Time (Amendment) (No 2) Regulations 2006, SI 2006/2389, entered into force on 1 October 2006. The definition of “offshore work” is specifically stated to include work done in the British sector of the Continental Shelf, as well as work done in the territorial waters of the UK adjacent to Great Britain. 102 103

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Who is covered by the Working Time Regulations? The Regulations are stated in Reg 2 to apply to a “worker”, which II-14.46 has the same definition as in Section 230 of ERA 1996.106 The Regulations therefore apply to those who are employed under a contract of employment and also to those who work under any other contract whereby the individual personally carries out work or services for the other party to the contract and that other party does not have the status of a client or a customer of the individual’s business or profession. The Regulations also apply to agency workers (Reg 36). They are to be treated as if they had a worker’s contract, with either the agency or the principal, whichever has the responsibility for paying the agency worker, and if neither is responsible, whichever of them does actually pay the agency worker for the work done. There is no qualifying period of employment. Accordingly, all employees, casual workers and agency workers who work offshore will be entitled to the protections afforded by the Regulations. Self-employed workers other than those who are pursuing a professional or business activity on their own account will also be protected. The main provisions Average working time in seven-day period (Reg 4) The average working time for each seven-day period should not II-14.47 exceed 48 hours, including overtime. It must be stressed, however, that this stipulation concerns average working hours. Article 20(2) of Directive 2000/34 provides that member states may use a reference period of up to 12 months for the calculation of an offshore worker’s average working hours, rather than the usual 17-week period used in Britain. Britain has chosen to use a reference period of 52 weeks for offshore workers:107 see Reg 25B. In practice, what this means is that workers can actually work well over 48 hours in a seven-day period for sustained periods, without exceeding the limit. The 52-week period is any period of 52 weeks in the course of II-14.48 the worker’s employment. However, an agreement may be made whereby each period that is taken is actually successive periods of 52 weeks. Where the worker has worked for less than 52 weeks with

  See the discussion at paras II-14.20 to II-14.30.   Note that the rest days during the 52-week reference period are excluded days in the calculation of average hours in the 52-week reference period, but the equivalent number of days worked immediately after the reference period are added back into the reference period calculation in order to calculate the average hours worked in the reference period.

106 107

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the employer, the reference period will be the period since he started work with the employer: see Reg 25B. II-14.49 “Working time” is defined in the Regulations as any time when the worker is working at the employer’s disposal and carrying out his duties. Time spent receiving training is included.108 Daily rest (Reg 10) II-14.50 A worker is also entitled to daily rest. He is entitled to at least 11 consecutive hours of rest in each 24-hour period during which he works for his employer. Reg 21(a) states that Reg 10(1) does not apply to offshore workers. However, this is subject to the requirement in Reg 24 that the employer “shall wherever possible” allow the worker to take an equivalent period of compensatory rest and, in exceptional cases where this is not possible for objective reasons, the employer must afford the worker such protection as is appropriate to safeguard the worker’s health and safety. The European Court of Justice of the European Union (ECJ) requires that the compensatory rest follow on immediately from the corresponding periods worked in order to prevent the worker from experiencing a state of fatigue or overload owing to the accumulation of consecutive periods of work.109 Therefore in practice this subsection does need to be applied although there is some flexibility in respect of the timing of allowing this rest entitlement. Weekly rest (Reg 11) II-14.51 A worker is entitled to weekly rest periods. He may be given an uninterrupted period of not less than 24 hours in each seven-day period during which he works for his employer. Alternatively, he may be given two periods of not less than 24 hours in each 14-day period or one period of 48 hours in each 14-day period. Reg 21(a) states that Reg 11(1) and (2) do not apply to offshore workers. However, this is again subject to the requirement in Reg 24, discussed at para II-14.50. Since the ECJ requires that the compensatory rest follow on immediately from the corresponding periods worked,110 in practice these subsections do actually need to be applied, although there is some flexibility in respect of the timing of allowing these rest entitlements. In the case of Russell v Transocean International Resources Ltd111 it was agreed between the employers and the offshore workers,   See Reg 2. For a further discussion of the meaning of “working time”, see paras II-14.73 to II-14.80. 109   Landeshauptstadt Kiel v Norbert Jaeger [2003] ECR 1–8389. The case is further discussed at para II-14.74. 110   Landeshauptstadt Kiel v Norbert Jaeger [2003] ECR 1–8389. 111   [2011] UKSC 57; 2012 SC (UKSC) 250. 108

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who worked a pattern of “two weeks on/two weeks off”, that the first two days of each period of their field break was compensatory rest, to make up for the fact that they worked a 12-hour shift each day during their two weeks offshore. Rest breaks (Reg 12) A worker is entitled to a rest break if his daily working time exceeds II-14.52 six hours. He is entitled to a designated 20 minutes of uninterrupted rest away from his workstation if he has one. Employers are not just required to permit the taking of a rest break; they have to actively ensure that working arrangements allow for rest breaks.112 The worker is entitled to know at the start of the break that it is such a break.113 So a period of 20 minutes which turns out to be down time cannot in retrospect become a rest break just because it can be seen, after it is over, that it was an uninterrupted period of at least 20 minutes.114 A collective agreement or a workforce agreement can specify a longer break. Reg 21(a) states that Reg 12(1) does not apply to offshore workers. However, this is again subject to the requirement in Reg 24, discussed at para II-14.50; and again, as a result of the Jaeger case,115 in practice these subsections do actually need to be applied although there is some flexibility in respect of the timing of allowing these rest entitlements. Shift work (Reg 22) Daily rest periods and weekly rest periods are stated in Reg 22 not II-14.53 to apply to shift workers when they change shifts and cannot take a daily rest period or a weekly rest period between one shift and the next. Shift workers could have to do, for example, two shifts together with no daily rest between them. The provisions regarding daily rest and weekly rest also do not apply to those whose work is split up over the day (the Regulations give cleaners as an example; chefs would be another example). However this is again subject to the requirement in Reg 24, and the effect of Jaeger, both of which are discussed at para II-14.74. “Shift work” is defined in Reg 2 as meaning “any method of II-14.54 organising work in shifts whereby workers succeed each other at the same work stations according to a certain pattern, including a rotating pattern, and which may be continuous or discontinuous, entailing the need for workers to work at different times over   Scottish Ambulance Service v Truslove UKEATS/0028/11/BI; 2012 WL 280455; Grange v Abellio London Ltd [2017] IRLR 108. 113   MacCartney v Oversley House Management [2006] ICR 510. 114   Gallagher v Alpha Catering Services Ltd (t/a Alpha Flight Services) [2005] ICR 673. 115   Also discussed at para II-14.51. 112

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a given period of days or weeks”. In Sindicato de Medicos de Asistencia Publica (SIMAP) v Conselleria de Sanidad y Consumo de la Generalidad Valenciana116 doctors in primary care teams were required to carry out a period of on-call duty every 11 days, at which time they would be on call from the end of the normal working day until the start of the following working day. The ECJ held that the work performed by the doctors while on call was shift work. They were assigned successively to the same work posts on a rotational basis, which made it necessary for them to perform their work at different hours over a given period of days or weeks. II-14.55 Some offshore workers will be shift workers for the purposes of the Working Time Regulations. In light of the Jaeger ruling, it would seem that a shift worker could do no more than two shifts before taking his equivalent compensatory rest period. Night work (Reg 6) II-14.56 The average hours of work for a night worker in any reference period117 must not exceed 8 in any 24-hour period. The definition of a night worker is a person who, as a normal course, works at least 3 hours of their daily working time during “night time” (which is defined as being between 11 pm and 6 am) (Reg 2). For the purposes of this provision, “as a normal course” is stated to mean that the person works such hours on the majority of days on which he works. However in R v A-G for Northern Ireland ex p Burns,118 which applied to a period of employment before the UK had transposed the Working Time Directive into domestic law for Northern Ireland, the worker worked for at least 3 hours between the hours of 11 pm and 6 am but only during 5 of a cycle of 15 shifts. The shifts were 8 hours long. It was nevertheless held by the High Court in Northern Ireland that she was a night worker. The Court construed the words “as a normal course” in the Directive as meaning “as a regular feature” and rejected the argument that a person required to work night shifts predominantly in order to fall within the definition of a night worker.119 II-14.57 Regulation 6 also provides that an employer must ensure that a night worker whose work involves special hazards or heavy physical or mental strain works for no more than 8 hours in any   [2000] ECR 1–7963.   Regulation 6(3) provides that the reference period applying to a night worker will be 17 weeks, unless this is modified by a collective or workforce agreement, by virtue of Reg 23(a). 118   [1999] IRLR 315. 119   At the time the case was heard, the Working Time (Northern Ireland) Regulations 1998 (SR 1998/386) had entered into force as from 23 November 1998 and were essentially the same as the Regulations which came into force on 1 October for Great Britain, including the definition of “night worker”. 116 117

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24-hour period. The work will be regarded as involving “special hazards or heavy physical or mental strain” if it is identified as such in a collective agreement or a workforce agreement or in a risk assessment made by the employer under Reg 3 of the Management of Health and Safety at Work Regulations 1999. Regulation 21(a) states that Reg 6(1), (2) and (7) do not apply to II-14.58 offshore workers. However, this is again subject to the requirement in Reg 24 and the effect of Jaeger, both of which are discussed at para  II-14.74. The practical result is that these subsections do actually need to be applied although there is some flexibility in respect of their application. At present, manned rigs or platforms will have a variety of workers who would fall within the definition of night workers who work in the region of 12 hours at a time. This is going to exceed the average limit of eight hours in any 24-hour period, or the straight eight-hour limit in 24 hours that applies if the work involves special hazards or heavy physical or mental strain. The combined effect of Regs 21 and 24 and ECJ jurisprudence means that the employer will need “wherever possible”120 to allow compensatory rest which follows on immediately. Therefore that worker will need daily rest of 11 consecutive hours in each 24-hour period but he will also need compensatory rest of approximately 4 or 4.5 hours121 for each 12.5-hour work period that is worked. Therefore it does not appear that this current work pattern122 can comply with the Working Time Regulations. An employer must arrange for a night worker to have the oppor- II-14.59 tunity of a free health assessment before the worker starts the assignment and thereafter the worker is entitled to a free health assessment at regular intervals. If a registered medical practitioner advises an employer that a worker is suffering from health problems which the practitioner considers is connected to the fact that the worker carries out night work, then the employer must transfer the worker to some other work to which he is suited and stops him working at night, if this is possible.123

  Reg 24.  If the work does not involve special hazards or heavy physical or mental strain, presumably the worker would not need to be given 4 or 4.5 hours’ compensatory rest for each 12.5-hour working period – simply the number of hours that would bring the worker within the eight-hour average in a 17-week reference period. 122   Note that this pattern of one person working 12 hours during the day and one person working 12 hours during the night would not fall within the definition of “shift work” in Reg 2, as it does not entail the need for workers to work at different times over a given period of days or weeks. 123   See Reg 7. 120 121

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Pattern of work (Reg 8) II-14.60 Where the pattern of work is such as to put the health and safety of a worker at risk, for example where the work is monotonous, the employer must ensure that the worker is given adequate rest breaks. Employer’s obligation to keep records (Reg 9) II-14.61 The employer must keep records in respect of each worker on the maximum weekly working time, length of night working, and any health assessments of night workers. These records must be kept for two years from when they were made. Entitlement to annual leave (Reg 13) II-14.62 Regulation 13 and 13A gives the right to workers to 5.6 weeks’ paid annual leave. The Transocean124 case has established that offshore workers must take their annual leave entitlement during periods when they were onshore on field break. The Supreme Court held that “leave” means a period which is not “working time” irrespective of where the worker is and what he is doing, so long as it is a period when he is not working. Any period when the worker is on field break onshore falls into this category. The claimants in the Transocean case, who were all offshore workers working on installations situated on the UKCS, claimed that their employers were in breach of the Working Time Regulations 1998 in failing to give them their then four weeks’ paid annual leave during a period when the worker would otherwise be offshore.125 II-14.63 Holiday pay. It has been the practice of some employers to include within the worker’s hourly rate of pay an amount that is designated as holiday pay, so that when the worker takes annual leave he receives no remuneration. II-14.64 The ECJ ruled in CD Robinson Steele v RD Retail Services Ltd126 that designating a proportion of the worker’s basic pay as being “holiday pay” so that the worker receives no pay while he is on annual leave is not permitted by Article 7 of the Working Time Directive. The whole point of requiring that annual leave be paid, said the ECJ, was that the worker was put in the same position, as regards remuneration, as he was whilst he was working. Member states are to take appropriate measures to ensure that this practice is discontinued. Employers should therefore no longer follow this practice. However, in situations where this practice has already taken   Russell v Transocean International Resources Ltd [2011] UKSC 57; 2012 SC (UKSC) 250. 125  For details of the unsuccessful offshore workers’ arguments, see the first edition of this book. 126   [2006] IRLR 386. 124

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place, provided that there genuinely is additional pay over and above that paid for the work done, and that this rolled-up holiday pay has been clearly designated as such, then these amounts can be set off against the payment that the worker is entitled to, for specific leave which is taken by the worker.127 When holiday pay is being calculated the employer should take into account, for the minimum 5.6 weeks’ statutory annual leave, any non-guaranteed but compulsory overtime128 and commission,129 as the worker is entitled to have his holiday pay calculated by reference to his normal remuneration.130 Exclusions Regulation 5 A worker can agree in writing to contract out of the average II-14.65 maximum weekly working time, either for a specified period of time or for an indefinite period of time. Either party can terminate this agreement by giving notice of not less than seven days. This notice period can be made longer with the agreement of both parties but cannot be longer than three months (Reg 5(2) and (3)). Regulation 21 As has already been noted above, Reg 21 states that certain provi- II-14.66 sions do not apply to certain workers, including offshore workers. The regulations which are stated to not apply are the length of night work, daily rest, weekly rest and rest breaks. However, as previously stated,131 this is subject to the requirement in Reg 24 and Jaeger. In practice, therefore, these regulations do need to be applied, albeit there is scope for flexibility in respect of the timing of these rest entitlements. Regulation 23 Regulation 23 allows a collective agreement or a workforce agreement II-14.67 to exclude or modify some of the regulations in relation to particular workers. The regulations which can be modified or excluded are the same as those which are stated not to apply to offshore workers and this regulation is also subject to Reg 24, so there would appear to be little, if any, need for such collective or workforce agreements for offshore workers.   See eg Lyddon v Englefield Brickwork Ltd [2008] IRLR 198.   Bear Scotland Ltd & Ors v Fulton & Ors [2015] 1CMLR 40; [2015] IRLR 15 EAT. 129   Lock v British Gas Trading Ltd [2013] CJEU Case C-539/12 and in the Court of Appeal – Lock v British Gas Trading Ltd [2016] EWCA Civ 983; [2017] 1 CMLR 25. 130   Lock v British Gas Trading Ltd [2016] EWCA Civ 983; [2017] 1 CMLR 25. 131   See para II-14.50. 127

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Enforcement II-14.68 The Regulations can be enforced in three ways: by the Health and Safety Executive; by complaint by a worker to an employment tribunal; and by an action for breach of contract of employment. Each will be considered in turn. The Health and Safety Executive’s enforcement function II-14.69 Inspectors from the Health and Safety Executive are responsible for the enforcement of the “relevant requirements” listed in Reg 28, of which the following are particularly relevant to offshore workers: (a) the duty of an employer to take all reasonable steps to ensure that the provisions relating to the 48-hour week have been complied with, and to keep up-to-date records of workers who are subject to an opt-out agreement; (b) the duty of an employer to provide a free health assessment for a night worker and for the health assessment to be repeated at regular intervals; (c) the duty of the employer to provide adequate rest breaks when the work is monotonous; (d) the duty of the employer to keep adequate records and to retain them for two years; (e) the duty of the employer to ensure that equivalent compensatory rest periods are given where relevant. II-14.70 The inspectors’ powers of enforcement are listed in Schedule 3 and are the same as those possessed by inspectors under the Health and Safety at Work Act 1974.132 An employer who fails to comply with the relevant requirements is guilty of an offence (Reg 29). It is also an offence to obstruct the inspector, give false information to an inspector or prevent another person from appearing before the inspector or from answering his questions (see Reg 29 and Sch 3). Enforcement officers also have the power to issue an improvement notice, which requires the employer to remedy any contravention that the inspector thinks is taking place or has taken place and is likely to be repeated. Failure to comply with such a notice is an offence (see Reg 29 and Sch 3). Enforcement by worker’s complaint to employment tribunal II-14.71 Reg 30 provides that the complaint to the employment tribunal must  For an account of the inspector’s powers under that legislation, see M Tyler et al., Tolley’s Accident Handbook (2nd edn, 2007), Chapter 6.

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be made within three months from the date on which it is alleged that the exercise of the right should have been permitted or, in the case of holiday pay, from the date when the payment should have been made. The tribunal may extend the period if it was not reasonably practicable to bring the complaint within it. If the complaint is well founded the tribunal will make a declaration to that effect and may award compensation of such amount as the tribunal considers to be just and equitable, having regard to the employer’s default in refusing to permit the worker to exercise the right in question, and any loss sustained by the worker attributable to that default. With regard to holiday pay, the amount that is due will be awarded. A claim for non-payment of holiday pay may also be brought under the unlawful deduction of wages provisions of Sections 13–23 of the Employment Rights Act 1996.133 If there is a series of deductions the latter will be preferable, as such a claim can be raised within three months of the last deduction in the series. The three-month time limit in Reg 30 is more restrictive. Enforcement by action for breach of contract of employment In Barber v RJB Mining (UK) Ltd134 the High Court found that it II-14.72 was clearly the intention of Parliament that Reg 4(1) create a freestanding right that be incorporated into all contracts of employment, limiting an employee’s average working time to 48 hours. The High Court granted a declaration that the employees need not work at all until such time as their average working hours fell below 48 hours. Interpretation and application of the Working Time Regulations “Working time” is defined in Directive 93/104/EC and in the Working II-14.73 Time Regulations 1998 as any period when the worker “is working, at his employer’s disposal and carrying out his activity or duties …”. In SMAP,135 the ECJ held that time spent by the doctors on call where they are present at the healthcare centre was all working time. The ECJ felt that the first two conditions of the working time definition were clearly fulfilled and even when the doctors were not actively performing their services at a time they were on call, because the doctors were obliged to be present and available at their workplace with a view to providing their professional services, this 133   Ainsworth v Inland Revenue Commissioners [2009] UKHL 31; [2009] 4 All ER 1205; [2009] ICR 985; [2009] IRLR. 677. 134   [1999] 2 CMLR 833. 135   Sindicato de Medicos de Asistencia Publica (SIMAP) v Conselleria de Sanidad y Consumo de la Generalidad Valenciana [2000] ECR 1–7963. The facts of the case were discussed at para II-14.54.

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meant that they were carrying out their duties in satisfaction of the third condition. However, the ECJ held that the situation where the doctors were on call, not physically at the healthcare centre, but obliged to be contactable at all times, did not amount to working time. This was because the doctors could manage their time with fewer constraints and pursue their own interests when they were on call but not having to remain within the healthcare centre. II-14.74 The Jaeger case136 was concerned with time spent on call by a doctor in a hospital where the doctor was provided with a rest room and allowed to sleep when not required on duty. The ECJ held that the fact that the doctor could sleep did not alter his obligations whilst he was on call and in the hospital. The time spent sleeping was still working time. Further, it held that if there was a reduction in the daily rest period of 11 consecutive hours, because of a period of on-call duty in addition to the normal working time, then equivalent compensating rest periods (provided in the Working Time Regulations at Reg 24) must be given to workers immediately following the corresponding periods worked and that this reduction in daily rest must not lead to the maximum weekly working time being exceeded. In reaching their decision, the ECJ looked at what the purpose of a rest period was. It felt that it was to allow a person to recover from the fatigue engendered by their work, and also to reduce the risk of adversely affecting the safety and health of a worker as far as possible, something that successive periods of work would be prone to do. In the context of equivalent compensating rest periods, the ECJ stated that, in order to neutralise the effects of work on his safety or health, the worker during these periods must not be subject to any obligation vis-à-vis his employer that may prevent him from pursuing freely and without interruption his own interests. The ECJ also stated that in order to rest effectively the worker must be able to remove himself from his working environment for a specific number of hours which must not only be consecutive but must also directly follow a period of work in order to enable him to relax and dispel the fatigue caused by the performance of his duties. II-14.75 The EAT case of MacCartney v Oversley House Management137 involved the working time of a residential home manager who was on 24-hour call, four days a week. She lived in an apartment situated on the top floor of the residential home, and her office was in the apartment. The EAT found that the whole period when she was on call constituted working time. The EAT based its decision on a number of factors. The claimant was required to remain at or

  Landeshauptstadt Kiel v Norbert Jaeger [2003] ECR 1–8389.   [2006] ICR 510.

136 137

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within a very short distance of her home, which was located within her place of work and contained her office; she was never off duty; she was always liable to answer calls directly from residents; and she had to remain at the place determined by her employers with a view to performing services if need be or when requested to intervene. The EAT considered its decision to be supported by the ECJ’s dicta in Jaeger about the purpose of rest periods. Such conditions were not met where a worker was required to be on call in tied accommodation that was a part of the workplace. In Truslove v Scottish Ambulance Service,138 the EAT said that II-14.76 the determining factor in whether on-call time was working time or not was whether the worker required to be present and remain available to the employer at a place determined by the employer, as this meant that the worker could not enjoy the quality of rest to which he was entitled to under the Working Time Regulations. The worker would not be able to exercise free choice to relax with family and friends and take part in leisure activities. Thus the time spent by the claimant paramedics on call during a night shift in which they were required to stay in accommodation of their choice but within a three-mile radius of the ambulance station that served the area in which they were providing cover for that period, was working time. The paramedics also had a target time of three minutes in which to mobilise if called upon. The EAT felt that in this situation the workers were still very much under the control of their employer. Their time was not their own. They were less able to relax and enjoy relief from the physical and mental stresses of their employment. Accommodation for offshore workers will normally be on the oil II-14.77 installation that the worker is working on, or on a “flotel” which is attached to the oil platform by a gangway. Leisure and catering facilities will normally be part of the accommodation section. The case law discussed at paras II-14.73 to II-14.76 suggests that this geographical set-up has serious implications for the maximum weekly working time of an offshore worker, the offshore worker’s entitlement to daily rest and, in some cases, to weekly rest. The major question which arises, in light of what the ECJ has said about working time and rest periods and the EAT’s decision in MacCartney and Truslove, is this: is the time when an offshore worker is on the rig, but not actually providing services for his employer, a rest period for the purposes of maximum weekly working time, daily rest and weekly rest, or is it working time? Reg 2 of the Working Time Regulations provides that a “rest II-14.78 period” is a period which is not working time, other than a rest

  [2014] ICR 1232.

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break or leave to which the worker is entitled under the Regulations. The physical presence of the worker at his workplace would appear at first sight to be a very relevant factor for the ECJ in its decisions in SIMAP and Jaeger. It is clear from Jaeger that merely by the fact that the offshore workers use this time to sleep does not mean that it is a rest period and does not mean that it is not working time. However it could be argued that, on closer inspection of these cases, it is the fact that the worker is required to be at the place determined by the employer and to be available to the employer in order to be able to provide his services immediately if there is a need which is the decisive factor both for the ECJ and thereby also for the EAT. II-14.79 Looking at the decisions in SIMAP and Jaeger, the important factors for the ECJ in time being a rest period and not being working time would appear to be: (a) The worker not having to be at a place determined by the employer and available to the employer to provide his services immediately if there becomes a need. In the offshore context the worker will obviously generally be physically available to the employer.139 However, if the position is that the worker, although physically present, is never required to work between his working hours, then it can be argued that he is in the same position as someone who works at a remote location. The fact that the worker is on the oil rig between his working hours is due to circumstance and the practicalities of the geographical position of his place of work. The worker is not required to be on the oil rig because it is so determined by his employer, so much as it simply is not practical for him to go elsewhere. (b) The worker can pursue his own interests freely without interruption. The offshore workers are apart from their family and social environment and have restricted freedom to manage the time when they do not have to perform their services. This was stated to be of relevance by the EAT in Truslove, where Mr Justice Langstaff emphasised the qualitative requirements of a rest period. However the oil rigs do have leisure facilities and if the worker can utilise those facilities and otherwise do what he wants in his free time without disturbance, then it can be argued that he is pursuing his own interests freely and without interruption. (c) The worker must be able to remove himself from his working environment. The worker cannot get off the oil rig. On the other hand he can and does go to the accommodation block   The position may be different when the worker is housed in a separate “flotel” accommodation unit.

139

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e mp l oy me nt l aw i s s u e s 483 of the rig which, even in instances where the accommodation module is part of the same platform as the working areas, and a fortiori where it is not, is a quite different environment from the “business end” of the platform.140 Does the ECJ mean that the worker must be able physically to remove himself, or will the ability mentally to remove himself suffice? The purpose is to enable the worker to relax and dispel the fatigue caused by work. It is arguable that so long as he cannot be called on to provide his services, the worker can mentally remove himself, relax and dispel fatigue by spending time in the accommodation block.

Purposive interpretation It should be kept in mind that the Working Time Directive was II-14.80 passed as a health and safety measure. The purpose of the Directive was to set out minimum health and safety requirements for the organisation of working time. The broad question that has to be asked is: does the time an offshore worker spends on the oil rig when he is not providing his services allow him sufficiently to rest, relax, dispel the fatigue caused by his work and generally neutralise the effects of his work? Practically speaking, an oil rig worker cannot be taken off the rig at the end of each working period. Even though the Regulations allow the modification or exclusion of daily rest for special cases such as offshore workers, the decision in Jaeger that the equivalent compensatory rest has to follow on immediately from the corresponding periods worked would appear to mean that an offshore worker could do no more than two shifts or work periods, before having to be taken off the rig for an equivalent daily rest period. This is not practical. Even taking the decisions of SIMAP, Jaeger, MacCartney and Truslove into account, it would appear to be open for a tribunal or court to find that despite the geographical constraints created by offshore work, an offshore worker was enjoying a rest period141 although on the oil rig, but not at a time when he was “on call”, ie not contractually bound to provide services for his employer. This was the decision

  Even if this analysis is correct for the general body of people on a rig, questions may still arise concerning a worker who ordinarily provides catering and/or housekeeping services. 141  The definition of “rest period” has been clarified by the Supreme Court in Russell v Transocean International Resources Ltd [2011] UKSC 57; 2012 SC (UKSC) 250, as any period that is not working time irrespective of where the worker is and what he is doing, so long as it is a period when he is not working. 140

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of the original ET in the Russell v Transocean142 case, which found that the time when the worker was not on duty, ie “off-shift time”, was not on-call time and was not therefore working time, even although there were obvious restrictions on the worker’s ability to do what he liked. The tribunal noted that neither the Directive nor the Regulations contain a qualitative aspect to the definition of “rest” or “rest period”. The right was to a certain quantity of rest, not to a particular quality of rest. Of course, decisions of ETs are not binding, and this aspect of the case was not taken further on appeal. However Lord Hope, in the Supreme Court judgment in the Transocean143case dealing with annual leave, also relied on the fact that there was no indication that the Working Time Directive was concerned about the quality of the minimum periods of rest; there was not a qualitative requirement. In contrast, it is to be noted that Mr Justice Langstaff in his decision in the Truslove case, some three years after the Transocean decision, identified the qualitative nature of a rest period as quite central to his decision that the on-call time in that case was not a rest period, but working time. Therefore this particular point, about whether off-shift time on an oil rig is working time or a rest period, does not appear to be finally resolved judicially and, arguably, could still be open to interpretation. Proposals for the future II-14.81 The proposals for amendment of the Working Time Regulations, referred to in the first edition of this book, made no progress.144 The discussions between the Council and the EU Parliament failed at conciliation stage in 2009. Since then the UK Government has consulted on the Regulations.145 The European Commission has initiated a review of the Working Time Directive and has consulted on the impact of the Directive, which consultation ended in March 2015.146 The Commission sought views on the right to opt out of the maximum 48-hour working week, on-call time, the inactive part of on-call time, or “stand-by time” as it is now being referred to, compensatory rest, autonomous workers, the treatment

  Russell v Transocean International Resources Ltd, Unreported, 21 February 2008 (ET), S/104056/04. 143   Russell v Transocean International Resources Ltd [2011] UKSC 57; 2012 SC (UKSC) 250. 144   See the first edition of this book for details of the proposed reforms. 145   Government Consultation on Modern Workplaces – May 2011. 146   Public consultation on the review on the Working Time Directive (Directive 2003/88/ EC). 142

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of concurrent contracts, the standard four-month reference period, and whether the Working Time Directive should introduce specific rules regulating  particular situations and types of contracts such as telework, zero-hour contracts, flexitime and performance-based contracts. The Commission plans on producing an impact assessment of a range of possible options for the review. The UK is, of course, planning to leave the EU. The Government II-14.82 has stated that it intends to transfer all workers’ rights that stem from the UK’s membership of the EU into UK law.147 However it would appear that any changes that are made to the Working Time Directive may well take place after the UK leaves the EU, in which case it would be up to the Government of the day to decide whether to adopt these changes into domestic law. DISMISSAL OF EMPLOYEES AT THE REQUEST OF A THIRD PARTY Another employment problem that can arise within the oil and gas II-14.83 industry is when the platform operator decides, for one reason or another, that it no longer wants certain of the contractor’s personnel working on that platform and requests the contractor to remove these personnel. If the personnel are employees of the contractor, ie if they have a contract of employment with the contractor, then the contractor has the problem of employees with no work to do. If they cannot redeploy these employees they will want to terminate their contracts of employment. However if the contractor has continuously employed these employees for at least two  years, then they have the right to claim unfair dismissal. In these circumstances the employer must act reasonably in dismissing the employee because of this third-party pressure. In Dobie v Burns International Security Services (UK) Ltd,148 the Court of Appeal said that in considering the employer’s reasonableness or otherwise in dismissing the employee, the tribunal should have regard to the extent that the employer considered any injustice suffered by the employee. From the cases referred to in the following paragraph, any injustice would seem to be lessened where the employee’s own contract warned that a third party could have him removed and a reasonable employer would also be expected to consider whether the employee could be redeployed. Two relevant cases to the oil and gas industry are the EAT case of II-14.84 Petrofac Offshore Management Ltd v David Olley and Others149 and   The Government expressed this intention in Parliament on 7 November 2016.   1984 ICR 812, CA. 149   2005 WL3142404 (EAT). 147 148

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the earlier EAT decision of KCA Drilling Ltd v Robert S Breeds.150 The decision in Petrofac showed far less sympathy for the position that the contractor found itself in than did the earlier KCA Drilling Ltd. In Petrofac, the claimants were employed under contracts of employment, with Petrofac Offshore Management Ltd (POM). They were employed by POM to work on oil installations in the North Sea which were owned and operated by another company, Kerr McGee. There was a contract between Kerr McGee and Petrofac Facilities Management Ltd (PFM) whereby PFM undertook to provide Kerr McGee with personnel and managed services. There was then a contract between PFM and POM whereby the latter provided personnel to PFM to enable PFM to fulfil its contractual obligations to Kerr McGee. (PFM and POM were in the same group of companies.) II-14.85 The contract between Kerr McGee and PFM allowed Kerr McGee to instruct PFM to remove from the oil installation any personnel provided by PFM, but only for specific reasons. The personnel could be removed if, in the reasonable opinion of Kerr McGee, the personnel were not needed by Kerr McGee and their continued use could not be satisfactorily justified to Kerr McGee; if they were incompetent, negligent or were guilty of misconduct; if they were engaged in activities which were contrary to or detrimental to the interests of Kerr McGee; or if they were not conforming with procedures laid down by Kerr McGee or their conduct was likely to prejudice safety, health or the environment. The contract between PFM and POM stated only that POM recognised the right of PFM to request that the personnel provided by POM be replaced. II-14.86 Kerr McGee instructed PFM to remove certain personnel which included the claimants. It gave no reasons and, when asked in writing by PFM for reasons and further explanation, Kerr McGee simply referred to the clause dealing with removal of personnel. PFM later made a verbal request for reasons to Kerr McGee but this did not receive a response. POM did not contact Kerr McGee to ask for reasons at all. The claimants were subsequently dismissed by POM. II-14.87 The tribunal had found that the dismissals were procedurally unfair because POM had refused to allow the claimants to have present at the appeal hearing and the meetings when the claimants were advised that they were to be dismissed, a representative from their union (because POM did not recognise the union of which they were members). It found however that it was highly probable that the claimants would have been dismissed in any case, and relying on

  2000 WL824099 (EAT).

150

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Polkey v AE Dayton Services Ltd151 and Fisher v California Cake & Cookie Ltd,152 reduced the compensation by 90 per cent. The EAT, however, found that the factors which the tribunal had II-14.88 found were indicative of unfairness and other matters which the tribunal had taken into account were not just procedural but went to the substance of the case. The EAT found that the claimants’ length of service, their excellent work records, the “clear” and “grave” injustice to the claimants, the fact that POM were aware of this injustice, the fact that more could have been done to persuade Kerr McGee to change its mind, and more could have been done to try to redeploy the claimants all pointed to substantial unfairness. The EAT also found that the tribunal had taken into account matters which they had no basis for taking into account since they had no basis in the findings of fact made on the evidence laid before the tribunal. For example, the tribunal had been influenced by what it saw as the competitive nature of the industry, and that PFM was in a weaker bargaining position with Kerr McGee, which would be a valued customer of PFM and was in a powerful position. The EAT found that this was however simply speculation or assumption. The tribunal had also based its decision on its finding that the request by Kerr McGee for the removal of the personnel had been legitimately made. The EAT found that it was not open for the tribunal to make this assessment when actually Kerr McGee had given no indication that it was making that request for any of the legitimate reasons laid down in the contract and in fact gave no reasons whatsoever. As a result, the EAT remitted the issue of the nature and extent to which the unfairness of the dismissals went beyond matters of procedure so as to determine whether the compensation to which the claimants were entitled should be reduced. The position taken by the EAT differs significantly from that II-14.89 taken in KCA Drilling Ltd. The appellants (KCA Drilling Ltd) were contractors who provided personnel to work on an oil platform that was operated by Kerr McGee. The contract between the appellants and Kerr McGee allowed Kerr McGee to instruct KCA to remove personnel provided by the appellants for the same reasons as in the Petrofac case. There was also a provision in the contract between the employee (Mr Breeds) and KCA that a client may require an employee to be removed from a rig or platform and that, in such a case, it may result in KCA Drilling terminating that employee’s employment. After certain allegations were made against Mr Breeds, Kerr McGee advised the appellants that they no longer wanted Mr Breeds to remain on the platform as materials clerk.

151 152

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  [1987] IRLR 503.   [1997] IRLR 212.

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II-14.90 The employment tribunal held that the contractors had not acted reasonably (under Section 98(4) of ERA 1996). They had simply complied with Kerr McGee’s request to remove Mr Breeds. They did not support their employee, as a reasonable employer would have done. They did not have regard to the “clear injustice” to Mr Breeds. They did not make any further representations to Kerr McGee after they had obtained Mr Breed’s version of events even though he had been “an entirely satisfactory employee” who had worked with KCA Drilling Ltd for a number of years. II-14.91 At appeal, the appellants argued that the tribunal’s approach was not relevant when there was a contractually legitimate instruction by a third-party client to remove the employee from the platform; the tribunal should have given proper weight to the reality of this situation. The EAT accepted that the appellants’ argument was correct. It held that the tribunal had confused what it might be necessary for an employer to do where there was a possible dismissal on the grounds of capability or misconduct with the situation that in fact prevailed – an “intractable” client making a request which was legitimately being made in the contractual context. The EAT did also place importance on the fact that Kerr McGee was not requiring that the employee be dismissed, but that he cease to work on the platform as materials clerk. Kerr McGee had been prepared to have the employee back in a lower capacity though when the appellants offered Mr Breeds this, he refused the offer. So the EAT very much took the reality of the situation into account when assessing reasonableness. It saw the situation as the employer having acted reasonably in responding to a legitimate request by Kerr McGee but nevertheless taking considerable steps to try to offer Mr Breeds alternative employment. The EAT accordingly overturned the decision of the tribunal that the employee had been unfairly dismissed. II-14.92 There are differences on the facts between these two cases. More seems to have been done for Mr Breeds than for the claimants in Petrofac in terms of redeployment and this point was clearly of significance to the EAT. However, the common issues that emerge is the injustice to the employee and the contractor’s failure to challenge the decision of the platform operator and try to convince against removal. The EAT’s attitude to what was argued to be a contractually legitimate request certainly differed in these two cases. The tribunal in Petrofac and the EAT in KCA Drilling Ltd were mindful of the uneven bargaining power of the parties in this kind of situation. However, the EAT in Petrofac was far less willing to take into account the reality of the situation when an operator makes such a request. It did not feel it could view the request to remove the personnel as legitimate because the contractor had no idea why the request was being made.

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What can be drawn from these cases would therefore appear to II-14.93 be that a contractor will not be able to rely on the mere fact that the operator required the personnel to be removed and that the contract between the operator and the contractor allows such a request to be made. The tribunal will look behind the request to see if it truly was a contractually legitimate one. The contractor itself will need to make efforts to discover the reasons for the request, investigate the circumstances and, if appropriate (for example, where it appears the allegations are trivial or perhaps motivated by prejudice, or where the reason does not in fact fall within the terms of the contract), try to persuade the operator against removal. If the removal cannot be avoided, the contractor will then have to make proper efforts to redeploy the employee. It has been suggested that the contractor go as far as interdicting the operator from removing the employee if the circumstances require this. In practice it is highly unlikely that a contractor would ever take such a course of action. Such a suggestion entirely fails to take account of the reality of the bargaining position of the contracting parties. However, it would appear from Petrofac that the contractor would be well advised to lead evidence of the nature of the industry and the relative bargaining powers of the parties at any subsequent unfair dismissal tribunal hearing.

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CHAPTER II-15 DISPUTE MANAGEMENT AND RESOLUTION Margaret Ross and Valerie Allan

INDUSTRY CULTURE II-15.01 As in other industries, a broad range of disputes regularly arise in the oil and gas industry, from straightforward payment disputes to complex technical, commercial and investment disputes. In the oil and gas industry in particular, very significant sums of money may depend upon the successful resolution of those disputes. Consequently, a broad range of dispute resolution processes are used across the oil and gas industry on a daily basis to resolve disputes having varying degrees of complexity and formality. Particularly where disputes prove difficult to resolve, close attention is often paid to the choice of process appropriate to the dispute. This is influenced by a number of factors: need, preference and, above all, commercial intuition. There is a need for processes that are fast, effective and cause minimum disruption to working processes and relationships. The preference is for processes which are both private and flexible. They require to be capable of crossing both international boundaries and business cultures. While, historically, there has been a limited pool of industry players, they have operated within a global marketplace. These factors combined to create an incentive to avoid making future enemies out of the present dispute, and drew into the range of choices the dispute resolution experiences and preferences of many nationalities and professions. As the industry has matured and expanded over time, slightly more willingness to use adversarial methods has become evident, driven less by regard for long-term relationships and more by desire for court-ordered enforceable remedies and perceived accuracy of return.1 1

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  Recent research by the ICEA suggested a preference amongst respondents for arbitration

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The dynamism of the industry had drawn parties and their II-15.02 advisers to possible choices in a spectrum of dispute resolution mechanisms more swiftly than had been the case in other industries where cultures can be more adversarial, and ongoing relationships less vital. These choices might be described as “exit points” from the dispute. The industry found routes away from the dispute with an eye to prospective dealings and opportunities.2 In other commercial contexts, dispute resolution choices have often been more limited and more closely tied to the retrospective adjudicative processes of litigation and arbitration. The predominance of in-house counsel and specialist external counsel has helped to ensure that in commerce more broadly, the processes selected are driven by the client’s commercial imperatives rather than the norms of civil litigators.3 However, lawyers in European member states reported more familiarity with litigation than mediation.4

Dispute resolution spectrum of choice This chapter will examine the methods of dispute resolution that II-15.03 have been found to be favoured in the oil and gas industry; the specific benefits and detractions of these; examples of their usage as exit points or levers in a spectrum from informal and unilateral action to litigation; and provide qualitative commentary on such methods.5 or hybrid arbitration processes. See their Initial Report into Dispute Resolution in the Energy Sector, available at www.scottisharbitrationcentre.org/?p=1695 (accessed 10 September 2017). 2   This topic features heavily in specialist repositories of material available on subscription only, namely Oil, Gas & Energy Law (OGEL), accessible at www.gasandoil.com/ogel, and Transnational Dispute Management (TDM), accessible at www.transnational-disputemanagement-com (both accessed 2 May 2017). 3  Explored in Scottish Government, Report of the Business Experts and Law Forum (BELF), November 2008, particularly Chapter 3, available at www.scotland.gov.uk/ Publications/2008/10/30105800/11 and in Dispute Resolution in London and the UK 2010, a report of TheCityUK (a commercial membership organisation), available at www. thecityuk.com (both accessed 2 May 2017). B Clark and C Dawson, “ADR and Scottish Commercial Litigators: A study of Attitudes and Experience”, 26 (Apr) (2007) CJQ, 228 (hereinafter “Clark and Dawson, ‘ADR and Scottish Commercial Litigators’”), at 247 notes the phenomenon of commercial clients driving lawyers’ advice, referring to studies in the USA identifying that corporate lawyers are “tools” or “conduits” of their clients. 4  ADR Center (funded by the EU and in association with the European Association of Craft, Small and Medium-Sized Enterprises and European Company Lawyers Association), The Cost of Non ADR – Surveying and Showing the Actual Costs of IntraCommunity Commercial Litigation, June 2010, available at www.adrcenterinternational. com/the-cost-of-non-adr-surveying-and-showing-the-actual-costs-of-intra-communitycommercial-litigation (accessed 2 May 2017); part of the Lawyers and ADR EU project. 5  The commentary is influenced, in part, by questionnaire surveys and structured inter-

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II-15.04 The spectrum of dispute resolution processes referred to above is divided for the purposes of this chapter into six sections, although there is overlap between them.6 These are: 1. 2. 3. 4. 5. 6.

unilateral action; collaboration and negotiation; assisted collaborative non-binding processes; expert determination; arbitration and litigation; and implementation and enforcement processes.

II-15.05 The parties may use a combination of these, either consecutively or contemporaneously. II-15.06 In general it is advisable to anticipate disputes in advance and provide for them by way of express dispute resolution clauses. However, there is merit in coming back to the issue of choice at times when disputes arise or are ongoing, or even as they are played out in a process which proves unable to deal with all of the underlying aspects in a way which will make most commercial sense for the future. The immediacy and commercial consequences of a dispute in the oil and gas industry mean that time spent on unsuitable processes is costly. Time spent between lawyer and client merely to understand and articulate the dispute in a court or arbitration for the benefit of a third-party decision-maker may be expensive and delay resolution. There is the risk that parties from outside the industry, or those who are new to it, will not understand the broader commercial considerations that will affect any particular attempts to resolve the dispute, quite apart from lawyers and judges having to try to understand the technical aspects of the dispute. Dispute anticipation and management II-15.07 This chapter also considers the topic of dispute management through anticipation and avoidance. Increasingly, processes that have been used in the resolution of disputes which have arisen are recognised for their potential in managing situations in which disputes may be predictable but are not yet apparent, and building consensus in advance of activity so that opportunities for dispute are minimised. Consensus-building and risk management processes which engage views with lawyers and managers in a range of oil industry players operating in the North Sea (although most also have experience of business in other parts of the world). The broad outcomes of these are reflected in this chapter. 6   For a thorough general description of dispute resolution processes and the factors that influence choice, see H Brown and A Marriott, ADR Principles and Practice (3rd edn, 2011).

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potentially affected parties in the “stakeholder” range are now commonplace in the industry.7 This can shift the timeline for considering disputes to the developmental end of business activities, particularly when environmental or safety risks have to be managed. Many oil and gas industry companies now also routinely invest II-15.08 in “lessons learned” analyses at key milestones during a project or following resolution of a particular dispute. These processes seek to identify the underlying causes of any difficulties that have arisen and assess how such risks might be reduced or more effectively managed in future. UNILATERAL ACTION Complaints to companies and regulators The oil and gas industry is heavily regulated, and some disputes may II-15.09 have as their first port of call the complaints procedures of a particular company, regulator or industry ombudsmen. For example, the procedures of the Department for Business, Energy and Industrial Strategy (BEIS) are subject to oversight by the Parliamentary Commissioner for Administration;8 activities within a particular country may be subject to oversight by state commissioners within that country, and activities funded by the International Finance Corporation of the World Bank will be subject to review by that body’s Compliance Advisor Ombudsman. Certain decisions of the Oil and Gas Authority (OGA) may be referred to the First Tier Tribunal.9 In the UK, the Energy Act 2016 introduced a new procedure10 to II-15.10 enable a party regulated by the OGA to seek a non-binding recommendation from the OGA as to how a qualifying dispute11 should be resolved “in a way which best contributes to the fulfilment of the

  See eg Shell’s public consultation in relation to the Decommissioning Programmes for Brent, available at www.shell.co.uk/sustainability/decommissioning/brent-field-decommissioning/brent-field-decommissioning-programme.html (accessed 2 May 2017). 8   For further information, see www.ombudsman.org.uk (accessed 2 May 2017). 9   Energy Act 2016 Pt 2 Ch 2 s 26 (Appeals against decisions of the OGA: disputes); s 36 (Appeals against decisions of the OGA: information and samples plans); ss 50–52 (Appeals in respect of sanctions); s 58 (appeals against information requests). 10   Energy Act 2016 Pt 2 Ch 2 ss 19–26 (Disputes). See also OGA, “Dispute Resolution Guidance Procedure”, available at www.ogauthority.co.uk/media/2711/oga_dispute_ resolutions-guidance.pdf (accessed 2 May 2017). 11   Energy Act 2016 Pt 2 Ch 2 s 19 – a qualifying dispute is a dispute which (i) relates to issues which are relevant to the fulfilment of the principal objective or relate to activities carried out under an offshore licence; and (ii) one of the parties to which is a relevant person, being a person listed in section 9A(1)(b) of the Petroleum Act 1998. 7

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principal objective whilst having regard to the need to achieve an economically viable position for the parties to the dispute”.12 II-15.11 Rarely will such processes exclude other dispute resolution choices completely, since the jurisdiction of the regulator or ombudsman will be limited. However, an application to court for a remedy on a specific point within the remit of the regulator might be challenged on jurisdiction or prematurity grounds. Usually the processes will exist in parallel, and unless both parties agree not to use such processes they may require to do so. Indeed, even if the parties are agreed to proceed in a different way towards resolution, or reach resolution on particular terms, it may be essential to reognise the regulator’s powers, procedures and standards in what those settlement terms are, or in how they are reached. So for example, in the UK, resolution of a dispute will require consideration of the parties’ obligations under the terms of their licences and the MER UK Strategy.13 Where the matter has been referred to the OGA’s “dispute resolution guidance” procedure, the OGA has indicated that it expects parties to implement its recommendation or an equally MER UK compliant solution within a short period of receiving the OGA’s non-binding recommendation.14 Avoidance II-15.12 With any problem within the industry that might develop into a dispute, some parties choose, even without discussion, that the way to deal with the matter is to ignore it as a dispute. It is often the case that a situation which could give rise to a lawful claim or contractual breach is, on economic or business relationship terms, simply ignored. The parties proceed as if it had not occurred, or treat it as if it had occurred due to the unilateral failure of one of them who volunteers to rectify the situation. Repeated occurrence of a similar problem might attract a different reaction (dependent on scale and value), and if a choice of alternative supplier exists the decision might be simply to choose not to deal with that person or company again rather than to identify this as a dispute and attempt to resolve it. II-15.13 Separately, the economic and technical imperatives to achieve milestone dates or project completion mean that parties often choose not to raise issues of dispute at the point in time at which they arise. Rather, they choose to allow issues to accumulate, unaddressed, until after project completion, to allow parties’ focus to remain on   Energy Act 2016 Pt 2 Ch 2 s 23(4)   See Chapter I-5. 14   OGA, “Dispute Resolution Guidance Procedure” (n 10), s 7. 12 13

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ongoing work. Dependent upon a number of factors, including the overall perceived success of a particular project, parties may then seek to agree a “global” settlement of all issues that have arisen rather than engage in a process requiring detailed analysis of each disputed issue. Dominant parties A dominant party may choose to trigger termination options or II-15.14 break the contract in order to walk away from the contractual realtionship as soon as possible, in the expectation that the other, perhaps less powerful, party will be unable or unwilling to resist this by litigation or other dispute resolution process. The force majeure clause has been used by parties keen to break the contract not just because of the unexpected event, but because of other points of dispute.15 Latterly, that approach has also been considered by some in the industry as a means of achieving a commercial re-negotiation of terms no longer perceived as beneficial in a low price environment, notwithstanding the risks of such an approach. Missed opportunities? While it is undoubtedly the case that unilateral avoidance occurs II-15.15 in all justiciable situations,16 it is reported as occurring especially frequently in this industry. The reasons given for it are comparative economic strength at the time of the disputable event and desire for future business harmony. There is a tendency to “put things down to experience” rather than consider whether something has gone wrong for reasons for which others are responsible. The industry’s “zero tolerance” approach to safety, which requires the encouragement of a “no blame” culture, has perhaps reinforced that approach to some extent. Undoubtedly, in some situations a party is wise in the wish to keep quiet on the reasons for unilateral action, but, commercial sensitivities apart, it might be productive in other cases to share the fact that this decision has been taken and the reasoning behind that decision. Viewed objectively, and for good governance, both parties can II-15.16 learn more from discussing the situation and sharing their reasons for avoidance decisions than from internalising them. Even when   See eg Thames Valley Power Ltd v Total Gas & Power Ltd [2006] Lloyd’s Rep 441.   Noted to be widespread in studies funded by the Nuffield Foundation: H Genn (with S Beinart), Paths to Justice (1999) and H Genn and A Paterson, Paths to Justice Scotland (2001). See also P Pleasance, N Balmer and R Sandefeur, Paths to Justice: A Past, Present and Future Roadmap (2013).

15 16

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discussion does occur, it may not be recorded in a way to influence decisions in future cases or inform the actions of subsequent decisionmakers. Sharing the reasoning requires an element of trust that may be missing between companies already in dispute, and some parties feel that they simply have to “get to know” the dispute tactics of the other players over time. The parties’ interests in this regard may not be aligned, particularly where a long-term business relationship is not anticipated. In an industry known for its pragmatic and tailored solutions to technical and other issues, engaging in more open discussion about attitudes to disputes might be a valuable exercise, particularly at the time of forming the business relationship. COLLABORATION AND NEGOTIATION Collaboration to build consensus II-15.17 Increasingly, commercial enterprises within a risk management culture anticipate the potential for dispute and embark on consensusbuilding methods to reduce risk as part of the process of planning and implementing business activities. This has been evident in the oil and gas industry. Anticipating the environmental impact of activities, whether exploration, production or decommissioning, has led to predictive discussions with neighbouring proprietors, regulatory agencies and environmental campaigners. The extensive consultations undertaken regarding the Brent Spar Decommissioning Programmes are a high-profile example of attempts to address environmental concerns in advance.17 It is not possible to prevent all disputes in this way, and adversarial methods might nonetheless be necessary to deal with actual or anticipated dispute.18 Neighbours (whether individuals, groups or agencies) who might be affected by commercial activity are now often treated as “stakeholders”. That recognition and respect in itself may help to provide a foundation for consensual management of disputes once the commercial activities are ongoing. II-15.18 Evidence from the USA suggests that potentially disruptive or polluting activities can be approached very positively by this advance collaboration with stakeholders, and indeed with insurers who offer policies to cover the stakeholders collectively for clean-up costs or  See www.shell.co.uk/sustainability/decommissioning/brent-field-decommissioning/bren t-field-decommissioning-programme.html (accessed 2 May 2017). For a fuller discussion of the Brent Spar case, see Chapter I-12. 18   For example, to interdict or injunct anticipated delictual or tortious wrong by environmental campaigners as in Allseas UK Ltd v Greenpeace 2001 SC 844. Interdict was unsuccessfully sought in Cairn Energy Plc v Greenpeace Ltd [2013] CSOH 50 where the defenders had provided adequate undertakings in lieu of the interdict sought. 17

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mitigation of environmental impact.19 Clearly this is preferable to “after the event” damage management, as in the aftermath of the Deepwater Horizon explosion in the Gulf of Mexico. In the USA and the UK, the liberalisation of energy supply markets prompted collaborative activity between industry players and regulators to standardise information for consumers, contractual terms and dispute resolution processes. These include attempts to pre-empt and manage disputes to avoid escalation to adversarial processes.20 Even prior to the Deepwater Horizon disaster, the impact of adverse events such as high-profile disputes played out in public had begun to be measured in terms of “reputation equity”, with direct impact on share prices being measured.21 This adds pressure upon companies to create effective processes and to allocate appropriate resources to problem management and communication in order to minimise the economic impact of bad publicity from adverse events and the processing of the claims arising.22 These dispute management examples focus on the adverse dispute II-15.19 impact for the company arising from disputes, but there is also significant potential impact upon individuals; a survey conducted in 2003 among Chief Executive Officers across a range of large commercial bodies revealed significant evidence (67 per cent of respondents) to the effect that commercial disputes generate personal stresses for CEOs including sleeplessness and relationship problems.23 No doubt such impact is often felt but under-reported in the business context. Disputes can have a corrosive impact upon work performance and personal reputation of all those involved within an organisation. The evidence points clearly to the wisdom of time and money spent on creative and effective dispute management and avoidance measures.

  For further explanation and discussion of Insured Fixed Price Clean-ups, see M Hill, “A tale of two sites: How insured fixed-price cleanups expedite protections, reduce costs, and help EPA, the SEC and the public”, 3(2) (2003), American Bar Association Science and Technology Committee Newsletter 17. 20   Information is available from Ofgem, at www.ofgem.gov.uk (accessed 2 May 2017). 21  Measurement of impacts of reputation-changing events upon share value has been carried out for various large insurers and commercial entities by Oxford Metrica; see www.oxfordmetrica.com (accessed 2 May 2017). The impact of the Deepwater Horizon explosion for BP’s commercial value has been much publicised. 22  For discussion of costs associated with conflict between stakeholders and extractive industries, see R Davis and D M Franks, “Costs of company-community conflict in the extractive sector”, Harvard Kennedy School (2014). Available for download at https:// sites.hks.harvard.edu/m-rcbg/CSRI/research/Costs%20of%20Conflict_Davis%20%20 Franks.pdf (accessed 10 September 2017). 23   BDO Stoy Hayward Commercial Disputes Survey 2003. 19

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Collaborative deal-building II-15.20 Deal-building has traditionally been handled by negotiation between parties’ employees or managers, assisted by lawyers as appropriate. There is evidence that mediation is being used in some deals to broker the most productive deal for both sides, although this approach remains unusual in the oil and gas industry.24 This might be useful in situations where preliminary consideration of the issues suggests that there might be significant stumbling blocks in direct negotiation, either because of the nature of the commercial activity, or the personalities of the participants in it. Mediation can assist in identifying underlying issues that a party may not wish to divulge in direct negotiation, but which can be divulged to a mediator so that they be addressed productively through the mediator within the negotiation process. Collaborative negotiation techniques have also been used to produce dedicated approaches to disputes anticipated from changing energy markets.25 They have also been pivotal in the creation of standard form contracts for the industry in the UK26 and in alliancing and partnering arrangements.27 Most recently in the UK, the OGA has strongly encouraged a collaborative approach to deal-building through implementation of the MER UK Strategy and its focus on commercial good practice, for example, by compliance with the Commercial Code of Practice28 and the Infrastructure Code of Practice.29 Negotiation practices II-15.21 Industry players report that negotiation is the principal means of   L Boulle and M Nesic, in Mediation: Principles, Process and Practice (1st edn reprint 2005), give examples at p 298, and cite M Hager and R Pritchard, “Hither the Deal Mediators”, 10(10) (1999) ICCLR 291 and R Buckley, “The applicability of mediation skills to the creation of contracts” (1992) Australian Dispute Resolution Journal 227. 25  For example the National Association of Regulatory Utility Commissioners in the USA (NARUC) funded by the US Department of Energy, worked with the Center for the Advancement of Energy Markets (CAEM) to develop and review uniform business terms to deal with the changing energy markets. 26  LOGIC (Leading Oil and Gas Industry Competitiveness) standard form contracts (previously CRINE) are available at www.logic-oil.com (accessed 2 May 2017). 27   A Ledger, “An Agenda for Collaborative Working Arrangements: The Role of Partnering and Alliancing in the UK”, 58(2) (2003) Dispute Resolution Journal 38; K Kaasen, “Offshore Project Alliancing: The Aim, the Constraints and the Contracts”, Scandinavian Institute of Maritime Law Yearbook 1997, s 141. 28   See www.ogauthority.co.uk/media/3088/commercial-code-of-practice-2016.pdf (accessed 2 May 2017). 29  A copy of which can be found at http://oilandgasuk.co.uk/product/code-of-practiceon-access-to-upstream-oil-and-gas-infrastructure-on-the-uk-continental-shelf (accessed 2 May 2017). 24

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resolving disputes. Because much of the discussion about alternative dispute resolution (ADR) worldwide has compared ADR to litigation or other adjudicated processes, the fact that negotiation is the most widely used process is often overlooked. Negotiation at operational or manager level is likely to be the first and most productive choice, as those closest to the implementation of the contract, are usually the most knowledgeable as to the issues that give rise to a dispute and the means range within which practical and commercial options for resolution will lie. If the matter is referred to lawyers, it is usually for advice at II-15.22 first, so that managers can continue to negotiate on commercial or technical levels. However, lawyers do become involved in negotiating certain disputes to resolution or to a point at which other dispute resolution processes can be chosen. In most instances, lawyers alone will not have the technical industry expertise to conduct negotiations without the parties or appropriate managers present, unless the matter at issue falls within a neat point of law and negotiating parameters can be set in advance. Hence it can be said that the model of negotiation within the industry is client-centred. The professionalisation of a client-centred approach to dispute II-15.23 resolution is often associated with the influence of blue chip companies in the USA in the 1980s. Their insistence on practical solutions rather than the expense and delay of litigation drove their lawyers (both in-house and external) to engage in a range of consensual dispute resolution processes. In the same decade the Harvard Negotiation Program on Negotiation (PON) analysed and articulated negotiation as a skill, and advocated the principled or problem-solving approach. This focuses on the benefits of negotiation in identifying underlying interests of the parties, exploring options for mutual gain, seeking objective criteria against which to measure what is being offered, and considering in advance of the negotiation what is the best alternative to a negotiated agreement or “BATNA”: for example, is there another supplier, a prior offer or a remedy in litigation which would be preferable to a final offer in the negotiation?30

 The books emerging from the project have become best-sellers, particularly R Fisher and W Ury (2nd edn with B Patton), Getting to Yes (2nd edn, 1991; 1st edn, 1981) (hereinafter “Fisher and Ury, Getting to Yes”), R Fisher and W Ury, Getting Past No (1993) (hereinafter “Fisher and Ury, Getting Past No”) and W Ury, The Power of a Positive No (2007) (hereinafter “Ury, Positive No”). See also the project website http://www.pon. harvard.edu (accessed 2 May 2017).

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Negotiation as a specialism Training and skills II-15.24 The role of negotiation is recognised widely, yet training in negotiation techniques has been patchy in its usage in legal practice. It is often assumed that lawyers will be good negotiators with little attention to the skills or training underlying that assumption. Negotiation training is more evident in management education and in-house skills development. In the international context, the importance of negotiation of global transactions has been recognised for some decades. The Association of International Petroleum Negotiators (AIPN)31 has existed since 1981, and provides research reports, training events and style documents. Various industry bodies provide negotiation training aimed specifically at the oil and gas industry.32 Industry-specific texts are few,33 but general texts on negotiation styles and strategies help in developing one’s own approach and understanding the approaches of other negotiators.34 II-15.25 Increasingly, management education and legal education include negotiation and scope for experimentation with different techniques in the “safe” context of role-play. Individuals engaged in dispute resolution in the industry also comment that approaches to negotiation and dispute resolution are affected by an individual’s own experience of using or being drawn into different styles and methods in the workplace, and that cultural or national factors do appear to make a difference.35 So, fear of corruption in the judicial system in some countries makes players there very interested in negotiation or mediation.36 In others, such as Holland, Denmark and the Nordic countries, a “pragmatic approach” to dispute resolution is notable

  See www.aipn.org (accessed 2 May 2017).   For example, the Energy Institute in the UK. 33   For example L Mosburg, Advanced Concepts of Oil and Gas Contract Negotiation and Deal Structure (1984); S Sayer, “Negotiating and Structuring International Joint Venture Agreements”, available at www.dundee.ac.uk/cepmlp/journal/html/vol5/article5-1.html (accessed 2 May 2017). 34   Fisher and Ury, Getting to Yes, Fisher and Ury, Getting Past No and Ury, Positive No. See also the project website www.pon.harvard.edu/hnp (accessed 2 May 2017). Other sources include S Covey, The 7 Habits of Highly Effective People (revd edn, 1999), S Le Poole, Never Take No for an Answer (2nd edn, 1991), B Scott, The Skills of Negotiating (1981) and L Sweeney, “Addressing some negotiating difficulties”, 41 (1996) JLSS 349. 35  For an interesting comment on cultural issues, see B Marsh, “The Development of Mediation in Central and Eastern Europe”, in C Newmark and A Monaghan (eds), Butterworths Mediators on Mediation (2005) (hereinafter “Newmark and Monaghan, Butterworths”). 36   Ibid, para 21.21. The fear is expressed by those in business within the country rather than those outside it. 31 32

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in systems and in daily life.37 In the USA, where ADR processes have been operating for some decades, negotiation takes place with the knowledge that many choices exist for consensual resolution, but there may still be a tendency to file a suit for tactical reasons, for example, to secure jurisdiction and discovery. Lawyers and negotiation Lawyers will be most closely connected to the legal parameters II-15.26 around the dispute and therefore most likely to negotiate in that shadow. Managers and technical specialists report that lawyers can over-legalise the dispute and its resolution, rather than have a sense of what is needed to make the solution work in practice.38 Essentially, lawyers are advisers and partners rather than leaders in the negotiation process in the industry. They can advise on the strength of the party’s case in the substantive law of contract, the options available in procedural law before the courts and in arbitration (including matters of private or public international law if the contract involves parties in different countries or state parties); the terms of the contract in so far as they define the parties’ choice in dispute resolution processes; and the impact of other legal factors such as public law effects of licensing, environmental regulation or international convention. Success of negotiation at all stages of the dispute is affected by the awareness of those engaged in the negotiation of the next stages open to the parties should negotiation fail, and their understanding of the approaches to settlement of senior personnel in the dispute management process. In a study of choices in international arbitration published in 2010, lawyer interviewees noted the difficulties in getting involved in dispute process negotiation at an early enough stage and to sufficient degree, noting that they were often called in late, after the commercial terms had been agreed.39 Some players report differences in culture between companies, II-15.27 according to both the nationality of the participants in the negotiation and the country of origin of the company. This will impact the role that the lawyer is asked to play. While it may be a generalisation   G De Palo and S Carmeli, “Mediation in Continental Europe: A meandering path toward efficient regulation”, at paras 19.29–19.36, in Newmark and Monaghan, Butterworths. 38  These concerns were highlighted in: Queen Mary, University of London with White & Case, 2015 International Arbitration Survey: Improvements and Innovations in International Arbitration, available at www.arbitration.qmul.ac.uk/docs/164761.pdf (accessed 2 May 2017), p 30. 39   Queen Mary, University of London with White & Case, 2010 International Arbitration Survey: Choices in International Arbitration, available at www.arbitration.qmul.ac.uk/ research/2015/index.html (accessed 2 May 2017) (hereinafter “QMU with White & Case, 2010 International Arbitration Survey”), p 11. 37

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to link these differences to the country of origin of a company, the scope for differences in the lawyer’s role is apparent nevertheless.40 Negotiating in teams II-15.28 Given the technical nature of disputes that may arise in the oil and gas industry, many negotiations in relation to disputes require to be carried out by a team of people who can, collectively, bring the necessary expertise (for example technical, legal, financial) to the dispute and its resolution. If such negotiations are to be effective, it is key to the process to nominate, at the outset, a leader who has a realistic mandate to agree upon an outcome, even if the members of the team are not agreed. Where there are distinct aspects to a dispute, all of which require to be addressed in order to reach a resolution (for example, both technical and commercial terms) or the amount in dispute is very significant, then mandated settlement authority may be shared between individuals with the appropriate expertise or seniority within the organisation. Ensuring that one (or a small number) of the negotiating team holds appropriate settlement authority is equally (if not more) important when that negotiating team enters into a process where the negotiation is assisted by a third party (mediator or conciliator). Consequently, members of the negotiating team (not limited to legal representatives) may play advisory roles to the mandated team leader at certain points in the course of the negotiation, for example where they are included in the team due to their specific expertise on one aspect of the dispute. It can be key to the success of these negotiations to identify who in the counterparty team is the ultimate decision-maker and ensure that good negotiating relationships are built between the appropriate members of each team. The negotiating team should have parameters and authority for settlement agreed in advance, or access on the day to those who can authorise the settlement terms. If no-one in the team has the authority to settle the matter, then the negotiation is in difficulty from the start, since at very best the team can agree to take the matter back to the decision-maker for the final say. This is undermining of the negotiating team and risks the other side (particularly if it has a settlement mandate) losing patience. Failure to ensure that this mandate is in place can jeopardise any progress made by the team and lead to a breakdown in trust between the parties. However, that approach is used tactically in some circumstances to allow a negotiating team an “exit route” from the negotiations if necessary,

 These roles are explored in the context of mediation in B Clark, “Mediation and Scottish Lawyers: Past, Present and Future”, 13 (2009) Edin LR 252–277.

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particularly where there is perceived disparity in the negotiating strengths of the parties. Timing of negotiation of dispute resolution options As is clear from other chapters,41 much effort goes into negotiating II-15.29 contracts which are particular to the industry context and are reflective of parties’ needs and business imperatives. Within that process falls the negotiation of dispute resolution clauses. Most contracts will provide in some form for processes to be used in the event of dispute. Those clauses may be silent on the matter of negotiation, making the assumption that negotiation will always be attempted and that resort to more formal processes will be necessary only if negotiation fails, or may provide for one or more round of negotiation at management level before resort to more formal dispute resolution processes. At the time of contract formation, the parties are intent upon II-15.30 working together and thinking positively: the opportunity exists to tailor dispute resolution processes to fit with other approaches in the contract, or series of linked contracts. However, parties at that stage are often very anxious to have the contract completed: they have their minds on the operational and production clauses rather than those directed to potential problems; they have future successes in mind rather than failures; and they are unable or unwilling to imagine what issues, conflicts or disputes may arise. They may consider dispute resolution arrangements to fall within the “boilerplate” aspects of the contract which are the territory of the legal rather than the commercial team and require little consideration. Alternatively, they may involve the lawyers too late in the process to give much attention to dispute resolution processes.42 They are also unable to predict with certainty all the future circumstances in which a dispute may arise. A tendency to use preferred forms of contract may lead to other parties feeling that they have no power to suggest change, or that the negotiating capital required to agree a bespoke approach is better focussed on other aspects of the contract. Tiered escalation clauses Clauses requiring at least one tier of negotiation by senior managers II-15.31 are common in the oil and gas industry, often providing for this as a pre-condition to commencing other consensual ADR processes or

  See, in particular, Chapters II-2, II-3 and II-6.   QMU with White & Case, 2010 International Arbitration Survey, p 11.

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to litigation.43 In the LOGIC standard form contract for services,44 three levels of negotiation are provided for and parties are expected to attempt these before proceeding to other dispute resolution process.45 In the LOGIC short form of purchase and sale agreement, the condensed form states that “the parties shall meet as soon as possible in good faith with each other to try to resolve the matter in an amicable way”.46 Often, such provisions seek to identify either the individuals who must participate in those attempts or the levels of management to which the discussions must be escalated at each stage, and for the final stipulated stage of negotiation to be at the level of Managing Director or Chief Executive Officer. Timeframes for those discussions to take place may also be included. II-15.32 Contracts may also seek, either with or without tiered negotiation requirements, to ensure that parties will attempt an assisted collaborative non-binding process, such as mediation, before any formal arbitration or court process is commenced. II-15.33 If not properly considered at the time of entering into the contract, these provisions can become difficult for parties to implement when disputes arise. For example, there may be disparity between the management levels within the two contracting parties, so that the appropriate level for such negotiations is different between the two – a small specialist contractor company will usually have fewer layers of management than a large oil company, and so will be more likely to quickly escalate a particular dispute to a very senior level. Named individuals may have left the company or be no longer involved in the project. Time periods for discussions or mediation which appeared reasonable when the contract was entered into may prove difficult to comply with when competing project completion demands must be given precedence. Care should therefore be taken to ensure that contractual requirements of this nature are realistic and appropriate to the particular parties and project in question. II-15.34 There is some question as to whether such clauses will be enforced as pre-requisites to formal litigation or arbitration proceedings.  On stepped dispute resolution provisions, see P O’Neill, “International Arbitral Jurisdiction: When taking control goes out of control”, 58(2) (2003) Dispute Resolution Journal 68–77 and 85. Such a clause existed in the contract disputed in Thames Valley Power Ltd v Total Gas & Power Ltd [2006] Lloyd’s Rep 441 but was not activated because no “real” dispute existed. 44  See eg LOGIC, General Conditions of Contract, On- and Offshore Services (3rd edn, 2014), cl 31.1. All LOGIC Standard Contracts are available at www.logic-oil.com/ contracts2.cfm (accessed 2 May 2017). 45   For example, LOGIC, General Conditions of Contract for Services On and Off Shore (March 2014), s 31; all LOGIC Standard Contracts are available at www.logic-oil.com/ contracts2.cfm (accessed 2 May 2017). 46   LOGIC Purchase Order Terms and Conditions Short Form (December 2005), para D8. 43

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It appears that the UK courts are willing to enforce such clauses, provided they are sufficiently clear as to the steps that parties are required to take. Provisions requiring attempts at negotiation may be more likely to be enforced, as less formality is required for that process;47 a requirement to attempt resolution by means of a process involving the appointment of a third party (for example a mediator) may also be enforced,48 but only where the provision is sufficiently clear and certain as to the parties’ rights and obligations.49 ASSISTED COLLABORATIVE NON-BINDING PROCESSES Introduction Escalating dispute resolution processes may provide for a step II-15.35 beyond negotiation but before the stage at which a dispute is passed to a third-party adjudicator (such as an arbitrator, expert or court) for determination and imposition of an outcome. This stage in the spectrum is consensual, in that the parties have agreed to attempt it and are not bound to reach an outcome. If they do, it is enforceable only as a contractual obligation, not as a court order. Settlement is dependent on their agreement but unlike consensus-building in the form of negotiation, a third party is engaged to facilitate, and, possibly, to provide advisory evaluation. These processes are often collectively called alternative dispute resolution, or ADR, although some feel that the “alternative” description is not particularly helpful. The third party is most commonly a mediator (or a conciliator, although the terms are often used indiscriminately and interchangeably),50 but could alternatively be a neutral evaluator.51 Consensual ADR and mediation Contracts in the oil and gas industry may provide for dispute II-15.36  For example, in Emirates Trading Agency LLC v Prime Mineral Exports Private Limited [2014] EWHC 2104 (Comm) the clause “In case of any dispute or claim arising out of or in connection with or under this [Agreement] … the parties shall first seek to resolve the dispute or claim by friendly discussion …” was said to be enforceable. 48   Cable & Wireless plc v IBM United Kingdom Ltd [2002] 2 All ER (Comm) 1041; Holloway v Chancery Mead [2008] 1 All ER (Comm) 653. 49  In Sulamerica Cia Nacional de Seguros SA and others v Enesa Engenharia SA and others [2012] EWCA Civ 638 the court held that a provision which sought to require parties to attempt mediation in respect of any dispute prior to raising arbitration, and made provision for how the costs of mediation were to be borne did not create a binding obligation because it did not specify the process by which that was to be undertaken. 50  Conciliation is more commonly associated with relationship mediation, including an element of evaluation and conciliator steerage towards a particular settlement. 51   For a discussion on neutral evaluation, see para II-15.55. 47

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resolution mechanisms to be attempted, including mediation; or when disputes arise, parties may consider entering into ADR governed by a standalone agreement on an ad hoc basis. Consensual dispute resolution is recognised as a process which may be selected in preference to adjudicative processes. Where the contract provides this to be a pre-condition of arbitration or litigation then that requirement has been enforced by the courts in the UK.52 Mediation may be the subject of bespoke contractual agreement by the parties (either when entering into the original contract or, more commonly, by separate contract when the dispute arises) or parties can take advantage of model clauses that are widely available via mediation providers when that provider is selected.53 Mediation process II-15.37 The term “mediation” refers to placing a person in the middle of the dispute. The key features of mediation are that the person is neutral and impartial and has no power to impose any outcome on the parties. By a process of listening and questioning in joint and private meetings with parties, the mediator assists them to explore the nature of the dispute and its causes and effects, and then to look to future potential solutions which address underlying interests and needs. The mediator looks for mutual ground between the parties, which is often entirely outside the parties’ expectations, and helps them to build consensus.54 The process has a recognised capability to expand options for settlement. It certainly extends beyond those remedies available within litigation and arbitration, which may be limited to the scope of the immediate dispute but also beyond the scope of direct negotiation, whether lawyer-aided or not. This is because confidential information can be disclosed by parties to the mediator and managed by the mediator for more productive and enduring settlement terms.55 Mediation is of particular value in

  Cable & Wireless plc v IBM United Kingdom Ltd [2002] 2 All ER (Comm) 1041; Holloway v Chancery Mead [2008] 1 All ER (Comm) 653; Sulamerica Cia Nacional de Seguros SA and others v Enesa Engenharia SA and others [2012] EWCA Civ 638. 53   See eg www.cedr.com; www.uncitral.org; www.core-solutions.com; and www.adrgroup. co.uk (all accessed 2 May 2017). 54   For an exploration of the process, see H Brown and A Marriott, ADR Principles and Practice, (3rd edn, 2011); M Noone, Mediation (1996); L Boulle and M Nesic, Mediation: Principles, Process and Practice (1st edn repr 2005) (hereinafter “Boulle and Nesic, Mediation”); S Roberts and M Palmer, ADR and the Primary Forms of Decision Making (2nd edn, 2005). 55   For a detailed consideration of mediation processes and practices, see Boulle and Nesic, Mediation. 52

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disputes with multiple parties or involving linked contracts,56 both of which are common in the oil and gas industry. Role and skills of the mediator Given the neutrality and non-adjudicative nature of the media- II-15.38 tor’s role, there is, in theory, no reason for the mediator to have expert knowledge or skill in anything other than the mediation process. Indeed, since one of the mediator’s functions is to explore motives and possibilities, it is important that nothing should be left to assumption by the mediator. At the very least, mediators with dedicated and rigorous training in the process and reasonable volume of experience as sole or joint mediator would be sought. Industry disputes would usually involve legal representation in preparation for, and participation in, the mediation. Increasingly, mediator involvement in the preparation before mediation is found to make the mediation process most effective, and lawyers who are trained or knowledgeable in or about mediation can play a very productive role in that preparation.57 Nonetheless, in oil and gas disputes it is recognised that benefit II-15.39 may arise from the mediator having specialist knowledge of the industry or of a technical process used within it. Awareness of its culture and familiarity with its terminology are also valued. Industry players note that time can be wasted in the mediation when dealing with questions from the mediator that are essentially for the education of the mediator. Those questions would not arise if the mediator had industry knowledge or relevant technical expertise. Settlement expectations may be skewed if a mediator explores a general possibility which, in industry terms, is in fact a blind alley. Engineers, architects, accountants and quantity surveyors are, with lawyers, among the ranks of those trained mediators available commercially to provide mediation services. Biographical data is available from commercial agencies and mediator websites to assist in choice, although personal recommendation is often the most influential factor. Lawyers and mediation Views are mixed on whether lawyers make appropriate mediators, II-15.40 even when trained in mediation,58 but the fact is that many lawyers  See D Richbell, “Mediating Multi-party Disputes”, in Newmark and Monaghan, Butterworths, pp 229–238. 57   The Law Society of Scotland now recognises lawyers who advise in mediation, as well as mediation practitioners, for specialist accreditation in mediation: “Mediation lawyers can apply”, 55(11) (2010) JLSS 34. 58  Clark and Dawson, “ADR and Scottish Commercial Litigators”, at 240 note the 56

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do act as mediators. It is accepted that lawyers have a very important part to play in advising clients in commercial mediation.59 There are specialist texts and training courses on this topic.60 It is important for the lawyer to have awareness of the mediation process so that appropriate advice and support can be given to clients in choosing and dealing with the process. They may otherwise feel that they cannot advise the client as to its risks and benefits. Some clients report that they have led the lawyer to mediation, because of personal experience of it or having it recommended by others in the industry. Evidence suggests that companies look for specialist legal advice before embarking on high-value arbitration61 and for a similar approach in preparing for mediation. Methods of mediation II-15.41 Mediation methods have been characterised into three main types: facilitative, evaluative and transformative. Agreement to use a particular method lies with the parties. The facilitative method is the most common. It involves the mediator shunning any comment on the strength or weakness of any party’s side of the dispute, although by reality testing, role-reversal or questioning about objective criteria the mediator can guide parties into a rigorous evaluation of their own side. Most mediators are trained in that method and adopt it, particularly in the earlier exploratory phases of the mediation. However, parties may prefer a mediator to express a view about the case. Some lawyers hope that the mediator will come to a view that accords with the lawyer’s evaluation and thereby assist in persuading the client, or the counterparty, of weaknesses that were not accepted on the lawyer’s word alone. Mediators and parties also note that as time passes in the mediation, once the scoping of the dispute has been done and as the end of the day or allotted time approaches, some evaluation by the mediator may at that stage be permitted (perhaps only privately with each party separately), even when the process chosen originally was facilitative. Of course, mediators may well form a personal view on aspects of the case, but training includes concerns raised by writers that lawyers as trained advisers and partisan litigators are not suited to the consensual nature of mediation, but this survey of commercial lawyers came out in broad support of lawyers as mediators, although that support was slightly lower among those with experience of representing clients in mediation. 59   Lawyers’ relationship with mediation is explored from a number of angles in B Clark, “Mediation and Scottish Lawyers: Past, Present and Future”, 13 (2009) Edin LR 252. 60   Most recognised mediation providers offer training courses and materials. 61   PWC and Queen Mary, University of London, 2013 International Arbitration Survey, available at www.pwc.com/gx/en/arbitration-dispute-resolution/assets/pwc-international-arbitration-study.pdf (accessed 2 May 2017) (hereinafter “PWC and QMU, 2013 International Arbitration Survey”).

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techniques to suppress any uninvited influence or assumption arising from the mediator’s own view. An alternative is the purposive selection of an evaluative method. II-15.42 This is more common within specialist industries than outside them. If the mediator has industry knowledge, there is value in applying that knowledge to weigh the strengths and weaknesses of a party’s case and share that in private with each party (but not with the other party unless confidentiality is waived). The transformative mediation method concentrates on getting below the current problem to identify and work on conflicting issues of personality and problemsolving. In this way, not only can the disputants be empowered to work on resolving the present problem themselves but they will be equipped to approach disputes more effectively in the future. The transformative method62 is the least embedded in commercial contexts, but increasingly mediators report that facilitative or evaluation mediation draws upon transformative techniques. Institutional direction towards ADR Civil procedures in the UK Some courts in the UK may, by procedural rules, be encouraged to II-15.43 manage or expedite the progress of the case63 or expect the parties to consider ADR and explain its non-use. In England, following the Woolf reforms on Access to Justice,64 the Civil Procedure Rules 1998 (“CPR”) have required the court to encourage the parties to use a form of ADR if the court considers it appropriate, and to facilitate the use of such procedure.65 Indeed, the Practice Direction on Pre-Action Conduct and Protocols66 stresses that litigation should be the last resort and expects parties to consider whether negotiation or ADR might enable the dispute to be settled without recourse to the courts. Parties are required to exchange information and attempt settlement before the case is even filed. They may be expected to provide the court with evidence that ADR has been considered. A

  As articulated by R Baruch Bush and J Folger in The Promise of Mediation: Responding to Conflict through Empowerment and Recognition (revd edn, 2005; 1st edn, 1994). 63  As in options hearing procedure in the sheriff courts in Scotland under the Ordinary Cause Rules 1993, as amended, r 9.13. 64  Lord Woolf, Interim Report to the Lord Chancellor on the Civil Justice System in England and Wales, June 1995; Final Report: Access to Justice, July 1996. See also N Andrews, English Civil Procedure (2003), paras 23.12–23.28. 65   Civil Procedure Rules 1998 (CPR), r 1.4.(2)(e) and Pt 36. 66  CPR Practice Direction on Pre-Action Conduct and Protocols, available at www. justice.gov.uk/civil/procrules_fin/contents/practice_directions/pd_pre-action_conduct.htm (accessed 2 May 2017). 62

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party can seek a stay of proceedings for ADR to take place.67 The CPR allow the court to allocate costs (including on an indemnity basis) taking into account efforts made to attempt to resolve the dispute,68 and taking account of compliance or non-compliance with the pre-action protocol.69 Courts have taken account of, inter alia, whether the refusing party had a reasonable belief that it would win on the merits at trial, previous settlement attempts, risk of delaying trial by attempting ADR and whether mediation had a reasonable prospect of success.70 If ADR has been suggested by one party and refused by another, then in the event of the refuser being successful, the onus would be on the losing party to make the case that it was unreasonable for the winner to have refused; however, it is competent for that to be argued.71 This approach to ADR and the allocation of costs was supported by Lord Justice Jackson in his report on the review of costs of civil litigation in England and Wales. He also recommended that judges become more aware of the ADR options open to parties.72 II-15.44 In Scotland, there is no equivalent pre-action protocol in civil cases generally.73 In the review of civil courts led by Lord Gill, reporting in September 2009,74 more use of pre-action protocols and case management was proposed among a suite of reforms. Scottish Government responses to the report in advance of legislative change are supportive of those aspects of the report and indicate a stronger will to link ADR to the court process than had been indicated in the Gill Report itself.75 For commercial actions in the Court of Session, parties will be expected to have complied with certain pre-action   CPR, r 26.4(1).   Ibid, r 44.5(a). 69   Ibid, r 44.4(3)(a)(i). 70   Halsey v Milton Keynes General NHS Trust [2004] 1 WLR 3002; R (ex parte Cowl) v Plymouth City Council [2002] 1 WLR 903; Dunnett v Railtrack plc [2002] 1 WLR 2434; Hurst v Leeming [2003] 1 Lloyd’s Rep 279. On the difficulties of timing, see Nigel Witham Ltd v Smith (No 2) [2008] EWHC 12 (TCC) per Coulson J. For the impact of timing more generally, see L Blomgren Bingham et al, “Dispute Resolution and the Vanishing Trial: Comparing Federal Government Litigation and ADR Outcomes”, 24 (2008–2009) Ohio St J on Disp Resol 225 (hereinafter “Blomgren Bingham et al, ‘Dispute Resolution’”). 71   Halsey v Milton Keynes General NHS Trust [2004] 1 WLR 3002. 72  Lord Justice Jackson, Review of Civil Litigation Costs: Final Report, Chapter 36, Ministry of Justice, December 2009, available at www.judiciary.gov.uk (accessed 2 May 2017). 73   A voluntary protocol was introduced for personal injury cases only in 2006. 74   Lord Gill, Report of the Scottish Civil Courts Review (Scottish Government, Edinburgh), September 2009, available at www.scotcourts.gov.uk/civilcourtsreview (accessed 2 May 2017). 75   Scottish Government Response to the Report and Recommendations of the Scottish Civil Courts Review (Scottish Government, Edinburgh, November 2010), available at www.scotland.gov.uk/Publications/2010/11/09114610/0 (accessed 2 May 2017). 67 68

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steps before proceedings are raised, and the court may have regard to any failure to comply with the court’s expectations when considering expenses.76 Other jurisdictions In the settlement conference used at a fairly early stage in civil II-15.45 litigation in the Netherlands, the judge will give a strong steer on the merits of the claim. Court-ordered mediation has now been built into the court process across the Netherlands. It is ordered prior to or at the settlement conference stage, particularly if it appears that the litigation process will not in itself be able to determine all aspects of the dispute between the parties.77 Many US state and federal courts (including appeal courts) have court-annexed or court-ordered ADR programmes that have, on evaluation, proved to be very effective.78 If jurisdictional choices exist, selection of the court should take into account whether that court will interpose a particular process of dispute resolution. In many countries, for example in Norway and parts of the II-15.46 USA, statutes require mediation in certain situations before parties are permitted to resort to adjudication in the domestic courts.79 A European Union Directive promotes the use of ADR in civil and commercial disputes and provides in particular for confidentiality and for time limitation rules for litigation in member states to be stayed to allow for the use of ADR.80 The EU has, in its Civil Justice programme, funded a number of research activities which have produced information on use of mediation in member states, and the cost of not using ADR in cross-state disputes.81 Processes insisted upon in particular types of dispute Choice may be influenced by factors specific to the nature of the II-15.47 dispute within the oil and gas context. Hence, claimants raising employment disputes governed by employment law in England or Scotland are required to contact ACAS, the Advisory Conciliation

  Court of Session Practice Note No 1 of 2017 (Commercial Actions), para 10.   See M Pel, Referral to Mediation (2008). 78   See Blomgren Bingham et al, “Dispute Resolution”. 79   For the situation in different parts of the world, see N Alexander (ed.), Global Trends in Mediation (2nd edn, 2006) (hereinafter “Alexander, Global Trends in Mediation”); Newmark and Monaghan, Butterworths; and Pryles (ed.), Dispute Resolution in Asia (2nd edn, 2002). 80  Directive 2008/52/EC of the European Parliament and of the Council of 21 May 2008 on certain aspects of mediation in civil and commercial matters. See also European Communities, Green Paper on alternative dispute resolution in civil and commercial law, COM(2002) 196 Brussels, 2002; Council of Europe, Alternatives to Litigation between Administrative Authorities and Private Parties, Rec (2001) 9 (2002). 81   The research was led by the ADR Center; see further n 4 above. 76 77

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and Arbitration Scheme, before the matter goes to an employment tribunal.82 Early conciliation is encouraged: conciliation or mediation may be undertaken, with the parties’ consent, after the case enters the tribunal system.83 In other countries, the law regulating a type of business may also dictate the dispute resolution process. In many European countries, mediation is required for employment disputes, but also, for example, in Italy and Sweden for telecommunications disputes, and in Australia and the UK for certain tax disputes.84 Disputes with states or state organisations II-15.48 Within the oil and gas industry, the potential for states to be party to contracts, and hence disputes, brings an interface with public international law in the form of international treaties concerning trade with state parties. The World Trade Organisation (WTO) dispute settlement processes85 apply to disputes in which one state party feels that the other is “violating an agreement or a commitment that it is has made in the WTO”.86 The Energy Charter Treaty which provides “a legal framework for international energy cooperation” has as signatories some countries which are not yet members of the WTO but which aim to collaborate effectively in the worldwide energy industry. That treaty provides for consensual dispute resolution at source, by reference to national courts or tribunals in accordance with contractually chosen dispute resolution processes, or by reference to international arbitration or conciliation.87 The International Centre for Settlement of Investment Disputes (ICSID), a centre of the World  Employment Act 2008, Pt 1. This followed the recommendations of M Gibbons, A Review of Employment Dispute Resolution in Great Britain (2007), available for download from www.dti.gov.uk/files/file38516.pdf (accessed 2 May 2017) (hereinafter the “Gibbons Report”). 83   Employment Tribunals Act 1996, s 7(3AA), inserted by the Employment Act 2008, s 4. 84  A number of useful texts have collated information about the use of, and state approaches to, mediation in different countries. See eg Alexander, Global Trends in Mediation; Newmark and Monaghan, Butterworths (2005); M Pryles (ed.), Dispute Resolution in Asia (2nd edn, 2002); G De Palo and M Trevor (eds), Arbitration and Mediation in the Southern Mediterranean Countries (2007), available at www.adrcenter. com/international/cms (accessed 2 May 2017), for a repository of information on the use of mediation and lawyers in mediation in EU member states. 85  WTO General Agreement on Trade in Services (GATS), Art XXIII, available at www. wto.org/english/docs_e/legal_e/26_gats.pdf (accessed 2 May 2017). 86  The WTO website at www.wto.org/english/tratop_e/dispu_e/dispu_e/htm/ gives more details on the Dispute Settlement Understanding and contains details of disputes referred. Most of the disputes referred relate to commodities other than oil and gas, although some relate to anti-dumping and to gasoline specification by the USA. See also C A Valenstein and D Hembrey, “The WTO Gasoline Dispute: A Case Study in WTO Dispute Resolution”, 14(8) (1996) OGLTR 332. 87   Energy Charter Treaty, Pt V, Art 26, available at www.encharter.org (accessed 2 May 2017). 82

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Bank,88 offers conciliation and arbitration processes for disputes involving states and nationals of other states,89 and is accessible for disputes referred under the dispute resolution provisions of the Energy Charter Treaty. An investor may choose to refer to the ICSID arbitration process regardless of what may have been agreed contractually.90 However, parties are wise to have provided for non-ICSID arbitration as an alternative in case the dispute is held not to fall within the jurisdiction of the ICSID process.91 A detailed examination of these is beyond the scope of this text, but many specialist texts are available.92 Concerns about ADR Power imbalances Power imbalances may exist between the parties. These can influence II-15.49 the management of the dispute in many ways, including the selection and implementation of choices of dispute resolution process. The small company designing and manufacturing a particular component or engineering process may seem to be the weaker player in a dispute with an international operating company and on many levels, such as access to specialist advice, financial security, and industry domination, that may be so. On the other hand, in operational terms, that company’s know-how may be essential to the productivity and viability of a high-value project. Therefore, in the dispute, “power” is not placed quite as clearly as it might appear. Unlike the blunter instrument of litigation, mediation of the dispute has the scope to elicit the finer details of power balance (particularly in private meetings) and those can be acknowledged and used to move the dispute towards a commercially viable resolution.93 Mediation   Established under the Convention on the Settlement of Investment Disputes between States and Nationals of Other States in 1966. See www.worldbank.org/icsid (accessed 2 May 2017). 89   ICSID publishes numbers and details of cases registered for dispute resolution, most of which are for arbitration, and a number of oil and gas disputes have been registered. Most cases appear to take a number of years from registration to conclusion. 90   G Turner, “Investment protection through arbitration: the dispute resolution provisions of the Energy Charter Treaty”, 1(5) (1998) Int Arbitration Law Review 166. 91   J Bowman and A T Martin, “Negotiating and Drafting Dispute Resolution Provisions for International Petroleum Contracts”, 5(4) (2007) OGEL Intelligence. 92  For example, A Stone Sweet, “Investor–State Arbitration: Proportionality’s New Frontier”, 4(1) (2010) Law and Ethics of Human Rights 47; P Pinsolle, “The Dispute Resolution Provisions of the Energy Charter Treaty”, 10(3) (2007) Int Arbitration Law Review 82; N Palmeter, Dispute Resolution in the World Trade Organisation: Practice and Procedure (2nd edn, 2004); C Carmody, Remedies and the WTO Agreement (2005); M Sornarajah, The Settlement of Foreign Investment Disputes (2000). 93   On this point, see G Chornenki, “Mediating Commercial Disputes: Exchanging ‘Power 88

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training focuses on fair and impartial handling of power imbalances and, in reality, power within the mediation may be placed differently from what may appear in advance. II-15.50 In the industry, there may be a perceived power imbalance at the point of selection of dispute resolution mechanism in the contracting process. One party may have a standard form dispute resolution clause which the smaller player must take or leave, and within which processes are determined by the larger player. Dispute resolution and arbitration clauses are sometimes the subject of trade-off in contractual negotiation, and some companies with hindsight regret concessions made.94 The only counter to this is to be very clear on the purpose of deploying each process and what the implications will be of, for example, conceding on the seat of arbitration in exchange for an extra tier of ADR. II-15.51 The conversation about a process can be had again when a dispute arises. This allows parties, or more probably their advisers, to think again then about where “power” lies. They may step back and, perhaps with more time to focus on dispute resolution than at the time of initial contracting, consider what are the interests of the respective parties at the point of dispute and how these might be managed most effectively in a dispute resolution process. This is more likely in relation to non-binding methods of dispute resolution, for example mediation, than to give rise to an agreement to refer a dispute to arbitration in place of litigation or vice versa. Non-binding nature II-15.52 Mediation produces outcomes by agreement only. It is not possible to impose an outcome. Unlike court or arbitration, any agreed outcome will become contractually binding, but is enforceable in the same way as any other contract. If mediation takes place alongside a litigation or arbitration process, its outcomes may be incorporated into a court order or arbitral decision which would be enforceable, but the court order will only be able to address matters which would have been within the decision power of the court. Collateral matters (which often form part of a mediated settlement) may have to be omitted from the court order and left to contractual terms. Disclosure and confidentiality II-15.53 Mediation agreements usually provide for confidentiality of Over’ for ‘Power With’”, in J MacFarlane (ed.), Rethinking Disputes: The Mediation Alternative (1997). 94   Queen Mary, University of London and PWC, Corporate Attitudes 2006, para 4.3.3. Available for download at www.arbitration.qmul.ac.uk/docs/123295.pdf (accessed 10 September 2017).

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communings in the mediation, and that nothing in the mediation will be recoverable in court proceedings. The application of “without prejudice” rules and negotiation privilege has been the subject of review in the courts in England.95 From these, a degree of confidence in the privileged nature of mediation discussions emerges. Mediated negotiations, in essence, carry the same protection as direct negotiations. A clause in a mediation agreement which purports to protect communications and settlement made “in the mediation” can include open offers taken from the mediation without agreement but which then become agreed by direct negotiation between the parties.96 If outright admissions are made in the context of negotiation or mediation, they may not fall within the “without prejudice” privilege.97 An important decision of the UK Supreme Court clarifies that “objective facts” that come out during the settlement discussions (in that case what was meant by a technical process term) can be admitted in court to assist in interpretation of the settlement agreement.98 However, when the parties at the case management stage of litigation agreed that the mediator be called as a witness on the question of whether settlement was influenced by economic duress, the court held that there is no remaining contractual duty of confidentiality or privilege to be invoked by the mediator if the interests of justice require disclosure.99 Parties sometimes fear that to discuss the dispute in mediation will II-15.54 reveal commercially sensitive information which they could withhold in litigation, and unscrupulous disputants may use the mediation simply to fish for information without any intention of coming to

  Aird v Prime Meridian Ltd [2006] EWCA Civ 1866 (Court of Appeal); Reed Executive plc v Reed Business Information Ltd [2004] 1 WLR 3026. 96   Brown v Rice, Patel and the ADR Group [2007] WL 763674. 97   As in Daks Simpson Group plc v Kuiper 1994 SLT 689. 98   Oceanbulk Shipping and Trading SA v TMT Asia Ltd (also known as TMT Asia Ltd v Oceanbulk Shipping and Trading SA) [2010] UKSC 44. 99   Farm Assist Ltd (in liquidation) v Secretary of State for the Environment, Food and Rural Affairs (No 2) [2009] EWHC 1102 (TCC). Ramsey J at para 44, after reviewing case law and academic commentaries, concludes in general terms: “(1) Confidentiality. The proceedings are confidential both as between the parties and as between the parties and the mediator. As a result even if the parties agree that matters can be referred to outside the mediation, the mediator can enforce the confidentiality provision. The court will generally uphold that confidentiality but where it is necessary in the interests of justice for evidence to be given of confidential matters, the Courts will order or permit that evidence to be given or produced. (2) Without Prejudice Privilege: The proceedings are covered by without prejudice privilege. This is a privilege which exists as between the parties and is not a privilege of the mediator. The parties can waive that privilege. (3) Other Privileges: If another privilege attaches to documents which are produced by a party and shown to a mediator, that party retains that privilege and it is not waived by disclosure to the mediator or by waiver of the without prejudice privilege.” 95

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agreement. However, in most procedural regimes in the UK, continental Europe and the USA the parties are expected to disclose relevant material to the court in so far as it is not privileged. Even in Scotland, where secrecy of preparation has survived for longer than in many other countries, it is expected that expert reports will be exchanged and parties can use procedural steps to flush out the evidence that is likely to be led by the other side. If parties withhold information from the courts or from an ADR neutral, the resolution is less likely to be satisfactory to either party. Mediators note that they can tell quite early in the mediation if one party is attempting to use the process in this way, and the mediator will react to that by attempting to overcome this, or by ending the mediation. The benefit of disclosing information to an ADR neutral is that a conversation can be held with that neutral around what, if any, of that information will be disclosed to the other party. Discussion of this, even with the neutral alone, means that the information can in some way influence the resolution rather than be kept out of the picture. Some industry players, particularly service companies, note that contracts contain very demanding audit provisions, making it difficult to conceal the true reasons behind points of conflict. Early neutral evaluation II-15.55 Parties may, if they agree (or have provided for it in the underlying contract), put the dispute before a neutral person who will evaluate its merits and offer a view to both parties.100 It is entirely up to the parties to decide what to place before the neutral and what power to give the neutral to investigate beyond that, such as looking for objective data against which to measure the strengths and weaknesses of the parties’ positions in the dispute. The evaluation is not binding on the parties unless they choose to adopt it and determine the dispute in accordance with the evaluation. The purpose of the evaluation is to assist the parties in deciding where to go with the dispute, and it can be all that is needed to prompt focused and realistic negotiations. Because of its evaluative and non-binding nature, it would be possible for the neutral to proceed to act as a mediator (having got to know the dispute as neutral evaluator), but parties choosing to go forward in that way probably could not expect the neutral in a mediator role to shake off the evaluative mantle. Many mediators are wary of accepting appointment in such circumstances, even if parties have agreed in advance that mediation should follow

  For a standalone agreement to secure an early neutral evaluation, see www.cedr.com/ about_us/modeldocs/?id=9 (accessed 2 May 2017).

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the neutral evaluation. If a purely facilitative mediation was sought after using the evaluation as a starting point, another person should be sought to mediate. Mini-trial or executive tribunal In this model of ADR, a neutral is appointed who sits with senior II-15.56 representatives of the two (or more) disputing parties. They hear submissions (sometimes supported by an agreed and limited volume of oral evidence) after which the neutral assists the two representatives to negotiate an outcome in light of what has been presented. If they do not come to an agreement (with the mediation assistance of the neutral) they may empower the neutral to offer an evaluation which will influence future ADR choices, or they may allow the neutral to mediate in accordance with usual mediation practices, or the neutral could be asked to arbitrate. The advantage of this process is that it puts senior executives in the position of listening to the case as adjudicators and negotiators, with the additional input of a neutral applying facilitative techniques. However, the facilitative non-binding nature of the process allows the neutral to be used thereafter for evaluative or determinative purposes. This process holds considerable potential for the oil and gas industry, as an option within stepped dispute resolution or on an ad hoc basis. However, although Disputes Boards are used in significant construction projects in the UK, this approach is not yet widely used in relation to oil and gas industry projects.101 In Australia and Hong Kong the same process is often termed Senior Executive Appraisal Mediation (SEAM) where it is used widely in construction disputes. Med-arb Disputants may agree upon med-arb, whereby a dispute on which II-15.57 the parties have failed to reach agreement is turned over to the original mediator for arbitration. The benefit is the saving in time and cost through using the same person in both roles. However, the mediator will have heard the parties’ accounts in mediation and is not able fully to ignore this when acting as arbitrator. Parties may be less open with the mediator in a private session if it is known that ultimately the mediator may act as arbitrator and  There is an executive tribunal agreement available at www.cedr.com/about_us/ modeldocs (accessed 2 May 2017). More information about it is available via the extensive resource of the American Arbitration Association (www.adr.org) (accessed 2 May 2017) where it is called “mini trial”.

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consequently some mediators are unwilling to accept appointments on this basis. Expert determination Nature of the process II-15.58 There is widespread use of expert determination in the oil and gas industry within the spectrum of available processes. Expert determination clauses appear routinely in contracts within the industry and they are used in many technical commercial disputes.102 It is a determinative, expert and reliable process, without many of the disadvantages and costs associated with formal arbitration discussed below. The process has developed its own characteristics as a result of it being a negotiated process defined by the parties. In a recent attempt by a party to define an expert determination as an arbitration, the Inner House of the Court of Session has acknowledged it is entirely separate in nature from arbitration, noting that, although expert determination may have arisen from practice in England, II-15.59

“expert determination, understood as an alternative to arbitration, has taken root in Scottish legal practice, as a consequence of its attractiveness to the commercial community as a relatively quick and informal means of resolving matters of disagreement or potential disagreement. It is now a well recognised means of resolving disputes in almost any area of commercial life, and owes its success to the fact that it generally works well and is found to be commercially useful. The difference between the role of an expert and that of an arbiter has become well understood in general terms, although the boundary between them can sometimes, in particular circumstances, be difficult to draw”.103

II-15.60 In the case before the court, this interpretation was assisted by the extent to which parties had excluded the use of arbitration in some parts of their agreements. Stating in the contract that the matter is referred to the expert “as an expert and not an arbitrator” helps to make the distinction clear. The role of the expert, although possessed  A sample standalone expert determination agreement is available at www.cedr. com/about_us/modeldocs. For discussion of expert accountability, see R King, “The Accountability of Experts in Unitisation Determination: Amoco (UK) Exploration Co v Amerada Hess”, 12(6) 1994 OGLTR 185. For activation of the clause, see Thames Valley Power Ltd v Total Gas & Power Ltd [2006] 1 Lloyd’s Rep 441 and for the interpretation of such a clause, see Veba Oil Supply And Trading GMBH v Petrotrade Inc [2001] 2 Lloyd’s Rep 731. For further discussion of Expert Determination in the unitisation context, see P Worthington, “Provision for expert determination in the unitization of straddling petroleum accumulations”, 9 (2016) JWEL&B 254. 103   MacDonald Estates plc v National Car Parks Ltd 2010 SLT 36, per Lord Reed at para [22]. 102

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of the power to make a decision that binds the parties, is not a judicial one.104 As has been noted in England, the clause gives the expert the power to make a decision contrary to that which a court would have made on the same facts.105 Scope The parties may determine procedures which the expert should II-15.61 follow. They need not do so, in which case the expert will determine a procedure appropriate to understanding and determining the dispute in a manner which is neutral, impartial and transparent. This could include gathering information independently of the parties, particularly of a technical and objective nature. It is not essential that the expert seeks submissions from both parties if the parties do not specify it106 (a feature one would expect of most adjudicative processes). Clearly, it is essential that an expert chosen will not only be neutral of the parties and expert in the technical subject matter of the dispute, but will also conduct the process in a fair and open manner. The parties must specify the extent of the expert’s substantive (as compared to procedural) power, for example what the expert should determine,107 and whether or not to award interest. Statutory adjudication A statutory adjudication process under the Housing Grants, II-15.62 Construction and Regeneration Act 1996 (as amended), Pt II applies to “construction operations”,108 defined broadly to include external and internal construction on or under land, but oil and gas activities are fairly clearly excluded. Part II of the Act provides for an adjudicative process which can be triggered by either party in which an independent adjudicator (usually skilled in construction and trained in adjudication methods) determines the particular dispute for the specific and interim purpose of keeping the construction contract moving. The ruling of the adjudicator is binding only until the dispute can be the subject of agreement of the parties, or of final determination in arbitration or litigation. Those engaged in the oil and gas industries have important II-15.63   Holland House Property Investments Ltd v Crabbe 2008 SLT 777, followed in MacDonald Estates plc v National Car Parks Ltd 2010 SLT 36. 105   Said by Hoffmann LJ (as he then was) in Director General of Telecommunications v Mercury Communications Ltd, CA, unreported at that level of decision. 106   Confirmed in MacDonald Estates plc v National Car Parks Ltd 2010 SC 250. 107  A point of dispute in Thames Valley Power Ltd v Total Gas & Power Ltd [2006] Lloyd’s Rep 441 and in Veba Oil Supply And Trading GMBH v Petrotrade Inc [2001] 2 Lloyd’s Rep 731. 108   Defined in s 105. 104

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exemption from the compulsory statutory process by virtue of Section 105(2) of the 1996 Act. Drilling for, or extraction of, oil or natural gas are not construction operations within the meaning of the Act,109 nor are assembly, installation or demolition of plant or machinery or access for construction on a site where the primary activity is the production, transmission, processing or bulk storage (other than warehousing) of oil or gas.110 Any attempt to rely upon statutory adjudication in a dispute within the oil and gas industry can be resisted on this basis, unless the parties have chosen to include provision for adjudication in their agreement.111 The Act does empower the Secretary of State by order to amend these definitions, but no such amendment has been effected by the time of writing.112 II-15.64 The statutory requirement applies to construction in England, Wales or Scotland whether or not the contract between the parties is governed by laws of England or Scotland.113 The process has generated much litigation in itself, particularly around the scope of the adjudicator’s powers. Claims of exceeding powers have been used frequently by parties unhappy with adjudication decisions. Although the adjudication outcome is interim, the commercial effect has been to drive parties to settle under its influence. It is a form of dispute resolution which combines features of early neutral evaluation and expert determination (each discussed above). Its difficulties in terms of scale of challenge in court are no doubt due to it being imposed by law as a process which one party can choose regardless of the views of the other, so the other is prompted to challenge its outcomes in process terms if unhappy with them. ADJUDICATIVE PROCESSES Arbitration General II-15.65 It is not surprising to find arbitration clauses in some oil and gas industry contracts,114 particularly when the contract involves cross  Section 105(2)(a).   Section 105(2)(c). 111   For example, in a contract based on a LOGIC standard form, by incorporating the optional provision on adjudication which is included in the LOGIC ADR Guidance Notes 2015. 112   Section 105(3), but this must be subject to affirmative resolution of both Houses of Parliament (s 105(4)). In Scotland this would be a reserved matter, so there would have to be acquiescence to any amendment by way of Sewel Motion, or separate legislative activity by the Scottish Parliament (none known at the date of writing). 113   Section 104(6) and (7). 114  R W Bentham, “Arbitration and Litigation in the Oil Industry”, 5(2) (1986/87) OGLTR 35. UK petroleum Production Licences provide that some (but by no means 109 110

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border activity. Arbitration has long been a preferred method of dispute adjudication in standard form construction, engineering and related contracts in the UK. In most jurisdictions worldwide it is a recognised mode of adjudication in international trade as an alternative to the risks of submitting complex disputes to determination by generalist judges in national courts. An arbitration clause115 is respected in usurping the jurisdiction of courts116 and allows for decision-makers to be involved for their specialist technical knowledge, as well as allowing the interests of disputing parties to be balanced in selection of arbitral panels. It draws upon consensus in choice of method combined with the certainty of a determined outcome, appealable usually only on the ground of arbitrator misconduct or exceeding jurisdiction. Parties retain the power, on agreement, to withdraw the dispute from arbitration prior to the issue of a final award. Court jurisdiction is retained where necessary for preservative and directive orders needed to support the arbitration, although increasingly established arbitration centres are providing emergency arbitration procedures117 which may limit the scope of the court’s jurisdiction even in respect of such interim orders.118 The binding choice of arbitration relies entirely upon the effectiveness of the contract by which it is created. Lack of clarity in the contract will leave scope for one party to argue that the arbitration clause does not apply. Courts in the UK are robust in their protection of the arbitration choice against litigation raised by one party in face of an arbitration clause.119

all) of the potential disputes which might arise between the state and the licensee are to be arbitrated. Arbitration is not provided for in the LOGIC standard form contracts agreed by the UK Oil and Gas industry task force; see www.logic-oil.com and www.gov. uk/government/groups/pilot (both accessed 2 May 2017). These are permissive as to the parties’ freedom to choose ADR after escalated levels of negotiations have failed, but assume litigation as the process of adjudication. See A T Martin, “Dispute resolution in the international energy sector: an overview”, 4(4) (2011) JWELB 332 (hereinafter “Martin, ‘Dispute resolution’”), at 339. 115   Most jurisdictions require arbitration agreements to be in writing eg Arbitration Act 1996, s 5. 116   Re arbitration in Scotland Hamlyn & Co v Talisker Distillery (1894) 21 R (HL) 21, at 25 and Arbitration (Scotland) Act 2010, ss 1 and 10; re an arbitration with its seat in England and Wales, Arbitration Act 1996, s 1. 117   For example, see LCIA Rules Art 9A – expedited formation of the arbitral tribunal, and Art 9B – appointment of an emergency arbitrator; ICC Arbitration Rules Art 29 and Appendix V. 118  In Gerald Metals SA v the Trustees of the Timis Trust & others [2016] EWHC 2327, the High Court held that it could only provide interim relief where there was an arbitration agreement in circumstances where either an emergency arbitrator or a expedited tribunal could not provide that relief. 119   As in Midgulf International Ltd v Groupe Chimique Tunisien [2010] EWCA 66 (Civ).

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Process II-15.66 Since arbitration withdraws the dispute from the system of civil process in national courts, a substitute procedural system must be set up for the arbitration. In many countries a domestic arbitration statute will regulate matters in the absence of a chosen set of procedures. In the UK the Arbitration Act 1996 applies in England and Wales and the Arbitration (Scotland) Act 2010 applies in Scotland. Both provide a system that is intended for use in both domestic and international arbitrations. In theory, parties may write their own arbitration processes from scratch, but few would be interested in doing so, and rules have tended to be the subject of national120 or international collaboration. Many parties agree to the arbitral rules of the United Nations Commission on International Trade Law (UNCITRAL),121 or submit to rules and services of arbitration institutions such as the International Chamber of Commerce, International Court of Arbitration (ICC); the London Court of International Arbitration (LCIA); or the American Arbitration Association/the International Court of Dispute Resolution (AAA/ICDR). Recent research indicates that 56 per cent of commercial respondents in the energy sector prefer international arbitration to resolve cross-border disputes and that, in opting for arbitration, parties in the energy sector perceive the top four benefits as neutrality, flexibility, confidentiality and expertise of decision-makers.122 Particularly in contracts which relate to work in jurisdictions which do not have strongly established court systems, or where parties to those contracts are from different cultures and legal traditions, arbitration is often seen as a mutually acceptable option. Questions of enforceability of arbitration awards as against court awards in the home jurisdictions of the parties to  A Scottish Arbitration Code was a collaborative project of Scottish Branch of the Chartered Institute and the Scottish Council for International Arbitration, and was endorsed by the Lord President in 1999. A revised 2007 version may be downloaded from www.ciarb.org/docs/default-source/ciarbdocuments/our-network/great-britain/scotland/ arbitration/scottish_arbitration_code_2007.pdf?sfvrsn=4 (accessed 10 September 2017). See F Davidson, “Some thoughts on the Scottish Arbitration Code 2007”, 74 (2008) Arbitration 348. For arbitrations set up after May 2010 it is likely to be overtaken by the Scottish Arbitration Rules set out in Sch 1 to the Arbitration (Scotland) Act 2010. 121   Prior to the enactment of the Arbitration (Scotland) Act 2010, international arbitrations with their seat in Scotland were, in the absence of specified procedure, conducted according to UNCITRAL rules (Law Reform Miscellaneous Provisions (Scotland) Act 1990, s 66 and Sch 7). The 2010 Act creates Scottish rules that mirror the UNCITRAL rules with some optional additions. The UNCITRAL Model Law on International Commercial Arbitration 1985 and UNCITRAL Model Law on International Commercial Conciliation 2002 are both available via www.uncitral.org/uncitral/en/uncitral_texts.html (accessed 2 May 2017). 122   QMU and PWC, International Arbitration Survey 2013, p 8. Available online at http:// www.arbitration.qmul.ac.uk/docs/123282.pdf (accessed 10 September 2017). 120

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the contract also often play a significant part in determining whether to select arbitration. It would be folly to allow the choice of arbitration which the II-15.67 parties have made to be undermined by failure to specify an agreed procedure, and industry players may be unhappy with accepting default procedures from the seat of the arbitration. To rely on default procedures of the arbitral seat assumes both that the chosen seat has a domestic arbitration law and that it is suitable for the determination of the dispute. Parties may select any rules of procedure. These need not be II-15.68 consistent with the rules of the seat, but if it is intended to enforce an arbitral award in another country, national courts may, on the application of a party, but not of its own accord, refuse to recognise or enforce a foreign award if it has been arrived at by a process or by application of law which does not conform to the law or procedure of the seat.123 The reach of the arbitration clause As noted above, activity in the oil and gas sector often involves a II-15.69 series of contracts that are linked to a central activity. Yet within each contractual relationship, scope exists for choice of dispute resolution process. It may be the case that there is not a match between contracts in choice of arbitration for that process. The arbitration clause in one contract may specify that it applies to all claims “arising out of or relating to” the agreement between the parties. This may bring in to the legitimate scope of the arbitration other agreements or contractual relationships that do not themselves provide for arbitration. The reach of the phrase “arising out of” may limit the arbitration to the fulfilment of the agreement in which the clause is contained. “Relating to” was found to have a broader reach in Norscot Rig Management PVT Ltd v Essar Oilfields Services,124 and led to the court supporting the arbitrator’s decision to include in his remit a dispute in relation to set-off arising from a separate contract without an arbitration clause. Arbitration as an alternative to litigation Arbitration has been associated with speed and efficiency as compared II-15.70 with litigation, but experiences of arbitration seem often to involve delay, expense, procedural complexity and legal challenges to jurisdiction or competence of proceedings. Nevertheless, the advantages are widely believed to outweigh the disadvantages and if weighed

  New York Convention, Art V, para 1.   [2010] EWHC 195 (Comm).

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against the prospect of litigating an international dispute in a remote national court, the choice seems clear. Some commercial users of arbitration still fear interference by national courts, but the risk of interference is more easily managed than affording jurisdiction to such courts by default. II-15.71 While privacy is often claimed as an advantage of arbitration, publication of progress and outcomes of arbitrations conducted under some of the international arbitration providers does occur. This could act as an aid to choice of process and provider, or as a disincentive to use a provider which will publish such material. Corporate disputants report seeking legal advice from specialist arbitration counsel rather than using their own in-house or external counsel with technical sector expertise for large international disputes.125 Some counsel report being called in only at a late stage in the dispute to discuss the arbitration choices. Litigation II-15.72 Many contracts in the UK oil and gas industry contain express jurisdiction provisions determining that disputes will be resolved by litigation in the High Court of England and Wales. Even where that is not the case, sometimes it will be necessary to have a decision from the court on a point of law, or a protective or injunctive remedy. In that event, litigation will be unavoidable, at least for the aspect of the dispute for which the order is necessary.126 Decisions then remain as to whether there is economic or other imperative for having the court deal with the other aspects. The important thing is not to assume that because one aspect must be litigated it follows that all aspects must be, and always to keep open the thought processes about which dispute resolution process will be best suited to the dispute, or aspects of it, at a particular point in time. II-15.73 Once a case is in court, lawyers and the courts may assume that the parties have expressly or implicitly opted for litigation over other dispute resolution processes. That may be founded on an incorrect assumption that a party embarking on litigation for the first time knows exactly what the court can and cannot do in relation to the dispute. Any assumption that the parties become more polarised

  PWC and QMU, 2013 International Arbitration Survey, p 4.   For example, a party to arbitration may seek a court order for security for costs to be lodged by the other party, as in Regia Autonoma de Electricitate Renel v Gulf Petroleum International Ltd [1996] 1 Lloyd’s Rep 67, although see earlier comments regarding recent case law which indicates that the court’s jurisdiction will be ousted even in relation to such interim applications where the arbitral tribunal is able to provide an appropriate remedy (irrespective of whether or not it chooses to do so).

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and less open to mediated settlement as the case continues in the court is not supported by evidence from the US Federal Courts. Here, it was found that the time between court referral to mediation and settlement remained much the same regardless of the stage of the case at which it was referred to mediation. If referred early the parties and the court were spared the cost of further procedure, but if referred even at a late stage in the case it would settle within a similar period of time.127 The contractual or consensual backdrop to most dispute resolution II-15.74 processes allows the tailoring of process to dispute, and ensures that disputes need not be made to fit the “one size fits all” model of litigation or statutory adjudication. Litigation in general is beyond the scope of this chapter, but some special procedures bear mention.128 Commercial court procedures In the UK, commercial court procedures provide a fast-track and II-15.75 commercially aware procedure for dealing with commercial cases. Parties opt into the procedure when the case is commenced. Specific judges are designated for commercial court cases. Because the rules for general civil actions promote dispute resolution processes and case management, the main difference in the commercial court is the shortened procedure and the specialist judge.129 In the Scottish courts, the rules do not yet provide for case management or dispute resolution in civil cases generally, but there is provision in commercial actions in addition to reduced timescales and specialist judges. Commercial action procedure in the Court of Session130 requires the commercial judge to ensure speedy determination of the action.131 In the similar but not identical procedure in the sheriff court,132 the commercial judge is enjoined to make orders for the speedy resolution of the action (including the use of alternative dispute resolution).133 In the sheriff court, hearings may be conducted by telephone or e-mail, and early evaluation of its use suggests that the procedure is effective and popular.134 However, there is no evidence of judges or sheriffs moving the parties towards dispute resolution processes once they have raised a commercial action. Also, the Inner   Blomgren Bingham et al, “Dispute Resolution”.   For a reflective and predictive account of the problems of litigation in the industry, see J Wallace, “Litigating an International Oil Dispute”, 2 (1980–81) NYLSch J Int’l & Comp L 253. See also “Martin, ‘Dispute resolution’”, at 339. 129   CPR, Pt 58 and Practice Direction, Commercial Court. 130   Rules of the Court of Session, Ch 47 and Practice Note 1 of 2017. 131   RCS, r 47.11(1)(e). 132   Ordinary Cause Rules, Ch 40. 133   Ibid, r 40.12(3)(m). 134   E Samuel, Commercial Procedure in Glasgow Sheriff Court (2005). 127 128

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House has disapproved the sheriffs’ use of problem-solving and dispute-focused (rather than litigation-focused) approaches in a commercial case as contrary to adversarial norms.135 Summary trial: special case II-15.76 In the Court of Session, parties may opt for summary trial procedure. They may nominate a particular judge of the outer house to deal with an issue of fact or law in dispute between them and forgo a right of appeal.136 If an authoritative ruling is required purely on a point of law, a special case may be filed for decision by the Inner House.137 Construction and arbitration list of the Civil Court II-15.77 In England and Wales, a Technology and Construction Court (TCC) List of the Business and Property Court of the High Court of Justice operates under a designated judge.138 Parties opt into the procedure, but cases may be transferred out of it on order of the judge. It is designated for engineering and construction cases with a value above £250,000 but other appropriate technically complex cases can be admitted to it. The procedures are similar to those of the commercial court, but particular attention is paid to active case management. Parties are expected to comply with a specific Pre-Action Protocol for Construction and Engineering Disputes before proceedings are raised in the TCC. The TCC Guide describes the purpose of that Protocol as “to encourage the frank and early exchange of information about the prospective claim and any defence to it; to enable parties to avoid litigation by agreeing a settlement of the claim before the commencement of proceedings; and to support the efficient management of proceedings where litigation cannot be avoided”.139 IMPLEMENTATION AND ENFORCEMENT II-15.78 Parties may simply implement outcomes of adjudicated processes or proceed to appeal by any means available. Indeed, many cases settle before arbitration or litigation gets to evidential stages. There is considerable anecdotal evidence that parties will implement negotiated outcomes more readily than those imposed by an arbitrator or a court. If the outcome is not implemented, or there is delay, appeal or resistance, parties require to be as attentive to the   Jackson v Hughes Dowdall 2008 SC 637. For a commentary on the case, see M Ross, “Commercial actions and Jackson v Hughes Dowdall”, 13(2) (2009) Edin LR. 136   RCS, Chapter 77. 137   Court of Session Act 1988, s 27; RCS, Chapter 78. 138   CPR Pt 60. 139   TCC Guide, para 2.1.2. 135

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range of options available at this stage as they do when embarking on choice of process for dispute management. Dispute resolution processes after adjudication The consensual nature of dispute resolution processes allows for their II-15.79 adoption (if the parties agree) at any stage, including after there has been litigation or arbitration on a particular dispute. If the parties are unhappy with the outcome of litigation or arbitration, or realise that it does not of itself address all aspects of the dispute, the option of another process remains. Clearly, this is difficult if the “winning” party in the litigation is happy with the overall outcome and proceeds to enforce the decree or award. However, if, as is often the case, the outcome of litigation merely makes clearer (or not) the application of laws to the averred facts of the dispute, the underlying problem, or a form of it now altered by the experience of the adjudicative process and/or its outcome, may remain. As is discussed above, the industry has embraced processes such as early neutral evaluation or expert determination which seek to avoid ill-fitting and binding litigated remedies. However, when there has been litigation, much remains to be considered in terms of whether dispute resolution processes can improve the fit of the outcome to the parties’ commercial situation. In most states in the USA and in many other countries, mediation II-15.80 schemes operate within the appeal court. In England, mediation is offered in the Court of Appeal, and may be recommended by the judge in appropriate cases under the general authority of the Civil Procedure Rules, although not provided for expressly in the relevant appeal rules. Global acknowledgement of arbitration awards Many countries are parties to the New York Convention on the II-15.81 recognition and enforcement of international arbitral awards,140 with new members continuing to join. For example, in 2017 Angola became the 157th Contracting State to the Convention, which now includes most oil- and gas-producing countries.141 The interpretation of grounds for refusing to recognise or enforce an award may vary from country to country142 and will directly affect the outcomes for   United Nations Convention on the Recognition and Enforcement of Foreign Arbitral Awards (New York, 10 June 1958). 141  Details of signatories are available on www.newyorkconvention.org/countries (accessed 2 May 2017). 142  For example, there is a perception that the power of a court of its own accord to refuse recognition or enforcement on grounds of public policy (New York Convention, 140

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disputants and their decision to attempt to enforce. It must be noted that some countries will not recognise or enforce awards if they provide for the accumulation of interest as distinct from the award of a specified sum of money.143 CONCLUSION AND FUTURE SCOPE II-15.82 This chapter notes that the oil and gas industry can, and does, make productive use of a range of dispute resolution processes. The dispute resolution landscape worldwide, and in the UK, has moved in recent years to a wider range of options than were historically considered and there is much greater access to evidence of what influences choice. This increased experience and awareness of options, changes in substantive and procedural laws, and expansion of markets globally sits uncomfortably alongside global financial constraints. Business efficiency should drive parties further towards a choice of process that uses the least time and expense, but in a situation where a party is unable to implement the contract due to financial constraints, a speedy solution may not necessarily provide the most advantageous outcome overall. II-15.83 Contracts in the industry that allow for periodic renegotiation enable both parties to respond to changing circumstances, but put even greater emphasis on the need for skilled and well-informed negotiators and for contracts to be negotiated with consideration as to how a project or business relationship might develop over time, rather than with the focus on the immediate work in hand. The industry runs a slight risk of being tied to well-known dispute resolution processes based on historical and personal experience and self-assessment of bargaining power, and may not yet take the maximum benefit to be had from open discussion over the choices available and the flexibility with which they may be combined. The industry has much to offer by way of collective experience in dispute resolution. It has much to gain by exploiting further potential for imaginative resolutions that are effective and productive for the disputants, the industry and wider environmental and financial domains in which it functions.

Art V, para 2(b)) may be used by courts, whether or not argued by a party, to favour disputants with greatest connection with that country, and disfavour those from countries with diverging political norms. A body of case law from different countries is kept on the Convention website at www.newyorkconvention.org/court+decisions (accessed 2 May 2017). 143   This is a particular issue in some Islamic countries.

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INDEX

Location references are to paragraph numbers; authors are indexed if they are mentioned in the main text. AAPL Model Form 610, II–2.03, II–2.43, II–2.44 AAPL Model Form 810, II–2.27 abandonment see decommissioning abuse of dominance EU law, II–11.10–14, II–11.18–20 ICoP and, II–11.52–3 infrastructure access and, I–6.64, I–6.70–2, II–11.46, II–11.51–4 prohibition, II–11.08, II–11.18–20 tying, II–11.20, II–11.56 vertical agreements, II–11.58 ACAS, II–15.47 account bank agreements, II–10.49, II–10.82–4 acreage competing applications, I–4.35–7, I–4–50 decline, II–3.15 Fallows Area Initiative, I–A.6 frontier areas, I–A.7 public announcement, I–4.19 recycling discarded acreage, I–4–54 rental payments, I–4–45–6 selection and environmental issues, I–4.24–31 unused acreage, I–A.23 adjudication arbitration see arbitration enforcement, II–15.78–81 litigation see litigation statutory adjudication, II–15.62–4 administration contractual rights and, II–10.99 decommissioning liabilities, II–10.105 environmental considerations, II–10.106–9 expenses, II–10.100–5 health and safety and, II–10.106–9 moratorium over legal proceedings, II–10.98–9

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objectives, II–10.97 overview, II–10.95–109 salvage principle, II–10.104–5 ADR see alternative dispute resolution affiliates affiliate guarantees, I–13.18, I–13.31 confidential information to, II–12.57 contractor groups, II–4.64, II–6.57 decommissioning, I–13.27, II–9.77 definition, II–5.58–9, II–5.67, II–9.49, II–9.50 IMHH Agreement, II–6.66 market share, II–11.14 operator groups, II–6.52 pre-emption rights and, II–9.48–54 transfer of assets to, II–9.48–54 agency law, operators, II–2.37–8 agency workers contracts, II–14.10 definition, II–14.04, II–14.10–18 employees or, II–14.12–18 end-users, II–14.10 implied contracts of service, II–14.12–18 length of employment relationship, II–14.17 working time rights, II–14.46 Agreement on Small Ceteceans of the Baltic and North Seas (ASCOBANS), I–11.15 AIM listing, II–10.11 AIPN see Association of International Petroleum Negotiators air pollution combustion installations, I–11.58–61 merchant shipping, I–11.50–7 national emission ceilings, I–11.64 offshore regulation, I–11.50–64 petroleum licensing and, I–11.62–4 air transport, IMHH Agreement and, II–6.71 ALARP standard, I–9.14, I–10.50 Aldersley-Williams, J, II–2.70 Algeria, I–3.55 alternative dispute resolution (ADR) civil procedure and, II–15.43–4

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concerns, II–15.49–54 confidential information, II–15.37, II–15.53–4 consensual nature, II–15.35 early neutral evaluation, II–15.55, II–15.64 enforcement, II–15.79 EU law, II–15.46 expert determination see expert determination foreign jurisdictions, II–15.45–6 litigation and, II–15.21 med-arb, II–15.57 mediation see mediation mini-trials, II–15.56 non-binding nature, II–15.52, II–15.56 option, II–15.04, II–15.35–64 power asymmetry, II–15.49–51 specialist tribunals, II–15.47 terminology, II–15.35 tiered escalation to, II–15.31, II–15.35 United States, II–15.25, II–15.45 American Arbitration Association/ International Court of Dispute Resolution (AAA/ICDR), II–15.66 AMIs (area of mutual interest) agreements, II–2.05, II–11.34 Anardako Petroleum, II–2.33 Angola, I–3.56, II–15.81 anti-competitive agreements block exemptions, II–11.17, II–11.48, II–11.64 technology transfer, II–11.64, II–12.27 de minimis exclusions, II–11.14–16 examples, II–11.11 exemptions, II–11.17, II–11.30, II–11.32 forms, II–11.12 horizontal agreements, II–11.28 infrastructure access and, I–6.64–9 issues in upstream agreements, II–11.30–67 joint operating agreements, II–11.28, II–11.30–3 joint procurement contracts, II–11.28, II–11.35 infrastructure agreements, II–11.46 joint sales contracts, II–11.28, II–11.36–45 Britannia decision, II–11.40 Corrib decision, II–11.42, II–11.45 EU decisions, II–11.39–45 infrastructure agreements, II–11.46–50

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UK-Belgium gas interconnector, II–11.41, II–11.44 non-compete clauses, II–11.58 prohibition, II–11.08–17 specialisation agreements, II–11.17, II–11.48 territorial restrictions, II–11.15, II–11.58 transport agreements, joint supply/ purchase of capacity, II–11.46–50 UUOAs, II–11.34 vertical agreements, II–11.29, II–11.56–67 exchange of information, II–11.60–2 market share, II–11.58 MER UK and, II–11.58–60 non-compete clauses, II–11.58 problem areas, II–11.58 void agreements, II–11.13 apprenticeships, II–14.05, II–14.22 arbitration binding nature, II–15.52, II–15.65 clauses, II–15.65 costs, II–15.06 Energy Charter, I–3.22 enforceability, II–15.66 enforcement, II–15.78–81 gas/LNG price reviews, II–8.45 governing law, II–15.67 industry preference for, II–15.01, II–15.66 international enforcement, II–15.81 international regimes, II–15.66 investor-state arbitration, II–15.48 jurisdiction, II–15.65 litigation alternative, II–15.70–1 med-arb, II–15.57 New York Convention, II–15.81 option, II–15.04 overview, II–15.65–71 power imbalances, II–15.50 privacy, II–15.71 process, II–15.66–8 reach of clauses, II–15.69 speed, II–15.70 Yukos arbitration, I–3.23 Ardmore field, I–12.54, II–2.56 area rental payments, I–4.45–7 Argyll field, I–4.74n ASCOBANS, I–11.15 Asfari, Ayman, I–10.58n asset acquisitions advantages, II–9.10–18 consents, II–9.14

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corporate acquisitions or, II–9.10–18, II–9.43 due diligence, II–9.16, II–9.19–29 earn-in, II–9.08 farm-in, II–9.07, II–9.81–3 insolvency cases, II–10.117–18 investigation of title, II–9.24 insolvency cases, II–10.117–18 liabilities, II–9.17, II–9.75–80 monetary consideration, II–9.06, II–9.59–65 no pre-emption, II–9.11–12 operatorship transfer, II–9.15 overview, II–9.04–18 simplicity, II–9.13 swaps, II–9.09, II–9.43, II–9.46 taxation, II–9.18 types, II–9.05–9 asset sale and purchase agreements assets, II–9.58 completion, II–9.84–8 conditions precedent, II–9.66–7 consents, II–9.66 consideration, II–9.59–65, II–10.118 decommissioning liabilities, II–9.76–80 indemnities, II–9.75–7 interim periods, II–9.68–9, II–9.88 overview, II–9.57–80 waiver of pre-emption rights, II–9.66 warranties, II–9.70–4 asset sales assignment clauses, II–9.21 auctions, II–9.22 consents, II–9.30–6 corporate capacity, II–9.29 due diligence, II–9.19 farm-out agreements, II–9.07, II–9.81–3 restrictions, II–9.37–56 asset stewardship see stewardship asset trading acquisitions see asset acquisitions agreements see asset sale and purchase agreements assignment see assignation/assignment completion, II–9.82 consents, II–9.27, II–9.30–6, II–9.66 consents to transfer, II–9.89, II–9.90 decommissioning agreements and, I–13.06, II–9.28 due diligence, II–9.19–29 execution deeds, II–9.89 farm-in/out, II–9.07, II–9.81–3, II–10.15 increasing activity, I–12.45 JOA consent, II–9.55–6

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joint ventures, II–2.12, II–2.22 Master Deed, II–2.13, II–9.32, II–9.43–5, II–9.87, II–9.89–93 MER Strategy and, I–12.45, II–9.03 New Transfer Arrangements, II–9.89–93 notices of transfer, II–9.89, II–9.92 OGA role, II–9.30–6 overview, II–9.01–93 portfolio management, II–9.02 pre-emption rights see pre-emption rights rationale, II–9.02 restrictions, II–9.37–56 sales see asset sales stewardship and, I–A.38 Wood Review, I–7.58 assignation/assignment completion, II–9.84–8 due diligence and, II–9.21, II–9.27, II–10.118 gas/LNG sales agreements, II–8.51 insolvency cases, II–10.118 intellectual property collaborations, II–12.43 future inventions, II–12.36 requirement, II–12.35 vertical agreements, II–11.58 JOAs, II–2.13, II–9.55–6 leases, II–13.13, II–13.24 licences, II–9.24 documentation, II–9.84 OGA consent, II–9.32 Master Deed, II–2.13, II–9.32, II–9.43–5, II–9.87, II–9.89–93 mortgages, II–10.77 patents, II–12.14 pre-emption rights and, II–9.21, II–9.27 affiliate route, II–9.48–54 overview, II–9.37–56 package deals, II–9.47 unmatchable deals, II–9.46 restrictions, II–9.21, II–9.37–56 securities, II–10.77, II–10.79 warranties, II–9.71 Association of International Petroleum Negotiators (AIPN) AIPN GSA, II–8.25, II–8.29, II–8.30, II–8.43, II–8.49, II–8.53 AIPN SPA, II–8.26, II–8.47 standard contracts, II–5.75–6 training programmes, II–15.24 Atiyah, Patrick, II–2.58 atmospheric emissions, I–11.50–61 auctions, II–9.22

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Australia forfeiture clauses and insolvency, II–2.91 Montara Oil Spill, I–11.101 production decline, I–5.07 SEAM, II–15.56 automated platforms, II–12.03 automatic referral notices (ARNs), I–6.86, I–6.94–5 aviation, II–6.04 back-to-back indemnity clauses, II–6.21–3, II–6.57, II–7.107 banking crisis (2007–8), II–10.94 BAT, I–11.36, I–11.37, I–11.60 BATNA, II–15.23 BDO Stoy Hayward Commercial Disputes Survey (2003), II–15.19 BEACH, II–8.30 BEACH 2015, II–8.22 Beck, M, I–10.47 Belgium North Sea continental shelf boundaries, I–8.09 UK-Belgium gas interconnector, II–11.41, II–11.44 benchmarking, II–11.55, II–11.60 bespoke licences, I–4.03, I–4.74 Best Available Technique (BAT), I–11.36, I–11.36, I–11.37, I–11.60 Best Environment Practice (BEP), I–11.36, I–11.37 Best Environment Practice (BES), I–11.36 bidding agreements, II–2.05–6, II–2.17, II–9.84, II–11.34 block exemptions see anti-competitive agreements blocks average size, II–3.15 contiguous blocks, I–4.22, I–4.23 fallow blocks see fallow blocks grid system, I–4.18–19 limitation on licensed numbers, I–4.66 meaning, II–03.02 part blocks, I–4.18 PEDLs, II–03.02 size and shape, I–5.17, I–9.09 bona vacantia, II–10.113 boycotts, I–12.25, II–11.11 BP, I–7.58, I–8.06, II–2.33, II–2.55, II–3.15, II–08.06, II–8.53 see also Deepwater Horizon disaster Brazil, II–4.41, II–12.03 Brent field, I–10.16n, I–12.01

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Brent Spar decommissioning consensus building, II–15.17 controversy, I–12.01, I–12.06, II–2.93 effect on regulation, I–11.20 Greenpeace protest, I–12.25–6 Guidance Notes and, I–12.56–7 legal impact, I–12.36, I–12.38–40, I–12.55 original disposal plan, I–12.20–4 OSPAR and, I–12.19, I–12.36, I–12.76 overview, I–12.19–36 Stakeholder Dialogue, I–12.06, I–12.27–35, I–12.36, II–15.07n Brexit, I–1.04, I–9.115n, II–11.01n, II–14.82 bribery, II–5.65, II–5.67 British Chamber of Commerce, I–9.86 British Gas, I–5.05, II–8.21 British Geological Survey, I–9.13 British National Oil Corporation (BNOC), I–5.05, II–2.03, II–5.13 brownfields Brownfields Initiative, I–5.06, I–12.81, I–A.35–51 Brownfields Studies Report, I–A.37–40 Brownfields Work Group, I–A.35, I–A.40 meaning, I–A.35 building contracts, II–2.67, II–2.85, II–5.03, II–6.04, II–15.62–4, II–15.77 bundling, I–6.72, I–6.89 Burgoyne Report, I–10.23–30, I–10.31, I–10.33–5, I–10.38–9 call-off contracts, II–5.57, II–5.59 Canada CAPL Operating Procedure JOA, II–2.43 JOAs, fiduciary duties, II–2.43 servitudes, II–13.23 standard contracts, II–5.74 Canadian Association of Oilwell Drilling Contractors (CAODC), I–5.74 capital allowances, I–3.44, I–7.28–33, I–7.62 CAR insurance, II–2.36 carbon budgets, I–3.60 carbon capture and storage, I–3.12, I–5.22, I–12.45 carry financing, II–10.26 cartels, II–11.02, II–11.03, II–11.23, II–11.36 cash flow finance, II–10–04

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casual workers, II–14.03, II–14.08, II–14.29, II–14.30 Center for Strategic & International Studies (CSIS), I–3.06 Centre for Environment, Fisheries and Aquaculture Science (CEFAS), I–11.19, I–11.38, I–11.45, I–11.46, I–11.47 Centrica, I–3.58 CERM, I–3.20–1, I–3.67 CFCs, I–11.51 CFR contracts, II–8.14 Channel Islands, I–8.12 charges, II–10.65, II–10.87, II–10.89 chemicals, I–9.26, I–11.38–42, I–11.44–8 Chevron, II–3.15 China, I–1.08 Chrysaor, I–7.58 Churchill, Winston, I–9.01 CIF contracts, II–08.06, II–8.15, II–8.17, II–8.20 circular indemnities, II–6.06–7 civil procedure ADR and, II–15.43–4 commercial court, II–15.75 costs, II–15.43 England, II–15.43, II–15.77 pre-action protocols, II–15.43–4 Scotland, II–15.44, II–15.75–6 summary trials, II–15.76 Technology and Construction Court, II–15.77 Clair field, II–3.15 Clair Platform, I–11.01, I–11.02 Clark, Greg, I–3.02 Claymore platform, I–10.32 climate change Committee on Climate Change, I–3.60 emission reduction and energy security, I–3.37–42, I–3.60–2 EU legislation, I–3.37, I–3.40, I–3.69 National Emissions Reduction Plan, I–3.37 renewable energy, I–3.30 closed list principle, II–13.03 cluster area allowances (CAAs), I–7.40 coal-fired power stations, I–3.41, I–3.62, I–3.69 coast protection, I–4.30, I–4.81, I–11.74–8 collaboration agreements, II–12.40–7 competition and, I–2.54, I–5.50–1, II–1.01, II–11.30–3, II–11.55, II–11.62–4

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deal-building, II–15.20 decommissioning, 1–12.46 dispute resolution and consensus building, II–15.17–19 option, II–15.04, II–15.17–20 intellectual property and, II–12.40 indemnities, II–12.46–7 joint ownership, II–12.43–5 legal obligation, I–5.33, I–5.46–57 meaning, II–12.38 MER Strategy, I–5.46–57, II–11.05, II–15.20 stakeholders, II–15.17–18 Wood Review and, I–2.54, I–5.23, I–5.46, II–04.01 Columbus field, II–3.15 combustion installations, I–11.58–61 Commercial Code of Practice (CCoP), I–5.53, I–6.79 commercial court, II–15.75 company groups, definition, II–5.59, II–5.62, II–6.52 company voluntary arrangements, II–10.119–20 Competition and Market Authority (CMA) collaboration and competition, I–5.50, II–1.01 de minimis agreements and, II–11.16 ICoP and, II–11.53 investigation powers, II–11.02 on OGA and competition, II–11.62 regulatory authority, I–6.64 competition law abuse of dominance see abuse of dominance administrative powers, II–11.04 anti-competitive agreements see anti-competitive agreements basic prohibitions, II–11.08–20 collaboration and, I–2.54, I–5.50–1, II–1.01, II–11.30–3, II–11.55, II–11.62–4 comfort letters, II–11.41 common oil and gas issues, II–11.30–67 dawn raids, II–11.03 de minimis exceptions, II–11.14–16, II–11.23 EU law, I–6.64, I–6.68 decisions on joint sales contracts, II–11.39–45 joint procurement, II–11.35 sanctions, II–11.02 exchange of information and, II–11.54–5

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importance, II–11.01–7 infrastructure access and, I–6.07, I–6.64–72, I–6.98, II–7.65 ICoP, II–11.52–3 joint supply/purchase, II–11.46–54 investigation powers, II–11.03 joint services, I–6.68 MER Strategy and, II–11.05, II–11.58–60, II–11.63–7 overview, II–11.01–67 price-fixing, I–6.68, II–11.11, II–11.15, II–11.58 relevant market, I–6.66–7, II–11.26–7 rule of capture and, II–3.04–5 sanctions, II–11.01–2 transport agreements and, II–7.65 UK or EU jurisdiction, II–11.21–5 whistle-blowing, II–11.03 compulsory purchase, II–13.03, II–13.09 computer programs see software concerted practices, II–11.12, II–11.55 confidential information ADR, II–15.37, II–15.53–4 arbitration, II–15.66 competition law and, II–11.54, II–11.55 vertical agreements, II–11.60–2 confidentiality agreements, II–5.14, II–7.09, II–7.29–32, II–11.56 due diligence and, II–9.20 employees and, II–12.33 intellectual property, II–12.26–32 joint operation agreements, II–2.42 LOGIC contracts, II–12.54–7 mediation, II–15.37 risk matrix, II–11.55 standard contracts, II–5.14 transport agreements, II–7.29–32 Conocophillips, II–3.15 consensus building, II–3.35, II–15.07, II–15.17–19, II–15.37 consequential losses assessment of exclusion, II–6.80–2 defining, II–6.81 drafting issues, II–6.80–1 exclusion, II–6.16, II–6.77–82 IMHH, II–6.61, II–6.81 JOAs, II–2.34 London Bridge, II–6.79, II–6.80 meaning, II–6.78–9 consideration asset purchase, II–9.06, II–9.59–65 insolvency cases, II–10.118 economic date, II–9.60–1 licences, I–4.32–4

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notional interest, II–9.63 share sales, II–9.65 working capital, II–9.62 consortium financing, II–10.30, II–10.33 construction and tie-in agreements entry into force, II–7.53 indemnities, II–7.51–2 transport, II–7.48–53 continental shelf boundaries see continental shelf boundaries UK see UKCS continental shelf boundaries 1969 North Sea cases, I–8.07, I–8.09–12 boundary agreements, I–8.06, I–8.08 unitisation and, II–3.52–65 early delimitation, I–8.07–8 North Sea boundaries, I–8.03–12 Rockall, I–8.13–35 territorial extent, I–4.61 UNCLOS, I–8.15–33 unresolved issues, I–8.13–33 contra proferentem interpretation, II–6.34–5, II–6.37, II–6.38–45 contractor groups, definition, II–4.62–4 contractors agency workers, II–14.04 contractor-operator relationship dismissal issues, II–14.83–93 drilling contracts, II–4.04–24 employment status, II–14.04 independence, II–14.25 contracts agency, II–2.37–8 categories, II–5.04 competition and see anti-competitive agreements construction and tie-in agreements, II–7.48–53 contract manuals, II–5.10 crude oil sales see crude oil sales agreements dayrate drilling see drilling contracts dispute resolution clauses, II–15.29–30 freedom of contract, II–8.02 gas/LNG sales see gas/LNG sales agreements IMHH Agreement see Industry Mutual Hold Harmless Deed indemnities see indemnities JOAs see joint operating agreements joint procurement contracts, II–11.28, II–11.35

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joint sales contracts, II–11.28, II–11.36–45 licences as, I–4.12–14, I–4.82, I–10.05 penalty clauses, II–8.40 primary and secondary obligations, II–8.41 risk allocation see indemnities risks, II–13.04 securities over contractual rights, II–10.76–80 service contracts, II–5.05–8 SPAs see petroleum sales agreements standard form see standard contracts structures, II–5.04–11, II–6.55, II–12.07–8 transport see transport agreements UUOAs see unitisation and unit operating agreements convertible bonds, II–10.09, II–10.12 co-operation, international law, II–3.51 copyright creation, II–12.17 exploitation options, II–12.19 licensing, II–12.19 overview, II–12.17–25 requirements, II–12.18, II–12.21 scope, II–12.22 software, II–12.23–5 training materials, II–12.20 corporate debt facilities, II–10.27–8, II–10.37, II–10.67 Corporate Major Accident Prevention Policy (CMAPP), I–10.65, I–10.66 corporate manslaughter, I–10.78–84 corporate veil, I–11.12, I–11.84 corporation tax capital allowances, I–7.31 new field developments, I–2.30–2 oil/gas taxation and, I–7.03 rates, I–2.22, I–2.24 recent reduction, effect, I–2.52 RFCT see ring fence corporation tax corruption, II–5.65, II–5.67, II–15.25 cost switch, II–7.77–9 cost-sharing agreements cost overruns, II–7.39 transport agreements, II–7.38–40 Côte d’Ivoire, I–3.56 country risks, II–10.08 Countryside Council for Wales (CCW), I–11.19 Court of Session procedure, II–15.44, II–15.76 Courtney, W, II–6.03

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credit insurance, II–10.25 credit rating, II–2.96, II–8.52 CREST, II–10.86 CRINE, II–5.15, II–11.35, II–12.51 Crommelin, M, II–2.20 cross guarantees, II–10.40, II–10.65, II–10.67 cross indemnities see mutual indemnities crossing agreements, II–7.42–7 cross-licence agreements, II–3.09, II–11.45 cross-user liability agreements (CULAs), II–7.97, II–7.106, II–7.107–9 Crown bona vacantia, II–10.113 exclusive exploration rights, I–4.08 leases, I–12.82 ownership of hydrocarbon deposits, I–4.04, I–4.59, II–3.10 ownership of UKCS, I–4.09, II–3.10 property rights, I–9.08 renewable energy and, I–12.82 crude oil sales agreements back-to-back contracts, II–08.06 CFR contracts, II–8.14 CIF contracts, II–8.06, II–8.15, II–8.17 collateral support, II–8.52–3 currency, II–8.19 delivery, II–08.12–17 derivatives, II–08.05 DES contracts, II–8.16 documents, II–08.05 FOB contracts, II–8.06, II–8.13, II–8.17 form and structure, II–8.04–7 general terms, II–08.05, II–08.06, II–08.07 grade and quality, II–08.08–10 overview, II–8.04–19 payment, II–8.19 price, II–8.18 quantity, II–08.11 risk and title, II–8.12–17 special provisions, II–08.05, II–08.06, II–08.07, II–08.08–19 Cuadrilla, I–9.01–2, I–9.91, I–9.100, I–9.128 Cullen Report causes of disaster, I–10.32–3 goal setting approach, I–10.36–7, I–10.50 overview, I–10.31–9 prescriptive approach and, I–9.16, I–10.35, I–10.50, I–12.55 recommendations, I–10.34–8, I–10.61, II–3.56

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safety case, I–10.41 trade unions and, I–10.39 Culzean field, I–7.40 currency movements, II–10.08 D’Ancona Report, I–6.73 Daintith, T, I–4.09, I–4.13, I–4.74, I–A.7, I–A.29 damages see also indemnities consequential losses see consequential losses decommissioning liabilities, I–12.77–82 Deepwater Horizon, II–2.33 torts, II–6.30 data room, II–9.22 Davey, Ed, I–5.07, I–10.63 DEA UK, II–9.35 DEAL, I–6.80, I–6.84, I–11.15 deal-building, II–15.20 debentures, II–10.65, II–10.69, II–10.72, II–10.95 debt capital options, II–10.09–14 decommissioning 1998 Petroleum Act, I–12.41–55 administration and, II–10.105 asset trading and, II–9.28 Brent field, I–12.01 Brent Spar see Brent Spar decommissioning chemicals, I–11.40 close-out reports, I–12.70, I–12.73, I–12.78 collaboration, 1–12.46 costs, I–12.03–5, I–12.40, I–12.54, I–13.01–3 current situation, I–12.01 definition, I–7.46 delaying, II–9.80 finance, II–10–04 financial information, I–12.52 financial security, I–12.53–4 Guidance Notes, I–12.41, I–12.56–74 residual liabilities, I–12.77, I–12.82 health and safety, I–10.44 IMO Guidelines, I–12.10, I–12.25, I–12.38n, I–12.58, II–2.93 international law 1996 Protocol, I–12.37 Continental Shelf Convention, I–12.07 London Dumping Convention, I–12.11–12, I–12.37

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OSPAR, I–12.13–18, I–12.19, I–12.36, II–93–4 OSPAR Decision 98/3, I–12.37–40, I–12.58, I–12.65, I–12.71–3, I–12.77, I–12.83, II–2.93 overview, I–12.07–18, II–2.93–4 UNCLOS, I–12.08–9, I–12.40, I–12.82 joint ventures, I–13.04–5, I–13.12, I–13.28, II–2.92–6 Model JOA, II–2.92, II–2.95 last option, I–12.57 liabilities, I–12.51, I–12.60–1 see also decommissioning security agreements asset sale and purchase agreements, II–9.76–80 foreign courts, I–12.79 Norway, I–12.79–80 residual liabilities, I–12.77–82 licences, Brent Spar, I–12.22–3 MER Strategy and, I–5.42, I–12.47, I–12.57, I–12.63, I–12.75, II–7.113 ministerial powers, I–12.53–5 monitoring sites, I–12.71–4 offshore installations, I–12.01–83 OGA role, I–12.42, I–12.46, I–12.47, I–12.48, I–12.63, I–12.75–6 strategy, II–5.78 plans see decommissioning plans principles, I–12.57 remedial action, I–12.51 section 29 notices see section 29 notices security see decommissioning security agreements (DSAs) site surveys, I–12.70 tax regime, I–13.02, I–13.34–8 relief, I–7.45–8, I–13.36–8, II–9.78 uncertainties, I–7.49–54 transport agreements and, II–7.110–13 Wood Review recommendations, I–5.23 decommissioning plans approval, I–12.46 Brent Spar, I–12.22 conditions, I–12.46 consultation, 1–12.46, I–12.42, I–12.48, I–12.59, I–12.66 contents, I–12.42, I–12.64 environmental impact assessments, I–12.67 environmental statements, I–12.67 financial information, I–12.52 financial security, I–12.53–4 implementation, I–12.50–1, I–12.70

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liabilities, I–12.51, I–12.60–1 MER Strategy and, 1–5.42, 1–12.46, I–12.47 ministerial powers, I–12.53–5 preliminary discussions, I–12.63–8 preparation by Secretary of State, 1–12.46 process, I–12.62–74 requirement, I–12.42, II–9.77 revision, 1–12.47–8 s 29 notices see section 29 notices submission, I–12.69 withdrawal of approval, I–12.49 Decommissioning Relief Deed (DRD), I–7.51–2 decommissioning security agreements (DSAs) asset trading and, I–13.06, II–9.28 collateral securities, I–13.19 commercial issues, I–13.31–3 end date, II–2.95 enforcing, I–13.21–2 fees, I–13.19 field and SPA-linked agreements, I–13.28–30 JOA parties, I–13.04–5, I–13.12, I–13.28 joint ventures, II–2.92, II–2.95 Model Form, I–13.11, I–13.26–7, I–13.31–3, I–13.38, II–2.03, II–2.92, II–2.95, II–2.96, II–5.14 alternative form, II–2.96 overview, I–13.12–25 parties, I–13.04–11 risk factor, I–13.14, I–13.15, I–13.31, II–2.95 run-down period, II–2.95 third tier participants, I–13.27 trigger date, I–13.15, I–13.29, I–13.31, II–2.95 Deepwater Horizon disaster catastrophic scale, I–11.101, II–4.138 criminal liabilities, II–2.33 damage, I–11.03–4, II–2.32 design and construction issues, I–10.68 dispute resolution and, II–15.18 fallout, II–1.01 liabilities, II–2.27, II–2.33 ministerial powers and, I–11.92 qualified indemnities and, II–6.25 regulatory impact, I–10.59, I–10.70, I–11.81, I–11.94, I–11.99, I–11.108, II–2.27 safety case approach and, I–10.90

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source of problems, I–11.83 wilful misconduct, II–2.32–3 delimitation agreements see continental shelf boundaries Delivered Ex Ship (DES) contracts, II–8.16, II–8.27 Denmark Brent Spar controversy and, I–12.32 cross-border fields, II–3.49 dispute resolution, II–15.25 DONG, II–11.43 DUC, II–11.43 joint sales agreements, II–11.43 North Sea continental shelf boundaries, I–8.07, I–8.08, I–8.09–12 Rockall dispute, I–8.14, I–8.19, I–8.20–2, I–8.25, I–8.26–7, I–8.32, I–8.35 deposits in the sea, I–11.49, I–11.72 derivatives, II–08.05, II–8.22 Derman, P and A, II–3.27, II–3.31 Det Norske Veritas (DNV), I–12.27, I–12.31, I–12.39 development control, I–9.36–42 development wells, I–4.60, I–11.32, I–13.01 Digital Energy Atlas and Library (DEAL), I–6.80, I–6.84, I–11.15 directors breach of permit, I–11.48 corporate manslaughter, I–10.78–84 disqualification, II–11.02 offences, I–10.87, I–11.12, I–11.61 wrongful trading, II–10.116 discoveries decline, I–2.02–3 early oil discoveries, I–3.08 maturity and undeveloped discoveries, I–2.21 Dispersed Oil in Produced Water Trading Scheme (DOPWTS), I–11.36 dispute resolution access to infrastructure, I–6.37 adjudication see adjudication ADR see alternative dispute resolution arbitration see arbitration choices, II–15.01–6 clauses, II–15.29 collaboration option, II–15.04, II–15.17–20 costs, II–15.06 dispute anticipation and management, II–15.07–8 employment disputes, II–15.47

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Energy Charter, II–15.48 exit points, II–15.02 flexibility, II–15.01 gas/LNG price reviews, II–8.45 gas/LNG sales agreements, II–8.51 guided-owner approach, II–3.38 industry culture, II–15.01–8 investor-state dispute resolution, II–15.48 lessons learned analyses, II–15.08 litigation see litigation MER Strategy and, II–15.11 negotiation clauses, II–15.29–34 lawyers and, II–15.26–7 LOGIC standard contracts, II–15.31 option, II–15.04, II–15.21–34 practices, II–15.21–3 teams, II–15.28 tiered escalation clauses, II–15.31–4 training, II–15.24–5 OGA recommendations, II–15.10, II–15.11 ombudsmen, II–15.09, II–15.11 overview, II–15.01–82 pendulum procedure, II–3.37 speed, II–15.01 stakeholders and, II–15.17–18 state parties, II–15.48 stress, II–15.19 unilateral action avoidance, II–15.12–13 complaints, II–15.09–11 dominant parties, II–15.14 health and safety and, II–15.15 missed opportunities, II–15.15–16 option, II–15.04 overview, II–15.09–16 unitisation agreements cross-border agreements, II–3.52, II–3.55 expert determination, II–3.35–40 WTO disputes, II–15.48 diving operations, I–10.45, II–14.44 drainage pipes, II–13.22 drill or drop, I–4.49 drilling contractor/ operator relationship commercial, II–04.05–12 operational, II–4.13–24 overview, II–04.04–24 supervision, II–4.49 dayrate drilling contracts see drilling contracts

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fluids and cuttings, I–11.43–9 industry cycles, II–4.05, II–4.07 onshore drilling consent, I–9.12–28 standard contracts, II–5.22 units see drilling units drilling contracts appendices, II–4.58 clauses, II–4.52 commencement, II–4.77–89 commencement date, II–4.77, II–4.83–9 effective date, II–4.77, II–4.80–2 conventional model, II–4.15, II–4.22–3 dayrates, II–4.06, II–4.121–36 currency, II–4.124 escalation clauses, II–4.69, II–4.81 force majeure rates, II–4.131–2 operating rates, II–4.123, II–4.125–6 redrill rates, II–4.134–6 repair rates, II–4.85, II–4.130 standby rates, II–4.127–9 weather rates, II–4.133 zero rates, II–4.85, II–4.92, II–4.130 definitions, II–4.61–76 contractor groups, II–4.62–4 drilling units, II–4.65–7 operating areas, II–4.68–70 wells, II–4.71–6, II–4.107 worksites, II–4.68–70 drilling units, II–4.25–48 duration, II–4.71, II–4.103–10 delivery deadlines, II–4.89 options, II–4.109–10 sidetracks, II–4.107 term-based contracts, II–4.104–5 well-based contracts, II–4.106 wells in progress, II–4.108 elements, II–4.49–144 end, II–4.90–103 completion date, II–4.90–3 contractors’ default, II–4.96 convenience, II–4.96, II–4.99–102 force majeure, II–4.89, II–4.96, II–4.98 insolvency, II–4.96, II–4.103 natural expiry, II–4.90–3 termination, II–4.55, II–4.94–103, II–5.23 exhibits, II–4.58 follow-on contracts, II–4.09, II–4.72, II–4.93 form of agreements, II–4.57–60 general conditions, II–4.58 indemnities, II–4.55, II–4.137–44

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catastrophic loss, II–5.55 downhole equipment, II–5.53 pollution, II–5.54 standard contracts, II–5.52–5 invitations to tender, II–4.49 liabilities, II–4.137–44 models, II–4.16–24 operator/contractor relationship, II–4.04–24 overview, II–04.01–144 project management model, II–4.21 remuneration, II–4.55 site access, II–4.54, II–4.56, II–4.111–20 standard contracts, II–5.22 indemnities, II–5.52–5 LOGIC MODU 97, II–4.52–74, II–4.86–91, II–4.97, II–4.114, II–4.116–18, II–5.22–4 structure, II–4.51–6 turnkey model, II–4.17–20 drilling units categories, II–4.25 definition, II–4.65–7 drillships, II–4.25, II–4.41–8 global numbers, II–4.26 inspection, II–4.28, II–4.82 jack-ups, II–4.25, II–4.26, II–4.27, II–4.29–34, II–4.112–13, II–4.118 nature, II–4.25–48 operational history, II–4.85 semi-sunmersibles, II–4.25, II–4.26, II–4.35–40, II–4.112 drillships, II–4.25, II–4.41–8 drinking water, I–10.42 due diligence asset purchasers, II–9.16, II–9.23 asset sellers, II–9.19 asset trading, II–9.19–29 assignment clauses and, II–9.21, II–9.27 charges, II–9.25 confidentiality and, II–9.20 consents, II–9.27 corporate capacity, II–9.29 data room, II–9.22 decommissioning agreements, II–9.28 encumbrances, II–9.25 existing agreements, II–9.26 insolvency cases, II–10.117–18 investigation of title, II–9.24 royalties, II–9.25 share purchase, II–9.16 third-party rights, II–9.25 duty of care confidential information and, II–11.56

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corporate manslaughter, I–10.79–81 decommissioning and, I–12.77–8 operators, II–2.27–31 principle, II–6.30

early neutral evaluation, II–15.55, II–15.64, II–15.79 earn-in, II–9.08 easements, II–13.06, II–13.21, II–13.27, II–13.31 economic date, II–9.60–1 economic modelling cost reductions, I–2.18–19, I–2.46 exploration, I–2.12, I–2.41–51 maturity and undeveloped discoveries, I–2.21 Monte Carlo technique, I–2.11, I–2.13, I–2.41, I–2.45 pre-oil price collapse, I–2.16–20 procedure, I–2.11–15 tax incentives and new field developments, I–2.22–40 EEA competition law, II–11.23, II–11.27 control of air pollution, I–11.60 members, II–11.23 Egypt, I–3.55 Ekofisk Bravo accident (1977), I–10.23 Elswick field, I–9.01 emergency preparation, I–10.43 emissions atmospheric emissions, I–11.50–61 emissions trading, II–7.72, II–7.73 employee protection insurance, II–2.36 employees agency workers, II–14.04 contracts of service, II–14.05 implied contracts, II–14.12–18 control criterion, II–14.06, II–14.12 definition, II–6.53, II–14.05–9 intellectual property and, II–12.33–7 intention of parties, II–14.07 multi-factor approach, II–14.06 mutual obligations, II–14.08, II–14.11 personal service, II–14.09, II–14.24 posted workers, II–14.36, II–14.42 rights, II–14.02 substitutes, II–14.09, II–14.24 territorial jurisdiction, II–14.33–43 unfair dismissal see unfair dismissal worker status, II–14.21 working time rights, II–14.46 employment ADR, II–15.47

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agency workers see agency workers British regulation of offshore workers meaning of offshore work, II–14.44–5 territorial jurisdiction, II–14.31–43 working time see working time categories, II–14.02–4 dismissal at third party requests, II–14.83–93 dispute resolution, II–15.47 employees see employees family rights, II–14.02 independent contractors see contractors industry practice, II–14.32 legal overview, II–14.01–93 mobile workforce, II–14.32 non-discrimination, II–14.22 post-Brexit regulation, II–14.82 status of personnel, II–14.02–30 workers see workers employment agencies see also agency workers indemnities, II–6.12 industry practice, II–14.10, II–14.18 status of workers, II–14.10–18 employment tribunals indemnities against claims, II–6.12 personal jurisdiction, II–14.02 pre-action protocol, II–15.47 territorial jurisdiction, II–14.33–43 working time jurisdiction, II–14.68, II–14.71 encumbrances, II–8.12, II–9.25 Energy Charter, I–3.22–5, I–3.68, II–15.48 Energy Charter Secretariat, I–3.06, I–3.07 energy consumption emission reduction, I–3.60–2 energy efficiency, I–3.60–2 EU reduction, I–3.28–9 UK, I–3.54–63 UK imports, I–3.54–6, I–3.64 energy security Energy Charter, I–3.22–5 EU legislation, I–3.26–36, I–3.66 reduction in energy consumption, I–3.28–9 renewable energy, I–3.30 stock-holding, I–3.26–7, I–3.31–5 international dimension, I–3.16–25 International Energy Program, I–3.16–21, I–3.32 National Security Strategy, I–3.03, I–3.74 oil crises, I–3.16, I–3.20, I–3.22, I–3.28 overview, I–3.01–75

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Scottish policy, I–9.119–22 UK, I–3.08–15 diversification, I–3.63 emission reduction, I–3.37–42, I–3.60–2 energy consumption, I–3.54–63 energy efficiency, I–3.14, I–3.60–2 energy production, I–3.43–53 exports, I–3.10, I–3.15, I–3.65 gas storage, I–3.57–9 imports, I–3.11–13, I–3.54–6, I–3.64 renewable energy, I–3.63, I–3.73 Wick Report, I–3.05 Energy Security Strategy (2012), I–3.51 English, W, II–3.09, II–3.19, II–3.26, II–3.46 Enoch and Blane, II–3.65 Enquest, I–7.58 environment administration and, II–10.106–9 air pollution, I–11.50–61 blowouts, I–11.03, I–11.101 chemicals, I–11.38–42, I–11.44–8 coastal areas, I–4.30, I–4.81, I–11.74–8 consequential harm regulation, I–11.81–93 decommissioning, I–12.67 Deepwater Horizon, I–11.03–4 drilling fluids and cuttings, I–11.43–9 early UKCS regulation, I–11.06–7 EIAs, I–4.26, I–11.14, I–12.67 emergencies, I–11.02 environmental statements decommissioning plans, I–12.67 production regulation, I–11.16–19 exploration regulation, I–11.22–9 model clauses, I–11.22 FEPA licences, I–11.37 habitats, I–4.25, I–11.08–15 health and safety regulation, I–10.66–7, I–11.98 incidents, I–11.01 interference with other sea users, I–11.73–80, I–12.07 jurisdictions, I–10.61 leases and, II–13.13 liabilities, asset trading and, II–9.76 marine spatial planning, I–4.28–31 oil pollution see oil pollution onshore wells, I–9.13, I–9.25–8 operational harm, I–11.02 operational impacts of petroleum operations, I–11.08–80 petroleum licensing and, I–4.24–31

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produced water, I–11.34–7 production regulation, I–11.16–21, I–11.30–3 environmental statements, I–11.16–19 risks, II–10.08 sewage and garbage, I–11.65–72 spills, I–11.01–2 strategic environmental assessments, I–4.27 UKCS regulation, I–11.01–108 Environment Agency, I–9.25–6, I–10.61 Environment Council, I–12.29–30 environmental impact assessments, I–4.26, I–11.14, I–12.67 environmental statements (ES) decommissioning plans, I–12.67 production regulation, I–11.16–19 E.ON, II–11.03 equality regulation, II–14.04, II–14.22, II–14.43 equity finance, II–10.09–14 Esso, I–8.06, I–12.20 EU see also Brexit Energy Charter, I–3.22–5 energy imports, I–3.15 law see EU law members, II–11.23 UK accession, I–3.27 EU law ADR, II–15.46 civil liability for oil pollution, I–11.105–6, I–11.108 climate change legislation, I–3.37, I–3.40, I–3.69 competition, I–6.64, I–6.68 abuse of dominance, II–11.10–14, II–11.18–20 decisions on joint sales contracts, II–11.39–45 joint procurement, II–11.35 sanctions, II–11.02 technology transfer, II–11.64, II–12.27 UK or EU jurisdiction, II–11.21–5 Emissions Trading Scheme, II–7.72, II–7.73 energy security legislation, I–3.26–36, I–3.66 environmental statements, I–12.67 health and safety at work, I–10.46 insolvency, II–10.96 licensing, I–4.11 competing applications, I–4.36

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offshore safety, I–10.59–76, I–11.94–8 oil pollution, I–11.94–8 patents, II–12.15 pipelines, I–6.66 REACH, I–9.26 trade secrets, II–12.31–2 working time, II–14.44–5 amending, II–14.81–2 European Federation of Energy Traders, MASTER DES LNG SPA, II–8.27, II–8.29 European Patent Office, II–11.15 Ewing, Fergus, I–9.108, I–9.119, I–9.121–2 exclusive economic zones, I–4.01, I–4.39, I–8.23, I–11.96, II–2.93 exclusive purchasing/supply agreements, II–11.11 expert determination court jurisdiction and, II–3.39 enforcement, II–15.79 gas/LNG price reviews, II–8.45 nature of process, II–15.58–60 option, II–15.04 overview, II–15.58–61 scope, II–15.61 unitisation, II–3.35–40 exploration competition law, relevant market, II–11.27 Crown rights, I–4.08 decline, I–2.01, I–2.51, I–5.07 early activity, I–3.08 environmental regulation, I–11.22–9 model clauses, I–11.22 finance, II–10–04, II–10.10 government funding, I–5.17 licences see exploration licences MER Strategy, I–5.42 modelling, I–2.12, I–2.41–51 regional exploration plans, I–5.16 shale gas, I–9.02–5 size of exploration blocks, I–5.17 tax issues, I–7.41–2 Wood Review recommendations, I–5.15–17 Exploration Expenditure Supplement, I–7.31–3 exploration licences geological surveys and, I–11.13 landward licences, I–4.79 Markham field, II–3.53 meaning, I–4.39 model clauses, I–4.17, I–4.40

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non-exclusivity, I–4.05, I–4.39 onshore petroleum, I–9.08 rights, I–4.39 seaward licences, I–4.03, I–4.39–40 shale gas, I–9.127 export control, II–4.69 export finance, II–10.25 facility information requests, I–12.59 Falkirk Against Unconventional Gas, I–9.103 Fallow Areas Initiative assessment, I–A.33–4 Fallow Blocks Process, I–A.11–22 Fallow Discovery Process, I–A.11, I–A.23–32 overview, I–A.7–34 pre-Wood state control, I–5.06 schemes, I–A.11 fallow blocks classification, I–A.14–16 definition, I–A.12 industry attitude, I–A.40 list, I–A.13 model clauses and, I–A.47 numbers, I–A.7, I–A.9, I–A.33 process, I–A.11–22, I–A.25 dispute resolution, I–A.22 timescale, I–A.27 voluntary system, I–A.22 public policy, I–A.49–50 reasons, I–A.7 Fallow Discovery Process aims, I–A.23 classification, I–A.26 grounds for rejecting programmes, I–A.32 model clauses and, I–A.28–32 overview, I–A.11, I–A.23–32 tightened scheme, I–A.34 timescale, I–A.27 voluntary system, I–A.23 family rights, II–14.02 farm-in/out agreements, II–9.81–3 finance option, II–9.07, II–10.15 Faroe Islands, I–8.14, I–8.19, I–8.20, I–8.21, I–8.27, I–8.30 fee letters, II–10.51 FEPA licences, I–11.49 Ferrers, Lord, I–10.13 FIDIC contracts, II–5.03 fiduciary duties definition, II–2.39–42

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operators, II–2.39–43 Field, S, I–10.84 field agreements contractual structure, II–5.05 function, II–5.04 parties, II–5.11 standard contracts, II–5.14 field allowances, I–3.47, I–7.12, I–7.34, I–7.37 finance account bank agreements, II–10.49 account controls, II–10.64 on balance sheet debt, II–10.27–8 borrowing base mechanism, II–10.54–60 carry financing, II–10.26 consortium financing, II–10.30, II–10.33 corporate debt facilities, II–10.27–8, II–10.37 debt capital options, II–10.09–14 documents, II–10.40–53 equity, II–10.09–14 export finance, II–10.25 farm-out, II–9.81, II–10.15 fee letters, II–10.51 forward purchasing, II–10.21–2 hedging documents, II–10.52–3 insolvency see insolvency intercreditor agreements, II–10.47–8 land rights and, II–13.08 lifecycle, II–10–06 loan agreements, II–10.40–6 net profit interest, II–10.16–18 prepayment facilities, II–10.20 project finance, II–10.23–4 purposes, II–10–04–5 RBL facilities, II–10.35–6 repayment, II–10.61–3 risk factors, II–10.07–8 royalties, II–10.19 securities see securities sources, II–10.06, II–10.08–39 step-in agreements, II–10.24 streaming, II–10.21–2 syndication, II–10.37–8 trends, II–10.121 vendor finance, II–10.29–32 Fiscal Review, I–1.03 Fisheries Legacy Trust Company, I–12.81 Fisheries Research Services (FRS), I–11.19, I–11.45, I–11.46, I–11.47 fixed charges, II–10.69, II–10.72, II–10.77, II–10.79, II–10.82–4 fixed-interest agreements, II–3.09

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floaters, II–4.26, II–4.27, II–4.35–40 floating charges, II–10.65, II–10.67, II–10.69–70, II–10.91, II–10.95, II–10.108, II–10.116 flotels, II–14.77 FOB contracts, II–08.06, II–8.13, II–8.17, II–8.20, II–8.28, II–8.29 force majeure dayrate drilling contracts, II–4.89, II–4.96, II–4.98, II–4.131–2 dispute resolution and, II–15.14 gas/LNG sales agreements, II–8.37, II–8.49–50 OSPAR Convention, I–12.18 Rough platform, I–3.58 volcanic ash, II–4.132 forfeiture clauses asymmetrical terms, II–2.75 building contracts, II–2.67 decommmisioning and, II–2.96 enforceability, II–2.57, II–2.70, II–2.74–82 insolvency law and, II–2.55–7, II–2.83–91 joint ventures, II–2.54–91 penalty clauses, II–2.57, II–2.58–82 time periods, II–2.82 unfair preferences, II–2.57, II–2.83–91 unitisation agreements, II–3.45–6 withering interest clauses, II–2.63, II–2.65 Forties field, I–10.16n forward purchasing, II–10.21–2 Foster, J, I–10.47 FPSO units see also transport agreements arrangements, II–7.21 costs, II–7.18, II–7.21 industry practice, II–7.20 meaning, II–7.18 storage capacity, II–7.19 transport option, II–7.18–21 Wood Review on, II–7.20 fracking see shale gas/fracking France, North Sea boundaries, I–8.12 fraud, I–11.80, II–6.43, II–6.44 free market economics, I–5.05 Fridman, Mikhail, II–9.35 Friends of the Earth, I–9.92, I–9.99 Frigg Agreement, II–3.59–61, II–3.62, II–3.63 frontier licences 26th round, I–4.64 assessment, I–4.68

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flexibility, I–4.86 introduction, I–3.46, I–4.63, I–4.74 MER Strategy, I–4.67 nine-year licences, I–4.65 numbers, I–4.68 overview, I–4.61–8 terms, I–4.64 withdrawal, I–4.63

G7, I–12.26 Gabon, I–3.56 Gannet Alpha Platform, I–11.01, I–11.03 garbage definition, I–11.65 offshore regulation, I–11.65, I–11.70–2 gas LNG, I–3.13, I–3.55, II–11.27 prices, II–8.42–8 relevant market, II–11.27 sales agreements see gas/LNG sales agreements storage, I–3.57–9 gas/LNG sales agreements AIPN GSA, II–8.25, II–8.29, II–8.30, II–8.43, II–8.49, II–8.53 AIPN SPA, II–8.26, II–8.47 assignment clauses, II–8.51 BEACH 2015, II–8.22 CIF contracts, II–8.20 collateral support, II–8.52–3 conditions precedents, II–8.51 delivery, II–8.30–5 dispute resolution, II–8.51 excess/shortfall, II–8.36–7 FOB contracts, II–8.20, II–8.28, II–8.29 force majeure, II–8.37, II–8.49–50 form and structure, II–8.20–8 governing law, II–8.51 key terms, II–8.29–51 liabilities, II–8.51 Master DES LNG SPA, II–8.27, II–8.29 Master Ex-Ship LNG Sales Agreement, II–8.28 Master FOB LNG Sales Agreement, II–8.28 Model Master Agreement, II–8.22 National Balancing Point (NBP), II–8.22, II–8.30, II–8.42 NBP 2015, II–8.22 overview, II–8.20–51 passing of risk/title, II–8.30 payment, II–8.51 price diversion, II–8.47–8 price review clauses, II–8.44–6

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pricing, II–8.42–3 quantity, II–8.29, II–8.51 specification, II–8.51 take or pay clauses, II–8.38–41 taxation, II–8.51 verification clauses, II–8.51 warranties, II–8.51 General Lighthouse Authority (GLA), I–11.75 geological surveys, I–11.11–15 Germany Brent Spar controversy and, I–12.32 Brent Spar protest, I–12.25 cross-border fields, II–3.49 North Sea cases, I–8.07–12 North Sea continental shelf boundaries, I–8.10–12 UK oil exports to, I–3.15 Ghana, I–3.56 Gill Report (2009), II–15.44 good oilfield practice, II–2.27, II–2.29 Greenpeace, I–12.01, I–12.06, I–12.25–7 grid system, I–4.18–19 gross negligence, II–2.28, II–2.33, II–6.24 Gryphon FPSO, I–10.92 guarantees affiliates, I–13.18, I–13.31 asset transfer and, II–9.55, II–9.66 cross guarantees, II–10.40, II–10.65, II–10.67 due diligence, II–9.26, II–9.28 leases, II–13.24 loan guarantees, II–10.25 parent company guarantees, II–8.52, II–8.53, II–9.77 Gulf War (1991), I–3.20 habitats, I–4.25, I–11.08–15 Hackett, Jim, II–2.33n Hackitt, Judith, I–10.92 Harvard Negotiation Program on Negotiation (PON), II–15.23 health and safety at work 1974 Act, I–9.15, I–10.18–22 administration and, II–10.106–9 maintenance trend, I–2.10 offshore see health and safety offshore onshore see health and safety onshore Robens Report (1972), I–10.18–22, I–10.24, I–10.30, I–10.33 working time and, II–14.74, II–14.80 zero tolerance approach, II–15.15 Health and Safety Commission, I–10.10, I–10.40

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Health and Safety Executive centralisation, I–10.10 cross-border agreements and, UK/ Netherlands, II–3.56 decommissioning and, I–12.63 environmental jurisdiction, I–10.61 guidance, I–10.51, I–10.53 Key Programme 3, I–10.55–8, I–10.90 Key Programme 4, I–10.91, I–10.92 on maintenance trend, I–2.10 methods, I–10.38, I–10.47, I–10.48 onshore safety, I–9.20–8 regulatory authority, I–9.16 safety cases, I–10.41–7 working time enforcement, II–14.68–70 health and safety offshore 1st phase, I–10.03, I–10.04–11 2nd phase, I–10.03, I–10.12–30 3rd phase, I–10.03, I–10.31–58 4th phase, I–10.03, I–10.59–76 1974 Act, I–10.18–22 asset integrity, I–10.55–8, I–10.83, I–10.90–1 Burgoyne Report, I–10.23–30, I–10.31, I–10.33–5, I–10.38–9 criminal liability, I–10.41, I–10.77–88 2008 Act, I–10.85–8 corporate manslaughter, I–10.78–84 penalties, I–10.83–4, I–10.85–7 cross-border agreements, UK/ Netherlands, II–3.56 Cullen Inquiry, I–10.31–9, I–10.39, I–10.41, I–10.50, I–10.60, I–12.55 emergency response, I–10.43, I–10.71 environment and, I–10.66–7, I–11.98 EU law, I–10.46, I–10.59–76 Offshore Safety Directive, I–10.60–76, I–11.94–8 evolution, I–10.02–3 goal-setting regulations, I–10.36–7, I–10.42–7 Institute of Petroleum Code, I–10.05, I–10.07–9 Key Programme 3, I–10.55–8, I–10.81, I–10.83, I–10.90, I–10.92 Key Programme 4, I–10.91, I–10.92 leadership, I–10.58 licensing approach, I–10.03, I–10.04–11 Macondo disaster see Deepwater Horizon disaster Major Hazard Report, I–10.62 no blame culture, II–15.15 occupational health, I–10.04 overview, I–10.01–92

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permissioning approach, I–10.03, I–10.31–58 Piper Alpha see Piper Alpha disaster (1988) prescriptive approach, I–10.03, I–10.12–30, I–11.94, I–12.55 quantified risk assessments (QRAs), I–10.35, I–10.38, I–10.53 regulators, I–10.17, I–10.61–3, I–10.75–6, I–11.97–8 Safety Case, I–10.34, I–10.37, I–10.62 1992 legislation, I–10.41–7 2005 Regulations, I–10.48–54 2015 Regulations, I–10.64–76 assessment, I–10.90 major accidents, I–10.71–4 Sea Gem Inquiry, I–10.06–11, I–10.12, I–10.13, I–10.16, I–10.19, I–10.23–5, I–10.32, I–10.35–6, I–10.38 workforce involvement, I–10.39, I–10.50 health and safety onshore consent to drill, I–9.12–28 guidance, I–9.21–3 legislation, I–9.15–16 well integrity, I–9.19–24 hedge funds, II–10.09, II–10.52–3 hedging agreements, II–10.76 Heffron, R, I–9.119 helicopter operations, I–10.42, I–10.43 Hewitt, G, II–2.17, II–2.18, II–2.70 Hewitt, T, II–6.28 high-yield bonds, II–10.09, II–10.12 Hill, A, I–4.04, I–4.09, I–4.74 Hinkley Point C power station, I–3.51 Historic Scotland, I–9.53 holidays annual holiday rights, II–14.62–4 holiday pay, II–14.23, II–14.63–4 home rule see Scottish devolution Hong Kong, II–15.56 horizontal agreements, II–11.28 see also anti-competitive agreements hub development, II–3.11 human rights, I–4.13 Hunt, Lord, I–3.48 hydraulic fracturing see shale gas/fracking Iceland, Rockall dispute, I–8.14, I–8.19, I–8.20–1, I–8.25, I–8.27–8, I–8.32, I–8.35 ICSID, II–15.48 IMHH see Industry Mutual Hold Harmless Deed

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indemnities asset trading agreements, II–9.75 building contracts, II–6.04 circular indemnities, II–6.06–7 collaboration, IP licensing, II–12.46–7 concept, II–6.03–4 consequential loss see consequential losses construction and tie-in agreements, II–7.51–2 contractual indemnities, II–6.03–76 corporate acquisitions, II–6.04 dayrate drilling contracts, II–4.55, II–4.137–44 definitions, II–6.03 company groups, II–6.52 drafting, II–6.52–4 employees, II–6.53 personnel, II–6.53, II–6.61 property, II–6.54, II–6.61 drafting issues definitions, II–6.03, II–6.52–4 delimiting circumstances, II–6.46–7 interpretation issues, II–6.37–54 multi-party issues, II–6.48–9 negligence issue, II–6.38–45 stray indemnities, II–6.51 employment agencies, II–6.12 fraud and, II–6.44 full and primary indemnities, II–6.50, II–6.60, II–6.61 gas/LNG sales agreements, II–8.51 heads, II–4.142 ICoP, I–6.92–3 indemnity and hold harmless clauses back-to-back provisions, II–6.21–3, II–6.57, II–7.107 carve-outs, II–6.23–5 case law, II–6.33–54 concept, II–6.05 drafting, II–6.37–54 interpreting, II–6.33–54 mapping, II–6.27 multi-party issues, II–6.48–9, II–6.55–76 negligence issue, II–6.38–45 oil and gas contracts, II–6.09–12, II–6.21–2 presumptions, II–6.30 qualifying provisions, II–6.23–5 rejection, II–6.26 statutory control, II–6.28–9 third parties, II–6.31–2 unfair contract terms, II–6.28–9

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infrastructure access, I–6.92–3, I–6.117–18, II–6.26, II–6.85 interpretation contextualism, II–6.36 contra proferentem, II–6.34–5, II–6.37, II–6.38–45, II–6.46 drafting implications, II–6.37–54 general rules, II–6.33 traditional approach, II–6.33–5 issues, II–6.28–32 judicial suspicion, II–6.04, II–6.11 liability caps, II–6.83–6 access to infrastructure, II–6.85 importance, II–6.86 third parties, II–6.84 transport agreements, II–7.43 unfair terms, II–6.84 LOGIC contracts, II–6.05 intellectual property, II–12.52, II–12.60–1 multiple parties, II–6.48–9, II–6.55–76 see also Industry Mutual Hold Harmless Deed mutual hold harmless see mutual hold harmless indemnities mutual indemnities meaning, II–6.04 mutual hold harmless clauses and, II–6.06–12 overall limitations of liability, II–6.83–6 parties, II–4.140 pipeline servitudes, II–13.14 qualified indemnities, II–6.23–5 risk matrix table, II–4.144 servitudes, pipelines, II–13.14, II–13.24 simple indemnity clauses meaning, II–6.04 oil and gas contracts, II–6.09 stray indemnities, II–6.51 strict liability, II–4.144 subrogation rights, II–6.50, II–6.61, II–6.66–7 timing, II–4.143 transport agreements, II–7.94, II–7.97–9 crossing and proximity agreements, II–7.43–5 CULAs, II–7.97, II–7.106, II–7.107–9 new entrants, II–7.106 triggers, II–4.141 independent contractors see contractors indirect losses see consequential losses Industry Mutual Hold Harmless Deed (IMHH) 2012 Deed, II–6.58

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affiliates, II–6.66 complexity, II–6.76 consequential losses, II–6.61, II–6.81 contractual, II–6.75–6 core provisions, II–6.59–61 dangers of scheme, II–6.76 Deed of Adherence, II–6.63, II–6.75 definitions, groups, II–6.66 effect, II–6.69 entry into force, II–6.63 exceptions, II–6.70–3 air transport, II–6.71 landward areas, II–6.72 operators, II–6.73 full and primary indemnities, II–6.50, II–6.60, II–6.61 gaps, II–6.76 general acceptance, II–6.76 geographical extent, II–6.64 group benefits, II–6.66 initial Deed, II–6.58 introduction, II–6.58 new parties, II–6.63 order of precedence, II–6.65 overview, II–6.58–76 parties, II–6.58 personnel, II–6.61, II–6.66 purpose, II–6.59 right to defend, II–6.68 risk allocation, II–5.63 scope, II–6.61 terminology, II–6.05 third parties, II–6.66, II–6.76 waiver of subrogation, II–6.61, II–6.66–7 withdrawal from, II–6.69 information see confidential information infrastructure access see infrastructure access categories, I–6.22–7 collaboration, I–5.33, I–5.61 competition and, I–6.07, I–6.64–72, I–6.98, II–7.65 integrity, I–10.57 lack, I–3.46 LNG, I–3.55 Norway, I–3.13 OGA role, II–7.76 pipelines see pipelines Piper Alpha disaster and, I–10.57 specification, II–7.92–6 taxation, I–7.55–7 terminology, I–6.22–7 transport see transport

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UK-Norway Framework Treaty (2005), II–3.63 West of Shetland, I–3.48 Wood Review, I–2.54, I–5.21 infrastructure access applications, I–6.94, I–6.99 capacity, I–6.38, I–6.90–1, I–6.102–3 collective capacity, II–7.100–3 new entrants, II–7.104–6 competition and, I–6.07, I–6.64–72, I–6.98, II–7.65 ICoP, II–11.52–3 joint supply/purchase, II–11.46–54 complex regime, I–6.14 Energy Act 2011, I–6.21–44 factors, I–6.29–30 Guidance, I–6.14, I–6.52, I–6.63, I–6.71 applications, I–6.99 capacity, I–6.102–3 conflicting contracts, I–6.104–5 goals, I–6.96 liabilities, I–6.117–18 non-discrimination, I–6.106 overview, I–6.96–118 principles, I–6.106 statutory factors, I–6.101 tariffs, I–6.107–16 ICoP see Infrastructure Code of Practice indemnities, I–6.92–3, I–6.117–18, II–6.26, II–7.97 liability caps, II–6.85 Infrastructure Act 2015, I–6.45–8 issues, I–6.01–19 legislative framework, I–6.21–48 MER Strategy, I–6.01, I–6.49–63, I–6.105, I–6.115, I–6.120 overview, I–6.01–123 principles, I–6.12, I–6.62–3 small companies, I–3.50, I–6.05 tariffs, I–6.90, I–6.107–16, I–7.55, II–7.71–6 technical difficulties, I–6.09 ullage, I–7.55 Wood Review, I–2.54, I–5.21 Infrastructure Code of Practice (ICoP) adhering to, I–5.53, II–7.65 applications, I–6.94 ARNs, I–6.94 automatic referral notices, I–6.86, I–6.94–5 capacity, I–6.90–1 competition issues, II–11.52–3 complex regime, I–6.14, I–6.52 compliance, II–11.52

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conflicts of interest, I–6.87 indemnities, I–6.92–3 information sharing, I–6.80–4 introduction, I–6.73–4 liabilities, I–6.92–3 mutual hold harmless provisions, I–6.93 non-discrimination, I–6.72, I–6.88 overview, I–6.73–95 parties, I–6.87 pre-MER document, I–6.15 principles, I–6.79 reasonableness, I–6.86, I–6.90 scope, I–6.75–8 separation of services, I–6.89 tariffs, I–6.90, II–11.52 timelines, I–6.86 transparency, I–6.79, I–6.88 unbundling, I–6.89 voluntary code, I–6.75 Wood Review and, I–5.19 innovate licences 29th round, I–4.03, I–4.41 flexibility, I–4.63, I–4.67, I–4.77, I–4.86 frontier licences and, I–4.63 guidance, I–4.78 meaning, I–4.03 model clauses, I–4.03 overview, I–4.75–8 purpose, I–4.76 success, I–4.79 terms, I–4.78 work programmes, I–4.47 innovation see also intellectual property collaborations see collaboration commercial challenges, II–12.05–10 first-mover advantage, II–12.06 importance, II–12.01–4 insolvency acquisition of assets in, II–10.117 administration, II–10.95–109 anti-deprivation principle, II–2.83, II–2.90 company voluntary arrangements, II–10.119–20 dayrate drilling contracts and, II–4.96, II–4.103 decommissioning securities and, I–13.21, I–13.25 EU law, II–10.96 liquidation, II–10.110–18 numbers, II–2.56, II–10.93, II–10.122 overview, II–10.93–122 small companies, II–2.55

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specialist regimes, II–10.94 unfair preferences, II–2.57, II–2.83–91 wrongful trading, II–10.116 Institute of Petroleum, Model Code of Safe Practice, I–10.05, I–10.07–9, I–11.06 insurance CAR insurance, II–2.36 credit insurance, II–10.25 employee protection, II–2.36 National Insurance, II–14.32, II–14.37 operators, II–2.36 overseas investment, II–10.25 securities over, II–10.76, II–10.81 intellectual property assignation collaborations, II–12.43 future inventions, II–12.36 requirement, II–12.35 vertical agreements, II–11.58 collaboration agreements, II–12.40 confidential information, II–12.26–32 copyright, II–12.17–25 know-how, II–12.26–32 licensing, II–12.14, II–12.19, II–12.48–50 LOGIC contracts, II–12.51–61 background IP, II–12.53–7 confidential information, II–12.54–7 foreground IP, II–12.58–9 indemnities, II–12.52, II–12.60–1 title, II–12.52–9 no-challenge clauses, II–11.64 overview, II–12.11–37 ownership employee v contractor, II–12.33–7 joint ownership in collaborations, II–12.43–5 patents, II–12.12–16, II–12.48 intercreditor agreements, II–10.47–8 interests clauses, JOAs, II–2.10–11, II–2.33 International Air Pollution Prevention Certificates (IAPPs), I–11.52 International Association of Drilling Contractors (IADC), standard contracts, II–5.16, II–5.73, II–5.76 International Chamber of Commerce (ICC), II–15.66 International Court of Arbitration, II–15.66 International Court of Justice jurisdiction, I–8.24, I–8.29 North Sea cases, I–8.07, I–8.09–12

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International Energy Agency (IEA), I–3.16–21, I–3.32, I–3.59, I–3.67 International Energy Program (IEP Agreement), I–3.16–21, I–3.32 International Finance Corporation, II–15.09 International Group of Liquefied Natural Gas Importers Master Ex-Ship LNG Sales Agreement, II–8.28 Master FOB LNG Sales Agreement, II–8.28 International Maritime Organization (IMO), decommissioning guidelines, I–12.06, I–12.10, I–12.25, I–12.38n, I–12.58, II–2.93 International Swaps and Derivatives Association, II–08.05, II–8.22 interpretation rules contextualism, II–6.36 contra proferentem, II–6.34–5, II–6.37, II–6.46 negligence issue, II–6.38–45 general rules, II–6.33 investment allowances assessment, I–7.62 introduction, I–7.34 mechanism, I–7.34–40 new field developments, I–2.22, I–2.28, I–2.34 value allowance, I–7.39 investment exit risk, II–10.08 investor-state dispute resolution, II–15.48 Iran, I–1.08, I–3.20 Iraq, invasion of Kuwait, I–3.20 Ireland, Rockall dispute, I–8.14, I–8.19, I–8.20–2, I–8.25, I–8.30, I–8.32, I–8.35 irritancy, II–10.98 Israel Six-Day War (1967), I–3.24 Yom Kippur War (1973), I–3.16, I–3.28 ITLOS, I–8.24, I–8.29 jack-up drilling units, II–4.25, II–4.26, II–4.27, II–4.29–34, II–4.112–13, II–4.118 Japan, I–3.11 JCT contracts, II–5.03 Jennings, A, II–6.81 joint bidding agreements, II–2.05–6, II–2.17, II–9.84, II–11.34 joint operating agreements (JOAs) see also operators

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pass marks, II–2.47 pre-emption rights, II–2.13, II–9.11, II–9.37, II–9.43–54 proprietorial functions, II–2.09–13 securities over rights, II–10.79–80 sole risk clauses, II–2.50–3 standard contracts, II–5.13 tenancy in common, II–2.11 tendering process, II–5.36 UUOAs and, II–3.17–18, II–3.46 wilful misconduct, II–2.28–9 work programmes, II–5.06 joint operating committees agency and, II–2.38 authorisations for expenditure, II–2.46, II–2.49 budgets, II–2.49 consents, II–2.43 contracts, II–2.35 importance, II–2.44 information to, II–2.48 insurance and, II–2.36 litigation and, II–2.36 membership, II–2.23, II–2.45 non-consent clauses, II–2.50–3 overview, II–2.45–91 pass mark, II–2.47, II–2.50–1 powers, II–2.46 sole risk clauses, II–2.50–3 subcommittees, II–2.45 supervision, II–2.26 ultimate responsibility, II–2.45 voting rights, II–2.45, II–2.47, II–9.26 asset sales, II–9.66 joint procurement contracts, II–11.28, II–11.35 joint sales contracts, II–11.28, II–11.36–45 joint ventures agreements see joint operating agreements benefits, II–2.01 competition law issues, II–11.30–3 federal contracts, II–11.33 information sharing, II–11.32 incorporated JVs, II–2.07 Macondo field, II–2.33 meaning, II–2.02, II–2.07, II–2.18 nature, II–2.07–22 rationale, II–2.01 tax advantages, II–2.02 termination, II–2.09 terminology, II–2.07 unincorporated JVs, II–2.02, II–2.07–8, II–2.97

assessment, II–2.97 cash calls, II–2.54, II–10–04 classes of members, II–2.23 common interests, II–6.26 competition law issues, II–11.28, II–11.30–3 confidential information, II–2.42 consent to transfers, II–9.55–6 consequential losses, II–2.34 contractual nature, II–2.08–9 contractual structure, II–5.04, II–5.06–7, II–5.09, II–5.11 co-operation and competition, II–11.30–3 decommissioning, II–2.92–6 security, I–13.04–5, I–13.12, I–13.28, II–2.95–6 default, II–2.54–7 description, II–2.75 express written terms, II–2.43 fiduciary duties, II–2.42–3 forfeiture clauses, II–2.54–91, II–10.109 decommmisioning and, II–2.96 enforceability, II–2.57, II–2.70, II–2.74–82 insolvency law and, II–2.57, II–2.83–91 penalty clauses, II–2.57, II–2.58–82 unfair preferences, II–2.57, II–2.83–91 functional-related functions, II–2.09, II–2.14–22 functions, II–2.08–9 good oilfield practice, II–2.27, II–2.29 horizontal agreements, II–11.28 interests clauses, II–2.10–11, II–2.33 interests transfer, II–2.12, II–2.22 model forms, II–2.03–4 no mutual liability, II–2.02 non-consent clauses, II–2.50–3 non-operators, II–2.23, II–2.24, II–2.42, II–2.44 novation, II–9.84, II–9.89 OGA Model JOA, II–2.03–4, II–5.13 agency, II–2.38 consequential losses, II–2.34 decommissioning, II–2.92 interests clause, II–2.10 Opcom, II–2.44 wilful misconduct, II–2.29 opcoms see joint operating committees operators’ obligations, II–2.23–43 partnerships, II–2.02, II–2.07, II–2.15–22, II–7.12–15

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unlocking value, I–5.53 Wood Review and, I–5.17 Jones, L, I–10.84 Jones, P, II–3.32 junior loans, II–10.09 Kasim, A S, I–2.05 Kemp. A G, I–2.05 Key Programme 3, I–10.55–8, I–10.81, I–10.83, I–10.90, I–10.92 Key Programme 4, I–10.91, I–10.92 knock for knock indemnities see mutual indemnities know-how, II–12.26–32 Korea, I–3.11 Ladbury, R, II–2.20 Laggan field, I–3.47, I–3.48 land law abandonment, II–13.11 leases see leases licence to occupy, I–4.04 no separate code for oil/gas, II–13.03–5 ownership, II–13.10–11 pipelines and, II–13.01 registration of interests, II–13.15 servitudes, II–13.25 servitudes see servitudes statutory wayleaves, II–13.31 Land Register of Scotland, II–13.15, II–13.25 Lands Tribunal for Scotland, II–13.20 landward licences see also onshore regulation categories, I–4.03, I–4.79 consent to drill, I–9.12–28 licensing authority, I–4.80, I–9.09 licensing rounds, I–4.80 overview, I–4.79–81 PEDLs see petroleum, exploration and development licences production rate, I–4.81 proprietary licences, I–4.04 law of the sea continental shelf boundaries see continental shelf boundaries decommissioning and, I–12.07–18, I–12.36 development, I–8.01–2 interference with other sea users, I–11.73–80 UNCLOS see UNCLOS Leadsom, Andrea, I–3.51

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leases assignation, II–13.13 covenants, II–13.24 commercial leases, II–13.13 exclusive possession, II–13.12 leasehold servitudes, II–13.01, II–13.23 pipeline routes, II–13.29 pre-emption rights, II–13.13 real rights, II–13.06, II–13.12–13 rent, II–13.13 statutory regulation, II–13.13 LetterOne Group, II–9.35 letters of credit, I–13.18, II–2.96, II–8.06, II–8.53, II–9.28 Lewis, G, II–2.20 liability caps access to infrastructure, II–6.85 importance, II–6.86 overview, II–6.83–6 third parties, II–6.84 transport agreements, II–7.43 unfair terms, II–6.84 Libecap, G, II–3.05 Liberia, I–3.56 licences see also licensing regime; specific licences assets, II–9.58 assignment see assignation/assignment breach of licence, I–4.84 categories, I–4.03 consideration, I–4.32–4 contractual nature, I–4.12–14, I–4.82, I–10.05 core rights, II–2.06 cross-licences, II–3.09 exclusivity, I–4.05 FEPA licences, I–11.49 forms, I–4.04 JOAs and, II–2.06, II–2.09 landward licences see landward licences non-exclusive licences, I–4.05 online information, II–9.24, II–9.30 retrospective amendment, I–5.13 revocation, I–4.51, II–9.36, II–10.99, II–10.120 royalties, I–4.33, I–7.27 sea deposits, I–11.49 seaward licences see seaward licences securities over, II–10.70–5 terms and conditions, I–4.15–17 third party rights and, I–4.06 transfer see also asset trading

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consents, II–9.30–6, II–9.45 JOA consent, II–9.56 Open Permission, II–2.12, II–10.70–5 share sale and, II–9.34–5 licensing applications competing applications, I–4.35–7, I–4.50 fees, I–4.34 notices, criteria, I–4.37 out-of-rounds applications, I–4.22–3, I–4.80, II–2.05, II–03.08, II–3.12 promote licences, I–4.72 licensing regime see also licences; specific licences air pollution and, I–11.62–4 applications see licensing applications collaboration, I–5.33 discretionary system, I–4.14, I–4.32 environmental issues, I–4.24–31 EU law, I–4.11 flexibility, I–4.86 grid system, I–4.18–19 intellectual property see intellectual property issues, I–4.18–38, I–4.82–6 legal basis, I–4.07–11 legal concept, I–4.04–6 light-touch regulation, I–5.06, I–5.11 replacement, II–1.01 MER Strategy, I–5.42 models, I–4.01–2 national security and, I–4.37 onshore petroleum, I–9.07–11 petroleum licensing, I–4.01–86 pre-Wood philosophy, I–5.05–6 Scottish devolution, I–9.125–6 strict concession regime, I–7.18, I–7.27 territorial rights, I–4.01 transition, I–4.85 transparency, I–4.38 UK approach, I–4.01, I–4.03 UK hybrid system, I–4.12–14 UK law, I–4.07–10 Wood Review and, I–4.82–3 licensing rounds 1st round, I–8.07, II–2.03 4th round, I–3.08 5th round, II–2.03, II–5.13 6th round, II–2.03 14th round, I–9.09, I–9.10 20th round, I–4.52, I–4.63, I–4.74, II–2.03, II–2.04, II–2.13 21st round, I–4.69, I–4.74 24th round, I–4.27

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25th round, II–5.13 26th round, I–4.63, I–4.64, I–4.65 28th round, I–4.43, I–4.68 29th round, I–4.03, I–4.21, I–4.41 30th round, I–4.15, I–4.41 landward licences, I–4.80 numbers, I–4.21, I–4.80 procedure, I–4.20–1 Wood Review and, I–5.16 liens, II–10.08, II–10.09, II–10.69n, II–10.85n lifting operations, I–10.45 limited companies, joint ventures, II–2.02 Lindley and Banks on Partnership, II–2.18, II–2.21 Lindsey Oil Refinery, I–10.84 liquefied natural gas see LNG liquidation disclaiming onerous property, II–10.112–13 overview, II–10.110–18 Scotland, II–10.110, II–10.114–15 liquidity risks, II–10.08 literary works, II–12.17, II–12.18, II–12.23 litigation alternative to arbitration, II–15.70–1 choice of court, II–15.72 civil procedure see civil procedure enforcement, II–15.78–81 jurisdiction, II–15.65 operators, II–2.36 overview, II–15.72–7 Technology and Construction Court, II–15.77 warranties, II–9.71 LNG competition law, relevant market, II–11.27 imports, I–3.13 infrastructure, I–3.55 sales agreements see gas/LNG sales agreements UK imports, I–3.55–6 loan agreements, II–10.40–6 loan guarantees, II–10.25 loan life cover ratio (LLCR), II–10.57 Loan Market Association (LMA), II–10.40–1 loan notes, II–10.09 logging while drilling, II–4.14 LOGIC establishment, II–5.16 fallow blocks and, I–A.14

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standard contracts see LOGIC standard contracts LOGIC standard contracts allocation of risk, II–5.43 amendments, II–5.21, II–5.56–65 anti-bribery and corruption, II–5.65, II–5.67 appendices, II–5.31 automation, II–5.84 call-off contracts, II–5.57, II–5.59 case law, II–5.22–4 changing terms, II–5.21 consistency, II–5.25 contractor-contractor liability, II–5.62–3 definition of affiliates, II–5.58–9 disadvantages, II–5.25 dispute resolution clauses, II–15.31 drafting, II–5.20, II–5.25 drilling contract, II–5.22–4 form, II–5.28–33 future, II–5.78–84 general terms, II–5.29–30 governing law, II–5.29 guidance notes, II–5.34–5, II–5.66 IMHH see Industry Mutual Hold Harmless Deed indemnities, II–5.41–55, II–6.05 intellectual property, II–12.51–61 key provisions, II–5.40–55 models, II–5.16–17, II–5.26 MODU 97, II–4.52–74, II–4.86–91, II–4.97, II–4.114, II–4.116–18, II–5.22–4 mutual hold harmless indemnities amendments, II–5.61–3 contractor-contractor liability, II–5.62–3 exceptions, II–5.46–55 IMHH Scheme see Industry Mutual Hold Harmless Deed key provisions, II–5.41–55 mobile drilling rigs, II–5.52–5 well services, II–5.46–51 negotiation of disputes, II–15.31 new contracts, II–5.82–3 On-and Offshore Services, II–15.31 Purchase Order Terms and Conditions, II–15.31 special terms, II–5.32–3 Standard Contracts Committee, II–5.40 tendering process, II–5.36–9 updating, II–5.21, II–5.25, II–5.66–8 variations clauses, I–5.64 warranties, II–5.60

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London Court of International Arbitration (LCIA), II–15.66 Low Carbon Transition Plan, I–3.40, I–3.60–2, I–3.69, I–3.72, I–3.73 loyalty, fiduciary duties, II–2.40 Macondo disaster see Deepwater Horizon disaster Magnus field, I–7.58 Major, John, I–12.26 Major Hazard Reports, I–10.62, I–11.95 mandated lead arrangers (MLAs), II–10.42 Mandelson, Peter, I–3.48 Marine and Coastguard Agency (MCA), I–10.61, I–10.90, I–11.26, I–11.67, I–11.69, I–11.85 Marine Management Organisation (MMO), I–4.30 Marine Scotland, I–4.30 marine spatial planning, I–4.28–31 market definition, II–11.26–7, II–11.46 market share, II–11.14, II–11.58 market-sharing agreements, II–11.11 Markham field, II–3.53–7 Marriage, P, I–4.09 Martin, A T, II–5.25 Master Deed, assignation, II–2.13, II–9.32, II–9.43–5, II–9.87, II–9.89–93 maternity leave, II–14.02 Mature Province Initiatives Fallow Areas Initiative, I–A.7–34 overview, I–A.1–51 Stewardship Initiative, I–A.35–51 Wood Review and, I–A.1 med-arb, II–15.57 mediation agreements, II–15.36 confidential information, II–15.37, II–15.53–4 contract clauses, II–15.32, II–15.36 deal-building and, II–15.20 evaluative method, II–15.42 facilitative method, II–15.41 lawyers and, II–15.40 med-arb, II–15.57 mediators’ role, II–15.38 mediators’ skills, II–15.39 methods, II–15.41–2 mini-trials, II–15.56 Netherlands, II–15.45 Norway, II–15.46 overview, II–15.36–42 process, II–15.37

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merchant shipping see shipping mergers see takeovers and mergers mezzanine loans, II–10.06, II–10.08, II–10.09, II–10.47 mini-trials, II–15.56 Mitsui, II–2.33 modelling see economic modelling Monte Carlo technique, I–2.11, I–2.13, I–2.41, I–2.45 Monti, Mario, II–11.42 Moodys, II–2.96 MOOIP (moveable oil originally in place), II–3.23, II–3.26 mortgages, II–2.11, II–10.69, II–10.77, II–10.85, II–10.87, II–10.89 Murchison Field Agreement, II–3.59, II–3.63 mutual hold harmless indemnities see also indemnities back-to-back provisions, II–6.21–3, II–6.57, II–7.107 concept, II–6.06–12 contractor-contractor liability, II–5.62–3 ICoP, I–6.93 LOGIC standard contracts amendments, II–5.61–3 contractor-contractor liability, II–5.62–3 exceptions, II–5.46–55 IMHH Scheme see Industry Mutual Hold Harmless Deed key provisions, II–5.41–55 mobile drilling rigs, II–5.52–5 well services, II–5.46–51 London Bridge, II–6.13, II–6.18–20, II–6.28–9, II–6.41–2, II–6.45, II–6.50 multi-party issues, II–6.48–9, II–6.55–76 mutual indemnities and, II–6.06–12 oil and gas contracts, II–6.13–20 qualified indemnities, II–6.23 transport agreements, II–7.97–9 mutual indemnities see also mutual hold harmless indemnities concept, II–6.06 mutual hold harmless indemnities and, II–6.06–12 Mutual Indemnity and Hold Harmless Deed see Industry Mutual Hold Harmless Deed

SEAM, II–15.56 training, II–15.38, II–15.49 transformative method, II–15.42 United States, II–15.45, II–15.46, II–15.73, II–15.79 MER Strategy abandonment plans and, 1–12.46, 1–12.47 asset trading and, I–12.45, II–9.03 Central Obligation, I–5.40, I–5.41, I–5.44 infrastructure access and, I–6.50, I–6.61 unitisation and, II–3.11 collaboration, I–5.46–57, II–11.05 deal-building, II–15.20 commencement, II–9.03 competition law and, II–11.05, II–11.58–60, II–11.63–7 conceptual confusion, I–5.28–32 decommissioning and, I–5.42, I–12.47, I–12.57, I–12.63, I–12.75 transport agreements, II–7.113 dispute resolution and, II–15.11 effect, I–1.08 enforceability, I–5.32 frontier licences and, I–4.67 implementation, I–4.17, I–5.02, I–5.25, I–5.28–70 infrastructure access, I–6.01, I–6.49–63, I–6.50, I–6.54, I–6.59–60, I–6.105, I–6.115, I–6.120 legal obligation, I–5.33–40 licensing regime and, I–4.84 LOGIC standard contracts and, II–5.78–84 OGA and, I–5.44, I–10.03, II–5.78 cost switch and, II–7.78 purpose, II–9.03 reinforcing, I–2.52–6 required actions, I–5.45, I–6.51 safeguards, I–5.45, I–5.49, I–5.58–62 competition law and, II–11.63 infrastructure access, I–6.50, I–6.54, I–6.59–60 sector strategies, I–5.63–70 send or pay clauses and, II–7.83 Supporting Obligations, I–5.40, I–5.42–4, I–5.67 infrastructure access, I–6.51, I–6.54, I–6.58 technology and, II–12.04, II–12.64 unitisation and, II–04–5 Wood Review see Wood Review

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National Balancing Point (NBP), II–8.22, II–8.30, II–8.42

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national emissions ceilings, I–11.64 National Emissions Reduction Plan, I–3.37 National Environmental Research Council (NERC), I–12.29 National Insurance, II–14.32, II–14.37 national oil companies, I–7.19 national security, licensing and, I–4.37 National Security Strategy, I–3.03, I–3.74 National Transmission System (NTS), I–6.11, II–7.10–11, II–7.12–13, II–8.22, II–8.30 Natura 2000, I–11.09, I–11.14 Natural England, I–11.19 Natural Environment Research Council (NERC), I–11.28 NBP 2015, II–8.22 negligence gross negligence, II–2.28, II–2.33, II–6.24 indemnity drafting and, II–6.38–45 negotiations clauses, II–15.29–34 collaborative deal-building, II–15.20 dispute resolution, II–15.04, II–15.21–34 foreign jurisdictions, II–15.25 lawyers and, II–15.26–7 practices, II–15.21–3 teams, II–15.28 tiered escalation clauses, II–15.31–4 training, II–15.24–5 net present value (NPV), II–9.60, II–10.56, II–10.57, II–10.58 net profit interest (NPI), II–9.07, II–9.59, II–10.08, II–10.16–18 Netherlands Brent Spar controversy and, I–12.32 cross-border fields, II–3.49 dispute resolution, II–15.25 exploration strategy, I–5.15 gas development, I–5.20 Groningen gas field, I–4.09, I–8.02 Markham field agreement, II–3.53–7 mediation, II–15.45 North Sea continental shelf boundaries, I–8.07, I–8.08, I–8.09–12, II–3.52–7 UK oil exports to, I–3.15 UK/Netherlands delimitation agreement (1965), I–8.08, II–3.52–7 neutral evaluation, II–15.35, II–15.55, II–15.64, II–15.79 Nigeria, I–1.08, I–3.56, II–3.27 night work, II–14.56–9, II–14.66

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Ninian field, I–10.16n non-compete clauses, II–11.58 non-consent clauses, II–2.50–3 non-discrimination law, I–4.11, I–4.36, II–14.22, II–14.26, II–14.43 non-operators, II–2.23, II–2.24, II–2.42, II–2.44 North Sea continental shelf boundaries, I–8.03–12 deep water, I–12.04 Norway Brent Spar decommissioning and, I–12.26, I–12.32 cross-border fields, II–3.49 decommissioning liabilities, I–12.79–80 development strategy, I–5.06 Ekofisk Bravo accident (1977), I–10.23 Frigg Agreement, II–3.59–61, II–3–62, II–3.63 gas exports to UK, I–3.54, I–3.64, I–3.70 Gas Negotiation Committee, II–11.43 gas transport, I–6.11 health and safety offshore, I–10.59 joint gas sales, II–11.43, II–11.45 mediation, II–15.46 Murchison Field Agreement, II–3.59, II–3.63 North Sea continental shelf boundaries, I–8.08, I–8.09 oil field size, I–7.17 oil pollution liability, I–11.103 oil trade, I–3.12–13 Petroleum Safety Authority, I–11.98 pipelines, I–3.13 production decline, I–5.07 sovereignty over continental shelf, I–8.02n standard contracts, II–5.70–2 Statfjord Agreement, II–3.59, II–3.62, II–3.63 taxation and exploration, I–7.42 transport tariffs, II–7.75, II–7.76 UK-Norway Agreement (1965), I–8.08, II–3.58–65 UK-Norway Framework Treaty (2005), II–3.63–5 notional interest, II–9.63 nuclear power, I–3.51, I–9.119, I–9.121 numerus clausus principle, II–13.03 Nuttal, W, I–9.119 Occidental Petroleum, I–10.32 OECD, I–3.16, I–3.22, I–3.67

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Office of Carbon Capture and Storage, I–5.22 Offshore Fisheries Legacy Trust, I–13.23 Offshore Industry Advisory Committee, I–10.27 Offshore Pollution Liability Agreement (OPOL), I–11.104, I–11.107, II–2.36 offshore work accommodation, II–14.77 dismissal at third party requests, II–14.83–93 meaning, II–14.44–5 UK employment regulation, II–14.31–43 working time and, II–14.44–82 offtake agreements, II–10.76 oil allowance, I–7.09 Oil and Gas Authority (OGA) see also licensing access to infrastructure and, I–6.28–63, I–6.96–118 guidance, II–11.52 Activity Survey (2014), I–5.07 appeals against decisions, II–15.09 asset stewardship and, I–5.68–70 Asset Stewardship Expectations, II–5.78, II–12.64 asset trading and consents, II–9.30–6, II–9.45, II–9.66 farm-outs, II–9.08 collaboration and, I–5.45, I–5.54–7, II–1.01 competition and, II–11.62, II–11.64–6 deal-building, II–15.20 creation, I–5.02, I–5.27, I–10.63, I–11.100 DEAL, I–11.15 decommissioning and, I–12.42, I–12.46, I–12.47, I–12.48, I–12.63 Decommissioning Insight 2016, I–12.01 MER Strategy, II–7.113 Model DSA, I–13.11, I–13.26–7, I–13.31–3, I–13.38, II–2.03, II–2.92, II–2.95, II–2.96 role, I–12.75–6, II–7.111 strategy, II–5.78 dispute resolution recommendations, II–15.10, II–15.11 effect, I–5.03 ICoP and, I–6.74, II–11.52 innovate licences and, I–4.77, I–4.78, I–4.86 interventionism, I–4.01, I–4.85, II–1.01 landward licences, I–4.80

EU42448.indb 555

launch, II–5.78 licensing obligations, I–4.13 licensing powers, I–4.14 discretionary licensing, I–4.17, I–4.32–4 reasonableness, I–5.59 revocation, I–4.51, II–9.36, II–10.99, II–10.120 using, I–5.71 MER Strategy and, I–5.44, I–10.03, II–5.78 balancing interests, II–9.03 cost switch and, II–7.78 decommissioning and, II–7.113 hub development, II–3.11 on national emissions ceilings, I–11.64 notifications to, surveys, I–11.13 Offshore Fisheries Legacy Trust, I–13.23 online licence information, II–9.24, II–9.30 operators and, I–4.60 programmes, I–5.02 second-tier participants, I–13.27, I–13.32 securities, consent, II–10.70, II–10.74–5 send or pay clauses and, II–7.83 standard contracts, II–5.13–14, II–5.20 Model JOA see joint operating agreements Supply Chain Strategy, II–5.01, II–5.18, II–5.78–81 transport and infrastructure role, II–7.76 unitisation and, II–3.13–18 work programmes and, I–4.49, I–4.51 Oil and Gas Independents’ Association (OGIA), I–3.50 Oil and Gas Industry Task Force (OGITF), I–A.5, II–5.16 Oil and Gas Technology Centre, II–12.63 Oil and Gas UK, I–3.48, I–5.24, II–12.51 oil crisis (1973), I–3.16, I–3.22, I–3.28 oil crisis (1979–81), I–3.20, I–3.22 Oil Industry Taskforce, I–4.38 oil pollution civil liability, I–11.102–8 EU law, I–11.105–6, I–11.108 international law, I–11.104 OPOL, I–11.104, I–11.107, II–2.26 Deepwater Horizon, I–11.03, I–11.81, I–11.83, I–11.92, I–11.94, I–11.99, I–11.101, I–11.108, II–2.32 emergency control, I–11.90–3 insurance, II–2.36

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international law, I–11.81 merchant shipping, I–11.82–5 Offshore Safety Directive, I–11.94–8 petroleum activities, I–11.86–9 UK Regulations, I–11.81 oil prices crash, I–1.08, I–2.01, I–10.02 asset trading and, II–9.01 decommissioning and, I–12.01, I–13.02 insolvencies, II–2.55–6, II–10.93, II–10.122 current trend, II–2.55 economic modelling and, I–2.20 high price period, I–7.22 new normal, II–5.02 SPAs, II–8.18 volatility, II–8.01 ombudsmen, II–15.09, II–15.11 Ong, D, II–3.02, II–3.51 onshore allowance, I–7.34 onshore regulation consent to drill, I–9.12–28 environmental impact, I–9.13, I–9.25–8 fracking see shale gas/fracking guidance, I–9.21–3 health and safety, I–9.13, I–9.15–18 landward licences see landward licences legislative framework, I–9.12–28 overview, I–9.01–128 planning see planning regulator, I–9.16 Review, I–9.02 UK approaches, I–9.07–28 well integrity, I–9.19–24 opcoms see joint operating committees Open Permission, II–2.12, II–10.70–5 operating areas, definition, II–4.68–70 operators agency, II–2.37–8 appointment ministerial approval, II–2.24 OGA consent, I–4.60 choice, II–2.24 contractor-operator relationship dismissal issues, II–14.83–93 drilling contracts, II–4.04–24 contractor-operators, II–2.25 contractual structure, II–5.04–11 default notices, II–2.54 definition, I–10.52, I–10.64 drilling contractor relationship commercial, II–04.05–12 invitations to tender, II–4.49–50

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operational, II–4.13–24 oversight, II–4.49 overview, II–4.04–24 duties, II–2.26–31 duty of care, II–2.27 fiduciary duties, II–2.39–43 good oilfield practice, II–2.27, II–2.29 IMHH Agreement and, II–6.73 information duties, II–2.48 insurance, II–2.36 JOAs, II–2.23–43 liabilities, II–2.27–31 litigation, II–2.36 one-stop shop approach, II–12.08 removal, II–2.24 resignation, II–2.24 role, II–2.24, II–2.26 sole risk, II–2.50–3, II–3.43 transfer, asset trading, II–9.15 UUOAs, II–3.17 wilful misconduct, II–2.28–33 OPOL, I–11.104, I–11.107, II–2.36 OSPAR Brent Spar and, I–12.38, I–12.76 chemicals and, I–11.45, I–11.46, I–11.47 Decision 98/3, I–12.37–40, I–12.58, I–12.63, I–12.65, I–12.71–3, I–12.76, I–12.77, I–12.83, II–2.93 decommissioning and, I–5.23, I–12.13–18, II–93–4 Recommendation 2001/1, I–11.36 OSPAR Commission, I–11.36, I–12.39, I–12.40 out-of-rounds applications, I–4.22–3, I–4.80, II–2.05, II–03.08, II–3.12 overseas investment insurance, II–10.25 Owen, David, I–10.29 ownership co-ownership and partnership, II–2.20 Crown see Crown doctrine of tenure, I–9.08 intellectual property employee v contractor, II–12.33–7 joint ownership in collaboration, II–12.43–5 LOGIC contracts, II–12.52–9 land law see land law parent company guarantees, II–2.96, II–8.52, II–8.53, II–9.77 Park, J, II–5.25 Parliamentary Ombudsman, II–15.09 part blocks, I–4.18

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partnerships agency, II–2.37 definition, II–2.20 joint ventures, II–2.02, II–2.07, II–2.15–22, II–7.12–15 passing of title gas/LNG sale agreements, II–8.30 petroleum sales agreements, II–8.12–17 Patent Office, II–11.13, II–11.16 patents assignation, II–12.14 EU law, II–12.15 European patents, II–11.15 exploitation options, II–12.14 international law, II–12.15 licensing, II–12.14, II–12.48 oil companies, II–12.16 overview, II–12.12–16 requirements, II–12.13 rights, II–12.12 paternity leave, II–14.02 Peel, E, II–6.43 penalty clauses, forfeiture clauses as, II–2.58–82 pendulum procedure, II–3.37 permit to work system (PTW), I–10.32, I–10.42 personal protective equipment, I–10.43 personal servitudes, II–13.31 personnel definition, II–6.53, II–6.61 IMHH, II–6.66 petroleum, exploration and development licences (PEDLs) blocks, II–03.02 introduction, I–4.79 landward licences, I–4.03, I–9.125 licensing authority, I–4.80 licensing rounds, I–4.80, I–9.09 model clauses, I–9.11 numbers, I–9.09 overview, I–4.79–81 rights, I–9.09 shale gas, I–9.09–10 terms, I–4.79, I–9.10 petroleum licences see licences; licensing regime; specific licences Petroleum Operation Notices (PONs), I–11.15, I–11.40, I–11.42 petroleum revenue tax (PRT) asset trading, II–9.60 capital allowances, I–7.33 decommissioning relief, I–7.47, I–7.50, I–13.37

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levy, I–7.05 new fields and, I–7.10 payments, I–7.04 rate changes, I–3.45, I–7.09, I–7.13, I–7.53–4 removal, I–7.62 petroleum sales agreements collateral support, II–8.52–3 crude oil see crude oil sales agreements drafting, II–8.55–6 freedom of contract, II–8.02 gas/LNG see gas/LNG sales agreements implied terms, II–8.02 overview, II–8.01–56 practice, II–8.54 PILOT Brownfields Initiative, I–12.81, I–A.35–51 Brownfields Studies Report, I–A.37–40 Brownfields Work Group, I–A.35, I–A.40 Fallow Areas Initiative, I–A.7–34 initiatives, I–A.5–6 PPWG, I–4.52, I–A.7, I–A.8, I–A.9, I–A.11, I–A.16 predecessor, II–5.16 pipelines see also infrastructure; transport; transport agreements abandonment, II–13.14, II–13.18 ageing pipelines, II–7.25 agreements, II–7.24 basic agreements, II–7.55–8 capacity see infrastructure access chemicals, I–11.40 crossing agreements, II–7.42–7 standard contracts, II–5.14, II–7.43 EU law, I–6.66 land law and see land law leasehold rights, II–13.12, II–13.29 meaning, I–6.22–3 Norway, I–3.13 overview, II–7.22–6 owners’ consent, II–13.03 ownership, II–13.10–11 Pipeline Work Authorisations, I–11.79 proximity agreements, II–7.42–7 standard contracts, II–5.14, II–7.43 real rights, II–13.04, II–13.07 regulator, I–9.16 replacement, II–13.18 section 29 notices, I–12.59 servitudes see servitudes

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smaller pipelines, II–7.23 statistics, I–12.02 statutory regulation, II–13.09 transparency of terms, II–7.22 trespass, II–13.03 UK-Norway Agreement, II–3.63 Piper 25 Conference (2013), I–10.92 Piper Alpha disaster (1988) see also Cullen Report casualties, I–9.16 catastrophic scale, II–4.138 effect on production, I–3.09 health and safety and, I–10.31–9, I–11.94 infrastructure and, I–10.57 legal response, I–9.16 London Bridge, II–6.41–2, II–6.45, II–6.50, II–6.79, II–6.80 negligence, II–6.38–9 Orbit Valve, II–6.38–9, II–6.45 overview, I–10.31–9 prescriptive approach and, I–11.94 Piper field, I–10.16n planning appeals, I–9.45–6 applications fracking, I–9.35, I–9.55, I–9.58–61, I–9.90–110 material considerations, I–9.56–69 process, I–9.47–56 public concern, I–9.70–82 statutory consultees, I–9.53 conditions, I–9.43 development control, I–9.36–42 England appeals, I–9.45 legislation, I–9.33 local plans, I–9.42 National Planning Policy Framework, I–9.42, I–9.57 fracking and, I–3.53, I–9.35, I–9.55, I–9.58–61, I–9.90–110 local development plans, I–9.31, I–9.41–2, I–9.49 onshore wells and, I–9.13, I–9.25, I–9.29–110 politics and law, I–9.83–110 Scotland appeals, I–9.46 considerations, I–9.56 legislation, I–9.34 local development plans, I–9.41 terminology, I–9.29 UK development, I–9.30–1

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pledges, II–10.65, II–10.69n, II–10.85n, II–13.08 political risks, II–10.08 polluter pays principle, I–12.15, I–12.37, II–2.94 pollution see oil pollution portfolio management, II–9.02 posted workers, II–14.36, II–14.42 precautionary principle, I–11.15, I–12.15, I–12.22, I–12.37 pre-emption rights affiliate route and, II–9.48–54 assignment and, II–9.21, II–9.27, II–9.37–56 JOAs, II–2.13, II–9.11, II–9.43–54 leases, II–13.13 Master Deed, II–9.43–5 package deals, II–9.47 unmatchable deals, II–9.46 waivers, II–9.66 Preese Hall incident, I–9.02, I–9.–05 prepayment facilities, II–10.20 Preston New Road Action Group, I–9.92, I–9.99 price-fixing, I–6.68, II–11.11, II–11.15, II–11.58 prices see also consideration gas/LNG sales agreements, II–8.42–8 oil see oil prices private equity, II–9.02, II–9.30, II–10.09, II–10.12, II–10.14, II–10.121 privatisations, I–5.05 produced water, I–11.02, I–11.34–7, I–11.100 production competition law, relevant market, II–11.27 decline, I–2.06, I–2.08, I–5.07, II–12.01 definition, II–11.48 efficiency, I–2.09–10, I–5.18, I–5.22 environmental regulation, I–11.16–21, I–11.30–3 chemicals, I–11.38–42 future estimates, II–11.67 landward areas, I–4.81 licences see production licences maturity, I–5.07 modelling see economic modelling onshore, I–9.01 overlifting, II–9.62 projections, I–2.07–10 recent experience, I–2.05–10 statistics, I–7.23

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tax incentives and new field developments, I–2.22–40 UK as energy producer, I–3.43–53 UK exports, I–3.09–10 UK ranking, II–11.64 underlifting, II–9.62 unit costs, I–2.04 production licences adjustments, I–5.01 air pollution and, I–11.62–4 area rental payments, I–4.45 bespoke licences, I–4.03, I–4.74 blocks, II–3.02 categories, I–4.03 contractual character, I–4.05, I–4.82 early licences, I–A.7 exclusivity, I–4.05, I–6.03 frontier licences see frontier licences geological surveys and, I–11.13 information rights, I–4.60 interventions, I–4.59–60 JOAs and, II–2.06, II–2.09 model clauses, I–4.17, I–4.56, I–5.01, I–A.9 numbers, I–4.68 operational control, I–4.59–60 overview, I–4.41–68 promote licences see promote licences proprietary rights, I–4.04 revocation, II–10.99 seaward licences, I–4.41–68 standard licences, I–4.43–60 terms and relinquishments, I–4.52–8 traditional licences, I–4.43–60 unitisation see unitisation work programmes, I–4.47–51 products, definition, II–11.48 project finance, II–10.23–4 project management drilling contracts, II–4.21 project/field life cover ratio (PCLR/ FLCR), II–10.57 promote licences annual rental fees, I–4.71 applications, I–4.72 concessions, I–4.73 consultation, I–4.69 flexibility, I–4.86 introduction, I–4.69 overview, I–4.69–73 terms, I–4.70 Wood Review and, I–5.15 work programmes, I–4.70 property, definition, II–6.54, II–6.61

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proximity agreements, II–5.14, II–7.42–7 PRT see petroleum revenue tax public concern, planning and, I–9.70–82 public policy ADR and, II–15.43 energy see energy security light-touch regulation, I–5.06, I–5.11 replacement, II–1.01 pre-Wood philosophy, I–5.05–6 pumping stations, II–13.12, II–13.23, II–13.27 Qatar, I–3.13, I–3.55 Quadrant 22, I–4.18 qualified indemnities, II–6.23–5 qualifying combustion installations (QCIs), I–11.58–9 quantified risk assessments (QRAs), I–10.35, I–10.38, I–10.53 radioactivity, II–5.54 railway lines, II–13.11 RBL facilities, II–10.06, II–10.09, II–10.14, II–10.22, II–10.23, II–10.35–7, II–10.40, II–10.45–6, II–10.50–3, II–10.78–9, II–10.81, II–10.121 real burdens, II–13.30 real rights categories, II–13.06 chain of rights, II–13.07 enforceability, II–13.05 finance and, II–13.08 leases see leases overview, II–13.06–9 ownership, II–13.06, II–13.10–11 pipelines, II–13.04 servitudes see servitudes reciprocal indemnities see mutual indemnities redundancy, II–14.02, II–14.40 refineries, II–13.10, II–13.12, II–13.22, II–13.23 regional development strategy, I–5.19–20 renewable energy Crown ownership and, I–12.82 EU Law, I–3.30 Scottish policy, I–9.121 UK, I–3.63, I–3.73 reputation equity, II–15.18 res nullius, I–4.09 research and development agreements, II–11.17, II–11.64 encouragement, I–3.51, I–4.36, I–A.14

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reserves borrowing base mechanism, II–10.54–60 RBL facilities and, II–10.35–6 recoverable reserves, I–2.21, I–A.47, II–2.92, II–3.23, II–3.25 warranties, II–9.72 reservoirs UK-Norway Framework Treaty (2005), II–3.63 warranties, II–9.72 Reynolds, T, II–3.51 Ridley, Nicholas, I–10.13 rig-sharing, II–11.35 ring fence corporation tax (RFCT) capital allowances, I–3.44, I–7.28–33 corporation tax and, I–7.07 decommissioning relief, I–7.47, I–13.37 levy, I–7.05 new field developments, I–2.22 rate, I–7.07 technical features, I–7.28–40 Ring Fence Expenditure Supplement (RFES), I–2.22, I–7.31, I–7.62 risk allocation contractual methods, II–6.02 indemnities see indemnities LOGIC standard contracts, II–5.40–55 oil and gas contracts, II–6.01–86 supply chain agreements, II–5.12, II–5.40–55 exceptions, II–5.46–55 risk assessments chemicals, I–11.38 drilling, I–9.14 EU law, I–10.62, I–11.95 goal-setting regulations, I–10.43 Monte Carlo technique, I–2.11 night work, II–14.57 offshore installations, I–10.53 OSPAR, I–11.36 quantified risk assessments, I–10.35, I–10.38, I–10.53 safety case, I–10.66, I–10.71 well integrity, I–9.20 Robens Report (1972), I–10.18–22, I–10.24, I–10.30, I–10.33 Robinson, J Rowan, I–11.06 Rockall, I–8.13–33 Roggenkamp, M, II–3.57 Roman law, II–13.21 Rough platform, I–3.58 Royal Academy of Engineering, I–9.02 Royal Society, I–9.02

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Royal Town Planing Institute, I–9.60, I–9.83 royalties, I–4.33, I–7.27, II–9.25, II–10.19, II–12.14 Rudd, Amber, I–3.01, I–3.02, I–5.50 rule of capture, II–3.04, II–3.05, II–3.07, II–3.10 Russia annexation of Crimea, II–9.35 Energy Charter and, I–3.23–4, I–3.68 EU energy dependence on, I–3.74 gas production, II–11.64 oil price and, I–1.08 Yukos arbitration, I–3.23 safeguard allowance, I–7.09 safety and environmental management systems, I–10.66, I–10.73 safety case see health and safety offshore safety management systems, I–10.34, I–10.37, I–10.41, I–10.58, I–10.66 sale of goods implied terms, II–8.02, II–8.08, II–8.12 international law, II–8.02 passing of title, II–8.30 sales agreements see crude oil sales agreements; gas/LNG sales agreements salvage principle, II–10.104–5 São Tomé and Príncipe, I–3.56 Sasine Register, II–13.15 sceptic tanks, II–13.22 Scilly Isles, I–8.12 Scotland civil procedure, II–15.44, II–15.75–6 devolution see Scottish devolution energy policy, I–9.119–22 independent kingdom, I–9.112 irritancy, II–10.98 land law see land law liquidation, II–10.110, II–10.114–15 mixed jurisdiction, II–13.02, II–13.21 National Marine Plan, I–4.30 planning appeals, I–9.46 considerations, I–9.56 fracking case, I–9.101–8 legislation, I–9.34 local development plans, I–9.41 property law, I–9.08, II–10.88 real burdens, II–13.30 securities, II–10.69 over shares, II–10.88 standard securities, II–10.89

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Scott, R, I–3.16, I–3.17, I–3.20 Scottish Constitutional Convention, I–9.112, I–9.117 Scottish devolution 1997 referendum, I–9.112 2014 independence referendum, I–1.04, I–5.29n, I–9.114–16 energy competence, I–9.117 energy policy, I–9.119–22 fracking moratorium, I–9.108, I–9.120–2, I–9.126, I–9.128 further devolution, I–9.116, I–9.123–6 history, I–9.112 licensing regime and, I–9.125–6 overview, I–9.111–26 recent developments, I–1.04 settlement, I–9.113 Smith Commission, I–9.116, I–9.123, I–9.125, I–9.126 Scottish Environmental Protection Agency (SEPA), I–9.25, I–9.53, I–10.61, I–11.19 Scottish Home Rule Association, I–9.112 Scottish Natural Heritage (SNH), I–9.53, I–11.19 Scottish Sentencing Council, I–10.83 Scottish Water, I–9.53 sea, law of the sea see law of the sea sea deposits, I–11.49, I–11.72 Sea Gem Inquiry, I–10.06–11, I–10.12, I–10.13, I–10.16, I–10.19, I–10.23–5, I–10.32, I–10.35–6, I–10.38 seasonal workers, II–14.30 seaward licences area rental payments, I–4.45–7 bespoke licences, I–4.03, I–4.74 categories, I–4.03 exploration licences see exploration licences frontier licences see frontier licences information requirements, I–4.60 innovate licences see innovate licences legal nature, I–4.04, I–4.09 model clauses, I–4.17, I–5.01, I–A.9 operational control, I–4.59–60 overview, I–4.39–42 production licences see production licences promote licences see promote licences revocation, II–9.36, II–10.99, II–10.120 work programmes and, I–4.51 terms and relinquishments, I–4.52–8 work programmes, I–4.47–51 second lien debts, II–10.08, II–10.09

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section 29 notices see also decommissioning plans asset sale and purchase agreements and, II–9.77 facility information requests, I–12.59 Guidance Notes, I–12.59–61 initiation, I–12.42 ministerial powers, I–12.42, I–13.04 penalties, I–12.45 recall, I–12.45, I–12.60 scope, I–13.09 service, I–12.43–5, I–13.04, I–13.08 warning letters, I–12.59 withdrawal, I–12.45, I–12.60, I–13.05 securities decommissioning see decommissioning security agreements documents, II–10.50 foreign assets, II–10.92 forms, II–10.65 over accounts, II–10.49, II–10.82–4 over collateral arrangements, II–10.90–1 over contractual rights, II–10.76–80 over insurance, II–10.76, II–10.81 over licences, II–10.70–5 over real estate, II–10.89 over shares, II–10.85–8 overview, II–10.65–92 registration, II–10.68, II–10.90 securitisation, II–13.08 seismic events, I–9.02 seismic imaging technology, II–12.03 self-employed categories, II–14.26–7 employment status, II–14.03 workers or, II–14.23–30 working time rights, II–14.46 semi-sunmersible drilling units, II–4.25, II–4.26, II–4.35–40, II–4.112–13, II–5.22 send or pay clauses, II–7.80–3 Senior Executive Appraisal Mediation (SEAM), II–15.56 sentencing guidelines, corporate manslaughter, I–10.83, I–10.84 service contracts, II–5.05–8 servitudes access, II–13.23, II–13.29 conditions, II–13.24 discharge, II–13.20 dominant tenements pipelines, II–13.24–30 principles, II–13.23 form of deeds, II–13.15

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leasehold servitudes, II–13.01, II–13.23 owners’ exclusion, II–13.22 personal servitudes, II–13.31 pipelines, II–13.07, II–13.14–31 benefits, II–13.16–20 dominant tenements, II–13.24–30 identification of land, II–13.25 indemnities, II–13.14, II–13.24 limitations, II–13.21, II–13.26 negative restraints, II–13.30 terms, II–13.14 third parties, II–13.28 praedial servitudes, II–13.06, II–13.31 praedial utility, II–13.27 real rights, II–13.06, II–13.31 registration, II–13.25 Roman origins, II–13.21 storage, II–13.22 utilitas, II–13.27 variation, II–13.20 vicinity requirement, II–13.27 sewage definition, I–11.66 offshore regulation, I–11.65–9 Sewel Convention, I–9.113 shale gas/fracking development, I–9.127–8 energy policy, I–3.53 environmental impact, I–9.25–8 guidelines, I–9.12, I–9.22 health and safety, I–9.15–24 moratorium, I–9.02, I–9.108, I–9.120–2, I–9.126 onshore exploration, I–9.02 PEDLs, I–9.09–10 planning and, I–3.53, I–9.35, I–9.55, I–9.58–61, I–9.90–110 potential, I–3.52 Preese Hall incident, I–9.02, I–9.05 revolution, I–4.81 safety, I–9.15–28 Scottish policy, I–9.108, I–9.120–2, I–9.128 Task Force on Shale Gas, I–9.03 UK developments, I–9.01–5 US exports to UK, I–3.56 shallow drilling, I–11.13–15, I–11.72 share fishermen, II–2.21 shares equitable mortgages, II–10.69, II–10.85 issues, II–10.09, II–10.10 securities over, II–10.85–8 English companies, II–10.85–6 pledges, II–13.08

EU42448.indb 562

Scottish companies, II–10.88 transfer asset purchase or, II–9.10–18 consideration, II–9.65 CVAs, II–10.120 due diligence, II–9.16 liabilities, II–9.17 licensing regulation and, II–9.34–5 taxation, II–9.18, II–9.86 warranties, II–9.74 Sharp, D, II–6.18 Shell asset trading, I–7.58 on boundary agreements, I–8.06 Brent field, I–12.01 Brent Spar see Brent Spar Clair field, II–3.15 smaller assets, II–2.55 SPAs, II–08.06 Stakeholder Dialogue, I–12.06, I–12.27–35, I–12.36, II–15.07n sheriff court procedure, II–15.75 shift work, II–14.53–5 shipping air pollution, I–11.51–7 industry, II–6.04 oil pollution, I–11.82–5 sewage and garbage, I–11.65–72 shut-in rights, II–7.84–8 sidetracks, II–4.107 Sierra Leone, I–3.56 small field allowance, I–7.37 small fields, I–2.32–3, I–2.52, I–4.81, I–6.05, I–6.10, I–6.90, I–6.103, II–7.01–2, II–7.78 Smith, John, I–A.28n Smith Commission, I–9.116, I–9.123, I–9.125, I–9.126 software copyright, II–12.23–5 track participation, II–3.39 sole risk clauses, II–2.50–3, II–3.43, II–9.71 South Africa, servitudes, II–13.23 sovereign wealth funds, II–10.09 Soviet Union, I–3.22, I–3.68 special areas of conservation (SACs), I–11.09 special protection areas (SPAs), I–11.09, I–13.29 specialisation agreements, II–11.17, II–11.48 Stakeholder Dialogue, I–12.06, I–12.27–35, I–12.36, II–15.07n

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stakeholders, II–15.17–18 stamp duty, II–9.86 stamp duty land tax, II–9.86 Standard and Poors, II–2.96 standard contracts AIPN see Association of International Petroleum Negotiators automation, II–5.84 benefits, II–5.21 Canada, II–5.74 contents, II–5.12 contractual structure, II–5.04–11 CRINE, II–5.15, II–11.35, II–12.51 field agreements, II–5.14 form, II–5.28–33 guidance notes, II–5.34–5 IADC, II–5.73 key provisions, II–5.40–55 LOGIC see LOGIC standard contracts mistakes, II–5.25 mutual hold harmless indemnities, II–5.41–55, II–5.61–3 new contracts, II–5.82–3 Norway, II–5.70–2 OGA, II–5.13–14, II–5.20 overview, II–5.012–17 rationale, II–5.01–3, II–5.18–25 risk allocation, II–5.12 supply chain agreements, II–5.11–13 tendering process, II–5.36–9 United States, II–5.73 updating, II–5.25 variations clauses, II–5.64 standard production licences see production licences standard securities, II–10.89 Statfjord Agreement, II–3.59, II–3.62, II–3.63 Statfjord B Platform, I–11.02 statutory adjudication, II–15.62–4 statutory wayleaves, II–13.31 Steele-Nicholson, A, II–3.37 step-in agreements, II–10.24 stewardship assessment, I–A.49–51 asset stewardship strategy, I–5.06, I–5.09n, I–5.18, I–5.66–70 asset transfer and, I–A.38 benchmarking, I–5.68 Brownfields Initiative, I–5.06, I–12.81, I–A.35–51 Brownfields Studies Report, I–A.37–40 collaboration, I–5.52–3 concept, I–A.39

EU42448.indb 563

expectations, I–5.67 MER Strategy, I–5.42, I–5.63, I–5.66–70, I–6.54 ministerial powers, I–A.41–2 model clauses, I–A.47 OGA Asset Stewardship Expectations, II–5.78, II–12.64 pre-Wood state control, I–5.06 process, I–A.41–8 reviews, I–5.70 sanctions, I–A.48 stages, I–A.44 Stewardship Initiative, I–5.06, I–12.81, I–A.35–51 UKCS Stewardship Survey, I–5.68 Wood Review and, I–5.18 STOOIP (stock tank oil originally in place), II–3.23–6 storage carbon capture and storage, I–3.12, I–5.22, I–12.45 FPSO units, II–7.19 gas, I–3.57–9 servitudes, II–13.22 strategic environmental assessments, I–4.24, I–4.27 Stratfjord B Platform, I–11.02 streaming, II–10.21–2 strict liability, I–11.103, I–11.107, I–12.79, II–4.144 study agreements allocation of costs, II–7.36 scope, II–7.34 site to shore transport, II–7.09 standard contracts, II–5.14, II–7.33 timelines, II–7.35 transport agreements, II–7.33–7 subordinated loans, II–10.09, II–10.76 summary trials, II–15.76 supplementary charge capital allowances, I–7.33 cluster area allowances (CAAs), I–7.40 decommissioning relief, I–7.47, I–13.37 energy production policy, I–3.44 field allowance, I–7.34, I–7.37 investment allowances, I–7.34–40, I–7.62 levy, I–7.05, I–7.08 new field developments, I–2.22, I–2.24, I–2.28, I–2.30 rate changes, I–7.08, I–7.50 rationale, I–7.11 supplementary seismic survey licences, I–4.03

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supply chain, meaning, II–5.05 supply chain agreements allocation of risk, II–5.43 contents, II–5.12 contractual structure, II–5.05 function, II–5.04 mutual hold harmless indemnities, II–5.40–55 parties, II–5.11 risk allocation, II–5.12, II–5.40–55 standard contracts, II–5.11–13, II–5.18–25 trend, II–5.09 Supply Chain Strategy, II–5.01, II–5.18, II–5.78–81 Supply Chain Taskforce, II–5.79–80 sustainable development, I–12.57 swap agreements, II–2.90 Sweden, North Sea continental shelf boundaries, I–8.08 syndicated loans, II–10.37–8 syndication risk, II–10.08 takeovers and mergers asset purchase or, II–9.10–18 competition and, II–11.11, II–11.27, II–11.49, II–11.51 consideration, II–9.65 CVAs, II–10.120 due diligence, II–9.16 liabilities, II–9.17 licensing regulation and, II–9.34–5 taxation, II–9.18, II–9.86 warranties, II–9.74 Task Force (1999), I–2.08 Task Force on Shale Gas, I–9.03 Taverne, B, II–3.30, II–3.45, II–3.62 taxation see also specific taxes alternative regimes, I–7.19 asset transfers, II–9.18, II–9.86 capital allowances, I–3.44, I–7.28–33, I–7.62 cash flow regime, I–7.04 categories, I–7.05 cross-border agreements and, UK/ Netherlands, II–3.56 decommissioning and, I–7.45–54, I–13.02, I–13.34–8, II–9.78 energy production policy, I–3.44–5 evaluation, I–7.62–4 exploration and, I–7.41–2 field allowances, I–3.47, I–7.12, I–7.34, I–7.37

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Fiscal Review, I–1.03 gas/LNG sales agreements, II–8.51 infrastructure, I–7.55–7 investment and, I–9.126 new driving investment blueprint, I–7.24–7, I–7.33 joint ventures, II–2.02 LOGIC standard contracts and, II–5.67 losses, I–7.43–8 loss relief, I–7.09, I–7.43–4 mature assets trading, I–7.58–61 neutral system, I–7.14 new field developments and, I–2.22–40 oil allowance, I–7.09 oil revenues, I–4.34 overview, I–7.01–64 payments, I–7.04 principles of good oil and gas practice, I–7.20–3 recent changes, I–2.53, I–7.06–14 safeguard allowance, I–7.09 share purchase, II–9.18 specific hydrocarbon regime, I–7.15–19 strict concession regime, I–7.18, I–7.27 territorial scope, II–14.37 Wood Review, I–3.45, I–5.08, I–7.01 Taylor, M, II–3.32, II–3.37, II–3.46 technology intellectual property see intellectual property MER Strategy, I–5.42 Oil and Gas Technology Centre, II–12.63 Wood Review, I–5.22, II–12.62 Technology and Construction Court, II–15.77 technology transfer agreements, block exemption, II–11.64, II–12.27 tenders drilling contracts, II–4.49–50 LOGIC standard contracts, II–5.36–9 Thatcher, Margaret, I–5.05 title see also passing of title intellectual property contracts, II–12.52–9 investigation by asset purchasers, II–9.24 insolvency cases, II–10.117–18 warranties, II–9.71 Tormore field, I–3.47, I–3.48 torts agents, II–2.38 compensatory damages, II–6.30

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fault, II–6.30 negligence, II–2.28, II–2.33, II–6.24, II–6.38–45 wilful misconduct, II–2.28–33, II–5.61, II–6.24 Total, I–10.84 track participation, II–3.19–34 trade associations, II–11.11, II–11.12, II–11.55 trade secrets, II–12.26–32 trade unions, I–9.39, I–10.27, I–10.39, I–10.47, II–14.19, II–14.87 traditional production licences see production licences training materials, II–12.20 transfer of undertakings, II–10.117, II–14.02 transport agreements see transport agreements arrangements, II–7.04, II–7.06–16 FPSO units, II–7.18–21 hub-based structure, II–7.02, II–7.04 multi-field arrangements, II–7.02 offtake options, II–7.17 overview, II–7.01–116 pipelines see pipelines site to sale, II–7.06, II–7.12–16 site to shore, II–7.06, II–7.08–11 transport agreements basic agreements, II–7.55–8 capacity booking, II–7.66–70 collective capacity, II–7.100–3 competition issues, II–7.65, II–11.46–54 confidentiality agreements, II–7.29–32 construction and tie-in agreements, II–7.48–53 cost switch, II–7.77–9 cost-sharing agreements, II–7.38–40 crossing agreements, II–5.14, II–7.42–7 decommmisioning, II–7.110–13 end dates, II–7.89–91 form, II–7.27–106 governing law, II–7.05 indemnities, II–7.94, II–7.97–9 crossing and proximity agreements, II–7.43–5 CTIAs, II–7.51–2 CULAs, II–7.97, II–7.106, II–7.107–9 liability caps, II–7.43 new entrants, II–7.106 initial assessments, II–7.28 joint supply/purchase of capacity, II–11.46–54 negotiation issues, II–7.64–106

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new entrants, II–7.104–6 novation, II–9.84 pipelines, II–7.24 pre-development stage, II–7.41–53 production stage, II–7.54–63 proximity agreements, II–5.14, II–7.42–7 send or pay clauses, II–7.80–3 shut-in rights, II–7.84–8 specification, II–7.92–6 study agreements, II–7.33–7 tariffs, II–7.71–6 transport, processing and operations services agreements, II–7.60, II–7.62–3 transport and processing agreements, II–7.59–61 Transport Scotland, I–9.53 trespass, II–13.03 Trinidad and Tobago, I–3.55 trust funds, I–7.45, I–12.81, I–13.18, I–13.21–2, I–13.24–5, I–13.31, I–13.38, II–2.95–6 turnkey drilling contracts, II–4.17–20 Tuscan Energy, II–2.56 tying, II–11.20, II–11.56 UK Hydrographic Office, I–12.74, I–12.78 UK Onshore Operators Group (UKOGG), shale gas wells guidance, I–9.22–3 UKAPP Certificates, I–11.53 UKCS boundaries see continental shelf boundaries decline, II–12.01 diversity, I–1.01–2 expensive area, II–12.02 exploration see exploration grid system, I–4.18–19 hostile environment, I–10.01 installation numbers, I–12.02 legal ownership, I–4.09 macro-conditions, II–01–2 maturity, I–1.01, I–2.01–4, I–2.05, I–5.07, I–7.58–61, I–10.02, I–10.51, II–1.01, II–5.01 production see production recent experience, I–2.05–10 UK-Nigeria Energy Working Group, I–3.56 UKOOA ICoP see Infrastructure Code of Practice (ICoP) infrastructure access and, I–6.73

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model JOAs, II–2.03 standard contracts, II–5.13 ullage, I–7.55 Ultramar Exploration, II–3.53 unbundling, I–6.72, I–6.89 UNCITRAL, II–15.66 UNCLOS continental shelf boundaries, I–8.15–33 decommissioning and, I–12.08–10, I–12.40, I–12.82 sovereignty, I–12.82 unitisation and, II–3.51 unfair contract terms, II–6.05, II–6.28–9, II–6.84 unfair dismissal dismissal at third party requests, II–14.83–93 employment status and, II–14.02, II–14.10 territorial jurisdiction, II–14.33–43 unfair preferences, II–2.57, II–2.83–91 Uniform Network Code, II–8.30 unit costs, I–2.04 United Nations Gulf War (1991) and, I–3.20 UNCITRAL, II–15.66 UNCLOS see UNCLOS Vienna Convention, II–8.02 United States ADR, II–15.45 mediation, II–15.46, II–15.54, II–15.73, II–15.79 collaboration with stakeholders, II–15.18 dispute resolution, II–15.23, II–15.25 export control, II–4.69 indemnities, II–6.28 JOAs, II–2.02 fiduciary duties, II–2.43 model forms, II–2.03, II–2.04, II–2.27 Macondo disaster see Deepwater Horizon disaster oil imports, I–3.15 pendulum procedure, II–3.37 rule of capture, II–3.04 shale gas, I–3.52, I–3.56, I–4.81, I–9.02 standard contracts, II–5.73 unitisation agreements, II–3.17, II–3.27 unitisation alternatives, II–07–9 case for, II–04–5 common issues, II–3.19–46 cross-border unitisation, II–3.47–65 UK/Netherlands, II–3.52–7, II–3.64–5

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UK/Norway, II–3.58–65 cross-licence agreements, II–3.09 fixed interest agreements, II–3.09 geological factors, II–01–3 international law, II–3.47–65 legislation, II–3.10–11 meaning, II–05 MER Strategy and, II–3.11 ministerial powers, II–3.12 MOOIP, II–3.23, II–3.26 overview, II–3.01–67 practice, II–3.13–18 pre-unitisation agreements, II–3.17 rule of capture, II–3.04, II–3.05, II–3.07, II–3.10 STOOIP, II–3.23–6 track participation computer programs, II–3.39 determination, 44, II–3, II–3.21–7 expert dispute resolution, II–3.35–40 re-determination, II–3.28–34 UUOAs see unitisation and unit operating agreements unitisation and unit operating agreements (UUOAs) clauses, II–3.17 competition law issues, II–11.34 cross-border agreements, II–3.49–65 dispute resolution, II–3.52, II–3.55, II–3.64 Frigg Agreement, II–3.59–61, II–3.62, II–3.63 governing law, II–3.54 Markham Agreement, II–3.53–7 Murchison Agreement, II–3.59 Statfjord Agreement, II–3.59, II–3.62, II–3.63 decision-making, II–3.44 default and forfeiture, II–3.45–6 dispute resolution, II–3.35–40 cross-border agreements, II–3.52, II–3.55, II–3.64 JOAs and, II–3.17–18, II–3.46 non-unit operations and, II–3.41–2 OGA approval, II–3.14 operators, II–3.17 overview, II–3.16–17 pre-emption rights, II–9.37 pre-unitisation agreements, II–3.17 purpose, II–06 sole risk operations, II–3.43 tract participation, II–3.19–34 unit operating committees, II–3.17 voting rights, II–3.44

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value allowances, I–7.39 vendor finance, II–10.29–32 Venezuela, I–1.08 Verma, Baroness, I–5.29, I–5.30, I–5.31 vertical agreements, II–11.29, II–11.56–67 Vision for 2010, I–A.5, I–A.35, I–A.37 volatile organic compounds, I–11.56, I–11.64 volcanic ash, II–4.132 warranties asset transfer agreements, II–9.70–4 gas/LNG sales agreements, II–8.51 LOGIC standard contracts, II–5.60 reserves, II–9.72 share sale agreements, II–9.74 time limits, II–9.73 title, II–9.71 waste see also decommissioning categories, I–12.11 London Dumping Convention, I–12.11–12 offshore regulation, I–11.65–72 water see also law of the sea; oil pollution drinking water, I–10.42 fracking and groundwater, I–9.27, I–9.61 pipes, II–13.22 produced water, I–11.02, I–11.34–7, I–11.100 wayleaves, II–13.31 Weaver, J, II–3.61 well services catastrophic loss, II–5.49 corrosion by well effluent, II–5.48 downhole equipment, II–5.47 LOGIC standard contracts, indemnities, II–5.46–51 pollution, II–5.50 property lost overboard, II–5.51 wells definition, II–4.71–6, II–4.107 services see well services sidetracks, II–4.107 West of Shetland Task Force, I–3.46 whistle-blowing, II–11.03 Wicks Report, 1–3.10, I–3.05, I–3.24, I–3.39, I–3.54 Wiggins, D, II–3.05 wilful misconduct, II–2.28–33, II–5.61, II–6.24 Willoughby, G, I–4.04

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withering interest forfeiture clauses, II–2.63, II–2.65 Wood Mackenzie, II–11.67 Wood Review asset stewardship, I–5.18 asset trading, I–7.58 collaboration, I–2.54, I–5.23, I–5.46, II–04.01 criticisms, I–5.08 decommissioning, I–5.23, I–12.03 effect, I–5.71–2 enhanced regulatory powers, I–5.12–13 exploration strategy, I–5.15–17 final report, I–5.08 on FPSO units, II–7.20 government response, I–3.45–6, I–5.24 health and safety, I–10.63 implementation, I–4.83, I–5.25–72 MER Strategy, I–4.83, I–5.25, I–5.28–70 OGA creation, I–5.27 sector strategies, I–5.63–70 infrastructure strategy, I–2.54, I–5.21 interim report, I–5.08 licensing regime, I–4.01, I–4.17, I–4.79, I–4.82–3 retrospective amendment of licences, I–5.13 on LOGIC, II–5.16 Mature Province Initiatives and, I–A.1 MER Strategy asset stewardship, I–5.18 implementation, I–4.83, I–5.25, I–5.28–70 legacy, II–1.01 licensing and, I–4.79 OGA powers, I–4.51 regulatory powers, I–5.12–13 technology and, II–12.04 tripartite approach, I–5.09 new regulator, I–4.51, I–5.10–11, I–5.19, I–5.27, I–11.100 objectives, I–4.86 origins, I–5.07, I–10.63 overview, I–5.07–72 pre-Wood philosophy, I–5.05–6 production diagnosis, I–2.08 radical change, I–5.02, I–5.24, II–04.01 reception, I–5.24 recommendations, I–5.09–23 regional development strategy, I–5.19–20 sector strategies, I–5.14–23, I–5.63–70 significance, I–1.03

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taxation, I–3.45, I–5.08, I–7.01 technology strategy, I–5.22, II–12.62 tripartite approach, I–5.09 Woolf reforms, II–15.43 Woolfson, C, I–10.47 work programmes appropriate programmes, I–4.51 competing applications, I–4.38, I–4.50 delivering, I–4.50 drill or drop, I–4.49 firm commitments, I–4.49 initial programmes, I–4.47–8 meaning, I–4.47 non-compliance, I–4.49 OGA requests for, I–4.51 seaward licences, I–4.47–51 terms, I–4.49 workers definition, II–14.03, II–14.19–30 dependence, II–14.25 mutual obligations, II–14.28–30 self-employed workers, II–14.03 statutory definitions, II–14.19–20 working time amending regulation, II–14.81–2 annual leave, II–14.62–4 application to offshore work exclusions, II–14.66 overview, II–14.44–82 average working time, II–14.47–9 breach of contract, II–14.68, II–14.72 case law, II–14.73–80 collective agreements, II–14.67

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contracting out, II–14.65 covered workers, II–14.46 daily rest, II–14.50, II–14.66 definition, II–14.49, II–14.73 employment tribunal claims, II–14.68, II–14.71 enforcement, II–14.68–72 EU law, II–14.44–5, II–14.81–2 exclusions, II–14.65–7 health and safety and, II–14.74, II–14.80 holiday pay, II–14.23, II–14.63–4 H&SE enforcement, II–14.68–70 night work, II–14.56–9, II–14.66 on-call time, II–14.74–80, II–14.81 patterns of work, II–14.60 purposive interpretation, II–14.80 record-keeping, II–14.61 rest breaks, II–14.52, II–14.66, II–14.78–9, II–14.80 shift work, II–14.53–5 weekly rest, II–14.51, II–14.66 worksites, definition, II–4.68–70 World Bank, II–15.09, II–15.48 World Trade Organization (WTO), II–15.48 Worthington, P, II–3.37 wrongful trading, II–10.116 Wytch Farm field, I–4.81, I–9.01 Yergin, D, I–5.24 zero-hour contracts, II–14.81

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