Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023) 9819972884, 9789819972883

Table of contents :
Contents
Part I Macro Trends
1 Global Energy Outlook in the Context of Russia-Ukraine Conflict
The Impact of the Russia-Ukraine Conflict on the Global Political and Economic Landscape
Global Political Landscape
Global Economic Landscape
The Impact of the Russia-Ukraine Conflict on the Global Energy Development
Direct Impact on the Global Oil and Gas Market
Impact on Energy Structure and Energy Transition
Conclusion
Bibliography
2 China’s Carbon Emission Peak Goals, Strategies and Policies
China’s Goals for Carbon Emission Peak
China’s Strategies for Carbon Emission Peak
Spatial Concentration of Carbon Emissions at the National Level
Spatial Concentration of Carbon Emissions at the Provincial Level
Policy Suggestions for Achieving Peak Carbon Emissions in China
Integrate Different Measures to Promote Smooth Emission Reduction in High-Emission Industries
Reduce Carbon Emissions in High-Emission Areas Based on Spatial Characteristics Properly
Bibliography
3 Carbon Market Outlook in the Context of Global Carbon Neutrality
Development Background of Global Carbon Neutrality
The Current Situation of International Carbon Market Development
EU Carbon Market Prices Rise Steadily
Transactions in Other International Carbon Markets
International Voluntary Emission Reduction Trading
Current Development of International Carbon Tariff
The Current Situation of China’s Carbon Market Development
Introduction of Local Pilot Carbon Market
Introduction to China’s National Carbon Market
Introduction to China Certified Emission Reduction (CCER)
Suggestions for the Development of China’s Carbon Market
Suggestion to Include More Types of Trading Entities to Increase Market Liquidity
Suggestion to Increase Trading Varieties and Enrich the Means of Carbon Asset Management
Strengthen Data Quality Management and Establish a Scientific Accounting System
Clarify Carbon Trading Invoicing System and Regulate Carbon Market’s Tax Requirements
Bibliography
Part II Petroleum
4 New Features of the Global Oil Market in the Context of High Oil Prices
Comparison of Three Oil Price Highs in History
2008: Oil Prices Soared to a Peak of $146/Barrel
2011–2014: Oil Prices Remained High Above $100/Barrel for 3.5 Years
Late February to July 2022: Russia-Ukraine Conflict Pushed Oil Prices Quickly up to the $100/Barrel Mark
Comparison of Three Oil Price Highs
New Features of the Global Oil Market Under the Current High Oil Price
High Oil Prices: Russia-Ukraine Conflict Pushed Oil Prices Quickly up to the $100/Barrel Mark
High Discount: Crude Oil Spot Discount Surged Higher
High Gross Margin: Refining Margins Continued to Strengthen and then Retreated Slightly in the Second Half
High Demand: The Overall Global Demand Is Steadily Recovering
Low Supply: OPEC's Growth Was Sluggish and Global Oil Supply Has Slowed Significantly
Low Inventories: Global Oil Stocks Ran at a Low Level, and Europe and the US Jointly Released Reserves
Strong Structure: The Benchmark Crude Oil Price Had a Strengthened Structure and the First Line Spread Has Widened Significantly
Suggestions for Response by China's Oil Market
Promote the Increase of Reserves and Production, and Deepen the Reform of Oil and Gas System
Give Full Play to the Consumption Potential of the Domestic Market and Continue to Enhance Trade Capacity
Improve the Rotation Mechanism of Strategic Oil Reserves to Ensure Energy Security
Give Full Play to the Advantages of Financial Capital and Promote the Internationalization of RMB
Accelerate the Construction of the National Carbon Market and Promote the Green Low-Carbon Development of the Oil Industry
Bibliography
5 Global Oil Supply Analysis and Outlook in the Context of Russia-Ukraine Conflict
Situation of OPEC+ Crude Oil Production
OPEC+ Countries Have Strong Willingness to Limit Production to Protect Prices
OPEC+’s Actual Production Increase Fell Short of Its Target
Russia-Ukraine Conflict Became the Biggest Black Swan Event in 2022
The Future of Iranian Nuclear Negotiations Is Uncertain, and Venezuela Is Still Under Sanctions
Non-OPEC+ Oil-Producing Countries Still Have a Small Increase in Production
Global Oil Supply Growth Will Slow Down in 2023
Forecast of Global Oil Supply in the Medium and Long Term
As Low Carbon Emission Reduction Becomes the Global Theme, Upstream Oil and Gas Capital Investment Will Decrease
Geopolitical Unrest Is Frequent, so Part of the Time There May Be Supply Shortages
Bibliography
6 Outlook for Global Oil Demand in the Post-COVID-19 Era
Global Oil Demand Is Recovering in 2022
The Global Economy Bottomed out and Rebounded
While Major Countries’ Demand Is Recovering, China's Oil Demand Has Been Hit Hard
In 2022, the Demand for Jet Fuel Rebounded Significantly, and That for Gasoline Recovered Less than Expected
Global Oil Demand Is Expected to Maintain Steady Growth in 2023
The Downside Risks Facing the Global Macro Economy Have Increased, and Inflation Remains High
The World's Major Economies Are Expected to See Limited Growth in Oil Demand
In 2023, the Demand for Diesel Oil Will Recover Slowly, While the Demand for Jet Fuel Will Recover Well
The Trend of Global Medium- and Long-Term Oil Demand
Conclusion
Bibliography
7 Development Status and Prospect of Global Oil Refining Industry
The Global Refining Industry Gradually Recovered from the Pandemic in 2021, but the Refining Capacity Declined for the First Time in 30 Years
In the Post-Pandemic Era, Refinery Projects Were Delayed, and a Wave of Refinery Closures Continues Globally
Crude Oil Processing Capacity of Refineries Globally
The Processing Revenue of Major Refining Centers in the World Has Been Repaired, but is Still at a Low Level
Crack Spreads of Major Oil Products Have Rebounded Steadily, and Low-Sulfur Fuel Oil Has Continued Its Strong Growth
In the Post-Pandemic Era, the Global Oil Refining Industry Will Gradually Come Out of the Doldrums
Global Refining Capacity Resumes Rapid Growth
The Refining Industry Will See a Gradual Recovery in the Post-Pandemic Era, but Refining Gross Margins Are Difficult to Restore to Pre-Pandemic Level
Medium- and Long-Term Outlook for the Oil Refining Industry
Bibliography
8 Analysis of the New Trend of Global Crude Oil Trade
Current Situation of Global Crude Oil Trade in 2021
In 2021, the Total Amount of Global Crude Oil Trade Decreased, and the Eastward Shift of Trade Center Slowed Down
China's Crude Oil Imports Declined for the First Time in 20 Years, with a Significant Increase in the Middle East as the Source of Imports
US Crude Oil Exports Fell for the First Time in Six Years Amid the COVID-19 Pandemic
OPEC + Slowly Increased Production, with Crude Oil Exports Picking up Slightly
Global Crude Oil Trade in 2022
Resilient Growth of Global Crude Oil Trade
Structural Adjustment of Global Crude Oil Trade Flows
Medium- and Long-Term Outlook for Global Crude Oil Trade
Geopolitical Impact on Global Crude Oil Trade Intensifies
Increasing Uncertainty in Global Crude Oil Trade and the Decline of Russia's Crude Oil Trade Position
The Short Term Cooling of the Energy Transition Will Still Reshape the Oil Trade Pattern
Bibliography
Part III Natural Gas
9 Global Natural Gas Market and Changing Trends of Natural Gas Trade
Overview of the Global Natural Gas Market
Since the Conflict Between Russia and Ukraine, the Tension of Global Natural Gas Supply Has Intensified
The Growth Rate of Natural Gas Demand Slows Down, and the Demand in Europe May Drop Significantly
Natural Gas Prices Hit Record Highs, with Europe Leading the Asia–Pacific Price Trend
LNG Transportation Market Fluctuates Violently
Characteristics of Global Natural Gas Trade
Russia's Natural Gas Exports Declined Under European and American Sanctions
US LNG Exports Grew Strongly
Europe is Committed to Seeking Multi-Source Import Sources
China's LNG Import Growth Slowed Sharply
Medium and Long-Term Outlook
The Goals of Peak Carbon Emissions and Carbon Neutrality Push up the Global Demand for Natural Gas, and the Emissions Probably Peak Around 2035
The Global Natural Gas Supply is Gradually Increasing, and May Peak in 10 Years
Bibliography
10 Analysis on High-Quality Development of Natural Gas Industry in China
Development Status of China’s Natural Gas Industry
Development Status of Commodity Market Structure
Current Status of Construction of Major Systems and Rules
Current Situation of Market Supervision
Major Problems Facing the High-Quality Development of the Natural Gas Industry
Rationalize the Balance Between Opening of Upstream Exploration and Development and Natural Gas Supply Assurance
Achieve the Resonance Between the Construction of Natural Gas Pricing Mechanism and the Competitiveness of the Industry
Achieve Synergy Between Short-Term Growth of Natural Gas Scale and Long-Term Carbon Emission Reduction
Suggestions for the High-Quality Development of the Natural Gas Industry
Deepen Reform and Accelerate the Diversification of Natural Gas Suppliers
Driven by Innovation, Steadily Advance Price Reform and Market-Oriented Development
Take the Initiative to Establish and Improve the Natural Gas Supervision System
Establish a Strategic Mindset and Plan the Transformation and Upgrading of Natural Gas in a Scientific Manner
References
11 Progress and Suggestions on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China
Introduction
Progress on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China
Independent Ownership of Trunk Pipeline Infrastructure
Progress of Integration of Some Provincial Networks Into the National Pipeline Network
Initial Establishment of Rules for Price Management and Cost Monitoring under the System of Separation of Transportation and Sales
Improved Opening of Spare Capacity to Third Parties
Initial Formation of the Regulatory System
Main Problems at this Stage
There are Shortcomings in the Construction and Development of Pipeline Infrastructure
The Operation Rules of Pipeline Network Need to be Refined and Improved
The Degree of Information Disclosure Needs to be Improved
Supervision System Construction Needs to be Strengthened
The Integration of Provincial Network into the National Management Network Needs to be Deepened
Suggestions on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China
Accelerate the Upgrading of Natural Gas Infrastructure Capacity
Improve the Detailed Rules for the Operation and Scheduling of Pipeline Network
Establish a “National Network” Supporting Interconnection and Separation of Transportation and Sales
Leverage the Pricing Reform of Pipeline Transmission Services with Regional Pilots
Improve the Regulatory System Centered on Information Disclosure and Fair Opening
Allow Some Pipeline Network Infrastructure to Be Exempted from Opening to Third Parties
Increase the Adaptability of Infrastructures to “Dual Carbon” Development
References
12 Analysis and Suggestions on the Scenarios of Integrated Development Between Natural Gas and Other Energy Resources Under the Goals of Peaking Carbon Emissions and Achieving Carbon Neutrality
Introduction
The Development Environment Faced by the Gas Industry Under the Goals of Peaking Carbon Emissions and Achieving Carbon Neutrality
The New Landscape Facing the Development of the Industry
The Role of Gas in Building China’s Clean Energy System
Analysis of Application Scenarios for the Integrated Development of Gas and Multiple Energy Sources
Integrated Development of Natural Gas and New Energy
Integrated Development of Natural Gas and Hydrogen Energy
Integrated Development of Natural Gas and Biogas
Suggestions on the Integrated Development of Gas and Various Energy Sources
Firm Confidence in Industry Development
Strengthen the Construction of Market Mechanism
Build a New Ecology of Industrial Development
Promote Technological Collaborative Innovation
Strengthen International Cooperation
Conclusion
References
13 Development Status and Prospect of Gas Distributed Energy Industry
Introduction
Development Status of Gas Distributed Energy Industry
Market Scale of Natural Gas Distributed Energy
Industrial Development Conditions
Technology Route and Core Equipment of Gas Distributed Energy
Problems in the Development of Gas Distributed Energy
Prospect of Gas Distributed Energy Industry
Forecast of the Development of Gas Distributed Energy
Trend of the Development of Gas Distributed Energy
Suggestions on Promoting the Development of Gas Distributed Energy Industry
Policy-Level Suggestions
Market-Level Suggestions
Technology-Level Suggestions
Part IV New Energy
14 Hydrogen Production from Renewable Energy: Current Status, Prospects and Challenges
The Practical Significance of China's Active Development of the Renewable Energy-to-Hydrogen Industry
Development Status of Hydrogen Production from Renewable Energy in China and Abroad
Development Status of Hydrogen Production from Renewable Energy Around the World
Development Status of Hydrogen Production from Renewable Energy in China
The Development and Trend of the Renewable Energy-to-Hydrogen Technology
The Development and Trend of the Electrolytic Water-to-Hydrogen Technology
The Development and Trend of Hydrogen Energy Storage and Transportation Technology
Economics of the Renewable Energy-to-Hydrogen Technology
Production Cost
Storage and Transportation Cost
The Main Challenges for the Development of Renewable Energy-to-Hydrogen Industry in China
Countermeasures and Suggestions
References
15 Advanced Bio-Liquid Fuels: An Important Means to Achieve Carbon Neutrality in Transportation
Background of Carbon Emission Reduction in the Transportation Sector
Peak Carbon Emissions and Carbon Neutrality
Carbon Emissions in the Transportation Sector and Challenges
Future Development Trend of Transportation in China
Bio-liquid Fuels as An Important Means to Achieve Carbon Neutrality in Transportation
Status of the Advanced Bio-Liquid Fuel Industry
Definition and Classification of Advanced Bio-Liquid Fuel
Biofuel Ethanol
Biodiesel
Sustainable Aviation Fuels (SAF)
Prospect of the Advanced Bio-liquid Fuel Industry
Future Development Trend
Promotion Model
Industrial Development Path
References
16 The Practice Exploration, Suggestions for Reflection and Development Prospects of the Hydrogen Energy Industry in China
Practice Exploration of Hydrogen Energy Industry
Continuous Improvement of Policy System
Significant Progress in Core Technology
Gradual Diversification of Hydrogen Energy Supply Path
Expanding Terminal Applications
Continuous Strengthening of Business Cooperation
Reflections and Suggestions
There is an Urgent Need to Break Through Policy and Regulatory Constraints
Support the Diversified Development of Hydrogen Energy Production, Transmission and Use
Insist on Promoting Independent Innovation of Core Technology
Play the Driving Role of Demonstration City Cluster
Development Prospects
A New Stage of Large-Scale Development of the Industry
Independent Control of Core Technology and Equipment
An Efficient and Low-Carbon Hydrogen Energy Supply System
Expanding Application Scenarios of Hydrogen Energy
References
17 Current Status and Outlook of CCUS Industry in China
Current Status of CCUS Industry in China
Technical Overview
National Policies
Project Progress
Issues of CCUS Development
Technical Issues
Economic Issues
Social Issues
Forecast of the Future of CCUS
CCUS's Technical Development Trend
CCUS's Economic Development Trend
Potential Environmental Risks of CCUS and Countermeasures
References
18 Economic Evaluation and Future Feasibility Analysis of the Coal Chemical Industry Coupled with Green Hydrogen Technology
Introduction
Development Trend of the Coal Chemical Industry and Hydrogen Energy Industry in China
Industrial Development Status
Industrial Policy Analysis
Analysis of the Technical Pathways of the Green Hydrogen-Coal Chemical Coupling
Technical Pathways of Hydrogen Production
Hydrogen Production from Fossil Energy and Future Direction of Development
Hydrogen Production from Electrolysis of Water and Future Direction of Development
Analysis of the Technical Pathways of the Green Hydrogen-Coal Chemical Coupling
Future Feasibility Analysis of the Coal Chemical Industry Coupled with Green Hydrogen Technology
Analysis of the Cost Structure and Cost Reduction Potential of Green Hydrogen
Cost Prediction of the Green Hydrogen-Coal Chemical Coupling
Cost Prediction of the Coal Chemical Process with CCS
Comparison of the Future Feasibility of Green Power-to-Hydrogen and Coal-to-Hydrogen
Conclusions and Recommendations
References
19 The Present and Future of Sustainable Aviation Fuels in China
Development of the Global Aviation Industry and Carbon Emission Reduction
Development of the Aviation Industry
Carbon Emission Reduction and SAF in the Aviation Industry
Current Development of China's SAF Industry Chain
Producers
Suppliers
Users
Outlook for SAF Development in China
Technical Pathways
Production Capacity
Availability of Feedstocks
Standards Development
Policy Suggestions
Further Clarification of the Policy Direction
Formation of Inter-Ministerial Working Groups and Development of Action Plans
Strengthened Assessment of Basic Information and Economic Analysis of Feedstocks
Collective Action of the Industry Chain
Support for Technological Innovation
Active Pilot Applications
References
Part V Electricity
20 Analysis of China’s Electricity Market Under the New Round of Reform
Overview of China's Electricity Market
Saw a Rebound in Social Electricity Consumption and an Increasingly Optimized Structure
As the Installed Power Generation Capacity Continued to Rise, the Proportion of Non-Fossil Energy Exceeded that of Coal-Fired Power for the First Time
Power Supply and Demand Was Tight Overall, and Energy Consumption Index Continued to Decline
National Power Investment Hit a 10-Year High and the Scale of Grid Construction Gradually Expanded
China's Electricity Market Reform and System Construction
China's Electric Power Market Reform
Overview of China's Electricity Market System Construction
Development Trend and Direction of China's Electricity Market
Establishment of a National Unified Electricity Market
Gradual Improvement of Electricity Spot Market
Transition to a Clean and Low-Carbon Electricity Market
Mutual Recognition of Green Power Trading and Carbon Trading
References
21 Main Challenges and Countermeasures for New Energy Development in China Under the Construction of New Power System
Current Situation of New Energy Development in China
Rich Endowment of New Energy Resources in China
Rapid Growth of New Energy Installations and Continuous Improvement of the Industrial Chain
High Level of Utilization of New Energy, with Steadily Enhanced Marketization
Challenges for New Energy Development in China
Economy
Market Mechanism Construction
Power System Security
Supply Chain Security
Security Measures for the Development of New Energy in China
Increase the Flexible Regulation Capacity of the Power System
Build a Fair and Efficient Electricity Market
Give Full Play to the Complementary Effect of Power-To-X
Strengthen the Development Pattern of Distributed Energy and Microgrid
Promote the Development of Circular Economy and “New Energy +”
References

Citation preview

Current Chinese Economic Report Series

China International United Petroleum & Chemicals Co., Ltd. Chinese Academy of Social Sciences Peking University Editors

Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023)

Current Chinese Economic Report Series

The Current Chinese Economic Reports series provides insights into the economic development of one of the largest and fastest growing economies in the world; though widely discussed internationally, many facets of its current development remain unknown to the English speaking world. All reports contain new data, which was previously unknown or unavailable outside of China. The series covers regional development, industry reports, as well as special topics like environmental or demographical issues.

China International United Petroleum & Chemicals Co., Ltd. · Chinese Academy of Social Sciences · Peking University Editors

Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023)

Editors China International United Petroleum & Chemicals Co., Ltd. Beijing, China

Chinese Academy of Social Sciences Beijing, China

Peking University Beijing, China Translated by Jing Luo

ISSN 2194-7937 ISSN 2194-7945 (electronic) Current Chinese Economic Report Series ISBN 978-981-99-7288-3 ISBN 978-981-99-7289-0 (eBook) https://doi.org/10.1007/978-981-99-7289-0 Jointly published with China Economic Publishing House. The print edition is not for sale in China (Mainland). Customers from China (Mainland) please order the print book from: China Economic Publishing House. ISBN of the Co-Publisher’s edition: 978-7-5136-7301-3 Translation from the Chinese Simplified language edition: “中国油气与新能源产业发展报告 (2022– 2023)” by China International United Petroleum & Chemicals Co., Ltd., et al., © China Economic Press 2023. Published by China Economic Press. All Rights Reserved. © China Economic Publishing House 2024 This work is subject to copyright. All rights are solely and exclusively licensed by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publishers, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publishers nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publishers remain neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Singapore Pte Ltd. The registered company address is: 152 Beach Road, #21-01/04 Gateway East, Singapore 189721, Singapore Paper in this product is recyclable.

Contents

Part I 1

Macro Trends

Global Energy Outlook in the Context of Russia-Ukraine Conflict . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Qiang Liu and Chen Pan

2

China’s Carbon Emission Peak Goals, Strategies and Policies . . . . . Anjun Hu

3

Carbon Market Outlook in the Context of Global Carbon Neutrality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Na Ren, Yi Cai, Zhiyuan Qin, and Ying Zhao

Part II 4

5

3 27

47

Petroleum

New Features of the Global Oil Market in the Context of High Oil Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pei Wang and Aijie Li

65

Global Oil Supply Analysis and Outlook in the Context of Russia-Ukraine Conflict . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Na Ren and Yi Cai

79

6

Outlook for Global Oil Demand in the Post-COVID-19 Era . . . . . . . Di Hu and Ying Zhao

93

7

Development Status and Prospect of Global Oil Refining Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Han Li, Kaijun Gong, and Zhuo Fang

8

Analysis of the New Trend of Global Crude Oil Trade . . . . . . . . . . . . 125 Guanhua Wang, Zhuo Fang, and Xiaoyuan Xia

v

vi

Contents

Part III Natural Gas 9

Global Natural Gas Market and Changing Trends of Natural Gas Trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139 Xiaoyuan Xia and Aijie Li

10 Analysis on High-Quality Development of Natural Gas Industry in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153 Hui Sun and Lei Yang 11 Progress and Suggestions on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China . . . . . . . . . . . . . . . . . . 169 Xiongjun Zhang and Jun Bai 12 Analysis and Suggestions on the Scenarios of Integrated Development Between Natural Gas and Other Energy Resources Under the Goals of Peaking Carbon Emissions and Achieving Carbon Neutrality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193 Weiwei Wang, Hui Sun, and Lei Yang 13 Development Status and Prospect of Gas Distributed Energy Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209 Yang Zhang, Xiqing Tang, Qingshan Meng, Weiwei Wang, and Wei Huang Part IV New Energy 14 Hydrogen Production from Renewable Energy: Current Status, Prospects and Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231 Qia Wang 15 Advanced Bio-Liquid Fuels: An Important Means to Achieve Carbon Neutrality in Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 253 Xiaozhou Xue, Jian Min, Bin Yu, Meng Wang, Guogang Zhang, and Guoqing Wu 16 The Practice Exploration, Suggestions for Reflection and Development Prospects of the Hydrogen Energy Industry in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273 Juan Gong, Zhongjun Zhang, Xianzhi Dai, Jiayi Wu, Wenfeng Chen, Zier Jin, Ziyuan Wang, and Jishi Zhao 17 Current Status and Outlook of CCUS Industry in China . . . . . . . . . . 289 Boyue Zheng, Jianjie Niu, and Kaiqiang Zhang 18 Economic Evaluation and Future Feasibility Analysis of the Coal Chemical Industry Coupled with Green Hydrogen Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307 Weidong Yang, Yujia Han, Haojun Yuan, Yihao Yan, and Xiang Li

Contents

vii

19 The Present and Future of Sustainable Aviation Fuels in China . . . . 333 Yiru Ding, Ping Zheng, Lei Yang, Qianyu Wang, and Qinke Han Part V

Electricity

20 Analysis of China’s Electricity Market Under the New Round of Reform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 359 Qianchun Yang, Guangbin Fu, Zhiyuan Qin, and Kaijun Gong 21 Main Challenges and Countermeasures for New Energy Development in China Under the Construction of New Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 373 Di Wu, Junjie Kang, Fuqiang Yang, and Lei Yang

Part I

Macro Trends

Chapter 1

Global Energy Outlook in the Context of Russia-Ukraine Conflict Qiang Liu and Chen Pan

On February 24, 2022, the Russia-Ukraine conflict erupted in full force when Russian troops entered Ukraine on multiple fronts and launched a “special military operation.” The conflict has a complex geopolitical background. Russia’s military action was born out of its mainstream ideology on international relations— New Eurasianism, which centers on maintaining Russia’s geo-strategic security and global influence through territorial control and the formation of spheres of influence around the country. Under the far-reaching influence of this ideology, the outbreak of the conflict was precipitated by the special historical and political issues including Russia’s cross-border ethnic issues, the historical impact of the Holodomor and World War II in Ukraine, Ukraine’s nuclear abandonment and the Budapest Treaty, Black Sea control and the Crimea issue, and NATO’s eastward expansion and Russia’s countermeasures. The outbreak of the conflict was immediately followed by unprecedented sanctions by the West against Russia and full assistance and support to Ukraine, with the possibility of a prolonged low-intensity war between the two countries around the borderline issue in the future. The conflict involving Russia, a major supplier to the global oil and gas market, continues to this day and has a huge impact not only on global politics and economics, but also on the global energy market. In view of this, this paper analyzes the impact of the Russia-Ukraine conflict on the global political and economic landscape, and, based on which, discusses the prospects for global energy development in the context of the conflict.

Q. Liu (B) · C. Pan Department of Energy Security and New Energy, Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_1

3

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Q. Liu and C. Pan

The Impact of the Russia-Ukraine Conflict on the Global Political and Economic Landscape The Russia-Ukraine conflict is the biggest geopolitical event since the twenty-first century, which has opened the way for the reorganization of the international political and economic order in the “post-Cold War” era and will inevitably promote changes and adjustments in the world’s geopolitics, political order, international rule system and economic relations. The West has been containing Russia by besieging and isolating on all fronts: politics, economy, science and technology, humanities and so on. On the one hand, they are imposing all-round economic and financial sanctions on Russia; on the other hand, they are providing all-round assistance to Ukraine, including military, financial and humanitarian assistance. The outbreak and continuation of this conflict will have a profound impact on the world political landscape, or reshape the global political structure.

Global Political Landscape Instead of weakening the power of NATO and Europe and separating the US and Europe, the Russia-Ukraine conflict has led to a renewed awareness of the importance of the US and NATO among European countries, especially in Eastern Europe, leaving Russia in unprecedented isolation in international politics. Since the outbreak of the conflict, European countries that have been at peace for a long time, especially the Baltic States and Eastern European countries close to Russia, such as Finland, Sweden and Poland, raise their military budgets, purchase weapons and expand their armies as they feel the threat from Russia. Finland and Sweden, which had always been neutral, now are applying to join NATO. Under the impetus of the US and NATO, the Western world is forming an anti-Russian coalition to support Ukraine. There is also an anti-Russian sentiment in Russia’s neighboring regions. Even Kazakhstan, which had been supported by Russia during its political turmoil, became largely neutral about the Russia-Ukraine conflict, provoking an almost antagonistic pattern between Russia and Kazakhstan. The Russian-led Eurasian Union, the Collective Security Treaty Organization, and other regional organizations involving former CIS countries are at risk of disintegration and friction. The Russia-Ukraine conflict has pushed the US to place greater emphasis on building global political alliances, while beginning to accelerate its efforts to draw in and geopolitically integrate with emerging markets and developing countries, in addition to its natural allies in the OECD countries of Europe, East Asia, and Oceania. The overall style of ASEAN countries in their diplomatic relations shows their increasing autonomy. In recent years, in response to some UN resolutions, ASEAN countries rarely follow the West blindly, but make choices based on their own interests. In this Russia-Ukraine conflict, the ten ASEAN countries, except Singapore, did not make substantial sanctions against Russia. On the balance of

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interests, the Middle East and North African countries are neutral in their attitude toward the conflict. As the United Nations General Assembly adopted a resolution on Wednesday condemning Russia’s invasion of Ukraine, Syria voted against, Iraq, Iran and Algeria abstained, and most Middle East countries did not join in the sanctions action against Russia. Latin American countries are generally unenthusiastic about international affairs in other parts of the world. For example, Brazil has remained neutral on the Russia-Ukraine situation and has stated that economic sanctions will not contribute to a peaceful resolution of the Russia-Ukraine issue, in line with its consistent moderate foreign policy.

Global Economic Landscape The Russia-Ukraine conflict has serious implications for the world economy, both in terms of the direct impact of the war on commodity prices and European energy supplies, but also in terms of the long-term global impact through changes in the global political and economic landscape. This adds to the woes of a world economy just recovering from the pandemic. There is no certainty as to when and how the Russia-Ukraine conflict will end, but in terms of the global economic landscape, it will undoubtedly add to the uncertainty of the global economy in any case.

Global Commodity Prices Fluctuate Sharply Russia is an important exporter of energy, food, metals and other commodities, while Ukraine is a major global food producer and exporter. The conflict between the two countries undoubtedly pushed up global commodity prices, and then the targeted economic and financial measures of Europe and the US made prices fall back. The dramatic fluctuations in commodity prices were quickly transmitted to global industries, which in addition to causing dramatic short-term shocks, made investment expectations more unstable and sometimes more damaging to the economy than simple price increases. Russia and Ukraine account for about 80% of global sunflower oil exports, 19% of global corn exports and 29% of global wheat exports. Crop sowing and harvesting have not been spared from the dramatic impact of the conflict, with the suspension of commercial shipping at Odessa, Ukraine’s largest port on the Black Sea coast, disruption of export shipments, reduced grain production and shipping restrictions, and a host of other factors pushing up global food prices. Although the food export agreement has eased the global food crisis, uncertainty remains. Russia is the world’s second largest exporter of crude oil and the largest supplier of natural gas to Europe, and the Russia-Ukraine conflict and sanctions against it by US and European countries continue to push up global energy prices. Russia is also a major exporter of metals such as palladium, nickel and aluminum, with its share of global exports of palladium, nickel and aluminum at 6%, 21.9% and 9.9%,

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respectively, in 2021. Since the conflict, the market has seen dramatic shocks, with metal trading prices rising sharply, pushing up the costs of downstream companies in the electronics industry, auto parts, and military aerospace. Subsequently, the US has gradually brought crude oil prices back down by promoting the appreciation of the US dollar, increasing domestic and other oilproducing countries’ supply, releasing inventories and other measures, and crude oil prices have now fallen back to the level before the conflict. In parallel, the prices of copper, aluminum, nickel, gold and other metals have also basically returned to the previous levels.

The Global Supply Chain Crisis is Intensified The Russia-Ukraine conflict is exacerbating the crisis of the global supply chain that has appeared less resilient since the outbreak of the COVID-19 pandemic, which sees international shipping and logistics prices soar in the short term, pushing up transportation costs. With more far-reaching effects, US and European countries imposed financial sanctions, oil embargoes and airspace closures on Russia, and European countries urgently adjusted their import channels for energy and other related materials, while banning exports of cutting-edge technology products to Russia and revoking Russia’s most-favored-nation status, among other measures. In terms of land transport, given that both Russia and Ukraine are important nodes of the “Belt and Road”, the near disruption of land transport routes caused by the conflict made it impossible to continue the operation of the China–Europe train, which in turn seriously affects the economic and trade relations between China and the countries bordering the Black Sea. On the one hand, the conflict has interrupted the transportation of China-EU trains via Ukraine, and on the other hand some customers who were worried about sanctions withdrew their orders. Most of the goods shipped to Europe via the China-EU trains are high-value electronic goods and other manufactured products, thus inevitably affecting China’s related manufacturing industry. In terms of pipeline transportation, European countries are most dependent on Russia for energy imports, mainly oil and gas, with gas being the most essential as its transportation benefits even more from the pipeline infrastructure. Immediately after the outbreak of the conflict, Europe announced plans to scale back its oil and gas imports from Russia, but this shift will take some time as it calls for new import facilities, mainly LNG import terminals. In the financial sector, the West promptly kicked Russia’s major banks out of the SWIFT system and froze Russian financial assets abroad. This measure had a serious impact on Russia’s foreign trade and affected Russia’s international investment and trade cooperation. In the field of technology, Europe and the US restrict the export of electronic products such as chips and related manufacturing products to Russia; large e-commerce companies and social networking platforms from Western countries, such as Amazon,

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Twitter and Google, have left Russia and carry out autonomous sanctions against Russia.

The World Economy Falls into Stagflation The Russia-Ukraine conflict has had an impact on monetary policies of various countries, causing the risk of stagflation. The conflict and sanctions against Russia have undermined the confidence of European consumers and investors, and coupled with the EU’s high dependence on Russian energy imports, high energy prices have forced the EU to accelerate its exit from accommodative monetary policies. The US has similarly accelerated its monetary tapering operations in order to reduce high inflation caused by high oil prices, which also carries the risk of causing stagflation. With the outbreak of the conflict, the international financial community reacted quickly, and as an emergency hedge against value preservation and long-term expectations, the US dollar began to appreciate and, correspondingly, the euro depreciated rapidly against the dollar. By mid-July 2022, the US dollar was almost equal to the euro for the first time in 20 years. The Russian ruble depreciated rapidly in the aftermath of the conflict, then recovered rapidly following strong intervention by the Russian government and is now above its pre-conflict value. The conflict dampened venture capital’s and private sector’s confidence, which in turn impacted demand in the real economy and will ultimately slow down the global economic repair process. The world is now in a post-pandemic era, with the economy gradually warming up from the cold winter of the COVID-19 pandemic, but the basis for economic recovery is weak. The Russia-Ukraine conflict and the sanctions imposed on Russia by the US and European countries further increase the uncertainty of the global economic recovery prospects. The conflict weakens economic recovery prospects while fueling inflation expectations, complicating the challenge of trade-offs between curbing inflation and supporting the economy. The conflict severely undermines investor confidence and significantly reduces the willingness of multinational companies to invest. Rising market risk aversion is accompanied by rising financial risks in emerging countries.

The Trend of Reverse Globalization in the World Economy Accelerates The regionalization and localization of the global economy occurred long before the outbreak of the Russia-Ukraine conflict, and the disruption of global supply chains due to the COVID-19 outbreak contributed to the acceleration of this dynamic. Thus, when the conflict broke out, the global political landscape was shaken. In the short term, the Western camp is weighing its interests and moving closer to the US, while a considerable number of developing countries choose to remain neutral and wait and see in order to protect their own interests. In the long run, European countries will be more determined to promote their “strategic autonomy,” and in the future will enhance their independent status in more economic and trade fields, actively

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expanding their geopolitical influence. Developing countries will also adjust their diplomatic attitudes to lean more toward autonomy. It is foreseeable that the chaos and the economic sanctions imposed on Russia mainly by the US and Europe will accelerate the reorganization of the global economic landscape and further regionalize and localize the global economy amidst greater uncertainty. The trend of counter-globalization in the world economy inevitably has a significant impact on China, which is deeply involved in the world economy. The US and Western countries have begun to deliberately reshape the international industrial chain in an attempt to weaken China’s influence in the international economic arena. The US is encouraging the return of manufacturers to the US and the transfer of manufacturers and supply chains that cannot return to the US to India and Southeast Asian countries, and there will be more restrictions and suppressive measures in the field of science and technology in the future, which will pose new challenges to the long-term sustainable development of the Chinese economy. At the same time, the efforts of the US and Western countries to establish a trade and economic integration system outside of the World Trade Organization (WTO) in accordance with Western market rules will significantly change the international economic environment that China will face in the future.

The Impact of the Russia-Ukraine Conflict on the Global Energy Development The Russia-Ukraine conflict has had a direct impact on the global oil and gas market, and the post-conflict spike in energy prices has exacerbated the inflation crisis in major economies, while the world economy stands at another crossroads. Changes in the energy supply structure will reshape the global energy market landscape. For the vast majority of countries, especially in the EU, the conflict has brought about a more long-term energy security issue, prompting countries to make energy security a top priority in its future energy policies.

Direct Impact on the Global Oil and Gas Market Forecast of Crude Oil Market and Crude Oil Prices The Russia-Ukraine conflict has led to drastic fluctuations in crude oil prices, seriously disrupting the global energy supply and demand order. The conflict forced European countries, which are highly dependent on Russian oil and gas resources, to switch their import sources, which will change the global oil and gas supply and demand pattern. Europe, which is most affected by the Russia-Ukraine conflict, including the EU and the UK, has proposed plans to reduce and eventually get rid

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of oil and gas imports from Russia. The EU released the REPowerEU: Joint European action for more affordable, secure and sustainable energy on March 8, 2022, which, based on the Fit for 55 package, proposes to reduce the EU’s Russian gas imports by two thirds by 2022, and to free itself from dependence on Russian oil and gas resources as early as possible by 2030. The main measures are to promote the diversification of gas imports in the near term (accounting to more than half of the alternatives) and to focus on increasing the use of renewable energy and energy efficiency in the medium and long term. The leaders of the 27 EU member states agreed to the action plan on March 11, and the European Commission will issue further implementation details. For the US, the Russia-Ukraine conflict represents a unique business opportunity for its oil and gas industry. With Russian oil accounting for only about 3% of all crude oil imports that arrived in the US in 2021 and the US not importing any Russian natural gas, the ban on Russian energy imports will have little impact on the US domestic energy supply system. After the conflict broke out, the US was the first to announce a halt to imports of Russian energy products, and as an alternative to Russian natural gas, US LNG will see a larger international market. Recently, the US has started another diplomatic public relations campaign to limit the price of Russian oil exported. The basic policy adopted by the US, Europe, Japan and other developed countries is, on the one hand, to push European countries to get rid of their dependence on Russian oil and gas; on the other hand, to try to convince developing countries like China and India to import Russian oil at a limited price. The Russia-Ukraine conflict has undoubtedly pushed up crude oil prices in the short term, an inevitable reaction to tight supply and psychological tension. But in the long term, as the situation becomes clearer, crude oil prices will return to the fundamentals of market supply and demand after their surge higher. In recent months, the policy goals of the US and European countries have become very clear: one is to reduce Russia’s share of the global oil market as much as possible, and the other is to lower oil prices. They hope to reduce, if not completely divest Russia from the oil market, the country’s oil export revenues, which would also help reduce high inflation in the US and European countries and ease the pressure on their domestic economy due to support for Ukraine. To this end, the US has pushed for both domestic tapering to reduce the dollar supply and international support from Saudi Arabia, the pivotal oil producing nation in the Organization of Petroleum Exporting Countries (OPEC). Both of these measures have begun to work recently, so international oil prices have fallen significantly since July (Fig. 1.1) and are now back to around $96 per barrel. The pullback in international oil prices is expected to continue until at least the second half of 2022.

Forecast of Natural Gas Market and Natural Gas Prices Europe is highly dependent on Russian gas resources (see Table 1.1), so the RussiaUkraine conflict has the most significant impact on the European gas market, especially in Germany. In turn, the loss of the European market would be very damaging

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Fig. 1.1 Crude oil price (WTI) curve ($/barrel). Source https://markets.businessinsider.com/com modities/oil-price/usd?type=wti

for Russia: in 2020, Russian exports to Europe accounted for 51.4% of total European imports and 70.4% of total Russian exports (see Table 1.1); if the volume of transit and re-exports is excluded, it is even 73.8% of Russia’s net exports. In relative terms, however, the conflict affects Russia more than Europe. While the EU can find alternative sources of gas by comprising on cost effectiveness, Russia, whose gas exports are dependent on pipeline facilities, would need to build LNG facilities or ultra-long-distance pipeline facilities to replace its gas export targets. In the context of Western sanctions, such long-term investments are difficult. In the future, Europe will have to look for new sources of gas supply in order to break away from its dependence on Russian gas resources. Europe’s import structure in fact has many options, with differences mainly in terms of price. From the point of view of sources, gas from Azerbaijan and Turkmenistan in the Caspian region can be delivered to Europe via the Baku-Tbilisi-Ceyhan pipeline to the Black Sea terminal, while gas reserves in the Eastern Mediterranean and the Black Sea (after the war) can also provide a source of gas imports for the South-East European region. In addition, Algeria and Libya could also increase their gas exports to countries in southern Europe through submarine pipelines. Examples include expansion of the capacity of the Medgaz gas pipeline linking Algeria and Spain, Bulgaria’s connection of its gas network to Romania and Serbia, Poland’s connection to Denmark, and Bulgaria’s promotion of further connections to Greece. The largest incremental volumes will come from US shale gas exported in the form of LNG. The US coordinated emergency exports to European countries as soon as the conflict erupted and will continue to build additional terminal facilities to meet more of the European countries’ natural gas needs in the future. In the first half of 2022, US exports reached 11.2 billion cubic meters of natural gas, an increase of 25.7% year-on-year. For the first time in history, US LNG supplies to European countries exceeded Russian pipeline deliveries in June 2022, the International Energy Agency said.

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Table 1.1 Europe’s international gas trade with Russia in 2020 Trade volume (billion m3 )

Global market share (%)

Europe Pipeline natural gas imports

211.3

22.5

Including: Russia

167.7

17.8

African countries

25.2

2.7

Other CIS countries

13.4

1.4

Middle East

5.1

0.5

LNG imports

114.8

12.2

Total imports

326.1

34.7

LNG exports∗

5.6

0.6

Total exports∗

5.6

0.6

Pipeline natural gas imports

11.0

1.2

Total imports

11.0

1.2

Pipeline natural gas exports

197.7

21.0

Including: Europe

167.7

17.8

26.1

2.8

Russia

Other CIS countries LNG exports

40.4

4.3

Total exports∗

238.1

25.3

Global pipeline trade

452.2

48.1

Global LNG trade

487.9

51.9

Total global trade

940.1

100.0

Source BP Energy Statistics, 2021 Note ∗ LNG exports include re-exports

While global oil prices have soared, natural gas prices have continued to hit record highs. Immediately after the conflict erupted, the EU proposed to reduce its gas dependence on Russia to more than half in order to quickly respond to the sanctions. The proposal, while reflecting the elevated energy sanctions concerns of European countries, also significantly increases their reliance on LNG in the spot market, thus pushing LNG prices even higher. The Dutch TTF gas price, the benchmark for natural gas prices in European countries, reached a high of e200/MW-h in futures in early March. On July 16, the TTF price was e159.57/MW-h (see Fig. 1.2). It cannot be ruled out that there will be more price fluctuations in the future, as the Russia-Ukraine conflict continues and the outlook is unpredictable. Perhaps only when the conflict is over or the outlook is clear will gas prices in European countries stabilize. As it will take a long time to adjust the supply structure, it is estimated that European countries and the world will face significant price volatility in the next 2–3 years.

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TTF Gas

Natural Gas EU Duthch TTF(EUR/MWh)159.57 -15.47(-8.84%)

250 225 200 175 159.57 150 125 100 75 50

Sep

Nov

2022

Mar

May

Jul

1D 1W 1M 6M 1Y 5Y 10Y All

Fig. 1.2 Curve of the Dutch TTF gas price (e/MW-h). Source https://tradingeconomics.com/com modity/eu-natural-gas

Global Oil and Gas Market Landscape What is clear is that after the outbreak of the conflict, and especially after the boycott of Russian oil and gas exports by the West gradually takes effect, both international oil and gas markets will undergo fundamental changes. These changes will be manifested in two main ways. The US and Saudi Arabia, two major oil and gas producers, will have a significantly higher “energy voice.” As the world’s largest producer of oil and natural gas, the US has great export potential despite not ranking first in the world in both oil and gas exports due to its huge domestic demand. Data for 2020 show that the US is the fifth largest exporter of crude oil (behind Saudi Arabia, Russia, Canada, and Iraq) and the second largest exporter of natural gas (after Russia, and with total exports even greater than the entire Middle East region combined). While the US has achieved a shale gas revolution, it still has many untapped offshore reservoirs and reserves in Alaska, thus its potential for future production increases remains a concern. Saudi Arabia, on the other hand, is the traditional OPEC production hub, retaining significant mobile capacity. Saudi Arabia’s role as a determinant of oil prices was exemplified by President Biden’s visit to Saudi Arabia on July 16, when talks with the Saudi king essentially resulted in an agreement to increase oil production. This dominance of the US and Saudi Arabia in the international oil and gas market is determined by their respective characteristics. The US has hegemony over the US dollar, which translates into a large part of pricing power over international oil prices, enabling it to manipulate oil prices through the dollar exchange rate and its huge production capacity. Saudi Arabia has the world’s largest oil reserves and

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production capacity (16.6% of the world’s oil production in 2020) and almost the lowest cost of oil extraction in the world. These two factors determine Saudi Arabia’s position in the international oil market. Russia will not be able to return to its former position in the sector due to the impact on its oil and gas production. Before the conflict broke out Russia was the world’s most important oil exporter and largest gas exporter outside of Saudi Arabia, and it is difficult for European countries to quickly decouple from Russian oil and gas because of the infrastructure-based tie-ups between the two sides. However, economic costs have given way to political fears, and Europe has developed firm plans to achieve its decoupling goals. Once such decoupling measures begin to be implemented, and old refineries are adapted to smelt crude oil from other sources, new LNG receiving terminals will begin to accept gas from the US, African countries and Middle East countries. The continuation of the carbon neutral program will also lead to a reduction in demand for oil and gas, and then the decoupling from Russian oil and gas will become permanent. Once the large market of Europe is lost, it will be difficult for Russia to find alternative markets elsewhere. In the case of the Chinese market, the current share of Russian oil and gas, which China has actually cut from other competitors in order to support Russia, has essentially reached its limit. In the first half of 2020, Russia overtook Saudi Arabia as China’s largest source of crude oil imports, but the right crude oil for each refinery is different, and the high price of Russian oil puts a lot of cost pressure on Chinese refineries. In the natural gas sector, it is difficult to increase supplies to China because of Russia’s limited capacity in East Siberia. Meanwhile, there are no pipelines from West Siberia to China for natural gas yet. Under Western sanctions, the lack of funding and technology has made it almost impossible to start construction of the originally planned western Russian-Chinese gas line. Therefore, the impact of the Russia-Ukraine conflict on Russian oil and gas exports can be considered irreversible. Russian oil and gas, unable to find alternative markets, have no other choice but to sell at reduced prices. As time goes on, some wells may have to be shut down.

Impact on Energy Structure and Energy Transition Rising oil and gas prices and potential changes in global energy supply and demand patterns may have an impact on countries’ future energy structures, but in the long run, the general trend for countries to transform their energy structures to green and low-carbon is inevitable. The surge in oil and gas prices and potential supply shortage brought about by the Russia-Ukraine conflict has warned countries of the importance of energy security. In the future, no matter how countries’ energy structure is adjusted, energy security has become an important base point of energy transition.

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Europe and US European countries are undoubtedly the most affected by the Russia-Ukraine conflict, and their energy security, energy transition policies and related industries are all profoundly affected. European countries have a high dependence on energy supplies from outside their borders, while Russia is the main supplier of oil and gas to Europe (Figs. 1.3, and 1.4). The share of renewable energy in the energy structure of EU countries is increasing year by year. In terms of electricity structure, the electricity structure varies among 250.0

Million tonne

200.0 150.0 100.0 50.0

Ce

nt ra

la

nd

Ca n M ad a ex So ic ut o h A U m S e O th Eu rica er C I R rop S u e c o ss u n ia tri O U es th n er it S I M ed au Ku raq id A di w d l ra A a i e E b ra t a s E m bi a t ir N c ou a t e or n s t tr So W h A ies e ut st fri he A ca as f r t A ica A fri us ca t ra l O C h ia th in er A Si Jap a sia ng an -P ap ac o i f i I re c r nd eg ia io ns

†

Crude oil Petroleum products

200 180 160 140 120 100 80 60 40 20 0

US Peru Trinidad and Tobago Other Americas Norway Other European regions Russian Federation Oman Qatar United Arab Emirates Yemen Algeria Angola Egypt Nigeria Other African regions Australia Brunei Indonesia Malaysia Papua New Guinea Other Asia-Pacific regions* Canada Mexico Bolivia Other Central & South America Netherlands Azerbaijan Kazakhstan Turkmenistan Uzbekistan Iran Other Middle East regions Libya Myanmar Other Asia-Pacific regions

Billion cubic meters

Fig. 1.3 Sources of Europe’s oil and oil product imports (2020). Source BP Energy Statistics, 2021

Fig. 1.4 Sources of Europe’s natural gas imports (2020). Source BP Energy Statistics, 2021

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Fig. 1.5 Power generation structure in selected European countries (2020). Source BP Energy Statistics, 2021

European countries (see Fig. 1.5), with a generally high share of electricity generated from low-carbon sources. Germany is vigorously developing low-carbon electricity in an orderly manner, and by 2020, wind power, solar power and other new energy power generation methods will already occupy a high proportion in its power structure. Ukraine is dominated by nuclear power and coal power. The UK has a high share of gas power generation, reaching 36% in 2020, but the UK relies on Norway for its gas imports,1 so the Russia-Ukraine conflict will have little impact on its gas supply security. European countries are clearly determined to turn this crisis into an opportunity to accelerate their transition to new energy sources. In the short term, the share of base-load power sources, such as coal and nuclear, is likely to increase over the next 5–10 years. The fact that natural gas has only half the carbon emissions of coal for the same calorific value has led to natural gas becoming an important energy source of green transition for European countries. Europe’s structure of the power source will see the impact of a change in the supply and demand structure for natural gas. First, more countries may decide to slow down the closure of coal and nuclear power plants in order to ensure a secure energy supply. Although replacing natural gas with coal or oil will result in greater greenhouse gas emissions, with energy security as a top priority, high-carbon fossil energy sources are likely to occupy a higher proportion of the energy structure in European countries in the short term, thereby suspending their process of energy transition for green growth. European countries such as Germany have already shown a major shift in their attitude toward high-carbon coal power—in March 2020, Germany, the Eurozone’s largest economy, called for a coal reserve that Europe should build to solve its electricity problem. At the same time, European countries will also try to speed up the construction process for renewable energy generation, in order to achieve a harmony between energy 1

UK: oil and gas imports|Statista.

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supply security and low-carbon energy transition for green growth. At present, wind power, solar power and other new energy generation methods still cannot perfectly replace gas power generation without the support of large-scale energy storage. In the long term, the energy structure of European countries will accelerate the transition to new energy sources such as wind and light. At the same time, the Russia-Ukraine conflict has also reinforced the nuclear-based countries, represented by France, to adhere to this energy transition path, in order to balance the autonomous control of energy supply with the transition to green and low-carbon energy. In addition, higher fossil fuel prices due to the Russia-Ukraine conflict may further increase the value of net-zero emissions technologies such as carbon capture and storage (CCS) and green hydrogen energy. The EU has an ambitious plan to replace nearly half of Russian natural gas with clean hydrogen energy by 2030 (see Fig. 1.6). Although the US energy structure has been affected only to a limited extent by the Russia-Ukraine conflict, there is a consensus reached globally, including the US, not only in Europe, that new energy sources are the mainstay of future energy increment. The US will account for nearly half of total newly installed capacity of PV in 2022. With a target of 80% clean electricity use by 2030, the cumulative installed renewable energy capacity in the US would rise to 885 million kW by that time. Not only has the Russia-Ukraine conflict raised the weight of energy security in the energy trilemma (energy security—environment sustainability—energy equity), but the potential of new energy sources to enhance energy independence and energy security has received further attention. As EU climate chief Frans Timmermans said in January 2022, renewable energy is the answer to ensuring energy security and affordability. Biomass methane 9% Hydrogen 9%

LNG 13% Other pipeline gas 3% Energy efficiency improvement and room temperature control 12%

Heat pumps 9% Renewable energy 45%

Fig. 1.6 EU’s alternative solutions for Russian gas by 2030. Source Communication from the EU Commission: REPowerEU: Joint European Action for more affordable, secure and sustainable energy

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Middle East and North Africa Most Middle East and North Africa (MENA) countries, with the exception of Turkey, are primarily affected by the secondary effects of the Russia-Ukraine conflict. For the most part, MENA countries are rich in oil and gas resources, so they do not rely much on imports in terms of oil and gas resources (Fig. 1.7). For example, Egypt’s natural gas imports are almost zero in 2020. The UAE and Kuwait import 31.3% and 27.5% of their natural gas consumption, respectively, with Qatar as the main supplier. In contrast, Turkey has a high dependence on imports of natural gas resources, importing almost all of its gas consumption and having Russia as its largest source of gas, accounting for 34% of its gas imports. Therefore, the Russia-Ukraine conflict has had a direct impact on Turkey’s gas imports. The power generation structure of MENA countries is closely linked to local resource advantages. Countries in this region are rich in oil and gas resources, and their power generation structure is dominated by oil-based and gas-based methods (see Fig. 1.8). In 2020, oil and gas power generation accounts for 91% of total power generation in Iran, and almost 100% in Saudi Arabia. Considering the increase in oil and gas prices brought about by the Russia-Ukraine conflict, the enhanced economics of new energy power compared to gas power generation, and the relatively abundant solar energy resources in the region, the future energy mix in this region may be reoriented toward renewable energy generation, especially PV generation. Others:19%

Russian Federation: 34%

Others:19%

Turkey

Iran:11%

Kuwait

US:8%

Qatar:55% Algeria:12% Azerbaijan:24%

Nigeria:18%

Others:7%

United Arab Emirates

Qatar:93%

Fig. 1.7 Sources of natural gas imports for selected Middle East countries (2020). Source BP Energy Statistics, 2021

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Iran Petroleum Wind energy

Natural gas Solar power

Saudi Arabia Egypt Coal Nuclear energy Hydro energy Other renewable energy Others

Fig. 1.8 Power generation structure in selected MENA countries (2020). Source BP Energy Statistics, 2021

Asia Pacific The Asia–Pacific region is mainly indirectly affected by the Russia-Ukraine conflict, and large fluctuations in fossil energy prices may promote the development of renewable energy. Australia, Malaysia, and Indonesia are all exporters of natural gas, and the US, Canada, and Mexico on the east coast of the Pacific have the capacity to sell natural gas (LNG) to China and the rest of the Asia–Pacific region. Therefore, in general, the oil and gas supply in the Asia–Pacific region will not be affected much, and the risk facing this region is the price issue. In the short term, there will not be much adjustment in the energy structure of these regions, but rising oil and gas prices will drive the development of non-fossil energy sources in the long term, including nuclear, hydropower and renewables. East Asian countries have different sources of imports, spreading the gas supply risk to some extent (see Fig. 1.9). Australian supplies are the main source of gas in East Asia, accounting for 29% of China’s gas imports, 39% of Japan’s, 20% of South Korea’s, and 27% of Taiwan, China’s; followed by supplies from the Middle East, such as Turkmenistan and Qatar. Russia’s supply of natural gas to East Asian countries is modest, accounting for 8% of China and Japan’s natural gas imports and 13% of Taiwan, China’s natural gas imports. In South Asia, India and Pakistan’s gas imports come mainly from Middle Eastern countries and are relatively less dependent on Russia. Figure 1.10 shows the composition of the countries that cumulatively account for 80% of the gas imports of these two countries, without Russia being present. Therefore, the impact of the RussiaUkraine conflict on the current gas supply to these countries is also not considered significant. Southeast Asian countries have a more concentrated source of gas imports than East Asian countries (see Fig. 1.11). In 2020, Russian gas exports to this region are almost nil. Australia, the Middle East, and Southeast Asian countries such as

1 Global Energy Outlook in the Context of Russia-Ukraine Conflict Others:19% Australia: 29%

19 Others:15%

Australia:39% Brunei:5%

China

Kazakhstan:5%

US:6%

Japan Indonesia:5%

Russian Federation: 8%

Malaysia:5% Turkmen istan:20%

Russian Federation:8% Qatar:8%

Qatar:12% Malaysia:15%

Others:14%

Qatar:24%

Indonesia:7% Korea Australia: 20%

Others:16% Qatar:28% Indonesia:6% Taiwan, China

Oman:10%

Papua New Guinea:9%

Malaysia:12% Russian Federation: 13%

Australia:27%

US:14%

Fig. 1.9 Sources of natural gas imports for selected East Asian countries (2020). Source BP Energy Statistics, 2021

Others:19%

Others:18% Qatar:67%

Qatar:39% Nigeria:6% India

Angola:9%

Pakistan US:9%

US:9%

United Arab Emirates:13%

Nigeria:11%

Fig. 1.10 Sources of natural gas imports for selected South Asian countries (2020). Source BP Energy Statistics, 2021

Myanmar and Malaysia are the main sources of gas imports to the region. Therefore, the impact of the Russia-Ukraine conflict on the current gas supply to these countries is also not considered significant. Coal power accounts for a relatively high share of the power mix in Southeast Asian countries, followed by natural gas power and hydropower. Due to the abundance of clean energy reserves in the Southeast Asian region, the region’s energy mix may begin to adapt to new energy directions such as PVs under the potential pull of electricity demand from its industrial development. Australia is rich in coal and natural gas resources and has a high energy selfsufficiency rate. Coal power accounts for 54% of its power mix, followed by natural gas power generation at around 20% (see Fig. 1.12). Australia is one of the world’s major exporters of natural gas, with exports totaling about 10.6 billion cubic meters

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Q. Liu and C. Pan Others:12%

Others:16%

Indonesia: 52% Brunei:24%

Malaysia

Singapore

Other Asia-Pacific regions:10%

Australia:22%

Australia:64% Others:2% Others:15% Myanmar: 48%

Uzbekistan:18%

Australia:7% Thailand

Kazakhstan Malaysia:9% Russian Qatar:21% Federation: 80%

Fig. 1.11 Sources of natural gas imports for selected Southeast Asian and Central Asian countries (2020). Source BP Energy Statistics, 2021

in 2020, mainly to the Asia–Pacific region, with China and Japan accounting for an absolute share (76%, see Fig. 1.13). The Russia-Ukraine conflict has raised gas prices and stimulated consumer countries to seek alternative sources, which is good for oil and gas exporters in the short term. For Australia’s energy structure, coal is abundant and coal power is an important source of electricity supply. However, its relatively old and inefficient coal power facilities and high costs make it difficult to meet the demands of today’s modern and highly flexible power systems. Thanks to its abundant solar energy resources, Australia is likely to achieve a major development in its energy transition with PV power generation. In general, the need for energy security is more urgent for developing countries, typically India and Southeast Asian countries. Therefore, the Russia-Ukraine conflict will not cause a change in direction in these countries’ energy policies in the short term. However, if gas prices remain high for a long period of time, it may cause a change in the energy choices of developing countries, such as improving the economics of renewable energy, thus making more renewable electricity available to these countries.

Other Countries and Regions Regions such as Latin America and Africa have little dependence on Russia’s oil and gas resources, but highly volatile oil and gas prices have an indirect impact on them. For Latin America, volatile oil and gas prices may drive its energy structure toward hydropower, nuclear power and renewable energy; while for sub-Saharan African

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% 100 90 80 70 60 50 40 30 20 10 0

Year 2019 2020 Petroleum Natural gas Coal Nuclear energy Hydro energy Wind energy Solar power Other renewable energy Others

Fig. 1.12 Australia’s power generation structure. Source BP Energy Statistics, 2021 Fig. 1.13 Australia’s gas export destinations (2020). Source BP Energy Statistics, 2021

Mexico 1% India 2% Thailand 0 Malaysia 3% Chile 0 Singapore 3% Taiwan, China 6% Korea 10%

China 38%

Japan 37%

countries, development opportunities may arise from Europe’s search for new oil and gas resources and the global demand for minerals for new energy development. Latin America can be divided into two units: Central America and the Caribbean, as well as South America. Mexico, a major oil and gas producer in Central America, can meet its own and regional oil and gas needs and export to the US and other regions, including China. South American countries are not highly dependent on natural gas imports, with imports accounting for about 16% and 30% of Argentina’s and Brazil’s gas consumption, respectively, in 2020. The share is slightly higher in Chile, at 60%, but Chile’s gas consumption is now high. The main sources of gas imports to South America are the US and Bolivia, while imports from Russia are almost nil (see Fig. 1.14). Brazil in South America is water-rich and its power generation structure is dominated by hydropower, which accounts for 64% of Brazil’s

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power generation structure in 2020. Argentina is dominated by natural gas power generation, accounting for 56% of its total power generation in 2020 (see Fig. 1.15). Most of sub-Saharan Africa will not have sufficient policy space to cope with the impact of the shock when the Russia-Ukraine conflict breaks out, which is likely to exacerbate socioeconomic stress, increase vulnerability of public debt, and worsen the pandemic trauma for millions of households and businesses. Higher oil and gas prices will hurt Africa’s power markets, and rising interest rates will adversely affect renewable energy projects. However, the urgent need to move away from Russia will reignite European market’s interest in African oil and natural gas, opening up new opportunities for Africa; and the demand for key minerals such as copper, nickel, and platinum caused by global demand for carbon neutrality will stimulate the development of African mining.

Others:6%

Others:13%

US:29% Qatar:13% Argentina

Brazil

Bolivia:75% Bolivia:65% Others:3% Other African countries:20% US:58% Chile Trinidad and Tobago:20%

Fig. 1.14 Sources of natural gas imports for selected Latin American countries (2020). Source BP Energy Statistics, 2021

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% 100 90 80 70 60 50 40 30 20 10 0 Argentina Brazil Petroleum Natural gas Coal Nuclear energy Hydro energy Wind energy Solar power Other renewable energy Others

Fig. 1.15 Power generation structure in selected South American countries (2020). Source BP Energy Statistics, 2021

Conclusion This paper, starting from the background of the outbreak of the Russia-Ukraine conflict, analyzes the impact of the Russia-Ukraine conflict on the global political economy, and then focuses on the impact of the conflict on global energy development, including the direct impact on the global oil and gas market and its expected direction, as well as the impact on the energy structure and energy transition process in various regions. Overall, the outbreak and continuation of this conflict will have a profound impact on the world political and economic landscape, reshaping the global political and economic structure. The conflict has directly led to drastic shocks in global commodity prices, and exacerbated the global supply chain crisis, thus the world economy is caught in a dilemma of simultaneous stagflation and accelerated reverse globalization. The Russia-Ukraine conflict has triggered a global energy crisis. There is a change in the global energy supply–demand landscape, where the US and Saudi Arabia, two major oil and gas producers, will have a significantly higher “energy voice,” while Russia will not be able to return to its former position in the sector due to the impact on its oil and gas production. The crisis has once again raised awareness of the importance of energy independence in many countries, and under the goal of carbon neutrality, new energy is undoubtedly a more suitable option to reduce the country’s dependence on fossil fuel imports. Although the conflict may have some impact on the process of green and low-carbon energy transition in the short term, this transition trend will not change in the long term. In fact, after this global energy price spike, on the one hand, the rising price of fossil fuels has stimulated green energy technology innovation; on the other hand, many countries have realized the importance of enhancing their energy independence and need to reduce their dependence on

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fossil fuel imports through clean energy with relatively higher independence under the carbon neutrality target.

Bibliography Accenture (2022) Balkans regional power industry research report Benton TG, Froggatt A, Wellesley L, Grafham O, King R, Morisetti N, Schröder P (2022) The Ukraine war and threats to food and energy security cascading risks from rising prices and supply disruptions. https://www.chathamhouse.org/sites/default/files/2022-04/2022-04-12-ukr aine-war-threats-food-energy-security-benton-et-al.pdf China-EU Energy Cooperation Platform (2020) China-EU power market and power system China Merchants Bank Research Institute (2019) Special report on the power construction industrysuggested focus on power investment in Southeast Asia to enhance cross-border services. Last Accessed 14 Nov 2019 China New Energy International Alliance (2021) Study on promoting overseas investment in renewable energy by Chinese companies Downs ES (2007) The fact and fiction of Sino-African energy relations. China Security, 3(3):42–68 EMBER (2022) Global electricity review. Last Accessed 30 Mar 2022 European Commission (2011) Speaking with one voice-the key to securing our energy interests abroad. Press Release. https://ec.europa.eu/commission/presscorner/detail/en/IP_11_1005 Greenpeace Sichuan Center for Circular Economy Research (2019) China’s overseas investment in wind power is expected to help South and Southeast Asia achieve energy transition and sustainable development goals as soon as possible. Last Accessed 19 June 2019 Joint Study of Asian Development Bank and Asian Development Bank Institute (2009) Improving infrastructure for a better Asia. Asian Development Bank and Asian Development Bank Institute Komlev S (2021) Evolution of Russian gas supple to Europe: contracts and prices. Presentation at 34th WS2 GAC. https://minenergo.gov.ru/system/download/14146/158148 Lewis P (1982) Gas pipeline is producing lots of steam among Allies. New York Times. https://www.nytimes.com/1982/02/14/weekinreview/gas-pipeline-is-producing-lots-ofsteam-among-allies.html. Last Accessed 14 Feb 1982 Le Coq C, Paltseva E (2012) Assessing gas transit risks: Russia versus the EU. Energy Policy (4) Le Coq C, Paltseva E (2013) EU and Russia gas relationship at a crossroads, in Russian energy and security up to 2030. Oxenstierna S, Tynkkynen VP (eds) Routledge Le Coq C, Paltseva E (2020) Covid-19: news for Europe’s energy security. FREE Policy brief Le Coq C, Paltseva E (2022) What does the gas crisis reveal about European energy security? https:// freepolicybriefs.org/wp-content/uploads/2022/01/freepolicybriefs20220124-1.pdf Le Coq C, Morega J, Mulder M, Schwenen S (2018) Gas and the electrification of heating & transport: scenarios for 2050. CERRE report Luft G (2017) Silk road 2.0: US strategy toward China’s belt and road initiative. Atlantic Council Strategy Paper No. 11. October 2017 Ma X, China’s global power database. Global Development Policy Center, Boston University Nedopil C (2021) Director IIGF Green BRI Center. China’s Investments in the belt and road initiative (BRI) in 2020: a year of COVID-19. Beijing Office of the Leading Group for Promoting the Belt and Road Initiative (2019) The belt and road initiative progress. Contributions and Prospects, Foreign Languages Press Co. Ltd., Beijing, China Olofsgård A, Strömberg S (2022) Environmental policy in Eastern Europe. SITE Development Day 202. FREE Policy Brief. https://freepolicybriefs.org/2022/01/10/environmentalpolicy-ineastern-europe-site-development-day-2021/

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Professional Committee on Renewable Energy (2020) China association of circular economy. Renewable energy investment trends in and suggestions for the belt and road countries. Stern J (2002) Security of European natural gas supplies-the impact of import dependence and liberalization. Royal Institute of International Affairs. http://www.chathamhouse.org.uk/files/ 3035_sec_of_euro_gas_jul02.pdf Tsinghua Wudaokou Institute for Green Innovation (2020) Renewable energy project investment and financing patterns, issues and recommendations in the belt and road countries United Nations (2022) Global impact of war in Ukraine on food, energy and finance systems. Last Accessed 13 Apr 2022 Zachmann G, McWilliams B, Sgaravatti G (2021) How serious is Europe’s natural gas storage shortfall? https://www.bruegel.org/2021/12/how-serious-iseuropes-natural-gas-storage-shortfall/

Qiang Liu Director, Department of Energy Security and New Energy, Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences. Chen Pan Assistant Researcher, Department of Energy Security and New Energy, Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences.

Chapter 2

China’s Carbon Emission Peak Goals, Strategies and Policies Anjun Hu

China’s Goals for Carbon Emission Peak As global greenhouse gas levels have continued to break historical records in recent years, the entire climate system has undergone changes on a scale unprecedented in thousands of years. The Earth is a non-linear and complex system where the continuous increase of greenhouse gas concentration will trigger the rapid melting of a large number of ice caps, large-scale changes in ocean circulation, and positive feedback of global warming, making sudden and potentially irreversible changes to the planet. The current year-round complex and volatile climate state have provided humanity with a preview of the devastating economic, social, and geopolitical impacts of a full-blown climate crisis and ecosystem collapse. To protect this planet of mankind, the international community has acted in concert, and as a rising power, China has been actively assuming international responsibility. At the general debate of the 75th Session of the United Nations General Assembly on September 2020, President Xi Jinping announced that China would scale up its Intended Nationally Determined Contributions by adopting more vigorous policies and measures, strive to peak CO2 emissions before 2030, and achieve carbon neutrality before 2060. President Xi’s speech clarifies China’s timeline for peak carbon emissions and carbon neutrality, demonstrating China’s strategic determination to accelerate the construction of ecological civilization and its role as a great nation to actively address climate change and promote the building of a community of human destiny.

A. Hu (B) Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_2

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Compared with developed economies, China’s energy supply structure is characterized by high carbon emissions, a large carbon emission base, a low level of economic development at the time of peak carbon emissions, and a short time interval from peak carbon emissions to carbon neutrality, and these characteristics determine that China needs to make strenuous efforts to achieve the goals of peak carbon emissions and carbon neutrality. First, China’s energy supply structure shows a high carbon emission. In 2019, the shares of coal consumption in primary energy consumption in the UK, EU, US and Japan are 3.3%, 11.2%, 12.0% and 26.3%, respectively, while the share in China is 57.6%. Second, the carbon emission base is large in China. When the UK, EU, US and Japan reached peak carbon emissions, their carbon emissions accounted for 4.5%, 25.0%, 19.6% and 4.3% of the world carbon emissions respectively, while China’s carbon emissions accounted for 28.8% in 2019. Third, China will still be at a relatively low level of economic development when it reach peak carbon emissions. According to the constant price in 2010, the GDP per capita of the UK, EU, US and Japan will reach $20,421.0, $19,395.9, $49,856.3 and $45,165.8 respectively when they reach peak carbon emissions, while the GDP per capita of China is expected to reach $14,118.0 in 2030. Fourth, the time interval from peak carbon emissions to carbon neutrality is short. The UK, EU, US and Japan reached peak carbon emissions in 1973, 1979, 2007 and 2008, respectively, and are committed to achieving carbon neutrality by 2050. The intervals from peak to neutral are 77 years, 71 years, 43 years and 42 years respectively, while China has only about 30 years of time (see Table 2.1). Peak carbon emissions is a prerequisite for carbon neutrality, and the timing and peak directly determine the implementation cost of carbon neutrality. Therefore, it is of great significance to achieve peak carbon emissions ahead of schedule and to reduce the peak of carbon emissions for better carbon neutrality. As China is still in the primary stage of socialism and will be in the long-term, facing the huge Table 2.1 Comparison of carbon emission characteristics of representative countries and regions. Unit Constant dollar value in 2010, % Country/region Coal consumption in 2019/primary energy consumption

Proportion of GDP per capita at world carbon peak carbon emissions at peak emissions carbon emissions

Time interval from peak carbon emissions to carbon neutrality

UK

3.3

4.5

20421.0

1973–2050

EU

11.2

25.0

19395.9

1979–2050

US

12.0

19.6

49856.3

2007–2050

Japan

26.3

4.3

45165.8

2008–2050

China

57.6

28.8*

8254.5* 14118.0**

2030–2060

Source BP Statistical Review of World Energy, WDI Database for 2021 from World Bank, Energy & Climate Intelligence Unit. Net Zero Emissions Race, 2021. https://eciu.net/netzerotracker/map Note * represents data selected for 2019 due to the impact of the COVID-19 outbreak. ** represents projections for 2030 based on real growth of 5%

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29

pressure of carbon emission reduction, it needs to balance the multi-dimensional goals of economic growth, employment stability, environmental improvement, industrial upgrading, security operation, etc., and needs to coordinate the multiple links involved in the process of green transformation, such as asset stock, future increment, technology path, financial constraints, norms and standards, policy measures, etc. Its multiple contradictions are intertwined and very complex. Therefore, to achieve peak carbon emissions, we must focus on the principal contradiction. China’s carbon emissions are significantly concentrated in a few major industries and regions, so these high-emission industries and regions are the principal contradiction in achieving peak carbon emissions. From the perspective of each province and region, carbon emissions also show significant industrial and spatial concentration. To promote China’s early achievement of peak carbon emissions, we should, based on the principles of seeking progress in a stable manner and adapting to local conditions, focus on high-emission industries and high-emission regions, and use a combination of price mechanisms and government regulations to promote carbon emission reduction.

China’s Strategies for Carbon Emission Peak Spatial Concentration of Carbon Emissions at the National Level Concentration of Carbon Emissions The main methods to study the concentration of industries and regions include CRn index, Herfindahl–Hirschman index (HHI), Harlequin-Key index (HK index), entropy index, Gini coefficient, agglomeration index, spatial statistics and spatial measurement. In this paper, we choose carbon emission proportion to measure the concentration of carbon emissions, which can not only reflect the concentration of carbon emissions more directly on the whole, but also can clearly understand which individuals belong to high-emission industries and high-emission regions. The carbon emission proportion is essentially the same as the CRn index, which is the ratio of the carbon emissions of an industry or region to the overall carbon emissions, and is calculated as follows: ∑ Ri = Ci / iCi where, i represents the industry or region; Ri is the carbon emission proportion of ∑ industry or region i; Ci is the carbon emission of industry or region i; and i Ci is the overall carbon emission.

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Based on the availability of data, carbon emission proportions were calculated using data from 2000–2018 in order to screen out high-emission industries and highemission regions at both national and provincial spatial scales. Among them, the industrial data include 44 subdivided industries covering three industries, and the spatial data include three spatial units at national, provincial and prefecture levels; the national and provincial data cover the period from 2000 to 2018, while the prefecture level data cover the period from 2000 to 2017. The carbon emission structure has a strong stability, and the transformation of the energy supply structure with high carbon emissions is a long-term process, so the data from 2000 to 2018 can show the transformation of the carbon emission pattern in a more comprehensive way.

Industrial Concentration of Carbon Emissions By comparing the carbon emission proportions of 44 industries from 2000 to 2018, it is found that the carbon emission proportions of six industries, namely, electricity, steam and hot water production and supply, ferrous metal smelting and rolling processing, non-metallic mineral products, transportation, storage and post and telecommunications services, chemical raw materials and chemical products, and petroleum processing and coking, are relatively large and have long been at the top, significantly higher than other industries. For this reason, these six industries are defined as the six high-emission industries in this paper. Carbon emissions at the national level show a significant industrial concentration. From 2000 to 2018, the proportion of carbon emissions of the six high-emission industries in the national carbon emissions has increased rapidly, from 69.2% in 2000 to 87.6% in 2018. During this period, the proportion has been at a high level of over 80% since 2010, and reached 88.3% in 2013. With China’s economy entering a new normal and high-quality development becoming the theme of the times, this proportion declined slightly in 2018 (see Fig. 2.1). There are two main reasons for the growing industrial concentration of carbon emissions in China in general: Firstly, China’s energy supply structure is dominated by coal, the energy utilization efficiency is low, and the high energy-consumption characteristics of the six highemission industries determine the industrial concentration of China’s carbon emissions. Secondly, since the reform and opening up, especially since the accession to the World Trade Organization, China has taken the initiative to join the international division of labor system and gradually developed into a world manufacturing base, which is an important reason for the rapid growth of carbon emissions in China’s six high-emission industries.

Spatial Concentration of Carbon Emissions Carbon emissions at the national level show a high degree of spatial concentration. From the provincial distribution of carbon emissions in 2018, the nine provinces with the highest carbon emissions account for 55.6% of the national carbon emissions,

2017

2018

2016

2014

31

2015

2013

2011

2012

2010

2008

2009

2007

2005

Carbon emissions

2006

2003

2004

2001

2000

Billion tons 90 80 70 60 50 40 30 20 10 0

2002

2 China’s Carbon Emission Peak Goals, Strategies and Policies % 90 80 70 60 50 40 30 20 10 0 Year

Share of carbon emissions (right axis)

Fig. 2.1 Evolution of carbon emissions and carbon emission proportion of the six high-emission industries in China from 2000 to 2018. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

and the 18 provinces with the largest carbon emissions account for 81.7%. Among them, Hebei Province and other nine provinces not only have large carbon emissions, but also have high carbon emission intensity, all of which are higher than the national average (1.0 ton/ten thousand yuan, see Fig. 2.2). Billion tons 10 9 8 7 6 5 4 3 2 1 Hebei Shandong Jiangsu Inner Mongolia Guangdong Shanxi Liaoning Henan Xinjiang Anhui Zhejiang Hubei Hunan Sichuan Shaanxi Fujian Guizhou Heilongjiang Jiangxi Guangxi Yunnan Jilin Ningxia Shanghai Gansu Chongqing Tianjin Beijing Qinghai Hainan Tibet

0

Province

Fig. 2.2 Carbon emissions and carbon emission intensity of each province in 2018. Note Data of Tibet Autonomous Region are for 2015. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

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The energy supply structure with high carbon emissions and low energy use efficiency determine the high-emission industrial structure, while the spatial distribution of high-emission industries determines the spatial pattern of carbon emissions The six high-emission industries are the mainstay of carbon emissions. In 2018, in the nine provinces with the highest carbon emissions, the carbon emissions of the six high-emission industries accounted for 53.3% of the national carbon emissions; in the 18 provinces with the highest carbon emissions, the proportion reached 76.4%. Both of these proportions are highly similar to the proportion of carbon emissions in the corresponding provinces in the national carbon emissions, indicating that the spatial distribution of the six high-emission industries determines the provincial distribution of carbon emissions.

Spatial Concentration of Carbon Emissions at the Provincial Level Industrial Concentration of Carbon Emissions Carbon emissions are also highly concentrated by industry in each province. By comparing the carbon emission proportion of 44 segmented industries in each province in 2018, we selected industries whose cumulative carbon emissions accounted for 80% in each province. The study found that each province is only involved in 2–9 industries, and a total of 11 industries are involved. Among them, the six high-emission industries have the widest distribution, while the other industries are less distributed in the provinces (see Fig. 2.3). In order to further verify the spatial concentration of carbon emissions of the six high-emission industries in each province, the proportion of carbon emissions of the six industries in each province from 2000 to 2018 was calculated. The results show that the proportion of carbon emissions of the six high-emission industries to the carbon emissions of each province from 2000 to 2018 is highly concentrated and stable. In terms of the mean value of the proportion, it ranges from 68.1% (Beijing) to 90.9% (Jiangsu), and the larger mean value reflects the higher industrial concentration of carbon emissions. The standard deviation of the proportion ranges from 1.0 (Guangdong Province) to 9.4 (Xinjiang Uygur Autonomous Region), and the smaller standard deviation reflects the higher stability of the proportion (see Fig. 2.4). Therefore, like the national level, the six high-emission industries nationwide are also highly concentrated in carbon emissions at the provincial level.

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Tons/10000 yuan 6 5 4 3 2 1 Ningxia Inner Mongolia Shanxi Xinjiang Hebei Liaoning Gansu Heilongjiang Qinghai Jilin Guizhou Shandong Guangxi Anhui Shaanxi Tianjin Jiangxi Yunnan Henan Hainan Hunan Jiangsu Hubei Chongqing Sichuan Fujian Zhejiang Guangdong Shanghai Beijing Tibet

0

Province

Fig. 2.3 Carbon emissions and carbon emission intensity of each province in 2018 (continued). Note Data of Tibet Autonomous Region are for 2015. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

Agriculture, forestry, fishery and water resources Oil and gas mining Coal mining Chemical raw materials and chemical products industry Other industries Wholesale, retail trade and food service Petroleum processing and coking industry Non-metallic mineral products industry Transportation, storage and postal services Ferrous metal smelting and rolling processing industry Electricity, steam and hot water production and supply industry

1 1 4 4 6 6 6 22 24 24 30

Fig. 2.4 Number of provinces in which the cumulative percentage of carbon emissions reached 80% in 2018 for the 11 industries. Note Data of Tibet Autonomous Region is unavailable. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

Spatial Concentration of Carbon Emissions Carbon Emissions in Urban and Rural Areas In 2020, China’s urbanization rate reached 63.9%, with only the Tibet Autonomous Region having an urbanization rate of less than 50% among provincial-level administrative regions, and municipal districts of cities above the prefecture level accounting for 61.3% of the country’s GDP. According to the law of evolution of Northam’s S-curve and the current development stage of China’s urbanization from rapid to decelerating, we introduce the primary and secondary terms of urbanization rate and

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Jiangsu Ningxia Jiangxi Zhejiang Shanxi Fujian Inner Mongolia Hainan Gansu Hebei Anhui Liaoning Guangdong Guangxi Hubei Shandong Shanghai Henan Tianjin Jilin Yunnan Shaanxi Xinjiang Hunan Heilongjiang Chongqing Sichuan Guizhou Qinghai Beijing

% 100 90 80 70 60 50 40 30 20 10 0

Mean value

10 9 8 7 6 5 4 3 2 1 0 Province

Standard deviation (right axis)

Fig. 2.5 Mean and standard deviation of the proportions of carbon emissions of the six highemission industries in each province from 2000 to 2018. Note Data of Tibet Autonomous Region is unavailable. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

predict that China’s urbanization rate will reach 71.6% in 2030. As the main concentration area for population and economic activities, cities are the key areas for carbon emissions. Due to the differences in economic development levels and spatial distribution of high-emission industries between urban and rural areas, the urban and rural carbon emissions of each province show some variability. In 2018, the rural carbon emissions of eight provinces, including Yunnan Province, Guizhou Province, Hebei Province, Xinjiang Uygur Autonomous Region, Gansu Province, Inner Mongolia Autonomous Region, Shanxi Province, and Jilin Province, were higher than their urban carbon emissions (see Fig. 2.5). Most of these provinces are located in northern regions or have abundant coal reserves, and have higher rural carbon emissions. On the one hand, it is related to the rapid industrialization of rural areas, and on the other hand, it is affected by the winter heating in northern rural areas. To reduce carbon emissions from rural areas, we need to reduce carbon emissions from rural industries as well as support clean energy development in rural areas, implementing clean heating projects and upgrading rural electrification.

Carbon Emissions at the Prefectural Level In order to identify the spatial structure of carbon emissions within each province, the proportion of carbon emissions of each prefecture-level administrative region in the province in 2017 was calculated based on the availability of data, and the regions with a cumulative percentage reaching 80% were selected (see Table 2.2). When the cumulative percentage of carbon emissions reaches 80%, the cumulative percentage

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35

of the number of prefectural-level administrative regions is smaller than the cumulative percentage of carbon emissions in all selected provinces except Chongqing (see Fig. 2.6). Among them, nine provinces emitted more than 80% of carbon dioxide with less than 60% of prefectural-level administrative regions, and 24 provinces emitted more than 80% of carbon dioxide with less than 70% prefectural-level administrative regions. This indicates that although these prefecture-level administrative regions with large differences in terms of economic development level, resource endowment, industrial structure, and ecological positioning differ greatly in terms of carbon emissions, carbon emissions at the province level also show a strong spatial concentration (Fig. 2.7).

Policy Suggestions for Achieving Peak Carbon Emissions in China China’s carbon emissions are strongly concentrated in industry and space, and there are large scale and wide scale carbon transfers between provinces. Achieving peak carbon emissions is subject to the constraints of economy, employment and environment, and it is necessary to deal with the relationships between development and emission reduction, overall and local, and short term and medium and long term. To this end, we should adhere to the principles of seeking progress in a stable manner and adapting to local conditions, focusing on high-emission industries and highemission regions, and incentivizing carbon emission reduction using a combination of price mechanisms and government regulations. Based on these judgments, this paper makes the following suggestions.

Integrate Different Measures to Promote Smooth Emission Reduction in High-Emission Industries Given the industrial concentration of carbon emissions, reducing carbon emissions from the six high-emitting industries is the key to achieving peak carbon emissions. To promote the stable emission reduction of the six high-emission industries, first, we should improve the market mechanism and develop a micro environment that stimulates enterprises to save energy and reduce emissions. There is a need to establish a sound system for basic statistics and accounting of national, local and corporate greenhouse gas emissions to clarify the carbon budget and improve the carbon market. Pension funds and other capital pools should play a role in the innovative carbon finance market to provide financial support for the green transformation of enterprises. On this basis, we should actively carry out carbon emissions trading and levy carbon taxes; improve energy use efficiency and carry out energy substitution to reduce carbon emissions by raising the price of carbon dioxide, incentivizing

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Table 2.2 Prefectural-level administrative regions with cumulative percentage of carbon emissions reaching 80% by province in 2017 Province

Prefecture-level administrative regions (in descending order of emissions)

Number of prefecture-level administrative regions; cumulative percentage of carbon emissions (%)

Total number of prefecture-level administrative regions

Beijing

Tongzhou District, Shunyi District, Chaoyang District, Daxing District, Changping District, Fangshan District, Haidian District, Fengtai District

8; 80.4

16

Tianjin

Binhai New Area, Wuqing District, Jinghai District, Dongli District, Xiqing District, Beichen District, Baodi District, Jizhou District, Jinnan District

9; 84.8

16

Hebei

Tangshan City, Shijiazhuang City, Baoding City, Cangzhou City, Handan City, Langfang City, Xingtai City

7; 81.9

11

Shanxi

Linfen City, Luliang City, Datong City, Taiyuan City, Jinzhong City, Yuncheng City, Xinzhou City, Changzhi City

8; 82.6

11

Inner Mongolia

Erdos City, Hulun Buir City, Hohhot City, Baotou City, Chifeng City, Tongliao City, Xilin Gol League, Ulanqab City

8; 84.5

12

Liaoning

Shenyang City, Dalian City, Anshan City, Tieling City, Panjin City, Yingkou City, Jinzhou City, Liaoyang City, Huludao City, Chaoyang City

10; 82.5

14

Jilin

Changchun City, Jilin City, Siping City, Yanbian Korean Autonomous Prefecture, Tonghua City, Songyuan City

6; 84.7

9

Heilongjiang

Harbin City, Daqing City, Suihua City, Qiqihar City, Jiamusi City, Shuangyashan City, Mudanjiang City, Jixi City

8; 82.3

13

Shanghai

Pudong New Area, Fengxian District, Qingpu District, Songjiang District, Jiading District, Chongming District, Minhang District, Jinshan District

8; 83.5

16

Jiangsu

Suzhou City, Nanjing City, Wuxi City, Nantong City, Xuzhou City, Yancheng City, Changzhou City, Yangzhou City, Taizhou City

9; 80.8

13

(continued)

2 China’s Carbon Emission Peak Goals, Strategies and Policies

37

Table 2.2 (continued) Province

Prefecture-level administrative regions (in descending order of emissions)

Number of prefecture-level administrative regions; cumulative percentage of carbon emissions (%)

Total number of prefecture-level administrative regions

Zhejiang

Ningbo City, Hangzhou City, Jinhua City, Wenzhou City, Jiaxing City, Taizhou City, Shaoxing City

7; 84.8

11

Anhui

Hefei City, Fuyang City, Chuzhou City, Suzhou City, Lu’an City, Wuhu City, Bozhou City, Anqing City, Huainan City, Bengbu City, Xuancheng City

11; 84.4

16

Fujian

Quanzhou City, Fuzhou City, Zhangzhou City, Xiamen City, Putian City, Longyan City

6; 83.8

9

Jiangxi

Nanchang City, Ganzhou City, Jiujiang City, Shangrao City, Yichun City, Ji’an City, Fuzhou City

7; 84.8

11

Shandong

Weifang City, Qingdao City, Linyi City, Yantai City, Jinan City, Jining City, Dezhou City, Binzhou City, Dongying City, Zibo City, Heze City, Liaocheng City

12; 84.1

16

Henan

Zhengzhou City, Nanyang City, Xinxiang City, Luoyang City, Anyang City, Zhoukou City, Pingdingshan City, Shangqiu City, Zhumadian City, Xuchang City, Jiaozuo City, Puyang City

12; 82.6

17

Hubei

Wuhan City, Xiangyang City, Yichang City, Huanggang City, Jingzhou City, Xiaogan City, Shiyan City, Huangshi City, Jingmen City

9; 82.5

13

Hunan

Changsha City, Chenzhou City, 9; 83.4 Yueyang City, Hengyang City, Zhuzhou City, Changde City, Xiangtan City, Yongzhou City, Loudi City

14

Guangdong

Guangzhou City, Foshan City, Dongguan City, Huizhou City, Shenzhen City, Jiangmen City, Zhongshan City, Shantou City, Qingyuan City, Zhanjiang City, Jieyang City, Zhaoqing City, Maoming City

21

13; 80.1

(continued)

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A. Hu

Table 2.2 (continued) Province

Prefecture-level administrative regions (in descending order of emissions)

Number of prefecture-level administrative regions; cumulative percentage of carbon emissions (%)

Total number of prefecture-level administrative regions

Guangxi

Nanning City, Liuzhou City, Guilin City, 9; 80.1 Yulin City, Beihai City, Guigang City, Baise City, Laibin City, Qinzhou City

14

Hainan

Haikou City, Sanya City, Danzhou City, 9; 83.7 Wanning City, Lingshui Li Autonomous County, Qionghai City, Wenchang City, Chengmai County City, Changjiang Li Autonomous County

4

Chongqing

Yubei District, Shapingba District, Jiulongpo District, Nanan District, Fuling District, Beibei District, Changshou District, Wanzhou District, Banan District, Yongchuan District, Jiangbei District, Bishan District, Jiangjin District, Hechuan District, Tongliang District, Dazu District, Kaizhou District, Rongchang District, Dianjiang County, Qijiang District, Dadukou District

21; 80.5

26

Sichuan

Chengdu City, Mianyang City, 12; 80.0 Panzhihua City, Deyang City, Liangshan Yi Autonomous Prefecture, Nanchong City, Dazhou City, Leshan City, Guangyuan City, Suining City, Meishan City, Neijiang City

21

Guizhou

Guiyang City, Zunyi City, Liupanshui City, Qianxinan Buyi and Miao Autonomous Prefecture, Qiannan Buyi and Miao Autonomous Prefecture, Qiandongnan Miao and Dong Autonomous Prefecture, Bijie City

7; 86.4

9

Yunnan

Kunming City, Qujing City, Dali Bai Autonomous Prefecture, Honghe Hani and Yi Autonomous Prefecture, Yuxi City, Baoshan City, Chuxiong Yi Autonomous Prefecture, Dehong Dai and Jingpo Autonomous Prefecture, Lijiang City

9; 83.1

16

Tibet

Lhasa City, Shannan City, Shigatse City 3; 86.8

7 (continued)

2 China’s Carbon Emission Peak Goals, Strategies and Policies

39

Table 2.2 (continued) Province

Prefecture-level administrative regions (in descending order of emissions)

Number of prefecture-level administrative regions; cumulative percentage of carbon emissions (%)

Total number of prefecture-level administrative regions

Shaanxi

Yulin City, Yan’an City, Xi’an City, Weinan City, Xianyang City

5; 81.1

10

Gansu

Lanzhou City, Qingyang City, Jiuquan City, Tianshui City, Dingxi City, Baiyin City, Pingliang City, Longnan City, Zhangye City

9; 82.6

14

Qinghai

Haixi Mongolian and Tibetan Autonomous Prefecture, Xining City, Haidong Prefecture, Hainan Tibetan Autonomous Prefecture

4; 86.9

8

Ningxia

Yinchuan City, Wuzhong City, Shizuishan City, Zhongwei City

4; 89.4

5

Xinjiang

Akesu Prefecture, Bayingolin Mongolian Autonomous Prefecture, Changji Hui Autonomous Prefecture, Yili Kazakh Autonomous Prefecture, Kashgar Prefecture, Urumqi City, Karamay City, Tacheng Prefecture, Turpan City

9; 81.5

14

Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database Note Hainan Province includes 4 prefecture-level cities and 15 province-administered county-level administrative units. Data of Tibet Autonomous Region are for 2014

enterprises to invent low-carbon or zero-carbon technologies, and increasing green investment. Second, to promote smooth emission reduction in the six high-emission industries, appropriate carbon reduction programs need to be developed according to the characteristics of the industries. (1) The power industry needs to reshape all aspects from power generation, transmission and distribution to consumption, in order to form a new power system with horizontal multi-energy complementarity and vertical coordination of source, network, load and storage, thus reducing carbon emissions. Specifically, we should strictly approve new coal-fired power plants, phase out backward coal-fired capacity, rationalize the price mechanism, improve the efficiency of existing coal-fired power plants, and transform coal-fired power from a “main power source” to a “base-load power source with equal emphasis on regulating power source”; promote commercialization of a number of promising energy storage devices and technologies, and actively develop smart grid to enhance the absorption capacity of new energy power; deeply implement the time-of-use power pricing

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Beijing Jiangsu Tianjin Hainan Shanghai Chongqing Guangxi Heilongjiang Hubei Sichuan Liaoning Shandong Guangdong Anhui Shaanxi Zhejiang Henan Qinghai Jiangxi Fujian Hunan Ningxia Jilin Shanxi Inner Mongolia Gansu Xinjiang Hebei Guizhou Yunnan

10 9 8 7 6 5 4 3 2 1 0

Province

Fig. 2.6 Ratio of urban to rural carbon emissions in each province in 2018. Note Data of Tibet Autonomous Region is unavailable. The dotted line indicates that the ratio of urban to rural carbon emissions is 1. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database % 100 90 80 70 60 50 Chongqing Ningxia Guizhou Shandong Shanxi Liaoning Henan Hubei Jiangsu Anhui Fujian Jilin Inner Mongolia Xinjiang Gansu Guangxi Hunan Jiangxi Zhejiang Hebei Guangdong Heilongjiang Sichuan Yunnan Tianjin Qinghai Shaanxi Shanghai Beijing Hainan Tibet

40

Province

Cumulative percentage of prefecture-level administrative regions Cumulative percentage of carbon emissions

Fig. 2.7 Cumulative percentage of carbon emissions at the prefecture level and cumulative percentage of carbon emissions when the cumulative percentage of carbon emissions reached 80% in 2017. Note Hainan Province includes 4 prefecture-level cities and 15 province-administered county-level administrative units. Data of Tibet Autonomous Region are for 2014. Source Carbon Emission Accounts and Datasets (CEADs) and Wind Database

policy, incentivizing large power-using units to build combined cooling, heating and power supply and energy storage facilities, and to improve their power efficiency by taking the measure of peak load shifting and enhancing their demand response capability. (2) Industries that produce and supply steam and hot water should improve

2 China’s Carbon Emission Peak Goals, Strategies and Policies

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energy use efficiency, fully promote “gas to electricity” to increase the proportion of renewable energy use, and retrofit their non-energy efficient buildings, etc. to reduce carbon emissions. (3) Four major manufacturing industries, including ferrous metal smelting and rolling processing industry, non-metallic mineral products industry, chemical raw materials and chemical products industry, and petroleum processing and coking industry, are facing common problems such as more backward production capacity, higher employment pressure, and insufficient supply of high-end products. To reduce the carbon emissions of the four major manufacturing industries, we should take into account the goals of peak carbon emissions and carbon neutrality, the balance between long-term development and short-term smooth operation of the industries, and employment stability, among others. First, we must improve the market and compliance-oriented long-term mechanism for resolving excess capacity, and reduce carbon emissions by focusing on reducing production capacity with poor environmental performance, high energy consumption and relatively backward process equipment. Second, we should aim at the next-generation production processes, energy saving and emission reduction, circular economy and carbon dioxide recycling technology, build a group of pilot enterprises by increasing investment in scientific and technological innovation and making efforts to break through some core and key technologies, and promote them to combine energy saving and emission reduction with industrial upgrading, thus changing the situation of insufficient high-end products and excessive low-end products. Third, we should improve laws, regulations and supporting policies, accelerate capacity integration through enterprise mergers and reorganization, industrial transfer and capacity replacement, and promote the convergence of production factors in high-quality enterprises and industrial parks to reduce carbon emissions. (4) The transportation and storage industries, on the one hand, need to develop clean energy and promote the decarbonization of transportation power; on the other hand, need to drive innovation in transportation technology, optimization of transportation networks, and improvement of organizational efficiency to reduce carbon emissions. (5) The post and telecommunications service industry, firstly, needs to strengthen disclosure of carbon emission information, enhance public supervision and government regulation, and further activate the momentum of carbon emission reduction. Secondly, it should boost technological innovation, and optimize arithmetic power, algorithms, and arithmetic efficiency, so as to enhance energy utilization efficiency. Lastly, the industry should carry out research and development and application of hydrogen energy, energy storage and other technologies, and expand renewable energy use. Third, the smooth reduction of emissions in the six high-emission industries needs to be supported by stable employment and livelihood protection. Employment is the basis of people’s livelihood and development. In the process of peak carbon emissions, there are both unemployment caused by overcapacity cut and that caused by intelligent upgrading, especially the four manufacturing industries among the six high-emission industries are under pressure to cut overcapacity, where there is a greater need to optimize staffing. To this end, firstly, we should make more efforts to publicize the significance of peak carbon emissions, the standard of capacity reduction, and the path of industrial peak carbon emissions to enterprises and employees in

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high-emission industries, helping them clearly understand the direction of industry development and set stable expectations. Secondly, we should adhere to the general keynote of seeking progress in a stable manner, focus on securing employment, and seize the huge demand of the third industrial revolution for the Internet of Things infrastructure consisting of communications, energy and transportation, while moderately over-investing in order to enhance the absorption of the employment population by the Global Green New Deal. We should also strengthen the training of employees in artificial intelligence technology to enhance their employability in the new economy, new industries, new business models and new modes. Issues such as support for unemployed employees and funding for early retirement should be properly addressed to ease the pains caused by the transition.

Reduce Carbon Emissions in High-Emission Areas Based on Spatial Characteristics Properly The focus should be on high-emission regions, keeping in mind the spatial characteristics and orderly reduction of carbon emissions. First, from the perspective of regional space, the governments at all levels should focus on high-emission regions, and according to the characteristics of each region in terms of economic development level, resource endowment, industrial structure, population employment, ecological function positioning, etc., they should formulate a timetable and roadmap for carbon peaking under the principles of localization and pragmatism, so as to promote different regions to peak carbon emissions in batches in a scientific and orderly manner. High-emission regions with a high level of economic development and stable carbon emissions can take the lead in achieving it through industrial upgrading. As for the high-emission regions with lower economic development level, heavy industrial structure and coal-focused energy structure, they should increase the support in terms of capital, technology and talents to optimize and adjust the industrial structure and energy structure, so as to achieve the peak carbon emission in tandem with the whole country. Since a large number of fossil energy assets in high-emission regions face the risk of being stranded during the carbon emission peaking process, relying solely on market forces to reduce carbon emissions will lead to insufficient incentives. Therefore, reducing carbon emissions requires actively taking advantage of the administrative system with Chinese characteristics. We should strengthen the guidance of public opinion, reinforce the responsibility of local CPC committees and governments, and enhance the intensity of environmental regulations in order to suppress carbon emissions in high-emission provinces and prefectures. Second, from the perspective of urban and rural space, carbon emission reduction in cities should be based on the development stage of the cities, resource endowment, employment pressure, the role and division of labor in the region and industrial chain in which the cities are located, and increase technical support and strengthen supervision and assessment around high-emission industries, so as to stimulate economically

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43

developed cities to achieve carbon emission peak as early as possible, and to promote carbon emission reduction in less developed cities. Meanwhile, optimizing urban spatial structure through urban planning is also an important means to reduce carbon emissions. Specifically, with the goal of improving the quality of cities for living and working, we should explore a smart growth approach to land use, scientifically determine the ratio of various types of land, and vigorously promote a balance between jobs and housing, in order to promote a balanced allocation of housing resources and industrial layout, and a balanced distribution of quality public services to new suburban cities. This will significantly reduce residents’ commuting, lower down energy consumption, and achieve carbon emission reduction. For carbon emission reduction in rural areas, in addition to research and development of emission reduction technologies, development of energy-saving equipment, improvement of soil quality, and enhancement of carbon sequestration and sink capacity of farmland and grassland, we should also focus on implementing clean heating projects and establishing a synergistic mechanism for pollution reduction and carbon reduction. In the process of implementing clean heating projects, we should take into account local conditions and encourage the use of distributed heating, biomass heating, decentralized biomass forming fuel + special environmental protection stoves, solar energy + , water source heat pumps and other methods. We should follow the enterpriseled, government-driven, resident-affordable approaches, and focus on reducing the cost of heating, in order to avoid putting clean heating systems on the shelf. At the same time, we should actively take advantage of the “bottom-up” practice and carry out pilot demonstrations of low-carbon parks and low-carbon communities to form replicable and scalable emission reduction paths and experiences to promote better emission reduction in other regions. In addition, we should vigorously research and develop geo-engineering technologies to enhance ecological carbon sink capacity, which is also an important supplement to the path to promote carbon peaking. Geoengineering technologies can be divided into two major categories: carbon dioxide removal (CDR) and solar radiation management (SRM). At present, the main geoengineering technologies that can be promoted are carbon dioxide capture, utilization and storage (CCUS) technology and bio-energy with carbon capture and storage (BECCS) technology. Research and development of geoengineering technologies should be carried out and international cooperation should be strengthened to promote the maturation and industrialization of each link, which can help to reach the carbon emission peak. Ecological carbon sinks are also a positive and effective way to reduce emissions, but due to the natural environment, China has limited potential to significantly increase ecological carbon sinks. Therefore, we should strengthen the restoration and management of forests, grasslands, wetlands and deserts to increase the capacity of ecological carbon sinks, so as to form a useful supplement to the path of achieving carbon peaks.

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Bibliography Du W, Bo C (2021) Environmental regulation, industrial concentration and environmental pollution. J Xi’an Jiaotong Univ ( Soc Sci Ed) 1:69–77 Fan J, Li J, Yan S et al (2021) China’s biomass energy: analysis of application potential of carbon capture and storage technologies. Therm Power Gener (1):7–17 Gates B (2021) How to Avoid a Climate Disaster. Random House, New York Guo W (2021) Scientific and orderly promotion of provinces and cities to achieve the peak of the ladder. China Dev Obs 21:11–12 Guofeng C (2021) Shandong: doing a good job of closing, upgrading and diverting high energyconsuming industries. China Nonferrous Metals 7:24 Hu A, Sun J (2014) Spatial measurement: models, methods and trends. World Econ Pap 6:111–120 If calculated by administrative area, the concentration of carbon emissions is more prominent Kong X (2019) The key to improve the regional concentration of the cement market in Shanxi, Hebei, Shandong and Henan. China Cem 12:11–13 Liu J (2021) Measures to promote carbon neutrality in transportation. China Transp News (3) Li X (2021) Building a new pattern of steel to start a new low-carbon journey. Ind China 7:21–24 Ma J (2021) How green finance can support China’s 30·60 targets. Int Finance 5:3–7 Min N, Huang H (2021) The development of coal chemical industry in the context of peak carbon emissions and carbon neutrality. Chem Enterp Manag 11:83–84 Nordhaus W (2013) The climate casino. Yale University Press, New Haven Pan J (2016) Construction, challenges and market expansion of carbon emission trading system. Chin J Popul Resour Environ 8:1–5 Qi Y (1998) An empirical analysis of the relationship between industrial concentration and economic performance in China. Manage World 4:99–106 Qimin C (2022) Research on the implementation path of China’s peak carbon emissions and carbon neutrality strategies under the vision of beautiful China. Environ Prot 6:21–25 Rifkin J (2020) Zero carbon society: the rise of ecological civilization and the global green new deal. CCID, Translation Beijing, CITIC Press Rosenberg N (2004) Exploring the black box: technology, economics, and history. In Wang W, Lu R (eds) Translation Beijing, The Commercial Press Sun R (2021) Activating the financial genus of the carbon market: an interview with Jin Penghui, Deputy Director of the Shanghai Branch of the People’s Bank of China, a Member of the National Committee of the Chinese People’s Political Consultative Conference. China Financ 3:69–70 Shan J (2021) The dual carbon target drives green transformation of transportation. China Transp News (3) Song Y (2020) How to change the situation of low-end overcapacity and high-end capacity shortage? China Environ News (3) Wang J (2019) Spatial data analysis tutorial. Science Publishing House, Beijing Wang Y (2021) New strategy for energy security guides historic achievements in energy development-an interview with Zhang Jianhua, Secretary of Leading CPC Member Group and Director of the National Energy Administration of China on the hot topics of the national two sessions. China Electr Power 3:4–5 Wang Z, Tan Q, Xu X (2006) An empirical study on the measurement of industrial agglomeration level. China Soft Sci (3):109–116 Xi Jinping delivers a keynote speech at the general debate of the 75th UN general assembly [EB/ OL]. http://www.xinhuanet.com/mrdx/2020-09/23/c_139389875.htm Zhu Y (2021) Clean heating in the context of peak carbon emissions. China Financ Econ News (2) Zhao Z (2014) Spatial pattern statistics and spatial economic analysis. Science Press, Beijing Zhuang G (2005) Analysis of low carbon development pathways and potential of China’s economy. Int Tech Econ Res 3:8–12

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Anjun Hu Associate Researcher, Institute of Quantitative & Technological Economics, Chinese Academy of Social Sciences; focusing on artificial intelligence and innovation economy, industrial layout and regional imbalance, and energy consumption revolution.

Chapter 3

Carbon Market Outlook in the Context of Global Carbon Neutrality Na Ren, Yi Cai, Zhiyuan Qin, and Ying Zhao

Development Background of Global Carbon Neutrality Climate change is the most rough security issue facing the world today, seriously threatening the survival and development of human society. Since the industrialization revolution, a large amount of carbon dioxide has been emitted into the atmosphere due to the widespread use of fossil energy such as coal and oil, and as the concentration of carbon dioxide rises, the greenhouse gas effect makes the global warming situation intensify. Since 2010, global greenhouse gas emissions have increased by an average of 1.4% per year, and the total global greenhouse gas emissions reached 59.1 billion tons of carbon dioxide equivalents in 2019, the highest level ever. In response to the serious challenge of climate change, the international community has reached a consensus on green, low-carbon and sustainable development. In 1997, more than 100 countries around the world signed the Kyoto Protocol, which stipulates the emission reduction obligations of developed countries and proposes emission reduction mechanisms such as carbon emissions trading. In December 2015, 178 countries adopted the Paris Agreement at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) in Paris, requiring parties to submit long-term low greenhouse gas emission development strategies by the middle of the twenty-first century. By the end of 2021, 51% of the world’s countries have set carbon neutrality targets, with 46 of them committed to achieving carbon neutrality by 2050. As more countries join the forces of carbon reduction and carbon neutrality, both global energy transition and replacement of fossil fuels by clean renewable energy accelerate, marking green, low carbon emission is becoming a major trend for future human development.

N. Ren (B) · Y. Cai · Z. Qin · Y. Zhao Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_3

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The Current Situation of International Carbon Market Development Since the Kyoto Protocol came into force, the carbon trading system has developed rapidly, and countries and regions have started to establish regional carbon trading systems to achieve the goal of carbon emission reduction commitments. At present, there are 25 mandatory emission reduction markets in the world, covering about 16% of GHG emissions, among which China’s carbon trading market is the world’s largest market covering GHG emissions, and the EU carbon trading market is the most liquid and largest market in terms of turnover. According to Refinitiv, the global carbon market will have a turnover of 15.81 billion tons in 2021, of which the EU carbon market will account for 77%; the global carbon market will have a turnover of 759.3 billion euros, of which the EU carbon market will account for 90%. The performance of the international carbon trading market is shown in Fig. 3.1.

EU Carbon Market Prices Rise Steadily Market Transactions in Recent Years As for the primary market, when the EU carbon market was established in 2005, carbon allowances were mainly allocated free of charge, and since then, the free allowances have been gradually reduced. Currently, more than 50% of the allowances are auctioned, and the EU plans to achieve paid allocation of all allowances by 2027. In 2021, the European Energy Exchange (EEX) held 230 auctions of carbon Billion tons 180 160 140 120 100 80 60 40 20 0

2018 2019 2020 2021 Year EU (EU-ETS) UK (UK-ETS) US (RCGI and WCI) China Korea New Zealand

Fig. 3.1 Global carbon market turnover. Source Refinitive, the turnover including auction volume, secondary market volume, etc.

3 Carbon Market Outlook in the Context of Global Carbon Neutrality 10,000 tons 90000 80000 70000 60000 50000 40000 30000 20000 10000 0

2015

2016

2017

2018 2019 EUA EUAA

2020

49

2021 Year

Fig. 3.2 Auction volumes in the EU carbon market. Source Refinitive, and Unipec Research & Strategy (URS)

allowances, with a total of 587 million tons (see Fig. 3.2), 13% less than the total auction volume in 2020. The average auction price was 54.13 euros per ton. In the secondary market, there are three exchanges in Europe that support EUA (Europe Union Allowance) futures, spot and derivatives trading, including ICE Endex in the Netherlands, EEX in Germany and Nasdaq Oslo in Norway. The EUA futures contracts on the three exchanges are designed differently, but all include quarterly contracts for the next few years, with the December 2022 contract as the primary contract. In 2021, the volume of all contracts traded on the ICE Endex for carbon allowance futures was 9.97 billion tonnes, an increase of 12% year-on-year.

EU Carbon Prices Rises Sharply In recent years, as Europe has increased its low-carbon transition efforts and tightened its total carbon market targets year by year, the EU carbon price has gradually climbed. Historically, from 2005 to 2020, the price of EU carbon allowances fluctuated between 10 and 30 euros per ton; from 2021 onwards, the EU carbon market entered its fourth phase, and the European carbon price has set record after record, approaching 100 euros per ton in August 2022, a 200% increase from the end of 2020 (see Fig. 3.3). The reasons for the sharp rise in European carbon prices since 2021 are mainly the following. First, the EU increases its efforts to reduce GHG emissions. In September 2020, the European Commission proposed to reduce GHG emissions by at least 55% by 2030 compared to 1990s levels, higher than the previous target of 40%; Germany announced in May 2021 that it would advance the deadline for achieving carbon neutrality from 2050 to 2045. In order to achieve higher emission reduction targets in Europe, the European Commission’s Fit for 55 plan proposes a more stringent revision of the EU ETS, tightening the total allowances issued, making European companies more aware of the scarcity of allowances and further increasing the demand for allowances in the market.

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Lot (1 lot = 1000 tons) 140000 120000

100

100000

80

80000 60 60000 40

40000

20

20000

0 20 17 -0 20 2-21 17 -0 20 8-21 18 -0 20 2-2 1 18 -0 8 -2 20 1 19 -0 20 2-2 1 19 -0 8 20 20 21 -0 20 2-2 1 20 -0 8 -2 20 21 1 -0 20 2-2 1 21 -0 20 8-2 1 22 -0 2 20 22 21 -0 821

0 Time

All contracts' daily turnover First line contracts for european carbon price in december

Fig. 3.3 Prices of European carbon allowance futures. Source Refinitive, and Unipec Research & Strategy (URS)

Second, ESG has attracted more capital to the carbon markets. As major economies around the world increase their focus on peak carbon emissions and carbon neutrality, strong climate policies and emission reduction targets are attracting more institutional investors to the market. For example, ESG (an acronym for Environment, Social Responsibility, Corporate Governance) is attracting more capital to the carbon markets. ESG funds are using carbon futures as a benchmark for climate risk investments. According to statistics, $685 billion flowed into ESG funds globally from January to December 2021, well above the $542 billion in 2020 and the $285 billion in 2019, and ESG funds now account for 10% of total global fund size. Third, the substitution of coal for gas-fired power generation increases. The rapid recovery of energy demand in the EU in the post-COVID-19 era, coupled with the Russia-Ukraine conflict that led to Russia’s reduction of gas supply to European countries, the coal, gas and electricity prices in European countries remain historically high, and market expectations of a repeat of the European energy crisis in winter have risen. The generation market in European countries mainly considers the substitution between coal and gas power, even though gas power generation has only 50% of the carbon emission factor per kW-h of coal power generation, but when the price of gas reaches a certain level, it will make coal power generation more competitive. Currently, European electricity prices have risen to more than 400 euros per megawatt-hour (over $3 per kW-h), and the price of natural gas in Europe is 2.2 times higher than the price of coal for the same unit of calorific value. Soaring gas prices are driving power plants to coal-fired generation (see Fig. 3.4), thereby increasing the demand for carbon allowances in Europe. Fourth, the European carbon market becomes more active in financial derivatives trading. After the Glasgow Climate Change Conference (COP26) in November 2021,

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MW-h 25000 20000 15000 10000

0

January 2019 March 2019 May 2019 July 2019 September 2019 November 2019 January 2020 March 2020 May 2020 July 2020 September 2020 November 2020 January 2021 March 2021 May 2021 July 2021 September 2021 November 2021 January 2022 March 2022 May 2022 July 2022 September 2022 November 2022* January 2023* March 2023* May 2023*

5000

Germany

France

Netherlands

Time

UK

Fig. 3.4 Coal-fired power generation in four European countries. Source Refinitive, and Unipec Research & Strategy (URS)

global investors have become more enthusiastic about climate investments and the EU carbon market has become more active. According to Reuters data, the average daily volume of EU carbon futures contracts in 2021 was 38,800 lots, up 13% yearon-year. At the same time, the bullish scenario is still fermenting in the market, with positions in the 100 EUR/ton call option on the EUA December 2022 contract having increased from 3,700 lots in August 2021 to 17,100 lots in September 2022.

Transactions in Other International Carbon Markets The California Carbon Market of the US The California Carbon Market of the US was established in 2013 and was linked to the carbon markets of Quebec and Ontario in Canada in 2014 and 2018, respectively, making it a carbon market with wide coverage and influence in North America. The California carbon market covers seven greenhouse gases—CO2 , CH4 , N2 O, SF6 , HFCs, PFCs, and NF3 —and includes facilities that emit more than 25,000 tons of greenhouse gases per year. The California carbon market will initially issue allowances using a combination of free carbon allowances and allowance auctions, with auctions being held quarterly with a reserve price = previous year’s auction reserve price × (5% + CPI year-over-year growth rate for the last 12 months). In August 2022, the California-Quebec carbon market held its 32nd auction at a historically high price of $27.37 per ton, with a total volume of 64.9 million tons, of

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$/ton 35 30 25 20 15 10

2019-02 2019-04 2019-06 2019-08 2019-10 2019-12 2020-02 2020-04 2020-06 2020-08 2020-10 2020-12 2021-02 2021-04 2021-06 2021-08 2021-10 2021-12 2022-02 2022-04 2022-06 2022-08

5

Spot auction volume Average price (right axis)

0 Time

Forward auction volume

Fig. 3.5 Auctions in the California-Quebec carbon market. Source California Air Resources Board; Unipec Research & Strategy (URS)

which 56.96 million tons were sold in spot auctions and 7.94 million tons in forward auctions (see Fig. 3.5).

The RGGI (Regional Greenhouse Gas Initiative) Market of the US In December 2005, seven states of the US, including Delaware and Maine, signed the RGGI framework agreement, creating the world’s first carbon trading system that allocates allowances primarily through auctions. Currently, the RGGI market covers 11 states, including Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Vermont, and Virginia. The RGGI includes fossil fuel-fired generating units with a capacity not less than 25 MW, and the total initial allowance is determined by adding up the total allowances of each member state, with the majority of the initial allowance being issued through auctions. The RGGI provides for a three-year compliance control period in which only 50% of the allowances are submitted each of the first two years, and in the third year, the entire amount of the year’s carbon allowances and the remaining allowances from the previous two years are required to be paid. The quarterly auctions in the RGGI market are held in March, June, September and December. In September 2022, the RGGI held its 57th auction, with an average price of $13.45 per ton, a historically high level, and a total volume of 22.4 million tons (see Fig. 3.6).

Korea’s Carbon Market Established in 2015, the Korea’s carbon market is the first national carbon market in Asia and is currently the only national carbon market in the world that allows the

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10,000 tons 4500 4000 3500 3000 2500 2000 1500 1000 500 0

$/ton 16 14 12 10 8 6 4 2

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Fig. 3.6 Auctions in the RGGI market. Source The Regional Greenhouse Gas Initiative for the North America; Unipec Research & Strategy (URS)

use of foreign carbon credits for compliance. The third phase of the Korea’s carbon market, involving the industries including power, industry, buildings, transportation, waste treatment, and the public sector, covers the period from 2021 to 2025, with total emissions of approximately 600 million tons, accounting for 73.5% of Korea’s total emissions. Korean allowance units (KAUs) and Korean credit units (KCUs) are issued by year. KAUs can only be used for the current compliance period; and KCUs can only be used for the current year’s compliance. Carbon allowances for that year should be canceled as soon as possible within 6 months from the end of the compliance year. Taking the second half of 2022 as an example, the tradable items in the Korea’s carbon market include KAUs for 2022 to 2025, KCUs for 2022 and international carbon credits (i-KCUs). In terms of transactions, almost all of the market’s trading volume comes from KAUs for 2022, with very few transactions of other items. According to Korea Exchange, from July to September 15, KAUs for 2022 were traded at an average price of $20/ton (26,603 KRW/ton), with a total of 1.25 million tons traded (see Fig. 3.7).

International Voluntary Emission Reduction Trading The voluntary emission reduction market is an important complement to the mandatory emission reduction market. The main mechanisms of the voluntary emission reduction market around the world are the UN’s Clean Development Mechanism (CDM), the Verified Carbon Standard (VCS), the Gold Standard (GS), the China Certified Emission Reduction (CCER), the American Carbon Registry (ACR), and the US Climate Action Reserve (CAR). CDM projects generate emission credits

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Fig. 3.7 KAU (KAUs for 2022) transactions in the Korea’s carbon market. Source Korea Exchange; Unipec Research & Strategy (URS)

called Certified Emission Reductions (CERs); VCS methodologies generate Verified Carbon Units (VCUs); GS methodologies generate Voluntary Emission Reductions (VERs); ACR projects generate Emission Reduction Tons (ERTs); and CAR projects generates Climate Reserve Tonnes (CRTs). At present, there is no unified trading market for international emission reduction projects, so they are mainly traded offline. CDM was the earliest emission reduction project, and after the collapse of CDM prices, the international market switched to VCS and GS, whose methodologies were initially quoted from CDM methodologies and have been continuously improved since then. In terms of issuance volume, four major independent third-party voluntary emission reduction mechanisms, namely the VCS, GS, ACR and CAR, currently dominate, accounting for almost three quarters of the total number of global voluntary emission reduction credits, with VCS being the most widely used methodology internationally. According to the World Bank, the newly issued carbon emission reductions from global projects in 2021 reached 478 million tons, among which 110 new registered projects of the VCS issued 290 million tons of emission reductions, as the largest independent mechanism in the international market (see Table 3.1). Since March 2021, the Chicago Mercantile Exchange (CME) has launched the Global Emissions Offset (GEO) futures contract, the Nature-based Global Emissions Offset (N-GEO) futures contract, and the Core Global Emissions Offset (C-GEO) futures contract, which have gradually become the international reference standard for pricing emission reductions globally. In terms of delivery and settlement, N-GEO and C-GEO only allow delivery of VCS projects, while GEO allows delivery of VCS, ACR, and CAR projects. In the first half of 2022, the average price of N-GEO first line contract was $11.72/ton, and the average daily volume of all N-GEO futures

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Table 3.1 Major voluntary emission reduction mechanisms globally. The deadline for total issuance is May 2023 Methodology

Emission reductions

Total reductions issued

City of registration

Current status

VCS

VCU

1114 Million tons

Washington, US

Most widely used internationally

GS

VER

261 Million tons

Geneva, Switzerland

Second largest emission reduction mechanism internationally

ACR

ERT

242 Million tons

Arlington, US

Available for GEO delivery

CAR

CRT

189 Million tons

Los Angeles, US

Mainly applicable to North American projects

CDM

CER

2.3 Billion tons

–

Near a standstill

UERV

UER

8 Million tons

Berlin, Germany

Mainly for upstream oil and gas projects

Source verra, CDM, ACR, CAR, etc.; Unipec Research & Strategy (URS)

contracts was 580,000 tons, among which the average daily volume of contracts in December 2022 accounted for nearly 50%.

Current Development of International Carbon Tariff While the international carbon market is in full swing, the EU and the US are eager to levy carbon tariffs. On June 22, 2022, the European Parliament adopted an amendment to the Carbon Border Adjustment Mechanism (CBAM), a formal amendment to the proposed legislation to be published by the European Commission in July 2021. According to the latest proposal of the European Parliament, carbon tariffs will be introduced on steel, cement, fertilizers, aluminum, fertilizers, electricity, organic chemicals, plastics, hydrogen and ammonia starting in 2027 and will be extended to all sectors covered by the EU carbon market by 2030. After adoption by the European Parliament, the European Commission, the Council of the EU and the European Parliament will conduct final consultations on the content of the carbon tariff, which will result in a final legal text once the content is agreed. Meanwhile, on June 7, 2022, the US Democratic Party introduced the Clean Competition Act, a legislative proposal to establish a carbon border regulation mechanism. The bill proposes to impose a border carbon tax on imported products that exceed the baseline (the average carbon content of similar products in the US) starting in 2024, covering fossil fuels, petroleum products, petrochemicals, fertilizers, hydrogen, etc., with a

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carbon tax of 55 cents per ton on the excess, and a 5% annual increase in the carbon tax rate. In the context of global low-carbon transition, carbon tariff may develop into a new type of trade barrier. In order to prepare in advance for the imposition of international carbon tariffs, China needs not only to participate in international carbon market transactions in advance and be familiar with international carbon trading rules, but also to improve the domestic carbon emission accounting mechanism in order to develop the domestic carbon trading market as soon as possible.

The Current Situation of China’s Carbon Market Development Introduction of Local Pilot Carbon Market The Development History of China’s Carbon Trading Market In November 2011, the National Development and Reform Commission of China issued the Notice on Piloting Carbon Emissions Trading, agreeing to launch pilot carbon emissions trading in eight provinces and cities, including Beijing, Tianjin, Shanghai, Chongqing, Guangdong, Hubei, Shenzhen and Sichuan, to explore marketbased paths for energy-saving and emission reduction and accelerate the transformation of economic development and industrial structure upgrading. From 2013 to 2016, the three provinces and five cities launched carbon market trading one after another. In 2013, Shenzhen, Shanghai, Beijing, Guangdong and Tianjin markets were launched respectively, Hubei and Chongqing officially launched carbon emissions trading in 2014, and Fujian launched its carbon trading market in 2016. The eight pilot regions cover the eastern, central and western regions of China, each with its own characteristics in terms of economic development, industrial structure, energy consumption and greenhouse gas emissions.

Operation of the Pilot Carbon Markets Since 2011, the coverage of the pilot carbon markets has gradually increased, and the online trading of carbon allowances has reached a certain scale. By the end of 2021, the cumulative volume of allowance transactions in the eight pilot carbon markets was 506 million tons, with a cumulative transaction amount of RMB 12.6 billion, covering more than 20 industries such as steel, electricity and cement, and involving more than 3,000 enterprises. However, the overall turnover of China’s local carbon market is small, with low activeness and mostly offline transactions. In 2021, with the launch of the national carbon market, power generation companies withdrew from the local pilot markets, pulling down the volume in the pilot regions of Guangdong,

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10,000 tons 120 100 80 60 40 20 2020-01-02 2020-01-27 2020-02-21 2020-03-17 2020-04-11 2020-05-06 2020-05-31 2020-06-25 2020-07-20 2020-08-14 2020-09-08 2020-10-03 2020-10-28 2020-11-22 2020-12-17 2021-01-11 2021-02-05 2021-03-02 2021-03-27 2021-04-21 2021-05-16 2021-06-10 2021-07-05 2021-07-30 2021-08-24 2021-09-18 2021-10-13 2021-11-07 2021-12-02 2021-12-27 2022-01-21 2022-02-15 2022-03-12 2022-04-06 2022-05-01 2022-05-26 2022-06-20

0

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Time

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Fig. 3.8 Trend of listed prices in local pilot carbon markets. Source Beijing Green Exchange, Shanghai Environment and Energy Exchange, etc.; Unipec Research & Strategy (URS)

Hubei, Shanghai, Shenzhen and Fujian, and some of the pilot markets began to add new incorporated industries to participate in local compliance. The inability to circulate carbon allowances between different regions and different pilots has led to large price divergences between regions. The average transaction price in Beijing has been at the highest level among the pilot carbon markets since 2015, while the carbon price in Tianjin was at a lower level. The carbon price in Guangdong was relatively stable in the early stage, and then showed a rapid rise from 2021 due to the tightening policy, once surpassing the carbon price in Beijing, and stabilizing at 77–80 RMB/ton in 2022; the carbon price in Hubei is relatively stable, fluctuating at 40–50 RMB/ton in 2022; the carbon price in Chongqing basically fluctuates at 30–40 RMB/ton since 2021 (see Fig. 3.8). Overall, the carbon prices of China’s carbon trading pilots show a natural fluctuation, and the maturity of the market is enhancing.

Introduction to China’s National Carbon Market On May 17, 2021, the Ministry of Ecology and Environment (MOE) of China issued the Rules for the Administration of Registration of Carbon Emissions (for Trial Implementation), the Rules for the Administration of Trading of Carbon Emissions (for Trial Implementation) and the Rules for the Administration of Settlement of Carbon Emissions (for Trial Implementation); on July 16, 2021, the national carbon market was officially launched online, and a dual-center pattern of trading in Shanghai and registration and settlement in Hubei was formed. In the first compliance period (2019–2020) of the national carbon market, only the power generation sector is included in the scope of compliance and trading. As

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Fig. 3.9 Closing prices and volume in the national carbon market. Source Shanghai Environment and Energy Exchange; Unipec Research & Strategy (URS)

of July 16, 2022, the first anniversary of the launch of the national carbon market, the cumulative turnover in 242 trading days was 194 million tons, of which 325.928 million tons were listed and 161 million tons were traded in bulk agreements, with a cumulative turnover of RMB 8.491 billion. Transactions were mainly concentrated in the compliance period; except for the compliance period, the overall market was relatively cold. The closing price showed a smile curve of high on both sides and low in the middle, with the highest national carbon allowance price surging to RMB 58.7/ton at the beginning of the online period, followed by declining to around RMB 41/ton, and then rapidly rising again to around RMB 58/ton near the end of 2021 when the compliance date ended (see Fig. 3.9). The launch of the national carbon market is of great significance. China has been an active participant in the global fight against climate change, and the launch of the national carbon market is China’s commitment to the international community, reflecting China’s role as a major country in actively addressing climate change. The national carbon market sets mandatory targets for total carbon emissions control, aiming to use market mechanisms to regulate the distribution of carbon dioxide emissions, thus directing funds to industries and enterprises with high emission reduction potential. The national carbon market has realized the transformation of carbon trading and carbon quota compliance in the power industry from local partition to national unification, which helps emission control enterprises reduce carbon emission reduction costs through reasonable asset allocation on a national scale.

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Introduction to China Certified Emission Reduction (CCER) The Development of CCER With the end of the first phase of the Kyoto Protocol in 2012, the price of Certified Emission Reduction (CER) has been declining against the background of supply exceeding demand. Since the participation in the international Clean Development Mechanism (CDM) was limited, China started to prepare for the establishment of a domestic voluntary carbon trading market. With the launch of the pilot regional carbon exchange, the CCER market has emerged as a counterpart to the former CER market. Since 2013, regional pilot CCER trading has gradually replaced the CDM, which had begun to be fully restricted, but unlike allowance trading, CCER trading is no longer limited to companies participating in the local carbon market, but can circulate between different pilot sites nationwide. In March 2017, the National Development and Reform Commission of China suspended the approval and filing of CCER projects due to the small volume of market transactions and the lack of regulation of some projects.

Application of CCERs in Carbon Market Compliance In 2021, it is stipulated for the first national compliance cycle that CCERs could be used for compliance in the national carbon market, which significantly pushed up the price of CCERs. Before the national carbon market included CCERs for compliance, the price of CCERs varied somewhat by project type, but basically remained below RMB 30/ton. Since the national carbon market provides that CCERs of all project types can be used for allowance settlement and offsetting, the prices of different types of CCERs have gradually equalized and aligned with the trend of carbon allowance prices. In addition, CCERs can continue to be used for compliance in the eight pilot carbon markets, which, combined with the voluntary purchase of CCERs by some enterprises for offsetting emissions, has led to an increase in the demand for CCERs, driving CCER prices even higher, with offers of CCERs exceeding RMB 80/ton in 2022. There is currently news in the market that CCERs are expected to restart issuance in 2023, with which, CCER prices are expected to fall after the market stock is replenished. Overall, China’s carbon market that has a late start, low price level, small coverage and homogeneous participants has not yet fully formed a real market-based trading mechanism. Currently, the homogeneousness of participants is reflected in the fact that only 2,162 power generation companies participate in trading; although local carbon markets are incorporating investors, the scope of the market is small and the level of activeness is low. In addition, China’s carbon market is not well developed, with very few derivatives traded outside of spot trading of carbon allowances. Under the current carbon market mechanism, carbon market transactions are very inactive,

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and the surplus of allowances is kept in enterprises unwilling to sell on the one hand, and acquired by carbon traders on the other hand, so the market liquidity is low.

Suggestions for the Development of China’s Carbon Market Suggestion to Include More Types of Trading Entities to Increase Market Liquidity At present, the national carbon market of China only includes major emitters in the power generation industry, and the scope of the local carbon market is small and low in activeness. Under the current carbon market mechanism, carbon market transactions are very inactive, and the surplus of allowances is kept in enterprises unwilling to sell on the one hand, and acquired by carbon traders on the other hand, so the market liquidity is low. For example, about 80% of carbon allowances in the Beijing market are held by three major carbon traders, namely Timing Carbon, JUNO and GreenTech, leading to a significant increase in compliance costs. For this reason, it is recommended to clarify the specific rules regarding qualification of investment institutions and individuals, and gradually allow financial institutions and various investors to participate in trading, so as to enhance the liquidity of the carbon trading market.

Suggestion to Increase Trading Varieties and Enrich the Means of Carbon Asset Management Currently, there is a single product traded in the national carbon market, and the market structure is fragmented, which is not conducive to unified scale development, for example, the product is only carbon allowance spot, while CCER still cannot be traded on the same platform with carbon allowance, and there is a lack of synergy between carbon allowance and emission reduction in terms of trading options and pricing mechanism. In addition, the national carbon market has not yet launched diversified carbon asset management tools, and the trading entities’ needs of financing and carbon financing, asset management and risk management are not yet realized. From the experience of the EU carbon market, carbon financial derivatives, especially forward and futures products, have played an important role in increasing the activeness of non-compliance trading in the carbon market, and the turnover of futures in the European market is much larger than the turnover of spot. It is recommended to increase the number of carbon financial derivatives to provide market players with tools to hedge price risks, so that enterprises can better manage their carbon asset risk exposures.

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Strengthen Data Quality Management and Establish a Scientific Accounting System China’s carbon market has seen some emission data falsification by emission control enterprises, substandard performance by verification units, perfunctory verification, and obvious inaccuracies in verification conclusions, etc. China’s Ministry of Ecology and Environment has already remedied data falsification for the first compliance cycle. Fair, true and compliant data is the cornerstone of the carbon market operation. It is recommended to strengthen the data quality supervision and operation management, set a more scientific measurement method for actual measurement values, and establish a sound information disclosure and credit-based disciplinary management mechanism in order to intensify punishment for violations of laws and regulations.

Clarify Carbon Trading Invoicing System and Regulate Carbon Market’s Tax Requirements At present, the domestic invoicing system for carbon market transactions is not yet sound. The carbon market in Hubei and Guangdong adopts the form of anonymous trading, thus it is impossible to obtain special VAT invoices when picking orders online; while the national carbon market is still in the early stage of operation, so that the national taxation department has not yet issued a taxation system for carbon trading. In addition, some intermediaries take advantage of the information asymmetry between trading parties and charge intermediary fees, which further increases the transaction costs. Market participants who do not obtain input tax VAT invoices when buying carbon allowances will not only be unable to take output tax credits, but will also face certain audit risks. It is suggested that the competent ecological and environmental authorities and taxation and other departments should jointly issue regulations to clarify the taxation matters related to carbon allowance invoicing as soon as possible.

Bibliography ICAP (2022) Emission trading worldwide Ministry of Ecology and Environment of China (2021) National carbon emission trading cap setting and allowance allocation implementation plan for 2019-2020 (Power generation industry) (Power generation sector) [EB/OL]. https://www.mee.gov.cn/xxgk2018/xxgk/xxgk06/202110/ t20211026_957871.html REFINITIVE (2022) Carbon market year in review Wang J (2021) Carbon neutrality. China Industry and Information Technology Publishing & Media Group, Beijing

Part II

Petroleum

Chapter 4

New Features of the Global Oil Market in the Context of High Oil Prices Pei Wang and Aijie Li

Comparison of Three Oil Price Highs in History Since the birth of crude oil futures in the 1980s, under the influence of multiple factors such as supply and demand, finance and geopolitics, Brent crude oil prices have exceeded the $100/barrel mark three times in history, namely in 2008 (lasting 7 months), 2011–2014 (lasting more than 3 years) and 2022 (lasting 4 months) (see Fig. 4.1).

2008: Oil Prices Soared to a Peak of $146/Barrel From February to September 2008, the Brent crude oil price reached the $100/barrel mark, with a record high of $146.08/barrel on July 3. The rapid rise in oil prices in 2008 was mainly driven by the supply and demand. First, the global macro economy was improving, along with the high economic growth of emerging economies, driving the rapid rise in global oil demand. Second, geopolitical instability made shortterm supply disruptions frequent, and OPEC production growth was lower than expected. Third, global inventory levels remained low, and crude oil and refined oil stocks in Organization for Economic Cooperation and Development (OECD) countries showed a declining trend. Fourth, with the continued depreciation of the US dollar and the global liquidity glut, funds were turning to commodity markets for windfall profits.

P. Wang (B) · A. Li Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_4

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2 19 -09 94 -22 19 -09 96 -22 19 -09 98 -22 20 - 0 9 00 -22 20 - 0 9 02 -22 20 - 0 9 04 -22 20 - 0 9 06 -22 20 - 0 9 08 -22 20 - 0 9 10 -22 20 - 0 9 12 -22 20 - 0 9 14 -22 20 - 0 9 16 -22 20 - 0 9 18 -22 20 - 0 9 20 -22 20 - 0 9 22 -22 -0 922

0

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Fig. 4.1 Brent crude oil price trend over the last 30 years. Source Reuters; Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd

2011–2014: Oil Prices Remained High Above $100/Barrel for 3.5 Years From 2011 to 2014, international oil prices remained high above $100/barrel for 3.5 years, with Brent oil prices breaking the $100/barrel mark on January 31, 2011, hitting a high of $126.65/barrel on April 8, 2011, and only falling below the $100/ barrel barrier on September 9, 2014. The 2011 surge in oil prices was mainly due to geopolitical and supply-driven market movements, especially the “Arab Spring” democratization movement that swept through North Africa and West Asia and significantly reduced supply from Middle East oil-producing countries. In addition, the US and emerging economies have seen strong growth in oil demand, the world’s major developed economies continued to maintain loose monetary policy, while a large influx of funds into the oil market and other factors also constituted a strong support for international oil prices.

Late February to July 2022: Russia-Ukraine Conflict Pushed Oil Prices Quickly up to the $100/Barrel Mark Starting in late February 2022, international oil prices surged, with Brent oil prices breaking the $100/barrel barrier on February 28, soaring to $139/barrel on March 7 and closing at $127.98/barrel on March 8, and fluctuating around $100–120/barrel

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thereafter. Until July 12, as the dollar index hit a new 20-year high, commodity prices fell across the board, investors’ concerns about the global economic slowdown continued to rise, macroeconomic pressures again prevailed, and international oil prices fell below the $100/barrel mark. The sharp rise in oil prices this round is mainly driven by geopolitical turmoil and tight supply and demand fundamentals. First, the Russia-Ukraine conflict has suddenly escalated and tended to be long-term, while the EU and the G7 have escalated and increased energy sanctions against Russia. Second, high oil prices and low spare capacity have led to a lack of willingness and ability of OPEC+ to increase production, while US production growth was slow. Third, most of the countries in the world have gradually released the embargo measures, and the oil demand in Europe and the US continued to recover. Fourth, global oil inventories were running at low levels, with limited buffer space for supply disruptions.

Comparison of Three Oil Price Highs Regarding their similarities, first, the three high oil prices all reflect the significant influence of OPEC on the oil market, with the OPEC production limit in 2008, the Libyan civil war in 2011 and the OPEC+ production cut in the current round of high oil prices all being important drivers of the rapid rise in international oil prices. Second, the three high oil prices are accompanied by a good performance of oil demand—global oil demand continued to increase before 2008, rebounded from 2011 to 2014 and recovered in 2022 in the post-pandemic era, which are the key support for high international oil prices (Table 4.1). From their differences, the outbreak of the global financial crisis in 2008 caused oil prices to fall after 7 months, the global economic recovery from 2011 supported oil prices to maintain a high level for 3 years, and the Russia-Ukraine conflict from 2022 became the trigger for oil prices to reach $100/barrel. In addition, it is worth noting that the current round of high oil prices is accompanied by a major global energy transition, with the world moving toward clean and low-carbon energy, and a significant decline in upstream investment in traditional fossil energy. This causes a structural imbalance in the supply of old and new energy sources in the process of conversion, which becomes the fundamental reason for the rise in oil prices. At the same time, it is because of the global energy transition, the peak of oil demand is getting closer and closer. We cannot rule out that this round of high oil prices is the last flourishingment of the oil market. 2022 and the next two or three years may be the last era of high oil prices.

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Table 4.1 Comparison of the three oil price highs Period

Duration

Brent oil price peak ($/ barrel)

Characteristics

Core factors

February 28 to September 9, 2008

7 months

146.08

Oil prices surged and plunged, rallying higher and then falling back quickly

OPEC production limits; strong demand from emerging economies; heavy buying by speculative funds

January 31, 2011 to September 8, 2014

3 years and 7 months

126.65

Golden period of high oil prices, longest run above $100/barrel

Strong economic recovery in China and the US; quantitative easing started in the US; Libyan civil war impact

February 28 to July 12, 2022

4.5 months

127.98

Broad oil price oscillation, perhaps the last era of high oil prices

Intensifing Russia-Ukraine conflict; eased COVID-19 pandemic; demand improvement; slow supply growth; low oil inventories

Source Reuters; Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd

New Features of the Global Oil Market Under the Current High Oil Price Since 2022, international oil prices have risen sharply due to a strong recovery in global oil demand, sluggish supply growth and the escalating conflict between Russia and Ukraine. In March, Brent and WTI oil prices once exceeded $130 per barrel. In the second quarter, the US and the International Energy Agency (IEA) jointly released oil reserves, coupled with China’s rising pandemic led to the escalation of preventive and control measures, so that oil prices once fell back to about $ 100/ barrel. At the beginning of June, oil prices hit the $120/barrel mark again amid a sixth round of EU sanctions and a significant improvement in the pandemic in China. Since July, due to the interest rate hike of central banks and the great downward pressure on the macro economy, the oil price has been under downward pressure, but it is still above $90/barrel, a historical high. The global oil market as a whole is characterized by “four high, two low and one strong”, namely, high oil price, high discount, high gross margin, high demand, low inventory, low supply and strong structure, and the volatile geopolitical situation makes these characteristics more prominent.

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High Oil Prices: Russia-Ukraine Conflict Pushed Oil Prices Quickly up to the $100/Barrel Mark Since 2022, due to the escalation of the Russia-Ukraine conflict and the increase of sanctions against Russia by Europe and the US, the market has become more worried about supply disruptions and international oil prices have surged, with Brent and WTI oil prices both exceeding the $100/barrel mark. Brent oil prices reached $100/barrel on February 28 and soared to $139/barrel on March 7, characterized by huge oscillations and very high volatility. On March 8, Brent oil prices rose to $127.98/barrel, up 32% from February 23 (before the escalation of the RussiaUkraine conflict), the highest level since July 2008; WTI oil prices rose to $123.70/ barrel, up 34% from February 23, the highest level since August 2008. Since the beginning of April, by the US and the International Energy Agency (IEA) largescale release of reserves, coupled with the deterioration of the pandemic in China, the market fundamentals weakened significantly. However, the continuous sanctions imposed by Europe and the US on Russia have heated up the market sentiment again. Therefore, from May to June, the international oil price fluctuated sharply and continued to fluctuate at a high level. Since the second half of the year, due to the continuous tightening of monetary policies by central banks, tight liquidity and low macroeconomic sentiment, Russia’s supply decline was lower than expected, Libya’s production rebounded rapidly, and the US released the largest strategic reserve in history, which to some extent eased the market supply tension, and the international oil price showed a downward trend of turbulence. Brent prices fell from a high of $123.58/barrel in late June to $84.06/ barrel, and WTI prices fell from a high of $122.11/barrel in late June to $76.71/barrel, down 32% and 37% respectively, retracting all the gains since the outbreak of the Russia-Ukraine conflict at the end of February, but still at relatively high historical levels overall.

High Discount: Crude Oil Spot Discount Surged Higher As crude oil futures prices continued to rise, the spot price of crude oil other than Russian crude oil was also rising. With the current sanctions imposed on Russia by Europe and the US, the EU has adopted seven rounds of sanctions, including the sixth round of sanctions to stop the import of Russian crude oil from December 5, 2022, and the import of Russian refined oil products from February 5, 2023. As buyers of Russian crude face difficulties in opening letters of credit, renting tankers and shipping insurance, more and more refiners and traders have stopped sourcing Russian crude and are looking for alternatives to Russian crude, leading to a significant increase in crude oil premiums in other regions of the world, with the North Sea Forties crude oil premium over spot Brent crude rising to $3.35/barrel at one point. In May, Saudi Arabia offered a premium of $9.35/barrel over the average

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price of Platts Dubai and Oman crude on the Dubai Mercantile Exchange (DME), the highest level ever. Spot discounts for key oil varieties in oil-producing regions such as West Africa, North and South America rose across the board. From a post-market perspective, it is expected that the superposition of sanctions and panic will make the market concern unabated, and the overall crude oil spot price in 2022 will remain high. Since the second half of the year, the official price in the Middle East has retreated to a high level, and the discount in West Africa has fallen. The official price of Saudi Arabian intermediate crude oil averaged $5.27/barrel above Oman/Dubai premium, $4/barrel higher than last year. With the recent sharp Saudi price cut for October, the official price of Saudi Arabian intermediate crude oil fell by $4/barrel to $3.75/ barrel above Oman/Dubai premium. At the same time, the overall physical market is weak due to weaker-than-expected demand during the driving season and the arrival of the inspection season, and discounts for oil varieties in West Africa fell back after a surge. In addition, US domestic demand remains stable, and European refineries enters the autumn maintenance season to reduce the demand for US light oil, coupled with the large-scale release of strategic reserves, the market continues to weaken, and the North American market offers are also on a lower trend.

High Gross Margin: Refining Margins Continued to Strengthen and then Retreated Slightly in the Second Half Since 2022, driven by the recovery of global oil demand, the gross refining margin in the Gulf of Mexico, Europe and Singapore all hit the highest level in history, among which the gross refining margin once climbed to $50/barrel in the Gulf Coast, soared to $35/barrel in Europe, and rebounded to $26/barrel in Singapore, which is almost 2–3 times of the normal level (see Fig. 4.2). Diesel cracker spreads rose sharply, becoming the brightest performer. The Russia-Ukraine conflict led traders to reduce their purchases of Russian diesel and the diesel market in Western countries strengthened rapidly, with the European diesel crack spread reaching a record high of $53.23/barrel on April 29 and that in Asia–Pacific soaring to a record high of $58.12/barrel on May 5. Since the second half of the year, margins in the three refining centers have fallen sharply due to weaker-than-expected global oil demand. Refining margins in the Gulf Coast region have fallen sharply from the historical relative high of $53.22 per barrel to $19.08 per barrel, a decrease of 64%; refining margins in Rotterdam plunged 87% to around $4/barrel, the lowest since February 2020; and those in Singapore fell from a high above $30/barrel to just $0.83/barrel, a drop of 97%. From the performance of major oil products, Singapore gasoline crack spread fell 108% to $-3. 18/barrel, the lowest level since late March 2022; diesel crack spread fell 67% to $24. 94/barrel, coal crack spread fell 71% to $18. 07/barrel, but in general, middle distillate crack spread was still at a historically high level.

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Fig. 4.2 Change in processing revenue for complex refineries in the Gulf Coast, Europe and Singapore. Source Reuters; Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd

High Demand: The Overall Global Demand Is Steadily Recovering In the first half of 2022, as the major regions and countries around the world gradually relaxed their controls, the marginal impact of the COVID-19 pandemic on the global economy and oil demand gradually receded, and oil demand in the US and major European countries showed a strong rebound, with gasoline and diesel demand even exceeding the pre-pandemic level. From January to May 2022, US oil demand averaged around 20 million barrels per day, close to the pre-pandemic level of 20.54 million barrels per day, including 20.51 million barrels per day in March, marking a basic recovery to pre-pandemic levels. Oil demand in European countries has largely recovered to 95% of pre-pandemic levels, with strong growth in diesel consumption in major countries such as France, the UK and Germany. In addition, many countries in Southeast Asia have eased entry restrictions. Singapore was fully unblocked at the end of March and the entry and exit restrictions were lifted; India also resumed international passenger flights for the first time after a two-year hiatus. Indian oil demand has returned to a normal level of around 5 million barrels per day. China’s infections rebounded significantly from March to May 2022, with the re-imposition of strict blockades and restrictions in a number of provinces and regions, causing a significant impact on road traffic and aviation oil use, and oil demand is expected to gradually return to normal levels after June when the outbreak in China is largely under control. Since the second half of the year, oil demand in major countries has been paradoxically weak in the 2020 driving season (late May to early September) due to recurring

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outbreaks and high oil prices. US oil demand has been on a counter-seasonal downward trend since May; in July, gasoline demand fell to 8.59 million bpd, down 0.72 million bpd year-over-year and down nearly 1 million bpd from the same period during 2015 and 2019. In June, gasoline demand in the U.K. was down 12% from the average for the same period during 2017 and 2019. Air travel was stagnant. The German and U.K. air travel indices remained at about 65% of normal prepandemic levels, and the resurgence of the pandemic in some parts of the country in July put a damper on summer driving. Gasoline demand did not rebound with a vengeance, but stabilized overall. In 2020, due to China’s early flood time, heavy rainfall, and heavy disasters, engineering infrastructure process was significantly hampered. These factors, coupled with the end of agricultural oil use in summer, as well as the arrival of the fishing season, caused diesel demand to fall in the second half of the year, but the decline was within reasonable expectations.

Low Supply: OPEC’s Growth Was Sluggish and Global Oil Supply Has Slowed Significantly As international oil prices have climbed to recent highs, the major OPEC+ producers have become the biggest beneficiaries, but their willingness to increase production was clearly not strong, so crude oil production remained below the agreed production ceiling (see Fig. 4.3). At the same time, the remaining capacity of OPEC oil-producing countries also showed a continuous decline, only Saudi Arabia and the United Arab Emirates currently have sufficient capacity. OPEC, represented by Saudi Arabia, insisted on fulfilling the agreement to increase production slightly by 400,000 barrels per day month by month, and in July and August, although the scale of production increased to 648,000 barrels per day, but the increase was still limited. In addition, Iran’s return to the market may be delayed until 2023 as the nuclear talks continue to be uncertain. From the perspective of non-OPEC countries, US crude oil production has not rebounded significantly since 2021. in September, the weekly crude oil production averaged 12.1 million barrels per day, an increase of only 0.4 million barrels per day from the beginning of the year, with the overall increase significantly lower than expected. US crude oil production growth is expected to remain limited in 2022, due to producers’ control of capital expenditure and improvement of shareholders’ returns, as well as the increase in upstream labor and raw material costs caused by high inflation.

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20 2 20 1-0 2 1 20 1-0 2 2 20 1-0 21 3 20 - 0 2 4 20 1-0 21 5 20 - 0 2 6 20 1-0 2 7 20 1-0 2021-08 2 20 1-19 2 0 20 1-1 21 1 20 -12 2 20 2- 0 22 1 20 - 0 2 2 20 2- 0 22 3 20 - 0 2 4 20 2- 0 22 5 20 - 0 2 0 22 - 6 2 0 20 2- 0 7 2 20 2- 8 * 2 0 20 2-19 * 2 0 20 2-1 * 22 1 * -1 2*

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Fig. 4.3 OPEC+ crude oil production and target production. Source OPEC; Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd

Low Inventories: Global Oil Stocks Ran at a Low Level, and Europe and the US Jointly Released Reserves Since 2022, the impact of the COVID-19 pandemic gradually recede so that global oil demand continues to improve, while the supply-side growth has not accelerated, with global oil stocks remaining low. Currently, commercial oil stocks in Organization for Economic Cooperation and Development (OECD) countries are at an 8-year low, strategic oil stocks are at a 12-year low, global crude oil stocks at a 5-year low, and global refined oil stocks are also significantly lower than the 5-year average (Fig. 4.4). To alleviate the pressure of supply shortage in the oil market, the US and the International Energy Agency announced the release of nearly 240 million barrels of oil reserves from May for a period of six months, which is equivalent to an increase in supply of 1.33 million barrels per day in six months, the largest release in history. The US government announced the release of another 20 million barrels of strategic oil reserves in late July, which significantly relieved the supply pressure and played a ballast role in stabilizing the oil market. However, with the release of the strategic petroleum reserve, the US strategic reserves have now fallen to 526 million barrels, the lowest level since 1985, implying a significant reduction in the global capacity to respond to sudden supply disruptions.

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Strong Structure: The Benchmark Crude Oil Price Had a Strengthened Structure and the First Line Spread Has Widened Significantly As prices of crude oil futures continue to rise, the benchmark crude oil’s price structure has widened significantly, showing deeper backwardation. In March 2022, Brent crude oil’s first line spread widened to an all-time high of $4.64/barrel, much higher than $0.5/barrel at the start of the year, and the spread between the first and 13th lines once approached $30/barrel, the highest level ever; WTI crude oil’s first line spread widened to $4.05/barrel, much higher than the $0.3/barrel level at the beginning of the year, and the spread between the first and 13th lines once reached $31.5/barrel; Platts Dubai crude oil’s first line spread widened to $4.92/barrel, also much higher than the $0.6/barrel level at the beginning of the year. In general, the price structure of Platts Dubai crude oil was the strongest, followed by Brent crude oil, and WTI crude oil was weak relatively. In April, the benchmark crude oil price structure narrowed slightly due to the announcement that Europe and the US would release strategic reserves on a large scale to limit oil price increases; in May, the Russia-Ukraine conflict and demand recovery caused the spot market to tighten, and the benchmark crude oil price structure widened again to over $3/barrel (see Fig. 4.5). Since the second half of the year, the backwardation structure of benchmark oil spreads has narrowed significantly, but has rebounded since September, still at historically high levels. At present, the Brent first line spread has narrowed significantly to $1.22/barrel from $5.78/barrel at the end of June, while the spread between the first and the 13th lines have narrowed to about $10/barrel from $12.29/barrel at the end of June. WTI first line spreads fell sharply to $0.5/barrel from $3/barrel at the

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Fig. 4.5 First line spreads of the three benchmark crude oils. Source Reuters; Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd

end of June, while the spread between the first and the 13th lines fell to $9/barrel from $13.25/barrel. The Platts Dubai first line spread narrowed from $7.32/barrel to around $3/barrel, but was still at a relatively high level for the same period in history. In terms of benchmark spreads, the current WTI/Brent spread was $6.89/barrel, a significant widening from the end of June.

Suggestions for Response by China’s Oil Market In the face of the global oil market changes brought about by the Russia-Ukraine conflict and the evolving global changes unprecedented in a century, China’s oil industry should maintain strategic stability. Internally, we should continue to increase storage and production, improve the strategic reserve rotation mechanism, and accelerate the development of new energy industry; externally, we should continue to enhance trade capacity, play the advantage of promoting production by financing, and continue to enhance energy security and supply capacity.

Promote the Increase of Reserves and Production, and Deepen the Reform of Oil and Gas System Energy security is an important issue related to international planning and livelihood, and an important cornerstone of national strategic security. We can only fully guarantee national energy security if we take the autonomy of energy into our own hands.

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In recent years, as China continues to increase the exploration and development of oil and gas and investment in scientific research capital, and make every effort to promote the increase of oil and gas reserves and production, Chinese oil companies, led by the three major oil giants, have significantly increased in key indicators of oil and gas production. At the same time, the development of China’s old oil fields has been in the overall medium- to high-water-content stage, difficult and costly to maintain stable production and increase production. It is suggested that the state appropriately raise the starting point of the oil special income tax to reduce the cost of domestic oil and gas upstream projects; give policy support and subsidies to shale oil and gas exploration and development to explore the potential of China’s shale oil and gas resources; at the same time, continue to deepen the reform of the oil and gas system to further break the barriers to social capital to enter the field of upstream exploration and development.

Give Full Play to the Consumption Potential of the Domestic Market and Continue to Enhance Trade Capacity China is the world’s largest importer of crude oil and natural gas, with influence on international oil prices. As China’s national economy continues to develop and people’s living standards continue to improve, the large market consumption potential brought by a population of more than 1.4 billion is expected to maintain China’s status as the world’s largest oil and gas importer. Currently, China is the largest purchaser of crude oil in the Middle East and West Africa, accounting for one third of the volume of the North Sea window. In recent years, China has gradually increased its influence in the global energy market, gradually participating in or leading the development of the rules of the international oil and gas market, and delivering China’s voice in the energy market. In addition, the Shanghai International Energy Exchange (INE), a unit of the Shanghai Futures Exchange, has launched Shanghai Crude Oil Futures (SC), which is expected to become an important crude oil pricing benchmark reflecting supply and demand in China and the Asia–Pacific market. In the future, China should continue to explore new markets and new opportunities, and diversify the players of oil and gas supply, in order to continue to broaden the sources of oil and gas imports and continue to enhance the globalization of trade capacity; take the initiative to carry out analysis of the international crude oil market, and make reasonable use of financial instruments for hedging, in order to alleviate the negative impact of geopolitical and other uncertainties on domestic oil and gas supply, so as to enhance the ability of oil and gas security supply.

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Improve the Rotation Mechanism of Strategic Oil Reserves to Ensure Energy Security Strategic reserves are an important means for a country to deal with sudden supply disruptions and ensure energy security. Over the years, China’s energy reserve system has been improving. The huge scale of reserves consumes high operating costs, but is rarely called upon, especially since China’s strategic oil reserves were collected in 2008, and only once in 2021 has a small-scale public release of reserves. In recent years, international oil prices have fluctuated significantly, and the oil market has experienced tight supply, soaring discount and freight rates, but the impact of China’s oil reserves on these market changes has been relatively low. In addition, the physical characteristics of crude oil determine that it will precipitate more obviously after 7 years of storage, which will seriously impair the oil quality. It is recommended to further improve the rotation and release mechanism of strategic oil reserves, and introduce clear management methods and form a fixed operation process, so as to give full play to the buffer function of strategic oil reserves and effectively guarantee energy security in the event of sudden supply disruptions and sharp oil price rises in the international community.

Give Full Play to the Advantages of Financial Capital and Promote the Internationalization of RMB The Russia-Ukraine conflict has highlighted the significance of “financial war.” European and American countries have introduced a number of financial sanctions, and sacrificed their “financial nuclear weapons,” kicking many Russian banks out of the SWIFT system, dealing a fatal blow to Russian energy exports. From China’s point of view, China’s financial capital has not followed the industrial capital to “go global” in recent years, which means that the combination of industry and finance is not as strong as it should be. In the past seven years, China’s Cross-border Interbank Payment System (CIPS) launched by the People’s Bank of China has made great progress in RMB settlement and domestic message transmission, but RMB cross-border settlement still relies mainly on the SWIFT system. It is suggested that financial capital should play a more active role in supporting energy enterprises to obtain first-hand resources, hedge market risks and carry out financial settlement, in order to achieve financial promotion of production, and the unification of industry and finance to the outside world. This will enhance our pricing power in the energy sector and boost the internationalization of the RMB.

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Accelerate the Construction of the National Carbon Market and Promote the Green Low-Carbon Development of the Oil Industry According to the new energy security strategy of “four revolutions and one cooperation” proposed by General Secretary Xi Jinping, practicing the concept of green development and promoting low-carbon energy transformation has become a social consensus, and actively participating in global energy governance and leading international cooperation to address climate change reflect China’s role as a major country to actively address climate change. Since China proposed the goals of peak carbon emissions and carbon neutrality on September 22, 2020, all industries have accelerated their carbon emission reduction plans, and the oil industry has rapidly launched green low-carbon development strategies. Sinopec proposes to build a comprehensive refueling station that integrates oil, gas, hydrogen and electricity refueling and automobile services, while PetroChina promotes the transformation to an integrated energy company covering oil, gas, heat, electricity and hydrogen services. China should accelerate the construction of the national carbon market, explore and launch carbon trading financial instruments, and attract more participating entities to further activate the carbon market and prepare in advance to deal with international carbon tariffs; should continue to accelerate the development of renewable energy and gradually reduce the dependence on traditional fossil energy demand; and should increase the financial and technical support for the transformation of the energy structure, providing more support for the green low-carbon development of the oil industry.

Bibliography Environmental Defense Fund (EDF), and Shanghai Environment and Energy Exchange (2021) Report on China carbon pricing mechanism 2021 IEA (2022) Oil market report Interpreting the BCA for US Border Carbon Regulation. Website of Guangdong Emissions Exchange, August 04, 2021. http://www.cnemission.cn/article/jydt/scyj/202108/202108000 02259.shtml Li X (2021) Post-Bretton-Woods international monetary landscape. China Foreign Exch (11) OPEC (2022) Monthly oil market report Pei W, Na R, Yi C et al (2022) New features of the global oil market and new trends of oil trade in the context of high oil prices. Int Pet Econ 30(6):35–44 Ren P (2022) Take the autonomy of energy into our own hands. People’s Daily

Chapter 5

Global Oil Supply Analysis and Outlook in the Context of Russia-Ukraine Conflict Na Ren and Yi Cai

In 2022, global oil supply totaled 99.64 million barrels per day, an increase of 4.47 million barrels per day; crude oil supply totaled 77.04 million barrels per day, an increase of 3.2 million barrels per day, of which OPEC+, production cut exemption countries (Venezuela, Libya, and Iran), and the US accounted for 72% of global crude oil supply, and non-OPEC+ countries other than the US accounted for 28%. In 2023, a rebound in international oil prices is expected to push major oil producers to continue increasing production, but global oil supply growth is expected to slow down overall. The direction of the OPEC+ alliance’s production policy, the implementation of the EU’s crude oil sanctions against Russia, the direction of the Iranian nuclear negotiations, and the speed of growth of US crude oil production are the key factors affecting global crude oil supply.

Situation of OPEC+ Crude Oil Production OPEC+ Countries Have Strong Willingness to Limit Production to Protect Prices OPEC+ refers to the cooperative organization formed by OPEC oil-producing countries and non-OPEC major oil-producing countries, which mainly achieves production limitation and price protection by reaching an agreement on production reduction. OPEC+ currently has 20 members, namely the 10 countries of OPEC, Saudi Arabia, Iraq, Angola, Kuwait, UAE, Congo, Equatorial Guinea, Gabon, Nigeria, and Algeria, and the 10 countries of non-OPEC, Azerbaijan, Kazakhstan, Mexico, Oman, N. Ren (B) · Y. Cai Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_5

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Fig. 5.1 OPEC+ production cut quota and Brent price trend. Source OPEC; Unipec Research & Strategy (URS)

Russia, Bahrain, Brunei, Malaysia, Sudan, and South Sudan. The two leaders, Saudi Arabia and Russia, are key to OPEC+ production decisions. Since the production cut agreement was reached in December 2016, the agreement has been extended and adjusted several times with almost no interruption of implementation. Judging from the implementation effect, OPEC+ has played a better role in limiting production and protecting the interests of member countries by organizing regular meetings to adjust the future production policy. In April 2020, the global demand for oil was hit by the spread of the COVID19 pandemic, with the price of Brent falling below $20 per barrel and the price of WTI crude oil falling into negative territory for the first time in history. Against this backdrop, OPEC+ members reached the largest production cut agreement in their history. The first phase of the current round of production cuts was 9.7 million barrels per day (compared to the production cut base1 ), after which the production cut quota was gradually reduced as the pandemic situation improved and international oil prices gradually climbed (see Fig. 5.1). At the end of August 2022, the current round of production cuts expired, but the OPEC+ remained cautious about increasing production. In October 2022, OPEC+ again agreed to cut production by 2 million barrels per day from the current cut and extended the cooperation until the end of 2023. With the improvement of the global pandemic situation and the recovery of oil demand, international oil prices have started a two-year-long upward cycle, in which the OPEC+ production cut agreement has played a pivotal role and the cooperation of the OPEC+ alliance has also enabled member countries to enjoy the dividends of high oil prices.

1

Production cuts are based on October 2018 production, with Saudi Arabia and Russia’s production cuts set at 11 million barrel/day.

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OPEC+’s Actual Production Increase Fell Short of Its Target In terms of actual production, OPEC+ crude oil production in 2021 averaged 37.26 million barrels/day, down 430,000 barrels/day year-on-year. With the exception of April 2021, crude oil production in all months was below the target production allowed under the production cut agreement. Of these, the ten OPEC countries produced 22.21 million barrels/day, down 0.6 million barrels/day year-on-year, while the ten non-OPEC countries produced 15.05 million barrels/day, up 0.17 million barrels/day year-on-year. In 2022, OPEC+ crude oil production was expected to average 39.72 million barrels/day, an increase of 2.47 million barrels/day year-onyear, with monthly production not reaching the production ceiling. Of these, the ten OPEC countries produced 24.64 million barrels/day, up 2.43 million barrels/day year-on-year, while the ten non-OPEC countries produced 14.69 million barrels/day, up 40 thousand barrels/day year-on-year (Fig. 5.2).

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Saudi Arabia has played an important leading role, but has limited spare capacity. Historically, Saudi Arabia has only produced more than 11 million barrels/ day in two months. Since the implementation of the current round of production cuts, Saudi Arabia’s implementation rate has largely exceeded 100%. As the low drilling rate in the past few years has failed to compensate for the loss of existing capacity, the current Saudi production capacity may not exceed 11 million barrels per day. In the past year, Saudi Arabia’s crude oil production has been below the agreed production ceiling. In 2021, Saudi crude oil production was 9.08 million barrels/ day, down 100,000 barrels/day from the previous year; and that in 2022 was 10.52 million barrels/day, an increase of 1.44 million barrels/day from the previous year.

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Fig. 5.2 OPEC+ production and target production. Source OPEC; IEA; Unipec Research & Strategy (URS)

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The UAE has raised its production target, with strongly willing to increase production. The UAE plans to increase crude oil production to 5 million barrels per day by 2025, and at one point refused to extend the production cut agreement due to its need to secure physical deliveries of crude oil from Murban. Subsequently, the OPEC+ agreed to increase the production cut base, and the UAE finally agreed to the production cut agreement. In 2021, UAE crude oil production was 2.72 million barrels/day, down 85,000 barrels/day from the previous year. In 2022, the figure was 3.05 million barrels/day, up 340,000 barrels/day from the previous year. Iraq has seen a steady increase in crude oil production as domestic politics stabilize. In October 2021, the Iraqi election was won by the “anti-American” Sadr, whose anti-American and anti-Iranian ideas have undoubtedly played a key role. Since the election, Iraq’s domestic politics have stabilized. In 2021, Iraq’s crude oil production was 4.02 million barrels/day, down 30,000 barrels/day from the previous year; and that in 2022 was 4.43 million barrels/day, an increase of 400,000 million barrels/day from the previous year. However, with the unabated conflict between Turkey and the Kurdistan Workers’ Party (PKK) in northern Iraq and the continued risk of terrorism, crude oil production is expected to remain at risk of disruption. Kazakhstan had frequent supply risks and increased risk of CPC pipeline outages. The risk of domestic political unrest in Kazakhstan has increased since 2022. In January 2022, a state of emergency was declared in Kazakhstan after protests broke out in several cities due to a sharp increase in LPG prices; in March 2022, two offshore moorings of the CPC Caspian pipeline were damaged due to storm attacks, affecting two-thirds of crude oil exports; in July 2022, a Russian court ordered the suspension of the CPC pipeline due to Kazakhstan’s refusal to recognize the independence of Luhansk and Donetsk; in July 2022, Kazakhstan’s crude oil production was again at risk of disruption when a Russian court ordered a 30-day suspension of the CPC pipeline operations due to that refusal of Kazakhstan. In 2021, Kazakhstan’s crude oil production was 1.51 million barrels/day, basically unchanged from the same period last year, with only 87% of the production cut implemented. In 2022, the figure was 1.54 million barrels/day, an increase of only 30,000 barrels/day over the previous year. As OPEC+ countries gradually increased production, coupled with reduced upstream investment and accelerated field aging, the remaining capacity of OPEC+ countries was gradually decreasing (see Fig. 5.3). In July 2022, the remaining capacity of OPEC+ countries was only 2.8 million barrels/day (compared with the highest monthly production in history), including 930,000 barrels/day in Saudi Arabia, 280,000 barrels/day in Iraq and 710,000 barrels/day in the UAE. With low spare capacity, OPEC+ had limited room to buffer against supply disruptions.

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Fig. 5.3 OPEC+ countries’ spare capacity (excluding Russia). Source OPEC; IEA; Unipec Research & Strategy (URS)

Russia-Ukraine Conflict Became the Biggest Black Swan Event in 2022 Since the outbreak of the Russia-Ukraine conflict on February 24, 2022, the conflict between the two sides has become the biggest black swan event in the crude oil market in 2022, and the sanctions imposed on Russia by Europe and the US Have increased in layers, which has significantly increased the market’s concern about supply shortage.

The Current Situation of Sanctions Against Russia by Europe and the US The EU has introduced eight rounds of sanctions against Russia, expanding the scope of sanctions from officials to enterprises, from the financial sector to the energy sector, and the sanctions have continued to escalate and their impact has gradually increased, with Russian oil facing the double test of sanctions and price limits. On June 4, 2022, the EU announced the sixth round of sanctions against Russia: a six-month halt to Russian crude oil imports by sea, but exemptions for pipeline crude oil imports, an eight-month halt to imports of refined oil products, and a ban on providing insurance for Russian oil shipments. In addition to the strict sanctions imposed on Russia by the EU, countries including the US, the United Kingdom, Canada, Japan and Australia have also introduced sanctions against Russia. In September 2022, the G7 finance ministers agreed to cap the price of Russian oil exports, and the US Treasury Department’s Office of Foreign Assets Control issued preliminary guidance on price caps for Russian oil; in October 2022, the EU officially approved the eighth round of

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sanctions against Russia, providing the legal basis for setting price caps on Russian oil.

Russian Crude Oil Exports Russia is the world’s leading producer and exporter of crude oil. In 2021, Russia produced 10.5 million barrels per day of crude oil, accounting for about 10% of the world’s crude oil production, and was the world’s second largest producer of crude oil; it exported 4.64 million barrels per day of crude oil, accounting for 12% of the world’s total crude oil exports, and was the world’s second largest exporter of crude oil after Saudi Arabia. In terms of export flows, Europe and Asia Pacific are the largest export regions for Russian crude oil, with exports to Europe accounting for 53% of Russia’s total crude oil exports in 2021 and exports to Asia Pacific accounting for 35% (Fig. 5.4). In addition, the US and CIS countries also import Russian crude oil in small quantities, accounting for 4.3% and 3.9% respectively. In terms of export mode, one third of Russian crude oil exports are by pipeline and two thirds by sea. In 2021, Russia exported 1.6 million barrel/d of crude oil by pipeline, mainly through Friendship Pipeline, ESPO Pipeline and China-Kazakhstan Pipeline; 3.04 million barrel/d of crude oil were exported by sea, including westward export through Novorossiysk, Ust Luga and Primorsk ports, and eastward export through Kozmino, Sakhalin I, Sakhalin II, Ust Luga and Primorsk ports, Sakhalin I, Sakhalin II, Umba FSO and Kola KSO. Since the escalation of the Russia-Ukraine conflict, Russian crude oil supply has shown strong resilience. In the first three quarters of 2022, Russian seaborne exports were 3.66 million barrels/day, an increase of 0.4 million barrels/day year-on-year, with the increase in Asian imports fully offsetting the decline in EU imports. CIS:4% America:4%

Asia Pacific:39%

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Fig. 5.4 Distribution of Russian crude oil export flows in 2021. Source Reuters; BP; Unipec Research & Strategy (URS)

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Impact of the EU-US Embargo on Russian Supply The Russia-Ukraine conflict has led to a profound restructuring of the global oil trade landscape, with Russia’s position in the global trade declining and OPEC and the US gaining significant ground. Russia’s Urals crude oil is a medium sour oil, similar in quality to North Sea Forties, Norwegian Johan Sverdrup and Saudi Arabian medium crude oil. It is expected that the continued increase of sanctions will lead to the withdrawal of a large amount of Russian crude oil from the market, and a large amount of alternative resources from the Middle East, North Sea, West Africa and America will flow to Europe, and long-distance transportation will replace short-distance transportation as the main form of trade to Europe. With both the European and US bans and price limits coming into effect in December 2022, Russia will be in a dilemma. If it refuses to sell crude oil to customers who enforce the G7 price limits, it will be subject to the insurance ban; if it compromises with the G7 price limits, it will have to sell crude oil at lower prices. Initially, it is expected that the G7 price limits will have limited effect and Russian crude oil may flow into the market through the use of other insurance or grey channels. In terms of trade volumes, Russian seaborne crude oil exports are expected to fall to 2.5 million barrels/day in December 2022, 1.2 million barrels/day lower than in September, and slowly increase thereafter. From the point of view of trade flow, it is expected that the inflow of Russian oil to the European region will drop significantly, and the Asian region will become the main market for Russian oil exports, resulting in a major shift in the global crude oil trade flow.

The Future of Iranian Nuclear Negotiations Is Uncertain, and Venezuela Is Still Under Sanctions Since the resumption of the Iranian nuclear negotiations in April 2021, the two governments have carried out eight rounds of negotiations, with both the US and Iran having the will to return to the Iranian nuclear agreement. The Iran nuclear deal is an important diplomatic achievement for the US Democratic Party, and the Biden administration wants to lead the US back to the Iran nuclear deal. Meanwhile, after nearly four years of sanctions, Iran has a desire to return to the Iran nuclear deal and increase its oil export revenues. However, the two sides are deadlocked on key provisions. From the perspective of the US, it is difficult to implement the resumption of the Iran nuclear agreement as a law, and it is difficult to guarantee that the next US President will not withdraw from the agreement again. And in Iran’s view, the US proposed restrictions on Iran’s enriched uranium, centrifuges, almost a complete abolition of Iran’s nuclear activities, is expected to be difficult to get Iran to compromise. The outcome of the follow-up negotiations is still unclear, but the US may relax some of the restrictions on Iranian oil exports, so Iranian crude oil can increase exports through gray channels. Currently, Iran’s crude oil production

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is basically stable at about 2.55 million barrels per day, and once an agreement is reached, Iran’s crude oil supply is expected to increase by about 1 million barrels per day in 4–6 months, which will also have a significant impact on global oil supply. Venezuela’s crude oil production has been declining since 2016 due to longterm US sanctions and has fallen to a record low of around 300,000 barrels/day in 2020. Since the outbreak of the Russia-Ukraine conflict in early 2022, global oil supply constraints have led the US to consider easing sanctions against Venezuela. In May 2022, the Biden administration announced that it had authorized Chevron to negotiate its business operations in Venezuela with the country’s oil companies and that it would allow two oil companies, Italy’s ENI and Spain’s Repsol, to transport Venezuelan crude to Europe. Currently, Venezuela’s oil production capacity will be further increased as Chevron’s joint venture in Venezuela resumes production, but it will be difficult for its crude oil production to pick up quickly due to lack of investment and dated facilities, and is expected to increase by 160,000 barrels/day to 720,000 barrels/day in 2022. Libya’s crude oil supply was subject to significant fluctuations due to the country’s political situation. Since April 2022, oil production has been forced to shut down due to prolonged protests in major oil-producing regions as a result of intense infighting between the national unity government in the west and the national representative government in the east. Libya’s national oil company has announced that its oil fields and ports have been shut down by force majeure. The country’s crude oil production fell rapidly from 1.2 million bpd to less than 100,000 bpd and averaged only 750,000 bpd in the second quarter, down 400,000 bpd from the beginning of the year. In late July, the country’s political situation eased as officials reached an agreement with protesters and tribal leaders to reopen most of the oil fields and export terminals that had been closed for months. As a result, crude oil production rebounded significantly and returned to normal levels of 1.2 million bpd in early August. At present, the country’s crude oil production remains stable in general, but the risk of future political unrest still exists, which does not rule out another significant decline in production.

Non-OPEC+ Oil-Producing Countries Still Have a Small Increase in Production US crude oil production is slowly rebounding. While the impact of the COVID-19 pandemic on global oil markets is subsiding and global oil prices are steadily rising, the recovery in US shale production has fallen significantly short of expectations as upstream investment has been slow to recover and shale producers have cut capital expenditures and increased shareholder returns. For example, the increase of active rigs and frac teams has slowed down. In 2021, US crude oil production fell slightly by

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80,000 barrels per day to 11.24 million barrels per day, the second consecutive yearon-year decline. In 2022, oil prices remained high, leading to a significant improvement in profitability for the world’s major oil producers and a continued recovery in upstream investment and oil production. However, there was no significant increase in US oil production and major shale oil companies continued to curb capex and increase shareholder returns. In addition, continued high inflation in the US has led to significant increases in upstream raw material and labor costs, which combined with the difficulty of effectively alleviating supply chain bottlenecks, making the overall recovery of crude oil production in the US less than expected. By the end of September, US crude oil production recovered to about 12 million barrels per day, an increase of only 400,000 barrels per day from the beginning of the year, far below the level of nearly 13 million barrels per day before the pandemic in 2020 (see Fig. 5.5). From the rig count, as of the end of September, the number of active oil rigs in the US increased to 604, 123 more than the beginning of the year, but still 70 lower than the beginning of 2020. The number in the US is expected to maintain a gradual increase in the trend. Overall, US shale production will remain on track for a slow recovery, with producers holding back on capex and a slower-than-expected recovery in rig counts limiting the recovery process. US crude oil production is expected to grow by 700,000 barrels/day year-on-year to 11.95 million barrels/day in 2022. Canada’s production is steadily increasing. In 2021, as international oil prices continued to recover, and Canadian oil producers’ operating conditions improved significantly, resulting in a significant increase in free cash flow and stimulating producers to increase upstream investment, with capital expenditures rising 20%

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year-over-year. In addition, the pipeline bottleneck was relieved and the Line 3 pipeline from Western Canada to PADD II in the US came on stream, adding 370,000 barrels/day of transportation capacity to support the growth of oil sands production in the west of the country. With the end of the maintenance season in the major oil sand production regions and the Fort Hills II oil sands project operating at full capacity, Canadian oil production grew to record levels by the end of 2021. In 2021, Canadian crude oil production was 4.27 million barrels/day, an increase of 240,000 barrels/day from the previous year. Overall Canadian oil production continues to show steady growth in 2022, with high oil prices encouraging Canadian oil companies to continue to increase upstream investment and expand new oil sands projects. With pipeline bottlenecks continuing to improve, including TC Energy’s Keystone pipeline and TransMountain expansion project to increase transportation capacity by nearly 600,000 barrels/day, which supports the commissioning of multiple oil sands projects in Alberta and increases production capacity, Canadian crude oil production is expected to be 4.42 million barrels/day in 2022, an increase of 150,000 barrels/ day year-over-year. Norway’s production increase is less than expected. As the largest oil and gas producer in Western Europe, Norway’s crude oil production has shown steady growth in the past two years, thanks to the first phase of the giant oil field Johan Sverdrup that has been in full production in 2021, with crude oil production climbing to more than 500,000 barrels per day. Although Norway is experiencing a decline in production due to the aging of some of its mature fields, the start-up of new fields and steady growth in production will support a rebound in production. In 2021, Norway’s crude oil production was 1.77 million barrels/day, an increase of 100,000 barrels/day from the previous year. In 2022, Norway’s crude oil production showed a steady decline due to a long maintenance season at the Johan Sverdrup field and the Ekofisk block, which had a significant impact on crude oil production, with Norwegian production falling sharply by 270,000 barrel/d to 1.3 million barrel/d in June. With the end of the maintenance season, the resumption of production at major fields and the commissioning of Johan Sverdrup field phase II in the fourth quarter of 2022, Norwegian crude oil production is expected to gradually rebound to more than 1.8 million barrels per day in the second half of the year. Overall, Norwegian crude oil production is expected to decline slightly by 50,000 barrel/d to 1.72 million barrel/d in 2022, dragged down by the first half of the year. Brazilian production returns in the second half of the year. Brazil’s crude oil production growth fell short of expectations, with crude oil production averaging 2.9 million barrels/day in 2021, down slightly by 40,000 barrels/day year-over-year. Although production from major fields such as Sepia and Buzios continued to grow, production was impacted by large-scale field maintenance in the third and fourth quarters, especially as production platform operations were impacted by more stringent pandemic control measures. In addition, some production projects were postponed and mature fields aged, resulting in a decline in overall production. In the first half of 2022, Petrobras’ oil production declined 5% year-over-year to 2.11 million barrels

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per day in the second quarter due to a slow recovery from extended field maintenance; in the second half of the year, production from the Tupi field accelerated with increased production from the Mero 1 and Peregrino 2 blocks in the subsalt Santos Basin, including the production from Peregrino 1 block in the Campos Basin, which had been halted due to equipment failures and now is going to resume. Brazil’s oil production is expected to grow significantly and rebound to around 3.1 million barrels/day by the end of the year. In 2022, Brazilian production is expected to increase by 100,000 barrel/d to 3.1 million barrel/d year-over-year, with production increases mainly in the second half of the year. New fields in Guyana are growing steadily. Guyana’s offshore oil fields have generally shown steady growth in production since the end of 2019 when they came on stream. Production from the first phase of the Liza field remained stable at 120,000 barrel/d in 2021, and the second phase of the project came on stream early in 2022, with production approaching 300,000 barrel/d. The country’s crude oil production increased by 50,000 barrels/day to 120,000 barrels/day in 2021. Guyana’s capacity is also expected to reach 220,000 barrels/day in 2022, given the upgraded and optimized production facilities at the Liza Field Phase I project, the steady increase in production from Phase II, and the possible commissioning of the Prosperity FPSO at Payara, the third project, by the end of 2023. The country’s crude oil production is expected to increase by 150,000 barrels per day year-over-year to 270,000 barrels per day in 2022.

Global Oil Supply Growth Will Slow Down in 2023 In 2023, a rebound in international oil prices is expected to push major oil producers to continue increasing production, but global oil supply growth is expected to slow down overall. In 2023, “OPEC+” will again take measures to limit production and protect prices, and the decay of mature oil fields in the Middle East will increase, so the remaining capacity of major oil-producing countries will fall to the bottom. The sanctions and price restrictions imposed on Russia by European and US countries may affect Russian crude oil exports, and Russian crude oil production is expected to decrease significantly. As drilling activity picks up and frac teams increase, with supply chain and labor costs being gradually eased, US crude oil production is expected to continue to rebound steadily. In addition, high oil prices stimulate Canadian oil companies to continue to increase upstream investment and expansion of new oil sands projects, major fields in Norway are coming back on stream, Phase II of the Johan Sverdrup field is ramping up production, new fields in Guyana are growing steadily, and non-OPEC producers excluding the US are expected to contribute to some of the growth. In 2023, global oil supply is expected to reach 101.37 million barrels per day, the first time after the pandemic to reach the 100 million bpd mark, but will only increase by 1.7 million bpd year-on-year, much less than the increase in 2022.

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Forecast of Global Oil Supply in the Medium and Long Term As Low Carbon Emission Reduction Becomes the Global Theme, Upstream Oil and Gas Capital Investment Will Decrease In the past few years, global upstream exploration and development capital expenditure was at a historical low. In 2021, global upstream investment in oil and gas was only $341 billion, about 25% lower than in 2019 before the pandemic, and new oil and gas exploration reserves hit a 75-year low. According to the International Energy Agency’s latest World Energy Investment 2022, since the outbreak of the Russia-Ukraine conflict, oil and gas prices have soared, and upstream oil and gas capital expenditure is expected to increase by 10% in 2022, still lower than the level before the pandemic, and raw material prices are one of the reasons for the increase in capital expenditure; therefor, most of the capital shifted to short-cycle investment to bring new supply to the market as soon as possible. In the long run, under the background of low carbon and emission reduction, it has become a common knowledge in the industry that the future global investment in oil exploration and development will gradually decrease. According to the International Energy Agency, if countries around the world strictly comply with their carbon neutrality commitments, the annual average value of global oil and gas investment from 2020 to 2050 will only be $210 billion, far below the pre-COVID-19 level of about $500 billion. With less upstream oil and gas capital investment, aging oil fields will lead to faster production declines.

Geopolitical Unrest Is Frequent, so Part of the Time There May Be Supply Shortages In the medium and long term, geopolitical turbulence will still have a significant impact on the international oil market. For example, the changes in the political pattern of the Middle East, Russia, Libya, Venezuela and other major oil producing countries will have a great impact on the oil market. At present, the European and American oil sanctions against Russia triggered by the conflict between Russia and Ukraine are about to be implemented. International oil companies have suspended their investment in Russian oil and gas, and there is still uncertainty whether the future supply of Russian crude oil can remain stable. In addition, Saudi Arabia is still facing the risk of Houthi attacks in Yemen, and the destruction of oil facilities will also cause the threat of supply disruption in the short term. In recent years, Libya’s crude oil production has fluctuated greatly due to the political turmoil in the country, which has dropped to 100,000 barrels/day at one point. Any future turmoil in the country will continue to have a significant impact on oil production. Overall,

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the political problems of the world’s major oil-producing countries are still factors that cannot be ignored to affect the market, and short-term supply disruptions will exacerbate the volatile pattern of the oil market.

Bibliography EIA (2022) Short term energy outlook IEA (2022) World energy investment 2022 IEA (2022) Oil market report OPEC (2022) Monthly oil market report PIRA (2022) World oil market forecast

Chapter 6

Outlook for Global Oil Demand in the Post-COVID-19 Era Di Hu and Ying Zhao

Global Oil Demand Is Recovering in 2022 The Global Economy Bottomed out and Rebounded In 2021, global economic activities recovered under the large-scale economic stimulus policies of central banks. Since 2022, the side effects of the excessive monetary easing policy led by the US have begun to emerge. With the massive inflow of hot money into the market, soaring commodity prices, and the conflict between Russia and Ukraine triggering a surge in the price of oil, natural gas and other major energy sources, inflation rates in major countries around the world have continued to exceed market expectations and have repeatedly hit record highs. In response to the continued high inflationary pressure, central banks have launched an unprecedented scale of interest rate hikes, which has dealt a blow to the global economy and slowed down economic growth in major countries. In the first half of 2022, the US GDP experienced two consecutive quarters of negative growth; manufacturing indices in the US, China, the Eurozone and other economies showed poor performance, and the macro market prospect was bleak. According to the latest World Economic Outlook released by the World Monetary Fund in July 2022, the global economic growth rate is expected to slow down to 3.2% in 2022 from 6.1% in 2021, the third consecutive downward revision of the organization’s global economic growth rate in 2022 (Fig. 6.1).

D. Hu (B) · Y. Zhao Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_6

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While Major Countries’ Demand Is Recovering, China’s Oil Demand Has Been Hit Hard Since 2022, global oil demand growth has slowed down under the influence of various factors such as soaring energy prices, gloomy global economic growth outlook, and the repeated impact of pandemics on the market. Some major agencies including the International Energy Agency (IEA), OPEC and the US Energy Information Administration continue to adjust the global oil demand expectations for 2022. In its September monthly report, the IEA forecast that global oil demand in 2022 will be 99.7 million barrels per day (barrels/day), a downward revision of 880,000 barrels/ day from the highest forecast at the beginning of the year, and an increase of only 2 million barrels/day for the year, which is significantly narrower than last year’s 6.05 million barrels/day (see Fig. 6.2). In 2022, global oil demand did not perform as expected due to high oil prices and high inflation. Specifically, in the first quarter, as impact of the pandemic quickly receded, global oil demand grew strongly, with a year-on-year increase of nearly 5 million barrels per day: the oil demand of major countries in Asia Pacific and the West basically approached or exceeded the level before the pandemic. In the second quarter, global oil demand fell slightly under the combined impact of the RussiaUkraine crisis, the resurgence of the pandemic in China and seasonal changes, but still increased by 2 million barrels per day year-on-year. The first half of the year saw an overall situation where global oil demand was “strong in the West and weak in the East.” In the third quarter, with the arrival of summer, the impact of high inflation and high oil prices on the economy and demand began to emerge: oil demand in Europe and the US during the driving season in the northern hemisphere was less than expected, showing paradoxically weak performance in the traditional peak season; global oil demand only increased slightly by 1.08 million barrels per day year-onyear. In the fourth quarter, the European energy crisis boosted the demand for oil

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substitutes, and with increased demand for winter heating, global oil demand is expected to have some room for rebound. Under the side effects of the central bank’s extreme monetary easing policy, inflation is soaring globally, and the economic situation is getting gloomier and gloomier, even facing a recession crisis. At the same time, on the one hand, the conflict between Russia and Ukraine broke out, the main western countries introduced sanctions against Russia one by one, the EU energy crisis reappeared, and energy prices soared. On the other hand, the repeated pandemic in China and the escalation of pandemic prevention and control measures in many places have had a significant impact on road transport and air transport, thus global oil demand has fallen short of expectations, and major institutions have been downgrading demand growth. The performance in major regions is as follows. In 2022, Asia–Pacific oil demand is expected to be 36.71 million barrels per day, up 520,000 bpd year-on-year, accounting for 36.8% of total global oil demand and further increasing its overall share. From the perspective of major countries, China’s overall oil demand fell by 510,000 bpd year-on-year to 13.58 million bpd from January to August 2022, down 3.6%. This is mainly due to the recurring pandemic this year, which continues to show frequent outbreaks in multiple locations, and therefore China has implemented a strict “dynamic zero-COVID policy” policy, which has a serious impact on travel and a great blow to demand. Among them, gasoline and jet fuel decreased by 10% and 42% respectively due to pandemic blockade control measures; driven by China’s infrastructure and economic stimulus measures, the overall performance of diesel is better than that of gasoline, with a slight increase of 4% from January to August. However, naphtha, LPG, fuel oil and other products have increased to varying degrees supported by strong chemical demand and infrastructure

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investment. As an oil consumer in the Asia–Pacific region, India’s overall oil demand is expected to increase by 370,000 barrels per day to 5.14 million barrels per day in 2022. On the one hand, since 2022, India’s economy and manufacturing industry have recovered rapidly. The IMF predicts that India’s GDP will increase by 7. 4% year-on-year, making it the fastest growing country in the world, which will boost the oil demand. On the other hand, in 2022, India suffered a more serious monsoon rainy season than in previous years, with frequent lightning storms and even floods. The data shows that the rainy season rainfall in India this year has increased by 6% compared with previous years, and extreme weather has put pressure on travel demand to some extent. In the fourth quarter of 2022, with the end of the rainy season, it is expected that demand will rebound. Under the influence of severe economic and monetary blows, Japan’s demand is expected to drop slightly by 30,000 barrels per day in 2022. That of South Korea is expected to increase slightly by 40,000 barrels per day. In North America, it is estimated that the oil demand in US will be 25 million barrels per day in 2022, an increase of 670,000 barrels per day year-on-year, making it the country with the most significant increase in global demand, accounting for 25% of global oil demand slightly compared with last year. Among them, although the impact of the pandemic has gradually subsided, the economic development of the US is weak under the influence of the continuous interest rate hike by the Federal Reserve and the soaring gasoline prices. Since the first half of the year, the PMI index of the US has been declining, and the economy is also facing two consecutive quarters of contraction, and the oil demand has been severely impacted. Since 2022, the demand for gasoline and diesel in the US has decreased by 150,000 barrels per day and 90,000 barrels per day respectively, while the demand for jet fuel has recovered by 230,000 barrels per day, but is still nearly 300,000 barrels per day lower than the pre-pandemic level. It is estimated that the annual oil demand in the US will be 20.75 million barrels per day, an increase of 350,000 barrels per day. In addition, Canada and Mexico are affected by the economy to varying degrees. It is estimated that Canada’s annual oil demand will increase slightly by 100,000 barrels per day to 2.44 million barrels per day. Mexico’s annual oil demand decreased slightly by 40,000 barrels per day. In Europe, it is estimated that the oil demand in 2022 will be 13.61 million barrels per day, an increase of 480,000 barrels per day. Specifically, on the one hand, under the multiple influences of the energy crisis, soaring inflation, interest rate hike by the central bank and currency diving, the European economy failed to perform as expected, putting pressure on oil demand. On the other hand, since March 2022, the conflict between Russia and Ukraine has subverted the global energy supply, and the EU has successively issued eight rounds of sanctions against Russia, involving the fields of finance, coal and oil. This has aggravated the energy supply crisis in Europe. The price of coal soared and the price of natural gas in Europe once hit a record high, which promoted the increase of oil substitution demand to some extent. It is estimated that the demand for energy substitution is expected to increase by 700,000 barrels per day from the fourth quarter of 2022 to the first quarter of 2023.

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Since 2022, demand in other regions, such as the Middle East, the Soviet Union, Africa and South America, has recovered slightly. The overall oil demand in the Middle East increased by 530,000 barrels per day to 9.01 million barrels per day; that in the Soviet Union decreased slightly by 100,000 barrels per day to 4.75 million barrels per day; and that in Africa increased by 110,000 barrels per day to 4.1 million barrels per day.

In 2022, the Demand for Jet Fuel Rebounded Significantly, and That for Gasoline Recovered Less than Expected In terms of varieties, in 2021, with the improvement of the pandemic situation and the relaxation of blockade policies in various countries, the demand for refined oil will rise steadily and is expected to return to the pre-pandemic level. Among them, the demand for gasoline and diesel will usher in a strong growth, but jet fuel is still under pressure. In 2022, due to the sanctions imposed by western countries on Russian energy, the oil and gas supply fundamentals was tightened. With the soaring price of natural gas, high temperature in summer and high probability of cold winter in some areas, the demand for oil power generation has increased. However, due to the conflict between China and Ukraine and the blockade policy of to deal with the pandemic, the global economic growth rate has slowed down. These factors, combined with high inflation in the US and Europe, have led to a slow recovery in demand for refined oil. Among them, the demand for gasoline recovered less than expected, and the demand for jet fuel recovered better. In terms of gasoline, the global gasoline demand in 2021 was 25.6 million barrels per day, an increase of 330,000 barrels per day, or 8%. In 2022, the global gasoline demand will further resume growth. The International Energy Agency predicts that the global gasoline demand will be 25.9 million barrels per day in 2022, up by 280,000 barrels per day, with an increase of 1.1 percentage points. Specifically, the price of gasoline in the US rose in 2022, and once soared to $5/gallon in mid-June, which, combining with high inflation, restrained travel demand. The demand for gasoline in the driving season was less than expected. From June to September, the average demand for gasoline in the US was 8.91 million barrels per day, a year-onyear decrease of 430,000 barrels per day, which was 420,000 barrels per day lower than the average in the past five years and 71 lower than the average in 2017–2019. In Europe, affected by the conflict between Russia and Ukraine and the slowdown of global economic growth, the demand for gasoline in various countries has declined to varying degrees, but many governments such as Germany, France, Ireland, the Netherlands and Norway plan to increase oil subsidies or implement tax reduction measures, which has slowed down the decline. The data shows that the demand for gasoline in Europe from June to August was 6.04 million barrels per day, down

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750,000 barrels per day year-on-year, down 600,000 barrels per day from the fiveyear average and down 660,000 barrels per day from the 2017–2019 average (see Fig. 6.3). In terms of diesel, with the turnaround of the pandemic and industrial recovery, the global demand for diesel recovered as a whole in 2021, with a total demand of 27.64 million barrels per day, up by 440,000 barrels per day year-on-year, or 6%, making it the best-performing variety in the whole year. In 2022, the global diesel demand is still strong, and the diesel crack spread has become the strongest variety. The diesel demand in the US, China, Indian and other countries has recovered or even exceeded the pre-pandemic level. The International Energy Agency (IEA) predicts that the global diesel demand will be 28.05 million barrels per day in 2022, up by 380,000 barrels per day, or 1.4 percentage points. From the calorific value perspective, oil is currently the cheapest primary energy source, and the demand of industrial enterprises to replace natural gas with oil for power generation is increasing, which supports the demand for industrial diesel fuel. The International Energy Information Agency (IEA) predicts that the demand of such industrial users as refineries for oil instead of natural gas is expected to reach 300,000 barrels per day, including 150,000 barrels per day for fuel oil and 140,000 barrels per day for diesel oil. It is noteworthy that due to the high energy prices and the slowdown of economic growth, the demand for diesel in Europe fell short of expectations. From June to August, the demand for diesel in Europe was 18.38 million barrels per day, down by 790,000 barrels per day year-on-year, 780,000 barrels per day compared with the five-year average and 1.2 million barrels per day compared with the average in 2017–2019 (see Fig. 6.4). In terms of jet fuel, in 2020, due to the outbreak of the COVID-19 pandemic, countries around the world introduced travel bans, which seriously affected international flights. The number of flights in major countries dropped by as much as 70% year-on-year, resulting in the largest decline in jet fuel demand in those countries

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including the US, Europe and the Asia–Pacific region. In 2021, with the improvement of the pandemic situation, countries began to gradually liberalize pandemic prevention measures and cancel travel bans; therefore, the demand for jet fuel improved. In 2021, the average demand for jet fuel in the US was 1.365 million barrels per day, up 297,000 barrels per day year-on-year, and still down 407,000 barrels per day compared with before the pandemic in 2019; and that average demand in Europe was 860,000 barrels per day, up 120,000 barrels per day year-on-year. In 2022, as more countries opened up after the embargo, and border international routes further restored, travel and business travel drove a significant rebound in demand for jet fuel, during which the demand for jet fuel was 3.34 million barrels per day, up 940,000 barrels per day, down 200,000 barrels per day compared to the 5-year average, but still down 1.28 million barrels per day compared to the average of 2017 to 2019. The International Energy Agency expects global jet fuel demand to be 6.11 million barrels per day in 2022, up 919,000 barrels per day, or 17.7% (see Fig. 6.5).

Global Oil Demand Is Expected to Maintain Steady Growth in 2023 The Downside Risks Facing the Global Macro Economy Have Increased, and Inflation Remains High In 2023, the global central banks headed by the Federal Reserve is likely to continue to raise interest rates to curb inflationary pressures, which will bring a lasting blow to the global economy. The market expects the Fed to raise interest rates until 2024,

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0 Time

Australia South America

Asia North America

Middle East Europe

Africa Russia

Fig. 6.5 Trend of global demand for jet fuel by region. Source Rystad Energy; IEA; Unipec Research & Strategy Dep. (URS)

casting a shadow over the global economy. Major institutions have continuously lowered the global economic growth rate in 2023. According to the IMF, the global economic growth rate in 2023 was 2.9%, 0.3 percentage points lower than that of the previous year. Among them, the growth rate of emerging economies will increase slightly from 3.6% last year to 3.9%, while that of developed countries will drop from 2.5 to 1.4%. This advantageous trend of emerging economies will continue in the stage of steady global economic recovery. In terms of countries, in 2023, high inflation and interest rate hikes will have the most serious impact on developed economies such as Europe and the US, while the economies of developing countries such as China are expected to recover further. Specifically, the economies of the US and the euro zone only grew by 1.0% and 1.2% respectively, lower than the pre-pandemic level. China’s economic growth will accelerate to 4.6%, while India’s will slow down slightly to 6.1% (see Table 6.1). In the future, the persistent inflationary pressure and the tightening of the global financing environment caused by the central bank’s interest rate hike, the spillover effect caused by the effective Russian energy sanctions, and the global supply chain and labor shortage will further bring downside risks to the economy.

The World’s Major Economies Are Expected to See Limited Growth in Oil Demand In 2023, as the pandemic prevention and control measures are gradually relaxed, the global oil demand is expected to increase, but it is still subject to the macro economy and faces great risks, so the upward momentum of this demand is limited. According to the expectations of major institutions, the International Energy Agency predicts that the global oil demand will exceed 100 million barrels per day to 101

6 Outlook for Global Oil Demand in the Post-COVID-19 Era Table 6.1 IMF’s latest world economic forecast (%)

101

Country

2022

2023

China

3.3

4.6

US

2.3

1.0

Japan

1.7

1.7

UK

3.2

0.5

Germany

1.2

0.8

Brazil

1.7

1.1

India

7.4

6.1

Global

3.2

2.9

Source IMF; Unipec Research & Strategy Dept. (URS)

million barrels per day in 2023, an increase of 2.12 million barrels per day. Among them, oil demand will rebound to 103 million barrels per day in the fourth quarter, exceeding the pre-pandemic level. In addition, OPEC is optimistic about the global oil demand in 2023, and it is estimated that the demand growth rate will be 2.7 million barrels per day to 103 million barrels per day, exceeding the pre-pandemic level; Energy Information Administration predicts that the demand will increase by 2 million barrels per day in 2023. In stages, global oil demand will pick up in the first half of 2023, but will remain under the shadow of economic weakness, coupled with the traditional low season in the second quarter, so the growth rate will be limited. However, since the third quarter, with the impact of the pandemic subsided and the effectiveness of the global central bank’s measures to curb inflation appeared, it is expected that the global oil demand will increase rapidly during the driving season, and there will be a certain rebound momentum in the fourth quarter with the boost of heating demand (see Fig. 6.6). From the perspective of Europe and the US, as we enter 2023, on the one hand, enduse demand will be hit by central banks’ austerity policies, and further hit traditional 10,000 barrels/day 11000 9000 7000 5000 3000 1000 0 -1000 US

Q1 Europe

Q2 China

India

Q3 Middle East

Q4 Soviet Union Others

Fig. 6.6 Oil demand forecast of some countries in 2023. Source IMF; Unipec Research & Strategy Dept. (URS)

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energy consumption. On the other hand, with the EU’s energy sanctions against Russia coming into effect at the end of 2022, the energy supply crisis will further worsen, soaring energy prices and inflationary pressures may further hit the European economy, and other countries will not escape the spillover effects. It is estimated that the US oil demand will be 20.4 million barrels per day in 2023, an increase of 100,000 barrels per day year-on-year, which is significantly slower than that in 2022, while the demand of European countries will decrease by 140,000 barrels per day to 13.74 million barrels per day. From the perspective of the Asia–Pacific region, with the gradual improvement of the pandemic in 2023, the economies in East Asia will recover, and the vast majority of oil demand growth will be concentrated in Asia, accounting for 96% of the global total demand. In India, under the influence of external environment deterioration and internal policy tightening, it is expected that India’s economic growth will slow down in 2023, which may limit the growth of oil demand to some extent. It is estimated that India’s oil demand will increase slightly by 220,000 barrels per day in 2023, slightly narrower than the previous year. The effect of pandemic prevention and control in China has been obvious. In addition, the government has continuously introduced economic stimulus plans. In 2023, as the impact of the pandemic on China’s economy and travel is expected to weaken, the economy may continue to develop rapidly and the demand may increase significantly. From the crude oil side, in the past two years, China has gradually phased out backward refining capacity, and large-scale integrated private refineries have been put into operation one after another, which has boosted the demand for crude oil. However, since last year, due to the repeated outbreak of pandemic, domestic energy supply guarantee, domestic refined oil market rectification and other factors, China’s crude oil imports and refined oil exports have been declining continuously, and the pattern of high imports and high exports has changed, which will have a certain impact on the global crude oil market.

In 2023, the Demand for Diesel Oil Will Recover Slowly, While the Demand for Jet Fuel Will Recover Well In 2023, the global demand for short-distance travel is expected to continue to recover, and commuting to work will increase, which will support the demand for gasoline. The International Energy Agency predicts that the global gasoline demand will be 26.04 million barrels per day in 2023, up 137,000 barrels per day year-on-year, with an increase of 0.5 percentage point mainly from the Asia–Pacific region. Among them, the gasoline demand in China is expected to be 3.52 million barrels per day, up 96,000 barrels per day, or 2.8 percentage points, and that in India is estimated to be 900,000 barrels per day, up by 36,000 barrels per day, or 4.1 percentage points. In terms of diesel, the economic growth of major economies in the world is weak, and economic activities may slow down; however, the high price of natural gas

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supports the increase in demand for oil-fired power generation. Overall, it is expected that the demand for diesel will end the high growth trend, but remain relatively strong. The International Energy Agency expects that the global demand for diesel fuel in 2023 will be 27.98 million barrels per day, basically flat year-on-year, with only a slight increase of 0.9 million barrels per day, close to the level before the pandemic. Among them, China’s diesel demand is expected to be 3.49 million barrels per day, up 19.1 million barrels per day, or 5.8 percentage points; and India’s is expected to be 1.79 million barrels per day, up 8.4 million barrels per day, or 4.9 percentage points. Affected by the depressed macro-economy, the demand for diesel in the US remained stable. In terms of jet fuel, with the decline of the pandemic, the demand for jet fuel is expected to recover further in 2023 and become the main engine driving the growth of global oil demand. The International Energy Agency predicts that the global demand for jet fuel will be 6.89 million barrels per day in 2023, a sharp increase of 770,000 barrels per day, or 5%. China’s jet fuel demand is expected to be 740,000 barrels/ day, a sharp rise of 176,000 barrels/day, or 31.3%; India’s is expected to be 204,000 barrels/day, up 5.2 million barrels/day, or 34.3%.

The Trend of Global Medium- and Long-Term Oil Demand Currently, despite the bleak economic prospects and the blow of the pandemic, global oil demand still has some room for recovery, but in the future, as the pace of energy transition accelerates, energy transition strategy will become one of the important factors affecting the demand for traditional energy. In the medium to long term, according to BP’s latest energy outlook report, in the baseline scenario, global road travel demand is affected by improved transport efficiency and energy transition and decline; in the aviation and maritime sectors, the decline in demand for jet fuel and fuel oil is mainly due to the impact of biofuels and hydrogen energy, putting pressure on global oil demand. By 2035, the proportion of demand affected by the improvement of travel efficiency will reach 60–70%. In addition, with the rising voice of low-carbon energy transformation in various countries, carbon neutrality will accelerate the market demand for traditional energy. Since the European Commission issued the European Green Agreement in December 2019, several large European energy groups have successively formulated their zerocarbon transition routes. China has also announced a major strategic decision to achieve peak carbon dioxide emissions by 2030 and carbon neutrality by 2060. Under the profound changes unseen in a century, the international political and economic landscape has been evolving at an accelerated pace, and the global efforts to promote low-carbon and sustainable development goals have posed huge challenges to traditional energy demand. However, it is worth noting that since 2021, many countries in the world, especially in Europe, have experienced severe energy crises, so the EU government is expected to relax its aggressive carbon emission policies to boost traditional energy demand, so that the energy transition may temporarily

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give way to energy security. In the medium to long term, the share of developing countries in global oil demand will increase to nearly 80% by 2050 as major Western countries rapidly achieve peak carbon dioxide emissions. In the future, as energy technology innovation enters a highly active period, energy technology will make a breakthrough, and clean energy, mainly wind energy and solar energy, will rise rapidly. The development and application of large-scale energy storage technology will accelerate the development of green and low-carbon energy. All these will further reduce the global demand for crude oil.

Conclusion In the post-pandemic era, the global oil market is entering a period of rapid change. As the global impact of the pandemic recedes and socio-economic activity increases, global oil demand is recovering, with many countries having recovered to or even surpassed pre-pandemic levels. Since 2020, global oil demand has continued to struggle to grow amidst a gloomy global economic outlook and a recurring pandemic in China. As the impact of the pandemic gradually recedes, the world will turn its attention to major strategies for energy transition, and the rapid rise of new energy sources will gradually replace traditional energy demand, bringing greater challenges to traditional energy markets. This situation will also accelerate the global oil demand to peak. The demand for oil in developed countries will gradually decline after peaking at a faster time, while there is still room for demand growth in developing countries for a long time. In addition, in the critical period of global energy reform, oil companies will face greater challenges, and the gradual peaking of oil demand growth will force major oil companies to accelerate the pace of transformation from oil developers and producers to comprehensive energy companies. BP, Shell, ExxonMobil and other companies are accelerating technological innovation, reducing costs and increasing efficiency, and actively seizing digital transformation opportunities to improve international competitiveness in the traditional oil sector; on the other hand, they are also expanding the layout of the natural gas sector and entering the new energy sector, such as hydrogen, fuel cells and new materials.

Bibliography BP (2022) Energy outlook 2022 edition. BP, London Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences, China International United Petroleum & Chemicals Co., Ltd. (2021) Annual report on Chinas petroleum industry development. China International Energy Agency (2022) Oil market report. IEA, Paris International Monetary Fund (2022) World economic outlook update: gloomy and more uncertain. IMF, Washington DC

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Rystad Energy (2022) Oil market weekly report US Energy Information Administration (2022) Short-term energy outlook

Di Hu Master, Analyst, Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd., focusing on international macro markets and international oil price trends. Ying Zhao Master, Analyst, Market Strategy Department of China International United Petroleum & Chemicals Co., Ltd., focusing on carbon markets and international oil price trends.

Chapter 7

Development Status and Prospect of Global Oil Refining Industry Han Li, Kaijun Gong, and Zhuo Fang

The Global Refining Industry Gradually Recovered from the Pandemic in 2021, but the Refining Capacity Declined for the First Time in 30 Years In the Post-Pandemic Era, Refinery Projects Were Delayed, and a Wave of Refinery Closures Continues Globally In 2021, the COVID-19 pandemic continued to spread around the world. Although refinery processing revenue and major oil crack spreads have rebounded, but are still at a low level. The carbon–neutral transformation forced major economies around the world to speed up the divestiture of traditional refining business and eliminate backward production capacity. Most new refining projects were delayed, and refineries in the US and Europe were shut down one after another, thus the global refining capacity decreased for the first time since 1988, by 1.08 million barrels per day year (Fig. 7.1).

Some New Projects Were Delayed, and the New Refining Capacity Was Lower Than Expected In 2021, the global new and expanded projects contributed a total of 530,000 barrels per day, much lower than the original forecast of 2.23 million barrels per day, mainly because of the pandemic and other factors that have delayed many new projects. New capacity is coming from Saudi Arabia and Iraq, with Saudi Arabia’s Jazan Refinery at H. Li (B) · K. Gong · Z. Fang Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_7

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H. Li et al. 10,000 barrels/day 11000 10000 9000 8000 7000

19 88 19 90 19 92 19 94 19 96 19 98 20 00 20 02 20 04 20 06 20 08 20 10 20 12 20 14 20 16 20 18 20 20 20 22 *

6000 Year

Fig. 7.1 Global refining capacity from 1988 to 2022. Source BP Statistical Review of World Energy 2022; UNIPEC Research and Strategy

400,000 barrels/day among the larger new facilities, while Kuwait’s Al-zour refinery (615,000 barrels/day) and the Jebel Ali refinery in the United Arab Emirates (32.6 barrels/day) were scheduled to come on stream were delayed to 2022, slowing global capacity growth. The specific projects of global new and expanded refining capacity in 2021 are shown in Table 7.1. Construction of the Jazan Refinery in Saudi Arabia began in 2015, but the project has been delayed several times due to the oil field attacks in Saudi Arabia in 2019 and the COVID-19 outbreak in 2020. In December, 2021, Jazan Refinery was officially put into operation, increasing Saudi Arabia’s refining capacity by 400,000 barrels per day to 1.4 million barrels per day. Iraq’s Baiji refinery, which is part of Iraq’s North Refineries Company, increased refining capacity from 6.5 million bpd to 140,000 bpd. In 2021, the refinery resumed operations in September after several summer shutdowns due to severe power shortages in Iraq during the summer, producing approximately 100,000 barrels/day. The Basrah Refinery, which had a refining capacity of 195,000 barrels/day in Phase I and increased to 260,000 barrels/day after a 65,000 barrels/day expansion, currently processes about 210,000 barrels/day on a daily basis. In August 2022, it was once surrounded by insurgents during the unrest in Iraq and was at risk of being shut down. Table 7.1 Projects of global new and expanded refining capacity in 2021 Country

Refinery/Project

New construction/capacity expansion (0,000 barrels per day)

Production time

Saudi Arabia

Jazan

New construction; 40

Second quarter of 2021

Iraq

Baiji

Capacity expansion; 6.5

June 2021

Basrah

New construction; 6.5

August 2021

Total

53

Data source UNIPEC Research and Strategy, FGE, Reuters, Platts, IHS.

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Refining Capacity Continues to Be Withdrawn in Europe and the US in Favor of Biofuel Production In 2021, despite the recovery of the demand side, the wave of refinery shutdown caused by the pandemic has not yet receded. The clean energy policy orientation in Europe and the US has made some large energy companies transform their downstream businesses, further promoting the shutdown and transition of refineries, which has had a huge impact on the refining industry. Globally, about 1.612 million barrels per day of refinery capacity was permanently closed. Among them, seven refineries were closed in Europe, with a permanent shut-down capacity of nearly 680,000 barrels per day, accounting for 42. 2% of the total shut-down capacity; North America shut down nearly 695,000 barrels per day, accounting for 43. 1% of the total production capacity. The global refinery shutdown in 2021 is shown in Table 7.2.

Shutdown of Refineries in Australia In February 2021, Exxon Australia shut down the Altona Refinery, which has a capacity of 90,000 bpd, and plans to integrate its common infrastructure with Mobil’s Melbourne fuel import and storage terminal in 2022. In March 2021, BP Australia shut down Kwinana Refinery in Perth, with a capacity of 146,000 barrels per day. Table 7.2 Global refinery shutdown in 2021 Country

Company

Refinery/Project

Australia

Exxon

Altona

Australia

BP PLC

Kwinana

14.6

US

Shell

Cnovent

24.0

US

Phillips 66

Sanfrancisco

25.5

US

Limetree Bay

Arelight and Freepoint

20.0

Finland

Neste

Naantali

Portugal

Galp

Matosinhos

11.0

France

Total SE

Grandpuits

10.0

France

Total SE

La Mede

15.5

Norway

Exxon Mobil

Slagen

12.0

Sweden

Preem AB

Lysekil

Sweden

Preem SE

Gothenburg

Total

Refining capacity (0,000 barrels per day) 9.0

5.5

1.7 12.4 161.0

Source UNIPEC Research and Strategy; FGE; Reuters; Platts; IHS

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Shutdown of Refineries in the US The impact of the pandemic on the demand side has started a wave of US refinery shutdowns since 2020 and will not stop in 2021. The tightening of US renewable fuel policies and the clean energy revolution have become the government’s core means of addressing the climate crisis, forcing major refiners to accelerate the transition to clean energy business, leaving US refining capacity at its lowest level since 2014. In June 2021, the Limetree Bay Refinery was ordered to close by the US Environmental Protection Agency due to environmental pollution concerns and was acquired by Jamaican storage company West Indies Petroleum in December 2021. The company said it planned to operate the refinery, but it has not been restarted because of outstanding environmental issues. Shell and Phillips 66’ s refineries in Los Angeles were permanently shut down, with a total shut-down capacity of about 460,000 barrels per day.

Shutdown of Refineries in Europe In 2021, approximately 680,000 barrels/day of capacity was shut down in Europe. European refineries were built earlier, so today they are seen as outdated and less adaptable. In 2021, refinery gross margins fell into negative territory, accelerating refinery retirements. Since 2019, under strict decarbonization policies, BP, Shell, Total, Eni, Statoil and others have announced their net-zero emission strategic targets, starting to develop renewable energy and transforming into integrated energy service providers. In March 2021, Finnish company Neste shut down its smaller Naantali Refinery (55,000 bpd) and shifted the site’s focus to terminal and port operations. In April 2021, Portugal’s Galp permanently shut down its Matosinhos Refinery (110,000 barrel/d), leaving the only remaining refinery in Portugal, Sines, in operation. In June 2021, Exxon Mobil shut down its refinery in Slagen, Norway, to convert it into a fuel import terminal with a capacity of 120,000 bpd. In addition, the French company Total switched its two refineries in Grandpuits and La Mede to renewable fuel production, reducing capacity by a total of 255,000 barrels/day. Sweden’s Preem AB and Preem SE also switched to renewable fuel production.

Crude Oil Processing Capacity of Refineries Globally The marginal impact of the pandemic on oil consumption gradually diminished in 2021 as the global pandemic situation improved, and the sustained economic recovery after the pandemic also boosted oil demand. According to the IEA, global oil consumption in 2021 was 96.6 million barrels per day, an increase of nearly 6% year-on-year, driving global crude oil processing out of the trough and exceeding 80 million barrels per day by the end of the year, back to the level at the beginning

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10,000 barrels/day 9000

8000

6000

January 2009 July 2009 January 2010 July 2010 January 2011 July 2011 January 2012 July 2012 January 2013 July 2013 January 2014 July 2014 January 2015 July 2015 January 2016 July 2016 January 2017 July 2017 January 2018 July 2018 January 2019 July 2019 January 2020 July 2020 January 2021 July 2021

7000

Time

Fig. 7.2 Global crude oil processing capacity of refineries from 2009 to 2021. Source Energy aspects; UNIPEC research and strategy

of the pandemic. And according to consulting firm Energy Aspects, global refinery processing volumes rose by 3.74 million barrels per day, or 4.4%, to 77.12 million bpd in 2021 (see Fig. 7.2). The crude oil processing volume of OECD countries led by Europe and America increased by 4% year-on-year, while that of China increased by 4. 3% year-on-year, which was 7. 4% higher than that before the pandemic in 2019, with an average growth rate of 3. 6% in two years. The operating rate of refineries has also continued to rise. The average operating rate of refineries around the world reached about 80%, with the Middle East and Asia Pacific better than the previous year. In 2021, refineries around the world adjusted their oil product yields in line with market demand. By oil type, gasoline was the oil product with the strongest demand growth. According to the IEA, by the end of 2021, gasoline demand in the US, China, India and other countries has recovered to levels even higher than before the COVID-19 pandemic. In 2021, the global gasoline demand resumed to increase by 10.1%, and the gasoline yield of refineries around the world increased by as high as 3.11% compared with 2020, leading the growth of diesel and jet fuel, of which Asia, Europe and Latin America experienced stronger growth, with their gasoline recovery rate remaining at about 25% (see Fig. 7.3). As for diesel, driven by the economic stimulus policies of various countries, the world diesel production and consumption have recovered. The implementation of the new regulations on sulfur content of the International Maritime Organization has led to an increase in diesel demand, close to the level in 2019. In 2021, the world diesel supply was about 27.31 million barrels per day, up by 3. 5% year-on-year; the demand was about 27.67 million barrels per day, up 5. 6% year-on-year. Worldwide, the oversupply of diesel fuel eased, with many regions even experiencing a tight supply of diesel fuel, significantly lowering inventories. The average oil recovery

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Year Africa Asia Europe Soviet Union Latin America Middle East North America

Fig. 7.3 Gasoline recovery rate of refineries around the world from 2009 to 2021 % 60.00 50.00 40.00 30.00 20.00 10.00 0

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Year Africa Asia Europe Soviet Union Latin America Middle East North America

Fig. 7.4 Diesel recovery rate of refineries around the world from 2009 to 2021

rate of diesel oil from refineries in the world rebounded slightly, and the increase in the Middle East was obvious (see Fig. 7.4). Jet fuel is the oil most affected by the pandemic, and is also a variety with lagging recovery. Following the COVID-19 outbreak, the jet fuel recovery rate of refineries plummeted worldwide in 2020, about 70% of the level in 2019. In 2021, the impact of the pandemic subsided slightly, and jet fuel market consumption increased by 24. 6% compared to 2020, but still far below the pre-pandemic level in 2019. According to statistics, the number of global flights in 2021 only recovered to 73% of the same period in 2019. It is estimated that the demand for jet fuel will fully recover as early as 2023. In 2021, jet fuel skimming rates rebounded considerably, with North America, Europe and Latin America, the regions that experienced the largest declines in jet fuel skimming rates in 2020 due to the pandemic, increasing by 1. 53%, 0. 24% and 0. 52%, respectively, in 2021 (see Fig. 7.5).

7 Development Status and Prospect of Global Oil Refining Industry % 16.00 14.00 12.00 10.00 8.00 6.00 4.00 2.00 0

113

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Year Asia Europe Soviet Union Africa Middle East North America Latin America

Fig. 7.5 Jet fuel recovery rate of refineries around the world from 2009 to 2021. Source Energy aspects; UNIPEC research and strategy

The Processing Revenue of Major Refining Centers in the World Has Been Repaired, but is Still at a Low Level In 2021, with the gradual improvement of the global pandemic, as well as the continued recovery of major economies, global oil demand rebounded, driving the refiners’ enthusiasm, along with the rise of the operating rate of refineries. But at the same time, upstream investment in the oil industry around the world has not increased significantly, and oil supply growth has been slow. The Opec + ‘s determination to control the oil market price has not diminished, resulting in a tight oil market supply throughout the year, and the gradual digestion of crude oil and refined oil inventories and continued low inventory. The rising price of crude oil has helped to squeeze refining margins and slow down the recovery of processing revenue. In addition, futures have largely moved in line with spot movements throughout the year, with a healthy discount level for physical crude and a weak tanker shipping market throughout the year, giving refiners some room to grow. In the fourth quarter of 2021, with the energy crisis sweeping the world, traditional fossil energy prices hit new or record highs in recent years. At the same time, the global spread of COVID19 mutant variants has again dampened market confidence, and a fall in demand has triggered a short-term pullback in refining margins. Singapore and Rotterdam refining margins retreated by nearly $6/barrel in just one month in November, a drop of more than 70%. As the mutant variants was deemed less virulent and the ease of lockdown measures in the US and Europe, oil demand rebounded quickly and gross margins in the three major refining centers returned to high levels by the end of December. As shown in Fig. 7.6, gross refining margins for complex refiners in the Gulf Coast in 2021 averaged $11/barrel, up $4.91/barrel from the previous year, returning to 80% of pre-pandemic levels. Driven by the relief of the pandemic in the US, the gross refining margin in the Gulf Coast increased by more than 100% year-on-year in the second, third and fourth quarters, respectively, with significant recovery in gross margin. Gross refining margins at Rotterdam’s complex refineries averaged

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$3.76/barrel for the year, up $1.49/barrel year-over-year and back to 72% of prepandemic levels. Gross refining margins in Rotterdam climbed quarter-on-quarter as outbreak control measures became more sophisticated and European demand gradually recovered. In the fourth quarter, European gross refining margins rose to nearly $7/barrel, a 13-year high, spurred by energy crises such as the U.K. oil shortage and the European gas shortage. The gross margins of complex refineries in Singapore averaged $ 3. 45/barrel, up $ 3. 07/barrel year-on-year, recovering to 93% of the pre-pandemic level. Driven by the steady recovery of demand and the quarterly increase of crude oil prices, the gross refining margins in the Asia–Pacific region also showed a quarterly increase trend, with the average level in the fourth quarter exceeding $6/barrel, steadily returning to the pre-pandemic level (Fig. 7.7). $/barrel 35 29.93

30 25 20 15

13.67

10

7.1

5 0

7.72 2015

15.8

15.21 8.24 4.9 6.12 2016

12.57

12.72

6.6

5.5

7.09 2017

WTI Gulf Coast

12.11 5.2

5.84 2018

13.46

7.20 2.3

3.8

3.45 0.38 2020 2021 January - Year August 2022 Brent Rotterdam Dubai Singapore 3.72 2019

Fig. 7.6 Annual processing revenue of three major oil refining centers from 2015 to 2022. Source Reuters; UNIPEC research and strategy

$/barrel 55 45 35 25 15

20 19 20 0119 01 -0 20 4 19 01 20 0719 01 20 1020 01 20 -0120 01 20 - 0 4 20 -01 20 -0720 01 20 1021 01 20 0121 01 -0 20 4 21 01 20 0721 01 20 1022 01 20 -0122 01 20 0 4 22 01 -0 701

5 -5

WTI Gulf Coast

Brent Rotterdam

Time

Dubai Singapore

Fig. 7.7 Daily processing revenue of three major oil refining centers from 2019 to 2022. Source Reuters; UNIPEC research and strategy

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Crack Spreads of Major Oil Products Have Rebounded Steadily, and Low-Sulfur Fuel Oil Has Continued Its Strong Growth In 2021, against the backdrop of a gradual recovery in global oil demand, the crack spreads of major oil products have rebounded steadily. As the world becomes more experienced in dealing with the pandemic, the impact of the pandemic on oil demand gradually weakened, and demand rebounded much faster than supply. In addition, due to the impact of declining investment, shrinking profits and environmental policy pressure in the post-pandemic era, it is difficult to recover the refining capacity closed during the pandemic in the short term, so the global crude oil stocks and oil product inventories both fell, driving the recovery of the major oil crack spreads. Specifically, as countries around the world gradually lifted restrictions, the global road traffic index in 2021 rose from less than 90% of the pre-pandemic level at the beginning of the year to more than 95%. What’s more, in Asia, the focus of consumption, it had basically recovered to pre-pandemic levels by the end of the year. As a result, gasoline demand recovered strongly. In 2021, Singapore’s gasoline crack spread averaged $9.1/barrel, 3.2 times the average for 2020, with an average value of nearly $13/barrel in the fourth quarter, well above the pre-pandemic level for the same period; Europe’s gasoline crack spread averaged $10.27/barrel, 3.9 times the average for 2020, well above the pre-pandemic level; and the US RBOB gasoline crack spread averaged $19.73/barrel, up 90% year-over-year and also higher than the pre-pandemic level (see Fig. 7.8). In terms of diesel, the global economy has fully recovered in the post-pandemic era. Under the dual stimulation of fiscal and monetary policies in various countries around the world, economies around the world are rapidly pulling out from the quagmire of 2020, and new infrastructure projects are being launched one after another, leading to a strong recovery in industrial activities and a steady recovery in diesel demand. Singapore diesel cracker spread for 2021 was $8.39/barrel, up 17% year-on-year, still lower than the pre-pandemic level; and that in the Gulf Coast and $/barrel 48 28 8

20 19 20 01-0 19 1 -0 20 4 - 0 19 1 -0 20 7-0 19 1 -1 20 0 - 0 20 1 20 010 20 1 20 0 4 20 01 20 07-0 20 1 -1 20 0 - 0 21 1 20 01-0 21 1 -0 20 4 - 0 21 1 -0 20 7-0 21 1 -1 20 0 - 0 22 1 20 01-0 22 1 -0 20 4 22 01 -0 701

-12

Gulf Coast

Rotterdam

Time

Singapore

Fig. 7.8 Gasoline crack spread in Singapore, Rotterdam, and Gulf Coast in 2019 to 2022. Source Reuters; UNIPEC research and strategy

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Fig. 7.9 Diesel crack spread in Singapore, Rotterdam, and Gulf Coast in 2019 to 2022. Source Reuters; UNIPEC research and strategy

Rotterdam showed a steady recovery. It is worth mentioning that the global air traffic index did not show a significant recovery in 2021. China’s aviation index basically stabilized at about 70% of the pre-pandemic level; and the international aviation index, which has the greatest impact on the demand for jet fuel, rebounded from 30% at the beginning of 2019 to about 55% at the end of the year, but it is still far below the pre-pandemic level. The Singapore jet fuel crack spread averaged $5.86/ barrel for 2021, up 131% year-on-year, but still only 42.7% of 2019’s level (see Fig. 7.9), due to the slow pace of border deregulation in various countries, especially the lagging recovery of China-related international routes. In addition, the marine fuel oil market is recovering solidly, with low-sulfur fuel oil still performing strongly as a new market favorite. In the second year of the new IMO regulations, low-sulfur fuel oil continued to perform strongly, with crack spreads higher than diesel at most points throughout the year, and was highly sought after by the market. At the same time, high sulfur fuel oil did not show weakness, and the trend was solid throughout the year, with the spread between high and low sulfur fuel oil not significantly widened, indicating that under the fundamental situation of trade demand not increasing significantly throughout the year, the ship position with desulfurization tower was relatively stable, and the market remained relatively balanced. In 2021, the crack spread of low-sulfur fuel oil averaged $12.7/barrel, up 13% year-on-year, basically the same as in 2019. The price difference between high-sulfur fuel oil and low-sulfur fuel oil remained at around $20/barrel, and the competitiveness of low-sulfur fuel oil was not fully demonstrated (see Fig. 7.10).

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$/barrel 64.00

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Fig. 7.10 Crack spread of high- and low-sulfur fuel oils and diesel in Singapore in 2019 to 2022. Source Reuters; UNIPEC research and strategy

In the Post-Pandemic Era, the Global Oil Refining Industry Will Gradually Come Out of the Doldrums Global Refining Capacity Resumes Rapid Growth In 2022, the global impact of the pandemic gradually receded, and some of the large refining projects originally planned to be put into operation in 2021 were finally completed in 2022. China, the Middle East and Indonesia become the main regions contributing to the world’s refining capacity growth. The wave of refinery closures in the US and Europe spread to the Asia–Pacific region, with Japan and Singapore shutting down larger local refineries and China’s refinery closures mainly take the approach of integrating small-scale local refinery resources. In 2022, global refining capacity will grow by a net 2.36 million barrels per day, returning to normal year expansion levels.

Several Large Projects Came on Stream, Concentrated in China and the Middle East Combining data from Platts, FGE and IHS, global refining capacity will increase by 2.78 million barrels per day in 2022, a significant expansion from 2021, with refinery projects in the Middle East and Asia Pacific steadily advancing. Among them, Asia Pacific added 1.698 million barrels per day of refining capacity, accounting for 61% of the world’s new refining capacity. China has three large refining projects, namely Zhejiang Petrochem & Chemical Phase II (400,000 bpd), CNPC Guangdong’s Refining-Chemical Integration Project (580,000 bpd) and Shenghong RefiningChemical Integration Project (320,000 bpd). The Middle East added 1.08 million bpd of refining capacity, accounting for 38% of the world’s new refining capacity,

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with new and expansion projects coming from Kuwait, Iraq and the UAE respectively. Among them, the project attracting the most market attention is the Al-zour Refinery in Kuwait, with a capacity of 615,000 bpd, originally planned for completion in 2020, but delayed to 2022 due to the pandemic, and expected to be fully operational by the end of 2022 (see Table 7.3). The refining capacity of Zhejiang Petrochem & Chemical Phase II project is 400,000 barrels per day. The first batch of units of the project (including normal depressurization and related utility units) was put into operation on November 1, 2020. The Phase II will be fully commissioned on January 12, 2022, after which Zhejiang Petrochem & Chemical will have an additional refining capacity of 400,000 barrels per day (20 million tons per year), 6.6 million tons per year of aromatics and 1.4 million tons per year of ethylene, with a total capacity of 40 million tons per year, making it the largest refinery in China. Zhejiang Petrochem & Chemical has a high proportion of chemicals and mostly produces aromatics and ethylene raw materials, while the oil recovery rate of refined products is relatively low. At present, Table 7.3 Projects of global new and expanded refining capacity in 2022 Country

Company

Refinery/Project

Production time

Refining capacity (0,000 barrels per day)

China

Zhejiang Petrochem & Chemical

Zhejiang Petrochem & Chemical Phase II

January 12, 2022

New construction; 40.0

CNPC

CNPC Guangdong’s Refining-Chemical Integration Project

2022

New construction; 58.0

Eastern Shenghong

Shenghong Refining-Chemical Integration Project

May 16, 2022

New construction; 32.0

Kuwait

KIPIC

Al-zour Refinery

2022

New construction; 61.5

Iraq

INOC-ORA

Karbala Integrated Refinery

2022

New construction; 14.0

UAE

ENOC

Jebel Ali Refinery

2022

Capacity expansion; 32.6

India

Hindustan Petroleum Corporation Ltd

Visakhapatnam Refinery

2022

Capacity expansion; 32.6

Indonesia

PT Pertamina

Balongan Refinery

2022

Capacity expansion; 23.0

Vitol

Tanjung Bin Refinery

2022

Capacity expansion; 3.3

Total Source UNIPEC research and strategy; FGE; Reuters; Platts; IHS

278.0

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the oil yield of the Phase I project is 35%, and that of the Phase II project will be further reduced to 29%, much lower than the average level of over 60% in traditional refineries. CNPC Guangdong’s Refining-Chemical Integration Project is the largest integrated refining and chemical project invested by CNPC at one time. It is expected to have a production scale of 580,000 barrels per day of refining, 2.6 million tons per year of aromatics and 1.2 million tons per year of ethylene, as well as a 300,000-ton crude oil terminal and a 30,000–50,000-ton product terminal. As of August 1, all 18 sets of major units in the refining area of CNPC Guangdong were delivered, and the total construction progress of the project reached 99.78%, with 175 out of 192 major units completed. As of August 24, the No. 1 Air Separation Unit of the air separation system of the CNPC Guangdong Project has been put into operation, and all the units of the public works have entered the production stage. The consultant FGE expects the project to be fully operational by the end of the third quarter of 2022. Shenghong Refining-Chemical Integration Project is the largest single refinery project in China. The project builds 320,000 barrels per day (16 million tons per year) of oil refining, 2.8 million tons per year of aromatics, and 1.1 million tons per year of ethylene. It will be accompanied by a 300,000-ton crude oil terminal, four 50,000-ton product and liquid chemical terminals and 3.5 million cubic meters of tank farm and other storage and transportation facilities. The project started construction in December 2018 and was scheduled to commence operation at the end of 2021, but was postponed to mid-2022 due to the impact of rising international oil prices and pandemic prevention and control policies. On May 16, 2022, Eastern Shenghong announced that the relevant units of Shenghong Refining-Chemical Integration Project are ready for feeding and start-up, and its atmospheric and vacuum distillation unit was successfully started up in one go. When mass production begins, Shenghong’s refined product yield will be approximately 37%, which is well below conventional refinery levels. Al Zour Refinery in Kuwait is another important project in addition to CFP to revive the refining industry in Kuwait. The refinery has a capacity of 615,000 bpd and was scheduled to start up in the third quarter of 2020, but the project has been delayed due to the pandemic. The refinery has three new crude distillation units, each with a capacity of 205,000 bpd. In June 2022, media reports indicated that Al Zour Refinery would start operating two of the crude distillation units in July and would be fully operational in 2023. On July 27, the refinery was operating at approximately 50% capacity and was being progressively started up. Karbala Refinery in Iraq is the only new refinery in the history of modern Iraq, with a capacity of 140,000 bpd. Its construction began in 2014, but has continued due to war and unrest. The Karbala refinery integration project has reportedly progressed steadily over the past two years and is now 90% complete, with the official startup set for September 2022. In July 2022, the Iraqi Oil Minister stated that Karbala Refinery would be operational by the end of 2022. Jebel Ali Refinery in the UAE is owned by Emirates National Oil Company and will be expanded to 50% of its original capacity, with a total refining capacity of 210,000 bpd. The expansion plan was announced in 2016, with construction to be

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completed in 2019. According to FGE’s analysis, the refinery’s new unit has not been commissioned due to two major reasons: weak market demand and lack of Iranian condensate supply. FGE expects that these two constraints will be alleviated in the third quarter of 2022, and the expansion project will be commissioned in the same quarter. India’s Visakhapatnam Refinery, an expansion project of Hindustan Petroleum Corporation Ltd. (HPCL) that plans to increase refining capacity from 167,000 to 300,000 barrels per day, is already in the advanced stages of construction. According to FGE, the project installed two pipe rack modules in October 2021 and began installation of the pressure-reducing unit in February 2022, with the atmospheric unit expected to be completed in October 2022 and the rest of the upgrade expected to be operational by April 2023. The Balongan Refinery in Indonesia is an expansion project of PT Pertamina. In December 2021, construction of the project reached 65%. FGE forecasts that the project will be commissioned in September 2022. Tanjung Bin Refinery project in Indonesia belongs to Vitol and has a planned capacity expansion of 33,000 bpd. Its construction began in June 2019 and is initially scheduled to be completed in May 2020, but was delayed due to the pandemic and is expected to come online in 2022. The unit is designed to produce IMO2020compliant low-sulfur fuel oil from medium to heavy sweet oils such as Escalante crude oil from Brazil and Dar Blend crude oil from South Sudan.

Refinery Shutdowns Continue, Spreading from Europe and the US to Asia Pacific In 2022, global refinery shutdowns spread from Europe and the US to the developed Asia–Pacific regions, mainly due to lack of competitiveness and industrial transformation. In addition, some small refineries in China have been integrated into large refining projects for industrial replacement. In 2022, the scale of refinery closures will be much smaller than in 2021 and 2020, totaling 420,000 barrels/day, due to the increase in refinery gross margin (Table 7.4). Table 7.4 Global refinery shutdown in 2022 Country

Company

Refinery/Project

Refining capacity (0,000 barrels per day)

New Zealand

Z Energy

Marsdon

14.5

Japan

Eneos

Negishi

12.0

China

HYSH

7.0

Fuyu Chemical

4.4

Shouguang Petrochemicals Total Source UNIPEC research and strategy; FGE; Reuters; Platts; IHS

4.2 42.0

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Z Energy’s Marsdon refinery in New Zealand, which is no longer economically viable due to chronic low margins, ceased refining in April 2022 and has been converted to a gasoline import terminal with a capacity of 145,000 barrels/day. Japan’s Eneos will shut down its Negishi Refinery near Tokyo in October 2022, with a capacity of 120,000 bpd. The company responded that the shutdown was due to weakening market demand and reduced refinery competitiveness. In addition, Eneos announced plans to shut down its Wakayama Refinery (with capacity of 127,500 bpd) in 2023, also due to weakening domestic demand and increased competition from Chinese and Korean refiners. With the closure of these two refineries, Eneos, which controls half of Japan’s gasoline and other fuel markets, will reduce its refining capacity by 13%. Three local refineries in China (HYSH, Fuyu Chemical and Shouguang Petrochemicals) shut down as a result of capacity swaps, with a total capacity of 156,000 bpd to be integrated into the Yulongdao project. Among them, HYSH will also change its product direction, mainly producing energy products such as needle coke in the future. In addition, three refineries (with a combined capacity of 9.12 million barrels per day), namely Haike Chemical, Koleda Chemical and Yongxin Chemical, are scheduled to be shut down and integrated into the Yulongdao project in 2023. According to FGE, the Yulongdao project is expected to be completed in 2025. In addition, US-based Lyondell plans to shut down its refinery in Houston in 2023 with a capacity of more than 230,000 barrels/day due to high maintenance costs. Japan’s Idemitsu Kosan also announced that it will shut down its Yamaguchi Refinery in 2024 and cut gasoline production by about 10%.

The Refining Industry Will See a Gradual Recovery in the Post-Pandemic Era, but Refining Gross Margins Are Difficult to Restore to Pre-Pandemic Level Since 2022, with the outbreak of the Russia-Ukraine conflict, the global energy market has experienced a huge shock, and the hype of Russia-Europe energy decoupling has intensified, with Western countries launching a series of sanctions against Russian oil involving settlement, transportation and insurance. At the same time, the global central banks, led by the Federal Reserve, frequently raised interest rates to tighten liquidity, leading to the evolution of macro risks, and the divergence between the futures and spot trends in the oil market led to a record high spot discount price; in addition, the shipping market volatility intensified, freight rates also rose, so the gross refining margin showed high volatility characteristics. The three major global refining centers hit a record high and then fell back sharply. In the first half of the year, the average monthly gross profit basically showed a monthly upward trend, and the half-year increase reached 3–5 times, so both refining and processing revenues are the best results in the history of the same period. Since the third quarter, as the global inflation level continues to be high, the pace of interest

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rate increase continues to accelerate, the risk of macroeconomic recession looms over the world, coupled with Europe and the US in the driving season of sluggish demand, high oil prices on demand has gradually become prominent, high spot discount and high freight further squeeze the refining industry’s living space, so the refining margins of the three refining centers have dropped significantly. Specifically, in the first three quarters of 2022, the gross refining margin in the Gulf Coast exceeded the $50/barrel mark several times, reaching a yearly high of $53. 58/barrel on May 10, second only to April 20, 2020, the day of negative WTI oil prices. The average of the first three quarters was $29. 81/barrel, an increase of $18. 01/barrel year-on-year. The average price in June reached an all-time monthly high of $47.34/barrel, before falling back to $28.7/barrel in September, down 61% from the peak. Gross refining margin in Rotterdam averaged $16/barrel in the first three quarters, up $13. 33/barrel year-over-year; the average price in June was $25. 45/barrel, the highest monthly level in history; the gross refining margin reached $35. 37/barrel on April 29, the highest level in history; the average price in September was $16. 12/barrel, down $9. 33/barrel from June. Gross refining margin in Singapore averaged $12.21/barrel in the first three quarters, up $9.65/barrel year-on-year; the price reached $30.49/barrel on June 21, the highest level in history, and the average price in June was $24.52/ barrel, the best monthly average level in history. Recently, the price fell to negative values due to the issuance of China’s fifth batch of refined oil quotas, dropping to -$0.45/barrel on September 30. At the same time, fears from geopolitical conflicts spread globally, driving the crack spread of refined oil products to soar rapidly. Gasoline and diesel crack spreads in the three major refining centers hit record highs in the first half of 2022, while jet fuel and low-sulfur fuel oil also followed diesel component price increases, with their crack spreads hitting record highs. On the contrary, high-sulfur fuel oil, due to the restrictions on ship positions with desulfurization tower, marine consumption is difficult to increase, while the demand for asphalt and boiler fuel has been suppressed under the high oil price condition, which led to high-sulfur fuel oil crack spreads to diverge from the trend, hitting a new record low while other oil crack spreads are at record highs.

Medium- and Long-Term Outlook for the Oil Refining Industry At present, macroeconomic risks are spreading globally, and a series of geopolitical risks such as the Russia-Ukraine conflict are profoundly changing the world landscape; at the same time, the pandemic has not yet subsided, extreme weather phenomena are occurring more and more frequently, energy crises are breaking out one after another, and economic development is challenging to achieve green and low-carbon transformation. For the oil refining industry, the global oil market in the medium to long term by the impact of upstream underinvestment is difficult

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to return to the oversupply situation, and new energy alternative is difficult to be achieved overnight, so the transition period of traditional energy resources will be relatively scarce resources. At the same time, the global economic development has led to an increase in energy demand, geopolitical conflicts and the lack of production capacity of oil-producing countries have brought greater uncertainty to the supply, while the high volatility of the crude oil market has been passed on to the refining cost, and the increase in refining market revenue is accompanied by increased risk. In the medium and long term, the carbon neutral process has profoundly changed the development pattern of the refining industry, the green development transformation of the refining industry with low carbon emission reduction is imminent, and the adjustment of product structure to cope with the shrinking consumption of refined oil will become the fundamental condition for the survival of refineries. These show that the competition in the refining industry has been upgraded. In the development trend of refining scale, in recent years, the major oil giants in the US and Europe are accelerating the pace of transformation, and have divested part of the traditional refining business, thus freeing up assets for more shift to biofuels, zero carbon new energy and other directions. In Asia Pacific, there is still some room for expansion in the refining scale, which may be released by accelerating the elimination of backward production capacity, but will also be gradually squeezed as the pace of the automotive electric revolution and new fuel substitution accelerates. In the Middle East, Africa, Latin America and other regions, as the barriers to technology introduction are gradually broken, it is expected to transform from a simple crude oil extraction and sales model to a model of local refining, local consumption or partial export of crude oil, becoming a new growth pole of refining capacity in the medium and long term. In the context of accelerated restructuring of the global industry chain, the green and low-carbon transformation of the oil refining industry may accelerate. According to major authorities, global oil demand is expected to peak around 2030, after which refined oil products will bear the brunt of the gradual replacement and decline. Therefore, the traditional competition model of expanding production capacity and capturing the refined oil market will be gradually eliminated and replaced by the development of bases and industrial clusters, iterative upgrading of new technologies, and flexible adjustment between energy saving, low carbon, pollution reduction, efficiency and product structure to adapt to the market competition and other new dimensions of competition. Specifically, traditional oil refining will accelerate the transformation to refining-chemical integration, refining product raw materialization and specialization, and high-end refinement of chemical products, while combining the construction of large bases and complete industry chain supporting clusters, and fully exploit the value of refining and chemical process by-products to enhance the competitiveness of the whole industry chain. At the same time, the refining industry will, according to market demand, apply oil reduction and chemical technology, special oil targeted production technology, emerging low-carbon or zero-carbon raw material production technology, crude oil direct ethylene technology, molecular refining technology and other transformation and upgrading technologies, and integrate information technology and digital technology, in order to optimize the

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refining production process and develop flexible refineries highly adaptable to the market. In addition, refining energy efficiency improvement, energy resources integration and optimization, economic low-carbon energy substitution, long-cycle stable operation of equipment manufacturing and maintenance, pollution prevention and intrinsic safety will also be important issues in the transformation and upgrading of the refining industry.

Bibliography CNPC economic and technological research institute. Recent development of China’s refining industry in 2021 and recent outlook [R]. China: CNPC economic and technological research institute, 2022 FGE Asia Pacific Databook 2: Refinery configuration and construction. Singapore: FGE. 2022 FGE. Middle East Refining Outlook: An update on projects. Singapore: FGE, 2022

Zhuo Fang Master, Assistant Analyst, Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on oil market supply situation and international oil price trend.

Chapter 8

Analysis of the New Trend of Global Crude Oil Trade Guanhua Wang, Zhuo Fang, and Xiaoyuan Xia

Current Situation of Global Crude Oil Trade in 2021 In 2021, the Total Amount of Global Crude Oil Trade Decreased, and the Eastward Shift of Trade Center Slowed Down In 2021, the total volume of global crude oil trade declined for the third consecutive year in 2021, due to the repeated COVID-19 outbreak, high inflation in major economies such as the US and Europe, downward macroeconomic indicators, and a tortuous recovery of oil demand. In addition, uncertainties on the supply side increased due to declining US production, uncertain prospects of Iran nuclear negotiations, and rising geopolitical situation. In 2021, the total volume of global crude oil trade decreased slightly to 41.35 million barrels per day (see Fig. 8.1), a year-on-year decrease of 750,000 barrels per day, or about 1.9%, and a decrease of 8% compared with the pre-pandemic period, which dragged down the average annual growth rate of crude oil trade from 1.2% to 0.8% in the past 10 years. From 2020 to 2021, the pandemic delayed the production of most large-scale refining and chemical projects, and led to a wave of refinery closures in Europe and the US, as well as the first negative growth in global refining capacity since 1988. Among them, the US shut down capacity of nearly 700,000 barrels/day, with refining capacity falling to the lowest level since 2014; Europe permanently shut down capacity of nearly 700,000 barrels/day, accounting for about 4. 5% of Europe’s total capacity. Nearly 2 million barrels/day of capacity has been shut down worldwide, significantly curbing demand for crude oil imports. G. Wang (B) · Z. Fang · X. Xia Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_8

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Fig. 8.1 Trend of global crude oil trade (by import). Source BP; China customs; EIA; PIRA; Unipec research and strategy (URS)

By region, weak economic growth and an accelerating energy transition in Europe have led to major energy companies announcing net zero emissions strategies and shutdowns of older refineries, such as ExxonMobil’s conversion of its 120,000barrels/day Slagen Refinery in Norway to a fuel import terminal in June and the closure of Portuguese state oil company Galp’s Matosinhos Refinery (110,000 barrels/day). As a result, Europe imported 9.71 million barrels/day of crude oil in 2021, down 200,000 barrels/day from the previous year, reducing its share of global crude oil trade to 23%. North America was hit by extreme weather in 2021, with an unusually cold snap in February affecting 2 to 4 million barrels per day of upstream production in places like Texas. US crude oil production fell after Hurricane IDA swept through the Gulf Coast in August, affecting offshore oil production platforms in the Gulf for more than 25 days. In addition, the pandemic combined with high inflation and incipience of bankruptcies among US shale oil companies has put pressure on the domestic supply side and turned to imports to meet demand. North America imported 6.6 million barrels/day of crude oil in 2021, a slight increase of 130,000 barrels/day from the previous year, accounting for 16% of global crude oil trade. In Asia Pacific, several large integrated refining and chemical projects failed to start production on time in 2021 due to the COVID-19 pandemic. Increased refinery competition against the backdrop of high oil prices and low gross margins, coupled with the mid-year outbreak of the COVID Delta strain in India and the largest decline in passenger traffic by some airlines since the outbreak, has dampened oil demand. In addition, China, the largest crude oil importer, has seen its crude oil imports fall for the first time in nearly 20 years due to the repeated pandemic outbreak and the double tightening of import quotas for local refineries and export quotas for refined oil products. However, overall, Asia Pacific remained the largest crude oil importing region in the world. In 2021, Asia Pacific imports were 23.71 million barrels/day, down 410,000 barrels/day from the previous year. It accounted for 56% of the world’s total crude oil imports, down 1.3 percentage points year on year (see Fig. 8.2).

8 Analysis of the New Trend of Global Crude Oil Trade Fig. 8.2 Global crude oil import shares by region in 2021 (selected regions). Source BP; Unipec research and strategy (URS)

127 1% 1%1% 16%

56%

North America Latin America

23%

Europe Middle East

Asia-Pacific Africa

China’s Crude Oil Imports Declined for the First Time in 20 Years, with a Significant Increase in the Middle East as the Source of Imports China’s crude oil imports have continued to climb since 2001, surpassing the US as the world’s largest crude oil importer in 2017. However, in 2021, China’s crude oil imports declined for the first time in 20 years due to the resonance of multiple factors, such as high oil prices, quota policy changes, repeated pandemics and accelerated energy structure adjustment. In 2021, international oil prices gradually increased, but demand has not recovered to pre-pandemic levels. Some import demand has been dampened by low refinery margins, increased pressure to reduce costs and increase efficiency, and the build-up of crude oil inventories in 2020. Affected by the national adjustment of refined oil export policy, China’s refined oil export quota in 2021 was significantly reduced by 21.42 million tons to 37.61 million tons, down 36% year-on-year, and the impact of export to domestic sales and supply assurance was enhanced, which led to a slowdown of crude oil imports to some extent. According to China Customs statistics, China’s crude oil imports in 2021 was 510 million tons, or 10.31 million barrels per day, down 560,000 barrels per day year-on-year, or 5.1%, the first decline in 20 years. In 2021, China’s dependence on foreign oil reached 71.9 percent, down 1.6 percentage points year-on-year, ending a 15-year growth trend (see Fig. 8.3). From the perspective of importing entities, China’s crude oil importing entities were further diversified, with new refining and chemical projects receiving 42 million tons of import quotas in 2021, or 840,000 barrels per day, including 20 million tons for Hengli and Zhejiang Petrochem & Chemical respectively. State-owned oil companies still dominated, accounting for 69% of total national imports, down about 5 percentage points year-on-year. In 2021, the government strictly enforced the standardized operation of non-state-owned oil companies, and the crude oil import quota of local refineries was cut again and again, and the import volume of local refineries

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Fig. 8.3 Changes in China’s crude oil import volume. Source China Customs; Unipec research and strategy (URS)

declined significantly. A total of 177.14 million tons, or 3.56 million barrels/day, of non-state crude oil imports were issued for the four batches, down 4% year on year, and the proportion of local refineries that gets the full quota dropped to about 70%. From the import source, China’s crude oil import source was still diversified. The Middle East remained China’s most important source of crude oil imports, with China importing 5.17 million bpd of crude oil from the Middle East in 2021, accounting for 50% of total crude oil imports; the share rose for the third consecutive year, up 3 percentage points year-on-year. Among them, Saudi Arabia has been China’s largest source of imports for three consecutive years, with China importing 1.76 million bpd of crude oil from Saudi Arabia in 2021, an increase of 60,000 bpd year-on-year. The CIS region was still the second largest source for China, but its share slightly decreased. In 2021, China imported 1.7 million barrels per day of crude oil from the CIS region, a decrease of 100,000 barrels per day year-on-year, accounting for 16% of the total crude oil imports, down 0.1% year on year. Africa moved from the fourth largest source of crude oil imports to the third, with 1.35 million barrels/day in 2021, accounting for 13% of total crude oil imports. The Americas fell to the fourth place from the third. In 2021, China imported 1.21 million barrels per day of crude oil from the Americas, a sharp decrease of 470,000 barrels per day year-on-year. Its share also fell to 11%, down 4 percentage points from a year earlier, led by sharp declines in imports from Brazil and the US, down 240,000 barrels/day and 170,000 barrels/day respectively. In addition, China’s crude oil imports from Western European countries rose for the second consecutive year, by 50,000 barrels/day to 430,000 barrels/day, accounting for less than 5% of the total, with most of the increase coming from the UK (see Fig. 8.4).

8 Analysis of the New Trend of Global Crude Oil Trade % 100 90 80 70 60 50 40 30 20 10 0 2011

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Fig. 8.4 Changes in China’s crude oil import sources. Source China Customs; Unipec Research & Strategy (URS)

US Crude Oil Exports Fell for the First Time in Six Years Amid the COVID-19 Pandemic Since the shale oil revolution, US crude oil production has soared, and after the government lifted export restrictions in 2015, crude oil exports reached 3 million bpd in 2019 and a record 3.18 million bpd in 2020, once becoming a net oil exporter. In 2021, the pandemic led to a curtailment of upstream production of shale oil, which in turn hit US crude oil exports and caused its fall for the first time in six years. According to Baker Hughes, a major US oil services company, the number of active oil rigs in the US fell to 275 at the beginning of 2021, only 41% of the same period in 2020. According to the US Energy Information Administration, US crude oil production in 2021 was 112.14 million barrels per day, down 80,000 barrels per day year-on-year; the annual average export volume was 2.99 million barrels per day, down 180,000 barrels per day year-on-year, a decline of up to 6%, the first export decline in six years. In September 2021, US crude oil exports fell to 2.67 million barrels per day, the lowest level in nearly three years. The decline in US crude oil production has affected exports to almost every region of the world. In 2021, US exports to the Asia–Pacific region were 1.37 million barrels/ day, down 60,000 barrels/day from the previous year, with a 46% export share, making the Asia–Pacific region remain the top export destination for US crude oil. Among them, the export volume to China was 240,000 bpd, a significant decrease of 240,000 bpd year-on-year, or 50%, with the export share falling from 15 to 8%. US crude oil exports to European countries reached 1.06 million barrels/day, down slightly by 20,000 barrels/day from the same period last year, accounting for 36% of total exports, and its share remained largely unchanged. The bulk of US exports to North America went to Canada, which exported 310,000 barrels/day of crude oil in 2021. Despite a decrease of nearly 90,000 barrels/day from the previous year,

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Fig. 8.5 Changes in the destination of US crude oil exports. Source EIA; Unipec research and strategy (URS)

Canada was still the largest crude oil exporter to the US, accounting for 11% of total US exports (see Fig. 8.5).

OPEC + Slowly Increased Production, with Crude Oil Exports Picking up Slightly In 2020, against the backdrop of plummeting oil prices, OPEC + reached the largest production cut agreement in its history. In 2021, international crude oil prices rose sharply, and OPEC + gradually resumed production after the cut. In the first quarter, OPEC + reduced production slightly, but Saudi Arabia cut production by an additional 1 million barrels per day, and Iraq also proposed additional production cuts, which reached a maximum of 8.13 million barrels per day. In the second quarter, OPEC + increased production slightly, and Saudi Arabia withdrew additional production cuts in phases. In the third and fourth quarters, OPEC + maintained its plan to increase production by 400,000 bpd per month, but some members had difficulties in increasing production, and the actual implementation rate of production cuts was maintained at around 116%, which was less than expected (see Fig. 8.6). As a result of production cuts, OPEC crude oil exports fell sharply in 2020, once falling to the lowest level in recent years, such as June 2020 exports of only 16.75 million barrels per day, down more than 6 million barrels per day from the normal level. In 2021, crude oil production of 13 OPEC members totaled 26.3 million bpd, an increase of 640,000 bpd year-on-year; crude oil exports reached 19.72 million bpd, a slight increase of 250,000 bpd year-on-year (Fig. 8.7). Among them, Saudi Arabia, the largest crude oil exporter, maintained its production reduction plan, exporting 6.57 million bpd for the year, down 290,000 bpd year-on-year. Libya, the UAE and Iraq rebounded, with Libya’s exports recovering to 1.04 million bpd, a significant increase of 720,000 bpd year-on-year; the UAE’s increased by 330,000 bpd to 3.5

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Global Crude Oil Trade in 2022 Resilient Growth of Global Crude Oil Trade In 2022, as countries gradually relax pandemic control, economic activities further pick up, and global oil demand and supply steadily recover, driving the total volume of global crude oil trade to increase. Total global crude oil trade grew rapidly in the first three quarters of 2022, rising 5.2% year-on-year to 39.57 million bpd, with Asia Pacific maintaining its position as a trading hub, with trade volumes increasing by 820,000 bpd to 23.93 million bpd compared to 2021; Europe followed, increasing by 950,000 bpd to 10.38 million bpd compared to 2021, while all other regions saw more or less growth. By country, the countries with faster growth (over 100,000 barrels/day) were India, Japan, France, Spain, South Korea, the US, Malaysia, Egypt, Thailand and Italy, while China’s demand was dampened by the recurring pandemic outbreak and sluggish economic and travel activity under the dynamic zero-COVID policy, with crude oil trade volumes falling to 9.94 million barrels/day, down 370,000 barrels/day year-on-year (see Fig. 8.8).

Structural Adjustment of Global Crude Oil Trade Flows From a global perspective, crude oil supply–demand mismatch drives trade development, and crude oil is transported from resource areas such as the Americas, the Middle East, the North Sea and West Africa to demand areas such as Asia–Pacific, Europe and the US, forming relatively fixed trade flows. After the outbreak of the Russia-Ukraine conflict in 2022, Europe imposed energy sanctions on Russia, which led to a sharp decline in European imports of Russian crude oil and triggered a major

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reshuffle of global crude oil trade flows, resulting in a fundamental adjustment of the global trade pattern. In 2021, Russia produced 10.5 million barrels per day of crude oil, making it the second largest exporter of crude oil in the world after Saudi Arabia, exporting about 2.46 million barrels per day to Europe and 2.2 million barrels per day to Asia Pacific. After the outbreak of the Russia-Ukraine conflict, countries such as India and China have increased the purchase of low-priced Russian crude oil, and some of the long-haul resources in the Americas and West Africa have been squeezed by Russian crude oil. In the context of the suspension of Russian oil procurement by the UK, the US and Sweden, Russian crude oil originally going to Europe and the US flowed to Asia Pacific in large quantities. For Europe, oil-producing countries other than Russia quickly filled the supply gap, and alternative resources from the Middle East, the Americas, West Africa and other regions flowed to Europe, becoming an important trading partner for Europe. Specifically, Europe’s share of Russian crude imports falleds sharply to 24% from 36% in 2021, while the share of crude imports to West Africa increased from 7 to 8% and the share of crude imports to the US increased from 11 to 13% (see Fig. 8.9). From a post-market perspective, the EU has imposed several rounds of sanctions on Russian oil exports since 2020, and since December 5, the EU has explicitly banned the import of Russian crude oil by sea and banned the provision of insurance and shipping services for Russian oil that does not comply with the price limit policy. In the eighth round of EU sanctions, if the price cap is accepted, the purchase of Russian oil would not be subject to the insurance ban, but the specific implementation of the price cap has not been agreed. Russia has previously said that it would not sell crude oil to countries that support the price cap plan, and may continue to rely on its own capacity and insurance to maintain some exports in the future. With the EU sanctions in place on December 5, Russian seaborne crude oil exports are likely Million barrels/day 3.0 2.5 2.0 1.5 1.0 0.5 0

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to fall to 2.5 million bpd in December 2022, down more than 1 million bpd from normal levels, and the global crude oil trade pattern will change further.

Medium- and Long-Term Outlook for Global Crude Oil Trade Geopolitical Impact on Global Crude Oil Trade Intensifies Since 2022, global geopolitical events have been frequent, the game around energy has been escalating, the risk of sudden supply disruptions has intensified, and important changes have occurred in crude oil trade. Given the unstable production in Venezuela, Libya, Nigeria and other oil-producing countries, frequent oil field or pipeline disruptions, as well as the delayed return of Iran to the crude oil market again, the supply side is facing a weak growth dilemma, which deeply affects the crude oil trade. In 2022, high oil prices swept through the US, and the US proposed measures such as easing crude oil sanctions on Venezuela in exchange for its increased crude oil exports. In fact, Venezuela’s crude oil production peaked at 2.49 million barrels per day in 2008, but limited by aging equipment, the current Venezuelan production is basically stable at about 700,000 barrels per day. If the US sanctions are eased, Venezuela’s production may slowly rebound, but due to its upstream production facilities in disrepair, there is limited room for growth in the short term. The road to Iranian nuclear negotiations has been tortuous and no agreement has been reached yet. Iran is expected to return to the market in 2023, which may bring 1 million to 1.5 million barrels per day of incremental crude oil exports. Against the backdrop of the energy crisis, OPEC + has a strong willingness to cut production to protect prices, and the voice and influence of major crude oil exporters such as Saudi Arabia has enhanced significantly. In addition, OPEC + ‘s diplomatic focus is tilted to emerging markets in Asia Pacific, where Saudi Arabia as its leading country has turned cold with the US, and the possibility of further production cuts cannot be ruled out. The US under the leadership of the Democratic Party seeks to lower oil prices to protect people’s livelihoods, which runs counter to OPEC + ‘s wishes, so the basis for cooperation between the two is weak. The US has seen some growth in its own production, but labor and raw material shortages and supply chain bottlenecks remain, and insufficient investment in upstream industries in recent years has led to slow growth in production capacity.

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Increasing Uncertainty in Global Crude Oil Trade and the Decline of Russia’s Crude Oil Trade Position In view of the continued fermentation of the Russia-Ukraine conflict, as the EU sanctions continue to advance, Russia’s seaborne crude oil trade is facing more and more difficulties, and is likely to decline in future. At the same time, a large number of upstream investments have been withdrawn from Russia, making Russia’s medium- to long-term upstream growth weak, and production may decline to a certain extent. As an important global exporter of crude oil trade, Russia’s position in the global crude oil trade has declined to a certain extent, and whether other countries can make up for the Russian gap remains to be clarified. In addition, with the improvement of the pandemic situation, China is expected to relax the pandemic prevention and control measures, coupled with the implementation of economic stabilization measures, China’s oil demand is expected to rebound, promoting the gradual recovery of crude oil trade, but whether it can return to the high growth situation of the past 20 years is still uncertain. From the inventory side, the world’s refineries maintains a high operating rate in 2022, and whether to maintain a high operating rate and high gross margin in 2023 is still uncertain. Looking ahead, with the European and American central banks’ aggressive rate hikes, the world may usher in an economic recession in 2023, oil demand and oil trading are facing serious challenges; at the same time, geopolitical changes will accelerate the supply and demand situation in various countries and regions reconfiguration, the existing trade pattern may usher in a new round of flexibility adjustment, the medium and long-term will encounter more challenges.

The Short Term Cooling of the Energy Transition Will Still Reshape the Oil Trade Pattern As the world moves toward clean and low-carbon energy, the demand for traditional fossil energy will gradually be replaced. The recent series of geopolitical crises have had a profound impact on the energy market, and Europe is in a phase of transition from old to new energy sources; and due to the unstable supply of clean energy and underdeveloped energy storage technology, there is a structural imbalance in the energy supply in Europe. In 2022, Europe restarted the application of coal and nuclear energy, and the energy transition has encountered short-term pressure, with the market reliance on traditional energy sources increased. Due to the sharp decline in Russian gas exports to Europe pipeline, the European region increases demand for oil-to-gas, so crude oil trading may restore growth. Europe’s energy transition may slow down, and the importance of energy transition has temporarily given way to energy security. In the long term, Europe’s dependence on its energy supply is a wake-up call, partly justifying the need for an energy transition that will see more efforts to develop clean energy sources and squeeze the share of oil trade.

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In addition, the country will continue to unswervingly move toward the goals of peaking carbon emissions and achieving carbon neutrality, with the sales of electric vehicles continuing to grow, the rapid development of alternative energy sources such as biomass fuel and hydrogen energy, and the accelerated distribution of clean energy generation such as wind, light, water and nuclear energy. The share of traditional oil and gas consumption in energy consumption will steadily decline.

Bibliography BP. BP world energy statistics yearbook. 2022 Pei W, Na R, Yi C et al (2022) New features of the global oil market and new trends of oil trade in the context of high oil prices. Int Pet Econ. 30(6):35–44 Li Xiaoyi, Xu Yingming, Xiao Xinyan (2022) Trends in the evolution of international oil trade pattern and china’s response in the context of Russia-Ukraine conflict. J Int Econ Coop, (3): 10–18 Xiaoying H, Xiaoyuan X (2021) Analysis of the new pattern of global crude oil trade. Report on China’s Petroleum. Gas New Energy Ind 2021:150–163

Guanhua Wang Master, Deputy Business Manager, the Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on oil market supply and demand fundamentals and international oil price trends. Zhuo Fang Master, Analyst, Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on carbon markets and international oil price trends. Xiaoyuan Xia Master, Deputy Business Manager, Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on oil market supply and demand fundamentals, international oil price trends, and natural gas price trend.

Part III

Natural Gas

Chapter 9

Global Natural Gas Market and Changing Trends of Natural Gas Trade Xiaoyuan Xia and Aijie Li

Overview of the Global Natural Gas Market Since the Conflict Between Russia and Ukraine, the Tension of Global Natural Gas Supply Has Intensified Since the outbreak of the global COVID-19 pandemic, global upstream oil and gas investment has declined significantly, leading to a delay in the start-up of some new capacity and a more pronounced impact on supply in the region. As the conflict between Russia and Ukraine continues to escalate, the supply in Russia is gradually decreasing and the uncertainty is increasing. The International Energy Agency (IEA) predicts that in 2022, the global natural gas supply will decrease by 18 billion cubic meters to 4,092 billion cubic meters year-on-year, mainly from Russia, and the estimated output will decrease by 94 billion cubic meters to 668 billion cubic meters year-on-year. In addition, North America is forecast to grow by 30 billion cubic meters year-over-year to 120.8 billion cubic meters in natural gas production, mainly from the US; the Middle East by 18 billion cubic meters year-over-year to 712 billion cubic meters; Asia Pacific by 19 billion cubic meters year-over-year to 670 billion cubic meters; and Europe by 4 billion cubic meters year-over-year to 227 billion cubic meters, but this will not offset the decline in Russian production. Russia is rich in natural gas resources, and its natural gas reserves and output rank first and second in the world. According to BP Statistical Review of World Energy 2022, the proven natural gas reserves in Russia are 37.4 trillion cubic meters, accounting for 19.9% of the world total. The output of natural gas is 701.7 billion cubic meters, accounting for 17.4% of the world total, the reserve-production ratio is X. Xia (B) · A. Li Unipec, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_9

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53.3, and the export volume is about 250 billion cubic meters, of which pipeline gas exports account for 84% and LNG exports account for 16%. In response to western sanctions, Russia has taken countermeasures and imposed ruble settlement orders on unfriendly countries and regions. Gazprom has successively stopped supplying gas to European countries such as Poland, Bulgaria, Finland, Denmark and the Netherlands that are in arrears with natural gas payments and refuse to settle in rubles. The International Energy Agency (IEA) predicts that Russian natural gas production will drop by more than 12% in 2022 due to the rapid reduction of Russian gas transmission to Europe and the decline of domestic demand. In addition, the supply of natural gas in other regions is also tight. The US signed an agreement with the EU in March to increase the supply of LNG to the EU by 15 billion cubic meters this year. According to the US Energy Information Administration (EIA), the peak capacity utilization rate of LNG export facilities in the US in the first half of 2022 was 87%, and the average LNG liquefaction capacity was 11.4 billion cubic feet/day. However, in June, the explosion accident at Freeport Port in the US shut down LNG export facilities, reducing the production capacity by 2 billion cubic feet per day. It is estimated that the export volume of LNG in the US may reach 12.2 billion cubic feet per day in 2022. At the same time, there is no new capacity in the Middle East in 2022, and many energy companies in Africa are expected to restart the previously shelved natural gas projects, while the proven natural gas reserves in Europe have been depleted for many years, so it is expected that there is limited room for capacity increase.

The Growth Rate of Natural Gas Demand Slows Down, and the Demand in Europe May Drop Significantly From the demand side, the growth rate of global natural gas demand may slow down. BP Statistical Review of World Energy 2022 shows that the global natural gas consumption in 2021 has been higher than the pre-pandemic level in 2019, reaching 4,037.5 billion cubic meters, up 5.3% year-on-year, which is the first time to exceed 4 trillion cubic meters. In 2021, the US consumed 826.7 billion cubic meters of natural gas, and Europe consumed 571.1 billion cubic meters of natural gas, ranking the top two in the world respectively. In addition, China and Russian natural gas consumption both increased by more than 12% year-on-year, making them the two countries with the fastest consumption growth. However, since 2022, due to factors such as the fermentation of the conflict between Russia and Ukraine, the Fed’s interest rate hike and contraction, the continued high international natural gas prices, and extreme weather uncertainty, the demand for natural gas may be under pressure. IEA predicts that the global natural gas demand will decrease by 20 billion to 408.3 billion cubic meters in 2022. Specifically, in Europe, before the heating season, the natural gas inventory in northwest Europe was about 46 billion cubic meters, which was higher than that in

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2021, but still lower than the pre-pandemic level. It is expected that the demand for replenishment in winter will support the demand for natural gas in Europe. But at the same time, the price of natural gas in Europe is running at a high level, and the economic recovery is facing downward pressure, so the demand for natural gas will be restrained to some extent. It is estimated that the demand for natural gas in Europe will decrease slightly by 55 billion cubic meters year-on-year to 549 billion cubic meters in 2022, far lower than the year-on-year increase of 31 billion cubic meters in 2021. The demand for natural gas in Asia and Europe is expected to decrease by 15 billion to 619 billion cubic meters year-on-year, mainly due to the fact that the demand for natural gas in Russia will be greatly reduced by 17 billion cubic meters to 484 billion cubic meters. The demand for natural gas in North America and the Middle East will increase, among which the demand for natural gas in the US will remain stable on the whole, and the demand for industrial gas will improve, but the demand for power generation may decline. IEA predicts that the demand for natural gas in the US will increase by 20 billion cubic meters to 887 billion cubic meters in 2022.

Natural Gas Prices Hit Record Highs, with Europe Leading the Asia–Pacific Price Trend Since 2021, the contradiction between global energy supply and demand has been increasing, with power shortage in China, oil shortage in Britain, gas shortage in Europe and coal shortage in India frequently staged. The global energy crisis has been continuously fermented, and the prices of coal, oil and natural gas have hit new highs in recent years or historical highs. With the improvement of the pandemic situation, the demand for traditional energy has surged, and the demand for natural gas has increased beyond expectations. However, the upstream capital expenditure has fallen sharply, and the recovery of energy production has lagged behind, which has caused the global supply shortage to intensify. At the same time, the environmental protection policies of various countries are constantly increasing, the coal supply is declining, and the new energy supply is insufficient, resulting in a gap in energy supply. Due to the intensification of the contradiction between supply and demand of traditional energy, the global energy crisis continues to ferment, and the price of natural gas keeps running at a high level, resulting in natural gas becoming the most expensive primary energy (see Fig. 9.1). In addition, Europe leads the Asia–Pacific price trend. As the Asia–Pacific region has always been the main LNG importing region in the world, the proportion of Asia–Pacific LNG imports in global LNG trade has remained at about 70% in the past 10 years. Asia–Pacific JKM has become the global LNG pricing benchmark in the past 10 years, and the European TTF price fluctuates with Asia–Pacific JKM most of the time. However, JKM takes the form of Platts window trading, with low market participation rate and poor liquidity. Since 2021, the European natural gas

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Fig. 9.1 Trends of the three pricing benchmarks of natural gas in the world. Source Reuters, Unipec Research and Strategy (URS)

market has become an important regulator of American LNG exports, and European natural gas futures have attracted a large number of funds and speculators. As TTF futures becomes an important energy investment, it continues to trade more actively and is beginning to lead JKM price action. For many years, JKM price is usually higher than TTF price, and the price difference between them is positive. Since December, 2021, influenced by the sudden drop of winter temperature, the reverse transportation of Russian natural gas pipelines, and the escalation of tension between Russia and Ukraine, TTF has risen at a faster rate than JKM, widening the negative spread between the two significantly.

LNG Transportation Market Fluctuates Violently The major global LNG carrierping routes have experienced more dramatic freight rate fluctuations, but have generally maintained a stable upward trend in recent years. The LNG transportation market is dominated by LNG project vessels and mediumand long-term time charter vessels, with relatively few spot vessels. However, in the last two to three years, spot trading has become increasingly active. Especially in 2021, LNG freight rates fluctuated sharply throughout the year due to unexpected events and market sentiment, showing a pattern of “high at both ends of the time frame and low in the middle.” Since 2022, the LNG freight rate showed a fall-rise pattern, followed by a slow retreat and then a shaky strengthening trend (see Fig. 9.2). Specifically, in the first half of 2021, freight rates fell from high levels as supply constraints in the shipping market eased significantly with a warming climate and

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a return to supply growth. In the Atlantic region, daily charter rates for 174,000 cubic meters LNG carriers have fallen back to $50,000–$80,000 from $300,000 at the beginning of the year. As the northern hemisphere enters the peak season of winter demand, major countries increase LNG procurement and push the freight rate to continue to rise. At the beginning of December, the daily rental of LNG carriers in the Asia–Pacific region rose to $300,000, an increase of nearly 400% compared with $75,000 at the beginning of September, which was close to the historical high at the beginning of the year. Since 2022, LNG freight has fluctuated greatly. In the first quarter, due to the impact of the Russia-Ukraine conflict, capacity tension pushed freight rates slightly higher; in the middle of the year, under the impact of the shutdown of the Freeport project, there were relatively sufficient spot berths in the East and West regions, coupled with a relatively flat demand for ships, so freight rates fell back; since the third quarter, due to the increase in demand for US LNG in Europe and Asia, ship demand was strong and capacity supply was tight, so LNG carriers were in short supply, and the freight rate has gradually picked up, such as the daily rent of 174,000 cubic meters LNG carriers in the Asia–Pacific region has increased from $40,000 in February to about $230,000. In terms of transportation capacity, there are more than 700 LNG carriers around the world, of which spot ships account for less than 15%, restricting the development of LNG trade to a certain extent and making LNG freight fluctuate violently. According to the current technology level, 60–70 LNG vessels can be built globally each year, and the construction cycle of an LNG vessel is usually 28–32 months. At present, the berth planned to be delivered in 2025 is very scarce, so it is expected that the global LNG capacity will remain tight for some time to come.

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Characteristics of Global Natural Gas Trade Russia’s Natural Gas Exports Declined Under European and American Sanctions Since the outbreak of the conflict between Russia and Ukraine, western sanctions against Russia have been escalating, mainly in the fields of finance and energy. Although the sanctions have not yet involved Russian natural gas exports, Russian natural gas supply is facing great uncertainty under geopolitical wrestling. According to BP Statistical Review of World Energy 2022, in 2021, Russia exported 241.3 billion cubic meters of natural gas, of which LNG was 39.6 billion cubic meters, a year-on-year decrease of 4.9% (the average growth rate in the past 10 years was 10.7%, accounting for 16.4% of the total export volume); the pipeline gas was 201.7 billion cubic meters, up 2.6% year-on-year (it remained basically stable in recent 10 years, accounting for 83.6% of the total export volume). 83% of Russian pipeline gas is exported to Europe. In 2021, the gas supply from Russia to the three main pipelines in Europe averaged 296 million cubic meters per day. Since 2022, the Russia-Ukraine conflict has led to numerous problems with the Nord Stream 1 pipeline. In the early days of the Russia-Ukraine conflict, Russian gas deliveries to Europe increased rather than decreased, but since March 15, Russian pipeline gas supplies to Europe have been unstable. The volume of gas delivered on the Nord Stream 1 pipeline was reduced by 60% to 67 million cubic meters per day from June 16 due to the failure of Siemens Germany to return the repaired gas pumping unit on time. On July 11 to 21, Nord Stream 1 pipeline started the annual maintenance, and the gas transmission capacity dropped to zero. On July 21, the pipeline resumed gas transmission, but only maintained the gas transmission capacity of 60 million cubic meters/day. On July 27th, Gazprom said that another turbine was shut down, thus the pipeline flow rate dropped to 20%. At the beginning of September, Gazprom announced that it would cut off the gas transmission of Nord Stream 1 pipeline “indefinitely” due to problems such as equipment failure and oil leakage found in the maintenance process, further tightening the supply of natural gas to the European region. The restoration of gas supply will be further delayed by the natural gas leaks and explosions on September 26 at Nord Stream 1 and 2 pipelines, making it highly unlikely that Nord Stream 1 will resume gas supply during the heating season. It is estimated that Russia’s natural gas supply for the whole year will be 668 billion cubic meters, a sharp decrease of 94 billion cubic meters year-on-year (see Fig. 9.3). The Nord Stream 1 pipeline, commissioned in 2011, runs from Vyborg, northwest of St. Petersburg, Russia, across the Baltic Sea to Greifswald, Germany, where it connects to the gas pipeline network in Central and Western Europe and delivers gas to Denmark, the Netherlands, Belgium, France, the United Kingdom, the Czech Republic and other European countries with an annual capacity of 55 billion cubic meters. If Russia stops gas transmission to Europe, nearly 70% of the global LNG spot flowing to areas outside Europe will be needed to completely replace Russia’s

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pipeline gas supply to Europe (about 272 million cubic meters/day), which is obviously difficult to achieve in the short term. At the same time, Russia is also highly dependent on the European export market due to infrastructure constraints. Russia’s upstream gas fields for transporting gas to Europe are distributed in western Siberia and Yamal, which are more than 1000 km away from the gas sources on the eastern route of China and Russia, and there is no pipeline connection. In addition, Yamal LNG export has been running at high load, so this part of natural gas cannot be transferred to China or exported as LNG. In addition, the Nord Stream 2 pipeline started to be formally constructed in 2018, and was suspended in 2019 due to sanctions imposed by the US. Although Russia and Germany insisted on the construction, but they failed to put into production after completion in September 2021. The designed gas transmission capacity of the pipeline is 55 billion cubic meters/year. Since 2020, Russia has been gradually reducing its pipeline gas supplies to Europe, hoping to accelerate the commissioning of Nord Stream 2 and to use pipeline gas supplies for geopolitical games. In August, 2022, Nord Stream 2 pipeline in Russia has been put into use to supply natural gas to the northwest of Russia. Russia said that the natural gas pipeline in Nord Stream 2 is fully ready for operation and has passed all inspections. Russian President Vladimir Putin said that it could be started at any time. However, under the influence of RussiaUkraine conflict and EU sanctions against Russia, the go-live time of Nord Stream 2 pipeline is postponed indefinitely. In the short term, Russian gas exports to Europe are subject to greater uncertainty, with a significant reduction in exports already seen in 2022. In the medium to long term, Europe’s dependence on Russian gas will gradually ease under European and US sanctions, and Russian gas exports to Europe will then decline. Natural gas has become the focus of the game between Russia and Europe, and Russia will use natural gas as a lever to exert its influence on the political and economic situation in Europe.

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US LNG Exports Grew Strongly The US, rich in oil and gas resources, is currently the world’s top gas producer, second largest gas exporter and third largest exporter of LNG. In May 2011, the US liberalized its natural gas exports. In February 2016, Sabine Pass, the first LNG export project in the US, was put into production, with export volume increasing rapidly. US LNG exports have increased significantly as domestic supplies have increased significantly and US natural gas prices have been chronically lower than those in other global LNG markets, driving inter-regional trade. According to the US Energy Information Administration, US LNG exports have grown significantly from 14.52 million tons per year to 73.08 million tons per year over the past five years, an average annual growth rate of 40%, making it the third largest LNG exporter in the world after Australia and Qatar. In 2021, total US natural gas exports was 186.3 billion cubic meters, of which pipeline gas exports were 86.6 billion cubic meters, accounting for 46%; LNG exports reached 99.7 billion cubic meters, accounting for 54%. The export destinations of American pipeline gas are only Mexico and Canada, accounting for 71% and 29% of exports respectively; LNG export destinations exceed 35 countries and regions, among which countries in Asia, Europe and Central and South America account for a relatively large proportion (Fig. 9.4). With the sixth production line of Sabine Pass and Calcasieu Pass put into production, the US is expected to surpass Australia and Qatar in 2022 to become the world’s largest LNG exporter with a total export capacity of nearly 80 million tons. By 2025, it may become the first country in the world with LNG export capacity exceeding 100 million tons. On June 8, 2022, Freeport, the second largest LNG export terminal (2 billion cubic feet/day) in the US, was completely shut down due to an explosion. Since 2022, American LNG exports account for about 45% of European LNG imports, of which Freeport accounts for about 7%. After the conflict between Russia and Ukraine broke out, 70% of Freeport’s LNG was shipped to Europe, and the export volume climbed from an average of 0.1 billion cubic meters per day in 2021 to an average

20 19 20 08 19 20 10 19 20 -12 20 20 - 02 20 20 - 0 4 20 20 - 0 6 20 20 - 08 20 20 -10 20 20 -12 21 20 02 21 -0 20 4 21 20 0 6 21 20 08 21 20 10 21 20 -12 22 20 - 02 22 -0 4

100 million cubic meters 900 800 700 600 500 400 300 200 100 0

Total exports

Freeport

Fig. 9.4 US LNG exports. Source Reuters, EIA, Unipec Research and Strategy (URS)

Time

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of 0.3 billion cubic meters per day in January to May 2022. After the explosion of Freeport export terminal, the supply of Cameron and Calcasieu Pass factories increased, and the capacity utilization rate of other LNG export facilities remained above 90%, which helped to partially offset the impact of Freeport interruption. It is estimated that the Freeport will not be fully operational until the end of 2022, and the supply of nearly 5 million tons of LNG will be affected, thus the LNG exports by the US to Europe will decline. Overall, US natural gas production has a large potential for growth, and with new LNG export projects coming on stream and LNG export resources being economical, there is still room for future growth, but exports face uncertainty in the short term due to project failures.

Europe is Committed to Seeking Multi-Source Import Sources The Russia-Ukraine conflict is still ongoing and Russian gas supplies are facing great uncertainty due to geopolitical influences. At present, the exports of Russia’s three major natural gas pipelines to Europe has fallen sharply, and the supply of natural gas in Europe is facing the risk of shortage. Since the Russia-Ukraine conflict, major European countries have increased LNG imports to stabilize the supply of natural gas, especially the import of LNG resources from the US has increased significantly. In the short term, it is difficult for Europe to completely get rid of Russian natural gas. First, there is a serious shortage of global alternative LNG resources. Russia’s annual natural gas export to Europe is about 195 billion cubic meters. Once the supply is cut off, almost all the gaps will need to be made up by LNG. However, most of the global LNG export resources are currently locked in long term contracts, so Europe will have limited increase in LNG imports in the short term. In the US, for example, medium and long term contracts account for 80% of US LNG exports and only 20% of spot. At this stage, resources from the LNG export program have had to be reallocated, with a biased allocation to Europe of resources that were not originally earmarked for offloading. Even if all the American LNG spot flows to Europe, it can only meet the import demand of about 20% in Europe. Second, the capacity of LNG infrastructure in Europe is seriously insufficient. At present, the regasification capacity of European LNG receiving terminals is about 208.8 billion cubic meters. If Russian pipeline gas is completely replaced by LNG, Europe must increase its regasification capacity by 84%. Even if construction of the terminals were to begin in full now, it would take at least five years to complete. Third, the available LNG capacity is seriously insufficient. Given the “take or pay” principle adopted by most LNG projects, the global LNG transportation market is dominated by project vessels and medium- and long-term time charters, with relatively few spot vessels. The year of 2021 saw only 90 spot LNG carriers, accounting for only 13% of the total LNG transportation capacity. Therefore, it is often difficult to find a vessel. If all Russian natural gas imported from Europe is replaced by LNG, at least 110 new LNG carriers will be needed. Obviously, the existing fleet cannot meet the demand.

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In the long run, Europe will gradually reduce its dependence on Russian natural gas and seek diversified import sources. On March 8th, the European Commission issued the REPowerEU. The EU will reduce its dependence on Russian natural gas by diversifying imported gas sources, accelerating the development of renewable energy and reducing the use of natural gas in heating and power generation. With the projects under construction in the US and Qatar put into operation, the LNG receiving facilities are constantly improving, and the transportation capacity is gradually increasing, Europe is expected to seek more alternative gas sources of Russian natural gas. According to European Commission estimates, the EU’s imports of Russian gas are expected to be cut by two-thirds by the end of 2022, and dependence on Russian gas supplies is expected to end in 2030.

China’s LNG Import Growth Slowed Sharply Over the past decade, China’s rapid growth in natural gas consumption has continued, driving strong growth in natural gas imports and making China the world’s largest importer of natural gas—the country’s natural gas imports have grown from 42 billion cubic meters to nearly 170 billion cubic meters, and its external dependence has risen significantly from 28% to around 45%. China began to import LNG in 2006, and the import scale has increased year by year in recent years. In 2021, it imported 79.93 million tons of LNG, surpassing Japan to become the largest LNG importer in the world. Since 2022, against the backdrop of slowing demand growth, increasing domestic supply and high international natural gas prices, China’s natural gas imports have declined month-on-month, with negative growth for the first time since 2015. In addition, the average c.i.f. price of LNG imports in China in the first half of the year was more than 3.5 times the price of pipeline gas imports, resulting in a significant decline in LNG imports, especially in the proportion of spot imports. Currently, China regulates the end-use price of natural gas, and the cost of high gas prices cannot be fully transmitted to the downstream, resulting in a loss of enthusiasm for acceptance by enterprises and a significant reduction in profits for importers. In the first half of the year, China’s apparent demand for natural gas was 181.1 billion cubic meters, down 1.5% year-on-year, and it has declined year-on-year for three consecutive months since the second quarter. In the aftermath, as temperatures rise, demand for natural gas for power generation will increase, but given the high price of natural gas or the suppression of demand for industrial gas, and the recurring pandemic in many places, China’s natural gas demand is expected to remain basically stable in the second half of the year. Due to the high spot price of international LNG, China’s LNG imports in the first half of the year were 31.26 million tons (43.1 billion cubic meters), a sharp drop of 20.8% year-on-year; pipeline gas imports reached 30.8 billion cubic meters, up 11.3% year-on-year. It is estimated that China’s LNG imports will be about 70 million tons in 2022, down 11% year-on-year, ending the previous high growth trend for many years.

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In the medium and long term, under the goals of peak carbon emissions and carbon neutrality in China, natural gas is still expected to usher in a golden decade, but the growth rate of demand has slowed down significantly. It is estimated that China’s total natural gas demand and natural gas imports may peak around 2040. Siya, a consultancy, predicts that China’s natural gas demand will increase to more than 550 billion cubic meters in 2030, with an average annual growth rate of around 4% during the 15th Five-Year Plan period, which is 3 percentage points lower than that during the 14th Five-Year Plan period. By 2040, China’s natural gas demand will increase to more than 660 billion cubic meters, with an average annual growth rate of 2% over 10 years. After 2040, China’s natural gas demand may usher in an inflection point, and then will decline steadily. Due to the intensification of geopolitical risks, continuous tight supply, pushing up the import price of LNG, and being limited by the receiving capacity and utilization rate of LNG, it is expected that the import growth rate of LNG in China will slow down. The import growth rate is expected to be around 5% before 2030, and will drop to around 2% after 2030, which is much lower than the average annual growth rate of 29% during the 13th Five-Year Plan period.

Medium and Long-Term Outlook The Goals of Peak Carbon Emissions and Carbon Neutrality Push up the Global Demand for Natural Gas, and the Emissions Probably Peak Around 2035 In recent years, the process of peak carbon emissions and carbon neutrality has been significantly accelerated around the world. As a relatively clean and low-carbon primary energy source, natural gas will play an important role in the energy transition in the next decade. However, with the development of new energy sources such as solar energy, wind energy and nuclear energy, the growth rate of natural gas demand will slow down. Rystad, a consultancy, predicts that global natural gas demand will reach 4,532 billion cubic meters in 2033, and then slowly decline; it is estimated that by 2035, the global natural gas demand will be 4,519 billion cubic meters, and by 2040, the figure will drop to 4,324 billion cubic meters (see Fig. 9.5). From the perspective of various industries, the demand for power generation accounts for about 35% of the total demand for natural gas, but around 2030, the demand for natural gas power generation will reach a peak, and then will show a slight downward trend, with the decline continuing to expand after 2035. By 2040, industrial and transportation gas demand will become the main sources of natural gas demand growth, accounting for 30% and 4% of the total demand respectively, and together accounting for more than 85% of new demand. As the economy enters a stable phase of operation, industrial gas demand growth will slow down and enter a plateau after 2035. Transportation demand is still expected to maintain a growth rate

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2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

100 million cubic meters 50000 45000 40000 35000 30000 25000 20000 15000 10000 5000 0

Commercial Series 2 Heat supply Others Power generation Residential

Industry Traffic

Year

Loss

Fig. 9.5 Trends of global natural gas demand. Source Rystad, Unipec Research and Strategy (URS)

of more than 2%. The development of residential and heating gas demand is almost synchronous, showing a slight downward trend after 2035, accounting for 35% of the total natural gas demand. The demand for commercial gas accounts for about 5% of the total demand for natural gas, which has declined in recent years and will continue to decline before 2040. By regions, North America, which currently accounts for 28% of global demand, ranks first and will peak around 2030, with a slight decline thereafter. Asia, which accounts for 24% of global demand, will peak around 2040 and is expected to overtake North America as the world’s top gas demander around 2030, but the growth rate of gas demand will slow down thereafter. Europe accounts for 13% of total global gas demand, but will show a gradual decline after 2022, to 8% by 2040. In addition, gas demand in Africa, South America, and Russia will maintain modest growth through 2040, while demand in the Middle East is expected to peak around 2035.

The Global Natural Gas Supply is Gradually Increasing, and May Peak in 10 Years Overall, global gas supply will increase modestly and slow down gradually in the future. The trend of Russia-Ukraine conflict will bring greater uncertainty to Russian production. In addition, as proven gas reserves in Europe have been depleted year after year, there are limited new gas sources for large-scale development, while newly approved LNG projects in the US are affected by the lack of LTA guarantees, declining resource availability and rising construction costs, so there is uncertainty whether they can be put into production as scheduled. Rystad expects global gas supply to gradually increase, reaching 4,422.9 billion cubic meters in 2032, and then

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20 2 20 0 2 20 1 22 20 2 20 3 24 20 2 20 5 26 20 2 20 7 28 20 2 20 9 30 20 3 20 1 32 20 3 20 3 34 20 3 20 5 36 20 3 20 7 38 20 3 20 9 40

100 million cubic meters 45000 40000 35000 30000 25000 20000 15000 10000 5000 0 Africa

North America Asia

Australia

Europe

Middle East

Year

Russia

Fig. 9.6 Trends of global natural gas supply. Source: Rystad, Unipec Research and Strategy (URS)

slowly decline; global gas supply is expected to be 4,336.4 billion cubic meters by 2035, falling to 4,307.4 billion cubic meters by 2040 (see Fig. 9.6). It is worth noting that LNG supply is expected to increase significantly in five years. With the soaring global LNG price in the past two years, developers have accelerated the expansion of project construction scale. At present, the proposed liquefaction capacity in the US exceeds 250 million tons/year, and the newly invested LNG projects mainly include: Driftwood LNG, Plaquemines LNG and Corpus Christi LNG T4-10, all of which have made significant progress in the Final Investment Decision (FID) stage. Capacity at US natural gas liquids facilities will continue to increase from 2023 to 2025, but at a slower rate. After 2025, the US is expected to usher in a new wave of LNG facilities construction. In addition, the Qatar state-owned energy company signed agreements with a number of energy giants in the middle of the year to jointly develop the first phase of the North Field expansion project. The North Field East project proposes to build four liquefaction lines (totaling 32.6 million tons per year), with production expected to begin by the end of 2025, while the second phase of the project, the North Field South project, includes two additional liquefaction lines. After it is fully put into production, Qatar’s total LNG production capacity will increase from the current 77 million tons/year to 126 million tons/year by 2027, leading to a significant increase in global LNG supply. By regions, North America, which currently accounts for 31% of global gas supply, ranks first and will peak around 2033, with a slight decline thereafter, and will remain in first place through 2040. The Middle East, which accounts for 18% of global gas supply, will peak around 2032 at 22% and then decline slightly to around 21%. Asia’s share of natural gas supply is 17%, but will gradually decline after 2022 to about 14% by 2040. Russia’s share of natural gas supply is around 17%, but increases steadily after 2022 to reach around 19% by 2040. In addition, Europe’s share of gas supply will gradually decline from 6% in 2022 to 3% in 2040, while Africa’s and Australia’s shares will remain stable at 7% and 4%, respectively, by 2040. By supply source, near-coastal gas supply currently accounts for 46% of global supply, ranking first, but then declining slightly to 40% by 2040. Shale gas/tight

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20 1 20 9 20 20 2 20 1 22 20 2 20 3 24 20 2 20 5 2 20 6 2 20 7 28 20 2 20 9 30 20 31 20 32 20 3 20 3 34 20 3 20 5 36 20 3 20 7 38 20 3 20 9 40

100 million cubic meters 45000 40000 35000 30000 25000 20000 15000 10000 5000 0 Offshore deepwater Other near-coastal areas

Offshore shelf Shale gas/Tight oil

Year

Oil sands

Fig. 9.7 Global sources of natural gas supply. Source Rystad, Unipec Research and& Strategy (URS)

oil supply, which accounts for 26% of global supply, will gradually rises, peaking around 2034 at 32%, before slowly falling to 30% in 2040. The share of offshore shelf gas is 19%, but will gradually decline after 2022 to about 16% by 2040. In addition, the share of offshore deepwater natural gas supply is currently about 10% and is expected to grow gradually to about 14% by 2040 (Fig. 9.7).

Bibliography BP (2021) BP Statistical review of world energy Rystad (2022) Long—Term energy outlook Shan Weiguo, Jiang Xuefeng, Chen Rui, et al. (2020) Analysis of global market and business strategy based on the proposed increase of LNG Trade. World Pet Ind, (27) Zhang Hong, Ding Hao, Zhang Lijun et al. (2030) Study on patterns of global natural gas trading and natural gas import route of China. AR Res Dev, (6)

Xiaoyuan Xia Analyst, Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on international oil and gas markets. Aijie Li Analyst, Market Strategy Department of China International United Petroleum and Chemicals Co., Ltd., focusing on international oil and gas markets.

Chapter 10

Analysis on High-Quality Development of Natural Gas Industry in China Hui Sun and Lei Yang

Development Status of China’s Natural Gas Industry Development Status of Commodity Market Structure Domestic Exploration and Development At present, the exploration and development of natural gas in China is mainly carried out by three oil companies—CNPC, Sinopec and CNOOC—and the provincial stateowned enterprise Yanchang Petroleum. In 2021, the natural gas output of the above four enterprises totaled 200.3 billion cubic meters (CNPC 2021b; Sinopec 2022a; China Natural Gas Production 2022), accounting for 96.5% of the total natural gas output. In order to promote the diversification of upstream entities, China has made great efforts to promote the reform of mining rights, especially prospecting rights since 2011. From 2011 to 2019, China has carried out more than 10 competitive prospecting rights offerings for conventional and unconventional oil and gas blocks, both within and outside the public sector. On December 31, 2019, the Ministry of Natural Resources officially issued the Opinions of the Ministry of Natural Resources on Several Matters Concerning Promoting the Reform of Mineral Resources Administration (for Trial Implementation) (No.7 [2019] of the Ministry of Natural Resources) (hereinafter referred to as “Document No.7”), which fully liberalized the upstream oil and gas market and stipulated that all domestic enterprises and foreign-funded enterprises registered within the territory of the People’s Republic of China with net assets of not less than RMB 300 million shall be eligible for obtaining oil and gas mineral rights as required. While lowering the access threshold for exploration H. Sun (B) · L. Yang Institute of Energy, Peking University, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_10

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and development, the term of prospecting right has also been greatly adjusted. It is stipulated that at the time of application for renewal registration of a prospecting right, 25% of the area specified on the exploration permit for the initially granted prospecting right (excluding the scope of resources quantity of non-oil and gas that has been submitted/scope of proven geological reserves of oil and gas that has been submitted, and excluding the upper or deep part of the vertical projection of the scope of a mining area under an existing exploitation right) shall be deducted, and, as for an oil and gas prospecting right, the equivalent area of other blocks in the same basin of the prospecting right holder may be deducted. After the publication of Document No.7, the withdrawal of oil and gas blocks was obviously accelerated. According to incomplete statistics, by the end of 2021, the registered oil and gas prospecting blocks of CNPC, Sinopec and CNOOC had greatly decreased, and the cumulative withdrawal area had exceeded 1 million square kilometers. The main players in the oil and gas exploration and development market have increased from the four enterprises mentioned above to more than 40. In 2021, the Ministry of Natural Resources authorized Xinjiang to carry out five competition-based assignment activities for prospecting rights of conventional oil and gas blocks, with a total of 18 blocks with an area of about 15,300 square kilometers, of which 64% of the block area was obtained by entities other than the above four enterprises.

Foreign Natural Gas Import Natural gas imports includes pipeline gas imports and LNG imports. Currently, except for a small amount of pipeline gas imported from Kazakhstan by Xinjiang Guanghui, the vast majority of pipeline gas imports are done by CNPC, which imports gas from Central Asia, Russia and Myanmar in three directions: northwest, northeast and southwest, respectively. In 2021, China imported a total of 59.5 billion cubic meters of pipeline gas (converted according to the data released by the General Administration of Customs), of which CNPC imported about 59.3 billion cubic meters, accounting for 99.7% of the total pipeline gas imports. The diversification of China’s import entities is mainly reflected in the import of LNG, which has basically realized the diversification of countries and entities. According to the data published by the General Administration of Customs, China imported 78.8 million tons (about 110.3 billion cubic meters) of LNG in 2021. In terms of resource sources, the number of LNG importing countries/trading partners has reached 27, among which Australia, Qatar, the US and Malaysia are the main importers, accounting for 72.7% of the total. Australia is the largest source of LNG imports, with 31.1 million tons (about 43.5 billion cubic meters) in 2021, accounting for nearly 40% of the total LNG imports. From the perspective of importers, on the basis of CNPC, Sinopec and CNOOC, it is a trend that large gas companies, provincial energy enterprises, provincial pipe network companies and large power generation groups extend to the upstream resource supply. According to preliminary statistics, in addition to the three oil companies, there are more than 20 domestic enterprises that have entered the field of LNG procurement, including provincial energy companies such as Zhejiang Energy

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and Hebei Construction & Investment, large and medium-sized gas companies such as Beijing Gas, Shenergy, ENN and Shenzhen Gas, power generation companies such as Huadian and Shenzhen Energy, and LNG distribution companies such as Guanghui and JOVO. There are two main ways for new entrants to the LNG import market to obtain the right to use LNG receiving stations. First, the LNG receiving stations are fair and open with the help of PipeChina. Second, to obtain the right to use LNG receiving stations through their own shareholding in LNG receiving stations. Dapeng LNG Receiving Station in Guangdong is a typical example of the model of sub-processing equity allocation. At present, Dapeng LNG Receiving Station has allocated 3.6 million tons/year of its receiving capacity to sub-processing interests. Among them, CNOOC has a 33% shareholding and receives 2 million tons/year of processing rights; BP has a 30% shareholding and receives 600,000 tons/year of processing rights; the municipal gas team, 24% and 650,000 tons/year; and the power plant team, 13% and 350,000 tons/year.

Natural Gas Transmission Pipeline is the main medium of natural gas transportation in China. At present, all national pipelines have been consolidated in PipeChina. By the end of 2021, the total mileage of long-distance natural gas pipelines in China is nearly 84,000 km (Liu et al. 2021), and a nationwide gas supply network that spans from east to west, north to south, and even to overseas has been formed with the backbone of the West–East Gas Transmission System, Shaanxi-Beijing System, Sichuan-East Gas Transmission System, and Southwest Pipeline (Sun 2018), forming a pattern of transmitting from the west to the east, from the north to the south, and from the sea to the land, and nearby supply. According to incomplete statistics, 19 provincial pipeline companies in 14 provinces among the 31 provincial administrative units in mainland China are involved in substantive business, with a pipeline length of more than 20,000 km. Among them, most of the provinces have only one company, and only a few provinces such as Shanxi and Hunan have multiple companies (Sun 2018). Before the establishment of PipeChina, provincial pipelines were mainly owned or controlled by local governments. With the birth of PipeChina, the equity interests held by the three oil companies in the provincial pipeline companies were all transferred to PipeChina. According to incomplete statistics, PipeChina holds the shares of 16 provincial pipe network companies in Guangdong, Zhejiang, Guizhou, Hunan, Jiangxi, Fujian, Jiangsu, Shanxi, Hubei, Inner Mongolia, Henan and other provinces (Table 10.1), with a combined pipeline length of more than 9000 km, making it the largest shareholder of provincial pipeline networks in China.

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Table 10.1 PipeChina’s shareholding in some provincial pipe network companies No.

Provincial pipe network company

PipeChina’s shareholding ratio (%)

No.

Provincial pipe network company

PipeChina’s shareholding ratio (%)

1

PipeChina Guangdong

72

9

Jiangxi Natural Gas Investment

50

2

PipeChina Shandong

70

10

PipeChina Jiangsu 49

3

PipeChina Hainan

65

11

Shanxi Guohua Energy

49

4

PipeChina Guizhou

60

12

PipeChina Hubei

49

5

PipeChina Zhejiang (North Network)

60

13

Jiangxi Natural Gas Pipeline

46

6

Hunan Natural Gas

60

14

Hunan Natural Gas Pipeline

45

7

PipeChina Jilin

51

15

Inner Mongolia West

42

8

PipeChina Fujian

60

16

Henan Fazhan Gas 30

Downstream Sales CNPC, Sinopec, and CNOOC, the absolute mainstays of natural gas wholesale in China, sold 205.6 billion cubic meters (CNPC 2021b), 65.8 billion cubic meters (Sinopec 2022a), and 68.6 billion cubic meters (CNOOC 2021), respectively, for a total of 340 billion cubic meters in 2021, accounting for more than 92% of the apparent natural gas consumption of 369 billion cubic meters (China Natural Gas Development Report 2022). Provincial energy companies are the main force of natural gas intermediate sellers. Most provincial energy companies resell natural gas purchased from oil companies to downstream municipal gas companies and end users while operating provincial natural gas pipelines within the provincial administrative scope. At present, most provincial energy companies are actively promoting the separation of transmission and sales. Municipal gas companies are the main force of natural gas retail market. Compared with the wholesale sales market, the retail gas market has a relatively large number of participants and a relatively low degree of market concentration. According to incomplete statistics, there are more than 1,000 municipal gas companies in China, involving enterprises directly under the central government, local state-owned enterprises, private enterprises, Hong Kong-funded enterprises, and foreign-funded enterprises. Among them, KunLun Energy, Towngas, China Gas, CR Gas and ENN constitute the wind vane of the retail market development. In 2021, these five companies retailed 1195.1774 billion cubic meters of natural gas, accounting for 32.3% of apparent natural gas consumption (Table 10.2).

10 Analysis on High-Quality Development of Natural Gas Industry in China Table 10.2 Operation of typical municipal gas companies in 2021

157

Unit: 100 million cubic meters Gas company CR Gas1 KunLun

Energy2

Natural gas sales

Natural gas retail

340.820

340.820

419.990

257.100

ENN3

330.970

252.690

China Gas4

367.032

219.188

Towngas5 Total

145.79

125.3794

1604.602

1195.1774

Remarks: 1 The sales volume of natural gas is from the Reference (China Resources Gas Holdings Co., Ltd 2022), and the retail volume of natural gas is estimated according to the sales structure in the Reference (China Resources Gas Holdings Co., Ltd 2022). 2 The sales volume and retail volume of natural gas are from the Reference (KunLun Energy Co., Ltd 2022). 3 The sales volume and retail volume of natural gas are from the Reference (ENN 2022). 4 The sales volume and retail volume of natural gas are from the Reference (China Gas Holdings Co., Ltd. 2022) for the fiscal year ending March 31, 2022. 5 The sales volume of natural gas is from the Reference (Towngas 2022), and the retail volume of natural gas is calculated according to the sales structure in the Reference (Towngas 2022)

Current Status of Construction of Major Systems and Rules Price Formation Mechanism Upstream and Midstream Pricing Mechanism In terms of upstream and midstream gas prices, outlet prices and pipeline prices co-exist, with government regulation and market-based pricing complementing each other. At present, the sales prices of offshore gas, shale gas, coalbed methane, coal gas, LNG, gas for direct supply to customers, gas for purchase and sale at storage facilities, gas for public trading on trading platforms, and imported pipeline gas put into operation after 2015 have all been formed on the basis of the market. The prices of other domestic onshore pipeline gas and imported pipeline gas from outlets commissioned before the end of 2014 are temporarily managed under the current pricing mechanism, and will be liberalized to be formed by the market at an appropriate time depending on the market reform process (National Development and Reform Commission 2020).

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Pipeline Transportation Price After the establishment of PipeChina, it is inevitable that the pipeline gas will be priced separately. In June 2021, the National Development and Reform Commission issued the Measures for the Administration of Natural Gas Pipeline Transportation Prices (for Trial Implementation) and the Measures for the Supervision and Review of Natural Gas Pipeline Transportation Pricing Costs (for Trial Implementation) (2021), which made it clear that the price of natural gas pipeline transportation still adhered to the pricing principle of “allowable cost plus reasonable income.” The freight rate adopts the mode of regional pricing. With Zhongwei of Ningxia, Yonker of Hebei and Guiyang of Guizhou as the main nodes, it is divided into four price zones: northwest, southwest, northeast and mid-east. In other words, pipeline transport price is formed according to the route on the basis of the freight rate.

Downstream Retail Price The pricing mechanism mostly depends on the nature of gas consumption. Most residential gas is priced by the government, and most of them are priced in steps, with three levels of prices based on the size of the gas consumption, with higher prices for higher consumption. The pricing of non-residential gas is mostly guided by the government, i.e., the government either sets a maximum price or gives a maximum percentage increase.

Operation Rules of Trunk Pipeline Network At present, the operation of the natural gas trunk pipeline network is mainly carried out by PipeChina, which focuses on the fair access to infrastructure, including three main aspects of work. First, PipeChina regularly submits the information of oil and gas pipe network facilities to the designated platform of the National Energy Administration, and has set up a Fair Opening column on its official website homepage to announce the infrastructure-related information to the public on a quarterly basis. Second, it began to gradually establish a fair opening related system, and issued the Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities (for Trial Implementation), which clearly defined the work processes of capacity allocation, information disclosure and submission, and shipper management of natural gas pipeline facilities. At the same time, PipeChina issued Customer Access Process and Work Process for Acceptance and Implementation of Application of Oil and Gas Pipeline Facilities Service of PipeChina on its official website. Third, it continues to improve the relevant management measures for infrastructure information disclosure, focusing on strengthening supervision of transportation costs of oil and gas trunk pipelines as well as provincial and inter-provincial pipelines.

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Construction of Trading Platform At present, there are two national natural gas trading platforms in Shanghai and Chongqing, and three regional trading platforms in Zhejiang, Hainan and Shenzhen. Shanghai Petroleum and Natural Gas Exchange is the first national natural gas trading platform in China. It was put into operation in 2015, with the bilateral trading volume exceeded 80 billion cubic meters in 2021. At present, natural gas trading mainly includes pipeline natural gas, liquefied natural gas, LNG capacity, LNG receiving station window, storage capacity and other products, mainly in two trading modes: spot listing and spot bidding. Chongqing Petroleum and Gas Exchange was put into operation in 2018, with a unilateral trading volume of nearly 25 billion cubic meters in 2021. The trading products include pipeline natural gas, liquefied natural gas, compressed natural gas and storage capacity, etc. Four types of trading methods are used: listing, agreement, auction and bidding. Zhejiang Natural Gas Exchange was officially put into operation in 2020. Hainan International Energy Exchange was established in 2019. Shenzhen Natural Gas Trading Center was put into operation in November 2021, mainly relying on Qianhai Mercantile Exchange. All three regional trading centers are currently trading relatively small volumes of natural gas.

Current Situation of Market Supervision According to the principle of “controlling the middle and relaxing the control over both ends,” China focuses on regulating natural gas infrastructure such as pipeline networks and LNG receiving stations. Currently, regulation of oil and gas pipelines adopts a model of differentiated management between oil and gas, coordinated governance and regulation, multi-level management and decentralized supervision. According to the national oil and gas infrastructure development plan, the approval and review of construction of national trunk pipelines, new LNG receiving stations, underground gas storage and other infrastructures is the responsibility of the National Development and Reform Commission and the National Energy Administration; the management of pipeline prices for trunk pipeline networks is the responsibility of the National Development and Reform Commission; and the fair opening of national oil and gas pipeline network facilities other than town-based gas facilities is supervised by the National Energy Administration. The people’s governments of each province, autonomous region and municipality directly under the Central Government prepare the natural gas infrastructure development plan for their administrative regions based on the national plan, and are responsible for the approval, approval and filing of the construction of oil and gas pipeline infrastructure at the provincial level and below within the administrative region, and the management of pipeline transmission prices and LNG receiving station service prices below the provincial level. In recent years, especially since the establishment of PipeChina, China has increased its market supervision efforts and has issued documents including the Measures for the Supervision and Administration of Fair Opening of Oil and Gas

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Pipelines Network Facilities, the Model Text for Fair Opening Information Disclosure of Natural Gas Pipeline Network Facilities, the Measures for the Administration of Natural Gas Pipeline Transportation Prices (for Trial Implementation), the Measures for the Supervision and Review of Natural Gas Pipeline Transportation Pricing Costs (for Trial Implementation), and the Measures for the Management of Operation and Dispatch of Natural Gas Pipeline Network Facilities and Emergency Supply Assurance (for Trial Implementation) (Draft for Comments). Among them, the Measures for the Management of Natural Gas Infrastructure Construction and Operation promulgated by the National Development and Reform Commission and the Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities (for Trial Implementation) promulgated by the National Energy Administration in February 2014 introduced the concept of “fair opening” for the first time. The Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities issued in 2019 requires oil and gas pipeline facilities operators to provide oil and gas transportation, storage, gasification, loading and unloading, transshipment and other services to users who meet the opening conditions without discrimination. While strengthening system construction, the National Energy Administration has also normalized the supervision of fair opening of infrastructures.

Major Problems Facing the High-Quality Development of the Natural Gas Industry Rationalize the Balance Between Opening of Upstream Exploration and Development and Natural Gas Supply Assurance How to control the upstream exploration and development reasonably is not only one of the main problems to be solved for the high-quality development of the natural gas industry, but also the key to straighten out the relationship between the upstream and downstream entities and enhance the cohesion of the industry. The Opinions on Deepening the Oil and Gas System Reform issued in May 2017 proposed that “an exploration and development system led by large state-owned oil and gas companies and involving various economic sectors should be gradually formed. “ However, the interests of each entity are different, so reform is a long way off. In the past, the three oil companies focused on upstream exploration and development and natural gas wholesale, while the municipal gas companies focused on downstream natural gas retail, with relatively clear boundaries between the two types of companies. However, with the oil companies entering the downstream retail field in a big way, the relationship between upstream and downstream has become increasingly tense. Some municipal gas companies believe that the upstream has substantially entered the downstream, but there are relatively few opportunities for the downstream to enter

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the domestic upstream for exploration and development, which makes them always at a disadvantage in actual competition. They urgently hope that the pace of upstream reform can be accelerated. For the oil and gas exploration blocks withdrawn by CNPC, Sinopec and CNOOC, they hope that competitive trading can be carried out in time, and the statement that “as for an oil and gas prospecting right, the equivalent area of other blocks in the same basin of the prospecting right holder may be deducted” put forward in Document No.7 can be adjusted, which is considered to be the main reason for the relatively poor resource potential of the blocks withdrawn. At the same time, from the perspective of supply assurance, resource-based provinces are increasingly demanding to improve their ability to control resources. In addition, the three oil companies, which are currently mainly responsible for gas supply assurance, disagree with the policy of deduction of 25% of the area specified upon expiration, believing that the current policy is not conducive to the Seven-Year Action Plan to increase reserves and production due to the high investment in exploration and development, slow returns, and weak technical level of new entrants—the term of the prospecting right should be extended appropriately to further reduce the area of deduction in the renewal of block registration. At the same time, the new entrants’ behavior of “buying when prices are low and waiting when prices are high” in the imported LNG market and the speculation and hype of some enterprises make the competent authorities doubt their ability to assume responsibility for supply assurance.

Achieve the Resonance Between the Construction of Natural Gas Pricing Mechanism and the Competitiveness of the Industry Weak price competitiveness is an unavoidable pain point in the development of natural gas. Compared with coal, assuming that the price of terminal thermal coal (calorific value of 5,500 kcal/ton) reaches 1000 yuan/ton, the efficiency of coalfired boiler is 65%, and the efficiency of natural gas boiler after coal is converted into gas is calculated at 90%, the equivalent price of natural gas (calorific value of 8,500 kcal/m3 ) is 2.14 yuan/m3 , still lower than most industrial natural gas prices in the eastern coastal areas. Compared with wind electricity and PV electricity, it is also an indisputable fact that the on-grid electricity price of gas electricity is relatively high. Compared with the foreseeable cost reduction of energy storage, the market expects a lower cost reduction of gas electricity. At the same time, the current natural gas pricing mechanism has not yet adapted to the direction of market development. Objectively, “controlling the middle and relaxing the control over both ends” requires that the prices at both ends of supply and sales are formed by the market, and only the prices at the middle pipeline are regulated by the government. Although the gas transmitted through pipelines is priced separately after the establishment of PipeChina, the benchmark price at outlets still exists and still includes the price through pipelines. Catalogue of Pricing by the Central Government revised in 2020

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proposed that the outlet prices of natural gas in provinces with competitive conditions shall be formed on the market (Towngas 2021), but it is not clear what the competitive conditions specifically include and which provinces have the conditions. Under the new situation, the reform of natural gas pricing mechanism should not only adapt to the direction of market development, but also needs to focus on improving the competitiveness of natural gas in the future energy system from the perspective of sustainable development.

Achieve Synergy Between Short-Term Growth of Natural Gas Scale and Long-Term Carbon Emission Reduction After the double carbon goals is put forward, how to adapt to the situation and maintain healthy and high-quality development of natural gas has always been the key concern of the industry. On the one hand, as the lowest-carbon fossil energy, natural gas has obvious advantages over coal in terms of air pollutant reduction, CO2 emission reduction and efficiency improvement. As the proportion of new energy sources increases, solving its problems of instability, discontinuity and difficulty in prediction will gradually become the core and key of energy development. Natural gas power generation supports fast start-stop and strong grid adaptability, and it has the ability to provide power peak shaving in different time scales from hour to quarter. Promoting the integrated development of natural gas and new energy, and optimizing and adjusting the utilization structure of natural gas have become the basic consensus of industry development. From the perspective of economic and social development and urbanization, the trend of rapid development and expansion of natural gas will not change in the next 10–15 year (Wang et al. 2022). Therefore, natural gas infrastructure needs to be built ahead of schedule, especially to make up for the shortcomings of gas storage and peak shaving facilities as soon as possible, so as to provide a strong physical foundation for natural gas to play a multi-scale power peak shaving capacity. On the other hand, natural gas, as a carbon-containing energy source, has to face the challenge of meeting the carbon reduction or zero carbon requirements as the “peak carbon emissions” process moves into the “carbon neutral” phase. On June 9, 2021, the National Development and Reform Commission issued the Measures for the Supervision and Review of Natural Gas Pipeline Transportation Pricing Costs (for Trial Implementation), which extended the depreciation period of natural gas pipelines from the 30–40 years. Even new pipelines built in 2020 will not be depreciated until 2060. Therefore, the development of natural gas must deal with the synergistic relationship between short-term scale growth and long-term carbon reduction, doing everything possible to avoid large-scale infrastructure losses, and planning the transformation and development of natural gas infrastructure in the “carbon neutral” stage.

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Suggestions for the High-Quality Development of the Natural Gas Industry Deepen Reform and Accelerate the Diversification of Natural Gas Suppliers First, further promote the trading of mining rights. On the basis of summarizing the pilot experience of management system reform for Xinjiang oil and gas exploration and development, we should continue to guide and encourage qualified domestic and foreign market entities to participate in oil and gas exploration and development. The Document No.7 for trial implementation, which will expire in early May 2023, should be improved for introducing an official document. Although oil companies disagree with the policy of deduction of 25% of the area specified upon expiration, it is recommended to continue to retain the policy, considering that it is currently the most effective means to increase the diversity of subjects in the exploration and development sector. At the same time, continue to encourage the circulation of oil and gas mining rights within and between major oil companies. Second, increase the investment in oil and gas blocks. We should fully summarize the experience and lessons learned from the pilot competitive trading of mining rights, and introduce management measures for the competitive trading as soon as possible. The backlog of blocks with prospecting rights in the hands of natural resources management departments should be reduced as much as possible, and it is recommended that the area reduced after the expiration of prospecting rights should be put on the market again through bidding, auction and listing within a period of time (e.g. 6 months). The scope of competitive trading of oil and gas mining rights should be expanded and the trading of mining rights/proven reserves should be carried out on a pilot basis. Third, we should promote the specialization and reorganization of engineering technology, engineering construction and equipment manufacturing of state-owned oil and gas enterprises to participate in competition as independent market players in order to solve the technical concerns of new entrants to the exploration and development market. Fourth, we should ensure that the new entrants to assume responsibility for supply assurance. It is suggested that enterprises that have newly acquired the prospecting right shall not transfer the prospecting right within a period of time (such as the first prospecting right period) to avoid speculation. New entrants to the gas supply field should meet the relevant national requirements in terms of gas storage capacity.

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Driven by Innovation, Steadily Advance Price Reform and Market-Oriented Development First, pilot first, and then gradually remove control over outlet price. It is necessary to integrate price reform with the construction of a competitive market by taking into account the abolition of outlet prices, the improvement of the pipeline pricing mechanism, the integration of the provincial and national networks, and the synergy between the trunk pipeline network and the provincial pipeline network in the pricing mechanism. This should start with provincial or regional pilots to accumulate experience, and then gradually expand to the whole country. Second, improve the pricing mechanism of pipeline transmission. We should study the feasibility of gradually adjusting pipeline pricing from the current model of “regional pricing by route” to the model of “inter-provincial pricing by route + fixed price within provinces,” taking into account the construction of regional competitive markets, the integration of national and provincial networks, and the organic unification of pricing mechanisms of trunk pipeline networks and provincial pipeline networks. This will enhance the space for optimization and synergy of the pipeline networks in the regional markets, and promote large-scale regional market competition, taking into account the needs of local universal service. It is important to study the synergy between the mainline and provincial networks in terms of pipeline pricing and explore various models to achieve integrated pricing. At the same time, we should balance the objective reality of large-scale promotion of pipeline construction with end-users’ expectations of lower gas costs, and study the feasibility of further reducing the benchmark rate of return. Third, we should study the applicability and feasibility of the two-part pricing in China. Two-part pricing is a common method adopted by developed countries in Europe and the US for natural gas infrastructure, i.e., the service charge is composed of two parts—capacity charge and usage charge. It has the advantage of solving the problem of unreasonable charges arising from uneven gas consumption under the one-part pricing, and also encourages users to effectively use the pipe, tank and storage capacity. Fourth, the pricing mechanism for residential gas should be further improved. It is recommended that the first step is to retain the management of the benchmark outlet price for residential gas, but to allow residential gas to be priced according to the pricing mechanism, i.e. “the supply and demand sides can negotiate specific outlet prices based on the benchmark outlet price, within the scope of allowing a 20% increase and an unlimited degree of decrease.” In the second step, residential gas should be liberalized as appropriate, but the government retains the right to regulate abnormal price fluctuations. Fifth, we should further rationalize the downstream gas distribution and sales prices. A unified nationwide gas price linkage mechanism from upstream to downstream should be established, with a gradual transition from non-residential gas to all gas types. Considering that the investment risk of gas distribution networks is usually lower than that of long-distance pipelines, it is recommended to study the feasibility

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of further reducing the permissible rate of return of gas distribution networks. The separation of gas distribution and sales should be encouraged based on the voluntary principle. When the price of residential gas increases, subsidies for low-income groups and others in need should also be increased to guarantee basic livelihoods.

Take the Initiative to Establish and Improve the Natural Gas Supervision System First, we should take the establishment of PipeChina’s regulatory rules for infrastructure fair opening as the entry point to improve the infrastructure regulatory rules, in order to further regulate the fair opening behavior of pipeline network facility operators. More detailed rules for the construction and operation of pipeline infrastructure should be introduced to refine and improve the system of shippers, and in addition to rules such as the pricing mechanism for pipeline transmission, emphasis should be placed on establishing a standard system for the calculation method of spare capacity of pipe capacity, tank capacity and storage capacity. The details of information disclosure requirements should be further improved on the basis of the Model Text for Fair Opening Information Disclosure of Natural Gas Pipeline Network Facilities issued in 2019, and it is recommended to further clarify the items including the information to disclose, time period, information granularity, information release platform, etc. with reference to the experience of Europe and the US, in order to develop a detailed template for information disclosure. Second, we should optimize the price regulation rules of transmission and distribution links. The pricing cost assessment and monitoring system should be improved, and a system for reporting, reviewing and disclosing cost information should be established. It is recommended that pricing cost assessment reports and pricing cost monitoring reports be issued on a regular basis. Cost benchmarking analysis should be introduced, i.e., by benchmarking the construction investment, operating cost and performance of each price zone, each enterprise, and even each pipeline, so that the regulatory authorities can grasp the true cost information as much as possible. The incentive of price regulation should be improved, and the method of determining pricing parameters and price adjustment cycle should be refined. Third, we should build a multi-level coordinated regulatory governance system. In terms of economic regulation, it is recommended to reorganize and optimize the existing regulatory force by establishing an independent regulatory agency, similar to but different from the US Federal Energy Regulatory Commission. It is recommended that the secondary regulatory agencies in each region or province remain as dispatched agencies with Chinese characteristics and receive vertical management from the central government. The regulatory responsibilities and authority of the relevant departments of the central and local governments in all aspects of the natural gas industry should be clarified to form a governance system with equal authority

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and responsibility, reasonable division of labor, smooth implementation and strong supervision.

Establish a Strategic Mindset and Plan the Transformation and Upgrading of Natural Gas in a Scientific Manner First, we should promote the integration of natural gas with wind power, PV, hydrogen energy, biogas and other energy sources. Wang et al. (2022) proposed that the integrated development of natural gas and new energy mainly adopts three modes: base type, ocean type and park type; the integrated development of natural gas and hydrogen energy mainly has three application scenarios: hydrogen-enriched compressed natural gas, hydrogen storage and hydrogen energy distribution; and that of natural gas and biogas mainly has two integration modes: point type and net type. The integration of natural gas and new energy is the development model that has received the most attention in the industry. Most of the oil and gas fields of oil companies are rich in wind and light resources, which have the physical basis for the integrated development of natural gas and new energy. At present, CNPC’s onshore oil and gas fields such as Daqing, Liaohe, Changqing, Tarim, Xinjiang, Jilin, Dagang, Qinghai, North China and Jidong are actively deploying new energy projects (CNPC 2022a). CNOOC is exploring new integrated development modes such as “wind-solar complementary power generation + oil and gas industry,” “wind-solar complementary power generation + natural gas power generation” and “offshore wind power generation + ocean ranch” (Wang 2022). Sinopec, with the advantage of its hydrogen business chain, has chosen hydrogen energy as the focus of new energy development and proposed to actively promote industrial demonstration in two major areas, namely, hydrogen transportation and green hydrogen refining (Sinopec 2022b). PipeChina, on the other hand, based on its transportation advantages, has chosen to focus its research and development on the transportation of hydrogen, carbon dioxide, etc. Municipal gas companies are also actively carrying out research on the transportation and utilization of hydrogen-enriched compressed natural gas. Second, we should actively carry out research and development of CCUS-related technologies and continue to expand the space of natural gas carbon emission. In CO2 flooding, we can give full play to the first-mover advantage of oil and gas companies, and strive to expand the scope of application based on the summary of the progress of existing CO2 flooding technology. As for CO2 sequestration, we can make full use of the advantages of oil and gas exploration and development technology to pilot research on CO2 sequestration technology in saline aquifers, depleted oil and gas reservoirs and deep sea. In terms of CO2 transportation, research and pilot work on CO2 transportation by oil and gas pipeline should be actively carried out. As for CCUS industrial base, it is suggested to build regional CCUS demonstration bases featuring CO2 capture, transportation, flooding and storage underground around areas

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with both natural gas resources and CO2 storage capacity, such as Junggar Basin, Ordos Basin and Bohai Bay Basin.

References China Gas Holdings Co., Ltd. Twenty years of cultivation brightens the future (annual report for 2021/2022) [EB/OL]. [2022-07-18/2022-08-23]. http://cn.chinagasholdings.com.hk/Private/ NewsImgs/6379377377990775051291474223.pdf China Natural Gas Development Report (2022) Department of Petroleum and Natural Gas of National Energy Administration, Institute of Resources and Environmental Policy of the State Council Development Research Center, Oil and Gas Resources Strategy Research Center of Ministry of Natural Resources. Petroleum Industry Press, Beijing, p 3 China Natural Gas Production in 2016–2021 (2022). Int Pet Econ 30(1):5 China Resources Gas Holdings Co., Ltd. Annual report for 2021 [EB/OL]. [2022-04-20/202208-23]. https://www.crc-gas.com/tzz/cwxx/cwbg/2021/yearnb/202204/P02022042072515178 8919.pdf CNOOC (2021) Annual report for 2021 [EB/OL]. [2022-05-26/2022-07-19]. http://www.cnpc. com.cn/cnpc/ndbg/202205/dfacd21e00704c86ad94c6317f755943/files/32925aa9c28043c484 e77fb21cbcf936.pdf CNPC (2022a) Accelerate the pace of transformation and comprehensively promote the integrated development of oil and gas and new energy [EB/OL]. [2022-06-24/2022-09-07]. https://baijia hao.baidu.com/s?id=1736444876553133810&wfr=spider&for=pc CNPC (2022b) Annual report for 2021 [EB/OL]. [2022-05-26/2022-07-19]. http://www.cnpc. com.cn/cnpc/ndbg/202205/dfacd21e00704c86ad94c6317f755943/files/32925aa9c28043c484 e77fb21cbcf936.pdf ENN (2022) Annual report for 2021—embark on the next low-carbon journey [EB/OL]. [2022-05/ 2022-08-23]. https://www.xinaogas.com/u/CMS/www/202205/12103002snva.pdf KunLun Energy Co., Ltd. Annual report for 2021 [EB/OL]. [2022-04-19/2022-08-23]. http://mediakunlunenergy.todayir.com/20220419182401463110216434_tc.pdf Liu C, Jiang X, Wu M (2021) Development report of oil and gas industry in China and abroad in 2021. Petroleum Industry Press, Beijing, p 90 National development and reform commission. Order No.31 of the national development and reform commission of the People’s Republic of China [EB/OL]. [2020-03-13/2022-08-23]. https:// www.ndrc.gov.cn/xxgk/zcfb/fzggwl/202003/t20200316_1223371.html?code=&state=123 Sinopec (2022a) Love my China, revitalize Sinopec—better energy for better living [EB/OL]. [2022-06-07/2022-07-19]. http://www.sinopecgroup.com/group/Resource/Pdf/GroupAnnualR eport2021.pdf Sinopec (2022b) Sinopec issued and implemented the medium and long-term development strategy of hydrogen energy [EB/OL]. [2022-09-05/2022-09-07]. https://baijiahao.baidu.com/s?id=174 3137867505174138 Sun H (2018) Analysis and optimization of China’s natural gas industry structure. China University of Geosciences (Beijing), p 17 Towngas. Annual report for 2021 [EB/OL]. [2022-08-23]. http://www.towngas-smartenergy. com/getattachment/Investor-Relations/Annual-Report/2022/Annual-Report-2021/CW_010 83AR2021-(Full).pdf.aspx?lang=zh-HK&ext=.pdf Wang Y (2022) The wind comes from the sea—CNOOC marches into the new energy sector [EB/ OL]. [2022-08-20/2022-09-07]. https://m.thepaper.cn/baijiahao_19545372 Wang W, Sun H, Yang L (2022) Vigorously promote the integrated development of gas and various energy sources: discussion on the development strategy of gas industry under the goals of peak carbon emissions and carbon neutrality. Urban Gas 569(7):1–5

Chapter 11

Progress and Suggestions on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China Xiongjun Zhang and Jun Bai

Introduction The physicochemical properties of natural gas dictate that its flow from the resource location to the end-user must rely on one or more of the processes of transportation and distribution in pipelines, liquefaction and regasification in LNG receiving stations, and injection and extraction in storage depots, resulting in a high dependence on the pipeline infrastructure1 of transmission pipelines, distribution pipelines, LNG import receiving stations and storage depots. Due to the high dependence among the various links in the natural gas industry chain, the extent of infrastructure development and interconnection, as well as its matching with the development of resource and consumer markets, will affect the scale and speed of natural gas market development. Infrastructure of natural gas pipeline network, as the route of natural gas resource flow, occupies public land, coastal or mineral natural resources, which has certain monopolistic, scale, public and public welfare characteristics, and is a key area of government regulation. These characteristics make the effectiveness of its institutional reform extremely important to the success of natural gas market-oriented reform. The infrastructure of China’s natural gas pipeline network is marked by the construction of the West-East Gas Transmission Line 1, Dazhangtuo Gas Storage in Dagang and Dapeng LNG Receiving Station in Guangdong, which has entered a 1 This paper does not consider the flexible but relatively small-scale transportation and storage methods such as tanks and tankers.

X. Zhang (B) Beijing Gas Group, Beijing, China e-mail: [email protected] J. Bai Beijing Gas Research Institute, Beijing, China © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_11

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stage of rapid development. By the end of 2021, the total mileage of trunk pipelines in service in China reached 116,000 km (Department of Petroleum and Natural Gas of National Energy Administration et al. 2022). According to public statistics, the mileage of urban natural gas distribution pipelines in China reached 1.05 million km; there are 22 LNG import receiving stations in service, with an annual receiving capacity of 100.1 million tons and an LNG storage tank capacity of 11.75 million cubic meters (Bai and Zhang 2021); and there are 15 gas storage groups in service, with a working gas production capacity of about 16.6 billion cubic meters. The establishment of PipeChina is the key to the institutional reform of natural gas pipeline infrastructure in China. The official operation of PipeChina has basically separated the competitive production and supply segments of China’s oil and gas market from the midstream monopoly segment of storage and transportation, laying an organizational foundation for enhancing the competitiveness and strengthening the supervision of monopoly. At present, the main tasks of the institutional mechanism reform are to establish a new operating mechanism of pipeline network, strengthen the fairness, openness and transparency of pipeline network services, enhance the supervision of infrastructure, promote the construction of pipeline infrastructure, improve the utilization efficiency of pipeline network facilities, support the efficient flow of natural gas resources, ensure the safety of natural gas supply and better serve the development needs of natural gas market. In this paper, the policy and practice progress of institutional mechanism reform of natural gas pipelines, LNG receiving stations and storage depots before and after the establishment of PipeChina are summarized, and the main problems are discussed, and relevant suggestions are put forward in combination with the development direction of China’s oil and gas system reform.

Progress on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China Independent Ownership of Trunk Pipeline Infrastructure After 1998, the major natural gas producers and suppliers in China—CNPC, Sinopec, and CNOOC (hereinafter referred to as the three major oil companies)—became the major owners and operators of natural gas pipelines, LNG receiving stations and gas storage in China. The Opinions on Deepening the Oil and Gas System Reform issued in May 2017 cover eight key tasks of oil and gas system reform, including establishing the operation mechanism of oil and gas pipeline network. In March 2019, the seventh meeting of the Central Committee for Comprehensively Deepening Reform adopted the Implementation Opinions on the Reform of the Operation Mechanism of Oil and Gas Pipeline Network, demanding the establishment of an oil and gas pipeline

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network company with state-owned capital holding and diversified investment entities, which promote the formation of an oil and gas market system with multi-agent and multi-channel supply of upstream oil and gas resources, efficient collection and transportation in the middle unified pipeline network and full competition in the downstream sales market, so as to improve the allocation efficiency of oil and gas resources and ensure the safe and stable supply of oil and gas. On December 9, 2019, PipeChina was established. After reaching a series of equity and cash trading schemes, on September 30, 2020, PipeChina, the three major oil companies and other shareholders held a signing ceremony for the delivery and operation handover of oil and gas pipeline network assets, thus PipeChina officially taking over the national trunk pipelines, some storage deports and LNG receiving stations of the three major oil companies. As it entered into substantial operation, the structure of the Chinese natural gas market changed significantly As an independent monopoly operator and carrier of oil and gas trunk pipelines, PipeChina does not engage in trading of oil and gas commodities, and provides fair, just and open storage and transportation services to shippers. Its production and operation, service charges and information disclosure all need to be strictly supervised by government departments (Bai and Zhang 2021), which has changed the situation that competitive business and monopoly business were mixed before the reform. In 2021, the average load rate of PipeChina’s pipelines and the average utilization rate of LNG receiving stations increased by 9 and 16% respectively year-on-year, the average transportation distance of natural gas decreased by 3% year-on-year, the pipeline transportation cost was saved by over 2 billion yuan (PipeChina 2020), and 53 shippers other than the three major oil companies were added (Xu 2020). PipeChina operates the main pipeline infrastructure originally operated by the three major oil companies in a unified way. It is the owner and operator of China’s natural gas trunk pipeline infrastructure, covering 30 provinces (autonomous regions and municipalities directly under the Central Government) and the Hong Kong Special Administrative Region, with the capacity to allocate resources around the country. PipeChina is responsible for the investment, construction and operation of the national natural gas trunk pipelines, some gas storage and peak-shaving facilities, LNG receiving stations and other infrastructure, for the interconnection of the trunk pipelines and interconnection of the trunk pipeline network with social pipelines, and for the operation and scheduling of the national natural gas trunk pipelines. It regularly discloses the remaining pipeline transportation and storage capacity to the public, and fairly open pipeline transportation and storage services to all eligible users (Introduction to PipeChina [EB/OL] 2022). In addition, PipeChina also undertakes the responsibility of emergency supply and coordination and the corresponding responsibility of gas storage, pipeline protection and safe operation of infrastructure. According to public information, PipeChina operates about 49,000 km of natural gas pipelines, accounting for about 44% of the total mileage of national trunk pipelines; the annual pipeline transportation capacity is 260 billion cubic meters, accounting for about 70% of the national natural gas consumption in 2021. In addition, the national pipeline network group owns seven active LNG receiving stations, with annual receiving capacity and storage capacity exceeding 30% of the national total

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respectively; and eight gas storage depots (including those with equity participation) (PipeChina 2021), which accounted for more than 25% of the national total and 1.2% of the national gas consumption in 2021. For the 14th Five-Year Plan period, PipeChina planned to build more than 25,000 km of new pipelines. As the reform progresses, with the integration of provincial pipeline networks into the market, the allocation of gas storage assets, and the completion of projects under construction and planned for commissioning, PipeChina’s national share of gas pipeline infrastructure will further increase. The share of pipeline infrastructure directly owned by the three major oil companies will shrink accordingly after this round of reform. In 2021, the mileage of China’s oil trunk pipelines was 17,000 km (CNPC 2021), accounting for about 15% of the national total, down from over 70% in 2019. The in-service LNG receiving stations of the three major oil companies account for about 55% of the total receiving capacity in China, while municipal gas companies, power companies and other enterprises have about 15% of the receiving capacity. The working gas volume of CNPC gas storage decreased from 90% to about 50% of the national total. However, the three major oil companies, as shareholders of PipeChina, still enjoy the corresponding shareholder rights and, as the most important shippers of PipeChina, enjoy priority access to the relevant infrastructure, and PipeChina only opens the spare capacity to other third parties. In 2021, the three major oil companies account for approximately 90% of the total infrastructure services of PipeChina.

Progress of Integration of Some Provincial Networks Into the National Pipeline Network According to public reports, the Implementation Opinions on the Reform of the Operation Mechanism of Oil and Gas Pipeline Network (Huang 2019) puts forward the following opinions on the provincial pipeline network reform. All equity shares held by large state-owned oil and gas enterprises in provincial pipeline companies are owned by PipeChina; localities are encouraged to take equity in PipeChina with provincial pipeline assets. After the establishment of PipeChina, it will actively communicate with relevant local government departments and pipeline enterprises to promote the integration of provincial pipeline companies into PipeChina in a market-oriented manner. Currently, there are 35 intra-provincial short-distance pipeline companies located in 25 gas-supplying provinces. PipeChina holds or participates in about 50% of the provincial pipeline companies through various means such as asset transfer, equity transactions and service commitments. According to TianYanCha data, the equity interests held by PipeChina in provincial pipeline companies are shown in Table 11.1 (Link 2020). At present, PipeChina has signed cooperation agreements with seven provincial governments in Guangdong, Hainan, Hubei, Hunan, Fujian, Gansu and Zhejiang

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Table 11.1 Equity interests in provincial pipeline companies acquired by PipeChina through asset transfer No.

Company

Shareholding ratio (%)

1

PipeChina Jiangsu Natural Gas Pipeline Co., Ltd.

76

2

PipeChina Shandong Natural Gas Pipeline Co., Ltd.

70

3

Shandong Guoshi Pipeline Natural Gas Co., Ltd.

65

4

PipeChina Jilin Natural Gas Pipeline Co., Ltd.

51

5

PipeChina Jilin Natural Gas Pipeline Co., Ltd.

60

6

PipeChina Guizhou Pipeline Co., Ltd.

60

7

PipeChina Zhongyuan Natural Gas Pipeline Co., Ltd.

65

8

PipeChina Hebei Construction & Investment Natural Gas Pipeline Co., Ltd.

50

9

PipeChina Guangdong Pipeline Co., Ltd.

72

10

PipeChina Hainan Pipeline Co., Ltd.

55

11

PipeChina Hunan Natural Gas Pipeline Co., Ltd.

60

12

PipeChina Fujian Pipeline Co., Ltd.

60

13

PipeChina Gansu Natural Gas Pipeline Co., Ltd.

60

14

Hubei Natural Gas Development Co., Ltd.

49

15

Zhejiang Natural Gas Development Co., Ltd.

60

16

Guangxi Natural Gas Pipeline Co., Ltd.

65

17

Jiangxi Natural Gas Investment Co., Ltd.

50

18

Jiangxi Natural Gas Pipeline Co., Ltd.

46

on the investment, construction and management of provincial pipeline networks. With the exception of Hubei Province, PipeChina has become the only construction and operation entity of natural gas trunk and branch pipelines in the other six provinces, establishing the principle of “unified planning, unified construction, unified operation, unified management and unified freight rate.” According to public information, the total mileage of trunk pipelines in Guangdong Province is about 3,600 km, including about 1,500 km of West-East Gas Transmission pipelines. Guangdong Pipeline Network Company has completed 1,300 km of trunk pipeline network, Dapeng LNG Receiving Station about 444 km, and CNOOC Guangdong Pipeline about 350 km; and 56 of 122 counties (districts and county-level cities) have been connected to natural gas pipelines. According to the plan, PipeChina will strive to connect almost all counties in Guangdong Province to the pipeline network by the end of 2022. In Hainan Province, about 470 km of natural gas pipelines have been completed and put into operation, with an annual gas transmission capacity of 1.6 billion cubic meters. During the 14th Five-Year Plan period, PipeChina will complete a network of pipelines covering major coastal cities and important industrial and economic development areas in the province to upgrade the natural gas pipeline network in Hainan Province to a more intensive

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distribution. The 664 km high-pressure pipeline network in Hubei Province will be integrated into PipeChina after the separation of the provincial natural gas sales and pipeline assets. Hunan Province has a total provincial gas pipeline network of over 2,000 km, with 86% coverage at the prefectural and municipal levels. Fujian Province has a total of 1,566 km of natural gas pipelines built and under construction, including national trunk pipelines such as the Fujian section of the West-East Gas Transmission Line III and pipeline networks within Fujian Province such as the West Coast Pipeline Network. In Gansu Province, there are seven trunk pipelines crossing the province with a total length of nearly 3,800 km, including the WestEast Gas Transmission Line, Sebei-Xining-Lanzhou Line, Lanzhou-Yinchuan Line and Zhongwei-Guiyang Line, with an annual gas transmission capacity of over 100 billion cubic meters. Zhejiang Province has a provincial gas pipeline network of over 2,500 km, and during the 14th Five-Year Plan period, PipeChina will plan 1,600 km of new provincial gas pipelines and one LNG receiving station in Zhejiang.

Initial Establishment of Rules for Price Management and Cost Monitoring under the System of Separation of Transportation and Sales In accordance with the idea of natural gas and electricity price reform “controlling the middle and relaxing the control over both ends,” while accelerating the full competition and market-oriented price reform of the competitive segments of the natural gas industry, we should also focus on strengthening the cost supervision of the prices of pipeline transportation and gas distribution segments with monopoly properties. According to the requirements of Price Law of the People’s Republic of China, the Rules for the Pricing Activities of Governments (2017), the Measures for the Supervision and Examination of the Government-fixed Costs (2017) and the Opinions of the National Development and Reform Commission on Further Strengthening Price Regulation in Monopolized Industries, China has initially established a pricing mechanism based on “allowable cost plus reasonable income” for networkbased natural monopolies, while government departments are also exploring ways to further improve the market-regulated pricing mechanism for competitive links. After the establishment of PipeChina, the relevant government departments have adjusted the management rules of inter-provincial pipeline service prices and LNG receiving station re-gasification service prices in a targeted manner. In terms of the price of pipeline transportation services (Zhang and Bai 2021), four price zones were set for inter-provincial pipelines, each with its own freight rate. In June 2021, the National Development and Reform Commission issued the Measures for the Administration of Natural Gas Pipeline Transportation Prices (for Trial Implementation) and the Measures for the Supervision and Review of Natural Gas Pipeline Transportation Pricing Costs (for Trial Implementation) (2021) (hereinafter referred

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to as the Measures for the Administration of Prices and the Measures for the Supervision and Review of Costs respectively), which classify inter-provincial pipelines into four zones with different freight rates: northwest, southwest, northeast and mid-east. the Measures for the Administration of Prices and the Measures for the Supervision and Review of Costs adapt to the requirements of the new market situation after the establishment of PipeChina. In the first regulatory period, the original restrictions on the main pricing parameters such as pipeline load rate of not less than 75%, cost return rate of 8% and pipeline depreciation period of 40 years have been maintained, thus the stability of pricing parameters has been maintained. In addition, by retaining the right to dynamically adjust the pricing parameters and adding the right to finetune the permitted revenue and freight rates for different price zones, the principle of dynamic adjustment according to the development stage of the pipeline network, the industry development situation and the natural gas reform process was clarified, paving the way for the subsequent adjustment of pipeline transportation prices, reflecting the characteristics of smooth reform and gradual advancement. As for the service prices of LNG receiving stations (Zhang and Yang 2022), the National Development and Reform Commission Guiding Opinions of the National Development and Reform Commission on Improving the Pricing Mechanism for Re-gasification Services Provided by Imported Liquefied Natural Gas Terminals, which distinguishes the services and products provided according to the different functional positioning of the facilities at the receiving stations, and implements government-guided pricing and market-independent pricing respectively. (1) Regasification service prices shall be subject to government-guided price administration, and the price regulation is implemented by combining the government-guided pricing and flexible pricing of the receiving station. The setting of a maximum re-gasification service price by each province (autonomous region or municipality directly under the Central Government) is encouraged. The re-gasification service provided by the process facilities related to “liquid-in and gas-out” can be understood as a link of the pipeline infrastructure. The pricing principle and the requirements of permissible rate of return are consistent with the inter-provincial pipeline pricing administration of the network-based natural monopoly link, and a minimum re-gasification ratio of 60% is required for the re-gasification service efficiency. The standardized pricing mechanism at the central government level provides standards and references for local development and adjustment of guideline prices for re-asification services. According to the requirements, provincial pricing authorities will develop their own provincial (autonomous regions and municipalities directly under the Central Government) price management methods and cost monitoring rules under this framework by the end of 2022, and set the highest re-gasification service rates in their provinces. Each receiving station will set and make public its own service rates for receiving stations, subject to the requirement that the highest gasification service rates in the province are not exceeded. Through the tiered price management process, on the one hand, it can ensure that the receiving stations obtain the revenue within the scope of government permission through policy protection, on the other hand, it leaves room for the receiving stations to innovate products and improve efficiency, which can stimulate the vitality of market players to take

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market risks independently within a certain range and expand reasonable and effective investment. (2) Liquid outbound services of LNG receiving stations, as well as tank outbound, transshipment and other emerging outbound services that play a hub function of receiving stations are regarded as competitive links and will no longer be priced by the government, but by the market, i.e., negotiated between receiving stations and users based on service costs and revenues, market supply and demand and competitive conditions. Among them, the liquid outbound services are connected with the market-oriented pricing of liquid commodities. LNG terminal storage tanks carry two different functions: firstly, as an accessory facility of the terminal to ensure the safety of terminal operations; secondly, as a large gas storage and peak-shaving facility to ensure the safety of natural gas supply. A maximum storage limit of 45 days has been set for the former, while the latter is open to market-based pricing. Although still weakly competitive, the gas storage market currently follows the provisions of the Opinions on Accelerating the Construction of Gas Storage Facilities and Improving the Market Mechanism for Gas Storage and Peak-shaving Services, which implement market-based pricing for gas storage and peak-shaving facility services. Wen 23 Gas Storage of PipeChina, Jintan Salt Cave Gas Storage of Towngas and Huangcaoxia Gas Storage of Chongqing Storage and Transportation Company have launched bidding and bidding transactions for storage capacity, trading of peakshaving products and listed transactions of storage capacity in the trading center on a trial basis. The provincial pipeline prices will be set by the provincial price authorities with reference to the relevant principles of the Measures for the Administration of Prices and the Measures for the Supervision and Review of Costs, and to strengthen the interface with inter-provincial pipelines on pricing administration. In terms of the price of urban gas distribution network, the National Development and Reform Commission issued the Guiding Opinions on Strengthening the Supervision of Gas Distribution Price in June 2017, which provides guidance to localities in formulating rules for gas distribution price management and pricing cost monitoring, stipulating the upper limits of core pricing indicators, such as the price differential between supply and sales should in principle not exceed 5% and be reduced to no more than 4% within 3 years, the depreciable life of the pipeline network should not be less than 30 years, and the permissible rate of return should not exceed 7%, etc., and allows localities to determine their own specific indicators taking into account the development and affordability of the natural gas market under their jurisdiction.

Improved Opening of Spare Capacity to Third Parties Before the independence of trunk pipeline network, China has put forward the requirement that the spare capacity of oil and gas pipeline infrastructure should be opened to third parties. After the independence, the opening of natural gas pipeline infrastructure to third parties has been obviously improved.

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The Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities (for Trial Implementation) (2014) issued by the National Energy Administration in February 2014 requires oil and gas pipeline facilities operators to separate the operation of pipeline facilities from other oil and gas businesses financially, and provide access to their oil and gas pipelines network facilities to new users in a fair and non-discriminatory manner in the precedence order of signing contracts in case of spare capacity of oil and gas pipelines network facilities. The Opinions on Deepening the Oil and Gas System Reform issued the CPC Central Committee and the State Council clearly proposes to improve the fair access mechanism of pipeline networks, and open access of trunk pipelines, provincial and inter-provincial pipeline networks to third-party market entities fairly. In May 2019, the National Development and Reform Commission, the National Energy Administration, the Ministry of Housing and Urban-Rural Development, and the General Administration of Market Supervision jointly issued the Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities (2019), requiring oil and gas operators to open pipeline facilities to qualified users as required before the reform of the pipeline network operation mechanism is complete, in case of spare capacity of oil and gas pipelines network facilities, while ensuring the existing services for existing users. The Measures further standardize the application, acceptance process and regulatory requirements for facilities such as oil and gas pipeline networks and LNG receiving stations, and propose to build fair opening services under the contract management mechanism and encourage diversified services. During this period, the three major oil companies explored conditional tentative opening to specific third parties such as shareholders during the window period of LNG import terminal (Zhang et al. 2019). Upon the establishment and formal operation of PipeChina, the effect of opening up the infrastructure of natural gas pipeline network has been significantly improved. Sinopec and CNOOC entered the previously inaccessible market with the help of the pipelines of PipeChina, and CNPC began to use the previously inaccessible receiving stations. Many other market players, including Kingho Xinjiang, Guanghui and JOVO, have gained unprecedented opportunities to enter the market, and the diversification of upstream resource suppliers has improved to some extent. Some companies have also begun to explore possible business opportunities under the new system and mechanism of pipe network operation.

Initial Formation of the Regulatory System Regulation is the continuous improvement of government functions in the process of marketization, as well as the correction and supplement of market failure on the basis of giving full play to the decisive role of market mechanism in resource allocation (Wang 2017). Along with the progress of oil and gas system reform, the oil and gas regulatory system is also in the process of gradual improvement. One of the important elements of the “controlling the middle” is the regulation of the opening

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and services of the natural gas pipeline network infrastructure, which is a natural monopoly. After nearly 10 years of development, a system for regulating natural gas pipeline infrastructure has been initially established. In terms of regulatory basis, a regulatory policy system based on administrative laws and regulations, departmental regulations and local government regulations has been formed, and these regulatory documents mainly include the Measures for the Management of Natural Gas Infrastructure Construction and Operation promulgated by the National Development and Reform Commission, the Measures for the Supervision and Administration of Fair Opening of Oil and Gas Pipelines Network Facilities (2019), the Notice on Enhancing Information on Fair Opening of Natural Gas Pipeline Network Facilities (2019), the Opinions on Accelerating the Construction of Gas Storage Facilities and Improving the Market Mechanism for Gas Storage and Peak-shaving Services (2018), the Measures for the Administration of Natural Gas Pipeline Transportation Prices (for Trial Implementation) and the Measures for the Supervision and Review of Natural Gas Pipeline Transportation Pricing Costs (for Trial Implementation) (2021), and other policy documents related to oil and gas system reform. In terms of regulatory practice, the existing requirements of fair opening and information disclosure are gradually regulated, price cost monitoring and fair competition regulation are gradually strengthened, service regulation is continuously improved, operation regulation is gradually launched, planning and construction regulation is expected to be improved, and a new energy regulatory mechanism based on credit is also being built. In addition, anti-monopoly regulation and production safety regulation are also being gradually strengthened. In terms of regulatory agencies, the National Development and Reform Commission, the National Energy Administration, the General Administration of Market Supervision, the Ministry of Housing and Urban-Rural Development and other departments as well as relevant local departments involved in development and reform, energy, economic and information, market supervision, etc. carry out regulatory work in accordance with their respective authorities. The Department of Market Regulation of the National Energy Administration and its 18 dispatched agencies are responsible for regulating the fair opening of oil and gas facilities (except city gas) nationwide, and the related work is gradually being deepened.

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Main Problems at this Stage There are Shortcomings in the Construction and Development of Pipeline Infrastructure New pipelines have been slow to increase. The Medium-and Long-term Plan for Oil and Gas Pipeline Networking (2017) issued by the National Development and Reform Commission and the National Energy Administration in May 2017 (hereinafter referred to as the Plan for Pipeline Networking) proposes that the mileage of national natural gas trunk pipelines would reach 104,000 km by 2020 and 163,000 km by 2025. By the end of 2020, the total mileage of the national natural gas trunk pipeline was 83,000 km, failing to reach the goal set for the year. According to the goal for 2025, 47,000 km of new trunk pipelines should be built on the basis of the mileage of trunk pipelines by the end of 2021, which is equivalent to doubling the mileage of existing pipelines of PipeChina. PipeChina has built about 3,000 km of new trunk pipelines since it started operations nearly 2 years ago, and at this rate of construction the country is unlikely to meet its target by 2025, making it difficult to completely improve the tight transmission capacity of the natural gas pipeline network. From the perspective of medium and long-term demand increment, there is still much room for development of supporting pipeline network infrastructure. In the context of peak carbon emissions and carbon neutrality, most institutions predict that the peak demand for natural gas in China will increase to more than 600 billion cubic meters from 2035 to 2040, which is about twice the consumption of natural gas in 2021, putting forward new requirements for increasing the capacity of pipeline network infrastructure. Interconnection of pipelines is inadequate. Physically, there is insufficient interconnection between trunk lines and branch lines, between regional branch lines, between LNG receiving stations and export pipelines, and between gas storage and export pipelines. There is still a gap to build a network. Technically, there is no interoperability between pipelines of different operators and LNG receiving stations (Fu et al. 2020). At present, there are few pipelines and no LNG receiving station that can support two-way transportation. According to the Development Plan of Modern Comprehensive Transportation System in the 14th Five-Year Plan issued by the State Council in January 2022 and the Plan of Modern Energy System in the 14th Five-Year Plan issued by the National Development and Reform Commission in March 2022, the construction of natural gas trunk pipelines and regional natural gas pipeline networks will be accelerated, the construction of interconnections and inter-provincial linkages will be accelerated, and efficient interconnection between various entities and different gas sources will be strengthened. There is a serious shortage of reserve capacity. According to public information, by the end of 2021, the total peak-shaving capacity formed by the working gas volume of China’s gas storage and the storage tanks of imported LNG receiving stations was about 23.9 billion cubic meters, less than 7% of the national natural gas consumption in that year, failing to meet the requirements of seasonal peak-shaving and emergency

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supply. The pricing mechanism of gas storage and peak-shaving facilities is ahead of the actual market reform of natural gas, which limits the value of gas storage. Zhang Jianhua, director of the National Energy Administration, said at the State Council press conference Speed up the Construction of an Energy-rich Country and Fully Ensure Energy Security in July 2022 that China will continue to base on the domestic market, implement diversified security and strengthen reserves to improve the production, supply, storage and marketing system. Focusing on the medium and long-term development, the implementation plan for building national gas storage capacity was formulated, and the layout of major gas storage projects was systematically planned based on large reservoirs and stations. It is estimated that by the end of the 14th Five-Year Plan period, China’s natural gas reserve capacity is expected to double on the basis of 2021, and the coordinated and stable development and safe and stable supply of natural gas will reach a new level (Information Office of the State Council 2020). The Plan of Modern Energy System in the 14th Five-Year Plan proposes that the national storage capacity will reach 55–60 billion cubic meters, accounting for about 13% of natural gas consumption. A multi-level gas storage system will be formed with several storage clusters (with a storage capacity reaching 10 billion cubic meters) in North China, Northeast China, Southwest China, Northwest China and other regions, supplemented by large-scale LNG import terminal storage tanks at important coastal port sites, and supported by pipeline network interconnection. It will simultaneously improve the storage and regulation capacity of pipelines, gas extraction capacity of gas storage and LNG gasification and transmission capacity, so as to enhance the peak shaving capacity of natural gas pipeline network during the supply assurance season and the emergency supply capacity, and ensure the security of natural gas supply.

The Operation Rules of Pipeline Network Need to be Refined and Improved The operation and scheduling rules of pipe network need to be refined. Although PipeChina has been in operation for nearly two years, the accompanying rules for operating and scheduling the pipeline network have not yet been made available to the public. In July 2021, the National Development and Reform Commission publicly solicited opinions on Management of Operation and Dispatch of Natural Gas Pipeline Network Facilities and Emergency Supply Assurance (for Trial Implementation) (hereinafter referred to as the Trial Measures), some of which need further refinement and improvement. A series of issues such as contract booking, capacity allocation, gas volume balance, deviation settlement, emergency supply assurance, dispatch coordination, shipper management, information disclosure, etc. need to be strengthened in order to enhance the openness and transparency of pipeline services, to strengthen the cultivation of new shippers and to overcome market force interference. Therefore, “controlling the middle and relaxing the control over both ends”

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can be ensured to promote market-oriented natural gas reform. The Trial Measures finally adopted have not yet been made public, and the implementation of the Trial Measures needs to be further refined or formulated separately to avoid excessive discretion. The guiding rules for pipeline opening are absent (Wang 2020). Opening rights, or opening approval rights, refer to the physical conditions under which a pipeline infrastructure shipper applies to a carrier to connect two pipelines by opening at a sub-station or valve chamber of its owned and operated pipeline (Chen 2020) to obtain upstream downloads of natural gas. Openings are actually part of the network interconnection, and two pipelines can be interconnected directly by connecting at an opening point, or indirectly through a third or more feeder or contact pipelines and multiple opening points. Due to the nature of network-based natural monopolies, pipelines occupying land and ancillary facilities including openings are scarce resources (Gao 2020). Under the current natural gas pricing mechanism in China, pipeline gas is relatively more stable and secure in terms of both supply volume and supply cost. The scope of pipelines determines the scope of the market for pipeline gas consumption that relies on pipeline transportation. In other words, obtaining the opening rights means having a safe and stable gas routing and, to some extent, a monopoly of the consumption market along the pipeline. Since 2018, the National Development and Reform Commission and the National Energy Administration have issued annual lists of major pipeline network interconnection projects to vigorously coordinate and promote natural gas infrastructure interconnection. Compared to the national emphasis on interconnection, the contradictions between market players brought about by the absence of opening rules are hidden under the various contradictions of the reform, which have become more prominent after the establishment of PipeChina. Upstream gas supply companies that own gas sources want to obtain openings in order to give priority to the transmission of their own gas resources and to gain access to terminal markets through their associated terminal sales companies; energy groups, provincial gas pipeline companies or municipal gas companies that own local pipelines and/or terminal markets want to obtain openings in trunk pipelines in order to gain access to the wholesale market for local resources, the pipeline transmission market or the consumer market along the pipelines. Therefore, open and transparent procedures and rules are needed for pipeline facility operators to receive and allocate pipeline opening resources.

The Degree of Information Disclosure Needs to be Improved Natural gas pipeline network infrastructure is a network-based natural monopoly, and although the Measures for the Supervision and Administration includes information disclosure and spare capacity, which are key factors affecting fair access, as systematic requirements, there are still problems such as sloppy requirements, lack of content and insufficient timeliness.

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Information disclosure involves various aspects such as operation status and conditions of pipeline network, service content, service charges, government regulation and enforcement, which are important influencing factors to determine the possibility and activeness of third-party access. At present, the phenomenon of inadequate, untimely and excessive secrecy of information disclosure is prominent, which is far from the fair opening of a large platform. Some of the information that should be disclosed is only reported to the National Energy Administration and its dispatching agencies, and is only disclosed to upstream and downstream users who apply for it, and upstream and downstream users who accept the information also need to bear the responsibility of confidentiality. The existing frequency of information disclosure by year, quarter and month cannot meet the demand of third parties to book services in real time according to market changes, especially during the window period of imported LNG receiving stations, which is sensitive to changes in market situation. The timeliness and frequency of information disclosure is one of the reasons that affects whether third parties can perform smoothly in practice. The standardization and completeness of information disclosure parameters also need to be improved (Zhang 2021). For example, regarding the design capacity, design working gas volume, and design gas injection (extraction) capacity of gas storage, the developed capacity, working gas volume, and gas injection (extraction) capacity are the basic parameters to understand a gas storage. The public information only includes design capacity, and the public data does not distinguish between the design parameters and the actual working capacity, and the statistical caliber is inconsistent. Important parameters reflecting the capacity of gas storage reservoirs, such as actual gas injection and recovery volumes and cyclical injection and recovery dynamic data of historical operations, are usually not publicly available. The allocation of priority utilization capacity of the pipeline network is not transparent, and the criteria for measuring spare capacity are not in place. Information on capacity allocation rules, allocation results and execution of priority service recipients are not made public, affecting market confidence. In April 2020, the National Energy Administration published the Notice on spare capacity Measurement of Oil and Gas Pipeline Network Facilities (Draft for Comments), which sought public comments on the principles and procedures for spare capacity measurement of pipelines, LNG receiving stations and gas storage, but the official conclusions were not made public. The spare capacity varies greatly with the measurement method. Under the current situation of insufficient overall infrastructure in China, once the market environment is better and gas demand grows and the demand for open pipeline network infrastructure capacity increases, the concern of all interested parties about the transparency of the calculation and allocation of spare capacity will further increase, and more questions will arise about whether the opening to third parties is open, fair and equitable.

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Supervision System Construction Needs to be Strengthened China has an integrated model of energy governance and energy regulation. The level of development of the regulatory system matches the stage of construction and development of the natural gas market system. In the context that the energy regulatory system is still in the process of development and the reform of the pipeline system is still in a transitional stage, there is much room for improvement in the regulation of pipeline infrastructure. The regulatory basis and regulatory content of the natural gas pipeline network infrastructure is still imperfect, while the natural gas regulations are not at a high level and have limited effectiveness. There is no single law on natural gas, nor are there laws and regulations such as natural gas management regulations and natural gas regulatory regulations. The basis for natural gas regulation is scattered in laws, regulations and regulatory documents at different levels, without relevance, comprehensiveness and convergence. The regulation of pipeline network infrastructure is still in its initial stage, and is focused on fair opening and information disclosure, service price management and cost monitoring, which are not in-depth and comprehensive enough, and there is little regulation of operational behavior. A regulatory system with clear responsibilities, efficient operation and strong law enforcement has not yet been formed (Wang 2018). Regulatory functions are scattered and intertwined, interdepartmental communication and collaboration and information sharing is insufficient, so the cost of coordination is high. It is difficult to form a regulatory synergy, which can easily lead to unclear regulatory boundaries and regulatory deficiencies. Vertically, the regulatory responsibilities at different levels overlap, and the regular information sharing and regulatory collaboration is not effective. From the staffing and funding of regulatory agencies and professional capacity, to the scientific and refined level of regulation, to the means of regulation and deterrence, all need to be improved. There are few ways to allow the public, trade associations, news media and other third parties to implement supervision, which makes it difficult for them to play their role.

The Integration of Provincial Network into the National Management Network Needs to be Deepened The Implementation Opinions on the Reform of the Operation Mechanism of Oil and Gas Pipeline Network put forward the principle of integrating provincial pipeline networks into PipeChina in a market-oriented manner. In practice, the key to promoting integration is to balance the interests of both sides and to find the maximum convention between the interests of localities and PipeChina through market-based negotiations and games. Due to the different levels of industry development and resource development in each province, the specific demands vary greatly. Further

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integration of the provincial network into the national network requires coordination of the interests of all parties. There are local concerns about the security of natural gas supply in the provinces. PipeChina is only responsible for natural gas transmission and storage, and undertakes pipeline transmission coordination and supply assurance in emergency situations. Localities need to take responsibility for the security of natural gas supply within their provinces and therefore need to raise their own natural gas resources and need to have their own infrastructure under their control to meet local needs for supply assurance. The integration of the provincial network into PipeChina reduces local autonomy in the use of provincial pipeline infrastructure, requiring them to compete in a wider range of allocations and making them lose the initiative to secure supply. The integration of provincial networks involves the allocation of benefits such as taxation. The provincial network is a product of local economic development, and one of the purposes of local support for the construction of provincial networks is to support and promote local economic development and improve local livelihoods with the natural gas industry. Some localities are highly developed in terms of resources, pipeline network and consumer markets and wish to achieve intraprovincial circulation, so they are not willing to integrate into PipeChina; some localities are rich in local resources and wish to independently operate the provincial pipeline network to achieve local supply of resources and keep the lower-cost domestic onshore gas resources for local consumption; and some other localities are resource-poor or capital-poor and wish to integrate into the national network as a whole as soon as possible in order to obtain capital and asset investment and support in order to enhance local gas and economic development. Localities and PipeChina have different expectations for the main body of pipeline planning and construction in the province. PipeChina expects to be the sole entity for the planning and construction of provincial trunk and branch pipelines, and to obtain exclusive management rights; while localities hope to speed up the construction, expand the coverage and reduce the transportation cost of intra-provincial pipelines. The localities, as the approved party for planning and investing in the construction of provincial pipeline infrastructure, hope to meet the demand for investment and construction of new pipelines through competition among market players.

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Suggestions on Institutional Mechanism Reform of Natural Gas Pipeline Infrastructure in China Accelerate the Upgrading of Natural Gas Infrastructure Capacity The system of domestic natural gas pipeline infrastructure has formed its basic pattern, and the problem of insufficient investment and construction that emerged in the early stage due to unstable reform expectations has been resolved. The next step is to accelerate the opening up of the upstream exploration and development market, and innovate the system and mechanism to activate domestic gas development potential and enhance domestic capacity to secure resource supply by analyzing the effectiveness and shortcomings of the existing reform policies; at the same time, to increase the subjects participating in imported pipeline gas cooperation and enrich the LNG import cooperation model under the premise of ensuring orderly external cooperation, and drive the construction of domestic pipeline infrastructure by diversifying domestic production and expanding international cooperation. A new plan for the development of the national pipeline network infrastructure should be developed and published. The existing pipeline network plan should be revised and improved, and a new national infrastructure development plan should be publicly released. Such plans should serve as a coordinated guide for internal planning by various corporate entities and localities to address key issues that locally impede the flow of natural gas, such as interconnection between pipelines, imported LNG receiving stations and storage depots of different entities, and interconnection between trunk lines and branch lines, and to address the construction of intensive national reserve capacity, which will avoid the waste of resources caused by overlapping small-scale low-level construction needs. The timely publication of national infrastructure planning is critical to guide the long-term expectation of natural gas market development, and will help increase the proportion of third-party access for incremental users and long-term capacity reservation and promote the development of natural gas industry. Non-discriminatory and fair treatment shall be maintained in all aspects of project application and approval. According to the Catalog of Investment Projects Subject to Government Confirmation (2016), the Catalog of Administrative Examination and Approval Items Issued by the National Development and Reform Commission and the Measures for the Administration of Natural Gas Infrastructure Construction and Operation (2014), China implements hierarchical overall planning and management of the pipeline infrastructure, and implements hierarchical approval system for investment in construction projects. Construction of new infrastructure should be put into planning first. Given the serious shortage of domestic pipeline networks and storage facilities, although PipeChina is the main force in construction, it should not exclude and restrict other market players from participating in investment, construction and operation. Other market players can participate in new projects of PipeChina, or

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they can independently invest, build and operate storage and transportation facilities according to market demand while observing the principles of compliance with the national unified planning, interconnection with the national network and nonparticipation in gas purchase and sale (Bai 2021). Incentive-based pricing mechanisms and corporate performance management should be used to motivate pipeline operators to accelerate investment and construction of infrastructure.

Improve the Detailed Rules for the Operation and Scheduling of Pipeline Network In view of the attributes of the public welfare platform of the pipeline network, the access criteria for shippers and the rules for capacity service allocation should be introduced as soon as possible under the principles of fairness, openness and transparency. Detailed management measures for unbalanced gas borrowing (gas storage) services should be formulated to clarify the criteria or basis for the provision of unbalanced gas borrowing services by pipeline network operators to shippers, and to clarify independent accounting for the costs of unbalanced gas borrowing (gas storage) services provided. The reasonable allocation of existing capacity and incremental capacity shall be properly handled. The current allocation of existing capacity should be maintained, while the incremental capacity should be open to all users in a fair manner. With the enhanced marketization, the space of pipe capacity should be released by continuously reducing the proportion of existing capacity. The rules of pipeline openings should be formulated as soon as possible. Opening rules should be formulated by government departments, and the authority to approve openings should be vested in pipeline operators, subject to the supervision of all relevant parties and society. A detailed approach to the management of national natural gas emergency reserves should be developed. The conditions for activating the emergency supply plan should be clarified, specifying the interfaces of daily gas supply, seasonal peak shaving and emergency supply, including parameters such as the amount of reserve resources for emergency supply, the amount of resources participating in national unified dispatch, the target and priority of emergency supply, and the range of pipeline pressure. It should further improve the details of the responsibilities of and measures to be taken by relevant government departments at all levels, gas supply enterprises, pipeline transport enterprises and different types of users when starting emergency supply assurance plans. The criteria for quantifying national and regional supply-demand imbalances should be further clarified. Only when several quantitative indicators such as expected gap ratio, expected gap duration, and impact scope and degree exceed the prescribed tolerance level, emergency supply can be activated, in order to avoid arbitrarily escalating the general gap to emergency supply, thus interfering with the spontaneous guiding and regulating functions of the market mechanism.

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Establish a “National Network” Supporting Interconnection and Separation of Transportation and Sales Provincial pipeline networks should continue to be encouraged to integrate with PipeChina. For provincial pipeline networks that are difficult to be fully integrated in the short term, they should be required to implement the separation of transportation and sales, and strengthen the supervision of their production and operation, fair opening of spare capacity, information disclosure and other aspects with reference to the supervision of PipeChina’s networks. The cost monitoring and pricing management of provincial pipeline networks should be strengthened in accordance with the basic principles of pricing set by the central government to ensure that their charges are fair, reasonable, open and transparent. Provincial pipeline networks must be interconnected with national pipeline networks, and when there is a need for national emergency supply, the joint supply should be implemented based on the principle of subordination of lower level to higher level.

Leverage the Pricing Reform of Pipeline Transmission Services with Regional Pilots It is recommended to pilot pipeline pricing reform in some regions in the Central and East China. Based on the results of the implementation of the regional one-part freight rate and the integration of the existing pipeline networks and the layout of new pipelines by PipeChina, some regions with high density of pipeline network, high level of interconnection and multiple paths should be selected in the Central and East China to carry out pilot reforms to improve the pricing mechanism (Chen et al. 2020). First, we should explore the design method of two-part freight rate in which service costs are recovered by “capacity charge + usage charge,” and reasonably determine the proportion of fixed costs and variable costs to be allocated to capacity charge and usage charge respectively, so as to implement different rates for non-interruptible and interruptible users, in order to stimulate path optimization by operators, encourage effective use of the pipe capacity by shippers, and avoid crosssubsidization to unbalanced users by balanced users. Second, the “stamp method” should be explored to design a pipeline pricing mechanism that applies the same price within the same network, in order to simplify the conditions of use and access barriers for pipeline transportation services and promote the free flow of resources. Third, energy metering pricing should be explored to accommodate the diversification of natural gas supply sources and supply entities and to fairly reflect the value of natural gas. Based on the effectiveness of the opening up of PipeChina’s LNG receiving stations and storage infrastructure services to third parties, a market-based reform of gas outlet prices should be piloted in some central and eastern regions of China where there are more incremental supply market players and diversified competition

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of gas sources is achieved. The amount of gas used for people’s livelihood should be approved based on accounting or audit reports, upstream and downstream purchase and sales contracts, and other relevant materials to achieve precise subsidies for gas use for people’s livelihood and market-based management of gas use for nonpeople’s livelihood, so as to improve the linkage mechanism between terminal sales prices and procurement costs and form regional market price benchmarks as early as possible (Yang et al. 2021). The pilots of pipeline pricing reform and opening up of outlet pricing can be carried out either in the same area or in different areas, simultaneously or step by step.

Improve the Regulatory System Centered on Information Disclosure and Fair Opening The regulatory requirements for information disclosure and fair opening should be enhanced to increase the operability of shippers’ access to pipeline network infrastructure (Zhang and Bai 2021). The transparency of information on pipeline network planning and investment, construction and operation, and pipeline capacity application and allocation should be enhanced simultaneously to ensure fair, just, and open access to and utilization of pipeline transportation services, as well as to improve the predictability of pipeline transportation costs and prices and pipeline transportation service development, thus guaranteeing that all market players can participate in fair competition. The content of information disclosure should be refined and standardized. First, the restrictions imposed on requests for access to information should be reduced so that information disclosure gradually becomes the norm and can be made public as much as possible. Companies should disclose their pipeline development and construction plans and shippers. Second, the names of all upstream and downstream gas points of each pipeline should be further disclosed, as well as the corresponding remaining capacity and the services that have been opened. Third, it is necessary to improve the coordination and unification of the existing disclosure channels in terms of basic information of operators, basic information of natural gas pipelines, information of services opened, space capacity of pipelines and pricing standards, so that shippers can clearly understand each pipeline and its company (or price zone), as well as the upstream and downstream gas points, service entities, service prices, and space capacity of each pipeline. Fourth, the frequency of information disclosure should be increased from the existing annual, quarterly, and monthly disclosure to weekly and daily, or even daytime updates of data such as actual load and download volumes, to meet the needs of shippers to book or adjust services in real time based on market opportunities. Fifth, the cycle of information disclosure should be extended and the practice of updating only the space capacity during the calendar year should be abolished, because the update must cover at least one full heating season. The

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space capacity can be updated on a rolling basis for the next 18 or 24 months or longer. Sixth, given the insufficient density of the pipeline network at this stage and the weakness of the storage link in the production-supply-storage-sales chain, consideration could be given to disclosing the space capacity of gas storage and their connected pipelines as a service package to ensure the effective use of the space capacity.

Allow Some Pipeline Network Infrastructure to Be Exempted from Opening to Third Parties The criteria for opening exemption of pipe network infrastructure should be formulated, and the approval authority for exemption should be clarified. Pipeline network infrastructure applying for full or partial exemption should have the corresponding conditions. First, their investment improves the security of natural gas supply; second, the exemption will not affect the overall competitive landscape of the natural gas market; third, it will not constrain the choice of users and consumers; and fourth, it will not affect the operation of other pipeline network infrastructures interconnected with it that is not exempt. For example, part of the storage depot capacity that is responsible for the safety of pipeline network operations, part of the storage capacity that is responsible for national strategic reserves, part of the storage capacity that is responsible for urban emergency supply, and part of the storage capacity of self-provided storage depot of upstream and downstream enterprises that are not connected to the pipeline system can apply for exemptions. The application procedure for exemption approval should be clarified. An operator that applies for exemption from opening pipe network infrastructure to a third party shall, at the stage of investment and construction, file an application with the approval department that has the power to examine and approve projects. Some projects may be exempted from the conditions of investment and construction when applying for investment and construction. The approving authority may approve, disapprove or conditionally approve, and infrastructure operators and users may apply for reconsideration of the decision of the approving authority. It is important to ensure that information on the results of the approval is publicly available, especially for infrastructure that enjoys partial capacity exemptions, in order to ensure that its capacity open to third parties is subject to strict regulation.

Increase the Adaptability of Infrastructures to “Dual Carbon” Development Metering and pricing schemes for natural gas energy and implementation methods should be in place as soon as possible. With the development of low-carbon gas,

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gas sources will become more and more diverse, and a comprehensive study is needed to develop calorific value standards for natural gas access into the grid, and to develop a unified range of calorific values based on the calorific value adaptation of infrastructure, so as to accelerate the progress of replacing from volumetric to calorific metering. At the same time, the conversion from volumetric to energy-based pricing should be implemented as soon as possible. Technical reserves should also be prepared in advance and the adaptability of pipeline infrastructure to low- and zero-carbon gas energy should be improved. Pipeline adaptability assessment for renewable gases such as biomass gas should be enhanced, and analysis studies on the adaptability of pipelines for hydrogen-enriched compressed natural gas should be added.

References Bai J (2021) Progress and prospect of market-oriented reform in natural gas industry. In: Fang C, Yongsheng M, Zhijun J (eds) Report on China’s petroleum, gas and new energy industry. China Economic Publishing House, Beijing, pp 179–199 Bai J, Zhang X (2021) Suggestions on improving the measures for the management of operation and dispatch of natural gas pipeline network facilities and emergency supply assurance (for trial implementation) (draft for comments). Nat Gas Ind 41(7):172–178 Chen X (2020) What does opening right mean for long-distance natural gas pipelines? [J/OL]. Energy Observer. http://www.chinacpc.com.cn/info/2020-08-02/topic_4370.html. Accessed 28 Aug 2022 Chen X, Yang L, Jing C et al (2020) Realizing the goal of “X+1+X” oil and gas reform through regional natural gas market construction. Int Pet Econ 28(6):10–18 CNPC (2021) Annual report for 2021 [EB/OL]. https://mp.weixin.qq.com/s/q2VSWyN8wFHx u2b99pYF0Q. https://vip.stock.finance.sina.com.cn/corp/view/vCB_AllBulle-tinDetail.php? stockid=601857&id=7950786. Accessed 28 Aug 2022 Department of Petroleum and Natural Gas of National Energy Administration, et al (2022) China natural gas development report. Petroleum Industry Press. Beijing Fu Z, Shan T, Yang Y et al (2020) Interoperability between LNG receiving station and gas pipeline network. Nat Gas Ind 40(7):97–105 Gao G (2020) Who owns the pipeline opening rights under the oil and gas pipeline network reform? [N/OL]. Economic Observer. https://mp.weixin.qq.com/s/Mh6Wq9KCfFTTTCfEv7 L0HA. Accessed 28 Aug 2022 Huang Y (2019) The national oil and gas pipeline network will be reformed in this way [EB/OL]. Energy Observer. Accessed 28 Aug 2022 Information Office of the State Council (2020) Graphic record of the press conference held by the information office of the state council on “Accelerating the Construction of an Energy Power and Ensuring Energy Security” [N/OL]. http://www.scio.gov.cn/xwfbh/xwbfbh/wqfbh/47673/ 48664/wz48666/Document/1727984/1727984.htm. Accessed 28 Aug 2022 Introduction to PipeChina [EB/OL]. https://www.pipechina.com.cn/gywm/jtjj.html. Accessed 28 Aug 2022 Oil Link (2020) An important breakthrough of PipeChina! The national network embarks on a new journey [EB/OL]. https://mp.weixin.qq.com/s/wUzgDIoWkW-h8kjwlWCNMuA. Accessed 28 Aug 2022

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PipeChina (2020) Make a bigger network, make a stronger center and make a greater company— PipeChina focuses on deepening the reform of oil and gas pipe network operation mechanism. [EB/OL]. https://mp.weixin.qq.com/s/ugzykegetlvrqu. Accessed 28 Aug 2022 PipeChina (2021) PipeChina released the social responsibility report 2021 [EB/OL]. https://www. pipechina.com.cn/xwdt/jtyw/4340.html. Accessed 31 Aug 2022 Wang J (2017) Introduction to government regulation economics. China Commerce and Trade Press, Beijing Wang J (2018) Research on modern energy supervision system and policy in China. China Social Sciences Press, Beijing Wang H (2020) Pipeline opening—who has the final say? [N/OL]. China Petrochem. http://www. chinacpc.com.cn/info/2020-08-02/topic_4370.html. Accessed 28 Aug 2022 Xu X (2020). How is the process of integrating provincial network into the national network? [EB/OL]. Energy News (2020-07-28). https://mp.weixin.qq.com/s/q2vswyn8wfhxu2b99pyf0q. Accessed 28 Aug 2022 Yang L, Chen X, Sun H et al (2021) Suggestions on path and pilot selection for China’s marketoriented reform in natural gas industry. Pet New Energy 6:10–18 Zhang X (2021) Information of three gas storages disclosed by PipeChina. Energy Observer 2:50–55 Zhang X, Bai J (2021) Analysis and suggestion on the influence of new pricing method of natural gas pipeline transportation. Int Pet Econ 29(7):15–20 Zhang X, Yang L (2022) Service pricing and impact of imported LNG receiving terminal in China [N/ OL]. Energy Observer. https://mp.weixin.qq.com/s/sV9DN-yTT_NdnIPeOYcNTQ. Accessed 25 Aug 2022 Zhang X, Zou G, Zhang J (2019) Chinese LNG receiving stations’ openness to third parties and its influence. Gas Heat 39(6):B08-B12

Xiongjun Zhang Senior Engineer, Master, graduated from China University of Petroleum (Beijing) in 2005. Currently, she is the Industry Research Director of Beijing Gas Group, mainly engaged in the policy research on natural gas market-oriented reform. Jun Bai Vice President, Beijing Gas Research Institute, mainly engaged in research on energy strategy, policy, economy, energy transition and international cooperation.

Chapter 12

Analysis and Suggestions on the Scenarios of Integrated Development Between Natural Gas and Other Energy Resources Under the Goals of Peaking Carbon Emissions and Achieving Carbon Neutrality Weiwei Wang, Hui Sun, and Lei Yang

Introduction Gas is an important part of energy consumption at urban terminals in China, and the gas industry has made great progress since the reform and opening up. From 1978 to 2020, the penetration rate of urban gas in China increased from 14.4 to 97.87%, and the population of gas users grew by more than 46 times, from 11.084 million to 526.1727 million (Ministry of Housing and Urban–Rural Development of the People’s Republic of China 2020). Gas is used in many industries such as residents’ cooking, heating, industrial fuel, power generation, transportation, chemical raw materials, etc. The main sources of gas has gradually evolved from a 60/40 split between LPG and manufactured gas to an 80/22 split between natural gas and LPG. After China put forward the goals of peaking carbon emissions and achieving carbon neutrality, green and high efficiency became the development direction of China’s energy system. Gas is clean, low-carbon, flexible and has a wide range of application scenarios, which determines that it will inevitably play a key supporting role in building an energy system. The Plan for Modern Energy System During the 14th Five-Year Plan Period issued by the National Development and Reform Commission and the National Energy Administration puts forward that, by 2025, W. Wang (B) Institute of Energy, Peking University, Beijing, China e-mail: [email protected] H. Sun · L. Yang Unipec, Beijing, China © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_12

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the annual output of natural gas will reach more than 230 billion cubic meters. The Action Plan for Peaking Carbon Emissions in Industrial Sectors issued by the Ministry of Industry and Information Technology, the National Development and Reform Commission and the Ministry of Ecology and Environment requires: orderly guide natural gas consumption and reasonably guide the growth of industrial gas and gas for chemical raw materials; encourage enterprises and parks to use clean energy nearby. The Notice on the Collaborative Implementation Plan for Pollution Reduction, Carbon Reduction and Efficiency Improvement jointly issued by the Ministry of Ecology and Environment, the National Development and Reform Commission, the Ministry of Industry and Information Technology, the Ministry of Housing and Urban–Rural Development, the Ministry of Transport and the Ministry of Agriculture and Rural Affairs proposes to continue to promote clean heating in winter in the North China. Newly reconstructed and expanded industrial furnaces should use clean and low-carbon energy and optimize the use of natural gas in order to promote the replacement of industrial coal and agricultural coal with natural gas in an orderly manner. The Notice of Issuing the Plan for National Urban Infrastructure Construction During the 14th Five-Year Plan Period by the Ministry of Housing and Urban–Rural Development and the National Development and Reform Commission emphasizes expanding the application of natural gas in the fields of peak shaving of power generation, industrial furnaces and boilers, clean heating, distributed energy and transportation according to local conditions. In the future, gas will play a more far-reaching role in many fields such as urban energy, rural revitalization, industrial energy supply, etc., which requires giving full play to the respective endowments and advantages of traditional energy and new energy, innovating technologies and business models, improving market mechanism, and jointly promoting the high-quality development of China’s gas industry.

The Development Environment Faced by the Gas Industry Under the Goals of Peaking Carbon Emissions and Achieving Carbon Neutrality The New Landscape Facing the Development of the Industry Substitution of Electric Energy Is Accelerated, and the Proportion of Traditional Gas in the Terminal Energy Consumption Is Facing a Decline With the rapid development of renewable energy, the proportion of electric energy in terminal energy consumption will also increase greatly. In March 2022, the National Development and Reform Commission and other nine departments jointly promulgated the Guiding Opinions on Further Promoting the Substitution of Electric Energy,

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which proposed that the electrification level in key areas such as industry, transportation, construction, agriculture and rural areas should be continuously improved, and the proportion of electric energy in terminal energy consumption will increase from about 25% at present to about 30% in 2025. The development of gas industry will face the competition and cooperation with the substitution of electric energy. On the one hand, the substitution of electric energy will have an impact on the scale and speed of the incremental gas market, especially in new towns, urban–rural junctions and rural areas, which will face competition with electricity; on the other hand, with the in-depth implementation of the strategy of peaking carbon emissions and achieving carbon neutrality, the stock market may also face electric energy transformation and scale contraction.

The Interaction Between Energy Varieties Is Strengthened, and the Development Model of the Gas Industry Needs Innovation With the deepening of the energy consumption revolution, the interaction between energy varieties will be strengthened, and the integrated solution of multiple energy varieties will gradually replace the mode of separate planning, separate design and separate operation of each traditional energy variety, guided by the energy demand of end users. Especially with the gradual increase in the proportion of wind power and PV in energy consumption, the inherent instability, discontinuity and unpredictability of energy as well as the development mode of centralized + decentralized development and utilization will lead to the complementary and integrated development of multiple energy sources, and the interactive and integrated development of the consumption side and supply side will become inevitable. In this development context, the gas industry also needs to actively adapt to the general trend of energy development, continuously innovate business models and accelerate the promotion of industrial transformation and upgrading.

With the Continuous Emergence of New Gas Varieties, the Connotation of Gas Is Constantly Enriched Looking back at the history of gas development, we can see that the definition of gas is not static. From manufactured gas, LPG to natural gas, gas has evolved with the times and with the adjustment of the energy structure, and its connotation and extension have always kept pace with the times. In this new phase of history, the concept of gas continues to extend to low-carbon and carbon-free gases. In 2021, the International Gas Union (IGU) issued a position paper, clearly stating that renewable gas, hydrogen, decarbonized gas and low-carbon gas are all gas. Combined with the actual development of decarbonized and low-carbon gas energy in China, the new gas attracting a high degree of attention currently includes marsh gas, biogas, hydrogen, etc. Under the goals of peaking carbon emissions and achieving carbon neutrality, the

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gas industry should pay attention to the cultivation and development of new gas, so as to lay the foundation for further transformation and upgrading of the gas industry.

The Role of Gas in Building China’s Clean Energy System Natural Gas Is an Important Support in the Process of Carbon Reduction As a carbon-containing energy source under the goals of peaking carbon emissions and achieving carbon neutrality, traditional gas, especially natural gas as the main protagonist of gas, still plays an important role in the construction of a clean energy system. This paper argues that natural gas has two main advantages. First, the utilization of natural gas can significantly reduce the emissions of air pollutants and carbon dioxide at the same time, which has a significant synergistic effect in environmental governance and carbon emission reduction. According to statistics, compared with coal-fired power plants, gas-fired power plants reduce nitrogen oxide emissions by 26%, sulfur dioxide by 95% and soot by 64.3%. Coal-fired power plants emit twice as much CO2 as gas-fired power plants for the same amount of power generation. In terms of carbon emissions, coal-fired boilers are 56–68% higher than natural gas (Institute of Energy, Peking University, China Gas Association, et al 2021). According to foreign experience, natural gas is an important support for carbon reduction in developed countries. After achieving peak carbon in 2007, the US has entered a phase of rapid carbon dioxide reduction. The largest source of carbon reduction is natural gas, with a contribution of 40% (GE 2021). Second, natural gas is a highly efficient, flexible, and easily stored source of energy that can be used as a flexible power source in the construction of new power systems. For the same installed capacity of a single generator set, natural gas is usually the most efficient set for power generation. At the same time, natural gas generator sets are simple and fast to start and stop, with fast ramp rates, allowing them to adapt to a wide range of peak shaving needs on different time scales, such as hours, days, months, and seasons. In addition, with the popularization of technologies such as generator set of hydrogen-enriched compressed natural gas, hydrogen-fired generator set and CCUS, the extension of gas-fired power generation is also expanding, and atmospheric pollutants and carbon dioxide emissions are expected to be further reduced (Fig. 12.1).

Achieve Synergy Between the Scale Growth of Gas in the Near and Medium Term and the Long-Term Carbon Reduction In December 2021, the Central Economic Work Conference proposed that the gradual withdrawal of traditional energy sources should be based on the safe and reliable substitution of new energy sources, which is a reassurance for the development of the gas industry. On the one hand, from the perspective of economic and social

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development and urbanization, the trend of rapid development and scale expansion of the gas industry, especially natural gas, will not change in the next 10–15 years. It will remain a constant theme for the industry to maintain a moderate overdue construction of gas infrastructure and ensure a safe and stable supply of gas. On the other hand, after peaking carbon emissions and entering the carbon neutral stage, how traditional gas meets the demand for carbon reduction is also a challenge we must meet. This requires the gas industry to balance development and emission reduction, as well as the relationship between near- and medium-term needs and long-term goals, and to ensure smooth growth by controlling the pace of industry development, especially to avoid large losses in gas infrastructure and the consequent serious financial burden. The experience of European gas transmission and distribution companies shows that they have mainly done two things well. First, they have organized an assessment of the role of natural gas and gas infrastructures in achieving net-zero emissions for the entire European energy system by 2050; second, they have planned in advance for the transformation and development of infrastructure, and have actively explored business in areas such as pipeline transmission of hydrogen, hydrogen-enriched compressed natural gas, and biogas (Analysis of the Current Development and Trends of the Global Natural Gas Industry 2021).

Gas Development Momentum Remains Strong In the new development stage, around the strategies of peaking carbon emissions and achieving carbon neutrality, the gas industry should make great efforts to promote its innovative development of green and low-carbon transformation while ensuring energy security. First, we should promote the integration of gas and various energy sources through innovation. We should take advantage of the peak shaving of natural gas, combine different development models of new energy sources, explore the integration of natural gas with different energy sources, and promote the construction

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and implementation of pilot demonstration projects. Second, we will take the initiative to innovate and expand our diversified business system, and transform from pure gas supply to integrated energy supply. It should focus on how to accelerate the development of electricity, heat, cold and other energy products and services by taking natural gas distributed energy as the entry point and user demand as the guidance, explore the extension of comprehensive energy business, and transform from a single business model of natural gas sales to integrated and market-oriented operation. Third, we will vigorously cultivate the development of new gas and build a diversified gas supply system. New gas generally has the advantages of low carbon/ carbon-free, flexible layout and efficient operation, which is not only conducive to the formation of a point-based layout in the gas strategic map, but more importantly, it can increase the ability of the gas industry to adapt to the strategies of peaking carbon emissions and achieving carbon neutrality.

Analysis of Application Scenarios for the Integrated Development of Gas and Multiple Energy Sources Integrated Development of Natural Gas and New Energy As a clean, low-carbon and high-efficiency energy source, the integrated development of natural gas with new energy sources has become an important element in building a clean, low-carbon, safe and efficient modern energy system. On the side of energy production, natural gas power generation helps to achieve high level of new energy consumption and large-scale development of new energy; on the side of energy consumption, natural gas coupled with new energy constitutes a multi-energy complementary system to meet the energy demand of various application scenarios such as parks, buildings and data centers. In a comprehensive analysis, there are three main application modes for the integration of natural gas and new energy.

The Base-Type Integrated Development in Outbound Mode Designed to Match the Construction of Wind Power and PV Bases in Northeast China, Northern North China and Northwest China In recent years, China’s renewable energy has developed rapidly, but the shortcomings and problems such as insufficient flexibility and regulation ability of power system are outstanding, which restrict the development of renewable energy with a higher proportion and larger scale. Therefore, the national and local authorities have listed gas and electricity as an important peak-shaving resource in accordance with the relevant requirements for the construction of energy production-supply-storagesales system and the consumption of renewable energy. In 2021, the National Development and Reform Commission and the National Energy Administration issued

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the Notice on Encouraging Renewable Energy Power Generators to Build or Buy Peak Shaving Capacity to Increase the Scale of Grid Connection, which encourages multi-channels to increase peak-shaving resources, including pumped-storage hydroelectric plant, chemical energy storage and other new energy storage facilities, gas-fired power stations, photo-thermal power stations, coal-fired power stations with flexible manufacturing and transformation, etc. The Plan of Qinghai Province fir Energy Development During the 14th Five-Year Plan Period lists gas and electricity as resources for the key projects of power peak shaving, and proposes that a three-million-kilowatt gas-fired power station with peak shaving capacity will be built in Qinghai during the period. The participation of gas and electricity in peak shaving can alleviate the problem of large peak-valley difference in the power grid at different times and make up for the lack of hydraulic peak shaving capacity during dry periods. Compared with peak shaving by coal-fired generator set, the response rate is faster and the adjustment is more flexible. The CPV Sentinel gas-fired peak shaving plant in the United States, for example, consists of eight gas-fired generator sets with a total installed capacity of 800 MW. With its fast response, high availability and reliability, low starting power, and environmental friendliness, the gas-fired engine provides flexible peak shaving support for a large wind farm with a total installed capacity of 900 MW near the Coachella Valley in California.

The Ocean-Type Integrated Development in Consumption Mode Designed to Complement the Development of Offshore Wind Power in Coastal Areas China’s coastal areas are rich in offshore wind power resources and have great development potential. In terms of capacity scale, in 2021, the newly installed capacity was 14.482 million kW, up by 276.7% year-on-year. By the end of 2021, the cumulative installed capacity reached 25.352 million kW (CWEA 2021), ranking first in the world. In terms of regional layout, Jiangsu, Guangdong, Fujian, Zhejiang, Liaoning and other provinces have achieved a million kW of installed capacity. According to the forecast of many institutions, the installed capacity of offshore wind power in China will reach 55–65 GW by the end of the 14th Five-Year Plan period (Shanghai Securities News 2022). In Jiangsu Province, for example, which has a good industrial base and obvious resource advantages, it is proposed to build an “offshore Three Gorges base”, i.e., 15 million kW of offshore wind power capacity will be built by the end of 2025 (Jiangsu Provincial Energy Bureau 2022). In order to solve the problems existing in the current offshore wind power configuration, such as scattered distribution, low capacity and consumption issues caused by output characteristics, the Jiangsu Provincial Development and Reform Commission clearly requires that enterprises investing in offshore wind power projects in the province should have peak-shaving power sources such as gas and electricity, and the peak-shaving capacity has become an important content in the scoring standard for competitive configuration of projects. Offshore wind power also has the characteristics of volatility and

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randomness. From the perspective of power consumption, the system shows diversity and difficulty in peak shaving; and the load shows seasonal characteristics of low in winter and high in summer, and the peak-valley difference is lower on typical summer days than on typical winter days, i.e., the problem of offshore wind power consumption is more complicated in winter than in summer (Li 2019). In order to meet the demand of peak shaving in offshore wind power plant operation, it is necessary to design a peak shaving power supply with a considerable capacity according to local conditions. Considering the distribution of natural resources and the characteristics of peak shaving power supply, the natural gas generator with quick start, flexible operation, fast output adjustment, wide adjustment range, environmental friendliness and low carbon emission is a suitable choice. At the same time, natural gas can not only promote the peak shaving and consumption of offshore wind power, but also participate in the construction of a multi-industry coordinated development system at sea to promote the coordinated development of wind power, PV power and energy storage.

The Park-Type Integrated Development in Service Mode Aiming at Multi-energy Complementary and Comprehensive Energy Supply in Industrial Parks This mode is based on the park, with gas distributed energy station as the core, bringing together distributed PV, decentralized wind power, waste heat recovery, ground source heat pump, air source heat pump, sewage source heat pump, intelligent micro-grid, energy storage and other clean energy supply technologies to provide electricity, heat, cooling, gas and other energy products. On the one hand, relying on information technology such as energy Internet, big data and cloud service platform to carry out intelligent management of regional energy, it can realize the complementary cooperation of various energy categories and the organic source-network-loadstorage interaction. On the other hand, it can organically connect comprehensive smart energy service industries such as clean energy supply, energy-saving transformation and energy efficiency service in series, and realize the mutually beneficial and win–win development of natural gas with multiple energy sources and multiple industries. For example, Beijing Sub-center 6# Energy Station is located in Hugezhuang, Lucheng Town, Tongzhou District, with an energy supply coverage of about 566,000 square meters. The project adopts the multi-energy coupling technology route, organically integrating the systems of gas distributed energy, ground source heat pumps, water storage, electric refrigeration, boilers and municipal heating, which embodies the concepts of energy saving, low carbon, smart city, safety and economy. The energy station shows good energy saving and environmental benefits. In terms of energy efficiency, the energy consumption evaluation index (cooling) EER exceeds 4.4, the system efficiency exceeds 3, and the energy saving rate reaches 35%; in terms of emission, it can achieve zero emission of solid waste, soot and sulfur dioxide, reduce carbon dioxide emission by more than 60%, and nitrogen oxide emission by

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95%. The comprehensive utilization of natural gas and renewable energy is realized through the integration of distributed energy, heat pump, solar power generation, cold storage and heat storage, intelligent network and other technologies. According to the different requirements of short-term, medium-term and long-term energy planning, the three basic links of energy prediction, energy balance and energy optimization are organically combined to realize the comprehensive balance and coordinated development of economy, energy, environment and ecology (Natural Gas Distributed Energy 2022).

Integrated Development of Natural Gas and Hydrogen Energy Hydrogen energy has the advantages of cleanness, high efficiency and diverse application scenarios. It is a bridge connecting traditional fossil energy and renewable energy, so that it has attracted much attention and has high hopes from the gas industry a new gas. Under the goals of peaking carbon emissions and achieving carbon neutrality, it is crucial to deepen the integrated development of natural gas and hydrogen energy, explore decarbonization scenarios and continuously improve the value of the industrial chain. According to the development experience at home and abroad, the application scenarios of the integrated development of hydrogen energy and natural gas mainly focus on three aspects: hydrogen-enriched compressed natural gas, hydrogen storage and hydrogen energy distribution.

Hydrogen-Enriched Compressed Natural Gas Hydrogen can be injected into natural gas network in a certain proportion, and hydrogen-enriched compressed natural gas can be directly delivered to factories, residential and commercial users, or supplied to factories and hydrogen refueling stations after separation and purification. From the perspective of energy storage and transportation, the development of hydrogen-enriched compressed natural gas not only realizes long-term storage and long-distance transportation of electricity from renewable energy sources, but also realizes large-scale storage and efficient and low-cost transportation of hydrogen energy, and promotes the optimal allocation of heterogeneous energy across regions and seasons. From the point of view of energy production and supply, hydrogen-enriched compressed natural gas can alleviate the pressure of natural gas supply, and also help to realize deep decarbonization in industries, buildings and other fields. Developed countries and regions such as Germany, France, the United States all believe that transforming natural gas infrastructure into hydrogen energy infrastructure is an important measure to break the bottleneck of hydrogen energy transportation and promote the development of hydrogen energy economy. In terms of technical standards, the technology of long-distance hydrogen pipeline is relatively mature around the world, and the corresponding design standards and specifications

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are also comprehensively studied, such as American ASMEB31.12-2019. In terms of demonstration project construction, in 2019, Snam conducted a trial of blending 5% of hydrogen into natural gas pipelines and then increased the proportion to 10%, while the HyBlend project in the United States evaluated the compatibility of natural gas pipes and operations with hydrogen under long-term use conditions (Zhong et al. 2022). The development of hydrogen-enriched compressed natural gas in China is also improving day by day. The Medium- and Long-term Plan for the Development of Hydrogen Energy Industry (2021–2035) and other documents suggest that the safety, reliability, economy, adaptability and integrity of pipelines and key transportation equipment for hydrogen-enriched compressed natural gas should be evaluated, and efficient hydrogen transportation methods such as transportation via gas pipelines should be explored, and pilot demonstrations should be carried out to gradually build a low-cost diversified hydrogen energy storage and transportation system. For instance, the demonstration project of hydrogen blending in natural gas pipeline of SPIC, undertaken by Chaoyang Yanshan Lake Power Generation Co., Ltd., has entered the trial phase. The project that passed the trial will build a hydrogen production line producing 1000 cubic meters per hour to provide industrial and residential green hydrogen energy to Chaoyang City. Cities such as Baicheng City in Jilin Province, Chengdu City in Sichuan Province, Wuhai City in Inner Mongolia Autonomous Region and Lu’an City in Anhui Province have also proposed the strategy of hydrogen blending in natural gas in their hydrogen energy planning.

Hydrogen Storage Hydrogen energy storage takes hydrogen energy as a medium, and its core is to realize the energy conversion process of renewable energy generation-hydrogen production by water electrolysis-hydrogen fuel cell generation by using the reciprocity of electricity-hydrogen-electricity, thus effectively solving the fluctuation and intermittence of renewable energy and achieving peak shaving in power grid. Hydrogen storage technology has the advantages of large scale, long cycle, inter-seasonal storage, etc. It can explore the demonstration of hydrogen storage in the application scenarios of renewable energy consumption and grid peak shaving, establish a new model of “PV-wind power generation + hydrogen storage,” and gradually integrate hydrogen storage into the energy storage system integrating pumped storage, electrochemical energy storage and other technologies. The MYRTE project invested and built by France in Corsica is equipped with 560 kW PV power generation equipment, which processes the power exceeding the predicted output with 50 kW water electrolysis device to produce hydrogen and oxygen, and store them in gas storage tanks respectively. The project is gridconnected, with a 100 kW solid polymer fuel cell generating hydrogen and oxygen when the PV output is insufficient. Waste heat from electrolysis and fuel cell power generation is used for warm water recovery and stored in a warm water tank. The project achieves a combined efficiency of 70–80%, and realizes the organic

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combination of PV power generation and hydrogen storage. From the development requirements of building a new type of power system, hydrogen energy storage can reduce power abandonment and smooth out fluctuations on the power generation side; provide peak shaving capacity for grid operation and relieve transmission line blockage on the grid side; and participate in power demand response and become an emergency backup power source on the power consumption side (Xu and Liu 2022).

Hydrogen Energy Distribution Hydrogen energy distribution system has the advantages of strong modularity, good adaptability, good scalability, low emission and low noise, can be applied to household distributed cogeneration systems and small- and medium-sized distributed power stations. The project of household fuel cell Ene-Farm in Japan is a typical demonstration project of distributed power generation system for micro fuel cell. Using the cogeneration model, the system currently has a combined efficiency of over 95%, with 700 W of power to basically meet 60–90% of the electricity consumption of a typical household. In addition to household micro-systems, Japan has also started the application of distributed hydrogen energy in the field of commercial buildings, and Panasonic has released a 5 kW hydrogen fuel cell power system based on PEMFC, with an electric efficiency of 57% (Zhong 2021). Most of the hydrogen energy development models in China rely on hydrogen energy industry clusters to promote the development of hydrogen energy distributed energy. Guided by building a hydrogen energy industry cluster, we will focus on the simultaneous development of upstream and downstream of the hydrogen energy industry from preparation, storage, transportation to application. First, we establish a clean and low-cost hydrogen supply pool; second, we build a hydrogen energy storage and transportation network; third, we strengthen the demonstration and promotion of hydrogen energy application gradually, from fuel cell-driven vehicles to the application demonstration in distributed hydrogen energy and other fields. In this way, we can realize the interaction and synergistic development of key links in the industry chain, such as hydrogen production equipment, hydrogen storage and transportation equipment, hydrogen fuel cell system, and hydrogen energy vehicles.

Integrated Development of Natural Gas and Biogas Biogas is a green, low-carbon, clean and renewable natural gas produced by anaerobic fermentation and purification process using various types of urban and rural organic waste such as crop straw, livestock manure, kitchen waste and wastewater generated from agricultural and by-product processing as raw materials. As a part of new gas, biogas can not only optimize the supply structure of natural gas, but also provide the low-carbon development capability of natural gas. In 2019, the Guiding Opinions on Promoting the Industrialization of Biogas jointly issued by the National Development

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and Reform Commission and other nine ministries and commissions proposed that the annual output of biogas would exceed 10 billion cubic meters in 2025 and 20 billion cubic meters in 2030. The methane content in biological natural gas is above 95%, which has the natural advantage of integrating with conventional natural gas. Generally speaking, there are two main integration modes. One is point-based integration, that is, building a biogas factory according to local conditions, using biogas as the supply source of natural gas and connecting it to the town-level gas pipeline network nearby. The other is net-based integration, that is, building a distributed energy system of biogas. In order to use biogas as a source of supplying gas to rural areas, we collect, process and transform raw materials locally in rural areas, supply energy nearby, and develop distributed energy supply systems for farmers or entire villages by combining with distributed PV power generation and decentralized wind power systems to meet farmers’ needs for gas, electricity, heat, etc. At present, China’s biogas industry is still in the early stage of development. The state has successively supported the construction of 64 large-scale biogas projects and more than 1,400 large-scale marsh gas projects, but due to the shortage of raw materials, environmental protection requirements, poor sales and other reasons, most of them have made slow progress and poor operation. The gas industry should strengthen the research and development of related technologies, innovate the business cooperation mode, and promote the development and growth of biogas as soon as possible.

Suggestions on the Integrated Development of Gas and Various Energy Sources Firm Confidence in Industry Development In recent years, the ability of natural gas as a resource to maintain supply has always been one of the focal points of concern for all sectors of society. In particular, the gas shortage in the winter of 2017 intensified the doubts about the gas supply capacity from all walks of life, and then spread to concerns about energy security. The swing of industry confidence has hindered the realization of natural gas development goals to a certain extent. The influence in the field of gas utilization is more prominent, such as the specific development direction is somewhat vague, and there are problems of insufficient coordination and unification. Under the new development goals, the gas industry will remain in an important strategic opportunity period for the next 10–15 years, and should develop with confidence and give full play to the key supporting role of gas in the modern energy system. The industry as a whole should refine the industrial development and deployment according to the established goals, and strive to build a business sector with competitive advantages in cost and scale; create a gas supply security system; rationalize

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the prices of all links in the industrial chain based on the risks and benefits. Multiple measures should be taken to improve the competitiveness of the industry, and efforts should be made to build a new pattern of integrated development of natural gas and multiple energy sources under the modern energy system.

Strengthen the Construction of Market Mechanism There are problems in the integrated development of gas and new energy such as poor cost channeling mechanism, imperfect compensation for auxiliary services, and unbroken industry barriers. We should improve the market-oriented energy price system and energy use right trading system, and provide the competitiveness of the gas industry through market-oriented development. On the one hand, the power industry should speed up the cultivation and development of independent market players in the distribution of electricity, and improve the connection mechanism between the medium and long-term market, the spot market and the auxiliary service market. It should improve the market-based pricing mechanism, develop a pricing model that reflects the low carbon and environmental protection value of gas and electricity, rationalize the transmission and distribution price structure through the coupling of the electricity market and the carbon trading market, and fully liberalize the pricing of electricity for competitive links. On the other hand, the gas industry should speed up the construction of a price trading center and promote the marketoriented reform of natural gas pricing. Through the construction and improvement of the electricity market, oil and gas market, carbon market, green certificate market, etc., the smooth flow of commodity factor resources in a wider scope should be promoted. A large national energy market with high efficiency and regulation, fair competition and full openness will become a solid foundation for the integrated development of gas and new energy.

Build a New Ecology of Industrial Development The traditional operation mode of the gas industry has many problems such as single business, low efficiency of production, sales, management and service, restricted cross-region operation, and decreasing growth of new customers year by year. A single business model can no longer meet the development trend of diversification, digitalization and cross-border coordination of production, operation, transmission and consumption modes in the energy industry under the goals of peaking carbon emissions and achieving carbon neutrality, with weak technology and business innovation. Under the new development goal, we should further innovate the business models and accelerate the construction of a new ecology of energy services. First, new user needs should be tapped. We should dig deeper into the new needs of energy use

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in the process of expanding our business field from gas supply to comprehensive energy services. Second, we should promote cross-border cooperation. We should carry out external cooperation in the upstream and downstream links of the industry chain, such as aggregated energy supply, energy services and equipment manufacturing. Third, we should create a new energy trading mechanism, building a digital trading platform, and shifting from the traditional monolithic energy supply mode to a mode of supplying diversified energy such as electricity, gas, cooling and heat and diversified value-added services.

Promote Technological Collaborative Innovation Technical progress is the driving force of development. At present, the technical problems that restrict the development of the industry mainly include the following three aspects. First, the lack of advanced energy technology and equipment leads to high project operation cost and poor investment income, which hinders the largescale development of the industry; second, the failure to achieve breakthroughs in key energy technologies has led to insufficient efficiency and reliability of the energy system and hindered industrial upgrading; third, the cross-integration of various technologies needs to be improved, and it is urgent to digitally improve the overall efficiency of the industry. Under the new development goal, it is necessary to establish a mechanism for technological collaborative innovation and development. It should focus on core technology research and development, optimize the cooperation system covering industry, academia, research; organize pilot demonstration projects and share development experience in a timely manner; improve the development of standard specifications and enhance the synergy level of standard governance effectiveness and technology iteration innovation.

Strengthen International Cooperation Natural gas is an important energy category in the green and low-carbon transformation of global energy. China should strengthen international cooperation to promote the political, technical and economic progress of the world gas industry and improve the competitiveness of gas energy in the global energy market. In particular, we should increase our participation in international governance in the field of natural gas, make good use of international platforms such as IGU (International Gas Union) and IEA (International Energy Agency), do a good job of our work as the IGU Chair (2022–2025) to strengthen international exchanges and promote the smooth development of the global gas market. In addition, we should jointly support the development of new technologies and skills in the gas field through academic exchanges, industry organizations, conferences and seminars.

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Conclusion Driven by the development goals of peaking carbon emissions and achieving carbon neutrality, the gas industry is facing opportunities and challenges of energy transformation and low-carbon development. We should fully understand the development advantages of the gas industry, firmly develop confidence, and deeply tap the value of the industrial chain, so as to vigorously promote the integrated development of gas and various energy sources and continuously improve the sustainable development capacity of the gas industry. First, we should promote the integration of natural gas with new energy sources such as wind power and PV, in order to promote the diversification of energy production and the comprehensive and intelligent innovation of the energy industry. Second, the connotation and extension of gas should be further enriched, and the integration with hydrogen, biogas and other energy sources should be promoted, so as to adapt to the new trend of diversified energy supply and enhance the flexible transformation of the energy system.

References Analysis of the Current Development and Trends of the Global Natural Gas Industry (2021) [EB/ OL]. https://mp.weixin.qq.com/s/ppudecftp4V705Q9R7FYG. Accessed 25 May 2022 CWEA (2021) Industry research department. Wind power industry map of China for 2021: offshore wind power installation [EB/OL]. https://mp.weixin.qq.com/s/jpl2mbulqdliqibipohlja. Accessed 1 Aug 2022 Institute of Energy, Peking University, China Gas Association et al (2021) Study on the role of natural gas in improving the atmospheric environment in China. Beijing GE (2021) Accelerated growth of renewables and gas power can rapidly change the trajectory on climate change, GE Jiangsu Provincial Energy Bureau (2022) Special plan for renewable energy development in Jiangsu province during the 14th five-year plan period (draft for comment) [EB/OL]. https://baijiahao. baidu.com/s?id=1688280353564752530&wfr=spider&for=pc. Accessed 25 May 2022 Li G (2019) Discussion on the output characteristics and consumption of offshore wind power. Telecom Power Technol 36(2):241–242 Ministry of Housing and Urban-Rural Development of the People’s Republic of China (2021) China urban construction statistical yearbook 2020. China Statistics Publishing House, Beijing, pp 34–42 Natural Gas Distributed Energy (2022) Exclusive case study: Beijing sub-center 6# Energy station [EB/OL]. https://mp.weixin.qq.com/s/P8HII37DF4JQCAURB8mPW. Accessed 1 Aug 2022 Shanghai Securities News (2022) The scale of offshore wind power operation in China is expected to reach about 60 GW by the end of the 14th five-year plan period [EB/OL]. https://finance.eas tmoney.com/a/20220715268696.html. Accessed 1 Aug 2022 Xu C, Liu J (2022) Application value, challenge and prospect of hydrogen energy storage in China’s new power system. Strat Study CAE 24(3):89–99 Zhong C (2021) Application status and prospect analysis of distributed fuel cell power generation in China and abroad. Energy China 2:34–37 Zhong B, Zhang X, Zhang B et al (2022) Study on the development of hydrogen-enriched compressed natural gas industry in China. Strat Study CAE 24(3):100–107

Chapter 13

Development Status and Prospect of Gas Distributed Energy Industry Yang Zhang, Xiqing Tang, Qingshan Meng, Weiwei Wang, and Wei Huang

Introduction Gas distributed energy uses gas as fuel and applies gas turbines, gas-fired internal combustion engines, micro-combustion engines and other generator sets and waste heat utilization equipment to provide users with various energy sources such as cooling, heat and electricity. It has multiple advantages such as energy saving, emission reduction, cost effectiveness, safety, peak shaving and valley filling. After years of practice, gas distributed energy has been applied in many places and application scenarios in China. With the deepening of reform, technological innovation and market development, the connotation and extension of gas distributed energy have been continuously enriched and expanded, which will play an important role in promoting low-carbon energy transformation, building a new power system and building a modern energy system in the future. With the goals of peaking carbon emissions and achieving carbon neutrality accelerating the transformation of energy structure, energy production is gradually changing to both centralized and decentralized, and the trend of decentralization, flattening and decentering is becoming more and more obvious. Distributed energy

Y. Zhang (B) Sunwise New Energy System (Shanghai) Co., Ltd, Shanghai, China X. Tang Shanghai Aerospace Smart Energy Technologies Co., Ltd, Shanghai, China Q. Meng China Gas Assosiation Distributed Energy Committee, Beijing, China W. Wang · W. Huang Institute of Energy, Peking University, Beijing, China © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_13

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has developed rapidly with its characteristics of low carbon, flexibility, decentralization, intelligence, and diversity, among which gas distributed energy is an important manifestation of distributed energy. The new development situation brings both opportunities and challenges to gas distributed energy. This paper aims to clarify the characteristics and conditions for the development of gas distributed energy through a review of the current status of gas distributed energy development. It further clarifies the development orientation, opportunities and challenges of the gas distributed energy industry under the background of peaking carbon emissions and achieving carbon neutrality, provides an outlook on the future development prospects, and proposes suggestions on promoting the rapid and highquality development of China’s gas distributed energy industry.

Development Status of Gas Distributed Energy Industry A variety of gases such as natural gas, biogas, and hydrogen can be used as gas distributed energy sources, of which natural gas distributed energy is an important approach and is currently the most developed in China. Therefore, this paper focuses on the development status of natural gas distributed energy.

Market Scale of Natural Gas Distributed Energy According to the incomplete statistics of the Distributed Energy Committee of China Gas Association, by the end of 2020, there were 632 natural gas distributed energy projects in China (single machine capacity less than or equal to 50 MW and total installed capacity less than 200 MW), with a total installed capacity of 22.74 million kW (Fig. 13.1). Especially since 2015, it has shown a rapid development trend, but there is still a big gap compared with the target of 50 million kW installed in cities above designated size in China in 2020, which is given in the Guiding Opinions of the National Development and Reform Commission on Developing Natural Gas Distributed Energy (2011). China’s natural gas distributed energy projects are mainly distributed in Beijing, Tianjin, Hebei, Shandong, Yangtze River Delta, Pearl River Delta, Sichuan and Chongqing, among which the Yangtze River Delta has the most projects, accounting for 30.7%; in terms of installed capacity, the Pearl River Delta ranks first, accounting for 25.4%. By type of power generation equipment, projects using natural gas-fired internal combustion engines, gas turbines and micro-combustion engines account for 44.8%, 48.1% and 7.1% of the total, respectively, and the installed capacity accounts for 10.7%, 88.8% and 0.5%, respectively (Figs. 13.2 and 13.3). The main application scenarios of gas distributed energy include industry, civil buildings and industrial parks, etc. The existing projects in descending order of proportion are: 48.6% for parks, 11.9% for industry, 11.9% for offices, 9.2% for

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2500

2000

1500

1000

500

0

2015

2018 2019 2020 Year Installed Capacity (10,000 kW)

2016 2017 Number of Projects

Fig. 13.1 General situation of natural gas distributed energy projects. Notes (1) North China includes: Beijing, Tianjin, Hebei, Shandong, Liaoning, Shanxi, Central Inner Mongolia, etc.; (2) Yangtze River Delta includes: Shanghai, Jiangsu, Zhejiang, Anhui, etc.; (3) Pearl River Delta includes: Guangzhou, Shenzhen, Foshan, Dongguan and other city groups; (4) Sichuan-Chongqing area includes: Sichuan, Chongqing, etc. 13.8%

20.3% 31.5%

23.4%

17.5% 14.2%

11.7% 11.4%

25.4%

30.7% Number of Projects North China Sichuan-Chongqing Area

Installed Capacity Yangtze River Delta Pearl River Delta Other Areas

Fig. 13.2 General situation of natural gas distributed energy projects in key areas (left: number of projects; right: installed capacity). Notes: (1) Since the installed capacity of external combustion engines and combined cycle steam turbines is not included in the table, the sum of installed capacity of the equipment is not exactly equal to the total installed capacity of the projects; (2) Since the number of equipment units cannot be determined for individual projects, the number of equipment items is incomplete

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10.7%

0.5%

48.1%

88.8%

44.8%

Number of Projects

Installed Capacity

Natural gas-fired internal combustion engines Gas turbines Micro-combustion engines

Fig. 13.3 Proportion of power equipment in distributed projects (left: number of projects; right: installed capacity)

hospitals, 6.8% for commercial complexes, 4.6% for data centers, 3.6% for hotels, and 3.5% for large public buildings; in order of installed capacity are: 84.7% for parks, 6.4% for industry, 3.2% for integrated commercial buildings, 2.6% for data centers, 1.4% for offices, 1.3% for large public buildings, 0.3% for hospitals, and 0.1% for hotels. As seen above, the development of gas distributed energy projects should be based on regional and scenario-specific analysis, taking into account user demand, resource conditions, policies and other factors (Table 13.1). The analysis of some of the projects in operation in China shows that the benefits of natural gas distributed energy are obvious in energy saving and emission Table 13.1 Natural gas distributed energy projects in key user markets Key user market

Number of projects

Proportion of project number (%)

Installed capacity (kW)

Proportion of installed capacity (%)

Park

307

48.6

19263261

84.7

Industry

75

11.9

1454190

6.4

Office building 75

11.9

319871

1.4

Hospital

58

9.2

76369

0.3

Commercial complexe

43

6.8

723883

3.2

Data center

29

4.6

593562

2.6

Hotel

22

3.6

23690

0.1

Large public building

22

3.5

286660

1.3

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reduction, and the projects have certain economic benefits under reasonable gas and electricity prices; the gas, electricity, cooling and heat prices vary greatly among different projects, especially the owners enjoy a strong autonomy in cooling and heat prices. Low pricing will affect the project economics, so it is recommended to employ the price linkage mechanism for gas, electricity, cooling and heating energy. The improvement of environmental protection requirements such as nitrogen oxide emissions will, to a certain extent, increase the initial investment and operation and maintenance costs of the project and reduce the project economy. With the integration of distributed energy and renewable energy, the installed capacity of the system is more flexible, the operation adjustment is more diversified, and the comprehensive energy utilization efficiency of the system is improved. Natural gas distributed energy projects put into operation in China are varied in characteristics, so the optimal operation strategy should be formulated according to local conditions, such as user demand, energy price and external factors.

Industrial Development Conditions Policy Environment Since 2014, national and local governments have started to explicitly incorporate gas distributed energy into one of the key tasks of institutional reform in the energy sector, and have issued a number of policies, regulations and guiding documents related, involving energy prices, mechanisms, market-oriented reforms, pilot application promotion, and equipment localization, which have played a positive role in promoting the development of gas distributed energy. For example, the relevant documents on power access require simplifying the process of grid connection procedures, providing convenient, timely and efficient access to grid services for distributed power generation, liberalizing the construction of distributed power on the user side, and establishing a new mechanism for the development of distributed power. Several local governments have announced special support measures. In addition to policy guidance, some regions have proposed certain energy price subsidies for distributed energy projects, giving corresponding economic subsidies in both the pre-project equipment investment and post-project operation. Shanghai, Changsha, Qingdao, Zhengzhou and other places have introduced policies to give government subsidies for natural gas distributed energy.

Gas Source Guarantee China’s natural gas supply pattern is characterized by west-to-east gas transmission, north-to-south gas transmission, from the sea to the land and nearby supply. During the 13th Five-Year Plan period, the total natural gas production was 813.7 billion cubic meters (see Fig. 13.4), an increase of 36.1% compared with that in the 12th

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Five-Year Plan period, an average annual growth rate of 8.56%. In 2021, natural gas production continued to grow steadily, reaching 205.3 billion cubic meters, an increase of 8.2% over the previous year, and an increase of over 10 billion cubic meters for five consecutive years. During the year, China imported 121.36 million tons of natural gas, an increase of 19.9% over the previous year, and consumed 367.1 billion cubic meters of natural gas, an increase of 12.7% over the previous year (Fig. 13.5). The external dependence of natural gas was 44.1%. According to the World and China Energy Outlook in 2060 (2021 Edition), China’s natural gas demand is projected to grow rapidly until 2040, peaking at nearly 650 billion cubic meters, and then decline steadily to about 410 billion cubic meters in 2060. With increased investment in exploration and development and technological 100 million cubic meters 3500 3000 2500 2000 1500 1000 500 0

2015

2016

2017 Production

2018

2019 2020 Import

Year

Fig. 13.4 Natural gas production and import in China from 2015 to 2021 % 25

100 million cubic meters 4000 3500

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3000 2500

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2000 10

1500 1000

5

500 0 2015

2016

2017

2018

2019

Apparent consumption

Fig. 13.5 Apparent consumption of natural gas from 2015 to 2021

2020

0 2021 Year

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advances in the oil and gas industry, China’s natural gas production is expected to grow faster, exceeding 250 billion cubic meters in 2030 and nearly 350 billion cubic meters in 2060, but there is still a large gap to be filled by imports. From the perspective of global/regional economic integration and external circulation, diversification of natural gas imports is an inevitable choice for China. China’s natural gas resources have huge exploration potential, natural gas production is steadily increasing, natural gas pipeline network construction tends to be improved, and the construction of LNG receiving stations, storage and other facilities is accelerated. This has formed a diversified supply system, and the construction of the productionsupply-storage-sales system has made effective progress, providing a gas source guarantee for the development of gas distributed energy. Moreover, with the increase of unconventional gas such as shale gas and coal-bed methane, biogas, hydrogen and other gas, more gas source options are provided for gas distributed energy.

Technical Standards and Specifications Since the National Energy Administration issued a plan to develop industry standards in the energy sector in 2009, the standards and regulations for the gas distributed industry have been gradually improved. As of December 2021, gas distributed energy has its own system design guidelines, engineering technical regulations, technical regulations for access to the grid, and regulations for commissioning, acceptance, and operation of energy stations. Although different standards are not compatible in part due to the different organizations that prepare them, the project design and construction requirements for gas distributed energy are becoming clearer with the gradual enrichment of technical regulations.

Technology Route and Core Equipment of Gas Distributed Energy Gas distributed energy system mainly consists of power generation equipment, waste heat boilers, absorption chillers and denitrification equipment. The distributed energy system can be divided into gas turbine-based system, gas-fired internal combustion engine-based system, and micro-combustion engine-based system according to the different power generation equipment. Since the micro-combustion engine-based systems are less used, this paper focuses on the analysis of distributed energy systems using gas turbine and gas-fired internal combustion engine.

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Natural gas-fired internal combustion engine Electric power output

Natural gas Flue gas

Waste heat boiler

Heat exchanger Jacket water

Hot water heating Steam heating

Lithium-bromide absorption unit Cooling and heating

Peak shaving equipment

Fig. 13.6 Gas-fired internal combustion engine + flue gas waste heat boiler + steam-operated absorption air conditioning unit + jacket water heat exchanger + peak shaving equipment

Distributed Energy System Using Gas-fired Internal Combustion Engine Typical Technical Process The waste heat sources of gas-fired internal combustion engines include hightemperature flue gas, cooling water for jacket water, and cooling water for lubricating oil. Depending on the waste heat equipment, the following typical processes can be selected: (1) gas-fired internal combustion engine + lithium bromide unit using waste heat; (2) gas-fired internal combustion engine + water—water heat exchanger + flue gas—water heat exchanger; (3) gas-fired internal combustion engine + lithium bromide unit using waste heat + water—water heat exchanger; (4) gas-fired internal combustion engine + waste heat boiler + heat exchanger; (5) gas-fired internal combustion engine + waste heat boiler + lithium bromide unit using hot water (see Fig. 13.6).

Core Equipment Gas-fired internal combustion engine generator sets are characterized by high power generation efficiency, multiple forms of waste heat utilization, strong fuel adaptability and operational flexibility. They are useful in small industrial user scenarios such as hospitals, hotels, public transportation hubs, commercial complexes, and data centers. At present, the power generation equipment used in such projects, both built and under construction, is still mainly imported, with the mainstream brands covering the power range of 20–10000 kW, including MWM, Caterpillar, Jenbacher, Waukesha, MTU, Cummins, Kawasaki, etc.

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The power of gas-fired internal combustion engines independently developed in China mainly ranges from 200 kW to 1000 kW, and some manufacturers have developed engines above 1000 kW, but almost all those above 2000 kW still need to be imported. At present, domestic gas-fired internal combustion engines have made breakthroughs in premixing mode before supercharging, supercharging and intercooling technology, lean combustion technology, magneto ignition, digital ignition, self-diagnosis and other technologies, and their applications in biogas, oil field associated gas, coke oven gas and other fields have fully verified that some performance indexes have reached the international advanced level. Domestic manufacturers engaged in research and development and manufacturing of gas-fired internal combustion engines mainly include CSIC 711, Liyu Group, Jichai, Huaqi Dongli, Weichai, Shengdong Group, Henan Diesel Engine, Zibo Diesel Engine, Guangzhou Diesel Engine, Shanghai Aerospace, etc., with traditional oil and gas engine manufacturers as the main force. The technology of gas-fired internal combustion engine is developing towards efficiency improvement, high altitude combustion, reduced lubricant consumption, compact structure and modularity, low carbon and zero carbon fuel, and zero pollutant emission. At present, domestic gas-fired internal combustion engines have made breakthroughs in premixing before gas pressurization, lean combustion technology with adjustable electric control on air-fuel ratio, high-energy ignition system with magneto ignition or digital ignition and electronic speed regulation, and program controller with networking and communication functions, with some main performance indexes having reached the international advanced level. However, there are still some technical problems to be overcome in long-life cycle raw materials, mechanical precision machining technology, turbocharging technology, adaptability of gas source change and so on.

Distributed Energy System Using Gas Turbine Typical Technical Process According to the different power generation methods and waste heat utilization forms, the cold-heat-electricity distributed energy system based on gas turbine can be divided into single-cycle power generation and gas-steam combined-cycle power generation. Common technical processes include: (1) gas turbine + waste heat boiler; (2) gas turbine + lithium bromide unit using waste heat; (3) gas turbine + waste heat boiler + lithium bromide unit using waste heat (see Fig. 13.7).

Core Equipment Gas turbine has the characteristics of high power generation, high voltage level, high exhaust temperature and simple waste heat utilization system. It is mainly used in process users, industrial parks, transportation hubs, regional energy centers, etc. At

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Electric power output Flue gas

Waste heat boiler

Steam heating Jacket water

Peak shaving equipment

Electric power output

Cooling and heating Lithium-bromide absorption unit

Fig. 13.7 Gas-steam combined-cycle system + absorption air conditioning unit + peak shaving equipment

present, almost all of the gas turbine-based distributed energy projects built and under construction use imported power generation equipment. The worldwide gas turbine market is mainly occupied by GE, Siemens Energy, MAN, Solar Turbines, Kawasaki, Mitsubishi Heavy Industries, Rolls-Royce, etc. and some Russian companies. China is still relatively weak in gas turbine research and development and production. Through the introduction of advanced technology and independent innovation, China has mastered the manufacturing technology and techniques of some advanced gas-fired power generation equipment. Domestic F-class gas turbines have achieved 80% to 90% of components from domestic manufacturers. There are three main types of domestic gas turbine manufacturers: those who cooperate with famous foreign brands through technology introduction and independent innovation, aero-engine manufacturers who carry out independent research and development and transformation, and manufacturers who engage in independent research and development and production of small and medium-sized industrial gas turbines. At present, the mainstream brands of gas turbine-based generator sets have covered the power range of 2 MW to 340 MW, while those applied in the field of gas distributed energy are mainly focused on the power range of 2 MW to 50 MW. The development direction of gas turbine includes advanced materials and manufacturing, design of gas turbine-based generator sets, improvement of component performance, high efficiency and clean combustion, research and development of high temperature materials, expansion of fuel range, hydrogen fuel-fired gas turbine, etc.

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Problems in the Development of Gas Distributed Energy Despite the greater progress of gas distributed energy, the developing gas distributed energy industry still faces many challenges due to the greater difficulties in securing gas sources, the long-term mechanism yet to be improved, the industry barriers more solid, and the technical means not advanced enough.

Industry Development Issues Foundation Guarantee for the Industry Still Needs to be Strengthened China’s natural gas market has a high degree of foreign dependence, high domestic development costs, high pipeline prices, high gas costs, lack of gas storage capacity, and great price fluctuations between low and high seasons, which put great pressure on the survival and development of gas distributed energy, so the foundation guarantee for industrial development still needs to be strengthened.

Development Space is Affected by Renewable Energy With the rapid growth of renewable energy in the energy structure, this has to some extent compressed the development window and development space of the gas industry.

Technical Issues The technical level of the industry still needs to be improved. There is still room for improvement in technical standards and systems. The domestic sets are still inferior to foreign ones in terms of automation management technology, power generation efficiency, high power and the technical level of the whole machine, core materials, heat treatment technology, high-precision processing, etc., and need to continuously improve the quality level of the host and supporting equipment. The professional level of operation and management needs to be continuously improved in terms of technology and management, so as to realize effective monitoring, management and optimization, and give full play to the advantages of energy saving and emission reduction of gas distributed energy and saving energy costs of customers.

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Mechanism Issues Industry Barriers Need to be Broken With the promotion of electricity marketization, the policy of gas distributed energy to participate in electricity market trading has encountered heavy obstacles in the formal promotion process, making it difficult to bring into play the advantages of unity of production and sales, which has the attributes of both power generation and electricity consumption and enables both buyers and sellers to profit from it.

There is a Lack of Cross-Sector Coordination Mechanisms Gas distributed energy spans many sectors such as oil and gas, electricity and heat, and it is difficult to adapt and coordinate the interests of different sectors, resulting in low enthusiasm and even resistance to the development of gas distributed energy from gas, grid and heat supply enterprises.

Market Issues The competitiveness of projects needs to be improved. In recent years, many gas distributed energy projects have failed to achieve the desired economic benefits due to various factors such as high initial investment, high operating costs, and unmet capacity, and the market tends to be cautious about investing in gas distributed energy. Under the imperfect electricity auxiliary service market and carbon market, the value of environmental protection, carbon reduction and flexibility has not yet emerged.

Prospect of Gas Distributed Energy Industry Forecast of the Development of Gas Distributed Energy In the near and medium term, gas distributed energy will give full play to its advantages of low carbon, stability and flexibility, provide support and guarantee for the construction of new energy system and the development of renewable energy, and promote technological innovation through the application of low carbon gas such as hydrogen energy and biogas. In the long run, gas distributed energy will also develop in the direction of using low-carbon gas and carbon capture, storage and utilization to help decarbonize the energy system.

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Table 13.2 Forecast of the development potential of natural gas distributed energy Forecast scenario

Low scenario

Year

2021–2025.

Medium scenario

High scenario

Average annual growth rate (%) Installed capacity in 2025 (10,000 kW)

5.7

9.7

13.6

3001

3605

Year

2025–2030

4297

Average annual growth rate (%) Installed capacity in 2030 (10,000 kW)

6.2

10.1

14.2

4050

5843

8363

Forecast of the Development of Natural Gas Distributed Energy According to Gas Distributed Energy Industry Report (2022) compiled by the Distributed Energy Committee of China Gas Association and Institute of Energy, Peking University, the development prospect of natural gas distributed energy is forecasted based on its development status. The total installed capacity of natural gas distributed energy in 2025 and 2030 is forecasted in low, medium and high scenarios, and the forecast results are shown in Table 13.2.

Forecast of the Development of Biogas Distributed Energy According to the Report of the Dual-carbon Development of the Biogas Industry in China issued by China Biogas Society, by 2030, the biogas production potential will be about 169 billion cubic meters, and the greenhouse gas emission reduction will be 300 million tons of CO2 equivalent. By 2060, the biogas production potential will be 371 billion cubic meters, with a GHG emission reduction of 660 million tons of CO2 equivalent, which is equivalent to replacing 68% of the national natural gas consumption in 2020, or more than 1.5 times the amount of natural gas imports in 2020. If they are all used for power generation, they could generate 742 billion kW-h of electricity, equivalent to nearly 10% of the national electricity consumption in 2020; if converted into energy, it would be equivalent to nearly 6% of the national energy consumption in 2020.

Forecast of the Development of Distributed Hydrogen Energy The White Paper on Hydrogen Energy and Fuel Cell Industry in China (2020) published by China Hydrogen Alliance predicts that the contribution of hydrogen and hydrogen-related fuels to China’s energy transformation will gradually increase from 2021 to 2060, especially after 2030. According to the white paper, in the "peak carbon emissions" scenario in 2030, the annual demand for hydrogen in China will reach 37.15 million tons, accounting for about 5% of the end-use energy consumption, and the production of renewable hydrogen will be about 5 million tons, with about 80

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GW of installed electrolytic cells deployed. In the context of "carbon neutrality" in 2060, the annual demand of hydrogen in China will increase to 130 million tons, accounting for about 20% of the end-use energy consumption. The industrial sector still uses the most hydrogen, about 77.94 million tons, accounting for 60% of the total hydrogen demand; the transportation sector uses 40.51 million tons, the construction sector uses 5.85 million tons, and the power generation and grid balance uses 6 million tons.

Trend of the Development of Gas Distributed Energy Optimization and Upgrading of Technology and Equipment to Promote the Innovative Integration of Gas Distributed Energy As the new round of technological revolution progresses, various technologies will continue to make innovative breakthroughs. The development of single technologies, multi-energy coupling technologies, and energy digitization technologies will provide richer technical means for gas distributed energy model and business model innovation. Gas distributed energy is upgrading from a single mode to a comprehensive and intelligent mode. Gas distributed energy equipment further develops towards high efficiency, emission friendliness, zero carbon and commercialization, fully stimulating the dual carbon potential of gas distributed energy. Depending on the continuous breakthrough in basic theory and key materials, individual technologies such as gas turbine are developing in the direction of higher efficiency and lower cost, effectively improving the economy of the project. The application of emerging digital technology has accelerated the organic integration of gas distributed energy and user-side services, promoted the synergy between supply and demand, and contributed to the innovative integration of gas distributed energy with renewable energy and finance.

Diversification of Gas Sources to Extend the Business Direction of Gas Distributed Energy The development of biomass energy and hydrogen energy has extended the new business direction of gas distributed energy and injected new gas source composition into gas distributed energy industry. With the continuous development of flexible storage and transportation technology of hydrogen energy, it will be possible for gas distributed energy to be widely promoted. Hydrogen fuel cell distributed energy will play an important role in the future gas distributed energy and even the whole energy supply field. It is of great significance for the future market prospect to realize the transition from fossil energy to low-carbon energy by gas-fired internal combustion engines and gas turbines with mixed hydrogen or pure hydrogen fuel.

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Biomass energy is an important zero-carbon renewable energy. Steadily promoting the diversified development of biomass energy and promoting the combination of biomass energy and distributed energy technology will help realize the development goal of clean and low-carbon energy consumption and comprehensive green transformation.

Integration with Renewable Energy to Create a Multi-energy Complementary Comprehensive Energy System Gas distributed energy has become the main framework of energy Internet characterized by multi-energy complementarity, integrated optimization and informationbased interconnection. The coupling of gas distributed energy and renewable energy to build a regional energy network can not only achieve regional energy balance, but also maximize the use of renewable energy. Gas-fired power generation technology is mature, clean, efficient, stable and flexible, which can timely supplement the shortcomings of discontinuous and unstable power generation that may occur when renewable energy is connected to the power grid on a large scale, and can play an active role in peak shaving, frequency modulation and fluctuation compensation. With the development of smart grid, Internet and other technologies, a comprehensive energy system of multi-energy complementarity with the characteristics of interconnection, low carbon, high efficiency and multi-source coordination came into being. It focuses on digital and intelligent energy production, storage, supply, consumption, management and service, and strive to realize the horizontal synergy of multiple energy sources such as electricity, heat, cold, gas, water, hydrogen and multiple supply methods such as water, fire, nuclear, wind, PV and storage, as well as the vertical interaction and optimization among various links such as source, network, load, storage and use, so as to provide comprehensive energy integrated solutions to end users.

A Smart Energy Management System Based on Digital Technology The development of gas distributed energy industry involves energy strategy adjustment, energy structure transformation, energy system optimization, energy business transformation and energy conservation and emission reduction actions, which need to be fully supported by digitalization. Digitalization and intelligence will fully tap and utilize the data value of gas distributed energy in the whole life cycle. New communication and Internet of Things technologies can realize online access and data collection of massive devices. Cloud computing and artificial intelligence technologies will improve the efficiency of calculation, processing and analysis of energy big data. Energy enterprises can optimize decisions through data analysis, improve the operational efficiency of energy production, transmission, trading and consumption, and ultimately improve the overall efficiency and security of gas distributed energy systems.

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Relying on the massive data acquisition platform, the energy management platform can realize data acquisition, real-time monitoring, analysis and statistics of various energy sources and intelligent terminals, and carry out multi-functional collaborative control, demand response, energy big data analysis and energy customer service for energy systems. It can accelerate the clean and low-carbon transformation of the energy supply side, realize intelligent and low-carbon development by digital empowerment, and move forward the service to get closer to and serve users better, thus building a harmonious and symbiotic ecological energy system, which will become an important direction to promote energy transformation and upgrading and innovative development models.

Diverse Development Mode of Gas Distributed Energy with Deepening Reform of Energy Market The continuous improvement of electricity market construction and the continuous optimization of trading rules and operation have enriched the energy trading model. The flexible and controllable nature of gas distributed energy makes it possible for it to participate in peak regulation, frequency regulation, black start and other power auxiliary services, which further enhances the competitiveness of gas distributed energy and guarantees the stability and flexibility of the power system. Based on the new mode of energy Internet of Things and comprehensive energy services, the business model of gas distributed energy will also transform from enterprise operation to platform operation, from asset as core to data as core, from value creation to shared empowerment, and from passive service to active docking.

Suggestions on Promoting the Development of Gas Distributed Energy Industry As an important part of the future energy under the strategies of peaking carbon emissions and achieving carbon neutrality, gas distributed energy needs to identify the orientation and direction of industrial development, innovate the management system and operation supervision mechanism, improve the industrial collaborative innovation system, and continue to promote and realize the sustainable development of the industry. The following development suggestions are put forward from the policy level, market level and technical equipment level.

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Policy-Level Suggestions To carry out energy integration planning, local governments should consider the project size and energy supply scope according to local conditions when approving gas distributed energy projects, relax the restrictions on the capacity of single equipment and the total installed capacity of projects, and give strong support for and convenience in project introduction, approval and grid connection. In view of the new trend of cross-border development of gas distributed energy, it is suggested that all competent departments in the energy field should strengthen coordination and cooperation, promote the reform of "separation of operating permits and business licenses" in the energy field, simplify the business approval procedures, encourage the adoption of filing system and simplify the power grid-connection procedures. Energy enterprises should be encouraged to operate across borders, including electricity, heat, gas (hydrogen) and other energy sources in specific administrative areas, and even combine energy, municipalities and sanitation to implement pilot integrated operations. Policy promotion of core technologies and equipment should continue to be strengthened, and financial and policy support should be further increased to build a number of demonstration projects. Priority should also be given to the use of independent technology and equipment, and investment subsidies or incentives should be given according to their level of autonomy. We should further improve the post-project evaluation mechanism and give some policy commendation to the high-quality projects.

Market-Level Suggestions We should expand our thinking, innovate market strategies and business models, and combine the construction of gas distributed energy projects with industrial transformation and upgrading and industrial aggregation in the new situation, so as to create an energy supply system that meets the needs of specific industries according to local conditions, and eventually lead to standardized and large-scale development. The development mechanism of rural energy projects suitable for China’s national conditions should be explored, combining technologies such as gas-distributed energy with the vast renewable energy resources in rural areas. The market-oriented reform of the on-grid price of gas distributed energy should be continuously deepened in order to establish and improve the market-oriented price mechanism for gas power and gas heat. The participation of gas distributed energy aggregators/virtual power plants in market-based trading of electricity should be encouraged, and priority should be given to pilot demonstrations of participation in spot market trading and auxiliary service markets in parks and load gathering areas, in order to build an energy Internet market with multi-body participation, multi-energy trading and multiple value-added service trading.

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The price transmission mechanism of the carbon market to gas distributed energy should be improved, rules for participation of gas distributed energy in the carbon market should be formulated, and the methodology should be regulated to include it as a voluntary emission reduction category. The carbon reduced should also be encouraged to participate in the carbon trading market in order to establish and improve the long-term management mechanism and regulatory mechanism for the participation of gas distributed energy in carbon trading.

Technology-Level Suggestions In terms of technology upgrading, gas distributed energy projects with multiple gas sources such as biomass natural gas, biogas and hydrogen should be developed. It is necessary to promote the formulation of standards and guidance documents related to hydrogen blending into natural gas pipeline, as well as bio-gas production and gridconnection, and encourage pilot demonstration and promotion of hydrogen blending into natural gas pipeline and incorporation of bio-gas into natural gas pipelines. The performance level of domestic equipment should be continuously improved, and the research and development and manufacturing of core equipment such as gas internal combustion engines and gas turbines should be continuously strengthened and technically upgraded. The quality level of host and supporting equipment should be improved, and the quality standards need to be gradually brought on par with the international advanced level. Emerging technologies should be developed to promote the research and development, production and application of new equipment, such as hydrogen-fueled internal combustion engines and gas turbines, fuel cells, etc. The municipal gas transmission and distribution pipelines should be improved, interconnection of pipeline networks should be strengthened, and the transmission capacity and reliability level should be enhanced. The layout of gas storage facilities should be optimized to enhance the capacity of gas sources for peak shaving and supply assurance. Digitalization and upgrading should be promoted to create an intelligent management system for gas distributed energy, expanding from traditional gas distributed systems to a comprehensive intelligent energy system integrating renewable energy, hydrogen energy, energy storage and carbon management. Engineering and technical service companies should broaden their professional fields, strengthen talent training, and develop from a single profession to a cross-disciplinary approach in order to enhance operation and management service capabilities and expand the scope of services.

Yang Zhang Yang Zhang: Sunwise New Energy System (Shanghai) Co., Ltd.

13 Development Status and Prospect of Gas Distributed Energy Industry Xiqing Tang Shanghai Aerospace Smart Energy Technologies Co., Ltd. Qingshan Meng China Gas Assosiation Distributed Energy Committee Weiwei Wang Institute of Energy, Peking University Wei Huang China Gas Assosiation Distributed Energy Committee

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Part IV

New Energy

Chapter 14

Hydrogen Production from Renewable Energy: Current Status, Prospects and Challenges Qia Wang

Hydrogen production from renewable energy is one of the most promising clean energy technologies in the twenty-first century. In February 2022, the Beijing Winter Olympics set a precedent for large-scale use of hydrogen in international Olympic events, not only by using hydrogen as all torch fuel for the first time, but also by putting into operation more than 1,000 hydrogen fuel cell vehicles with more than 30 hydrogen refueling stations. Compared with pure electric vehicles, hydrogen fuel cell vehicles are highly favored by consumers because of their cold resistance, high energy density, long driving range and shorter refueling time. On March 23, 2022, the National Development and Reform Commission and the National Energy Administration of China jointly issued the Medium- and Long-term Plan for the Development of Hydrogen Energy Industry (2021–2035) (hereinafter referred to as “the Plan”), which sets out three milestones for the development of China’s hydrogen energy industry. (1) By 2025, a more complete institutional policy environment for the development of the hydrogen energy industry will be formed, the industrial innovation capability will be significantly improved, the core technology and manufacturing process will be basically mastered, and a more complete supply chain and industrial system will be initially established. The demonstration application of hydrogen energy will achieve obvious results, along with the greater progress of clean energy hydrogen production and hydrogen energy storage and transportation technology, so that the market competitiveness of the industry will be greatly improved, and a hydrogen energy supply system mainly based on industrial by-product hydrogen and hydrogen from renewable energy will be initially built. The number of fuel cell vehicles will reach 50,000, and a batch of hydrogen refueling stations will be deployed and built. The amount of hydrogen production from renewable energy will Q. Wang (B) Institute of Quantitative and Technological Economics, Chinese Academy of Social Sciences, Beijing, China e-mail: [email protected] © China Economic Publishing House 2024 China International United Petroleum & Chemicals Co., Ltd., et al. (eds.), Annual Report on China’s Petroleum, Gas and New Energy Industry (2022–2023), Current Chinese Economic Report Series, https://doi.org/10.1007/978-981-99-7289-0_14

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reach 100,000 to 200,000 tons/year, becoming an important part of the new hydrogen energy consumption and achieving CO2 emission reduction of 1 million to 2 million tons/year. (2) By 2030, a more complete hydrogen energy industry technology innovation system and clean energy hydrogen production and supply system will be formed, and the reasonable and orderly industrial layout and the wide application of hydrogen from renewable energy will strongly support the achievement of the goal of peak carbon emissions. (3) By 2035, the hydrogen energy industry system will be formed, developing a diversified hydrogen energy application ecology covering transportation, energy storage and industry. The proportion of renewable energyproduced hydrogen production in end-use energy consumption will be significantly increased, which will play an important role in supporting the development of green energy transformation. Hydrogen energy can be divided into gray hydrogen, blue hydrogen and green hydrogen according to different production sources.1 Compared with grey hydrogen and blue hydrogen, green hydrogen hardly produces carbon emissions in the production process. In the modern energy system featuring multi-energy complementarity and the new power system coordinating power source, grid, load and storage, green hydrogenplays a very prominent role and value. Green hydrogen is not only an important secondary energy source to help achieve deep decarbonization in the difficult-to-reduce-emissions field, but also an important transformation vehicle for the efficient use of renewable energy, promoting the optimal allocation of green lowcarbon energy across regions and seasons, and enhancing the diversity, flexibility and stability of the energy system.

The Practical Significance of China’s Active Development of the Renewable Energy-to-Hydrogen Industry The Plan clearly points out the strategic positioning of China’s hydrogen energy industry development: “hydrogen energy is an important part of the future national energy system,” “hydrogen energy is an important carrier for the green and lowcarbon transformation of energy-using terminals,” and “the hydrogen energy industry is a strategic emerging industry and the key development direction of future industry.” In this context, the strategic significance of accelerating the development of renewable energy hydrogen industry can be interpreted from the following three perspectives. Firstly, to promote the development of the renewable energy-to-hydrogen industry and explore the wide application of green hydrogen in polymorphic scenarios is a necessary way for China to realize the vision of peak carbon emissions and carbon 1

Grey hydrogen is produced from fossil fuels such as coal, oil, natural gas or industrial by-products. Blue hydrogen is produced from gray hydrogen combined with the CCUS technology (CO2 capturing, utilization and storage). Green hydrogen is produced from non-fossil energy sources, usually including renewable energy sources such as hydroelectricity, wind power and solar power. In addition, green hydrogen can also be obtained from nuclear power and bio-hydrogen (hydrogen production from biomass through gasification and microbial catalytic dehydrogenation).

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neutrality. Figure 14.1 depicts the production, conversion, transportation and enduse of green hydrogen in the energy system. It shows that green hydrogen, as a zero-carbon secondary energy source, is an important carrier for renewable energy consumption and an ideal alternative fuel for smelting, chemical industry, longdistance transportation, heavy trucks, aviation and other fields where decarbonization is difficult to be achieved through electrification. Promoting the layout of the whole industry chain of green hydrogen covering production, storage, transportation, refueling and utilization links in order to realize its batch and large-scale production can not only give full play to the role of hydrogen as a carrier for the large-scale and efficient utilization of renewable energy and increase the supply of low-carbon energy, but also help to promote the transformation of energy consumption at energyconsuming terminals such as industry, transportation, heating and power generation, thus reducing greenhouse gas emissions. This is of great significance to the overall improvement of the cleanliness of the energy system and the formation of a modern energy supply system with multi-energy complementarity. Secondly, optimizing the industry layout of renewable energy-to-hydrogen technology and expanding the scale of green hydrogen production and storage is an objective need for China to enhance the security level of energy system and power system. At present, China’s renewable energy consumption is mainly in the form of electricity, and due to the intermittent and volatile characteristics of wind power, PV and other new energy sources, large-scale and high-ratio grid connection brings a greater challenge to the safe and stable operation of the power system. On the occasion Production

Conversion

Transportation

End-use Industry Steel Industry Chemical Industry

Renewable energy

Refining Industry No conversion

Transportation Shipping

Electrolysis

Trucking Conversion Sustainable CO2 capture

Pipeline

Automotive Rail Truck

Synthetic fuels*

Bus Storage

Green ammonia

Shipping Air transport

Heat supply Power generation

Fig. 14.1 Production, conversion, transportation and end-use of green hydrogen

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of the construction of nine clean energy bases and five offshore wind power bases,2 an appropriate amount of renewable energy-to-hydrogen projects can not only further enhance the level of renewable energy consumption, but also reduce the impact of renewable energy volatility on the power system, thus optimal allocation of renewable energy across regions and seasons. This is of great significance for preventing systemic risks in energy supply and promoting safe and reliable alternatives to new energy sources.3 Finally, to accelerate the upgrading and growth of the renewable energy-tohydrogen industry and to realize the virtuous cycle and innovative development of the industry chain is in line with the development trend of the new round of global scientific and technological revolution and energy industry change. Hydrogen production from renewable energy is one of the key development directions of strategic emerging industries and future industries. Strengthening the construction of innovation system for the hydrogen energy industry, accelerating the breakthrough of hydrogen energy core technology and key material bottlenecks, and accelerating the cultivation of new products, new industries and new modes (such as ammonia, methanol and synthetic liquid fuels) will not only help China’s green and low-carbon industry achieve highquality development, but also help China maintain its competitive advantage of leading technology in the future international energy market.

Development Status of Hydrogen Production from Renewable Energy in China and Abroad The history of human discovering hydrogen and applying hydrogen can be traced back to several centuries ago. In the middle of the eighteenth century, mankind began to study hydrogen in depth and named this combustible gas “hydrogen.“4 In 1970, 2

The nine clean energy bases planned for the 14th Five-Year Plan include: Songliao Clean Energy Base, Jibei Clean Energy Base, Yellow River Jiziwan Clean Energy Base, Hexi Corridor Clean Energy Base, Upper Yellow River Clean Energy Base, Xinjiang Clean Energy Base, Upper Jinsha River Clean Energy Base, Yalong River Basin Clean Energy Base, and Lower Jinsha River Clean Energy Base. The five offshore wind power bases include: Guangdong Offshore Wind Power Base, Fujian Offshore Wind Power Base, Zhejiang Offshore Wind Power Base, Jiangsu Offshore Wind Power Base, and Shandong Offshore Wind Power Base. 3 In December 2021, General Secretary Xi Jinping emphasized in the Central Economic Work Conference that the gradual withdrawal of traditional energy sources should be based on the safe and reliable substitution of new energy sources. 4 As early as the middle of the sixteenth century, the Swiss scientist Paracelsus noticed a phenomenon that when acid corrodes metal, it produces a gas that can be burned. In 1776, the English scientist Henry Cavendish produced and collected a kind of flammable gas by reacting zinc metal with hydrochloric acid. In 1788, the French chemist Antoine Laurent de Lavoisier proved that this flammable gas was a single substance and named it "hydrogen." The British scientist William Nicholson discovered in 1800 that hydrogen was precipitated from one pole of the battery and oxygen from the other by electrolysis of water. The Swiss chemist Christian Friedrich Schoenbein discovered the fuel cell effect in 1838. William Grove, a British scientist and judge, invented the

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the term “hydrogen economy” was creatively coined by electrochemist John O’M. Bockris during a discussion at the General Motors Technical Center, followed by the publication of the book Energy: The Solar-hydrogen Alternative. After the first oil crisis in 1973, hydrogen energy was seen as an ideal alternative fuel to oil, and more attention was paid to hydrogen research and the application of hydrogen fuel cell technology. In 1974, the International Association for Hydrogen Energy (IAHE) was founded. Subsequently, hydrogen fuel cell technology gradually became one of the power sources for automobiles, airships, airplanes and rockets. Along with the rapid development of hydrogen fuel cell technology, the hydrogen energy industry has gradually grown.

Development Status of Hydrogen Production from Renewable Energy Around the World In the current carbon neutral action sweeping the world, hydrogen energy as a key part of the energy system to achieve in-depth decarbonization has attracted much attention from various countries, and the hydrogen energy industry has entered a new stage of development. Not only China, but also the US, EU, Japan, Korea, India, Canada, Australia, Chile, Norway, Germany, France, Spain, the Netherlands, Portugal and other countries or regions have released their national hydrogen energy strategies (China Z-Park Hydrogen Fuel Cell Industry Alliance 2021), elevating the development of hydrogen energy industry to a national strategic level. Depending on the situation of each country or region, the models of developing hydrogen energy industry can be broadly divided into the following four categories. (1) Carbon neutralityoriented (represented by EU countries and the UK): By supporting the development of hydrogen production from renewable energy on a large scale, the countries help industry and transportation sectors to reduce their dependence on fossil energy, thus helping to achieve the goal of carbon neutrality. (2) Technology reserve-oriented (represented by the United States and Canada): These countries are rich in oil and gas resources, and shale gas, which has economic and low-carbon advantages, has more competition with hydrogen energy in terms of application, resulting in relatively slow expansion of hydrogen energy market. (3) Export-oriented (represented by Russia and Australia): Relying on the resource advantages of fossil energy in their countries, they produce grey hydrogen and blue hydrogen on a large scale and use them as new growth points for export trade. (4) Import-oriented (represented by Japan and South Korea): These countries have scarce energy resources and are highly dependent on imports for energy supply. By encouraging hydrogen consumption and expanding hydrogen imports, they can optimize their energy consumption structure and energy import channels, improve energy security, and resolve the risk of energy supply disruptions and price fluctuations. gas cell in 1845. In 1889, Ludwig Mond and Charles Langer built the first fuel cell device using air and industrial gas.

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According to the Hydrogen Projects Database of the International Energy Agency (IEA) (IEA 2021), as of October 2021, there are 202 hydrogen projects in operation worldwide, including six hydro-to-hydrogen projects, 19 onshore wind-to-hydrogen projects, and 16 PV-to-hydrogen projects5 ; in addition, there are 67 hydrogen projects under construction, including seven onshore wind-to-hydrogen projects, three offshore wind-to-hydrogen projects, and eight PV-to-hydrogen projects. In China, nine hydrogen energy projects have been put into operation, including two onshore wind-to-hydrogen projects (Hebei Zhangjiakou Hypower Wind-toHydrogen Project Phase I; Hebei Guyuan Wind-to-Hydrogen Project Phase I) and two PV-to-hydrogen projects (PV-to-Hydrogen Project for the Fine Chemical Industry Park in Lanzhou New District; Liaoning Dalian Tongji-Xinyuan Hydrogen Refueling Station); in addition, there are six hydrogen energy projects under construction, including Hebei Guyuan Wind-to-Hydrogen Project Phase II, and the Chongli PV-Wind-to-Hydrogen Demonstration Project. Renewable energy-to-hydrogen is one of the most active areas of investment in the new energy industry. Thanks to the dramatic cost reductions in onshore wind power and solar PV power over the last decade, the cost of renewable energy has fallen rapidly and its economics have become more apparent. Over the past two years, global investment in renewable energy-to-hydrogen has continued to climb. In Europe alone, there are currently hundreds of projects under construction (Qian et al. 2022). In July 2021, PosHYdon, the world’s first green hydrogen project on an offshore oil and gas platform, received e3.6 million in funding from the Dutch government (Energy Development and Policy 2021). In addition to government departments, some international energy giants have also invested heavily in green hydrogen as a new business, such as BP (CWEA 2022a), Total Energy, Saudi Aramco, Chevron, Ørsted (CWEA 2022b), Siemens Energy (CWEA 2022c), etc.

Development Status of Hydrogen Production from Renewable Energy in China China is the largest hydrogen producer in the world, with an annual production of about 33 million tons of hydrogen, and has the basic conditions for large-scale popularization of the main technologies and production processes, such as hydrogen energy preparation, storage and transportation, hydrogen refueling, fuel cell and system integration. There are more than 300 industrial enterprises above the scale in the whole industry chain, which are concentrated in Yangtze River Delta, GuangdongHong Kong-Macao Greater Bay Area, Beijing-Tianjin-Hebei Region, etc. However, it is important to note that the production of hydrogen in China is dominated by grey

5

Only projects with clearly documented hydrogen production methods in the database are counted here. There are also many projects that use fossil energy-to-hydrogen, grid electricity-to-hydrogen, and unknown hydrogen production methods.

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hydrogen, with green hydrogen production accounting for about 1.5% of the total hydrogen production.6 China’s abundant and widely distributed renewable energy resources have laid a solid foundation for the development of renewable energy-to-hydrogen industry. After years of unremitting efforts, the installed capacity of renewable energy in China has been the first in the world for many years, and the cost of onshore wind power and PV power generation has been equal to the cost of coal-fired power generation, and even lower than it in some areas. The abandonment of hydropower, wind power and PV power generation technologies has been effectively mitigated throughout the country. Due to the distribution of renewable energy and its electricity price, the existing renewable energy-to-hydrogen projects in operation in China are mainly concentrated in the western regions such as Xinjiang, Inner Mongolia and Ningxia, accounting for 80.68% of all green hydrogen production, while such projects in coastal areas are moving more slowly. In view of the important role of hydrogen energy for the green transformation of energy system, hydrogen energy was mentioned in China’s Five-Year Plan7 for the first time. Since the 14th Five-Year Plan period, a number of policy documents related to the development of hydrogen energy industry have been issued at the national level, including the Plan for Implementation of Cleaner Production in China During the 14th Five-Year Plan Period, the Plan for Development of Integrated Transport Services During the 14th Five-Year Plan Period, the Plan for Development of Green Transportation During the 14th Five-Year Plan Period, the Plan for Modern Energy System During the 14th Five-Year Plan Period, the Plan for Development of New Energy Storage During the 14th Five-Year Plan Period, and the Plan for Scientific and Technological Innovation in the Energy Sector During the 14th Five-Year Plan Period (Guanyun et al. 2022). Under the above policies, the planning and development of renewable energy industry in each region began to speed up. In September 2021, the joint debugging test of the megawatt-level demonstration station for the comprehensive utilization of hydrogen energy in Lu’an, Anhui province was successfully completed. The demonstration project adopts PEM water electrolysis for hydrogen production, designed 6

This is based on the data from 2019 published in the White Paper on China’s Hydrogen Energy and Fuel Cell Industry (2020), “the largest output is coal-to-hydrogen, which reaches 21.24 million tons, accounting for 63.54%; followed by industrial by-product hydrogen and natural gas-to-hydrogen, with outputs of 7.08 million tons and 4.6 million tons respectively; the output of electrolytic waterto-hydrogen is about 500,000 tons,” and the information provided in the Report on the Development of China’s Hydrogen Energy Industry in 2022, “China is still in the early stage of development of hydrogen production from electrolytic water, accounting for about 1.5% of the national hydrogen production, and there is great room for future growth.” 7 According to the Outline of the 14th Five-Year Plan (2021-2025) for National Economic and Social Development and Vision 2035 of the People’s Republic of China, China will organize and implement the plan for incubating and accelerating the hydrogen energy industry, and plan and create a layout for the industry. In areas where it has prominent advantages in science and education resources and strong industrial foundation, it will establish a number of national research institutes on industrial technology of hydrogen energy to strengthen multi-path exploration and multidisciplinary integration of cutting-edge technology and supply of disruptive technology.

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to produce 723,000 Nm3 of hydrogen per year and generate 1,278,000 kW-h of hydrogen for peak shaving and valley filling in the power system. On November 30, 2021, the construction of Sinopec Green Hydrogen Demonstration Project in Kuqa, Xinjiang, the first 10,000-ton PV green hydrogen demonstration project in China, was officially launched (Sinopec 2022). The project will build a 300,000-kilowatt PV power plant (with an average annual power generation capacity of 618 million kWh), an electrolytic water-to-hydrogen plant with an annual capacity of 20,000 tons, a hydrogen storage spherical tank with a storage capacity of 210,000 Nm3 , a hydrogen transmission pipeline with a capacity of 28,000 Nm3 /hour, and supporting transmission and substation facilities. After the project is put into operation, the annual production capacity of green hydrogen is expected to reach 20,000 tons, making it the largest green hydrogen production project in the world. In January 2022, the first hydrogen energy storage project in Shanxi Province was officially signed. The first phase of the project will build 6 × 25 MW distributed PV power stations and 100 MW wind power stations, supported by 150 MW electrode boiler heating systems and 10 MW high-pressure hydrogen storage systems for electrolytic water-to-hydrogen; the second phase is expected to build 1000 MW PV power stations, supported by 50 MW liquid hydrogen storage systems for electrolytic water-to-hydrogen. After the completion of the two phases, 10,000 kg of high purity hydrogen will be produced every day, which meet the demand of twenty 500 kg hydrogen refueling stations at the same time. On May 17, 2022, Huadian Darhan Muminggan 200,000 kW new energy-to-hydrogen demonstration project, a large-scale integrated project for PVwind-hydrogen storage in Inner Mongolia, was won by China Energy Engineering Group Guangdong Electric Power Design Institute Co., Ltd. (China Energy Engineering Group 2022). The project is expected to build 120,000 kW of wind power generating capacity, 80,000 kW of PV power generating capacity, 20,000 kW-h of electrochemical energy storage capacity, and 12,000 Nm3 /hour electrolytic water-tohydrogen, using 100% green electricity methods to produce hydrogen. The project is expected to produce 0.78 million tons of green hydrogen per year. Up to now, a large number of green hydrogen projects have been planned in Inner Mongolia, Gansu, Jilin and Shandong (IN-EN.com 2022). The second half of 2022 is expected to see a rapid increase in construction or bidding new renewable energy-to-hydrogen projects nationwide.

14 Hydrogen Production from Renewable Energy: Current Status …

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The Development and Trend of the Renewable Energy-to-Hydrogen Technology The Development and Trend of the Electrolytic Water-to-Hydrogen Technology At present, the main technologies of hydrogen production from electrolytic water are alkaline water electrolysis (ALK or AWE), proton exchange membrane (PEM) electrolysis, anion exchange membrane (AEM) electrolysis and solid oxide electrolysis (SOE) (see Table 14.1). Alkaline water electrolysis technology has achieved industrial-scale hydrogen production, and is the most mature technology with relatively low cost to produce hydrogen, suitable for electrolytic hydrogen production on the grid. PEM electrolysis technology is advancing faster in Europe and the United States, which produces high-purity hydrogen, with higher energy efficiency than AWE technology, higher flexibility in plant operation, faster response to power changes, and good compatibility with wind power and PVs, which are more volatile and stochastic. However, due to the use of precious metal catalysts such as platinum (Pt), iridium (Ir) and ruthenium (Ru), the cost is high. AEM technology combines the advantages of traditional AWE technology and PEM electrolysis technology, but it is still in the stage of development and improvement at home and abroad, and the research and development mainly focuses on alkaline solid polymer AEM and highly active non-precious metal catalysts. SOE technology has a lower power consumption than AWE technology and PEM electrolysis technology, but it has not been widely commercialized yet, and only validation demonstrations have been completed on a laboratory scale in China. Because of the high temperature environment required, this technology is more suitable for systems such as concentrated solar power generation that generate steam under high pressure and temperature.

The Development and Trend of Hydrogen Energy Storage and Transportation Technology In terms of hydrogen storage, there are four main technologies that are more mature and have better prospects8 : high-pressure gaseous hydrogen storage, low-temperature liquid hydrogen storage, solid alloy hydrogen storage and organic liquid hydrogen 8

Hydrogen storage technologies are divided into two categories according to the storage principle: physical and chemical hydrogen storage. Physical hydrogen storage mainly includes: liquefaction storage, high-pressure storage, low-temperature compression storage, etc. Chemical hydrogen storage mainly includes: metal hydride storage, hydrogen adsorption on activated carbons, storage by carbon fiber and carbon nanotube, organic liquid hydride storage, inorganic storage, etc. There are still some technologies to be explored and developed, including Glass Microspheres for Hydrogen

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Table 14.1 Four characteristics of water electrolysis technologies (Hongmei et al. 2021) AWE

PEM

AEM

SOE

Electrolyte diaphragm

30% KOH asbestos membrane

Proton exchange membrane

Anion exchange membrane

Solid oxide

Current density (A/cm2 )