World Energy
Outlook2022

INTERNATIONAL ENERGYAGENCY

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Foreword
Today, the world is in the midst of the first truly global energy crisis, with impacts that will
be felt for years to come. Russia’s unprovoked invasion of Ukraine in February has had far‐reaching impacts on the global energy system, disrupting supply and demand patterns andfracturing long‐standing trading relationships.
The crisis is affecting all countries, but at the International Energy Agency (IEA), we areparticularly concerned about the effect it is having on the people who can least afford it. Oneof the striking findings in this year’s World Energy Outlook (WEO) is that the combination of
the Covid pandemic and the current energy crisis means that 70 million people who recently
gained access to electricity will likely lose the ability to afford that access – and 100 million
people may no longer be able to cook with clean fuels, returning to unhealthy and unsafe
means of cooking. That is a global tragedy. And it is not only an energy crisis with which weare dealing: many countries also face a food security crisis and increasingly visible impacts ofclimate change.
As the world faces this unprecedented energy shock and the other overlapping crises, weneed to be clear on how we got here and where we need to go. The analysis in this Outlook
is particularly important to shed light on these questions and to dispel some of the mistaken
and misleading ideas that have arisen about this energy crisis.
For example, there is a mistaken idea that this is somehow a clean energy crisis. That is simply
not true. The world is struggling with too little clean energy, not too much. Faster clean
energy transitions would have helped to moderate the impact of this crisis, and they
represent the best way out of it. When people misleadingly blame climate and clean energy
for today’s crisis, what they are doing – whether they mean to or not – is shifting attention
away from the real cause: Russia’s invasion of Ukraine.
Another mistaken idea is that today’s crisis is a huge setback for efforts to tackle climatechange. The analysis in this Outlook shows that, in fact, this can be a historic turning point
towards a cleaner and more secure energy system thanks to the unprecedented response
from governments around the world, including the Inflation Reduction Act in the UnitedStates, the Fit for 55 package and REPowerEU in the European Union, Japan’s Green
Transformation (GX) programme, Korea’s aim to increase the share of nuclear andrenewables in its energy mix, and ambitious clean energy targets in China and India.

This WEO underscores that successful energy transitions must be fair and inclusive, offeringa helping hand to those in need and ensuring the benefits of the new energy economy areshared widely. Even as countries struggle to manage the brutal shocks from the crisis, theForeword

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At the same time, I am worried that today’s major global energy and climate challenges
increase the risk of geopolitical fractures and new international dividing lines – especiallybetween advanced economies and many emerging and developing economies. Unity andsolidarity need to be the hallmarks of our response to today’s crisis. That is the case forEurope during what promise to be tough winters not only this year but also next. And it istrue globally.

last thing we should do is turn inwards and away from supporting each other. Instead, weneed to work together to build trust.
The IEA is committed to continuing to play a central role in this by helping governments todefine the actions that are needed to enable the world to confront our shared energy andclimate challenges together. In this, we are guided by the IEA’s world class energy modelling
and analysis – underpinned by unparalleled data – that is exemplified by the World Energy
Outlook. For this, I would like to warmly thank the excellent IEA team that has worked skilfully
and tirelessly under the outstanding leadership of my colleagues Laura Cozzi and Tim Gould
to produce another essential and timely Outlook that I hope will help decision‐makers
globally to navigate the current crisis and move the world towards a more secure andsustainable future.

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International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

Dr Fatih Birol
Executive Director
International Energy Agency

Acknowledgements
This study was prepared by the World Energy Outlook (WEO) team in the Directorate of
Sustainability, Technology and Outlooks (STO) in co‐operation with other directorates andoffices of the International Energy Agency (IEA). The study was designed and directed by
Laura Cozzi, Chief Energy Modeller and Head of Division for Energy Demand Outlook, andTim Gould, Chief Energy Economist and Head of Division for Energy Supply and Investment
Outlooks.
The modelling and analytical teams for this WEO‐2022 were led by Stéphanie Bouckaert(demand), Jonathan Coppel (investment and finance), Christophe McGlade (supply),
Thomas Spencer (climate and environment), Brent Wanner (power) and Daniel Wetzel(sustainable transitions).
Key contributions from across the WEO team were from:Oskaras Alšauskas (transport), Lucila Arboleya Sarazola (investment and finance),
Yasmine Arsalane (lead on economic outlook, power), Blandine Barreau (recovery plan),
Simon Bennett (co‐lead on hydrogen, energy technologies), Charlène Bisch (datamanagement), Justina Bodláková (employment), Olivia Chen (employment), Yunyou Chen
(power), Daniel Crow (lead on behaviour, air pollution), Davide D'Ambrosio (lead on data
science, power), Amrita Dasgupta (critical minerals), Tanguy De Bienassis (investment andfinance), Tomás de Oliveira Bredariol (lead on coal, methane), Michael Drtil (power andelectricity networks), Darlain Edeme (Africa), Musa Erdogan (fossil fuel subsidies, data
management), Eric Fabozzi (power and electricity networks), Víctor García Tapia (datascience, buildings), Pablo González (investment and finance), Timothy Goodson (lead onbuildings), Emma Gordon (investment and finance), Jérôme Hilaire (lead on oil and gas
supply modelling), Paul Hugues (lead on industry), Jacob Hyppolite II (energy access),
Bruno Idini (transport), George Kamiya (energy technologies, digitalisation), Hyeji Kim(transport), Tae‐Yoon Kim (lead on energy security and critical minerals), Martin Kueppers(industry), Tobias Lechtenbohmer (industry), Laura Maiolo (oil and gas supply),
Orla McAlinden (behaviour), Yannick Monschauer (affordability), Toru Muta (lead on fossil
fuel subsidies), Paweł Olejarnik (supply modelling), Diana Perez Sanchez (industry),
Apostolos Petropoulos (lead on transport), Mariachiara Polisena (power), Ryszard Pospiech(lead on coal supply modelling, data management), Arthur Rogé (buildings),
Max Schoenfisch (power), Rebecca Schulz (oil and gas supply), Leonie Staas (buildings,
behaviour), Gianluca Tonolo (lead on energy access), Wonjik Yang (data visualisation) andPeter Zeniewski (lead on gas). Other contributions were from Niccolò Hurst andCarlo Starace. Marina Dos Santos and Eleni Tsoukala provided essential support.
Edmund Hosker carried editorial responsibility.

Colleagues from the Energy Technology Policy (ETP) Division led by Head of Division
Timur Gül co‐lead on modelling and analysis, with overall guidance fromAraceli Fernandez Pales and Uwe Remme. Peter Levi, Tiffany Vass, Alexandre Gouy,
Leonardo Collina and Faidon Papadimoulis contributed to the analysis on industry.
Acknowledgements

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Debra Justus was the copy‐editor.

Jacob Teter, Leonardo Paoli, Elizabeth Connelly and Ekta Bibra contributed to the analysis ontransport. Chiara Delmastro and Martin Husek contributed to the analysis on buildings.
Stavroula Evangelopoulou, Francesco Pavan, Amalia Pizarro and Amar Bhardwaj contributed
to the analysis on hydrogen. Praveen Bains contributed to the analysis on biofuels.
Mathilde Huismans contributed to data science.
Other key contributors from across the IEA were: Ali Al‐Saffar, Heymi Bahar, Chiara D'Adamo,
Carlos Fernández Alvarez, David Fischer, Inhoi Heo, Jinsun Lim, Luca Lo Re, Rebecca McKimm,
Jeremy Moorhouse, Kristine Petrosyan, Gabriel Saive and Talya Vatman.
Valuable comments and feedback were provided by other senior management andnumerous other colleagues within the IEA. In particular, Mary Warlick, Keisuke Sadamori,
Nick Johnstone, Amos Bromhead, Toril Bosoni, Joel Couse, Paolo Frankl, Brian Motherway,
Aad Van Bohemen, Rebecca Gaghen, An Fengquan, Sara Moarif, Hiro Sakaguchi andJacob Messing.
Thanks go to the IEA’s Communications and Digital Office for their help in producing thereport and website materials, particularly to Jad Mouawad, Fabien Barau, Curtis Brainard,
Adrien Chorlet, Jon Custer, Claire Dehouck, Astrid Dumond, Tanya Dyhin, Merve Erdem,
Grace Gordon, Barbara Moure, Jethro Mullen, Isabelle Nonain‐Semelin, Julie Puech,
Clara Vallois, Gregory Viscusi and Therese Walsh. Ivo Letra and Ben McCulloch provided
essential support to the production process. IEA’s Office of the Legal Counsel, Office ofManagement and Administration and Energy Data Centre provided assistance throughout
the preparation of the report.
Valuable input to the analysis was provided by: David Wilkinson (independent consultant).
Valuable input to the modelling on air pollution and associated health impacts was provided
by Peter Rafaj, Gregor Kiesewetter, Wolfgang Schöpp, Chris Heyes, Pallav Purohit,
Laura Warnecke, Adriana Gomez‐Sanabria and Zbigniew Klimont (International Institute forApplied Systems Analysis). Valuable input to the modelling and analysis of greenhouse gas
emissions from land use and bioenergy production was provided by Nicklas Forsell,
Andrey Lessa‐Derci‐Augustynczik, Pekka Lauri, Mykola Gusti, Zuelclady Araujo Gutierrez andPetr Havlík (International Institute for Applied Systems Analysis).
The work could not have been achieved without the support and co‐operation provided bymany government bodies, organisations and companies worldwide, notably: Enel; Eni;
European Union (Global Public Goods and Challenges Programme); Hitachi Energy; Iberdrola;
Jupiter Intelligence; Ministry of Economy, Trade and Industry, Japan; Ministry of Economic
Affairs and Climate Policy, the Netherlands; The Research Institute of Innovative Technology
for the Earth, Japan; Shell; Swiss Federal Office of Energy; and Toshiba.

Thanks also go to the IEA Energy Business Council, IEA Coal Industry Advisory Board, IEA
Energy Efficiency Industry Advisory Board and the IEA Renewable Industry Advisory Board.
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International Energy Agency | World Energy Outlook 2022

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The IEA Clean Energy Transitions Programme (CETP), particularly through the contributionsof the Agence Française de Développement, Italy, Japan, the Netherlands, Sweden and theUnited Kingdom supported this analysis.

Peer reviewers
Many senior government officials and international experts provided input and reviewed
preliminary drafts of the report. Their comments and suggestions were of great value. They
include:Harmeet Bawa
Lee Beck
Christian Besson
Sama Bilbao y Leon
Jorge Blazquez
Jason Bordoff
Mick Buffier
Nick Butler
Ben Cahill
Diane Cameron
Kimball Chen
Drew Clarke
Rebecca Collyer
Russell Conklin
Anne‐Sophie Corbeau
Ian Cronshaw
Helen Currie
Francois Dassa
Ralf Dickel
Giles Dickson
Zuzana Dobrotkova
Lynette Dray
Cody Finke
Nikki Fisher
Acknowledgements

Research Institute of Innovative Technology for the Earth, Japan
Economic Research Institute for ASEAN and East Asia (ERIA)
National Renewable Energy Laboratory (NREL), United States
Independent consultant
International Institute for Applied Systems Analysis (IIASA)
Danish Energy Agency
State Grid Energy Research Institute, China
European Investment BankWorld Coal Association
UK Department for Business, Energy and Industrial Strategy(BEIS)
Hitachi Energy
Clean Air Task Force
Independent consultant
World Nuclear Association
BP
Columbia University, United States
GlencoreKing’s College London
Center for Strategic and International Studies (CSIS),
United States
Nuclear Energy Agency
Global LPG Partnership
Australian Energy Market Operator
European Climate Foundation
US Department of Energy
Columbia University
Independent consultant
ConocoPhillips
EDF
Oxford Institute for Energy Studies, United Kingdom
WindEurope
World Bank
University College London
Brimstone Energy
Thungela7

IEA. CC BY 4.0.

Keigo Akimoto
Venkatachalam
Anbumozhi
Doug Arent
Neil Atkinson
Andrey Augustynszik
Peter BachShan Baoguo
Manuel Baritaud
Paul Baruya
Tom Bastin

Pierre‐Laurent LucilleMalte Meinshausen
Antonio Merino Garcia
Michelle Michot Foss
Cristobal Miller
Vincent Minier
Tatiana Mitrova
Simone MoriPeter Morris
Steve Nadel

8

Delta Electricity
IIASA
US Energy Information Administration
ToyotaNexantNatural Resources Defense Council (NRDC)International Renewable Energy Agency (IRENA)
International Atomic Energy Agency (IAEA)
Ministry for Economic Affairs and Industry, Germany
Ministry of Economy, Trade and Industry, Japan
University of Calgary
Clean Coal Centre
Oxford Institute for Energy Studies, United Kingdom
Tokyo Gas
Mitsui Global Strategic Studies Institute, JapanJOSCO Energy Finance and Strategy Consultancy
Mediterranean Observatory for Energy
Siemens Energy
World LPG Association
Ministry of Foreign Affairs, Japan
Institute of Energy Economics, Japan
Baker Institute for Public Policy
Kyoto University of Foreign Studies, Japan
Rocky Mountain Institute
Iberdrola
Global Wind Energy Council
BHP
State Grid Energy Research Institute, China
Energy Research Institute, National Development and Reform
Commission, China
Engie
University of Melbourne, Australia
RepsolBaker Institute for Public Policy
Department of Natural Resources, Canada
Schneider Electric
SIPA Center on Global Energy Policy
ENEL
Minerals Council of Australia
American Council for an Energy‐Efficient Economy,
United States
International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

Justin Flood
Nicklas ForsellDavid Fritsch
Hiroyuki Fukui
Mike Fulwood
David G. Hawkins
Dolf Gielen
Andrii Gritsevskyi
Michael Hackethal
Yuya Hasegawa
Sara Hastings‐Simon
Colin Henderson
James Henderson
Masazumi Hirono
Takashi Hongo
Jan‐Hein Jesse
Sohbet Karbuz
Rafael Kawecki
Michael Kelly
Nobuyuki Kikuchi
Ken Koyama
Jim Krane
Atsuhito Kurozumi
Sarah Ladislaw
Francisco Laveron
Joyce Lee
Lee Levkowitz
Li Jiangtao
Liu Xiaoli

Stephanie Pfeifer
Cédric Philibert

Norad
Coordinating Ministry for Economic Affairs, Indonesia
Technology Collaboration Programme on Photovoltaic Power
European Heat Pump Association
Permanent Delegation of Japan to the OECD
Korea Energy Economics Institute
Comillas Pontifical University's Institute for Research inTechnology, Spain
Institutional Investors Group on Climate Change
French Institute of International Relations, Centre forEnergy & Climate
Ministry of Climate and Environment, Poland
DG for Climate Action, European Commission
World Steel
Department of Natural Resources, Canada
Saudi Aramco
Glasgow Financial Alliance for Net Zero
ExxonMobil
OpenEXP, IPCC author
Permanent Representation of Spain to the European UnionElżbieta Piskorz
Vicki Pollard
Andrew Purvis
Jason Randall
Seth Roberts
Tony Rooke
April Ross
Yamina Saheb
Juan Bautista
Sánchez‐Peñuela LejarragaHans‐Wilhelm Schiffer
World Energy Council
Polar Geology Federal Institute for Geosciences and Natural
Sandro Schmidt
Resources, Germany
Robert Schwiers
ChevronAdnan Shihab Eldin
Independent expert
Deutsches Institut für Wirtschaftsforschung (German
Jesse Scott
Institute for Economic Research)
Simona Serafini
ENI
Maria Sicilia
EnagásPaul Simons
Yale University
Jim Skea
Imperial College London, IPCC Co‐Chair Working Group III
Ashley SteelFood and Agriculture Organization of the United Nations
Jonathan Stern
Oxford Institute for Energy Studies, United Kingdom
Wim Thomas
Independent consultant
General Secretariat of the Prime Minister of the Hellenic
Nikos Tsafos
Republic
James Turnure
US Energy Information Administration
Fridtjof Fossum Unander
Aker Horizons
International Partnership for Hydrogen and Fuel Cells
Noé Van Hulst
in the Economy
David Victor
University of California, San Diego, United States
Acknowledgements

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IEA. CC BY 4.0.

Jan Petter Nore
Andi Novianto
Stefan Nowak
Thomas Nowak
Kentaro Oe
Pak Yongduk
Ignacio Perez Arriaga

Andrew Walker
Peter Wood
Christian Zinglersen

Cheniere Energy
Shell
European Union Agency for the Cooperation ofEnergy Regulators

The work reflects the views of the International Energy Agency Secretariat, but does notnecessarily reflect those of individual IEA member countries or of any particular funder,
supporter or collaborator. None of the IEA or any funder, supporter or collaborator that
contributed to this work makes any representation or warranty, express or implied, inrespect of the work’s contents (including its completeness or accuracy) and shall not be
responsible for any use of, or reliance on, the work.
This document and any map included herein are without prejudice to the status of orsovereignty over any territory, to the delimitation of international frontiers and boundaries
and to the name of any territory, city or area.

Comments and questions are welcome and should be addressed to:Laura Cozzi and Tim Gould
Directorate of Sustainability, Technology and Outlooks
International Energy Agency
9, rue de la Fédération
75739 Paris Cedex 15
FranceE‐mail: weo@iea.org

10International Energy Agency | World Energy Outlook 2022

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More information about the World Energy Outlook is available at www.iea.org/weo.

IEA. CC BY 4.0.

TABLE OFTABLE
OFCONTENTSCONTENTS

PART A: OVERVIEW AND CONTEXT
Overview and key findings

29

Setting the scene

83

PART B: ROADMAP TO NET ZERO EMISSIONS
An updated roadmap to Net Zero Emissions by 2050

121PART C: KEY ENERGY TRENDS
Energy security in energy transitions

181

Outlook for energy demand

233

Outlook for electricity

277

Outlook for liquid fuels

325

Outlook for gaseous fuels

365

Outlook for solid fuels

409

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ANNEXESForeword

3

Acknowledgements

5

Executive summary

19

Part A: Overview and context

27

Overview and key findings

29

1.1 Introduction

32

1.2 Causes of the crisis and immediate consequences

33

1.2.1

Causes of the crisis

33

1.2.2

Immediate consequences36

1.3 Outlook for energy markets and security

42

1.3.1

Trends and vulnerabilities across the energy mix

44

1.3.2

Is a messy transition unavoidable?

58

1.4 Outlook for energy transitions

2

63

1.4.1

Selected country and regional trends

66

1.4.2

Keeping the door to 1.5 °C open

72

Setting the scene

83

2.1 Introduction

86

2.2 Background to the global energy crisis

87

2.2.1

Initial signs of strain

87

2.2.2

Russia’s invasion of Ukraine

88

2.2.3

Economic consequences

92

2.3 Where do we go from here?

97

2.3.1

Investment and trade responses

97

2.3.2

Policy responses

102

2.3.3

World Energy Outlook‐2022 scenarios

105

2.4 Inputs to the scenarios

107

2.4.1

Economic and population assumptions

107

2.4.2

Energy, mineral and carbon prices

110

2.4.3

Technology costs

115

Part B: Road to net zero emissions
3

14

119

An updated roadmap to Net Zero Emissions by 2050

121

Introduction

124

World Energy Outlook 2022

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1

Net Zero Emissions Scenario
Emissions and temperature trends

125

3.2

Energy trends

128

3.3

Fuel supply

133

3.4

Electricity generation

136

3.5

Industry141

3.6

Transport

146

3.7

Buildings

150
155

3.8

Avoiding growth in energy demand

3.9

What are the public and private investments needed to 2030? 163

3.10

Can we ramp up low‐emissions technologies fast enough?

166

3.11

Energy employment: an opportunity and a bottleneck in the
NZE Scenario

175

Part C: Key energy trends
Energy security in energy transitions

155

179
181

Introduction

184

Ten essentials for secure energy transitions

186

4.1

Synchronise scaling up a range of clean energy technologies
with scaling back of fossil fuels

186

4.2

Tackle the demand side and prioritise energy efficiency

191

4.3

Reverse the slide into energy poverty and give poor
communities a lift into the new energy economy

195

4.4

Collaborate to bring down the cost of capital in emerging
market and developing economies

200

4.5

Manage the retirement and reuse of existing infrastructure
carefully, some of it will be essential for a secure journey to
net zero emissions

204

4.6

Tackle the specific risks facing producer economies

209

4.7

Invest in flexibility – a new watchword for electricity security

214

4.8

Ensure diverse and resilient clean energy supply chains

217

4.9

Foster the climate resilience of energy infrastructure

223

4.10

Provide strategic direction and address market failures,but do not dismantle markets

228

Conclusion

Table of Contents

232

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Key themes

4

125

3.1

Outlook for energy demand

233

Introduction

236

Scenarios

236

5.1

Overview

236

5.2

Energy demand

241

5.3

Emissions

249

5.4

Air pollution

255

5.5

Investment

257

Key themes

6

259

5.6

Energy access

259

5.7

Efficient cooling for a warming world

266

5.8

Bringing forward the peak in oil use for road transport

272

Outlook for electricity

277

Introduction

280

Scenarios

281

6.1

Overview

281

6.2

Electricity demand

283

6.3

Electricity supply

290

6.4

CO₂ emissions from electricity generation

303

6.5

Investment

305

Key themes

7

16

307

6.6

Power system flexibility is key to electricity security

307

6.7

Electricity networks are the backbone of clean power systems

312

6.8

Critical minerals underpin future clean electricity systems

318

Outlook for liquid fuels

325

Introduction

328

Scenarios

329

7.1

Overview

329

7.2

Oil demand by region and sector

331

7.3

Oil supply

336

7.4

Oil trade

341

7.5

Oil investment

342

7.6

Liquid biofuels

343

7.7

Low‐emissions hydrogen‐based liquid fuels

345

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5Key themes
Oil use in plastics

347

7.9

Are new conventional oil projects an answer to today’s
energy crisis?

352

Refining: immediate and longer term challenges

357

Outlook for gaseous fuels

365

Introduction

368

Scenarios

369

8.1

Overview369

8.2

Gas demand

372

8.3

Gas supply

377

8.4

Gas trade

381

8.5

Investment

383

Key themes

9

386

8.6

Outlook for natural gas in the European Union after
Russia’s invasion of Ukraine

386

8.7

Scaling up hydrogen

395

8.8

Is natural gas still a transition fuel in emerging market anddeveloping economies in Asia?

402

Outlook for solid fuels

409

Introduction

411

Scenarios

412

9.1

Overview

412

9.2

Coal demand

414

9.3

Coal supply

418

9.4

Coal trade

421

9.5

Coal investment

422

9.6

Solid bioenergy

423

Annexes429

Annex A. Tables for scenario projections

431

Annex B. Design of the scenarios

463

Annex C. Definitions

485

Annex D. References

505

Annex E. Inputs to the Global Energy and Climate Model

517

Table of Contents

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7.10
8

347

7.8

Executive Summary
Russia’s invasion of Ukraine has sparked a global energy crisis
The world is in the midst of its first global energy crisis – a shock of unprecedented breadthand complexity. Pressures in markets predated Russia’s invasion of Ukraine, but Russia’s
actions have turned a rapid economic recovery from the pandemic – which strained allmanner of global supply chains, including energy – into full‐blown energy turmoil. Russia has
been by far the world’s largest exporter of fossil fuels, but its curtailments of natural gas
supply to Europe and European sanctions on imports of oil and coal from Russia are severing
one of the main arteries of global energy trade. All fuels are affected, but gas markets are
the epicentre as Russia seeks leverage by exposing consumers to higher energy bills andsupply shortages.
Prices for spot purchases of natural gas have reached levels never seen before, regularly
exceeding the equivalent of USD 250 for a barrel of oil. Coal prices have also hit record
levels, while oil rose well above USD 100 per barrel in mid‐2022 before falling back. High gas
and coal prices account for 90% of the upward pressure on electricity costs around the world.
To offset shortfalls in Russian gas supply, Europe is set to import an extra 50 billion cubic
metres (bcm) of liquefied natural gas (LNG) in 2022 compared with the previous year. Thishas been eased by lower demand from China, where gas use was held back by lockdowns
and subdued economic growth, but higher European LNG demand has diverted gas awayfrom other importers in Asia.
The crisis has stoked inflationary pressures and created a looming risk of recession, as well
as a huge USD 2 trillion windfall for fossil fuel producers above their 2021 net income.
Higher energy prices are also increasing food insecurity in many developing economies, withthe heaviest burden falling on poorer households where a larger share of income is spent onenergy and food. Some 75 million people who recently gained access to electricity are likely
to lose the ability to pay for it, meaning that for the first time since we started tracking it, thetotal number of people worldwide without electricity access has started to rise. And almost
100 million people may be pushed back into reliance on firewood for cooking instead ofcleaner, healthier solutions.
Faced with energy shortfalls and high prices, governments have so far committed well over
USD 500 billion, mainly in advanced economies, to shield consumers from the immediate
impacts. They have rushed to try and secure alternative fuel supplies and ensure adequate
gas storage. Other short‐term actions have included increasing oil‐ and coal‐fired electricity
generation, extending the lifetimes of some nuclear power plants, and accelerating the flowof new renewables projects. Demand‐side measures have generally received less attention,
but greater efficiency is an essential part of the short‐ and longer‐term response.

With energy markets remaining extremely vulnerable, today’s energy shock is a reminderof the fragility and unsustainability of our current energy system. A key question for policy
makers, and for this Outlook, is whether the crisis will be a setback for clean energy
transitions or will catalyse faster action. Climate policies and net zero commitments were
Executive Summary

19

IEA. CC BY 4.0.

Is the crisis a boost, or a setback, for energy transitions?

blamed in some quarters for contributing to the run‐up in energy prices, but there is scantevidence for this. In the most affected regions, higher shares of renewables were correlatedwith lower electricity prices, and more efficient homes and electrified heat have provided an
important buffer for some – but far from enough – consumers.
Times of crisis put the spotlight on governments, and on how they react. Alongside short‐term measures, many governments are now taking longer‐term steps: some seeking toincrease or diversify oil and gas supply; many looking to accelerate structural change. The
three scenarios explored in this World Energy Outlook (WEO) are differentiated primarily by
the assumptions made on government policies. The Stated Policies Scenario (STEPS) shows
the trajectory implied by today’s policy settings. The Announced Pledges Scenario (APS)
assumes that all aspirational targets announced by governments are met on time and in full,including their long‐term net zero and energy access goals. The Net Zero Emissions by 2050
(NZE) Scenario maps out a way to achieve a 1.5 °C stabilisation in the rise in global averagetemperatures, alongside universal access to modern energy by 2030.

Policy responses are fast‐tracking the emergence of a clean energy economy

As markets rebalance, renewables, supported by nuclear power, see sustained gains; theupside for coal from today’s crisis is temporary. The increase in renewable electricity
generation is sufficiently fast to outpace growth in total electricity generation, driving down
the contribution of fossil fuels for power. The crisis briefly pushes up utilisation rates forexisting coal‐fired assets, but does not bring higher investment in new ones. Strengthened
policies, a subdued economic outlook and high near‐term prices combine to moderate
overall energy demand growth. Increases come primarily from India, Southeast Asia, Africa
and the Middle East. However, the rise in China’s energy use, which has been such animportant driver for global energy trends over the past two decades, slows and then halts
altogether before 2030 as China shifts to a more services‐orientated economy.
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New policies in major energy markets help propel annual clean energy investment to morethan USD 2 trillion by 2030 in the STEPS, a rise of more than 50% from today. Clean energy
becomes a huge opportunity for growth and jobs, and a major arena for international
economic competition. By 2030, thanks in large part to the US Inflation Reduction Act, annual
solar and wind capacity additions in the United States grow two‐and‐a‐half‐times overtoday’s levels, while electric car sales are seven times larger. New targets continue to spur
the massive build‐out of clean energy in China, meaning that its coal and oil consumption
both peak before the end of this decade. Faster deployment of renewables and efficiency
improvements in the European Union bring down EU natural gas and oil demand by 20% thisdecade, and coal demand by 50%, a push given additional urgency by the need to find newsources of economic and industrial advantage beyond Russian gas. Japan’s Green
Transformation (GX) programme provides a major funding boost for technologies including
nuclear, low‐emissions hydrogen and ammonia, while Korea is also looking to increase theshare of nuclear and renewables in its energy mix. India makes further progress towards its
domestic renewable capacity target of 500 gigawatts (GW) in 2030, and renewables meetnearly two‐thirds of the country’s rapidly rising demand for electricity.

International energy trade undergoes a profound reorientation in the 2020s as countries
adjust to the rupture of Russia‐Europe flows, which is assumed to be permanent. Not all
Russian flows displaced from Europe find a new home in other markets, bringing down
Russian production and global supply. Crude oil and product markets, especially diesel, facea turbulent period as EU bans on Russian imports kick in. Natural gas takes longer to adjust.
The upcoming northern hemisphere winter promises to be a perilous moment for gas
markets and a testing time for EU solidarity – and the winter of 2023‐24 could be eventougher. Major new additions to LNG supply – mainly from North America, Qatar and Africa– arrive only around the mid‐2020s. Competition for available cargoes is fierce in themeantime as Chinese import demand picks up again.

Today’s stronger policy settings bring a fossil fuel peak into view
For the first time, a WEO scenario based on prevailing policy settings has global demandfor each of the fossil fuels exhibiting a peak or plateau. In the STEPS, coal use falls backwithin the next few years, natural gas demand reaches a plateau by the end of the decade,and rising sales of electric vehicles (EVs) mean that oil demand levels off in the mid‐2030s
before ebbing slightly to mid‐century. Total demand for fossil fuels declines steadily from themid‐2020s by around 2 exajoules per year on average to 2050, an annual reduction roughly
equivalent to the lifetime output of a large oil field.

Full achievement of all climate pledges would move the world towards safer ground, butthere is still a large gap between today’s ambitions and a 1.5 °C stabilisation. In the APS, anear‐term peak in annual emissions is followed by a faster decline to 12 Gt by 2050. This is abigger reduction than in the WEO‐2021 APS, reflecting the additional pledges that have been
made over the past year, notably by India and Indonesia. If implemented on time and in full,these additional national commitments – as well as sectoral commitments for specificindustries and company targets (considered for the first time in this year’s APS) – keep thetemperature rise in the APS in 2100 at around 1.7 °C. However, it is easier to make pledges
than to implement them and, even if they are achieved, there is still considerably further to
go to align with the NZE Scenario, which achieves the 1.5 °C outcome by reducing annual
emissions to 23 Gt by 2030 and to net zero by 2050.
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Global fossil fuel use has risen alongside GDP since the start of the Industrial Revolution in
the 18th century: putting this rise into reverse while continuing to expand the global
economy will be a pivotal moment in energy history. The share of fossil fuels in the global
energy mix has been stubbornly high, at around 80%, for decades. By 2030 in the STEPS, thisshare falls below 75%, and to just above 60% by 2050. A high point for global energy‐related
CO2 emissions is reached in the STEPS in 2025, at 37 billion tonnes (Gt) per year, and they fallback to 32 Gt by 2050. This would be associated with a rise of around 2.5 °C in global averagetemperatures by 2100. This is a better outcome than projected a few years ago: renewed
policy momentum and technology gains made since 2015 have shaved around 1 °C off thelong‐term temperature rise. However, a reduction of only 13% in annual CO2 emissions to2050 in the STEPS is far from enough to avoid severe impacts from a changing climate.

Led by clean electricity, some sectors are poised for a faster transformation
The world is in a critical decade for delivering a more secure, sustainable and affordable
energy system – the potential for faster progress is enormous if strong action is taken
immediately. Investments in clean electricity and electrification, along with expanded andmodernised grids, offer clear and cost‐effective opportunities to cut emissions more rapidly
while bringing electricity costs down from their current highs. Today’s growth rates for
deployment of solar PV, wind, EVs and batteries, if maintained, would lead to a much fastertransformation than projected in the STEPS, although this would require supportive policies
not just in the leading markets for these technologies but across the world. By 2030, if
countries deliver on their climate pledges, every second car sold in the European Union,
China and the United States is electric.
Supply chains for some key technologies – including batteries, solar PV and electrolysers –are expanding at rates that support higher global ambition. If all announced manufacturing
expansion plans for solar PV see the light of day, manufacturing capacity would exceed thedeployment levels in the APS in 2030 by around 75% and approach the levels required in the
NZE Scenario. In the case of electrolysers for hydrogen production, the potential excess
capacity of all announced projects relative to APS deployment in 2030 is around 50%. In the
EV sector, the expansion of battery manufacturing capacity reflects the shift underway in theautomotive industry, which at times has moved faster than governments in setting targets
for electrified mobility. These clean energy supply chains are a huge source of employment
growth, with clean energy jobs already exceeding those in fossil fuels worldwide andprojected to grow from around 33 million today to almost 55 million in 2030 in the APS.

Efficiency and clean fuels get a competitive boost

Concerns about fuel prices, energy security and emissions – bolstered by stronger policy
support – are brightening the prospects for many low‐emissions fuels. Investment in low‐emissions gases is set to rise sharply in the coming years. In the APS, global low‐emissionshydrogen production rises from very low levels today to reach over 30 million tonnes (Mt)
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Today’s high energy prices underscore the benefits of greater energy efficiency and areprompting behavioural and technology changes in some countries to reduce energy use.
Efficiency measures can have dramatic effects – today’s light bulbs are at least four times
more efficient than those on sale two decades ago – but much more remains to be done.
Demand for cooling needs to be a particularly focus for policy makers, as it makes the second‐largest contribution to the overall rise in global electricity demand over the coming decades(after EVs). Many air conditioners used today are subject only to weak efficiency standards
and one‐fifth of electricity demand for cooling in emerging and developing economies is notcovered by any standards at all. In the STEPS, cooling demand in emerging and developing
economies rises by 2 800 terawatt‐hours to 2050, which is the equivalent of adding another
European Union to today’s global electricity demand. This growth is reduced by half in the
APS because of tighter efficiency standards and better building design and insulation – andby half again in the NZE Scenario.

per year in 2030, equivalent to over 100 bcm of natural gas (although not all low‐emissionshydrogen would replace natural gas). Much of this is produced close to the point of use, butthere is growing momentum behind international trade in hydrogen and hydrogen‐based
fuels. Projects representing a potential 12 Mt of export capacity are in various stages ofplanning, although these are more numerous and more advanced than corresponding
projects to underpin import infrastructure and demand. Carbon capture, utilisation andstorage projects are also advancing more rapidly than before, spurred by greater policy
support to aid industrial decarbonisation, to produce low‐ or lower‐emissions fuels, and toallow for direct air capture projects that remove carbon from the atmosphere.

But rapid transitions ultimately depend on investment
A huge increase in energy investment is essential to reduce the risks of future price spikes
and volatility, and to get on track for net zero emissions by 2050. From USD 1.3 trillion
today, clean energy investment rises above USD 2 trillion by 2030 in the STEPS, but it would
have to be above USD 4 trillion by the same date in the NZE Scenario, highlighting the need
to attract new investors to the energy sector. Governments should take the lead and provide
strong strategic direction, but the investments required are far beyond the reaches of publicfinance. It is vital to harness the vast resources of markets and incentivise private actors toplay their part. Today, for every USD 1 spent globally on fossil fuels, USD 1.5 is spent on clean
energy technologies. By 2030, in the NZE Scenario, every USD 1 spent on fossil fuels isoutmatched by USD 5 on clean energy supply and another USD 4 on efficiency and end‐uses.

The speed at which investors react to broad and credible transition frameworks depends
in practice on a host of more granular issues. Supply chains are fragile, and infrastructureand skilled labour are not always available. Permitting provisions and deadlines are often
complex and time‐consuming. Clear procedures for project approval, supported by adequate
administrative capacity, are vital to accelerate the flow of viable, investable projects – bothfor clean energy supply as well as for efficiency and electrification. Our analysis finds that
permitting and construction of a single overhead electricity transmission line can take up to
13 years, with some of the longest lead times in advanced economies. Developing new
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Shortfalls in clean energy investment are largest in emerging and developing economies, aworrying signal given their rapid projected growth in demand for energy services. If China
is excluded, then the amount being invested in clean energy each year in emerging anddeveloping economies has remained flat since the Paris Agreement was concluded in 2015.
The cost of capital for a solar PV plant in 2021 in key emerging economies was between two‐and three‐times higher than in advanced economies and China. Today’s rising borrowing
costs could exacerbate the financing challenges facing such projects, despite their favourable
underlying costs. A renewed international effort is needed to step up climate finance andtackle the various economy‐wide or project‐specific risks that deter investors. There isimmense value in broad national transition strategies such as the Just Energy Transition
Partnerships with Indonesia, South Africa and other countries, that integrate international
support and ambitious national policy actions while also providing safeguards for energy
security and the social consequences of change.

deposits of critical minerals has historically taken over 16 years on average, with 12 years
spent lining up all aspects of permitting and financing and 4‐5 years for construction.

What if transitions don’t pick up?
If clean energy investment does not accelerate as in the NZE Scenario then higher
investment in oil and gas would be needed to avoid further fuel price volatility, but thiswould also mean putting the 1.5 °C goal in jeopardy. In the STEPS, an average of almost
USD 650 billion per year is spent on upstream oil and natural gas investment to 2030, a riseof more than 50% compared with recent years. This investment comes with risks, bothcommercial and environmental, and cannot be taken for granted. Despite huge windfalls thisyear, some Middle East producers are the only part of the upstream industry investing more
today than prior to the Covid‐19 pandemic. Amid concerns about cost inflation, capitaldiscipline rather than production growth has become the default setting for the US shaleindustry, meaning that some of the wind has gone from the sails of the main source of recent
global oil and gas growth.
Immediate shortfalls in fossil fuel production from Russia will need to be replaced byproduction elsewhere – even in a world working towards net zero emissions by 2050. The
most suitable near‐term substitutes are projects with short lead times that bring oil and gas
to market quickly, as well as capturing some of the 260 bcm of gas that is wasted each year
through flaring and methane leaks to the atmosphere. But lasting solutions to today’s crisis
lie in reducing fossil fuel demand. Many financial organisations have set goals and plans toscale down investment in fossil fuels. Much more emphasis is needed on goals and plans for
scaling up investment in clean energy transitions, and on what governments can do to
incentivise this.

Russia loses out in the reshuffling of international trade

Russia’s reorientation to Asian markets is particularly challenging in the case of natural gas,as the market opportunity for large‐scale additional deliveries to China is limited. Russia istargeting new pipeline links to China, notably the large‐capacity Power of Siberia‐2 pipeline
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Russia’s invasion of Ukraine is prompting a wholesale reorientation of global energy trade,leaving Russia with a much‐diminished position. All Russia’s trade ties with Europe basedon fossil fuels had ultimately been undercut in our previous scenarios by Europe’s net zeroambitions, but Russia’s ability to deliver at relatively low cost meant that it lost ground only
gradually. Now the rupture has come with a speed that few imagined possible. In this
Outlook, more Russian resources are drawn eastwards to Asian markets, but Russia is
unsuccessful in finding markets for all of the flows that previously went to Europe. In 2025,
Russia’s oil production is 2 million barrels a day lower than in the WEO‐2021 and gas
production is down by 200 bcm. Longer‐term prospects are weakened by uncertainties overdemand, as well as restricted access to international capital and technologies to develop
more challenging fields and LNG projects. Russian fossil fuel exports never return – in any of
our scenarios – to the levels seen in 2021, and its share of internationally traded oil and gas
falls by half by 2030 in the STEPS.

through Mongolia. However, our demand projections for China raise considerable doubts
about the viability of another large‐scale gas link with Russia, once the existing Power ofSiberia line ramps up to full capacity. In the STEPS, China’s gas demand growth slows to 2%
per year between 2021 and 2030, compared with an average growth rate of 12% per year
since 2010, reflecting a policy preference for renewables and electrification over gas use forpower and heat. Chinese importers have been actively contracting for new long‐term LNG
supplies, and China already has adequate contracted supply to meet projected demand in
the STEPS until well into the 2030s.

Were the 2010s the “golden age of gas”?
One of the effects of Russia’s actions is that the era of rapid growth in natural gas demanddraws to a close. In the STEPS, the scenario that sees the highest gas consumption, global
demand rises by less than 5% between 2021 and 2030 and then remains flat at around
4 400 bcm through to 2050. The outlook for gas is dampened by higher near‐term prices;more rapid deployment of heat pumps and other efficiency measures; higher renewables
deployment and a faster uptake of other flexibility options in the power sector; and, in somecases, reliance on coal for slightly longer. The Inflation Reduction Act cuts projected US
natural gas demand in 2030 in the STEPS by more than 40 bcm compared with last year’s
projections, freeing up gas for export. Stronger climate policies accelerate Europe’s
structural shift away from gas. New supply brings prices down by the mid‐2020s, and LNG
becomes even more important to overall gas security. But momentum behind natural gas
growth in developing economies has slowed, notably in South and Southeast Asia, putting adent in the credentials of gas as a transition fuel. Most of the downward revision to gas
demand to 2030 in this year’s STEPS is due to a faster switch to clean energy, although aroundone‐quarter is because gas loses out to coal and oil.

A new energy security paradigm is needed to maintain reliability and affordability while
reducing emissions. This Outlook includes ten principles that can help guide policy makers
through the period when declining fossil fuel and expanding clean energy systems co‐exist.
During energy transitions, both systems are required to function well in order to deliver theenergy services needed by consumers, even as their respective contributions change overtime. Maintaining electricity security in tomorrow’s power systems calls for new tools, more
flexible approaches and mechanisms to ensure adequate capacities. Power generators willneed to be more responsive, consumers will need to be more connected and adaptable, andgrid infrastructure will need to be strengthened and digitalised. Inclusive, people‐centred
approaches are essential to allow vulnerable communities to manage the upfront costs ofcleaner technologies and ensure that the benefits of transitions are felt widely acrosssocieties. Even as transitions reduce fossil fuel use, there are parts of the fossil fuel systemthat remain critical to energy security, such as gas‐fired power for peak electricity needs, or
refineries to supply residual users of transport fuels. Unplanned or premature retirement of
this infrastructure could have negative consequences for energy security.
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A focus on affordable, secure transitions based on resilient supply chainsAs the world moves on from today’s energy crisis, it needs to avoid new vulnerabilities
arising from high and volatile critical mineral prices or highly concentrated clean energy
supply chains. If not adequately addressed, these issues could delay energy transitions or
make them more costly. Demand for critical minerals for clean energy technologies is set torise sharply, more than doubling from today’s level by 2030 in the APS. Copper sees thelargest increase in terms of absolute volumes, but other critical minerals experience much
faster rates of demand growth, notably silicon and silver for solar PV, rare earth elements forwind turbine motors and lithium for batteries. Continued technology innovation andrecycling are vital options to ease strains on critical minerals markets. High reliance on
individual countries such as China for critical mineral supplies and for many clean technology
supply chains is a risk for transitions, but so too are diversification options that close off thebenefits of trade.

The energy crisis promises to be a historic turning point towards a cleaner
and more secure energy system

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Energy markets and policies have changed as a result of Russia’s invasion of Ukraine, notjust for the time being, but for decades to come. The environmental case for clean energy
needed no reinforcement, but the economic arguments in favour of cost‐competitive andaffordable clean technologies are now stronger – and so too is the energy security case. Thisalignment of economic, climate and security priorities has already started to move the dial
towards a better outcome for the world’s people and for the planet. Much more remains to
be done, and as these efforts gather momentum, it is essential to bring everyone on board,
especially at a time when geopolitical fractures on energy and climate are all the more visible.
This means redoubling efforts to ensure that a broad coalition of countries has a stake in the
new energy economy. The journey to a more secure and sustainable energy system may not
be a smooth one. But today’s crisis makes it crystal clear why we need to press ahead.

PART AOVERVIEW AND CONTEXTPart A of the World Energy Outlook provides the starting
point for this year’s energy projections and gives an overview
of some of the key findings.
Chapter 1 explores the causes of today’s global energy crisisand the consequences. It provides projections for energy
markets and energy security through three scenarios andexamines what those outlooks imply for energy‐related
emissions and achievement of the world’s sustainable
development goals.

IEA. CC BY 4.0.

Chapter 2 examines the various forces that are impacting theenergy sector today and the policy responses, and assesses
the implications for our Outlook in 2022. It also details thebasis of each of the three main scenarios and how and why
they differ.

Chapter 1
Overview and key findings
Global energy crisis: causes and implications
S U M M A R Y
 The global energy crisis sparked by Russia’s invasion of Ukraine is having far‐reaching
implications for households, businesses and entire economies, prompting short‐term
responses from governments as well as a deeper debate about the ways to reduce
the risk of future disruptions and promote energy security. This is a global crisis, but
Europe is the main theatre in which it is playing out, and natural gas is centre stage –especially during the coming northern hemisphere winter.

 High energy prices are causing a huge transfer of wealth from consumers to
producers, back to the levels seen in 2014 for oil, but entirely unprecedented fornatural gas. High fuel prices account for 90% of the rise in the average costs ofelectricity generation worldwide, natural gas alone for more than 50%. The costs ofrenewables and carbon dioxide have played only a marginal role, underscoring that
this is a crisis where energy transitions are the solution, rather than the problem.

 Price and economic pressures mean that the number of people without access tomodern energy is rising for the first time in a decade. Around 75 million people who
recently gained access to electricity are likely to lose the ability to pay for it, and100 million people may revert to the use of traditional biomass for cooking.

 There remain huge uncertainties over how this energy crisis will evolve and for how
long fossil fuel prices will remain elevated, and the risks of further energy disruption
and geopolitical fragmentation are high. In all our scenarios, price pressures and a dimnear‐term outlook for the global economy feed through into lower energy demandthan in last year’s Outlook.

 The crisis provides a short‐term boost to demand for oil and coal as consumers
scramble for alternatives to high priced gas. But the lasting gains from the crisis accrue
to low‐emissions sources, mainly renewables, but also nuclear in some cases,
alongside faster progress with efficiency and electrification, e.g. electric vehicles.

 In the Stated Policies Scenario (STEPS), global energy demand growth of around 1%
per year to 2030 is met in aggregate almost entirely by renewables. Emerging market
and developing economies, such as India, see increases across a broader range of fuels
and technologies, while the only sources to show growth in advanced economies to2030 are low‐emissions.

 The cost advantages of mature clean energy technologies and the prospects for new

 The STEPS in this Outlook is the first World Energy Outlook (WEO) scenario based onprevailing policy settings that sees a definitive peak in global demand for fossil fuels.
Chapter 1 | Overview and key findings

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ones, such as low‐emissions hydrogen, are boosted by the Inflation Reduction Act in
the United States, Europe’s increased push for clean energy, and other major new
policies. The result is to turbo‐charge the emerging global clean energy economy.

Coal demand peaks in the next few years, natural gas demand reaches a plateau by
the end of the decade, and oil demand reaches a high point in the mid‐2030s before
falling slightly. From 80% today – a level that has been constant for decades – theshare of fossil fuels in the global energy mix falls to less than 75% by 2030 and to justabove 60% by mid‐century. In the Announced Pledges Scenario (APS), the drive tomeet climate pledges in full sends demand for all the fossil fuels into decline by 2030.

 With the loss of its largest export market in Europe, Russia faces the prospect of amuch‐diminished role in international energy affairs. 2021 proves to be a high‐watermark for Russian export flows. Its share of internationally traded gas, which stood at
30% in 2021, falls to 15% by 2030 in the STEPS and to 10% in the APS. Importers in
China have been actively contracting for liquefied natural gas, and there is no room in
China’s projected gas balance for another large‐scale pipeline from Russia.

 Energy‐related CO2 emissions rebounded to 36.6 Gt in 2021, the largest ever annual
rise in emissions. In the STEPS, they reach a plateau around 37 Gt before falling slowly
to 32 Gt in 2050, a trajectory that would lead to a 2.5 °C rise in global averagetemperatures by 2100. This is around 1 °C lower than implied by the baseline
trajectory prior to the Paris Agreement, indicating the progress that has been madesince then. But much more needs to be done. In the APS, emissions peak in themid‐2020s and fall to 12 Gt in 2050, resulting in a projected global mediantemperature rise in 2100 of 1.7 °C. In the Net Zero Emissions by 2050 (NZE) Scenario,
CO2 emissions fall to 23 Gt in 2030 and to zero in 2050, a trajectory consistent withlimiting the temperature increase to less than 1.5 °C in 2100.

 Planned increases in global clean energy manufacturing capacity provide a leading
indicator of the potential for rapid increases in deployment. In the case of heatpumps, current and planned manufacturing capacity is below the deployment levels
projected in the APS. But announced global manufacturing capacity for electrolysers
and solar PV modules in 2030 is sufficient not only to reach APS deployment levels
but to go beyond them.

 One point common to each scenario is the rising share of electricity in global final
energy consumption. From 20% today, this increases in each scenario, reaching morethan 50% by mid‐century in the NZE Scenario. This is associated with a huge overall
increase in global electricity demand – with the bulk of this growth coming fromemerging market and developing economies – and the need for constant vigilancefrom policy makers to a range of risks to electricity security, in particular the everincreasing need for flexible operation of power systems.

 The world has not been investing enough in energy in recent years, a fact that left theenergy system much more vulnerable to the sort of shocks seen in 2022. A smoothand secure energy transition will require a major uptick in clean energy investment
flows. Getting on track for the NZE Scenario will require a tripling in spending on clean
energy and infrastructure to 2030, alongside a shift towards much higher investment
in emerging market and developing economies.
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Huge transfers fromconsumers to producers:0.8

Oil has been expensive before, but there is noprecedent for the import bills for natural gas in 2022.

Central andSouth America

Eurasia
Middle East

AfricaOther

Trillion USD

0.4

Gas exporters
Gas importers
2006

2016

2010

2008

2012

2020

2018

2014

Other

Asia Pacific

0

-0.4

Europe

53
2022
-0.8

Emissions have tocome down
Policy and technology changes since
the Paris Agreement in 2015 have
reduced the projected temperature rise,
but there’s still a long way to go to cap
global warming at 1.5 °C.

36 Gt CO2

32

12.3

Emissions
2030
2021

2040

4

Net Zero

2050

Pre-Paris
Agreement
APS

NZE

3
2

STEPS

1
0 °C

Median temperature rise in 2100

2 400

A shock to the system

Index (1 September 2020 = 100)
2 000

Russia’s invasion of Ukraine has led to a periodof extraordinary turbulence in energy markets,
especially for natural gas.

Europe natural gas (TTF)

1 600

German power

Asian spot LNG
EU imported coalOct 20Dec 20Feb 21

Apr 21

Jun 21Aug 21

North Sea Brent

Oct 21

Dec 21

Feb 22

Apr 22Jun 22Aug 22

1.1

Introduction

Each energy crisis has echoes of the past, and the acute strains on markets today are drawing
comparison with the most severe energy disruptions in modern energy history, most notably
the oil shocks of the 1970s. Then, as now, there were strong geopolitical drivers for the risein prices, which led to high inflation and economic damage. Then, as now, the crises brought
to the surface some underlying fragilities and dependencies in the energy system. Then, as
now, high prices created strong economic incentives to act, and those incentives were
reinforced by considerations of economic and energy security.
But today’s global energy crisis is significantly broader and more complex than those thatcame before. The shocks in the 1970s were about oil, and the task facing policy makers was
relatively clear (if not necessarily simple to implement): reduce dependence on oil, especially
oil imports. By contrast, the energy crisis today has multiple dimensions: natural gas, but alsooil, coal, electricity, food security and climate. Therefore, the solutions are similarly all
encompassing. Ultimately what is required is not just to diversify away from a single energy
commodity, but to change the nature of the energy system itself, and to do so while
maintaining the affordable, secure provision of energy services.
This Outlook explores how this change might play out, and what pitfalls and opportunities
may be encountered along the way. Each scenario is based on a different vision of how policy
makers might respond to today’s crisis. In the Stated Policies Scenario (STEPS), we explore
how the energy system evolves if we retain current policy settings. These include the latest
policy measures adopted by governments around the world, such as the Inflation Reduction
Act in the United States, but do not assume that aspirational or economy‐wide targets are
met unless they are backed up with detail on how they are to be achieved.

Each scenario meets current energy security and climate challenges in different ways and todifferent extents, but the starting point for today’s decision makers is fundamentallydifferent from that facing their counterparts in the 1970s. The climate and environmental
challenges are much more acute, due to a half‐century of rising emissions. But the clean
technology choices available today are also much more mature and cost competitive,
providing options for much more efficient energy use, cleaner energy production andgeneration, and new kinds of storage. As a result, many of the component parts of a new
type of energy system are clearly visible. The question is how effectively and quickly they canbe deployed alongside traditional technologies, and then in place of them.

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In the Announced Pledges Scenario (APS), governments get the benefit of the doubt. In this
scenario, their targets are achieved on time and in full, whether they relate to climatechange, energy systems or national pledges in other areas such as energy access. Trends inthis scenario reveal the extent of the world’s collective ambition, as it stands today, to tackle
climate change and meet other sustainable development goals. Only in the Net Zero
Emissions by 2050 (NZE) Scenario, do we work back from specific goals – the main one inthis case being to cap global warming to 1.5 °C – and show how they can be achieved.

1.2

Causes of the crisis and immediate consequences

1.2.1

Causes of the crisis

1

The world is facing a global energy crisis of unprecedented depth and complexity. This ishaving far‐reaching implications for many households, businesses and entire economies,
prompting a range of short‐term responses from governments as well as a deeper debate
about the ways to avoid such disruptions in the future. Pressures on markets predated theRussian Federation’s (hereinafter Russia) invasion of Ukraine, but its actions have tipped
what was a strong recovery from the pandemic – strong enough to strain weakened supply
chains and production capacity – into full‐blown turmoil in energy markets, causing severe
damage to the global economy.
This is a global crisis, but Europe is the main theatre in which it is playing out, and natural gas
is centre stage. Russia is seeking to gain political leverage by withholding gas supplies andexposing consumers to higher energy bills and supply shortages over the winter heating
season. As of September 2022, Russia’s gas deliveries to the European Union are down by
80% compared to where they have been in recent years. This has naturally created significant
pressure on European and global gas balances. Due to demand for heating, European gas
demand is roughly twice as high during the winter months as during the summer, and is met
by a combination of domestic production (which has been in decline), imports by pipeline
and liquefied natural gas (LNG), and withdrawals from storage (Figure 1.1).
Figure 1.1 ⊳European Union and United Kingdom winter natural gas supply
and options to compensate for a cut in Russian pipeline gas

IEA. CC BY 4.0.

Russian pipeline imports met 20% of gas demand in the European Union in winter 2021-22;

Chapter 1 | Overview and key findings

33

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managing without this gas requires alternative imports, use of storage and lower demandEU gas storage facilities were more than 90% full in early October 2022, a considerable
achievement given the cuts to Russian supply over the course of the year. In combination
with lower demand and continued strong inflows from non‐Russian sources, this opens anarrow but potentially safe pathway for Europe through the northern hemisphere wintermonths, albeit at highly elevated prices, on condition that the weather does not turn too
cold. However, the balances for 2023‐2024 look more challenging.
There are many strands to the energy relationship between Russia and Europe. Russia has
acted to sever the gas relationship. The European Union has halted coal imports from Russia,
meaning that coal deliveries from Europe’s largest external supplier fell to zero as of August2022. For the moment, Russian oil production and exports remain close to pre‐war levels,
despite some countries such as the United States and the United Kingdom imposing
immediate restrictions on oil trade. Some reorientation of trade flows has already takenplace, with lower flows of oil from Russia to the European Union and North America offset
by higher exports to other markets, notably India, China and Türkiye. But the major changes
lie ahead: Russia exported 2.6 million barrels per day (mb/d) of oil to the European Union in
September 2022, and most of these exports will come to an end when an EU ban on seaborne
crude oil imports from Russia enters into force in December 2022 and on a ban on oil
products from Russia (which are mainly middle distillates) takes effect in February 2023.
The proximate cause of the crisis was Russia’s invasion of Ukraine, but pressure on markets
was visible before February 2022. The main reason was the speed of the economic reboundfrom the pandemic‐induced slump in 2020; this stretched all manner of supply chains,
including those in fuel supply. There were also weather‐related factors, a higher incidence ofoutages to supply – often related to maintenance postponed from 2020 as a result of thepandemic – and what the IEA was calling “artificial tightness” in markets. In natural gas
markets, this stemmed in large part from Gazprom’s sluggishness in re‐filling its European
gas storage in the third‐ quarter of 2021, which in retrospect has to be seen in the context ofRussia’s invasion of Ukraine some months later and the pressure subsequently applied toEurope by cutting off gas supplies.

The other side of the investment coin is spending on fossil fuels. This dropped rapidly after
the fall of the oil price in 2014‐15, reflecting lower revenues and investor frustration at thepoor returns that oil and gas companies were generating. In the absence of a much‐needed
acceleration to energy transitions to curb fossil fuel demand, the declines in oil and gas
34

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The key underlying imbalance, which had been some years in the making, relates toinvestment (Figure 1.2). This has been a recurrent theme in IEA analysis in the World Energy
Outlook and World Energy Investment series. For five years after the conclusion of the Paris
Agreement, the amount of investment going into energy transitions remained flat at around
USD 1 trillion per year. Since clean energy technology costs continued to decline during thisperiod, this was enough to generate year‐on‐year increases in deployment. But it remained
far short of the amounts needed to support a thoroughgoing transformation of the energy
system. Only in the last two years, 2021 and 2022, did clean energy spending see a notable
uptick.

investment in the second‐half of the 2010s presented a risk to market balances in the 2020s.
In the WEO‐2016 Executive Summary, for example, we said that “if new project approvals
remain low for a third year in a row in 2017, then it becomes increasingly unlikely thatdemand (as projected in our then New Policies Scenario) and supply can be matched in theearly 2020s without the start of a new boom/bust cycle for the industry”. Natural gas markets
also faced the “risk of a hard landing” (IEA, 2016).
Figure 1.2 ⊳Historical energy investment and GDP trends
Annual change in GDP and investment

Investment as a share of GDP
2.0%

20%

1.5%

10%

1.0%

0%

0.5%

‐10%

2015

1

2017

Clean energy

2019

2021
Fossil fuels

‐20%
2015

2017

2019

Energy investment

2021
GDP
IEA. CC BY 4.0.

Energy investment was subdued from 2015 to 2020; fossil fuel investment dropped after the
2014-2015 oil price fall and clean energy spending did not start to pick up until recently

Acceleration in new approvals failed to materialise, however, at least in part because
uncertainty over long‐term demand led the industry to shy away from large capital‐intensive
projects. Even today, despite higher prices and huge windfall products for the oil and gas
industry in 2022, upstream spending is the only significant segment of the investment picturethat remains below pre‐Covid levels.

Climate policies and net zero emissions commitments were blamed in some quarters forcontributing to the run‐up in prices, but it is difficult to argue that they played a role. Morerapid deployment of clean energy sources and technologies in practice would have helped
to protect consumers and mitigate some of the upward pressure on fuel prices. It would also
Chapter 1 | Overview and key findings

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The other underlying issue that has contributed to the crisis is Europe’s continued high levelof reliance on Russian energy. In 2021, one‐out‐of‐five units of primary energy consumed in
the European Union came from Russia. This reliance on Russia had long been identified as a
strategic weakness, especially after the annexation of Crimea in 2014, and someinfrastructure was built to diversify sources of imports, but Russian flows remained high. In
the case of natural gas, Russia’s share of European gas demand actually rose from 30% on
average in 2005‐10 to reach 40% in 2015‐20.

have mitigated the post‐pandemic rebound in energy‐related carbon dioxide (CO2) emissions
which reached 36.6 gigatonnes (Gt) in 2021. The annual increase of 1.9 Gt was the largest in
history, offsetting the previous year’s pandemic‐induced decline.
Moreover, there is scant evidence to support the notion that net zero emissions pledges havestifled traditional investments in supply, as these pledges are not yet correlated with changes
in fossil fuel spending. Most net zero emissions pledges are recent, and many have yet to betranslated into specific plans and policy measures. Our analysis of fossil fuel investment incountries with net zero emissions pledges (68 countries plus the European Union) shows thatthey are at a similar level to where they were in 2016, and that changes in investment levelsin those countries in recent years are not noticeably different from those that have takenplace in countries without net zero emissions pledges (Figure 1.3).

Billion USD (2021)

Figure 1.3 ⊳Fossil fuel investment in countries with and without
net zero emissions pledges, 2015-22

1 200
1 000
800
600
400
200
2015

2016

With NZE pledges in law

2017

2018

2019

2020

With NZE pledges in policy documents

2021

2022

Without a NZE pledge
IEA. CC BY 4.0.

There are, as yet, few signs that net zero emissions pledges arecorrelated with lower global spending on fossil fuels
Notes: NZE = net zero emissions. Investment is based on countries where investment occurs rather than whereit originates. Status of NZE pledges as of 2022.

Immediate consequences

The most visible consequence of the crisis was an explosion in energy prices. While oil prices
above USD 100/barrel have been seen before, there is no precedent for the price levels seen
in 2022 for natural gas, with prices at Europe’s Title Transfer Facility (TTF) hub regularly
exceeding USD 50 per million British thermal units (MBtu), the equivalent of more than
USD 200/barrel. High fuel prices were the main reason for upward pressure on global
36International Energy Agency | World Energy Outlook 2022

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1.2.2

electricity prices, in our estimation accounting for 90% of the rise in the average costs ofelectricity generation worldwide (natural gas alone for more than 50%). The costs of capital
recovery added only about 5% to the price pressures, as the electricity sector continues toshift towards relatively capital‐intensive technologies like solar PV and wind. The remaining
5% increase in costs was due to higher costs for maintenance and those related to CO2 prices
in several markets.
Figure 1.4 ⊳1Year-on-year increase in average power generation costsby selected country and region, 2022

European Union
India
Korea
Japan
China
Mexico
10%

20%

30%

40%

50%
IEA. CC BY 4.0.

Increases in power generation costs were driven by higher fuel prices andhave been particularly sharp in gas-importing countries and regions

The ripple effects of higher natural gas prices in Europe were felt around the world. One of
the most immediate consequences of Russia’s curtailment of gas deliveries was a sharp
increase in European demand for LNG imports: in the first eight months of 2022, net LNG
imports in Europe rose by two‐thirds (by 45 billion cubic metres [bcm]) compared with thesame period a year earlier. It fell mainly on Asia to balance the market; Asian LNG demandhas fallen year‐on‐year in 2022 for the first time since 2015. Relatively weak demand in the
Chapter 1 | Overview and key findings

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The high cost of natural gas‐fired power – typically the marginal source of generation – wasthe main factor behind a huge rise in EU wholesale electricity prices, with trends also abettedby higher coal, oil and CO2 prices, reduced availability of nuclear power and a poor year forhydropower. Wholesale electricity prices in the European Union tripled in the first‐half of2022, well above the 40% increase in the underlying average costs of generation (Figure 1.4).
This divergence, which produced huge excess revenues for some market participants,
sparked a vigorous debate over the EU electricity market design and whether gas andelectricity prices should somehow be de‐linked.

People’s Republic of China (herein after China), due to slower economic growth and Covid‐
related lockdowns, has been a factor in easing market balances (the same is true for oil),
although this raises questions about what lies ahead when demand in China starts to pick up.
Elsewhere, high prices and shortfalls in supply have led to significant hardship for developing
countries that rely on LNG.

Trillion USD (2021)

Figure 1.5 ⊳Value of natural gas trade, 2005-2022

0.8
Exportingregions

0.4

0Importingregions

‐0.4

‐0.8

2005

Middle East2010
Eurasia

Africa2015
Central and South America

2020
Asia Pacific2022
EuropeOther

IEA. CC BY 4.0.

There is no precedent for the huge increase in payments for traded gas in 2022

The energy crisis is fuelling inflationary pressures, increasing food insecurity and squeezing
household budgets, especially in poor households where a relatively high percentage ofincome is spent on energy and food. The effects of higher natural gas and electricity prices
have been felt acutely across much of Europe. Elsewhere in the world, the consequences
have varied according to the type of economy, but they are clearly negative in overall terms:
the International Monetary Fund cut its expectations of global growth for 2022 from 4.9% in
October 2021 to 3.2% in its October update (IMF, 2022a). Overall, low income countries are
particularly exposed to higher food prices, to which higher energy and fertiliser costs
contribute (Figure 1.6). The crisis has also been a further setback for efforts to improveenergy access (Box 1.1).

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One effect of the current high energy prices is a huge transfer of wealth from consumers to
producers. The sums involved are large but not entirely unprecedented for oil, being similar
to the amounts paid during the early 2010s, and prior to the decline in the oil price in late
2014. But they are extraordinary for natural gas (Figure 1.5). Natural gas is typically the juniorpartner in terms of revenue for hydrocarbon exporters, with the value of international tradein gas averaging around 20% of the total value of traded oil and gas between 2010 and 2021.
This percentage is now set to increase to 40% in 2022.

Figure 1.6 ⊳Contributions of energy and food to inflation in
selected countries, 2022

1

IEA. CC BY 4.0.

Energy is behind many of the inflationary impacts of the crisis in Europe, but higher foodprices – to which energy contributes – are the main driver in many low income countries
Source: IEA analysis based on IMF (2022b).

Box 1.1 ⊳Getting energy access back on track

Due to the combination of the pandemic and the current energy crisis, the IEA estimatesthat 75 million people that recently gained access to electricity are likely to lose theability to pay for it, and that 100 million people that have gained access to cooking withclean fuels may forgo it on cost grounds, returning instead to the use of traditional
biomass.

The gap between the Sustainable Development Goal 7 (SDG 7) target and current policy
ambitions is even wider in the case of clean cooking fuels. Some 128 countries currently
lack universal access to clean cooking, but only 39 of them have clean cooking targets,and fewer than half of these are targeting universal access by 2030. China and Indonesia
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Getting the world on track for universal access to electricity and clean cooking will require
dedicated additional effort from a wide range of national and international actors. Only
half of the 113 countries without universal access to electricity have targets to increase
access, and fewer than half of those aim to reach universal access by 2030. An evensmaller number, e.g. Côte d'Ivoire, Kenya, Senegal, Rwanda and Myanmar, havecomprehensive national electrification strategies in place. The achievement of nationaltargets – as modelled in the APS – is therefore not enough to achieve full universal accessto electricity by 2030 (the aim of Sustainable Development Goal 7). The NZE Scenario, bycontrast, builds in achievement of the 2030 target (Figure 1.7).

are close to being on track to achieve their targets but in many other countries there is aneed to raise the current level of ambition and to improve implementation. As withaccess to electricity, universal access to clean cooking by 2030 is built into the NZE
Scenario.
Figure 1.7 ⊳Number of people without access to electricity andclean cooking by scenario, 2021 and 2030
Without access to clean cooking
Million people

Million people

Without access to electricity
1 000
800
600

2 500
2 000
1 500

400

1 000

200

500
2021

2030 2030 2030
STEPS APS NZE
Sub‐Saharan Africa

2021
Developing Asia

2030 2030 2030
STEPS APS NZERest of world
IEA. CC BY 4.0.

Well-formulated national strategies and international support are vital to regain
momentum on improving energy access after Covid-19 and today’s high energy prices

Short‐term policy responses to the crisis have been focused on affordability and security ofsupply, with mitigating measures that can be implemented quickly at a premium, even when
they are expensive or come at the cost of temporarily higher emissions. One response has
been to seek to protect consumers from some or all of the increase in prices, with massiveinterventions in particular to shield vulnerable consumers. Since September 2021, the IEA
has tracked around USD 550 billion in government interventions, mostly in Europe, to shieldconsumers from the worst effects of the price spikes, with a large amount of additional
support also under consideration in several countries. There have been measures to allow
for higher coal‐fired generation, to extend the lifetime of some nuclear power plants and toaccelerate the flow of new renewable projects. Demand‐side measures have generally
received less attention, but there have been initiatives to encourage and incentivise cuts inenergy use: at the European Union level, these include a voluntary 15% reduction in natural
gas demand as well as a mandatory reduction target of 5% of electricity use in peak hours(demand which is typically met by gas‐fired generation). There have also been various
interventions to cap the revenues paid for cheaper sources of generation, which would
40

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Notes: Sub‐Saharan Africa excludes South Africa. STEPS = Stated Policies Scenario; APS = Announced
Pledges Scenario; NZE = Net Zero Emissions by 2050 Scenario.

otherwise be making huge gains because of the price‐setting role of gas‐fired plants,
alongside temporary additional taxes on the profits of oil and gas companies, with theproceeds used to help ease the pressure on household and company energy bills.

1

Alongside these short‐term measures, some governments have taken steps that will play out
over the longer term. Some of these seek to increase oil and gas supply, via announcementsof new incentives or licensing rounds,1 or through support for new infrastructure, inparticular new LNG terminals in Europe to facilitate the supply of non‐Russian gas. But mostof the new policy initiatives aim to accelerate the structural transformation of the energy
sector. The European Union is raising its renewables and energy efficiency targets andputting significant resources behind achieving them. The adoption of the Inflation Reduction
Act in the United States gives a boost to an array of clean energy technologies through theprovision of USD 370 billion for energy security and climate change investments, with thepotential to mobilise far larger sums from the private sector. The Japanese government isseeking to restart and build more nuclear plants and expand other low‐emissions
technologies with its Green Transformation (GX) plan. China continues to break records forinvestments in renewables and to add huge numbers of electric vehicles (EVs) to its stock
each year. India has taken a key step towards establishing a carbon market and boosting theenergy efficiency of buildings and appliances.

1
The typical lead times for upstream projects are considerable. Our analysis shows that for conventional
upstream projects that have started production since 2010, it took on average around six years from the award
of an exploration licence to discovery; nine years from discovery to project approval; and just over four years
from approval to first production.

Chapter 1 | Overview and key findings

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There remain huge uncertainties over how this energy crisis will evolve. The biggest concern
is the war in Ukraine – how it will progress, when and how it might end. Others relate to thepossibility of further escalation in prices, the severity of the 2022‐23 winter, the extent towhich Russian export flows can be redirected to other markets, and the way that high prices
influence consumer behaviour or social attitudes towards clean energy transitions. But thecurrent energy shock has already had a seismic effect, providing a vivid reminder – if one wasneeded – of the importance of energy security and diversity. In so doing, it has highlighted
the fragility and unsustainability of many aspects of our current energy system and the wider
risks that this poses for our economies and well‐being. And it has played out against a
backdrop of increasingly visible vulnerabilities and impacts from a changing climate. Timesof crisis put the spotlight on governments, and the scenarios that we include in the World
Energy Outlook are differentiated primarily by how policy makers respond.

1.3

Outlook for energy markets and security

Today’s high energy prices and gloomy economic outlook lead to lower energy demand
growth in the STEPS and APS, both in the near term and out to 2030, than in the WEO‐2021(IEA, 2021a). Faced with market uncertainty and high prices, consumers are forgoingpurchases and industry is scaling back production. Despite a strong economic rebound fromthe pandemic in 2021, the assumed rate of average annual GDP growth for the rest of thedecade has been revised down slightly to 3.3% (see Chapter 2). Energy demand rises more
slowly in both the STEPS and APS as a result, and the mixture of fuels used to meet thisdemand growth changes substantially from previous projections (Figure 1.8).

EJ

Figure 1.8 ⊳Difference in total energy supply in the WEO-2022 STEPS relative
to the WEO-2021 STEPS

15
10
5
0
‐5
‐10
‐15

2021

2022
Oil

2023

2024

2025

2026

2027

Natural gas

Coal

Renewables

2028

2029

2030

Nuclear
IEA. CC BY 4.0.

Gas demand is markedly lower than in last year’s STEPS while low-emissions sources – led
by renewables – see even greater growth. The upside for coal proves short-lived.

The trends to 2030 in the STEPS are consistent with a world that is grappling with a host ofnear‐term vulnerabilities, concerned about the high cost of imported fuels but also aboutclimate change, and aware of the opportunities afforded by cost‐effective clean energy
technologies. Natural gas prices remain at very high levels by historical standards until the
middle of the decade, causing gas to lose ground as new natural gas power plant
constructions slows, with countries opting for other sources to maintain system adequacy
and flexibility while accelerating renewables. Trade flows undergo a profound reorientation
as importing regions tend to prioritise domestic resources where possible in an attempt toensure reliable supplies of energy and limit exposure to volatile international markets, andas the implications of Europe’s shift away from Russian imports reverberate around thesystem. Overall, energy security concerns reinforce the rise of low‐emissions sources and42

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Notes: EJ = exajoule. Positive numbers indicate total energy supply is higher in the STEPS in this Outlook thanin the WEO‐2021 STEPS.

efficiency: energy demand growth of almost 1% a year to 2030 is largely met by renewables.
For the first time, the STEPS in this Outlook shows a noticeable peak in overall fossil fuelconsumption within this decade (Box 1.2). However, while showing distinct signs of change,
the trends in the STEPS do not yet amount to a paradigm shift.

1

Era of fossil fuel growth may soon be overBox 1.2 ⊳The Stated Policies Scenario in this Outlook is the first WEO scenario based on prevailingpolicy settings that sees global demand for each of the fossil fuels exhibit a peak orplateau. Coal demand peaks within the next few years, natural gas demand reaches aplateau by the end of the decade, and oil demand reaches a high point in the mid‐2030s
before falling. The result is that total demand for fossil fuels declines steadily from themid‐2020s by around 2 exajoules (EJ) (equivalent to 1 million barrels of oil equivalent per
day [mboe/d]) every year on average to 2050 (Figure 1.9).

EJ

Figure 1.9 ⊳Fossil fuel demand in the STEPS, 1990-2050

500

100%

400

80%

300

60%

200

40%

100

20%

1990
Oil

2000

2010

Coal

Natural gas

2020

2030

2040

2050

Share of fossil fuels in TES (right axis)
IEA. CC BY 4.0.

Total fossil fuel use sees a definitive peak for the first time in this year’s STEPS. The shareof fossil fuels in the energy mix falls to around 60% in 2050, a clear break from past trends

Changes in fossil fuel use have broadly followed changes in GDP for decades, and global
fossil fuel demand has remained at around 80% of total demand for decades. The 2022
STEPS projections are now putting the world on a path towards a significant break withthese trends within a few years. By 2030, fossil fuels account for less than three‐quartersof total energy supply, and by 2050 their share falls to just above 60%. These trends areemblematic of a shift in the energy landscape since the Paris Agreement. In theWEO‐2015, for example, the scenario equivalent to the STEPS (then called the New
Policies Scenario) saw a steady rise in demand for each of the fossil fuels to 2040, andtotal fossil fuel use in 2040 was projected to be nearly 20% larger than in 2040 in this
Chapter 1 | Overview and key findings

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Note: EJ = exajoule; TES = total energy supply.

year’s STEPS projections (IEA, 2015). The biggest single change since then has been in the
power sector: the STEPS in this Outlook sees a much higher level of renewables
deployment to 2030 and beyond than its predecessor scenario did in 2015, and thiscomes at the expense of coal and natural gas.
The APS builds on these trends, but assumes that governments, companies and citizens takefurther measures to ensure that the response to these trends is consistent with long‐termclimate goals. These have collectively become more ambitious since the WEO‐2021 as aresult of new pledges and targets announced since then, notably in India and Indonesia. In
the APS, global energy demand is set to increase by 0.2% per year to 2030, compared with
0.8% per year in the STEPS, reflecting more active measures in the APS to curb demandthrough energy efficiency gains. There is also a much more dramatic shift in favour of low‐emissions sources of energy. The NZE Scenario maps out a complete and even more rapidtransformation which is consistent with a path to net zero CO2 emissions from energy andindustrial processes by 2050.
The rate at which the energy efficiency of different economies improves is a crucial variablein our Outlook. Between 2017 and 2020, energy intensity has improved on average by 1.3%
per year – considerably lower than the 2.1% seen between 2011 and 2016 – and the rate of
improvement further slowed to 0.5% in 2021. In the STEPS, energy intensity improves by
2.4% per year from 2021 to 2030; as a result, around 44 EJ (10% of total final consumption)
is avoided by 2030. However, this still leaves a great deal of untapped potential: in the APS,
energy intensity improves by 3% per year, and even more rapidly in the NZE Scenario.

1.3.1

Trends and vulnerabilities across the energy mix

Electricity

The bulk of the growth comes from emerging market and developing economies, where
electricity meets a broad range of residential, commercial and industrial needs. Growing
populations, higher incomes and rising temperatures lead to rapidly increasing demand forspace cooling, which is one of the biggest contributors to electricity demand growth; an extra
2 800 terawatt‐hours (TWh) globally for space cooling to 2050 in emerging market anddeveloping economies in the STEPS is the equivalent of adding another European Union to
current global electricity demand. Comparing this demand for space cooling across the
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There are many uncertainties in our Outlook, but one point which is common to all the
scenarios is the rising share of electricity in global final energy consumption. From 20% today,
this increases to 22% by 2030 in the STEPS, and 28% in 2050. In the APS, the share rises to
24% in 2030 and 39% in 2050. In the NZE Scenario, the share rises further to 28% by 2030
and 52% by 2050. This is associated with a huge overall increase in global electricity demand
over the coming decades – by mid‐century, electricity demand is 75% higher than today in
the STEPS, 120% higher in APS and 150% in the NZE Scenario. Clean electricity andelectrification are absolutely central to the shift to a net zero emissions system.

scenarios provides a useful illustration of the value of stringent efficiency policies: in the APS,
efficiency gains cut the growth in cooling demand by almost half; even more stringent
standards for air conditioners in the NZE Scenario, together with better insulation in homes,
cut this by half again.

1

As modern lives and economies become increasingly reliant on electricity, so the reliability
and affordability of electricity supply take centre stage in any discussion about energy
security, and decarbonisation of electricity supply becomes central in planning for net zero
emissions goals. Around 65% of the coal used globally in 2021 and 40% of the natural gas
were for power generation. Coal use for electricity generation is rising in many countries, atleast temporarily, in response to the energy crisis. The shares of coal and natural gas in power
generation are set to decrease to 2030 in each scenario, but to varying degrees (Figure 1.10).
The global average carbon intensity of electricity generation is currently 460 grammes ofcarbon dioxide per kilowatt‐hour (g CO2/kWh), heavily influenced by the amount of coal in
the mix. By mid‐century, unabated coal falls to 12% of total generation in the STEPS, downfrom 36% today, helping to reduce the carbon intensity of electricity generation to
160 g CO2/kWh. This point is reached 20 years earlier in the NZE Scenario, which sees carbon
intensity dip below zero by 2050 as negative emissions in the power sector offset residual
emissions in industry and transport.

Adequate investment to expand and modernise grid infrastructure is a case in point. Our
projections in the STEPS see annual investment of USD 770 billion in infrastructure andstorage to 2050 as grids increase in length by about 90% over the period. Investment in grids
and storage is 30% higher on average in the APS, at close to USD 1 trillion per year. However,there are obstacles that need to be addressed. In practice, the permitting and constructionof a single high power overhead line (>400 kilovolts) can take as much as 13 years, dependingon the jurisdiction and length of the line, with some of the longest lead times found inadvanced economies. Transmission bottlenecks are already creating numerous inefficiencies
and risks. For example, authorities in Viet Nam announced in early 2022 that they would notconnect any new solar PV or wind project to the grid for the rest of the year, while in
Mongolia 12% of the electricity generated in 2021 could not be transported to end‐users.

Chapter 1 | Overview and key findings

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Changing demand patterns and rising shares of solar photovoltaics (PV) and wind in theelectricity mix put a premium on power system flexibility as a cornerstone of electricity
security. Flexibility needs (measured as the amount the rest of the system needs to adjust
on an hourly basis to accommodate demand patterns and the variability of wind and solar
output) increase in all scenarios; they double in the APS by 2030, for example, and thennearly double again by 2050. There are four main sources of flexibility in power systems:
generation plants, grids, demand‐side response and energy storage. For the moment,
thermal power plants perform most of the adjustments to match energy demand and supply,
but as other forms of flexibility develop and expand, coal and then gas‐fired plants see theirrole as a source of flexibility progressively diminish and eventually disappear. Removing
existing sources of flexibility before others are scaled up represents a major risk to electricity
security.

Figure 1.10 ⊳ Global energy supply and demand by sector, scenario and fuelTotal energy supply (EJ)
2021

2030

STEPS
APS
NZE
120

240

360

480

600

720

100

150

200

250

300

Electricity and heat (EJ)

2030

2021
STEPS
APS
NZE
Industry (EJ)

2030

2021
STEPS
APS
NZE
Transport (EJ)

2030

2021
STEPS
APS
NZE
Buildings (EJ)

2030

2021
STEPS
APS
NZE
50

Coal
Oil
Natural gas
Traditional use of biomass
Other renewables
Electricity
Other

NuclearModern bioenergy

Energy efficiency, electrification and expansion of low-emissions supply
are the hallmarks of rapid transitions to 2030

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Clean energy supply and critical minerals
Clean energy, including both low‐emissions electricity and fuels, is the big growth story ofthis Outlook. The extent of that growth still rests in the hands of policy makers, even where– as in the case of wind and solar – they enjoy large cost advantages over other technologies.
But there are signs that the energy crisis is galvanising increased policy support, with the
Inflation Reduction Act in the United States being a particularly striking example.

1

Low‐emissions sources now account for around 40% of electricity generation, with 30%
coming from renewables and another 10% from nuclear. Deployment of solar PV and wind
power accelerates in all scenarios, setting new records every year to 2030: by mid‐century
their combined share of these two technologies in the electricity mix reaches 45% in the
STEPS and 60% in the APS. Within ten years, if countries are taking the necessary action todeliver on their climate pledges, the world will be deploying around 210 gigawatts (GW) of
wind capacity each year and 370 GW of solar. The balance of deployment varies by region
and country. In the United States and India, for example, solar PV becomes the leading
technology. By contrast, the European Union moves towards an electricity system dominatedby onshore and offshore wind, with both sources combined accounting for more than 40%
of total generation in 2050 in the STEPS and over 50% in the APS and NZE Scenario.
The huge rise in the share of solar PV and wind in total generation in all scenarios
fundamentally reshapes the power system and significantly increases the demand for powersystem flexibility to maintain electricity security. This puts a premium on dispatchable low‐emissions technologies, such as hydropower, bioenergy and geothermal. It also encourages
new approaches such as the co‐firing of ammonia in coal plants and low‐emissions hydrogenin natural gas plants, as well as some retrofits of existing power plants with carbon capture,utilisation and storage (CCUS). Regions with high shares of solar PV relative to wind tend tosee higher relative levels of battery deployment than regions in which wind predominates,
such as China or the European Union, because the short‐duration storage that batteries
provide is well suited to smooth out the daily cycle of solar PV‐based electricity generation.
Regions where wind is the leading power generation technology tend to rely on a wider rangeof sources of flexibility.

Critical minerals are a fundamental part of the energy and electricity security landscape.
Demand for critical minerals for clean energy technologies is set to rise two to fourfold by2030 (depending on the scenario) as a result of the expanding deployment of renewables,
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Investment in nuclear power is also coming back into favour in some countries. There havebeen announcements of lifetime extensions for existing reactors, often as part of the
response to the current crisis, as well as announcements of new construction, for example
in Japan and France. Worldwide, the largest new build nuclear programme is in China as it
works towards its goal of carbon neutrality by 2060. There is growing interest in the potential
for small modular reactors to contribute to emissions reductions and power system
reliability. The share of nuclear in the generation mix remains broadly where it is today –around 10% – in all scenarios.

EVs, battery storage and electricity networks (Figure 1.11). Copper use sees the largest
increase in terms of absolute volumes, with current demand of around 6 million tonnes (Mt)per year increasing to 11 Mt by 2030 in the APS and 16 Mt in the NZE Scenario, but othercritical minerals experience faster rates of demand growth, notably silver and silicon forsolar PV, rare earth elements for wind turbine motors and lithium for batteries. Both theextraction and processing of critical minerals are highly concentrated geographically: unlessthe need for stronger resilience and diversity in supply chains is addressed, there is a risk thatthe increasing use and importance of critical minerals could become a bottleneck for clean
energy deployment.
Figure 1.11 ⊳ Mineral requirements for clean energy technologies by scenario,
2021 and 2030

By mineral

10

2030

Lithium
20

Graphite
Nickel10

Copper

2021

NZE

APS

STEPS

2021

Wind
Solar PV

CobaltManganese

30

NZE

20

Other

APS

30

40

STEPS

HydrogenElectricity
EVs andstorage
Nuclearand otherrenewables

Mt

Mt

By technology
40

2030
IEA. CC BY 4.0.

Mineral requirements for clean energy technologies quadruple to 2030
in the NZE Scenario, with particularly high growth for materials for electric vehicles
Notes: Mt = million tonnes; EVs = electric vehicles. Includes most of the minerals used in various clean energy
technologies, but does not include steel and aluminium. See IEA (2021b) for a full list of minerals assessed.

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Recycling is an important and – for the moment – underutilised option to reduce criticalminerals demand: 95% of solar panel components by mass are recyclable, and thepercentage for wind turbines is similar. In the NZE Scenario, annual capacity retirements forsolar PV rise from 3 GW in 2030 to 400 GW in 2050, and for wind turbines from 16 GW to240 GW over the same period. Further policy efforts are needed to boost recycling andensure that the solar panels and wind turbines reaching the end of their life do not end up
in landfills. Other untapped opportunities for reuse and recycling include spent EV batteries,
which can retain large amounts of unused energy that no longer meet the standards for use
in a vehicle; spent EV batteries typically maintain about 80% of their total usable capacity.

While not increasing at the scale of low‐emissions electricity, the prospects for low‐emissions
fuels are brightening, with biogases and low‐emissions hydrogen in particular getting a boost
from the current energy crisis. In the APS, global low‐emissions hydrogen production rises
from very low levels today to reach 30 million tonnes of hydrogen (Mt H2) per year in 2030.
This is equivalent to 100 bcm of natural gas (although not all low‐emissions hydrogen would
replace natural gas use). More ambitious production targets are also being set in many
countries for biogases and biomethane. Efforts to promote the use of hydrogen areconcentrated in Europe and the United States, but other countries are also active in this field:
Japan, for example, aims for a 20% rate of co‐firing imported ammonia at its coal‐fired power
plants by 2030, and this will require 0.5 Mt H2 per year.

1

Liquid fuels are deriving less benefit from current market conditions: disruption to foodsupply chains and high fertiliser prices mean liquid biofuel costs have risen sharply. To avoid
conflicts between food production and affordability, there is a general shift in planning forenergy transitions away from conventional bioenergy sources towards advanced biofuels,
and a particular focus on two inputs: sustainable waste streams that do not require specificland use and dedicated short rotation woody crops grown on cropland, pasture land andmarginal lands that are not suited to food crops. In the NZE Scenario, there is no increase incropland use for bioenergy and no bioenergy crops are grown on existing forested land.
Liquid biofuels increase from 2.2 million barrels of oil equivalent per day (mboe/d) in 2021
to 3.4 mboe/d in the STEPS, 5.5 mboe/d in the APS and 5.7 mboe/d in the NZE Scenario in2030. Aviation and shipping are the largest contributors to the rise in liquid biofuel demandin the APS and NZE Scenario as road transport is increasingly electrified.

Natural gas

In both the STEPS and APS, natural gas prices in importing countries in Europe and Asia
remain high over the next few years as Europe’s drive to reduce reliance on Russian imports
keeps global gas markets tight during a relatively barren period for large new gas export
projects. A rebalancing comes later in the 2020s when slower demand growth coincides withnew supply projects coming online. But this crisis has undercut momentum behind natural
gas expansion in some large potential markets in south and southeast Asia and put a
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The era of rapid growth in natural gas seems to be drawing to a close. In the STEPS, demandrises by less than 5% between 2021 and 2030 and then remains flat at around 4 400 bcm
through to 2050. This is about 750 bcm lower in 2050 than in the corresponding scenario in
the WEO‐2021 (Figure 1.12). Higher near‐term prices, more rapid electrification of heat
demand, faster uptake of other flexibility options in the power sector – and in some cases
reliance on coal for slightly longer – all dampen the outlook for gas. New policy initiatives
also play an important part: for example, the support provided for a variety of clean energy
technologies by the US Inflation Reduction Act is a key reason why natural gas demand in the
United States is around 250 bcm lower by mid‐century, compared with the STEPS in theWEO‐2021. Russia’s invasion of Ukraine and its cuts in gas supply to the European Union also
accelerate Europe’s structural shift away from natural gas.

significant dent in the idea of gas as a transition fuel. Globally, around one‐quarter of thedownward revision to gas demand to 2030 in this year’s STEPS is due to less switching fromcoal and oil to natural gas, but most of it reflects accelerated switching from natural gas toclean energy. In the NZE Scenario, natural gas demand falls further and faster than in the
STEPS and APS, declining to 3 300 bcm in 2030 and 1 200 bcm in 2050. Around 1 900 bcm
equivalent of low‐emissions gases – hydrogen, biogases and synthetic methane – areconsumed globally in the NZE Scenario in 2050.
Figure 1.12 ⊳ Drivers of change in natural gas demand in the WEO-2022 STEPS
relative to the WEO-2021 STEPS
2030

2040

2050
More gas‐to‐renewables
switchingLess coal‐ and oil‐to‐gas
switching‐200

Avoided demand
‐400

bcm

‐600

‐800
IEA. CC BY 4.0.

Natural gas demand in this year’s STEPS is around 750 bcm lower in 2050 than in the
WEO-2021, driven mainly by switching from natural gas to renewables
Note: bcm = billion cubic metres.

The broader gas security landscape is defined by three key questions. First concerns the roleof gas in the electricity market. Gas accounted for 23% of global electricity generation in 2021
and this share declines in all scenarios, albeit not as precipitously as that of coal. But declines
in the volume of gas consumed for power generation do not imply a commensurate
reduction in the value of gas to electricity security: natural gas‐fired capacity remains a
critical source of power system flexibility in many markets, especially to cover for seasonal
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In all our scenarios, the European Union compensates for the loss of Russian imports with anaccelerated transition away from natural gas through a surge in renewable capacity additions
and a push to retrofit buildings and install heat pumps, alongside an increased near‐term callon non‐Russian supply, notably via LNG. Additional annual clean energy investment of someUSD 65 billion to 2030 in the APS is more than offset over time by lower natural gas importcosts. Meanwhile there are no easy diversification options for the Russian gas traditionally
exported to Europe.

variations in demand. Europe’s gas storage continues to play a vital role: the share of gas
stored to total gas demand in 2030 in the APS is similar to the share in 2021.

1

Second concerns the level of investment. Gas infrastructure investments are capital intensive
and typically pay back over decades; they are therefore vulnerable to uncertainties
concerning long‐term demand. This has already been a stumbling block for gas diversification
efforts in Europe: most potential suppliers are looking for long‐term commitments, which
European buyers are unwilling to provide because strong near‐term needs are unlikely to besustained into the 2030s. And a similar dilemma may come to Asia. The commercial case for
new LNG investments in the APS is undercut by falling import demand in emerging market
and developing economies in Asia in the 2040s and beyond. Shortening economic lifetimes
to ten years would reduce the risk of new capacity additions turning into stranded assets,
but it would also increase the break‐even gas price needed to fully recoup investment costsby around 20% on average. A shift to low‐emissions hydrogen and hydrogen‐based fuels
could provide a partial answer to this dilemma, but is unlikely to offer a complete solution.
The third question concerns flexibility of delivery. Around 50% of current global LNG trade,
250 bcm, is flexible in the sense of having its end destination determined cargo‐by‐cargo byprice competition at a late stage: the rest is governed by fixed point‐to‐point delivery
arrangements. The current energy crisis has illustrated this flexibility well, with high prices in
Europe incentivising a major influx of cargoes to meet the continent’s shortfall in gas, albeit
at the expense of gas importers elsewhere, notably among developing countries in Asia.
However, while flexibility on the supply side is likely to be underpinned by a further rise in
LNG exports from the United States (facilitated by the reductions in domestic demand arisingfrom the Inflation Reduction Act), there are open questions about flexibility on the demandside. The power sector is typically an important provider of flexibility, as utilities often havethe ability to switch to other fuels if gas becomes too costly. But the phase‐out of coal will
reduce this flexibility: as a result, gas demand in Europe in particular is likely to become lessresponsive to price, and demand‐side flexibility is likely to become concentrated in othermarkets, notably in China.

Oil demand peaks in each scenario in this Outlook. In the STEPS, demand reaches a high pointin the mid‐2030s at 103 mb/d and then declines very gently to 2050. Global gasoline demand
peaks in the near term and falls as EVs deploy. Demand in advanced economies declines by
3 mb/d to 2030, mainly because of reductions in road transport, but this is more than offset
by increases in emerging market and developing economies where demand rises by 8 mb/d
this decade. Globally, the main sectors seeing an increase in the use of oil are aviation andshipping, petrochemicals (where oil is used as feedstock), and heavy trucks, where oil is used
as a fuel and not displaced by the rise of EVs in the same way as in other road transportmodes. These sectors see a rise in demand of around 16 mb/d between 2021 and 2050, butfrom the mid‐2030s growth in these sectors is more than offset by declining oil use
elsewhere, especially in passenger cars, buildings and power generation.
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Oil

There is no shortage of oil resources worldwide to cover this level of demand in the STEPS to2050; a key uncertainty for oil security relates to the adequacy of investment. The impact of
the Covid‐19 pandemic and the low level of investment in recent years mean there are
relatively few new resources under development and a dwindling stock of discoveredresources in the non‐OPEC world available to be developed. New oil resources discovered in
2021 were at their lowest level since the 1930s. Moreover, there are concerns in somequarters in several non‐OPEC countries about the commercial wisdom and social
acceptability of embarking on significant high upstream capital expenditure. The STEPS seesnear‐term increases in output in the United States, Guyana and Brazil, among others, butreliance on major resource‐holders in the Middle East grows steadily: the share of OPEC
countries in global oil production rises from 35% in 2021 to 36% in 2030 and 43% in 2050,
implying an increasing degree of market power for that group of producers. Persistent under‐
production in recent years among this group, relative to the targeted levels, may be aharbinger of the risks that lie ahead.
The outlook for oil is very different in the APS, where stronger policy action leads global oil
demand to peak in the mid‐2020s before dropping to 93 mb/d in 2030 (similar to the level ofdemand in 2019). Oil demand in advanced economies falls by 7.5 mb/d between 2021 and
2030 and increases by 4 mb/d in emerging market and developing economies. It is different
again in the NZE Scenario, where global oil demand never recovers to its 2019 level and falls
by nearly 20 mb/d between 2021 and 2030, led by a sharp decline in oil use in passenger cars
(Figure 1.13).
Figure 1.13 ⊳ Energy use in transport by scenario, 2000-2050
mboe/d

STEPS

NZE

APS

70
60
50
40
30
20

Oil productsElectricity

Biofuels

HydrogenHydrogen‐based fuels

2050

2040

2030

2020

2050

2040

2030

2020

2050

2040

2030

2020

2010

2000

10

Natural gas
IEA. CC BY 4.0.

Transport has long been the bedrock of oil demand, but its role weakens in the APS and NZE

Note: mboe/d = million barrels of oil equivalent per day.

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Scenario as electricity displaces very large volumes of oil

These two scenarios ease the risks on the supply side that arise in the STEPS, but, despite
today’s scramble for oil products, they imply severe long‐term pressures for refiners. In the
APS, more than half of current refining capacity faces the risk of lower utilisation or closureby 2050, and there are few capacity additions after projects currently under construction
come online. Those refiners that survive, invest to reduce emissions from refining
operations, notably via low‐emissions hydrogen, CCUS and efficiency improvements. They
also view integration with petrochemical operations as a major strategic priority, given thatthe use of oil as a petrochemical feedstock is the most durable element of demand. It was
the only use of oil that increased in 2020 amid the disruption of the Covid‐19 pandemic, anddemand remains relatively robust even in very rapid transitions: in the NZE Scenario, oil use
for passenger cars falls by 98% between today and 2050, but oil use for petrochemicals falls
by only 10%, despite policies to ban or reduce single‐use plastics, improve recycling rates andpromote alternative feedstocks. This is not to say that these policies have no effects: global
average recycling rates for plastics increase from the current level of 17% to 27% in 2050 in
the STEPS, 50% in the APS, and 54% in the NZE Scenario.2 Many refiners are now considering
expansion into plastics recycling as another way to secure new revenue streams, alongsideareas such as liquid biofuels and low‐emissions hydrogen.

1

Coal
Coal consumption is projected to fall in all scenarios, declining by 10% to 2030 in the STEPS,
by 20% in the APS over the same period, and by 45% in the NZE Scenario. In the near term,coal demand increases as the energy crisis leads to some switching away from natural gas
because of concerns about high prices and availability. As a result, coal demand in the STEPS
is higher in 2030 than in the same scenario in the WEO‐2021. This increase in demand,
however, is relatively short‐lived: in the STEPS, coal demand is lower in 2030 than it is today(although not as low as projected in the STEPS in the WEO‐2021). By and large, the current
crisis pushes up utilisation rates for existing coal‐fired assets, but does not bring higher
investment in new ones. This amount of additional capacity, however, does prolong theperiod until global coal‐fired capacity peaks (2025 in the STEPS).
In addition to increased demand in the power sector, coal sees a rise in demand in industry
in emerging market and developing economies, where it already accounts for 35% of energy
used by industry. These trends in power and industry keep coal demand around today’s
elevated levels to the mid‐2020s, but structural decline sets in thereafter. Overall coalconsumption shows a more sustained rise only in a few fast growing countries and regions,notably India and Southeast Asia. In India, coal demand in the STEPS does not peak until theearly‐2030s, when the deployment of renewables in the power sector speeds up; in the APS,
this peak occurs in the late 2020s, and the subsequent decline in coal demand is considerably
steeper.

Globally, 17% of plastic waste is collected for recycling today although there are large differences between
regions: for example, 25% is collected for recycling in Europe and less than 10% in the United States. Recycling
rates for plastics are much lower than recycling rates for steel (80%), aluminium (80%) and paper (60%).

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2Advanced economies consumed around 1 000 million tonnes of coal equivalent (Mtce) ofcoal in 2021, accounting for just under 20% of global coal demand (for context, coal demandin China increased by an average of 100 Mtce each year between 2000 and 2020).
Three‐quarters of advanced economy coal use is in the power sector; in the APS, wherecountries meet their climate targets, unabated coal generation falls by around 80% to 2030
and is phased out completely by 2040. The NZE Scenario includes an even more ambitious
timetable: it sees an end to unabated coal use for electricity generation in advanced
economies by 2035 and worldwide by 2040.

Focus: Russia and the reshuffling of global energy trade
The World Energy Outlook has long highlighted the prospect of changes in the geography,
scale and composition of international energy trade, notably the shift in fossil fuel imports
towards Asia, the rising importance of trade in critical minerals and the emergence of trade
in hydrogen and hydrogen‐based fuels. Some of these changes are now being turbo‐charged
by Russia’s invasion of Ukraine, which has led to the abrupt severance of the large andimportant inter‐regional energy trade relationship between Russia and Europe.
All trade ties with Europe based on fossil fuels are ultimately undercut in our scenarios by
the region’s net zero emissions ambitions, but Russia’s ability to deliver at relatively low costmeant that it lost ground only gradually in previous editions of the Outlook. Now the rupture
has come with a speed that few imagined possible, and our scenarios assume that there is
no way back. This means a major reshuffling of international trade, with inevitable
implications for the geopolitics of energy.
Figure 1.14 ⊳ Crude oil and natural gas imports to the European Union andemerging market and developing economies in Asia by origin

EJ

European Union

Developing Asia

60
50
40
30
20
10
2015 2021

2025 2030
STEPS
Russia2025 2030
APS
North America

2015 2021

2025 2030
STEPS

Middle East

2025 2030
APS

Other
IEA. CC BY 4.0.

but gains in these new markets are less than losses in exports to Europe
Note: EJ = exajoule.

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Russia’s oil and gas exports switch focus to developing Asia in the STEPS and APS,The largest uncertainty regards Russia’s ability to find alternative export markets. The
prospects vary by fuel, with natural gas presenting Russia with the most difficult dilemma. In
our scenarios, Russia attempts to pivot to Asia and other non‐European markets, but isunsuccessful in finding markets for all of the flows that previously went to Europe, and it
struggles in some cases to develop new resources and infrastructure (Box 1.3). Total Russian
export levels are considerably lower than in previous WEOs, and Russia never returns – inany of our scenarios – to the export levels that it saw in 2021 (Figure 1.14).
Box 1.3 ⊳1

What next for Russian oil and gas?

The outlook for Russian oil and gas was marked by uncertainty well before its invasion of
Ukraine. Markets for Russian exports were shifting, but infrastructure links were stillconcentrated in Europe. Future production growth would need to come from morechallenging and remote deposits, yet some important upstream technologies were
subject to sanctions imposed after the annexation of Crimea in 2014. And oil and gas
assets were being concentrated in the hands of a few state‐owned champions to thedetriment of the private or semi‐private players – both domestic and international – thatdrove much of Russia’s oil and gas growth since 2000.
The invasion of Ukraine deepened all of these dilemmas. Major companies, led byRosneft, had announced increases in investment for 2022, but these are now far fromcertain. Along with the loss of key European markets, the sanctions put in place by theEuropean Union and United States are considerably tougher now than in 2014. They
include wide‐ranging restrictions on the ability of international companies to invest in
Russia, on the scope for Russian companies to raise finance internationally, and on
Russian access to western technology. Russia had attempted to work around the earlier
restrictions through a programme of import substitution, which was only partiallyeffective. Some fields are at risk of being shut in – a jolt from which older reservoirs inparticular might struggle to recover.

Prior to its invasion of Ukraine, Russia planned to use LNG to diversify export flows awayfrom Europe with a stated aim to export 170‐200 bcm of LNG per year by 2035, up fromaround 40 bcm currently. Now this appears a distant prospect without international
partners and technologies, especially for liquefaction. Novatek has developed ahome‐grown liquefaction technology called Arctic Cascade, used for the fourth train ofChapter 1 | Overview and key findings

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There are many uncertainties about how this plays out, but our projections in the STEPS
and APS suggest that the key long‐term challenges for Russia are concentrated in the
upstream for oil, and in the midstream for gas (the issues are moot in the NZE Scenario,
as no new developments are required). A growing share of Russian oil production had
been set to come from new production areas, including projects in Eastern Siberia, theArctic and offshore, as well as other hard‐to‐recover resources. Risks to the timing andcost of these developments have compounded, and they are amplified by the absence ofwestern companies, technologies and some service providers (Figure 1.15).

the Yamal LNG project, but implementation was beset by difficulties and delays. Now
most of Russia’s LNG expansion plans are back on the drawing board.
Figure 1.15 ⊳ Changes in Russian oil production and natural gas export
in 2035 in the WEO-2022 STEPS relative to the WEO-2021 STEPSNatural gas exports

Oil production

LNG

‐1

New conventional
onshore‐1‐2

Offshore, Arctic
and other

‐2

‐3

‐3

‐4

‐4

‐5

mboe/dmb/dExisting fields

Pipeline‐5
IEA. CC BY 4.0.

Russia’s oil and gas outlook has deteriorated since the WEO-2021, it will be toughfor it to develop new upstream oil projects and to find alternative markets for gas
Notes: mb/d = million barrels per day; mboe/d = million barrels of oil equivalent per day; LNG = liquefied
natural gas. The figure shows the differences in oil and natural gas production in 2050 between the STEPS
in the WEO‐2021 and the same scenario in this Outlook.

Over time, more Russian resources are likely to be drawn eastwards to Asian markets. In
the case of oil, increased Russian flows to Asia are already visible. For natural gas, thereorientation of flows will require more time to take shape because of the need for major
new infrastructure investments if exports are to expand beyond the 38 bcm/year
foreseen for the Power of Siberia pipeline. These will require new agreements withpartners, some of which have found their confidence in natural gas – and in Russia –shaken by recent events.

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For the moment, with no links to alternative markets, much of the natural gas that was
intended to flow westwards to Europe has no place to go. As a result, Russia’s share ofinternationally traded gas, which stood at 30% in 2021, falls to 15% by 2030 in the STEPS
and to 10% in the APS. Its projected net income from gas sales (revenue minus costs) falls
from USD 75 billion in 2021 to less than USD 30 billion in 2030 in the APS.

Russia’s share of global fossil fuel exports declines substantially as a result of the current
crisis (Figure 1.16). In the case of oil, Russia exported more than 7 mb/d in 2021;3 this falls
by around 25% by 2030 in the STEPS and by 40% to 2050. By the mid‐2020s, North America
is exporting more oil to global markets than Russia, but the gap left by Russia is mainly filledby higher exports from the Middle East. In coal markets, more than 80% of global exports go
to the Pacific Basin in 2030 (up from about 75% in 2021). Russia has plans to switch exports
to these markets, but the ability to do so rapidly is constrained by bottlenecks in the railsystem.

1

Figure 1.16 ⊳ Change in net trade position of selected oil and gas exporters

mboe/din the STEPS, 2021-2030

6

OilNatural gas

4

2

0

‐2

United States

Middle East

Central andSouth America

RussiaIEA. CC BY 4.0.

With the loss of its largest export market, Russia faces the prospect ofa much-diminished future role in international energy trade3
This represents volumes traded between regions modelled in the WEO and does not include intra‐regional
trade. Oil trade includes both crude oil and oil products.

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Russia’s reorientation to Asian markets is trickiest in the case of natural gas. Russia isdiscussing the possibility of new pipeline links to China, notably the large capacity Power ofSiberia‐2 pipeline through Mongolia (also sometimes called Soyuz‐Vostok). However, ourdemand projections for China raise considerable doubt about the viability of another large‐
scale gas link with Russia. The STEPS is the most favourable scenario for such a pipeline, andin these projections natural gas demand growth in China slows to 2% per year between 2021
and 2030, compared with an average growth rate of 12% per year between 2010 and 2021.
Importers in China have been actively contracting for new long‐term LNG supplies, andChina’s most recent five‐year plan focusses on boosting domestic production. Alongside theramp‐up of imports through existing pipelines, China’s already contracted supplies morethan cover its requirements in this scenario until well into the 2030s.
Today’s gas security crisis has also boosted momentum behind projects seeking to tradehydrogen and hydrogen‐based fuels. However, our tracking of planned projects reveals asignificant imbalance: export projects are more numerous and more advanced than thosefor the corresponding import infrastructure. Of the 12 Mt H2 per year of proposed exports,
only 2 Mt H2 per year have named potential or agreed off‐takers and a further 3 Mt H2 peryear cite export to a specific region. The amount of investment necessary to set up
international value chains for hydrogen is enormous. Assets that could deliver 10 Mt H2 peryear to the European Union in 2030 (in line with the REPowerEU Plan) would cost some
USD 700‐850 billion, a sum that would more than double when financing costs are included.

1.3.2

Is a messy transition unavoidable?

Our scenarios model orderly processes of change in which markets are always in equilibrium,with investment rising and falling in different sectors to allow for a balance of supply anddemand. However, today’s energy crisis has underscored that, in practice, the future ofenergy markets is likely to be disjointed, subject to geopolitical friction and prone to regularmarket imbalances. In particular, the crisis has undercut the trust and collaboration that are
essential to ease the journey to a net zero emissions system. A lack of sequencing andco‐ordination, both within countries and internationally, would also be very damaging to theprospects for a people‐centred process of change.

EJ

Figure 1.17 ⊳ Fossil and non-fossil energy supply by scenario, 2020-2050
STEPS

600

NZE

APS

500
400
300
200
100
2020

2050 2020
Fossil2050 2020

2050

Non‐fossil
IEA. CC BY 4.0.

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There is an orderly process of change in the global fuel mix in all WEO scenarios,with the main differentiating feature being the rapidity of transition from fossil fuels

Does this make a messy transition unavoidable? In this Outlook, we explore approaches thatcan lessen the scope for volatility and turbulence ahead. These are not related specifically tothe current crisis, although many of them are relevant to discussions about how best to copewith it and move beyond it. The ten guidelines below, amplified in Chapter 4, are designed
to advance climate, security and affordability objectives in tandem, and require a strong rolefor governments to manage the process of change – though without giving up the gains thatcome from well‐functioning market mechanisms. Many of them are designed to address
specific issues that arise in what has been called the “mid‐transition”, when carbon‐emitting
and clean fuels and technologies need to co‐exist (Figure 1.17).
Synchronise scaling up a range of clean energy technologies with scaling back of fossil
fuels. Many companies and financial organisations have set goals and plans to scale
down investment in fossil fuels. Much more emphasis is needed on their goals and plans
for the scaling up of investment in clean energy technologies, and on what governments
can do to incentivise this. Sequencing is important: continuing investment in fossil fuelsis needed to keep supply and demand in balance while energy transitions are in
progress, but the extent of this requirement is entirely dependent on the speed at whichclean energy investment scales up. In the NZE Scenario, for every USD 1 spent globallyon fossil fuels in 2030, more than USD 9 is spent on clean energy (Spotlight).

Tackle the demand side and prioritise energy efficiency. The energy crisis highlights the
crucial role of energy efficiency and behavioural measures to help avoid mismatches
between demand and supply. Since 2000, efficiency measures have reduced unit energy
consumption significantly across various end‐uses, but there is much more that can be
done. This is especially the case in emerging market and developing economies whereenergy performance standards for appliances such as air conditioners and refrigerators
are often weak and sometimes non‐existent. Stock turnover is another major challenge,
especially for long‐lived assets, for example, over half of the buildings that will be in use
in 2050 have already been built. This underlines the case for policies that accelerate therate of retrofits.

Reverse the slide into energy poverty and give poor communities a lift into the newenergy economy. As a result of the pandemic and the energy crisis, 75 million people
have lost the ability to pay for extended electricity services and 100 million for clean
cooking solutions. In emerging market and developing economies, the poorest
households consume nine‐times less energy than the wealthiest, but spend a far higher
proportion of their income on energy. The least well‐off often live in less efficientbuildings, utilise older inefficient appliances, and rely on more inefficient means forcooking and heating. Policy interventions are essential to help them cope with thehigher upfront costs of clean energy investments (such as efficiency and electrification).
If climate policies do not do this, they risk being socially divisive, especially in a high priceenvironment.

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1Collaborate to bring down the cost of capital in emerging market and developing
economies. The cost of capital is a signal of the real and perceived risks associated withinvestment, and it is higher in many emerging market and developing economies thanelsewhere. New investor surveys conducted for the new IEA‐hosted Cost of Capital
Observatory suggest that the cost of capital for a solar PV plant in 2021 in key emerging
economies was between two‐ and three‐times higher than in advanced economies andChina. Tackling the various economy‐wide or project‐specific risks that push up the costof capital is essential to bring investment to where it is most needed. It would also makea huge difference to the overall costs of transition. A 200 basis point reduction in thecost of capital in all emerging market and developing economies would reduce thecumulative clean energy financing costs to reach net zero emissions by USD 15 trillion
through to 2050.

Manage the retirement and reuse of existing infrastructure carefully, bearing in mind
that some of it will be essential for a secure journey to net zero emissions. Some partsof the existing fossil fuel infrastructure perform functions that will remain critical forsome time, even in very rapid energy transitions. For example, the importance of gas‐
fired power for electricity security actually increases in many countries during energy
transitions before falling – especially in systems with significant seasonal variations indemand. In the European Union, peak requirements for natural gas go up through to2030 even though overall or aggregate demand goes down. Managing the decline inrefinery capacity is also important: even in markets where internal combustion engine(ICE) vehicle sales are banned, oil demand for transport does not disappear immediately.
Unplanned or premature retirement of this infrastructure will have negative
consequences for energy security and for jobs.

Tackle the specific risks facing producer economies. Oil and gas security duringtransitions will depend on the ability of hydrocarbon‐dependent economies to diversify
and find other sources of economic advantage. These may well continue to be in theenergy sector: many resource‐rich countries are investing a part of current windfall oil
and gas profits in renewables and low‐emissions hydrogen. Potential export earnings
from hydrogen are no substitute for those from oil and gas, but low cost renewables,
natural gas and CCUS storage potential could provide a durable foundation for attracting
investment in energy‐intensive industrial sectors.



Invest in flexibility – a new watchword for electricity security. Maintaining electricity
security in the power systems of tomorrow calls for new tools and approaches. Powergenerators will need to be more responsive; consumers will need to be more connected
and adaptable, and grid infrastructure will need to be strengthened and digitalised.
Higher variability in electricity supply and demand means that the requirement for
flexibility quadruples by mid‐century in both the APS and the NZE Scenario, underscoring
the importance of policies that adequately remunerate the relevant technologies andinfrastructure. Battery storage and demand‐side response become increasingly
important, each providing a quarter of the flexibility needs in 2050 in the APS.

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

Ensure diverse and resilient clean energy supply chains. High and volatile criticalmineral prices and highly concentrated supply chains could delay energy transitions or
make them more costly. Demand for critical minerals is set to quadruple by 2050 in both
the APS and the NZE Scenario. At 2021 prices, the value of the minerals used in clean
energy technologies increases more than fivefold, reaching USD 400 billion by 2050 inthese scenarios. Minimising this risk requires action to scale up and diversify supplies
alongside recycling and other measures to moderate demand growth. Technologicalinnovation has already shown its ability to relieve some of the pressure on primary
supplies: newer low cobalt EV batteries contain 75–90% less cobalt than earlier
generations of batteries, although they use twice as much nickel.



Foster the climate resilience of energy infrastructure. The growing frequency andintensity of extreme weather events presents major risks to the security of energy
supplies. IEA analysis of the risks facing four illustrative assets shows that the potential
financial impact from flooding could amount to 0.3‐1.2% of their total asset value in
2050, and in one case would be four‐times higher than this without flood defences inplace. Governments need to anticipate the risks and ensure that energy systems havethe ability to absorb and recover from adverse climate impacts.

Provide strategic direction and address market failures, but do not dismantle markets.
The energy crisis has been accompanied by large‐scale interventions from governments,
often to protect different types of consumers from price spikes and to ensure energy
security. Governments are also taking on increasingly expansive roles to drive andaccelerate transitions. However, transitions are unlikely to be efficient if they are
managed on a top‐down basis alone. Governments need to harness the vast resourcesof markets and incentivise private actors to play their part. Around 70% of theinvestments required in transitions are likely to need to come from private sources. Thismeans correcting for market failures – including via support for innovation and by thephase out of harmful fossil fuel subsidies – and providing the policy signals and publicfinance that can catalyse private investment.

1

S P O T L I G H T
Can the world right its investment imbalances?

IEA analysis has repeatedly highlighted that a surge in spending to boost deployment ofclean energy technologies and infrastructure provides the way forward, and that thisneeds to happen quickly or global energy markets will face a turbulent and volatile period
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Clean energy investment has picked up in recent years, but is still well short of the levels
required to provide lasting solutions to today’s energy crisis. In the absence ofaccelerated clean energy transitions, spending on traditional fuels is also insufficient tokeep the current system operating effectively. Something has to change in order to avoid
an energy‐starved world characterised by continued price volatility.

ahead. However, the task ahead is sometimes mischaracterised and oversimplified as areallocation of existing flows from “dirty” to “clean”. In practice, comparing current
energy investment flows with what will be required in the NZE Scenario in 2030 highlights
at least four inter‐related tasks (Figure 1.18). None of these can be considered in isolation
without risking new imbalances and market volatility. Reductions in fossil fuel investment
are a consequence of these changes.
Figure 1.18 ⊳ Energy investment in the NZE Scenario, 2021 and 2030

Trillion USD (2021)

Total energy

Clean energy

End‐use and efficiency

EMDE*

5
4
3

2.1x
3.2x

2

2.7x

3.6x

1

2021

NZE
2030

2021

NZE
2030

2021

NZE
2030

2021

NZE
2030

IEA. CC BY 4.0.

There are multiple imbalances in current investment flows that need to be addressedin order to meet rising demand for energy services while reducing emissions* Excludes China.

Attract more investors to energy. There is not enough capital flowing to the energy
sector. It would need to double over the coming decade to get the world on track
for a 1.5 °C stabilisation in global average temperatures. This means tapping new
sources of finance, beyond those already engaged.



Scale up a range of clean technologies and infrastructure. The increase in global
investment needs to be concentrated across multiple clean technologies, including
renewable generation, efficiency improvements, clean fuels and CCUS, as well as therequired infrastructure in the form of expanded and modernised grids and storage.
Total clean energy investment increases threefold between 2021 and 2030 andnine‐times more energy investment flows to clean energy than to fossil fuels in 2030.

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Note: EMDE = emerging market and developing economies; NZE = NZE Scenario.



Do not underweight the demand side. The transformation of the energy sector
requires a rebalancing towards demand and end‐use sectors to spur much higher
efficiency and electrification.

1

Create a low‐emissions pathway for developing economies. With the exception ofChina, investment levels are lagging most significantly in emerging market anddeveloping economies. Meeting rising demand for energy services in a sustainable
way will only be possible if development models are able to bypass the high carbon
choices that other economies have pursued in the past.

The scale of additional investment required means that most of it will need to come fromprivate sources, but public financial institutions play crucial roles to bring forward
investment in areas where private players do not yet see the right balance of risk andreward. A clear and unified focus on energy transitions among the international
development banks, alongside larger climate finance commitments from advanced
economies, is critical to support transitions across the developing world.

1.4

Outlook for energy transitions

Energy‐related and industrial process CO2 emissions rebounded by 1.9 Gt in 2021 – thelargest ever annual rise in emissions – with global CO2 emissions in 2021 totalling 36.6 Gt. In
the STEPS, CO2 emissions reach a plateau in the mid‐2020s at 37 Gt and thereafter fall slowly
to 32 Gt by 2050 (Figure 1.19). This decline represents a break in the close historical
relationship between growth in GDP and growth in emissions. It highlights the progress madesince the Paris Agreement in 2015. Prior to that, the trajectory based on current policies was
for CO2 emissions to rise to more than 50 Gt by 2050. This would have led to a median global
average surface temperature rise of around 3.5 °C by 2100.4 The STEPS indicates a trajectorythat would lead to a 2.5 °C temperature rise in 2100. In other words, the changes in policies
and technologies made since 2015 have already reduced the projected long‐term
temperature rise by around 1 °C by 2100. However, the STEPS trajectory is not an adequateanswer to the challenge of climate change; it would not be enough to avoid severe impacts
from a warming planet.
In the APS, CO2 emissions peak in the mid‐2020s and fall to around 12 Gt in 2050. This is abigger emissions reduction than in the WEO‐2021, reflecting the new or updated Nationally
Determined Contributions (NDCs) and announced net zero emissions pledges that have been
made over the last year, the most significant of which was India’s announcement of a2070 net zero emissions target (Figure 1.20). These additional commitments help to reduce
the gap in 2030 between energy‐related CO2 emissions in the APS and the NZE Scenario by
2.1 Gt. There are large differences in emissions trajectories between regions, CO2 emissions
Energy‐related non‐CO2 emissions, including methane and nitrogen dioxide, are modelled in detail for all
scenarios; non‐energy‐related greenhouse gas emissions are assumed to move in line with the overall
emissions reduction efforts of each scenario.

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4

in 2030 decline by 40% in advanced economies but by only 5% in emerging market anddeveloping economies. The projected global median temperature rise in 2100 is about 1.7 °C.
This gets close to achieving the goal of the Paris Agreement to limit the temperature rise to“well below 2 °C”, and it marks the first time that collective government targets and pledges
have been sufficient, if delivered in full and on time, to hold global warming to below 2 °C.
However, as the IPCC has underlined, warming of close to 2 °C would still entail strong
negative impacts for societies around the world (IPCC, 2022b).
Figure 1.19 ⊳ Energy-related and process CO2 emissions, 2010-2050 andtemperature rise in 2100 by scenario

Temperature rise in 2100

Pre‐Paris baseline

50°C

Gt CO₂CO2 emissions
60

6

5th ‐ 95th
percentile

5

40

STEPS

30
20

APS

10

4

33rd ‐ 67th
percentile

3

Median

2
1

2010

2020

2030

2040

2050

NZE
APS
STEPS
Pre‐Paris

NZE

IEA. CC BY 4.0.

Policy and technology advances since 2015 have shaved 1 °C off the temperature rise in2100 but stated policies still lead to a temperature rise well above the Paris Agreement goals
Notes: Pre‐Paris trajectory is based on the Current Policies Scenario from the WEO‐2015 (IEA, 2015).
Temperature rise estimates are relative to 1850‐1900 and match the IPCC Sixth Assessment Report definitionof warming of 0.85 °C between 1995‐2014 (IPCC, 2022a).

Access to clean energy is one of the key indicators of sustainable development tracked in our
scenarios along with energy‐related emissions. The outlook for the future varies widely by
scenario. Only in the NZE Scenario is universal access to both electricity and clean cooking
achieved by 2030. Air quality is another critical indicator of well‐being. Outcomes are strongly
correlated with the strength of climate action (Box 1.4).
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In the NZE Scenario, CO2 emissions decline to 23 Gt in 2030 and to zero in 2050, plus there
is a 75% reduction in energy‐related methane emissions to 2030. The global temperature risepeaks below 1.6 °C around 2040, before dropping to around 1.4 °C in 2100. As a result, the
NZE Scenario falls within the group of scenarios categorised by the IPCC as a “no or low
overshoot” scenario, and aligns with the goal, agreed again in Glasgow at COP26 in 2021, to“pursue efforts to limit the temperature increase to 1.5 °C” (IPCC, 2022b).

Figure 1.20 ⊳ Change in CO2 emissions in the 2022 APS relative to the

Gt CO2

WEO-2021 APS, 2025-2050

1

2
India
0

Southeast Asia

‐2

Middle East
Africa‐4

Advanced economies
Other

‐6
‐8
‐10
2025

2030

2035

2040

2045

2050
IEA. CC BY 4.0.

Emissions in 2050 in this year’s APS are 8 Gt CO2 lower than last year’s Outlook,mainly due to the net zero emissions pledges made by India and in Southeast Asia

Box 1.4 ⊳Air pollution and its negative impacts on human health

Polluted air causes at least 19 000 excess deaths a day around the world.5 It also entails
significant direct economic costs, such as those related to the provision of healthcare, as
well as indirect economic costs, such as those arising from labour productivity losses orcrop damage. Air pollutant emissions decline in each of the scenarios, but the trajectories
vary considerably.
In the STEPS, vehicle emissions standards, reduced coal use and a lower level of relianceon fuelwood and other solid biomass for heating and cooking help to bring about amodest decline in air pollutant emissions from current levels. However, the overall
effects of polluted air on public health continue to worsen through to 2050 – especiallyin Asia – because of population growth and urbanisation and because of the time lag
between exposure to pollution and health problems and premature death.

5

In 2021, indoor air pollution caused an estimated 3.6 million premature deaths, while outdoor air pollution
caused 4.2 million.

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The health impacts of air pollution continue to rise through to 2050 in the APS, despite
the achievement of all announced emissions reductions goals. This is because fossil fueluse in many emerging market and developing economies does not dramatically decline
until after 2030, leaving many exposed to high levels of pollution during this decade. The

SDG 7 goal of universal access to clean cooking by 2030 is not achieved in this scenario,
which has a similar effect. Only in the NZE Scenario do we see a major difference inoutcomes, with nearly two billion fewer people breathing heavily polluted air in 2050
than today (Figure 1.21).
Figure 1.21 ⊳ Population exposed to heavily polluted air, 2021 and 2050
Emerging market anddeveloping economies

2021

Advanced economies
STEPS 2050
APS 2050
NZE 2050
1

2

3Billion people
IEA. CC BY 4.0.

The APS sees a lower number of people breathing heavily polluted air than in the STEPS
but only in the NZE Scenario does the number in 2050 fall below current levels
Note: Heavily polluted air = PM2.5 concentrations ≥ 35 microgrammes per cubic metre.

1.4.1

Selected country and regional trends

The Inflation Reduction Act and the Bipartisan Infrastructure Act catalyse a sharp rise in thepace of energy transitions in the United States compared with the WEO‐2021 (Box 1.5).
Strong growth in renewables means that coal demand falls by three‐quarters to 2030
(Figure 1.22). Gas‐fired generation peaks before 2030: overall natural gas demand ends thedecade just under the level it reached in 2021, allowing for increased exports of LNG. Oil
demand falls by 1 mb/d by 2030 from nearly 18 mb/d today, largely due to an increase in EV
sales (30% of car sales in 2030) and fuel economy improvements. Policy changes also provide
support for lifetime extensions for the ageing fleet of nuclear power plants. The STEPS
projections are consistent with a nearly 40% reduction in US energy‐related CO2 emissions
to 2030 relative to 2005 levels. In the APS, the United States achieves its stated ambition of
net zero emissions from the electricity sector around 2035 through faster deployment of
renewables, CCUS, hydrogen and ammonia, and an expansion of nuclear power including
development of small modular reactors. Sales of EVs rise more quickly than in the STEPS, and
EVs account for one‐out‐of‐two cars sold by 2030.

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United States

Figure 1.22 ⊳ Energy demand growth by region and scenario, 2021-30

Oil (mb/d)

4

0
‐2
‐4

Natural gas (bcm)1

2

UnitedStatesEuropean
Union

Japan

China

India

Southeast
Asia

AfricaMiddle East

UnitedStatesEuropean
Union

Japan

China

India

Southeast
Asia

AfricaMiddle East

UnitedStatesEuropean
Union

Japan

China

India

Southeast
Asia

AfricaMiddle East

UnitedStatesEuropean
Union

Japan

China

India

Southeast
Asia

AfricaMiddle East

UnitedStatesEuropean
Union

Japan

China

India

Southeast
Asia

AfricaMiddle East

200
100
0
‐100
‐200

Coal (Mtce)

500
250
0
‐250

Emissions (Gt CO2)

Renewables (EJ)

‐500

16
12
8
4

2
1
0
‐1
‐2

2010‐192021‐30:

STEPS

APS

Fast growing regions see energy demand met by a range of fuels and technologies, while
growth in advanced economies is met exclusively by low-emissions sources

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Box 1.5 ⊳The Inflation Reduction Act: a major landmark in US transitions

The US Inflation Reduction Act commits nearly USD 370 billion to energy security andclimate change provisions, more than one‐third of all government spending earmarked
for clean energy in recovery packages since the outbreak of the Covid‐19 pandemic in
2020. This comes on top of an additional USD 190 billion for clean energy and mass transit
in the Infrastructure Investment and Jobs Act, adopted in November 2021.
Together, these bolster efforts to reduce greenhouse gas emissions in the United States,
resulting in around 40% less CO2 emissions in 2030 in the STEPS relative to 2005 levels.
The largest impact of the Inflation Reduction Act is in the electricity sector, where CO2
emissions in 2030 are almost 50% lower than today, due to tax credits accelerating the
deployment of solar PV and wind, combined with support for nuclear lifetime extensions
and batteries. Tax credits for electric cars help lift annual sales from 0.6 million today (5%of car sales), to nearly 4.5 million in 2030 (30% of sales). Technologies that aid emissions
reductions in hard‐to‐abate industrial sectors, such as CCUS and low‐emissions hydrogen,all are eligible for substantial tax credits, which lay the foundations for strong growth.
Figure 1.23 ⊳ Government funding in the US Inflation Reduction Act andInfrastructure Investment and Jobs Act and technology
deployment in the STEPS in the United States, 2021-30
Allocation of government funding
40%
60%

20%

Low‐emissions powerLow‐emissions vehicles

80%

100%

Technology innovation

Other

50
40
30

6

Low‐emissionshydrogen (Mt)60

Sales (million)

Additions (GW)

Technology deployment in the United States in the STEPS
5
4
3

3.0
2.5
2.0
1.5

20

2

1.0

10

1

0.5

2021 2030
Solar PV

2021 2030
Wind

2021 2030
Electric cars

2021 2030
IEA. CC BY 4.0.

Recent US legislation provides nearly USD 560 billion for clean energy,

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significantly boosting clean power, electric cars, and low-emissions hydrogen

These incentives mobilise substantial additional private investment. With the tax credits,the levelised cost for new solar PV and wind in the United States would be lower than
new renewable projects in all other regions in the STEPS. When stacked with the low‐emissions hydrogen production tax credits, hydrogen produced using solar PV or wind
could cover upfront investment within the first year of investment when secured against
the future tax credit revenues. Direct air capture projects, if capturing the full tax
benefits, could be in a similar situation by the end of this decade. This removes many
critical barriers for these industries and their off‐takers, and is set to move these newtechnologies rapidly along the learning curve towards larger scale commercial
deployment. Higher incentives are available for projects and consumers using goods
manufactured in the United States, which coupled with tax credits for investors, is set toprovide a major boost to clean energy manufacturing in the United States.

1

Overall, the Inflation Reduction Act leads to a strong uptick of new clean energy projects
in the STEPS. In the power sector, annual solar and wind capacity additions expand
2.5‐times over current levels by 2030, while electric car sales expand around seven‐fold(Figure 1.23). These trends, along with other efficiency policies and efforts to reduce
methane emissions, increase the availability and value proposition of US oil and gas
exports, which help to substitute for lower exports from Russia.

European Union
Higher coal use during the energy crisis proves temporary as energy transitions gather pace.
In the STEPS, strengthened policy targets and frameworks, high fossil fuel prices and the drive
to reduce import dependency on Russia mean that the European Union sees demand for coalfall by around half by 2030, and demand for natural gas and for oil by almost a fifth each.
Deployment of wind and solar PV gains further momentum and they respectively account foralmost for 30% and 15% of electricity generation by 2030 in the STEPS, up from 13% and 5%
in 2021. In end‐use sectors, reductions in natural gas use in buildings and industry and theuptake of EVs in road transport contribute the majority of the reductions in fossil fuel use.
In the APS, targets in the Fit for 55 package are largely met – and in some cases exceeded –to fulfil the NDC objective to reduce greenhouse gas (GHG) emissions by 55% by 2030 relative
to 1990. This means CO2 emissions decline by around 45% relative to 2021 levels in the APS,
compared to 26% in the STEPS. Rapid renewables deployment, efficiency gains andelectrification drive a faster reduction of natural gas use in the power and buildings sectors
than in the STEPS, as well as lower demand for oil. The European Union moves towards anelectricity system dominated by wind, with onshore and offshore sources together
accounting for just over 40% of total generation in 2050 in the STEPS and 50% in the APS.

Japan sees a 1% annual reduction in total energy supply to 2030 in the STEPS, in line with its
new Strategic Energy Plan approved in October 2021. This plan foresees restarting nuclear
reactors that are offline and lifting both the shares of nuclear and renewables to allow for a
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Japan

significant reduction in reliance on coal‐ and gas‐fired plants. Japan is also seeking to retrofit
coal plants to co‐fire with ammonia; it is the only country deploying this technology atsignificant scale in the STEPS.
In the APS, a 36% decrease in emissions from 2021 to 2030 is achieved via further
electrification of industry and transport, and acceleration of energy efficiency improvements,for example through building materials standards for new construction. Additional policy
impetus comes from the new Energy Efficient Technological Strategies and strengthening its
Top Runner programme. Further decarbonisation of the power sector in the APS reflects the
new Green Transformation initiative, which would make large‐scale funding available tovarious low‐emissions technologies, reinforce the effort to revive nuclear reactors andintroduce measures to support manufacturers of nuclear technology.

China
Growth in energy demand in China has been a major driver for all manner of energy trends
over the past two decades, yet it slows in the STEPS and stalls before 2030, with emissions
peaking around the same time (in line with its NDC and national targets). Renewables
account for nearly 45% of electricity generation in 2030 and account for the majority of theelectricity demand growth, helping unabated coal use to peak before 2030 in alignment withgovernment targets. Oil demand also peaks in the second‐half of this decade, reaching asimilar level of demand as the United States in 2030 at just under 17 mb/d (with a population
four‐times larger) before declining. This peak and decline reflect rising EV sales, and China
remains the world’s largest EV market.
In the APS, the peak in emissions occurs slightly earlier and at a lower level as China
accelerates action to achieve carbon neutrality before 2060. Electrification via low‐emissions
sources is central to its emissions reduction efforts: total generation in 2050 rises by
two‐thirds in the STEPS and nearly doubles in the APS. The share of low‐emissions
technologies exceeds 75% in the STEPS and 90% in the APS, up from 34% today. The world’s
largest new build nuclear programme means an expanding role: new projects add more than
120 GW of nuclear capacity in the STEPS, and 160 GW in the APS, on top of the 50 GW in
operation today.

India

Coal generation is projected to continue to expand in absolute terms in the STEPS, peaking
around 2030, though its share of electricity generation falls from just below 75% to 55% over70

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India becomes the world’s most populous country by 2025 and, combined with the twin
forces of urbanisation and industrialisation, this underpins rapid growth in energy demand,
which rises by more than 3% per year in the STEPS from 2021 to 2030. It sees the largest
increase in energy demand of any country. Even though India continues to make great strides
with renewables deployment and efficiency policies, the sheer scale of its development
means that the combined import bill for fossil fuels doubles over the next two decades in the
STEPS, with oil by far the largest component. This points to continued risks to energy security.

this period. Government programmes, such as the Gati Shakti National Master Plan and theSelf‐Reliant India scheme, and strong economics underpin robust growth in renewables andelectric mobility, notably for two/three‐wheelers. Renewables meet more than 60% of thegrowth in demand for power, and account for 35% of the electricity mix by 2030: solar PV
alone accounts for more than 15%. However, coal still meets a third of overall energy
demand growth by 2030, and oil, mainly for transport, another quarter. In the APS, more
rapid progress in deploying low‐emissions alternatives in power, industry and transport
sectors in particular puts India on a trajectory in line with its goal of net zero emissions by
2070.

1

Southeast Asia
Southeast Asia is also projected to see a rapid rise in energy demand, with annual average
growth of more than 3% from 2021 to 2030 in the STEPS. This is met by increases in all fuels
and technologies, led by oil. Coal continues to dominate in the electricity sector, its sharedeclining only slightly from 42% today to 39% by 2030 in the STEPS. With the implementationin full of announced pledges – notably Indonesia’s goal to halt unabated coal generation by
the 2050s – coal use in the power sector falls by more than half by 2050 in the APS, andrenewables quickly become the largest source of electricity generation. Electricity use
extends to new end‐use sectors, driven by targets to halt sales of ICE vehicles in Thailand by2035 and in Singapore by 2040, and the aim of Indonesia to achieve 2 million electric cars on
the road by 2030.

AfricaThe global energy crisis has been a setback for many African countries, with the partial
exception of energy exporters. High energy prices have contributed to rising costs for basic
foodstuffs both directly (cost of energy for agricultural equipment) and indirectly (throughhigher natural gas input costs for nitrogen fertilisers). In the STEPS, low cost renewable
power, including solar PV, hydro and geothermal, adds substantially to the energy supply
over the coming decades, and renewables provide one‐third of total generation by 2030.
Growth in oil in transport and for liquefied petroleum gas (LPG) for cooking push demand toover 5 mb/d by 2030; natural gas, supported by new discoveries, fuels the expanding steel,cement, water desalination and fertiliser industries.

Natural gas meets more than 60% of energy demand growth in the Middle East to 2030 in
the STEPS, much of which is due to an increase in the use of natural gas in water desalination
plants. Gas demand remains relatively resilient in the APS, with a small but increasing shareused for hydrogen production. Renewables meet half of rising power demand, thanks tosome of the lowest cost solar in the world and an increasing policy focus on diversifying theenergy sector and the broader economy. With large hydrocarbon reserves and renewables
potential, many Middle East countries are also exploring the potential for hydrogenproduction and trade, with Europe and Japan the main potential buyers.
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Middle East

1.4.2

Keeping the door to 1.5 °C open

Today’s policy settings fall short of what is needed during a critical decade to deliver thecollective emissions reductions contained in the NDCs, and even further short of what isrequired to align with a 1.5 °C stabilisation in global average temperatures. In 2030, CO2
emissions in the APS are around 5 Gt CO2 lower than in the STEPS, but nearly 9 Gt CO2 higher
than in the NZE Scenario. The gap between the APS and the NZE Scenario to 2030 is nearly
twice as large as the gap between the STEPS and the APS, highlighting the need not only to
implement existing pledges but also to raise the overall level of ambition.
Closing the gap between the STEPS and the APS trajectories, and then with the NZE Scenario,
will depend on the world’s ability to scale up resilient clean energy supply chains, which has
clear implications for the need for investment in traditional elements of supply. This
overview chapter concludes with a review of our findings on these critically important andhighly interdependent questions.

Priority measures to close the gap with the NZE Scenario to 2030
What are the key policy measures and instruments that will be required this decade to
implement existing pledges and close the gap between the STEPS and the APS trajectories,
and then with the NZE Scenario?
The most rapid changes and the largest emissions reductions this decade will need to comefrom the electricity sector, and in particular from a rapid expansion of clean electricity
generation and a consequent decline in emissions from coal (Figure 1.24).6 The early
decarbonisation of electricity supply is a critical element to energy transitions, since clean
electricity not only cuts power sector emissions but also helps bring about emissions
reductions in end‐use sectors as they increasingly look to electricity to meet demand forenergy services. As a result, electricity becomes the “new oil” in terms of its dominant rolein final energy consumption. Unlike oil, however, it plays a role in all end‐use sectors and also
drives huge improvements in the overall efficiency of the energy system. By 2050, electricity
provides two‐thirds of the useful energy enjoyed by consumers, much higher than its sharein final consumption (slightly more than one‐half).

6

In November 2022, the IEA will release Coal in Net Zero Transitions: Strategies for rapid, secure and people‐
centred change.

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Despite its position in the vanguard of energy transitions, the electricity sector emitted
13 Gt CO₂ in 2021, more than one‐third of global energy‐related CO₂ emissions. Electricity
sector CO2 emissions peak in the coming years in each scenario and are followed by steep
reductions. Additional pledges and announcements over the past year have helped close theprojected gap in emissions between the APS and NZE Scenario, especially in advanced
economies where the full implementation of country pledges would now bring the outlook
close to that of the NZE Scenario. However, there remains a huge amount to be done tocompletely close this gap, particularly in emerging market and developing economies.

Figure 1.24 ⊳ CO2 emissions reductions in selected sectors, 2021-2030

1

Coal power
Energy‐intensive industries

NZE
APS

Cars

STEPS

Space heating
‐6

‐5

‐4

‐3

‐2

‐1

0

1
Gt CO₂
IEA. CC BY 4.0.

Reducing emissions from coal-fired power, energy intensive industries, cars and spaceheating accounts for three-quarters of total emissions reductions to 2030 in the NZE Scenario

The reduction in emissions from coal‐fired power generation call for a dramatic accelerationin deployment of low‐emissions sources, mainly renewables, supported by measures toexpand and modernise grids and to incentivise investment in various forms of flexibility,
including energy storage. There is no way to tackle climate change effectively without a surge
in investment in clean power and infrastructure that significantly reduces coal‐fired
generation. If the existing fleet of coal‐fired power plants were to operate as they have inrecent years for the next 50 years, this alone would take up two‐thirds of the remaining CO2
budget consistent with limiting the global average temperature increase to 1.5 °C.

Two other critical strategies to close the gap with climate objectives are energy efficiency
improvements and electrification of end‐uses. Efficiency improvements, combined withmore robust materials efficiency and behaviour change, are fundamental in the NZE Scenario
to facilitate a much faster rise in the share of low‐emissions electricity supply. In 2030, energy
savings from these measures as well as behavioural changes amount to around 110 EJ,
equivalent to total final energy consumption of China today. As a result, total energy supply
declines by 10% over the coming decade in the NZE Scenario even as the global economy
grows by nearly a third. This contrasts with a 2% increase in total energy supply over thesame period in the APS and a near 10% rise in the STEPS.
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Despite the huge investment required, the rapid replacement of fossil fuel generation by
renewables, principally solar PV and wind, helps to reduce electricity costs as well as
emissions. In the NZE Scenario, electricity costs come down from their current high levels by
the middle of the decade, and total electricity supply costs per unit of electricity generation
are then broadly stable to 2030. After 2030 they start to reduce: by 2050 the average cost ofelectricity is around 10% below the level seen in 2021.

Expanding electrification and the widespread deployment of efficiency and energy savings
enable the buildings sector to almost halve its emissions in the NZE Scenario by 2030, despite
the continued expansion of floor area and appliance ownership driven mainly by emerging
market and developing economies. The switch from traditional biomass to more efficient
cook stoves and fuels is also an important driver of overall trends. Electricity becomes theprincipal source of energy for decarbonised heating: homes using electricity for heating risefrom 20% today to 30% in 2030 and to more than 50% in 2050, with high efficiency heatpumps becoming the primary technology choice.
Emissions trends in the transport sector are determined by how quickly oil can be displaced;at present it accounts for 90% of energy use in transport. Both passenger and freight activity
are set to more than double by 2050, underpinned by higher mobility demand needs in thedeveloping world as economies and populations expand and living standards rise. Reductions
in emissions of around one‐quarter to 2030 in the NZE Scenario are driven by increased
electrification, efficiency improvements and behaviour change.
Electric vehicles offer the most cost‐effective low‐emissions technology in most segments inboth the short and long term, and they come to dominate road transport. By 2030, 60% of
all new car sales are electric in the NZE Scenario (compared with 35% in the APS and 25% in
the STEPS). The electrification of heavy freight segments proceeds more slowly, while
emerging market and developing economies initially focus on the electrification of
two/three‐wheelers and urban buses. Over the longer term, the blending and direct use of
low‐emissions fuels such as biofuels, hydrogen and hydrogen‐based fuels increases
significantly, especially in aviation and shipping, and for long‐haul road freight.
The outlook for energy use in industry is shaped by continuing growth in demand forindustrial materials. In the STEPS, world output of crude steel increases by around 10% by2030, and around 30% by 2050, driven by India, Southeast Asia and Africa. Global output of
cement also expands as Africa and India continue the process of urbanisation andindustrialisation. A much stronger focus on more efficient use of materials tempers thisgrowth in the NZE Scenario, but it is not enough to prevent an overall increase in demand forindustrial materials.

Progress in some areas therefore depends on the further development of key technologies.
This underscores the importance of enhanced public support for innovation anddemonstration projects in the 2020s so that these technologies can be deployed at scale inthe 2030s and beyond. Between 2031 and 2040, the speed of emissions reductions in theindustry and transport sectors accelerates to almost 10% per year in the NZE Scenario, as

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Nonetheless, the industry sector sees a reduction of nearly a quarter in overall emissions by
2030 in the NZE Scenario. Widespread implementation of more stringent efficiency
standards and policies encouraging fuel switching are the key measures to generate these
reductions in the near term. Some technologies required for the transition of energy‐
intensive industrial branches are not yet commercially available.

electrification, low‐emissions fuels and CCUS technologies start to make more significant
inroads into the existing stock of assets.

1

In addition to rapid cuts in CO2, the NZE Scenario entails a steep fall in other energy‐related
greenhouse gases. For example, energy‐related methane emissions drop by 75% from125 Mt in 2021 to 30 Mt in 2030, on track for less than 10 Mt in 2050. Some of this occurs
because of the overall reduction in fossil fuel consumption, but most of it comes from a hugeincrease in the deployment of emissions reduction measures and technologies across the oil,natural gas and coal supply chains. These measures lead to the elimination of all technically
avoidable methane emissions by 2030. Reducing methane leaks and a rapid phase out in all
non‐emergency flaring would bring a double dividend: relief for very tight gas markets andreduced greenhouse gas emissions.

Scaling up clean energy supply chains
Accelerating clean energy transitions requires large increases in the global manufacturing
capacity of clean energy technologies and in related inputs such as critical minerals. Meeting
this industrial challenge is essential to reduce emissions in line with climate goals, plus it will
create jobs in the companies and countries that are positioned to take advantage of themarket opportunities (Box 1.6).
Current deployment trends for key clean energy technologies show some encouraging signs.
Renewables‐based electricity generation rose by a record 500 TWh in 2021 to reach an all‐time high and it looks set to mark a new record in 2022. Electric car sales reached a record
6.6 million in 2021, more than double the sales in 2020, and sales in 2022 are indicating
particularly strong growth, led by China, United States and European Union.
Planned increases in global clean energy manufacturing capacity for key technologies
provide a crucial leading indicator of the way that things could evolve (Figure 1.25). There
are some technologies where a lack of manufacturing capacity risks becoming a bottleneck.
For example, current and planned manufacturing capacity for heat pumps is below the levels
projected in the APS. There are also some encouraging signs. Increasing confidence in future
demand, boosted by measures such as the US Inflation Reduction Act that encourage
investment in more resilient and diversified supply chains, means that companies andcountries are scaling up clean energy manufacturing capacity.

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For some technologies, announced capacity increases exceed the required manufacturing
capacity in 2030 in the APS. For example, if all announced expansions of electrolyser
manufacturing capacity see the light of day, it would lead to global manufacturing capacity
around 50% higher by 2030 than projected in the APS. In the case of solar PV, the potential
excess capacity if all announced projects are implemented relative to APS levels would beeven larger, at 80%. This provides important comfort to policy makers that their collective
ambitions are not only aligned with global supply chains, but that even more robust ambition
would be possible.

Figure 1.25 ⊳ Announced manufacturing capacity for selected energy
technologies relative to deployment in the APS, 2021 and 2030
Batteries

Solar PVElectrolysers

Lithium

Copper200%

150%

APS deployment

100%

50%

2021

2030:

Announced pipeline

Exceeding APS

Still needed to reach APS
IEA. CC BY 4.0.

Announced increases in manufacturing capacity for key technologies, including solar PV,
electrolysers and batteries, would exceed projected deployment in 2030 in the APS
Note: Shows annual production capacity in 2030 relative to the level of demand projected in the APS in 2030.

This optimistic message, however, needs to be tempered with caveats. First, it is far fromguaranteed that all of the announced projects will come to fruition. For example, if we
exclude more speculative announcements such as those without a clear start date from thecalculation for electrolysers, then the announced manufacturing capacity for 2030 would fallshort of the needs in the APS. Therefore, it is critical that policy continues to play a supportiverole to help turn these ambitions into reality.
Second, the finding that in some instances announced supply capacity exceeds our
projections for 2030 demand in the APS is also a risk to markets and suppliers. In some cases,
policy makers need to do more to ensure that demand actually materialises. For example, inthe case of solar PV, policy action is essential to address local barriers to uptake, including
those relating to land acquisition, permitting, provision of timely grid connections and secure
integration of the variable resource into electricity systems.

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Third, not all parts of any given supply chain are developing new capacity at the same rate.
For example, even though announced projects and potential new projects would see lithium
supply capacity expand three‐and‐a‐half‐times to 2030, this is still not sufficient to meet APS
needs. The smooth growth of clean technology supply chains requires co‐ordination andsequencing across all parts of the value chain, from inputs to manufacturing capacity throughto demand. Good data on projects, capacities and project timelines together with credible
commitments to future levels of deployment are essential to limit future volatility.

Fourth, today’s clean technology supply chains are very concentrated geographically. China
accounts for 75% of the world’s production capacity for battery cells, and as much as 97% of
global capacity for wafer manufacturing for PV cells (14% of global wafer production in 2021
was at a single factory in China). This industrial capacity has been instrumental to bring down
costs worldwide, giving much‐needed momentum to clean energy transitions, but thecurrent level of geographical concentration also poses potential challenges thatgovernments need to address. Maintaining the economic efficiency benefits of trade while
diversifying supply chains will be critical to ensure that clean energy transitions are bothsecure and cost effective.

1

In addition, even if the projected growth of clean technology supply chains is encouraging
when measured against the benchmarks set by the APS, it is still insufficient to bring theworld into line with the trajectory in the NZE Scenario. None of the clean energy technologies
or critical minerals shown in Figure 1.25 currently have an announced supply capacity
sufficient to meet the massive ramp‐up needed in the NZE Scenario by 2030, althoughbatteries and solar PV get close (see Chapter 3, Box 3.6).
Box 1.6 ⊳Energy job growth: opportunity or bottleneck?

Energy transitions are already starting to transform the landscape for energy
employment, with more than 50% of the energy workforce now employed in clean
energy (IEA, 2022). The development of new energy‐related projects, including the
manufacture of their components, is the largest driver of energy employment,
accounting for over 60% of energy‐related jobs. The energy sector, which is not clearly
defined by industrial codes, includes workers from several industrial sectors. Their work
includes constructing new power generation facilities and transmission lines, carrying out
efficiency retrofits, installing heat pumps, completing new oil and gas wells, anddesigning and constructing infrastructure.
In the NZE Scenario, total energy investment more than doubles to 2030, driving up thedemand for skilled workers across the energy sector. Energy employment expands toalmost 90 million in 2030 from around 65 million today (Figure 1.26). Job growth in the
APS is less dramatic, but energy employment still reaches 80 million in 2030. In all
scenarios, the number of new jobs created outweighs the number of those lost in fossil
fuel industries, although the jobs that are created may not be in the same places as thosethat are lost, and the required skills in many cases will be different.

The energy sector demands, as a whole, far more skilled workers than economy‐wideaverages – around 45% of energy workers today are in high skilled occupations,
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Recent legislative and policy measures, such as the US Inflation Reduction Act, Make inIndia and Japan’s Green Transformation (GX), include provisions to support thedevelopment of local clean energy manufacturing. There is a strong case for bolsteringsuch provisions with strategic and proactive labour policies to ensure that their ambitions
are not hampered by a shortage of skilled workers.

compared to only one‐quarter economy‐wide. This share is even higher for jobs in energy
research and development, and the number of such jobs is set to expand rapidly to 2030
and beyond. Establishing market strength in clean energy technologies is likely to besignificantly helped by tailored training and certification, an area where businesses
should work in close collaboration with ministries of energy, labour and education.

Million employees

Figure 1.26 ⊳ Global employment in fossil fuels and clean energy
100

100%

80

80%

60

60%

40

40%

20

20%

Clean energy
Fossil fuels

2019

2020

2021

APS
2030

Share ofemployment
in clean energy(right axis)

NZE
2030
IEA. CC BY 4.0.

Clean energy employment makes up just over half of the energy workforce today
and this share rises significantly in both the APS and the NZE Scenario

In order to attract workers, including those moving from other parts of the energy sector,
firms will need to take account of various factors. Energy sector wages typically have apremium relative to economy‐wide average wages, though established industries suchas nuclear, oil and gas typically offer the highest wages, which may make it challenging
to attract workers to new clean energy industries. Newer industries, such as solar, often
do not have the same labour protections and union representation as established fossil
fuel industries, especially in emerging market and developing economies.
The percentage of women in the energy workforce is consistently low when comparedto economy‐wide averages: it averages 15% in traditional energy sectors compared to
39% in the economy as a whole. As the energy workforce expands, there will be
opportunities to address these long‐standing imbalances.

Our scenarios project widely different outlooks for oil and gas demand, and therefore also
for the investments that are required. If demand increases in the future or remains at aconsistently high level – as in the STEPS – new upstream conventional projects are required
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Implications for investment in oil and gas

to meet this demand and to offset declines in production from existing fields. New upstream
projects are needed in the APS as well; even though global demand soon peaks and starts tofall, the reduction in demand is slower than the rate at which production from existing fields
declines.

1

In the IEA’s Net Zero by 2050 Roadmap, first published in 2021 (IEA, 2021a), a huge surge inclean energy investment led to a large projected drop in oil and gas consumption. The
trajectory of falling demand matched the declines in supply that would be seen with
continued investment in existing sources of supply but without any need for the approval of
new long lead time upstream conventional projects.
However, over the year since the 2021 Roadmap was published, oil and gas demand has risen
and additional oil and gas (and coal) projects have received final investment decisions; all the
new investments in fossil fuel infrastructure not included in the 2021 NZE Scenario would
result in 25 Gt of emissions if operated to the end of their lifetime (around 5% of theremaining carbon budget for 1.5 °C). Russia’s invasion of Ukraine adds an additional
dimension to this outlook, as it could now lead to a substantial and prolonged reduction in
Russian energy supplies.
Against this backdrop, does the 2021 finding that no new oil and gas fields are needed along
the journey to net zero by mid‐century still hold for the updated NZE Scenario in this year’s
Outlook? There are two dimensions to this question, which need to be treated separately.
First, how can countries replace the immediate shortfalls in fossil fuel supply from Russia?
And second, have circumstances changed in a way that could justify approvals of new oil andgas fields, even in a world working towards net zero emissions by 2050?
On the first question, the immediate shortfalls in Russian fossil fuel production need to be
replaced in part by production elsewhere, in any scenario. The size of the shortfall depends
in large part on the strength of actions taken to reduce demand. But new conventional oil
and gas field approvals taken today would not help to meet these immediate needs, as thelead times for large new supply projects mean that they take many years to start producing
meaningful volumes.

On the second question, it is worth taking a step back and considering the sort of world the
NZE Scenario is describing. As the 2021 Roadmap underlined, this is a world that is united inits determination to achieve the 1.5 °C goal, and that is working consistently andcooperatively towards that goal. In the words of the 2021 Summary for Policymakers: “theunwavering policy focus on climate change in the net zero pathway results in a sharp decline
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The more suitable options are investments with shorter lead times and quicker payback
periods. These include, for example, extending production from existing fields, tight oil andshale gas (which can be brought to market quickly), and making use of natural gas that iscurrently flared and vented. Some new infrastructure may also be needed to facilitate thediversification of supply away from Russia. For example, many European countries arelooking to install LNG import terminals and, with careful investment planning, there areopportunities for these to facilitate future imports of hydrogen or hydrogen‐based fuels.

in fossil fuel demand, meaning that the focus for oil and gas producers switches entirely to
output – and emissions reductions – from the operation of existing assets.”
The NZE Scenario in this Outlook relies on a similar vision of the future to that in the 2021
Roadmap. And, as a result it remains the case that – with the steep reductions in fossil fueldemand in the NZE Scenario in this Outlook – fossil fuel demand can be met throughcontinued investment in existing assets and already approved projects, but without any newlong lead time upstream conventional projects.
Meeting this condition, though, comes with consequences that countries need to consider
carefully, especially in a world marked by geopolitical tensions. One crucial aspect – alreadyhighlighted in the 2021 Roadmap, and even more visible in this year’s update – is theincreased reliance over time on a smaller concentration of suppliers. In the case of oil, theupdated NZE Scenario requires higher near‐term production from members of OPEC than
before to keep markets in balance, and a continuing high level of reliance on this production
to meet remaining oil demand through to 2050. In the NZE Scenario, the share of oil supply
coming from OPEC members rises from 35% in 2021 to 52% in 2050. Even though the oilmarket is much smaller in 2050 than today, the share of OPEC by then would be higher thanat any point in the history of oil markets. It cannot be taken for granted that importers will
be comfortable with such a concentration in supply.
In the case of natural gas, the reduction in Russian supply to Europe in this year’s NZE
Scenario is accompanied by lower projected gas use, as higher prices curb the costeffectiveness of gas helping to displace coal. But Europe is still left in a precarious situation.
In last year’s NZE Scenario, Europe’s declining gas import needs were met in large part bycontracted gas supply from Russia. In this year’s scenario, Europe relies on natural gas
becoming available from elsewhere in the world. This includes gas that has already been
contracted to Asian importers – notably in China – that is surplus to their requirements asthese countries undertake efforts to cut emissions. In this case, Europe may want greatercertainty over its gas import requirements by concluding new gas supply arrangements, evenas it redoubles its efforts to reduce reliance on all fossil fuels.

Discussion of the supply and investment aspects of the transition should not distractfrom the need for a massive surge in investment in renewables, energy efficiency andother clean energy technologies. This is the necessary condition that needs to be met inorder to reduce and then remove the need for new field developments.

Any emissions coming from new projects would need to be compensated by even morerobust emissions reductions in the latter years of our projections to achieve net zero
emissions by 2050; they do not come for free in climate terms. This would make thelater stages of the transition even more challenging, and creates the clear risk that thistarget moves out of reach. No one should imagine that Russia’s invasion can justify awave of new oil and gas infrastructure in a world that wants to reach net zero emissions
by 2050.

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The possibility of additional oil and gas projects, beyond the levels of supply needed in the
NZE Scenario, comes with some important caveats and qualifications:

Any new developments that do go ahead would have to prioritise low‐emissions
technologies across the full supply chain from extraction, processing and transport toend‐use. This means minimising methane leaks and other upstream and midstream
emissions, and integrating the use of CCUS or of non‐combustion uses of thehydrocarbons. For new LNG liquefaction facilities, projects would likely need to have amuch shorter lifetime for delivering natural gas than is traditionally the case. This could
mean shortening the period of capital recovery, making the delivered gas more
expensive, and planning from the outset how to extend emissions reductions across thewhole value chain, for example by moving to delivery of low‐emissions gases.

1

If the world is successful in bringing down fossil demand quickly enough to reach net
zero emissions by 2050; any new projects would face major commercial risks. The
countries or companies choosing to undertake them need to recognise that thesedevelopments may fail to recover their upfront costs. They would also need to plan andjustify for how global production levels will be further reduced in the future in a
successful transition to net zero emissions by mid‐century.

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It is understandable why some countries and companies are looking to move ahead with the
exploration and approval of large longer‐term supply projects. But the higher emissions thatthese projects imply have consequences for our efforts to meet a 1.5 °C, and it is imperativethat decision makers today make the additional burden on future generations as light as
possible. There are many ways to respond to the immediate energy crisis that can pave theway both to a more secure and a cleaner future. That is where the lasting solutions lie.

Chapter 2
Setting the scene
Context and scenario design
S U M M A R Y
 The recovery in global energy consumption that followed the pandemic‐induced dropin 2020 ended prematurely with Russia’s invasion of Ukraine in early 2022, plunging
global energy markets into turmoil, stoking inflationary pressures and slowing
economic growth. The strains on markets did not begin with Russia’s invasion of
Ukraine, but they have been sharply exacerbated by it. This has led to volatility andsteep spikes in energy prices, particularly for natural gas in European markets, andthe menace of further disruption to supply looms large. Amid this turmoil, growth inrenewables has held up well.

 The crisis has shattered energy relationships with Russia built on the assumption oftrust and secure supplies, and led to a reappraisal of energy security needs in many
countries. This is leading to a recasting of the energy trade and investment landscapein profound ways. It has already prompted a host of measures aimed at strengthening
energy security, including support to build domestic production capability in key
sectors.

 One key question is whether today’s crisis will lead to acceleration in energy
transitions, or whether a combination of economic turmoil and short‐term policy
choices will slow momentum. On the one hand, high fossil fuel prices and record levelsof emissions offer strong reasons to move away from reliance on these fuels or to usethem more efficiently. On the other, energy security concerns may spur renewed
investments in fossil fuel supply and infrastructure. This Outlook considers theimplications of different policy choices.

 Today’s energy crisis shares some parallels with the 1970s oil price shocks, but there
are also important differences. The crises in the 1970s were concentrated in oil
markets and the global economy was much more dependent on oil than it is today.
However, the intensity of use of other fossil fuels has not declined to the same extent;
for natural gas it has risen in many cases. The global nature of the current crisis, its
spread across all fossil fuels and the knock‐on effects on electricity prices are all
warning signs of broader economic impacts.
COP26 meeting in Glasgow in 2021, and these remain the bedrock for many energy
strategies. In some cases, these ambitions have now been reinforced by new
measures seeking to reinforce long‐term energy security and accelerate energy
transitions, including the US Inflation Reduction Act and the REPowerEU Plan. The
total amount of government spending committed to clean energy transitions since
the start of the pandemic amounts to USD 1.1 trillion.

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 Governments made a host of commitments to sustainability in the run‐up to the Near‐term borrowing costs are likely to rise as monetary policy tightens in many
countries. This could disadvantage some clean energy projects for which financing
costs play a major role in levelised costs. Nonetheless, clean technologies remain themost cost‐efficient option for new power generation in many countries, even before
taking account of the exceptionally high prices seen in 2022 for coal and gas.

 This Outlook explores three scenarios – fully updated – that provide a framework forthinking about the future of energy and exploring the implications of various policy
choices, investment trends and technology dynamics. The scenarios, which should not
be considered as IEA forecasts, are:o Stated Policies Scenario, which looks not at what governments say they willachieve, but at what they are actually doing to achieve the targets and objectives
they have set out, and assesses where this leads the energy sector.
o Announced Pledges Scenario, which examines where all current announced
energy and climate commitments – including net zero emissions pledges as wellas commitments in areas such as energy access – would take the energy sector if
implemented in full and on time.
o Net Zero Emissions by 2050 Scenario, which maps out a way to achieve a 1.5 °C
stabilisation in global average temperature and meet key energy‐related UN
Sustainable Development Goals.

 Rising demand for energy services to 2040 is underpinned by economic growth, which
is lower to 2030 than in last year’s Outlook but which averages 2.8% per year throughto 2050. The world’s population rises from 7.8 billion people in 2021 to 9.7 billion in
2050, an increase of almost one‐quarter. These economic and demographic
assumptions are kept constant across the various scenarios, while energy and climate
policies, technology costs and prices vary.

 Cost pressures are being felt across the energy sector from persistent strains on
supply chains and from higher prices for critical minerals and essential construction
materials such as cement and steel. We expect recent rises in clean technology costs
to be temporary, and to recede in the face of the forces of innovation andimprovements in manufacturing and installation processes. Current trends are,however, prompting governments to pay closer attention to the resilience anddiversity of clean energy supply chains, which cannot be taken for granted.

 Today’s exceptionally high fossil fuel prices are projected to ease as economies slow

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and markets rebalance, although natural gas markets remain tight for several years
as Europe competes for available LNG cargoes to compensate for curtailed Russian
supply. The speed of adjustment and the longer‐term price trajectories differ by
scenario, depending on the strength of policy action to curb demand.

Energy markets High and volatile energy prices are
hurting households and businesses,
shifting the choice of fuels and settingback progress towards achieving
universal access to energy.

Russia’s invasion of
Ukraine is reshaping
the energy world

Short-term responses have Energy policy
focused on securing available
supply and protecting consumers,
but many governments in the US,
EU and elsewhere have adopted
new policies that give a major
boost to investments in clean
energy and efficiency.

Energy trade European sanctions on coal andoil imports and Gazprom’s
decisions to cut gas supply are
triggering a profound reshufflingof trade flows around the world.

High fossil fuel prices are Economic impacts
stoking inflationary pressures;the combination of falling real
incomes and rising prices iscreating a looming risk ofglobal recession.

Russia has cut its
natural gas pipeline flows…

CO2 emissions from global
fossil fuel combustion...

…to the European Union by around
80% since invading Ukraine.

…saw a record rise in 2021, but a strong expansionof renewables and electric vehicles is expected
to dampen growth in 2022.

Feb 24 2022

Gt CO2
2

6%

mcm/d
300

1

3%

200

0

0%

-1

-3%

Russia’s invasion of Ukraine
Other
PolandUkraineTurkStream

100-2
Jan 22

Nord Stream

Oct 222020

Annual change:

2021
CO2 emissions

2022e

-6%

GDP growth (right axis)

2.1

Introduction

The world is in the middle of a global energy crisis of unprecedented depth and complexity.
Europe is at the centre of this crisis, but it is having major implications for markets, policies
and economies worldwide. As so often is the case, the poorest and most vulnerable are likely
to suffer most. The strains did not begin with Russia’s invasion of Ukraine, but they havebeen sharply exacerbated by it. Extraordinarily high prices are sparking a reappraisal ofenergy policies and priorities. The Europe‐Russia energy relationship lies in tatters, calling
into question the viability of decades of fossil fuel infrastructure and investment decisions
built on this foundation. A profound reorientation of international energy trade is underway,
bringing new market risks even as it addresses longstanding vulnerabilities.
Many of the contours of this new world are not yet fully defined, but there is no going backto the way things were. And we know from past energy crises that the process of adjustment
is unlikely to be a smooth one. That adjustment will also be taking place in the context ofcommitments made by governments to clean energy transitions. A central theme of thisWorld Energy Outlook 2022 is how the levers of technological change and innovation, tradeand investment and behavioural shifts might drive a secure transition towards a net zero
emissions energy system, while minimising the potential risks and trade‐offs between
various policy objectives.
This chapter sets the scene. It starts with an exploration of how the crisis has not justupended energy markets but also soured the economic outlook, before considering theunderlying forces bearing on today’s energy sector, the policy responses and what it allmeans for our starting point in 2022. Europe’s scramble to reduce reliance on Russian fossil
fuel imports takes centre stage, but the repercussions of Russia’s invasion of Ukraine arebeing felt much more broadly across a deeply interconnected global energy system.

Stated Policies Scenario (STEPS), which maps out a trajectory that reflects current policy
settings, based on a detailed sector‐by‐sector assessment of what policies are actuallyin place or are under development by governments around the world.



Announced Pledges Scenario (APS), which assumes that all long‐term emissions andenergy access targets, including net zero commitments, will be met on time and in full,even where policies are not yet in place to deliver them.

Net Zero Emissions by 2050 (NZE) Scenario, which sets out a pathway for the global
energy sector to achieve net zero CO2 emissions by 2050, updating the landmark IEA
analysis first published in 2021. While the first two scenarios are exploratory, the NZE
Scenario is normative, as it is designed to achieve the stated objective and shows apathway to that goal.

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The chapter concludes by introducing the scenarios used in this Outlook, explaining how andwhy they differ from each other, setting out the macroeconomic and demographic
assumptions that underpin them as well as the outlook for energy and carbon prices andenergy technology development. The three scenarios are:

2.2

Background to the global energy crisis

The historic plunge in global energy consumption in the early months of the Covid‐19 crisis
in 2020 drove the prices of many fossil fuels to their lowest levels in decades. However, theprice rebounds since mid‐2021 have been brutally quick (Figure 2.1). Oil prices that briefly
moved into negative territory in 2020 have been back around or above USD 100/barrel. Coal
prices have reached record levels. Spot natural gas prices in Europe have regularly been
above USD 50 per million British thermal units (MBtu), more than double the crude oil priceon an energy‐equivalent basis. Tight gas and coal markets have fed through into
exceptionally high electricity prices in many markets. The global energy crisis has hurt
households, industries and entire economies around the world, with the poorest and mostvulnerable suffering particular hardship.

Index (1 September 2020 = 1)

Figure 2.1 ⊳2Evolution in selected energy price indicators since
September 2020

25

TTF MA
German power

20

Asian spot LNG
EU imported coal

15

North Sea Brent
10
5

Sep‐20Mar‐21

Sep‐21Mar‐22

Sep‐22
IEA. CC BY 4.0.

This has been a period of extraordinary turbulence in energy markets,
intensified by Russia’s invasion of Ukraine in February 2022
Note: TTF MA = Title Transfer Facility month‐ahead prices; LNG = liquefied natural gas; Brent = Brent crude
oil benchmark.
Sources: IEA analysis based on Argus Media (2022); ICIS (2022); BNEF (2022).

2.2.1

Initial signs of strain

The rapidity of the economic recovery from the pandemic‐induced recession. This
strained many elements of global supply chains, including those in the energy sector. In
2021, demand for all the fossil fuels grew by at least 5%.

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There was no single cause behind the initial rise in prices in 2021, prior to Russia’s invasionof Ukraine. Many factors played a part, chief among them being:

The impact of weather‐related events on demand and electricity generation trends.
These events include droughts that curtailed hydropower output in Brazil and elsewhere(resulting in a more than threefold year‐on‐year increase in Brazil’s liquefied natural gas[LNG] imports), heat waves that reduced nuclear power availability in France andelsewhere, lower than average wind speeds that affected wind generation in Europe,and Hurricane Ida’s interruption of US offshore production.

Planned and unplanned outages to supply. Covid lockdowns in 2020 pushed somemaintenance work into 2021, which weighed on supply just when demand wasrecovering. Flooding in Australia in early 2022 temporarily interrupted coal production,
and a month‐long coal export ban in Indonesia tightened trading conditions, sending
prices much higher. Natural gas markets were meanwhile affected by unplanned
outages at LNG liquefaction plants, unforeseen repair works and a variety of project
delays.

The stance of major suppliers. The most notable example was Russia’s Gazprom, which
reduced its short‐term sales and did not replenish its own storage sites in Europe to thelevels seen in previous years or otherwise increase natural gas availability. This amplified
the market reaction when a cold spell hit Europe in December 2021.



Underlying investment dynamics. Governments have not been pursuing strong enoughpolicies to generate a much‐needed increase in clean energy investment. In the absenceof such a surge in energy efficiency improvements and clean energy deployment,
investment in the fossil fuels sector has also been falling short of what is required tomeet rising demand. Investment in upstream oil and gas halved between 2014 and 2021,
due primarily to two commodity price collapses in 2014‐15 and in 2020.

Climate policies were blamed in some quarters for contributing to the initial run‐up in prices,
but it is difficult to argue that they played a significant role. In fact, more rapid deploymentof clean energy sources and technologies would have helped to protect consumers andmitigate some of the upward pressure on fuel prices. They would also have mitigated thepost‐pandemic rebound in energy‐related carbon dioxide (CO2) emissions which reached36.6 billion tonnes in 2021. The annual increase of 1.9 billion tonnes was the largest in
history, offsetting the previous year’s pandemic‐induced decline.

Russia’s invasion of Ukraine

Russia’s invasion of Ukraine in February 2022 made the strains in the energy sector far worse.
Alongside huge damage to Ukraine’s energy sector (Box 2.1), it has had wider implications
for energy that will be felt for many years to come. Russia has been by some distance theworld’s largest exporter of fossil fuels, and a particularly important supplier to Europe: in
2021, one‐of‐five units of energy consumed in the European Union came from Russia. Thisreliance on Russia had long been identified as a strategic weakness, and some infrastructure
was built to diversify sources of imports, but Russian flows remained high: in the case ofnatural gas, Russia’s share of European gas demand actually rose from 30% on average over
2005‐10 to reach 40% in the 2015‐20 period.
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2.2.2

Box 2.1 ⊳Moving towards a new energy sector in Ukraine

The war in Ukraine has tragically upended the lives of Ukrainians and created hugeeconomic difficulties. There are of course huge uncertainties over the future course of
the conflict and its aftermath. However, in the energy sector, as in many others, Russia’s
invasion is likely to mark a decisive break with the past for Ukraine.

2

Although diversification efforts have accelerated since 2014, Ukraine has remainedlargely dependent on Russian sources of energy to meet domestic demand. Russia often
used this dependency to its advantage. Russia also sought to reduce Ukraine’s
importance to European natural gas security by building up alternative pipeline routes toEuropean consumers, after cutting off gas supplies to Ukraine in 2006 and in the winterof 2008‐09 over price and pipeline tariff disputes. In 2015, Ukraine decided to stop buying
Russian gas and was able to contract what it needed from its western neighbours instead,although these new arrangements still relied in practice on Russian transit volumes fortheir delivery. In addition, Ukraine continued to depend heavily on Russian andBelarusian oil products, which met roughly 75% of domestic demand.
Ukraine’s energy infrastructure has suffered severely since February. The safety of its
nuclear facilities is a particular area of concern: nearly half of Ukraine’s nuclear
generation capacity is located in occupied territory and Zaporizhzhia – the largest nuclear
plant in Europe – is very close to the front lines. Nuclear safety should be paramount. On‐
going military operations raise significant nuclear safety risks.
More broadly, the ability of decision makers to assure power and heat for civilians isbeing compromised by Russian attacks on critical energy infrastructure and other targets.
As of mid‐September 2022, 30% of thermal and solar generation and 90% of wind
generation capacity had been destroyed or was under Russian occupation, and all oil
refining capacity is either offline or has been destroyed. These numbers predate Russia’s
coordinated missile attacks against Ukraine in October where electricity grid facilities andother energy assets were among the targets. Falling revenues, driven in large part bydeteriorating collection rates from utilities, also present a major challenge to thegovernment.

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The winter of 2022‐23 will be a very difficult one for Ukraine, particularly if gas transit
through Ukraine is interrupted. Ukraine has been buying as much gas as it can to fill its
underground storage infrastructure, but high prices and fiscal constraints have limited
how much can be achieved. Domestic production levels are likely to reach 16‐17 billion
cubic metres (bcm), barring any attacks on production facilities. Gas demand is likely to
be significantly lower than the 27 bcm consumed in 2021 and may even fall to 18 bcm orlower: much depends on how much territory is occupied and how much infrastructure is
lost. The government is looking at potential demand‐restraint measures such as lowering
minimum temperature standards in residential buildings to 16 °C.

In the medium and longer term, Ukraine is looking towards integration with European
energy infrastructure. The day before the invasion, Ukraine’s transmission service
operator, Ukrenergo, decided to disconnect from the Integrated Power System, which
linked Ukraine’s power system to that of Russia and Belarus, and to do a test run in “islandmode”. The system ended up running in this mode for 21 days until it was synchronisedwith the European Union’s ENTSO‐E power system.
The government has put together an ambitious recovery and reconstruction plan with astrong focus on energy security and greater self‐sufficiency. Ukraine’s European Union
candidate status also underpins its ambition to build a “future‐proof” energy system. The
plan aims to increase the share of renewables, bring about the building of more nuclear
reactors, increase investment in biogas and renewable hydrogen, and reconstruct cities
with energy efficient buildings and transport systems. Balancing these long‐term goals
with urgent short‐term repairs – for example, to combined heat and power plants
severely damaged by Russian bombing – will be very challenging.
Rebuilding Ukraine’s energy sector will be expensive: preliminary government estimates
put the total cost of reconstructing Ukraine’s energy sector through to 2032 at
USD 128 billion. This figure is obviously provisional, given continuing hostilities, but thework of rebuilding will provide an opportunity to create a different, cleaner future for
Ukraine’s energy sector.

The invasion triggered moves by many of Russia’s international partners to limit or cut ties.
European Union leaders, meeting in Versailles on 10‐11 March, agreed to “phase out ourdependency on Russian gas, oil and coal imports as soon as possible”. In addition, many
international companies – especially those domiciled in Europe or North America – have left
Russia or are winding down their business operations there. Some of these intentions havebeen reinforced by firm commitments, including sanctions. Over time, this will
fundamentally reshape Russia’s position in international energy.

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For the moment, Russian oil production and exports remain close to pre‐invasion levels, butthere have been some sizeable shifts in trade flows, with exports to Europe and North
America falling, but buyers in India, China and Türkiye attracted by the discounted prices onoffer. Russian Urals crude has been trading at a discount to Brent crude oil on average ofaround USD 30/barrel since March (Figure 2.2). An important test for global product andcrude markets will come when the European Union ban on seaborne imports of Russian oil
enters into force (December 2022 for crude oil and February 2023 for oil products). Not allof the Russian exports displaced from the European Union are likely to find a new home inother markets.

USD per barrel

Figure 2.2 ⊳Prices for Brent and Urals crude oil, and diesel in Northwest
Europe since January 2021

200
Northwest
EuropeDiesel150

2

North Sea
Brent
Urals

100

50

Jan‐21

May‐21

Sep‐21

Jan‐22

May‐22

Sep‐22
IEA. CC BY 4.0.

The invasion has produced deep discounts for Russian crudes and a major rise in refining
margins as product markets run up against a shortage of global refining capacity
Source: IEA analysis based on Argus Media (2022).

The breakdown of Russia’s natural gas relationship with Europe is still more complicated. It
is not possible in the near term for Russia to switch its European pipeline exports to othermarkets, for example to Asia. However, Europe’s ability to find alternative supplies in thenear term is also constrained. LNG is the clearest candidate. Europe increased its LNG
imports by around 45 bcm in the first 8 months of 2022, compared with the same period in
2021. Its ability to do so was helped by relatively muted demand in China (which reduced its
spot purchases of LNG significantly over this period) and by new projects in the United Statescoming on stream. But increased LNG deliveries from a tight international market cover onlya small part of the reductions in Russian deliveries over the course of 2022, putting the
spotlight and the burden of adjustment firmly on European natural gas demand (Figure 2.3).

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The northern hemisphere winter of 2022‐23 will be a perilous moment for Europe,
international natural gas balances and global energy security. Europe has made progress inrefilling its gas storage sites, which were more than 90% full by early October despite regularcurtailments of Russian supply that appeared to be aimed at slowing the process. During thewinter heating season, withdrawals from storage – alongside continued imports – are vital
to meet the seasonal upswing in demand, and the market may be very tight indeed if flows
from Russia remain low or cease entirely. Early, co‐ordinated action to limit gas use and peakelectricity demand (which is typically met by gas‐fired power plants) will be essential if
Europe is to ward off rising energy security threats.

mcm/dFigure 2.3 ⊳400

Natural gas pipeline flows from Russia to the European Union andTürkiye since January 2022
Other

Russia's invasion of Ukraine

PolandUkraine300

Nord Stream
TurkStream

200

100

Jan‐2022

Apr‐2022

Jul‐2022

Oct‐2022
IEA. CC BY 4.0.

Between May and October 2022, daily pipeline flows from Russia
to the European Union dropped by around 80%
Note: mcm/d = million cubic metres per day.
Source: IEA analysis based on ENTSOG Transparency Platform (2022).

Russia’s influence on the energy sector extends beyond oil and gas to encompass coal,uranium, fertiliser and many of the minerals and metals that are vital for clean energy
transitions. Russia has been Europe’s largest source of imported coal, and a reordering oftrade flows is underway as a result of a European Union ban on imports of Russian coal thatentered into force in August 2022. Russia also produces around 20% of the world’s
Class 1 nickel (which is the grade needed for batteries) and accounts for over 40% of global
uranium enrichment capacity. In addition, it is the world’s second‐largest global producer ofcobalt and aluminium, and the fourth‐largest producer of graphite.

Economic consequences

The macroeconomic reverberations from the global energy crisis, coming on the heels of thepandemic, are having far‐reaching economic consequences. In emerging market anddeveloping economies, where the share of energy and food in household budgets is relatively
large, energy prices have had a significant impact on inflation, setting back progress towards
achieving affordable access to energy and contributing to a sharp increase in extreme
poverty in the most vulnerable countries and communities. In South Asia, the crisis is alreadyhaving destabilising effects, with Pakistan and Sri Lanka in particular suffering widespreadenergy shortages. In Africa, the number of people living without electricity increased by morethan 15 million (or 3%) between 2019 and 2021, reversing almost all the gains made over theprevious five years, and this dire trend is set to be reinforced in 2022.
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2.2.3

Most projections of economic activity have been scaled back significantly since the start of
the year, with the International Monetary Fund (IMF) cutting its expectations of global
growth for 2022 from 4.9% in October 2021 to 3.2% in its October 2022 update (IMF, 2022).
In energy importing economies, higher prices for fuels and electricity reduce economic
output by lowering the real incomes of households and raising the production costs ofbusinesses. Some energy exporting economies stand to benefit from higher energy prices,with better terms of trade boosting national income, expanding production and making
investment opportunities more attractive. However, this provides only a partial offset to thedrag on global growth, since energy exporting economies tend to save more and spend lessof their income than importing economies (World Bank, 2022). The extent to which higher
energy prices ultimately impact individual countries depends on a range of factors, including
the share of energy in their exports and imports, the energy intensity of their industrial
production, their reliance on the energy sector for taxation revenue and the effect of higher
energy prices on investor and consumer confidence.
Figure 2.4 ⊳2Change in base interest rates in selected economies,
year-to-August 2022 relative to 2021

China
Japan
Indonesia
Eurozone
India
South Africa
CanadaUnited Kingdom
United States
Brazil

8.0

‐0.6

0.0

0.6

1.2

1.8

2.4
3.0
Percentage points
IEA. CC BY 4.0.

Inflationary pressures, linked in part to higher energy prices, are prompting
a shift in monetary policies; further interest rate hikes are likely
Note: Eurozone in this figure includes 19 countries that use the Euro: Belgium, Germany, Ireland, Spain, France,
Italy, Luxembourg, Netherlands, Austria, Portugal, Finland, Greece, Slovenia, Cyprus, Malta, Slovakia, Estonia,
Latvia and Lithuania.

With inflation in many countries well above target level, the ability of authorities to cushion
the impact of higher energy prices on activity with accommodative macroeconomic policy
may be more limited than it was when the Covid shock hit in early 2020. In advanced
economies, higher prices and rising inflation have already brought forward the normalisation
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Source: Oxford Economics (2022).

of monetary policy. The base rate of central banks in Canada, United Kingdom and UnitedStates has risen by close to 200 basis points since 2021 (Figure 2.4). The European Central
Bank started to tighten later, raising its base rate for the first time in over a decade by
50 basis points in July 2022, and by a further 75 basis points in September. Japan has thus far
been an exception to this tightening trend. Monetary policy varies more among emerging
market and developing economies, reflecting their differing cyclical positions. The tighteningof monetary policy in many countries comes at a time when public and private debt are at ahigh level, particularly for this point of the cycle, meaning that any change in interest rates
has a larger contractionary and potentially destabilising effect than just a few years ago.
Change in household savings rate in selected economies,
year-to-August 2022 relative to 2021

Figure 2.5 ⊳China
Indonesia
South Africa
India
BrazilEurozone
Japan
United Kingdom
CanadaUnited States
‐7

‐6

‐5

‐4

‐3

‐2

‐1

0

1
2
Percentage points
IEA. CC BY 4.0.

Drawing down savings accumulated during the pandemic provides a safety net for somehouseholds, but the broader economic risks are clearly skewed to the downside
Note: Eurozone in this figure includes 19 countries that use the Euro: Belgium, Germany, Ireland, Spain, France,
Italy, Luxembourg, Netherlands, Austria, Portugal, Finland, Greece, Slovenia, Cyprus, Malta, Slovakia, Estonia,
Latvia and Lithuania.

Some partial buffers for the economic outlook – especially in advanced economies – havecome from household balance sheets that were buoyed by savings during the pandemic,strong labour market conditions and fiscal support measures (Figure 2.5). This has provided
some support to economic activity in the face of headwinds from the energy crisis, and as
central banks tighten monetary policy. However, the risks are clearly skewed to thedownside. The war in Ukraine shows few signs of ending, curtailment of Russian gas flows
and high prices are forcing painful curtailments of industrial output in parts of Europe,
geopolitical strains continue to divide and fragment trade and investment flows, and possible
new Covid variants cannot be excluded. In this febrile and largely uncharted environment,
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Source: Oxford Economics (2022).

additional shocks have the potential to cause significant economic harm. Price pressures
could also mount, making stagflation a genuine threat.
Overall, the ability of different economies to withstand the crisis varies widely. European
countries are directly exposed to shortfalls in energy supply but also have greater possibilities
to adjust. Higher borrowing costs, alongside a strong dollar, are hurting many emerging anddeveloping economies – especially those with pre‐existing economic weaknesses. Ultimately,
the combination of falling real incomes and rising prices is being widely felt, inviting
comparisons with the most serious energy shocks of the past (Box 2.2).
Box 2.2 ⊳2

How does this energy crisis differ from previous price shocks?

Today’s energy crisis has some features in common with the oil price shocks of the 1970s,
notably the combination of slowing growth and rising inflation linked to high commodity
prices and tight labour markets. But there are also important differences.
One is that recent oil price movements have been relatively modest by comparison withthe 1970s, when prices rose swiftly from less than USD 10/barrel (expressed in current US
dollars) before the embargo in 1973 to more than USD 40/barrel at the start of 1974.
Higher prices persisted after the embargo was lifted and then rose again to the equivalentof USD 80‐90/barrel as oil production in Iran fell after the Iranian revolution.
Another is that the global economy is much less dependent on oil than it was in the 1970s(Figure 2.6). In 1973, USD 10 000 of value added to the global economy required
5.6 barrels of oil; the figure today is closer to 2.4 barrels. In 1973, oil was widely used notjust for transportation, but also for more than a quarter of the world’s electricity
generation – a higher share than renewables. Today, oil generates less than 3% of theworld’s power (and renewables close to one‐third).
However, to focus on oil in the current energy crisis misses the larger context. The worldis experiencing a global energy crisis, with large price increases for all fossil fuels and, inturn, substantial upward pressure on electricity prices as well. Coal and natural gas prices
have reached record levels in many markets. The effects of today’s crisis are felt very
widely across a range of economic activities and countries.

Searching for silver linings in the current crisis is not easy, but there are two reasons forguarded optimism. First, macroeconomic policy makers and institutions have learned
important lessons on how to respond to commodity price shocks. Monetary policy haslargely focused on calming demand‐side price pressures while letting supply‐side shocks
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At the same time, the current crisis leaves Europe uniquely exposed. Europe is unusual inbeing a major gas‐consuming region that is heavily dependent on imports – virtually allother countries or regions with comparable levels of dependence on gas are major
producers. Although it is wealthy enough to outbid some other parts of the world foravailable LNG cargoes, this is far from enough to cushion the continent from the effects
of reduced Russian supplies.

flow through, and policy frameworks in many countries are firmly based on the objectiveof price stability. Labour bargaining arrangements generally also take more account thanin the past of the risk of cost‐push inflation, with fewer automatic wage indexation
provisions than used to be the case.
Second, the 1970s are now remembered not only for the social and economic pain causedby high energy prices but also for rapid energy innovation and diversification. Low‐
emissions options got a major boost, notably in the form of investment in nuclear power.
Energy efficiency took centre stage: the fuel economy of an average new car sold in the
United States went from 18 litres/100 km at the start of the 1970s to 15 litres/100 km by
the end of the decade.
Oil and gas use relative to GDP per capita in selected
countries/regions since 1971

Oil intensity(MJ per USD [2021, MER])

Figure 2.6 ⊳

Oil

6

1971
2021

4
Japan
India
2

World

China

Natural gas intensity(MJ per USD [2021, MER])

0

UnitedKingdom

EuropeanUnion
20 00040 000

UnitedStates60 00080 000GDP per capita (USD [2021, MER])

Natural gas

6

1971
2021

4

World

2

European Union

India

Japan

China
0

20 00040 000

UnitedKingdom

UnitedStates60 00080 000GDP per capita (USD [2021, MER])
IEA. CC BY 4.0.

Starting at a much lower level for natural gas, trends in oil and gas intensity

Note: MJ = megajoule; MER = market exchange rate.

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for most countries have moved in opposite directions since the early 1970s

There is much more scope today to deploy new technologies and diversify than there wasin the 1970s. Back then, wind and solar photovoltaics (PV) were just entering the market,
whereas now they are mature technologies whose economic advantages are only being
reinforced by sky‐high prices for fossil fuels. There has also been rapid progress in recent
years in the development of technologies that support and enable demand‐sidemanagement as well as those that support the use and storage of clean electricity fromvariable sources. As a result, there are opportunities in many countries to pursue adramatic and immediate scale up of clean energy investment and deployment in waysthat were not possible in the 1970s.

2.3

Where do we go from here?

2.3.1

Investment and trade responses

2

Energy investment and trade flows are being reshaped by the current crisis in ways that will
have a significant bearing on the future of energy. Periods of high fossil fuel prices offer
strong incentives to move away from reliance on these fuels or to use them more efficiently,
reinforcing the momentum behind energy transitions. However, today’s crisis could also spur
renewed investments in fossil fuel supply in the name of energy security. The relative weightof these responses will be determined by policy priorities, including long‐term climate
commitments as well as energy security imperatives, and different priorities may not be wellaligned. Governments, companies, investors and financial institutions all face a complex andfast‐evolving situation as they decide which energy projects to back.
Our latest estimates suggest that the bulk of additional investment in 2022 is being drawn
towards clean energy (Figure 2.7). Overall global energy investment is anticipated to rise by
8% in 2022 to reach USD 2.4 trillion, with almost three‐quarters of the increase for clean
energy, including not just renewable power, but also other low‐emissions fuels andtechnologies as well as grids, storage and energy efficiency. However, this shift towards clean
energy investment comes with some important caveats.

Second, the impact on the energy system from higher spending is partly absorbed by higher
costs and inflationary pressures. Investors fret about inflation because it can reduce theirreturn on investment in ways that are beyond their control. If rising inflation is not contained,
there is a risk it will put a brake on the willingness of companies to increase capital spending,despite strong price and policy signals. Equally, tighter monetary conditions increase the costof borrowing and thus put at risk capital‐intensive projects, including many clean energy
projects.

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First, the total is still well short of the amount that is required to meet rising demand forenergy services in a climate sustainable way. Total investment in clean energy, estimated at
USD 1.4 trillion in 2022, would need to double by 2030 to be consistent with national climate
pledges as reflected in the APS, and to triple over the same period to be aligned with the NZE
Scenario.

Global energy investment by region

Figure 2.7 ⊳Billion USD (2021, MER)

Advanced economies

China

Other EMDE

1 200

Fossil fuels

1 000

Clean energy

800
600
400

2022e

2021

2020

2015‐19

2022e

2021

2020

2015‐19

2022e

2021

2020

2015‐19200

IEA. CC BY 4.0.

Emerging market and developing economies, other than China, account for two-thirds ofthe global population, but their share of clean energy investment is both low and declining
Note: EMDE = emerging market and developing economies; MER = market exchange rate; 2015‐19 indicatesaverage annual figure; 2022e = estimated values for 2022.

Today’s high fossil fuel prices have generated an unprecedented windfall for producers. Net
income for the world’s oil and gas producers, for example, is set to double in 2022 to an
unprecedented USD 4 trillion. For the moment, however, this is only generating a modest
pick‐up in overall spending on fossil fuels, with almost half of the cash generated by the
majors being used to pay down their debt. Investment in upstream oil and gas is now rising,although the level of investment remains 17% below where it was in 2019, and is around half
the investment peak recorded in the sector in 2014 (Figure 2.8). Policy uncertainty is high,intermediated financing can be difficult to secure, and companies are generally shying awayfrom large commitments of capital that may take years to pay back. However, investments
in coal supply have been picking up, rising by 10% in 2021 with a further 10% rise expected
for 2022. The increase is being led by mining companies in China and India, the dominant
players in global coal markets.

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As well, there is the concentration of clean energy investment in advanced economies andChina. Virtually all of the global increase in spending on renewables, grids and storage since2020 has taken place in these economies, and more than 80% of electric vehicle sales areconcentrated in China and Europe. Despite some success stories, such as solar investments
in India, other emerging market and developing economies risk being left behind. This
divergence underlines the material risk of new dividing lines in collective efforts to address
climate change and to reach other sustainable development goals.

Coal supply

Upstreamoil and gas

Figure 2.8 ⊳Global investment in upstream oil, gas and coal supply

2015‐19
2020
2021

2

2022e
2015‐19
2020
2021
2022e
100

200

300

400
500
Billion USD (2021, MER)
IEA. CC BY 4.0.

Investment in coal supply is rising at around 10% per year, but oil and gas
spending remains below pre-Covid levels, despite sky-high prices
Note: 2015‐19 indicates average annual figure; 2022e = estimated values for 2022; MER = market exchange
rate.

Russia’s invasion of Ukraine is closing off one of the main arteries of international energy
commerce, both because of European sanctions on coal and oil imports and Gazprom’s
decisions to cut gas supply. This is set to generate a reduction in Russian output as well as aprofound reshuffling of trade flows around the world. The logical expectation is that, overtime, more Russian resources will flow eastwards to Asian markets, rather than westwards
to Europe.
There are some signs of this already with crude oil, although the reorientation of oil productflows will involve a wider set of actors, given that both China and India are oil productexporters. An eastward focus for Russia’s crude exports sets up a battle for market sharewith Middle East oil exporters, which have invested both politically and financially in theirrelationships with key Asian oil consumers.

The European Union remains very vulnerable to near‐term shortfalls in Russian supply,
especially for natural gas, but the key elements of a medium‐term strategy to reduce relianceon Russian imports have taken shape relatively quickly. Most of the work will need to bedone on the demand side, as there is little prospect of large volumes of additional non‐
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Reconfiguring global gas flows will be a much more challenging and lengthy process. The
distances from the Russian gas fields of western Siberia and the Yamal peninsula toalternative non‐European markets are huge, and the infrastructure needed for this is not inplace. Russian energy strategy has long sought to increase the diversity of gas export flows,
but there has been no contingency planning for a complete breakdown of ties with its
primary export market.

Russian supply becoming quickly available. More LNG from the United States will help, but it
will take time to find other major new sources of LNG: for example, large new export facilities
in Qatar are not expected to start operations until the middle of the decade. In themeantime, tight markets and fierce competition for available LNG cargoes could leave alasting reluctance among many price‐sensitive developing economies to rely on large‐scale
gas imports. As discussed in Chapter 8, the downside for gas does not automatically translate
into an upside for clean energy; coal or oil could also stand to gain.
Even before the energy crisis, underlying forces and events were reshaping the broader
environment for international trade and foreign investment (Box 2.3). For example,
shortages of personal protective equipment and vaccine supplies during the early phase of
the Covid pandemic prompted national export restrictions, highlighting the vulnerabilities ofjust‐in‐time inventory management. Frustration with the slow pace of change in updating
the multilateral trading system is leading to an increasing number of bilateral and plurilateral
trade and investment agreements. Geopolitical rivalries and new national security concerns
may in the future favour multiple trading blocs centred on trusted partners.
Box 2.3 ⊳Has the world reached peak globalisation?

Globalisation is not a precisely defined concept, but is widely interpreted as the closer
integration of economies, especially through international trade and investment. The
intensity of trade, measured by the value of imports and exports of goods and services
relative to GDP, is a standard indicator used to measure globalisation (Figure 2.9).
Following multiple rounds of trade liberalisation, and reductions in shipping andcommunication costs, global trade intensity rose progressively to reach its highest level inthe years before the financial crisis in 2008. Since then, apart from cyclical fluctuations,trade intensity has been broadly steady. It is still too early to judge how recent events willaffect this indicator. The plateau in globalisation seems to have begun before the Covid
pandemic. At the same time, the plateau does not necessarily presage a fall: in fact, global
trade rebounded strongly in 2021 to above pre‐pandemic levels as lockdowns eased andtravel restrictions were lifted.

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Trade is both a propagator and an absorber of economic shocks, but in recent years
attention has focussed more on the former than the latter. Natural disasters, Covid
lockdowns and geopolitical tensions have exposed vulnerabilities in cross‐border supply
chains, and Russia’s use of natural gas in the current conflict to exert pressure on
European consumers and decision makers provides a vivid example of the hazards thatsuch supply chains can involve. A reassessment of trade‐related economic and security
risks in many countries has prompted a host of measures aimed at strengthening supply
chain resilience, including support to build domestic production capability in key sectors,
the “re‐shoring” and diversification of suppliers and calls to update World Trade
Organization agreements. This has led some to ask whether we have reached “peak”
globalisation.

Percent of GDP

Figure 2.9 ⊳Ratio of global trade to GDP

60

2

40
China joins
WTO

Globalfinancial crisis

COVID
pandemic

20
Tokyo trade round

1971

1976

1981

Uruguay trade round

1986

1991

1996

2001

2006

2011

2016 2021e
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Cyclical fluctuations apart, trade intensity has beensteady at a high level for the past 15 years
Notes: Global trade sum of imports and exports to the nominal value of GDP. WTO = World Trade
Organization; 2021e = estimated values for 2021.
Sources: World Bank national accounts data; OECD National Accounts data files; IEA calculations.

Clean energy transitions will affect international trade in significant ways, and by the same
token changes in international trade arrangements could profoundly affect the course of
those transitions. Trade in fuels will eventually diminish as the share of oil, gas and coal in
the energy mix falls. However, this trade may become steadily more concentrated as it
diminishes. At the same time, international clean energy supply chains might increase involume and in strategic importance. Trade enables businesses to buy from the mostglobally cost‐competitive suppliers of clean energy technologies, with solar panels from
China being a particularly notable example. This has accelerated the uptake of renewableenergy, but the concentration of solar panel production in one country poses potential
challenges that governments need to address (IEA, 2022a). Over time, economies with a
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The capacity of trade to play a role as an absorber of economic shocks is weakened bytrade frictions. An illustration of this came at the start of the pandemic when the global
surge in demand for personal protective equipment (PPE) could not be met. Many PPE‐
producing economies put in place export restrictions, which assured national supplies, but
did not help to meet the spike in global demand. The restrictions did not last long andwere replaced by measures to facilitate trade, notably streamlined certification
procedures: these led to a surge in global production that helped to meet worldwide
demand and eased local capacity constraints. The restrictions nevertheless served as areminder of the potential for trade to be curtailed at times of crisis. The possibility of gas
shortages in the coming months will provide another important test of the resilience ofopen markets in Europe and beyond.

cost advantage in renewable energy may secure a larger share of international value
chains, just as aluminium smelter operators were drawn to countries with low costhydropower.
The challenge is to harness the positive role that trade has played in reducing the cost andexpanding the deployment of renewable energy technologies, such as solar PV and wind,while increasing the resilience and diversity of supply chains – including those for thecritical minerals that are vital inputs to many clean technologies. Rather than mounting
new obstacles to trade, this requires a determined effort to update the rules ofinternational trade, for example to provide clarity on when and how trade restrictions
may legitimately be deployed, to remove remaining tariff barriers on clean energy
technologies and the components needed to make them, and to make use of tradefacilitation mechanisms, such as mutual recognition, to lower the costs of working withdifferent product standards.

2.3.2

Policy responses

The policy actions taken by governments are a crucial variable in determining where we gofrom here; they represent the main reasons for the differences in outcomes across thevarious scenarios in this Outlook. In 2021, governments made a number of commitments tosustainability in the run‐up to the crucial meeting of COP26 at Glasgow, some of which took
the form of new or updated Nationally Determined Contributions (NDCs) under the Paris
Agreement – typically for 2030 – or of longer term strategies and targets. By the end of the
COP26 meeting, countries representing more than 80% of today’s CO2 emissions had pledged
to reach net zero emissions. There were other commitments too, notably the 30% reduction
in worldwide methane emissions by 2030 included in the Global Methane Pledge. Less thana year later, however, the global energy crisis and market tumult triggered by Russia’s
invasion of Ukraine have introduced a host of new pressures.
A key question, explored in the World Energy Outlook (WEO) scenarios, is whether today’s
crisis will lead to an acceleration in energy transitions, or whether it is more likely to slow
momentum. Governments in Europe and elsewhere are discussing steps to simplify
permitting for new clean energy projects and to redouble policy support. However, Europe
is also seeing an increase in coal consumption, as well as increased readiness to support newoil and gas projects and infrastructure, and it is not alone in this.

102

US Inflation Reduction Act, signed into law in August 2022, gives a major boost to a hugearray of clean energy technologies from solar, wind and electric vehicles to carbon
capture and hydrogen. The new legislation provides for almost USD 370 billion in energy
security and climate change resilience investments, which are included in the STEPS.
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The following major policies and targets are incorporated into the scenarios in this WEO,
either in the STEPS or APS, reflecting the degree of concrete policy and legislative
developments backing the targets:

The European Commission REPowerEU plan sets out how the European Union can
reduce reliance on Russian natural gas through energy savings, diversification of energy
supplies and an accelerated roll out of renewable energy. This builds on many of thetargets in the Fit for 55 plan, which are largely met – and in some cases exceeded – inthe APS, allowing the fulfilment of GHG reductions committed in the EU and its member
countries’ NDCs while also meeting important energy security goals. The acceleration of
key measures, in particular power sector renewables and fuel switching, means that EU
imports of Russian natural gas end well before 2030 in the APS, the key objective of the
REPowerEU Plan.



India passed amendments in August 2022 to its Energy Conservation Act that allow for
the establishment of a carbon market, make it easier for the government to improveenergy‐related standards for appliances and for the environmental performance ofbuildings.

Japan’s 6th Strategic Energy Plan was passed into law, laying out targets to 2030
reflected in the STEPS. Additionally, Japan announced its Green Transformation (GX)
plan, which restarts a part of its nuclear power fleet, and also lays out a longer‐term
vision for efficiency, renewables, storage, and advanced nuclear to reach Japan’s carbon
neutrality target for 2050.

2

National recovery plans, designed to help countries bounce back after the pandemic‐induced
slump, continue to exert a strong near‐term influence on energy markets and investment, as
do additional measures prompted by the current energy crisis. Since the start of thepandemic, governments have earmarked over USD 1.1 trillion for policies and incentives insupport of clean energy, far exceeding the financial commitments made to green recovery
measures after the 2008‐10 financial crisis.
However, these figures reveal worrying global imbalances. Over 90% of government
sustainable recovery spending is in advanced economies. Many emerging market anddeveloping economies are more reliant on public funding for energy investment thanadvanced economies, but at the same time are increasingly constrained by rising debt levels
and limited fiscal leeway.
Countries are also responding to recent developments by giving high priority to energy
security, and are having to find ways to balance this with broader energy and emissions
reduction policies, including in many cases the achievement of net zero emissions goals.
China provides an important example of a near‐term rebalancing in energy policy in response
to energy security concerns (Box 2.4).
Coal and the road to carbon neutrality in China

Few moments have been as important for energy policy in China as the pledge by thepresident in September 2020 that its emissions would peak before 2030 and that it would
achieve carbon neutrality before 2060. The announcement set in motion nationwide
efforts to formulate mid‐ and long‐term policy frameworks for decarbonisation, and to
identify promising clean energy technologies that would help deliver the goals. These
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Box 2.4 ⊳efforts were reflected in China’s updated NDC, issued shortly before COP26. China also
committed with the United States in the Joint Glasgow Declaration to curb international
unabated coal power projects and limit CO2 emissions in the 2020s.
Since then, there has been a stronger emphasis on the strategic importance of energy
security in China, accompanied by higher near‐term use of coal to ensure reliable
electricity supply. This shift in emphasis pre‐dated Russia’s invasion of Ukraine: it was
prompted by power outages and a spike in energy prices in many provinces during thesecond‐half of 2021, amid rapid economic recovery and coal supply issues. Restrictions
on domestic coal output were eased, and coal‐producing provinces were encouraged toramp up production.
Sourcing energy cheaply and reliably has been a constant priority for China’s energy
policy. By some distance, China is now the leading global investor in solar, onshore andoffshore wind, hydropower and nuclear generation technologies. China’s support forclean energy technologies reflects not only environmental and industrial strategy
considerations, but also a desire to reduce its increasing reliance on imported fuels.
Nonetheless, China’s energy sector remains reliant on fossil fuels for 85% of its primaryenergy, with coal the largest single contributor: China accounts for more than half of both
the world’s production and consumption of coal. Countering risks from volatileinternational energy markets means redoubling efforts to develop and deploy clean
technologies; for the moment, it also means turning more to domestic coal.
This approach is visible in a succession of recent policy statements, starting in December
2021 with the Central Economic Work Conference, which re‐emphasised the importanceof coal for China’s energy system, while also recognising the need to move away, overtime, from traditional energy sources in order to achieve carbon neutrality. The 14th Five‐
Year Plan for a Modern Energy System, released in March 2022, calls for efforts to jointly
promote energy supply security and low‐carbon transitions, while underlining the central
importance of energy security, and framing it as an aspect of national security.

High prices have also brought forward a range of interventions by governments to provide
some protection for consumers from their impact. The value of emergency government
spending or foregone revenue provided to cushion consumers and businesses from high104

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In March, during a major annual macroeconomic meeting, the National Development andReform Commission released the Plan on National Economic and Social Development,
the details of which underscore China’s balancing act. On the one hand, it relaxes coalconstraints, indicating some flexibility in respect of the energy consumption and intensity
targets set out in the macroeconomic Five‐Year Plan in 2021, and calls for the exploitationof domestic coal, oil and gas resources. On the other, it continues to emphasise emissions
reduction, nuclear power, feed‐in tariff pricing mechanisms and improved wind and solar
power generation pricing mechanisms to accelerate broader power market reform
efforts.

energy prices is nearing USD 550 billion as of September 2022 (Figure 2.10). This is set toincrease further, with packages currently under consideration, notably in the United
Kingdom and Germany. In emerging market and developing economies, short‐term
consumer support now outweighs the support provided for clean energy investments since
March 2020.

2

Figure 2.10 ⊳ Total government outlays on sustainable recovery spending andenergy affordability support

Billion USD (2020, MER)

Advanced economies

Emerging market and developing economies

1 200

1.0%

900
600

0.5%

300

Clean energy investment support (March 2020 ‐ September 2022)
Short‐term energy affordability support (September 2021 ‐ September 2022)
Short‐term energy affordability support as share of GDP (right axis)
IEA. CC BY 4.0.

Emergency government spending to help keep energy affordable is growing and alreadyhalf the total allocated to support clean energy investment since the pandemic
Notes: Clean energy investment support encompasses sustainable recovery spending (fiscal spending by
national governments in favour of clean energy measures, enacted in the framework of their Covid‐19
recovery plans) and clean energy spending from energy crisis packages, aimed at boosting energy efficiency
and/or low‐emissions production capacity. Short‐term energy affordability support are measures enacted in
response to the energy price crisis from September 2021 to early September 2022, in the form of emergency
consumer support (e.g. temporary energy price subsidies or tax alleviation, state‐backed loans).

World Energy Outlook‐2022 scenarios

This Outlook explores three main scenarios for the future, all of which are fully updated toinclude the latest energy market and cost data. Common to each is rising demand for energy
services, driven by powerful underlying economic and demographic forces. How this demandis met, however, varies substantially across the scenarios. These differences depend largelyon the policy choices made by governments, which, in turn, shape investment decisions
made by public and private actors, and the ways in which individual consumers meet theirenergy needs. The modelling framework that produces these scenarios is a dynamic one,covering all fuels and technologies, reflecting the real‐world interplay between policies, costs
and investment choices, and providing insights into how changes in one area may have (often
unintended) consequences for others.
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2.3.3

The intention of these scenarios is to provide a framework for thinking about the future ofenergy, rather than a definitive view on how that future will look. Each scenario models a
different set of responses to the current global energy crisis. By comparing them, the reader
is able to assess what drives the various outcomes, and the opportunities and pitfalls that lie
along the way. The IEA does not have a single view on how the energy system might evolve,
so none of these scenarios should be considered as a forecast.
The Net Zero Emissions by 2050 Scenario is a normative scenario, in that it works backwards
from a defined outcome. The other two, the Stated Policies and Announced Pledges
scenarios, are exploratory, in that they do not target a specific outcome but rather establish
different sets of starting conditions and consider where they may lead. These scenarios aremodelled for 26 countries and regions for demand, power and fuel transformation, and for
all the major producers on the supply side. The scenarios assume that there is no quick or
stable end to the war in Ukraine, and that international sanctions on Russia remain in place
for a prolonged period. However, they assume a gradual normalisation of the internationalsituation of other major resource‐holders subject to sanctions, notably Iran and Venezuela.



Net Zero Emissions by 2050 (NZE) Scenario: This normative scenario sets out a pathway
to the stabilisation of global average temperatures at 1.5 °C above pre‐industrial levels.
It has been fully updated for this Outlook, so it starts from a higher level of fossil fueldemand and emissions than the version published in the WEO‐2021. It also has one year
less in which to achieve global net zero CO2 emissions by 2050. As a result, reaching thisgoal requires more robust efforts than in the 2021 analysis. The NZE Scenario does thiswithout relying on emissions reductions from outside the energy sector. As in theprevious analysis, advanced economies reach net zero emissions before developing
economies do. The NZE Scenario also meets the key energy‐related UN Sustainable
Development Goals, achieving universal access to energy by 2030 and securing major
improvements in air quality. The results for the NZE Scenario are presented at the global
level, with some separate indicators for advanced and for emerging market anddeveloping economies.

Announced Pledges Scenario (APS): This scenario assumes that governments will meet,in full and on time, all of the climate‐related commitments that they have announced,
including longer term net zero emissions targets and pledges in NDCs, as well as
commitments in related areas such as energy access. It does so irrespective of whether
or not those commitments are underpinned by specific policies to secure theirimplementation. Pledges made in international fora and initiatives on the part ofbusinesses and other non‐governmental organisations are also taken into accountwherever they add to the ambition of governments.
The APS, first introduced in the WEO‐2021, builds on the analysis released during the
Glasgow COP26, which demonstrated that the combined implementation of all net zero
emissions pledges and the Global Methane Pledge would lead to a temperature rise ofaround 1.8 °C in 2100 (with a 50% probability). In this Outlook, the analysis is extended

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The scenarios are:

to consider the implications for countries that have not made ambitious long‐term
pledges, but nonetheless benefit in this scenario from the accelerated cost reductions
for a range of clean energy technologies. These additional abatement efforts mean that
the APS is now associated with a temperature rise of 1.7 °C in 2100 (with a 50%
probability).
2Stated Policies Scenario (STEPS): This scenario looks not at what governments say they
will achieve, but at what they are actually doing to reach the targets and objectives thatthey have set out. As such, it is based on a detailed sector‐by‐sector review of thepolicies and measures that are actually in place or under development in a variety ofareas. This analysis assesses relevant regulatory, market, infrastructure and financial
constraints. The STEPS reflects a pragmatic exploration of the current policy landscape,and gives a view on where the energy system might be heading in the absence of specific
new policy initiatives. As with the APS, this scenario is not designed to achieve aparticular outcome. Emissions do not reach net zero and the rise in averagetemperatures associated with the STEPS is around 2.5 °C in 2100 (with a 50%
probability).

We refer to the gap in outcomes between the STEPS and APS as the “implementation gap”,
i.e. the gap that needs to be filled to realise commitments in full. The gap between the APS
and the NZE Scenario is called the “ambition gap” because it reflects those pledges made todate collectively are not ambitious enough to match the goal of a 1.5 °C stabilisation in global
average temperatures.
This edition of the World Energy Outlook does not include the Sustainable Development
Scenario, which is another normative scenario used in previous editions to model a “wellbelow 2 °C” pathway (the upper boundary of the temperature outcomes targeted by theParis Agreement) as well as the achievement of other sustainable development goals. The
APS outcomes in this edition are close, in some respects, to those in the Sustainable
Development Scenario, in particular in terms of the temperature outcome. But they are theproduct of a different modelling approach and so the APS falls short of achieving theoutcomes targeted in the Sustainable Development Scenario.

2.4

Inputs to the scenarios

2.4.1

Economic and population assumptions

The assumed rates of economic growth are held constant across the scenarios. This allows
for a comparison of the effects of different energy and climate choices against a common
macroeconomic backdrop, but it does not capture feedback loops between climate action,
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The global economy is assumed to grow on average at close to trend – nearly 3% per year –over the period to the middle of the century (Table 2.1). There are large differences bycountry and by region, reflecting the exposure and resilience to shocks as well as variations
in growth potential of each geographic area.

climate change and economic growth. That said, we recognise that the pace, nature andchoice of mechanisms used to drive change in the energy system will have broader economic
repercussions for different countries and regions, both positive and negative.
Over the near term, the growth trajectory remains positive, but much less so than a year ago
when global aggregate demand was experiencing near record growth in response to theremoval of pandemic lockdowns and restrictions being eased in many countries. As excess
capacity unwinds and macroeconomic support is withdrawn, world GDP growth over theperiod to 2030 is projected to average 3.3%, and the composition of growth is likely to shiftback towards services, such as travel and tourism, following the removal of remaining
pandemic‐related health and mobility restrictions in most countries.
There are, however, significant downside risks for the outlook to 2030. Possible drags on
growth include negative effects from higher interest rates, a mood of insecurity holding backinvestment decisions and spending on household durables, and uncertainty as to whether
macroeconomic authorities are able to contain inflation and avoid a price‐wage spiral. If a
price‐wage spiral were to break out, it would be likely to damage growth through theremainder of the decade and risk inflation becoming stuck at an elevated level, otherwise
known as stagflation.
Table 2.1 ⊳GDP average growth assumptions by region
Compound average annual growth rate
2010‐2021

2021‐2030

2030‐2050

2021‐2050

North America

1.9%

2.0%

2.0%

2.0%

United States

2.0%

2.0%

2.0%

2.0%

0.9%

2.4%

2.4%

2.4%

Brazil

0.7%

1.8%

2.5%

2.3%

Europe

1.6%

2.0%

1.4%

1.6%

1.2%

1.9%

1.2%

1.4%

2.7%

4.1%

4.2%

4.1%

1.1%

1.6%

2.8%

2.4%

Middle East

2.0%

3.2%

3.2%

3.2%

Eurasia

2.1%

0.1%

1.4%

1.0%

Russia

1.7%

‐1.1%

0.7%

0.1%

Asia Pacific

4.9%

4.7%

3.1%

3.6%

China

6.8%

4.7%

2.8%

3.4%

India

5.5%

7.2%

4.4%

5.2%

Japan

0.5%

0.9%

0.6%

0.7%

Southeast Asia

4.1%

5.0%

3.3%

3.8%

2.9%

3.3%

2.6%

2.8%

Central and South America

European Union
AfricaSouth Africa

World

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Note: Calculated based on GDP expressed in year‐2021 US dollars in purchasing power parity terms.
Sources: IEA analysis based on Oxford Economics (2022) and IMF (2022).

Over the longer term, GDP per capita in emerging market and developing economies
continues gradually to move towards the levels in advanced economies, with emerging
market and developing economies accounting for a larger share of global GDP in 2050 (66%)
than they do today (53%). Russia may be a notable exception, with GDP dropping as many
countries seek to end their dependence on Russian exports of energy and resources; Russian
GDP is projected to only recover its 2021 level by 2040.

2

The main energy‐related uncertainties for the economic outlook relate to the impact ofhigher energy prices and input costs on energy investment (especially the mix between
investment in clean energy and in traditional fuels), the degree to which higher prices set
back progress towards achieving affordable access to energy, and the extent of productivity
gains associated with the deployment of new energy technologies. There is an importantquestion in this context about the deployment of how the windfall gains currently accruing
to major oil and gas companies in the private sector and large government‐owned entities.
They could encourage the stepping up of fossil fuel investment, or they could be used todiversify the economic base of hydrocarbon‐rich economies. Whichever path is followed will
have a large and continuing impact on the composition of fuel supply and on the pace ofprogress towards achieving climate commitments.
The global population is assumed to rise from 7.8 billion people in 2021 to 8.5 billion in 2030
and 9.7 billion in 2050, an increase of almost one‐quarter in 29 years.1 This brings about asizeable increase in the number of those requiring energy services, but it also represents aslowing of annual population growth, which halves from close to 1% in 2020 to 0.5% in 2050.
While the pace of population growth slows in all regions, it starts from a high base in sub‐Saharan Africa, where high fertility rates and lengthening life expectancy drive almost adoubling of the population by 2050. In some countries, notably Italy, Germany, Japan and
China, fertility rates below replacement level translate into falling and ageing populations
over the period to 2050.
The Covid‐19 pandemic is likely to have had only a small impact on these demographic
projections. The number of lives lost directly attributed to the illness is nearly 6.5 million(WHO, 2022), however the number of excess deaths could be much higher, especially incountries where reporting is limited. Strict public health rules, and prompt development anddeployment of vaccines in many countries no doubt helped to avoid a situation that could
have been a lot worse.

1

The 2022 Revision of UN DESA's World Population Prospects could not be incorporated in this modelling
cycle as the modelling was already advanced by its publication time.

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There are two other factors related to demography that have important implications forpatterns of energy use. The first is the way in which improvements in health, diet and living
conditions have gradually lifted life expectancy of the global population by a decade over the
past 40 years. Coupled with declining fertility rates, this translates into a rising share of older

people in the global population, a group that uses more energy than the average at home,
but less for transport.
The second is urban development, where the share of the global population living in towns
and cities is expected to rise to almost 70% by 2050. In the past, urbanisation has been
associated with a rising overall population and economic development. In China, however,the projections anticipate that an additional 215 million people will be living in towns andcities by 2050, a positive driver for energy demand, while over the same period the total
population is projected to decline by around 40 million, a negative driver for energy demand.

2.4.2

Energy, mineral and carbon prices

Our scenarios model an energy system in equilibrium, in which energy prices follow a
relatively smooth trajectory to balance supply and demand, and where energy markets,
investment, technologies and policies all evolve in a mutually consistent direction (Table 2.2).
The price trajectories do not attempt to track the fluctuations and price cycles thatcharacterise commodity markets in practice. The potential for volatility is ever present,
especially in systems that are undergoing a necessary and profound transformation (seeChapter 4).
Table 2.2 ⊳Fossil fuel prices by scenario
Net Zero
Emissionsby 2050

Announced
PledgesStatedPolicies

Real terms (USD 2021)

2010

2021

2030

2050

2030

2050

2030

2050

IEA crude oil (USD/barrel)

96

69

35

24

64

60

82

95

United States

5.3

3.9

1.9

1.8

3.7

2.6

4.0

4.7

European Union

9.0

9.5

4.6

3.8

7.9

6.3

8.5

9.2

China

8.0

10.1

6.1

5.1

8.8

7.4

9.8

10.2

Japan

13.3

10.2

6.0

5.1

9.1

7.4

10.9

10.6

United States

63

44

22

17

42

24

46

44

European Union

113

120

52

42

62

53

60

64

Japan

132

153

59

46

74

59

91

72

Coastal China

142

164

58

48

73

62

89

74

Natural gas (USD/MBtu)

Notes: MBtu = million British thermal units. The IEA crude oil price is a weighted average import price among
IEA member countries. Natural gas prices are weighted averages expressed on a gross calorific‐value basis.
The US natural gas price reflects the wholesale price prevailing on the domestic market. The European Union
and China natural gas prices reflect a balance of pipeline and LNG imports, while the Japan gas price solely
reflects LNG imports. The LNG prices used are those at the customs border, prior to regasification. Steam coalprices are weighted averages adjusted to 6 000 kilocalories per kilogramme. The US steam coal price reflects
mine mouth prices plus transport and handling costs. Coastal China steam coal price reflects a balance ofimports and domestic sales, while the European Union and Japanese steam coal prices are solely for imports.

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Steam coal (USD/tonne)Oil
Today’s market tightness is assumed to ease in the coming years, although prices could
remain high and volatile for a period as the market absorbs a reduction in Russian
production, once European Union import restrictions enter into force. The oil market returns
to a more stable balance between supply and demand by the late 2020s, although the levels
vary widely between scenarios (Figure 2.11).

2

In the STEPS, long‐term demand is broadly similar to last year’s WEO, and this continues to
put a relatively high floor under price levels, with the post‐2030 price on a rising trend above
USD 80/barrel. Near‐term higher prices bring forward additional supply, including tight oil;these developments continue for a number of years, and this exerts some downward pricepressure. However, long‐term prices are higher than in the WEO‐2021 as a result of uncertain
prospects for investment (notably, but not only, in Russia), combined with a strategic shift
among some large oil and gas companies away from hydrocarbons.

USD per barrel (2021)

Figure 2.11 ⊳ Average IEA crude import price by scenario
150
120
STEPS

90
60

APS

30

NZE

2000

2010

2020

2030

2040

2050
IEA. CC BY 4.0.

Equilibrium oil prices vary substantially by scenario, reflecting the waythat policies, costs and resources affect the supply-demand balance

In the APS, a much stronger policy focus on curbing oil demand brings down the price atwhich the market finds equilibrium, with the international oil price stabilising at around
USD 60/barrel. Maintaining prices around this level will depend to a large degree on the
stance taken by members of the Organisation of Petroleum Exporting Countries (OPEC), andwhether they are ready to moderate long‐term production in the name of price stability,
even in a market that is shrinking in size. As we have set out elsewhere (IEA, 2020), if major
resource‐holders were to opt instead to maximise their own market share, then this would
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Note: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario.

result in much lower prices and thus reduce in overall terms the revenues upon which manyof these economies are highly reliant.
In the NZE Scenario, any immediate market tightness is quickly relieved by strong efforts to
reduce demand, although some continued investment is also required to replace Russian
supplies. Over time, prices are increasingly set by the operating costs of the marginal projectrequired to meet falling demand. Costs here include the usual costs of extraction, theremedial work necessary to reduce the emissions intensity of existing fields, and the CO2
price applied to any residual emissions. It is assumed that some countries at the margin
reduce taxes on oil and gas extraction to allow domestic production to continue. Additional
near‐term oil use – and emissions – compared with last year’s NZE Scenario need to becompensated for by an even faster reduction in demand in the 2030s and beyond in order tokeep within a very limited emissions budget.

Natural gas
Unlike oil, there is no single global price for natural gas, but instead a set of regional pricesthat are increasingly interlinked by the ability of LNG tankers to seek out the mostadvantageous commercial destination. During the current crisis, high gas prices in Europe
mean that it has attracted most of the available LNG cargoes to compensate for cuts in
Russian supply.
In the STEPS, EU gas prices are much higher through the mid‐2020s than anticipated in theWEO‐2021. Russian exports to the European Union are assumed to fall further in line withthe expiry of those contracts that have yet to be cut unilaterally, while additions to globalliquefaction capacity are relatively modest over the coming years (with only around 60 bcm
in export capacity coming online between 2022‐24, compared with 105 bcm between
2019‐21). Near‐term prices in Europe are higher than in Japan or other Asian markets during
this time, a reversal of the usual state of affairs in natural gas markets. By the middle of thedecade, however, the EU gas price returns to around USD 8.50/MBtu as new supply comes
online and market conditions ease. The Henry Hub price, the marker for natural gas in the
United States, is slightly higher than in the WEO‐2021, a function of higher demand for US
LNG exports.

2
The STEPS and APS price trajectories both assume readiness by Russia to continue some level of natural gas
deliveries to the European Union, but the APS incorporates a stronger drive within Europe to reduce theseimports, in line with the overall aim of this scenario to reflect announced policy objectives even where they
are not backed by specific measures to achieve them. However, there is also the distinct possibility that
Russian supply curtailments will bring about a much faster decline in European use of Russian gas than
European efforts to diversify or to reduce demand. Russia may even simply stop supplying any gas to Europe.

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The APS has slightly lower equilibrium gas prices in Europe and Asia than in the STEPS by
2030. This is because there is a more rapid decrease in gas demand in the APS than in the
STEPS, due to increased efficiency, electrification and accelerated deployment of
renewables. But the European Union still needs to attract additional non‐Russian gas in this
scenario, keeping near‐term gas prices elevated.2 This has knock‐on effects on prices in otherimporting regions, although the effects in Asia are muted by the link to oil prices in many
long‐term contracts. The additional costs of diversification efforts incurred up to 2030 would
be offset thereafter by lower prices and lower overall gas demand, both in the European
Union and Japan.
In the NZE Scenario, the decline in natural gas consumption is even more precipitous,
although, as with oil, some additional investment is needed to compensate for Russian
supplies that have no obvious route to market after the breakdown of the energy
relationship with Europe. By the end of this decade, natural gas prices in producing regions
fall to the short‐run marginal cost of existing projects.

2

Coal
International coal prices reached record levels in the first‐half of 2022. Coal production failed
to keep pace with rebounding coal demand in 2021, especially during the first‐half of theyear, and this cut into stock levels and pushed up prices. Major coal producers, led by China
and India, introduced policies to ramp up production and reduce domestic coal shortages,
facilitated by the large presence of state‐owned companies in production. However, themain coal exporting countries were supply constrained, partly as a result of various weather‐related outages, such as flooding in Indonesian mines and infrastructure issues.
In our scenarios, the coal markets balance at lower prices, but these prices vary considerably
depending on overall levels of demand. Relatively robust coal consumption trends in the
STEPS offer some support to price levels, particularly given constrained access to finance for
new coal supply projects and infrastructure outside China and India. However, prices decline
towards the operating costs of existing mines in the APS, and they do the same in the NZE
Scenario, but faster.

Critical minerals

Prices for many materials have started to moderate since April as additional supplies havebecome available and as weakening economic growth has begun to affect demand. This has
not been a smooth process: for example, in August 2022 there were supply disruptions in
China, which accounts for around 60% of global lithium chemical supply, when extreme heatand the record low water level on the Yangtze River triggered power shortages in Sichuan
and reduced production capacity. Even after taking account of the way prices have comedown in recent months, price increases since the start of 2021 have outpaced or been
comparable to the largest annual increases seen in the 2010s.
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In 2021, many important minerals and metals that are essential for clean energy technologies
registered broad‐based price increases due to a combination of rising demand, disrupted
supply chains and concerns around tightening supply (Figure 2.12). Prices for lithium andpolysilicon more than tripled in 2021, and those for copper, nickel and aluminium all rose byaround 25‐40%. These elevated prices continued into the first few months of 2022. The
increase in the cost of lithium has been astonishing, with prices going up anothertwo‐and‐a‐half‐times between January and April. Prices for nickel and aluminium alsosoared, driven in part by Russia’s invasion of Ukraine and a short squeeze on nickel.

Index (100 = Jan 2021)

Figure 2.12 ⊳ Price developments for selected critical minerals and metals
1 000

Lithium

500

800

400

600

300

400

200

200

100

Jan
2021

Polysilicon

Aug
Jan
2022
2021
Price development since 2021

NickelAluminium

Aug Jan
Aug JanAug2022 2021
2022 2021
2022
Largest annual increase in the 2010s
IEA. CC BY 4.0.

Prices for important energy transition minerals and metals have been on a rapid upwardmarch since the start of 2021, although price rises moderated in second-half 2022
Note: Assessment based on Lithium Carbonate Global Average, London Metal Exchange (LME) Cobalt Cash,LME Nickel Cash and LME Aluminium 99.7% Cash prices.
Sources: S&P Global (2022); BNEF (2022) for polysilicon prices.

Several major projects are expected to start bringing new supplies into the market in thelatter part of 2022 and in 2023, and this may help to moderate prices, especially ifmacroeconomic headwinds intensify. Investment levels are rising: thanks to the recent risein prices, the profits and cash flows of mining companies have increased significantly andcapital spending on non‐ferrous metal production rose by 20% in 2021. However, current
investment trends still fall short of meeting the projected increases in demand in the IEA
climate‐driven scenarios, including the APS and the NZE Scenario. We do not yet model the
supply‐demand balances or price trajectories for critical minerals in the same way as forfuels, and take the 2021 average prices as a baseline assumption for the calculation of future
revenues. Without a further scaling up of investment in new supplies, together with efforts
to improve material efficiency and find substitutes for existing metals and minerals, there isa risk in the future of higher prices and high price volatility, and this could hamper clean
energy transitions.

Carbon prices

The main development since the WEO‐2021 has been the increase in price levels in multiple
market‐based carbon pricing systems. Over the course of 2021, the price of carbon tripled in
the European Union Emissions Trading System (ETS) and doubled in Korea, New Zealand and114

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The adoption of carbon pricing instruments continues worldwide, with about 23% of global
emissions now covered by a carbon price of some description.

state‐level schemes in the United States. Following Russia’s invasion of Ukraine, prices insome jurisdictions have fallen below their all‐time highs, but they are still at historically highlevels. Higher carbon prices led to a sharp increase in global carbon pricing revenue to
USD 84 billion in 2021, which is nearly 60% higher than in 2020.
Other developments include the increasing use of carbon pricing, with the launch of schemesin Austria, Canada and Uruguay and at the state level in the United States. Indonesia’s carbon
pricing scheme is scheduled to start this year. India has announced plans for the phased
launch of a carbon market. South Africa has announced plans for steady increases in its
carbon tax to 2030 and beyond.

2

At the international level, governments reached an agreement at COP26 on the rules
governing international carbon markets (Article 6 of the Paris Agreement). Around 85% of
new or updated NDCs indicate that the countries submitting them will or may use thesemarkets to help deliver their commitments. Voluntary carbon markets, mostly used bycompanies as a means to fulfil their voluntary commitments, have also been growing fast in
the last two years. Global issuance of carbon credits in 2021 was around 480 million tonnesof carbon‐dioxide equivalent (Mt CO2‐eq), with a market valuation exceeding USD 1 billion
for the first time.
In our scenarios, the STEPS incorporates existing and announced carbon pricing initiatives,
whereas the APS and the NZE Scenario include additional measures of varying stringency andscope. In the NZE Scenario, for example, carbon prices are quickly established in all regions,rising by 2050 to an average of USD 250/tonne CO2 in advanced economies, to
USD 200/tonne CO2 in other major economies (e.g. China, Brazil, Russia and South Africa),
and to lower levels elsewhere. As with other policy measures, CO2 prices need to be
introduced carefully, with a view to the likely consequences and distributional impacts. The
level of CO2 prices included in the scenarios should be interpreted with caution. The scenarios
include a number of other energy policies and accompanying measures designed to reduce
emissions, and this means that the CO2 prices shown are not the marginal costs of abatement(as is often the case in other modelling approaches).

Technology costs

Technology costs are crucial in determining how demand for energy services is met in a given
sector or country. The Global Energy and Climate Model (GEC‐M) that is now used for our
projections contains a very rich representation of energy technologies, including not only
those that are widely available, but also those that are judged to be approachingcommercialisation. We do not assume any major new technology breakthroughs in the WEO
scenarios (on the grounds that these are inherently difficult to anticipate), but a continuous
process of technology improvement and learning is built into the modelling. This applies toappliances and vehicles purchased by end‐users; infrastructure for transporting energy
products, including smart grids; and storage and other technologies for energy extraction,
generation and transformation.
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2.4.3

The starting point is a rising trend in costs for most fuels and technologies. Cost pressures
are being felt across much of the energy sector, due to persistent supply chain pressures,tight markets for specialised labour and services, bottlenecks in critical mineral supply, andhigher prices for essential construction materials like steel and cement. Ebbs and flows inunderlying costs for fossil fuel production are not unusual and have been observed manytimes. Recent rises in costs for clean energy technologies, however, mark a distinctive breakwith the steady, and sometimes dramatic, reductions seen in recent years.
Oil and gas resources generally become more expensive to extract over time in our scenarios,
as continued upstream innovation and technology improvements are more than offset by
the effects of depletion, meaning that resources become more difficult and geologicallychallenging to develop. As a result, these fuels face increasingly stiff competition in a growing
number of areas from clean energy technologies.
Figure 2.13 ⊳ Changes in levelised costs for a benchmark project inEurope and North America, 2020, 2022 and 2030
Utility‐scale solar PV

Onshore wind150%

Operation andmaintenance
Financing costs

100%

Capital cost

50%

2020

2022e

APS
2030

2020

2022e

APS
2030
IEA. CC BY 4.0.

Tight supply chains and higher financing costs are putting upward pressure on renewables
costs, but they remain the least-cost option for new generation in most countries

With regard to cost trends for these clean technologies, the key question is whether today’s
elevated costs are simply a bump in a downhill journey or whether they represent a more
profound change in the direction of travel. For many technologies, this puts the spotlightfirmly on raw material inputs, which now account for a larger proportion of overall costs thanthey did before. Increases in the prices of polysilicon (tripled in 2021), steel (up by 70% overthe same period) and aluminium (up 40%) now feed much more directly into the costs ofsolar panels and wind turbines, which are up by between 10% and 20% since 2020. Financing
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Notes: 2022e = estimated values for 2022. Assumptions based on the APS and the IEA World Energy
Investment 2022 report (IEA, 2022b).

costs also play a major role in levelised costs, and are likely to rise as monetary policy tightens
in many countries (Figure 2.13). Nonetheless, clean technologies in the power sector remain
the most cost‐efficient option for new power generation in many countries, even before
taking account of the exceptionally high prices seen in 2022 for coal and gas.
We do not assume that current pressures will result in a lasting uptick to the cost of clean
energy technologies. Pressures from higher commodity prices are real, but they do not ruleout further cost reductions for clean energy technologies. There is scope to reduce other costelements via technology innovation, efficiency improvements and economies of scale.
Material costs could also be reduced as technologies adapt to reduce reliance on criticalmaterials. As a result, clean technology costs continue to come down in our scenarios, albeit
with variations across the different scenarios, depending on the level of policy support andthe extent of deployment.

2

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However, the current pressures on costs provide a reminder that cost trajectories may not
be smooth and linear, and that governments need to pay close attention to potential
vulnerabilities and imbalances in clean energy supply chains (see Chapter 4). For example,
the scale of China’s investment in solar PV manufacturing has been instrumental in bringing
down costs worldwide, with multiple benefits for energy transitions. At the same time, IEA
analysis has highlighted that China’s share in all the key manufacturing stages of solar panels
already exceeds 80% today and that, for key elements including polysilicon and wafers, thisis set to rise to more than 95% in the coming years, based on manufacturing capacity underconstruction (IEA, 2022c). There is a clear need for countries and regions to help diversify
clean energy supply chains and make them more resilient.

PART B
ROADMAP TO NET ZEROEMISSIONSPart B of this WEO focusses on the pathway for the global
energy sector to reach net zero emissions by 2050, while
addressing energy security and affordability concerns.
In 2021, the IEA published Net Zero by 2050: A Roadmap for the
Global Energy Sector. In the short time since then, much haschanged. To take into account the new landscape, Chapter 3

presents an updated Net Zero Emissions by 2050 (NZE)
Scenario.
It emphasises the key results of the NZE Scenario for energy
supply, demand and emissions, and focusses on the actions
needed by sector to achieve deep reductions in energy‐
related emissions. It examines the measures needed to curb
growth in demand including energy and materials efficiency,
electrification and behavioural change.
The challenges of scaling up clean technology supply chainsto meet the surge in deployment projected in the NZE
Scenario are assessed. This includes a review of theannounced and under development manufacturing capacity
for solar PV, electrolysers for hydrogen production,batteries, as well as for carbon, capture, utilisation andstorage, and direct air capture and storage projects.

IEA. CC BY 4.0.

Chapter 3 includes a special focus on the NZE Scenario
relative to the scenarios assessed by the Intergovernmental
Panel on Climate Change. Plus, it looks at the future of flying
in the context of the NZE Scenario.

Chapter 3
An updated roadmap to Net Zero Emissions by 2050
Energy transition for 1.5 °C
S U M M A R Y
 In 2021, the IEA published its report Net Zero by 2050: A Roadmap for the Global
Energy Sector. However, in the short time since then much has changed. The global
economy has rebounded from the Covid‐19 pandemic, and the first global energy
crisis has seen world energy prices touching record levels in many markets, bringing
energy security concerns to the fore.

 In 2021, emissions rose by a record 1.9 Gt to reach 36.6 Gt, driven by extraordinarily
rapid post‐pandemic economic growth, slow progress in improving energy intensity,and a surge in coal demand even as renewables capacity additions scaled recordheights. Recent investment in fossil fuel infrastructure not included in our 2021 NZEScenario would result in 25 Gt of emissions if run to the end of its lifetime (around 5%of the remaining carbon budget for 1.5 °C).

 Despite these mostly discouraging developments, the pathway detailed in the Net
Zero Emissions by 2050 (NZE) Scenario remains narrow but still achievable. Thisupdate to the NZE Scenario offers a comprehensive account of how policymakers andothers could respond coherently to the challenges of climate change, energy
affordability and energy security.

 Between 2021 and 2030, low emissions sources of supply grow by around 125 EJ in
the NZE Scenario. This is equivalent to the growth of world energy supply from all
sources over the last fifteen years. Among low emissions sources, modern bioenergy
and solar increase the most, rising by around 35 EJ and 28 EJ respectively to 2030.
Over the period to 2050, however, the largest growth in low‐emissions energy supply
comes from solar and wind. By 2050, unabated fossil fuels for energy uses account forjust 5% of total energy supply: adding fossil fuels used with CCUS and for non‐energy
uses raises this to slightly less than 20%.

 In the NZE Scenario, electricity becomes the new linchpin of the global energy system,
providing more than half of total final consumption and two‐thirds of useful energy
by 2050. Total electricity generation grows by 3.3% per year to 2050, which is fasterthan the global rate of economic growth across the period. Annual capacity additionsof all renewables quadruple from 290 GW in 2021 to around 1 200 GW in 2030. With
renewables reaching over 60% of total generation in 2030, no new unabated coal‐
fired plants are needed. Annual nuclear capacity additions to 2050 are nearly four‐times their recent historical average.
measures to save energy, bringing benefits in terms of emissions reductions,affordability and energy security. In the NZE Scenario, energy intensity improvements
Chapter 3 | An updated roadmap to Net Zero Emissions by 2050

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 Increased supplies of clean energy are complemented in the NZE Scenario byto 2030 are nearly three times faster than over the past decade. In 2030, energy
savings from energy efficiency, material efficiency, and behavioural change amountto around 110 EJ, equivalent to the total final consumption of China today.

 End‐use sectors all achieve emissions reductions of over 90% by 2050. Hydrogen andhydrogen‐based fuels are deployed in heavy industry and long‐distance transport, andtheir share in total final consumption reaches around 10% in 2050. Bioenergy use is
kept to around 100 EJ in the interests of sustainability and reaches around 15% of
total final consumption in 2050. CO2 capture totals 1.2 Gt in 2030, rising to 6.2 Gt in
2050, and more than 60% of this occurs in industry and other fuel transformation
sectors.

 The NZE Scenario requires a large increase in investment in clean energy. Energy
investment accounted for just over 2% of global GDP annually between 2017 and
2021, and this rises to nearly 4% by 2030 in the NZE Scenario. Electricity generationfrom renewables sees one of the largest increases, rising from USD 390 billion inrecent years to USD 1 300 billion by 2030. This level of spending in 2030 is equal tothe highest level ever spent on fossil fuel supply (USD 1.3 trillion spent on fossil fuels
in 2014).

 There are some positive indications that clean energy technology is now rapidly
scaling up. Announced EV battery production capacity for 2030 is only 15% lower thanthe level of battery demand underpinning the NZE Scenario in the same year, whileannounced expansions of solar PV production capacity would be essentially sufficientto achieve the level of deployment envisaged in the NZE Scenario, if they aresuccessfully delivered on time. Assuming full implementation of all announced
manufacturing capacity expansions including speculative projects, the cumulative
output of electrolyser manufacturing capacity could reach 380 GW by 2030, which isstill little more than half of 2030 needs in the NZE Scenario.

 There are however many areas where progress is well short of what is envisaged in
the NZE Scenario. The path to success requires policy makers to do much more toprovide signals on the demand side, to develop the clean technology supply chain asa whole, to ensure that supply chains are diverse and resilient, and to promote thecoordinated growth of different parts of particular supply chains.
90 million in 2030 in the NZE Scenario. New jobs in clean energy industries reach 40
million by 2030, outweighing job losses in the fossil fuel‐related industries. Fossil fuelsupply jobs decrease by 7 million by 2030 in the NZE Scenario, with coal supply seeing
the sharpest decline as mechanisation and decarbonisation efforts lead to further
downsizing of the industry. Shortages of skilled labour in clean energy construction
projects are already starting to be seen, underlining the importance of strategic andproactive labour policies to build up the workforce needed for the rapid expansion ofclean energy technologies.
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 Total energy sector employment increases from just over 65 million today to

2021
37 Gt
CO2 emissions

No new sales offossil fuel boilers

Nearly 50% of electricity
from low-emissions sources

2025

8% of emissions from cement
production captured and stored

60% of global car sales are electric
2030
23 Gt

720 GW electrolyser capacity

Advanced economies: net zero
emissions in the electricity sector

No new ICE car sales
2035

3 Gt CO2 captured

Electricity accounts for 40%
of industrial energy consumption

50% of existing buildings retrofitted
to zero carbon-ready levels
2040
5 Gt

Key milestoneson the pathway
to net zero emissions
by 2050
Electricity
Industry
Buildings

Transport
Other

Negative emissions

Nearly 90% of electricity from renewables

2045

3 670 GW electrolyser

2050

Coal

Scaling up
production capacity
Still needed
to reach 2030 NZE

Oil

16%

400

45%

17%

0%

Gas

Fossil fuel supply
STEPS 2030

38%

100%

EJ
300

50% of heating demand
met by heat pumps

Net zero

A demand-led transition500

No new ICE heavy truck sales

NZE 2030

Key demand-side measures to drive transition
Clean and efficient industry
Solar and wind
Behaviour
Efficient buildings and heat pumps
Other
Electric vehicles

Lithium

Solar PV

Batteries

CopperElectrolysers

2021 production capacity
All announced expansion to 2030

Introduction
In 2021, the IEA published its Net Zero by 2050: A Roadmap for the Global Energy Sector (IEA,
2021), which sets out a narrow but achievable pathway for the global energy sector to reachnet zero emissions by 2050. However, much has changed in the short time since that report
was published.
The global economy rebounded at record speed in 2021 from the COVID‐19 pandemic, withGDP growth reaching 5.9%. As energy intensity improvements stalled, global energy demand
increased by 5.4%. Surging energy demand was in part met by increased use of coal, resulting
in a 1.9 gigatonnes (Gt) jump in emissions in 2021, the largest annual increase in global CO2
emissions from the energy sector ever recorded. This brought total CO2 emissions from theenergy sector to 36.6 Gt in 2021. Recent investment in fossil fuel infrastructure not includedin the 2021 Net Zero Emissions by 2050 Scenario would result in 25 Gt of emissions if run tothe end of its lifetime (around 5% of the remaining carbon budget for 1.5 °C). At the sametime, 2021 also saw renewables‐based electricity generation reach an all‐time high, a record
more than 500 terawatt‐hours (TWh) above the level in 2020.
As a consequence of the surge in demand, bottlenecks in supply, and above all Russia’s
invasion of Ukraine, the world is currently experiencing the worst energy shock since the1970s, with prices of fuels and commodities hitting record levels in many markets. In the faceof this shock, some governments are announcing new targets for the deployment of clean
energy technologies, or temporarily increasing the use of coal, and in some cases doing bothat the same time. How energy security and climate objectives can be aligned is therefore a
critical question for policy makers (see Chapter 4).
The Intergovernmental Panel on Climate Change (IPCC) published the first volume of its Sixth
Assessment report in August 2021, after the IEA published its Net Zero by 2050 report. The
IPCC report confirms that rapid and deep reductions in CO2 emissions are necessary to limit
warming to 1.5 °C (IPCC, 2021). In scenarios that achieve this objective with no or limited
temperature overshoot, net emissions of greenhouse gases (GHGs) need to be reduced by
43% by 2030 compared with 2019 levels, and CO2 emissions need to reach net zero by around2050 (IPCC, 2022a). The Glasgow Climate Pact which was adopted at COP26 reinforced theParis Agreement objective of limiting warming to 1.5 °C by achieving net zero CO2 emissions
by around mid‐century as well as deep reductions in other GHGs.

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In this context, this chapter presents a 2022 update to the IEA Net Zero Emissions by 2050
(NZE) Scenario. Its central purpose is still to reach net zero emissions from the energy sector
by 2050, but this updated version takes into account the latest information about energy
markets and technologies, and reflects concerns about energy security. The NZE Scenario is
supported by new modelling using the climate model MAGICC which is widely used in the
IPCC analyses and makes possible a richer assessment of the implications of the NZE Scenario
for the global temperature.

The design approach for the updated NZE Scenario sticks closely to the approach followed in
the IEA 2021 report:


The NZE Scenario is based on the deployment of a wide portfolio of clean energy
technologies, with decisions about deployment driven by costs, technology maturity,
market conditions and policy preferences. The pathway reflects the particular
circumstances of various countries in terms of resource and infrastructure endowments,
development pathways and policy preferences.



The NZE Scenario sees all countries contribute to the pathway to net zero emissions by
2050, with advanced economies taking the lead and reaching net zero emissions wellbefore emerging market and developing economies. Rapid transition is supported by
global collaboration to facilitate ambitious policies, drive down the costs of clean energy
technologies, create bigger and more international markets for those technologies, andsupport emerging market and developing economies to achieve emissions reductions
and the energy‐related United Nations Sustainable Development Goals (SDGs).



The NZE Scenario aims to safeguardenergy security through rapid deployment of clean
energy technologies, energy efficiency and demand reduction while minimising energy
market volatility and stranded assets to the extent possible. It targets a smoothtransition through strong and co‐ordinated policies and incentives that enable all actors– governments, investors, companies and workers – to anticipate the rapid change
required.

3

The NZE Scenario is a pathway to reach net zero emissions by 2050, not the pathway. It setsout a comprehensive and detailed view of how the energy sector could respond coherently
to the challenges of climate change while taking account of concerns about energy security
and affordability.

Net Zero Emissions Scenario
3.1

Emissions and temperature trends

1
Here and henceforth unless otherwise specified, CO2 emissions from the energy sector include industrial
processes.

Chapter 3 | An updated roadmap to Net Zero Emissions by 2050

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Between 2021 and 2030, CO2 emissions from the energy sector decrease by more than one‐
third in the NZE Scenario, falling from 36.6 Gt today to less than 23 Gt in 2030.1 The electricity
sector leads the way: emissions from electricity generation halve between 2021 and 2030,
accounting for more than half of the overall emissions reductions from the energy sector.
Growing electrification and the widespread deployment of efficiency and energy savings
measures enable the buildings sector to almost halve its emissions by 2030. Rapid reductions
are also seen in the transport sector, with emissions falling by one‐quarter by 2030, thanks
to electrification, efficiency improvements and behavioural change. The industry sector alsosees a reduction of nearly a quarter by 2030 from 2021 levels, driven in particular by effective
policies on materials efficiency, energy efficiency and fuel switching.

Between 2031 and 2040, the speed of emissions reductions in the industry and transport
sectors accelerates to almost 10% per year, as electrification, low‐emissions fuels, andcarbon capture, utilisation and storage (CCUS) technologies start to make bigger inroads into
the existing stock of assets. The electricity sector reaches zero net emissions in advanced
economies by 2035, and in emerging market and developing economies by 2040. The rapid
drop in emissions in electricity helps to bring about continued reductions in emissions in thetransport and buildings sectors as they electrify. By 2040, most of the remaining 5.8 Gt ofenergy sector emissions are from the transport sector (40% of the total, mainly from ships,
planes and heavy trucks), and the industry sector (55%).
By 2050, all end‐use sectors achieve emissions reductions of more than 90% compared tocurrent levels, although residual CO2 emissions are about 0.5 Gt in transport and 0.4 Gt in
industry. These, and net residual emissions from other sectors, are counterbalanced bycarbon dioxide removal (CDR) from the atmosphere through bioenergy with carbon captureand storage (BECCS) in electricity generation and biofuels production, and through direct air
capture and storage (DACS). By 2050, CDR reaches 1.5 Gt per year (Figure 3.1).
Energy-related CO2 emissions by sector and gross andnet emissions in the NZE Scenario, 2010-2050

16

Emissions by sector
Gt CO₂Gt CO₂

Figure 3.1 ⊳Electricity

1240

Gross and net emissions

Net emissions
30

Industry
20

8Transport
4 Buildings0Grossemissions

10

Other

0
BECCS and DACS

‐4
2010

2020

2030

2040

2050

‐10
2010

2020

2030

2040

2050

IEA. CC BY 4.0.

The power sector leads emissions reductions to 2030, but all sectors contribute to the net
zero emissions goal, with residual emissions in 2050 balanced by atmospheric removals

In addition to rapid cuts in CO2, the NZE Scenario entails a steep fall in other energy‐related
GHGs. For example, energy‐related methane emissions drop by 75% from 120 million tonnes(Mt) in 2021 to 30 Mt in 2030, on track for less than 10 Mt in 2050. There are also reductions
in energy‐related nitrogen dioxide emissions.
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Notes: BECCS = bioenergy equipped with CCUS; DACS = direct air capture and storage. Other includes
agriculture and other energy transformation sectors.

Our modelling of land‐use change and bioenergy production indicates that, taking accountof the level of bioenergy production in the NZE Scenario and assuming parallel action to halt
and reverse deforestation, CO2 emissions from agriculture, forestry and other land use(AFOLU) would drop to become a net CO2 sink before 2030. (See Chapter 9)
The steep reductions in GHG in the NZE Scenario would achieve the goal of the Paris
Agreement to limit the long‐term global temperature rise to “...well below 2 °C above
pre‐industrial levels ... pursuing efforts to limit the temperature increase to 1.5 °C above
pre‐industrial levels”. The global temperature rise in the NZE Scenario peaks under 1.6 °C
around 2040 before dropping to around 1.4 °C in 2100 (Figure 3.2). 2 In the Stated Policies
Scenario (STEPS), by contrast, temperatures reach 2 °C around 2060, and continue to rise
thereafter.

3

Due to uncertainties about the physical response of the climate to GHG emissions, it should
be noted that such projections of future levels of warming are probabilistic in nature: forexample, in the STEPS there is an 10% chance of a temperature rise above 3.2 °C in 2100.
Such an increase would pose a severe threat to the wellbeing of humans and global
ecosystems, with some of the starkest consequences manifesting themselves in the least
wealthy parts of the world (IPCC, 2022b and IEA, 2022a).
Figure 3.2 ⊳Temperature rise in 2050 and 2100 in the WEO-2022 scenarios
2100

°C

2050
4

33rd ‐ 67th
percentile
5th ‐ 95th
percentile

3

Median
2

1

NZE

APS

STEPS

NZE

APS

STEPS
IEA. CC BY 4.0.

Temperature rise peaks at less than 1.6 °C in 2050 in the NZE Scenario and falls to around
1.4 °C by 2100. In the STEPS, it exceeds 2 °C around 2060 and continues rising2

Temperature rise estimates quoted in this section refer to the median temperature rise, meaning there is a
50% probability of remaining below a given temperature rise.

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Notes: NZE = Net Zero Emissions by 2050 Scenario; APS = Announced Pledges Scenario; STEPS = Stated Policies
Scenario. Temperature rise estimates in this section are relative to 1850‐1900 and match the IPCC Sixth
Assessment Report definition of warming of 0.85 °C between 1995‐2014 (IPCC, 2021).

3.2

Energy trends

In the NZE Scenario, the global energy mix undergoes a profound transformation as low‐emissions sources ramp up dramatically and displace unabated sources across the wholeenergy sector. Between 2021 and 2030, low‐emissions sources of supply increase by around
125 exajoules (EJ) (Figure 3.3). The traditional use of biomass is phased out as energy accessgoals are achieved. Among low‐emissions sources, modern bioenergy and solar increase themost to 2030 by around 35 EJ and 28 EJ respectively.
Thanks to electrification, improvements in energy efficiency and behavioural changes totalenergy supply declines by 10% between 2021 and 2030 even as the global economy growsby nearly a third. The annual rate of energy intensity improvement nearly triples as it rises
to more than 4% per year (see section 3.8). Unabated sources of supply decline by nearly athird, with unabated coal falling by nearly one‐half and unabated natural gas by more than
one‐quarter by 2030. This contrasts with the NZE Scenario in the World Energy Outlook 2021
(WEO‐2021), in which natural gas held on to a larger share of the global energy mix for a little
longer: the change reflects heightened energy security concerns around natural gas
precipitated by Russia’s invasion of Ukraine (see Chapter 2). Oil also declines by around one‐
fifth to 2030 as a result of energy efficiency gains, behavioural change and increasing
electrification in transport.
Figure 3.3 ⊳Total energy supply of unabated fossil fuels and low-emissions
sources in the NZE Scenario, 2010-2050

EJ

Unabated fossil fuels

Low‐emissions sources600

Traditionaluse of biomass
Other
renewables
Geothermal
Solar
Wind
Modernbioenergy
Hydro
NuclearNatural gas
Oil
Coal

500
400
300
200

2050

2040

2030

2021

2010

2050

2040

2030

2021

2010

100

IEA. CC BY 4.0.

A profound change in global energy supply underpins the NZE Scenario,

Notes: Unabated fossil fuels are those used for energy purposes without CCUS. Low‐emissions fossil fuelsources are those equipped with CCUS or those for non‐energy uses. Hydrogen and hydrogen‐based fuels are
not shown directly in this figure as these are not primary sources of energy supply.

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with low-emissions sources increasing by around 125 EJ by 2030

The transformation of energy supply is matched by a change in energy consumption(Figure 3.4). Total final consumption in 2021 amounted to around 440 EJ, an increase of 5.2%
over the 2020 level. By 2030, total final consumption in the NZE Scenario is down by almost
10% on the 2021 level, despite rapid growth of global GDP. Over this period, the total final
consumption intensity of GDP improves more than two‐and‐a‐half‐ times faster than the
average over the last decade. Four factors drive this improvement: efficiency benefits ofswitching from the traditional use of biomass; technical gains in energy consuming
equipment and building envelopes; efficiency benefits of electrification; and behaviouralchange and avoided demand (see section 3.8).

EJ

Figure 3.4 ⊳200

3Total final consumption by source in the NZE Scenario, 2010-2050

Industry

Transport

Buildings
Traditional useof biomass
Other
Hydrogen‐based
Other renewables
Modern bioenergy
Electricity
Fossil fuels with CCUS
Unabated fossil fuels

150

100

2010
2021
2030
2040
2050

2010
2021
2030
2040
2050

2010
2021
2030
2040
2050

50

IEA. CC BY 4.0.

End-use sectors come to be dominated by electricity,which provides more than half of total final consumption by 2050
Note: Other renewables include solar thermal and geothermal used directly in end‐use sectors.

Unabated fossil fuels directly provided nearly 60% of total final consumption in 2021,
excluding fossil fuel use for non‐energy purposes such as chemical feedstocks. In the NZE
Scenario, this falls to around 45% in 2030, and to only 5% by 2050 (Box 3.1). Electricity
becomes the “new oil” in terms of its dominance of final consumption; unlike oil, however,it plays a key role in all end‐use sectors. The share of electricity in total final consumption
rises from 20% today to slightly less than 30% by 2030 and more than 50% by 2050. Hydrogenand hydrogen‐based fuels take off after 2030 and account for 10% of total final consumption
by 2050. 3 In absolute terms, the consumption of bioenergy in end‐use sectors remains
broadly stable from today to 2050, rising from 46 EJ to slightly less than 50 EJ. However, thisExcluding the onsite production of hydrogen in industry. In IEA energy balances the onsite production ofhydrogen in industry appears as electricity consumption, raising the share of electricity in final energy
consumption.

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3

masks a shift in composition: the use of modern bioenergy rises sharply while the traditionaluse of bioenergy declines and then ends as full access to modern forms of energy is achievedin all countries by 2030 (Box 3.3).
Box 3.1 ⊳Why doesn’t electricity reach a higher share of TFC?

In the NZE Scenario, electricity accounts for more than 50% of total final consumption by
2050, higher than the highest ever share of oil products in the global final consumptionmix (i.e. around 47% in 1973). However, given the efficiency benefits of electricity, why
is its share in a low‐emissions consumption mix not even higher? The answer to thisquestion has two parts.
Final consumption, useful energy and non-electricity demandby sector and use in the NZE Scenario, 2021 and 2050

Figure 3.5 ⊳Final consumption and useful energy
TFC

BUILD

IND

IND

TRA

Heating

33%

34%

22%

BUILD

32%

20%

Non‐electricity demand NZE 2050

28%

Intensive

Cooking

Light

Feedstock

1%
TRA

47%

Ships
50%

Share of electricity 2021

100%
NZE 2050 share of electricity

PlanesTrucks

Cars

50%
100%
NZE 2050 useful energy demand
IEA. CC BY 4.0.

Electricity provides more than half of final consumption by 2050,
but two-thirds of useful energy
Notes: TFC = total final consumption; BUILD = buildings sector; IND = industry sector; TRA = transportation
sector. NZE 2050 = Net Zero Emissions by 2050 Scenario. In industry, intensive and light refer to energy‐
intensive and light industry sub‐sectors. Trucks = medium and heavy freight trucks.

First, the efficiency of electricity means that its share in useful energy supplied to theend‐user is higher than its share in final consumption.4 The efficiency of an EV is three‐times higher than that of a gasoline car, for example, while the efficiency of a heat pump
can be substantially more than one, so it can deliver more useful energy to the consumer

Useful energy refers to the portion of final energy available to the end‐user after the final conversion. For
example, an internal combustion engine converts the chemical energy in gasoline (final energy) into kinetic
energy, i.e. the motion of the car (useful energy).

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4than it consumes in final energy (efficiencies of between 2 and 5 are prevalent in available
models today). The efficiency of electricity means that its share in useful energy enjoyedby consumers (two‐thirds) is much higher than its share in final consumption (more thanhalf) (Figure 3.5).
Second, there are end‐uses for which it is not feasible or cost effective to electrify directlywith the technologies currently available on the market or likely to be commercialised incoming decades. Around half of energy demand in energy‐intensive industries is for high‐grade process heat (above 400 °C), which is challenging to electrify with current
technologies. Ships, planes and heavy trucks make up around 85% of transport non‐electricity demand in 2050; at present it is very difficult to see how most of the energy
they use could be electrified, although the NZE Scenario does see an increasing amountof electricity used even in these segments, particularly in the case of heavy trucks (seesection 3.6). In the buildings sector, existing district heating networks are strategic assets,
and are in part decarbonised with non‐electrical energy sources in the NZE Scenario,
notably modern solid bioenergy. In addition, industry feedstocks by definition cannot beelectrified, and account for nearly one‐third of non‐electrical demand in industry in 2050
in the NZE Scenario.

3

S P O T L I G H T
Comparison with the new scenarios assessed by the IPCCThe IEA NZE Scenario entails very ambitious policies and measures to improveenergy efficiency and reduce energy demand, including through behavioural change(see section 3.8). As a consequence of this and the benefits of electrification, total
final consumption is around 340 EJ in 2050, compared to around 460 EJ in the
median IPCC scenario.

The NZE Scenario sees the share of wind and solar in electricity generation reachover 70% in 2050, compared to around 55% in the median IPCC scenario.

The NZE Scenario sees total energy supply from bioenergy of around 100 EJ,
reflecting the importance of remaining within identified sustainable limits for global
bioenergy supply. The median IPCC scenario reaching net zero emissions by 2050
sees around 235 EJ of bioenergy demand, more than double the level of the NZE
Scenario and three‐and‐a‐half‐times the current level.

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The third volume of the IPCC Sixth Assessment Report deals with climate mitigation (IPCC,
2022a). Published in April 2022, it includes a new scenario database (IIASA, 2022). Amongthe more than 1 000 scenarios vetted by the IPCC, only 16 achieved net zero emissions
from the energy sector in 2050, and therefore are comparable in terms of energy sector
ambition with the IEA NZE Scenario. Here we highlight a comparison between those IPCC
assessed scenarios and the IEA NZE Scenario (Figure 3.6).

The NZE Scenario sees about 30 EJ of hydrogen and hydrogen‐based fuels used todecarbonise end‐use sectors that are difficult to electrify. The median IPCC scenario
uses about 18 EJ of hydrogen and hydrogen‐based fuels.

The NZE Scenario uses 6.2 Gt of CCUS in 2050 while the median of the IPCC scenarios
see about 17 Gt.



The NZE Scenario relies on around 1.5 Gt of energy sector CDR from both BECCS and
DACS, while the median IPCC scenario sees 12 Gt of energy sector CDR in 2050,
largely from BECCS and mostly to offset continued use of oil in the transport sector.
Comparison of key indicators for the selected IPCC scenarios
and the IEA NZE Scenario in 2050

EJ

TFC

Bioenergy TES

Wind and solar share

600

100%

450

75%

EJ

Figure 3.6 ⊳

300

200
300

50%

150

25%

100

30

Gt CO₂30

Energy‐related CDR

CCUS
Gt CO2

EJ

Hydrogen in TFC
40

15

20

10

10

5

20
10

IPCC Scenarios

NZE
IEA. CC BY 4.0.

IEA NZE Scenario requires less CCUS and CDR than comparable IPCC scenarios,
and it relies more on energy efficiency, renewables and hydrogen

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Notes: TFC = total final consumption; TES = total energy supply; CCUS = carbon capture, storage andutilisation; CDR = carbon dioxide removal. IPCC Scenarios refers to the 16 vetted C1 IPCC scenarios thatreach net zero energy sector emissions by 2050 (IIASA, 2022).

3.3

Fuel supply

Fossil fuel supply
Oil, natural gas and coal accounted for around four‐fifths of total energy supply worldwide
in 2021. In the NZE Scenario, this share falls to around two‐thirds in 2030 and less than one‐
fifth in 2050, a proportion of which is used with CCUS and for non‐energy uses. Between
2021 and 2050, coal demand declines by 90%, oil declines by around 80%, and natural gas
declines by more than 70%.

3

Just under 100 EJ of fossil fuels are consumed in 2050 in the NZE Scenario. Just over 40% of
this, including 65% of natural gas and 90% of coal, is consumed in facilities equipped with
CCUS. A further 40% – including more than 70% of the oil still being used – is consumed inapplications where the carbon is embodied in the product and there are no direct CO2
emissions (examples include chemical feedstocks, lubricants, paraffin waxes and asphalt).
The remaining 20% is used in sectors where clean energy technologies are least feasible andcost effective: for example, oil still accounts for around 20% of fuel use in aviation in 2050 in
the NZE Scenario. The unabated combustion of fossil fuels results in 1.2 Gt CO2 emissions in
2050, and these are fully offset by BECCS and DACS.

EJ

Figure 3.7 ⊳200

Oil, natural gas and coal supply by region in the NZE Scenario
Oil

Natural gas

Coal

150

100

50

2010
Asia PacificMiddle East

2050 2010
North America

Eurasia2050 2010
AfricaC & S America

2050
EuropeIEA. CC BY 4.0.

Declines in demand can be met without approving new long lead time upstream
conventional oil and gas projects, new coal mines or mine lifetime extensions

Coal use declines from 5 600 million tonnes of coal equivalent (Mtce) in 2021 to
3 000 Mtce in 2030 and to less than 600 Mtce in 2050 (Figure 3.7). Supply declines on
average by more than 10% every year during the 2030s. Natural gas demand drops fromaround 4 200 bcm in 2021 to 3 300 bcm in 2030, and 1 200 bcm in 2050. Rates of decline are
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Note: C & S America = Central and South America.

fastest in the 2030s, when natural gas use falls by 7% per year on average. Natural gas use
continues to fall in the 2040s, but at a slower rate (around 3% per year) as reductions in gas
use in power generation, industry and buildings are partly offset by increases in the volumesof gas being converted to low‐emissions hydrogen. Oil demand declines from 95 million
barrels per day (mb/d) in 2021 to 75 mb/d in 2030, and to less than 25 mb/d in 2050, withan annual decline rate of 6% on average from 2030 onwards.
The declines in fossil fuel demand in the NZE Scenario stem primarily from a major surge inclean energy investment (from around USD 1.2 trillion in recent years to USD 4.2 trillion in2030). Some investment in existing supply projects continues in the NZE Scenario to ensure
supply does not fall faster than the decline in demand. Other investment is undertaken to
reduce the emissions intensity of remaining fossil fuel operations. In the NZE Scenario, thisleads to a 50% reduction in the global average emissions intensity of oil and gas production
between 2021 and 2030. If demand were to fall at the rates projected in the NZE Scenario, it
could be met without approving the development of any new long lead‐time upstream
conventional oil and gas projects and without any new coal mines or coal mine lifetime
extensions worldwide.
Reducing fossil fuel investment in advance of, or instead of, policy action and clean energy
investment to reduce energy demand would not lead to the same outcomes as in the NZE
Scenario. If supply were to transition faster than demand, with a drop in fossil fuelinvestment preceding a surge in clean energy technologies, this would lead to much higher
prices – possibly for a prolonged period – even if the world moves towards net zero
emissions. The scope for reductions in fossil fuel expenditure is closely linked to the scaleand speed of increases in clean energy expenditure, and to the success of efforts to reduceenergy demand: it does not make sense to look at any one of these factors in isolation fromthe others.
Russia’s invasion of Ukraine adds an additional dimension to this analysis because it could
lead to a substantial and prolonged reduction in Russian energy supplies. This is reflected in
the updated NZE Scenario.

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Turning first to oil, Russian production is lower in the 2022 NZE Scenario than it was in lastyear’s NZE Scenario. The failure to ensure a sustainable recovery from the pandemic meansthat projected oil demand is at the same time higher in the mid‐2020s in this NZE Scenario.
The more suitable options to fill this combined gap are investments with shorter lead times
and quicker payback periods, including extending production from existing fields and tightoil. The updated NZE Scenario also requires higher near‐term production from members of
OPEC than before to keep markets in balance, and a continuing high level of reliance on thisproduction to meet remaining oil demand through to 2050. The share of oil supply comingfrom OPEC members rises from 35% in 2021 to 52% in 2050. Even though the oil market ismuch smaller in 2050 than today, the share of OPEC by then would be higher than at any
point in the history of oil markets.

For natural gas, Russian production in the mid‐2020s is lower than it was in the 2021 Net
Zero Roadmap. However, in contrast to oil, near‐term gas consumption has been revised
downwards in this year’s NZE Scenario as higher prices curb the cost effectiveness of gas
helping to displace coal. Some new infrastructure may be needed to facilitate thediversification of supply away from Russia, and, with careful investment planning, there areopportunities for these to facilitate future imports of hydrogen or hydrogen‐based fuels.
Nonetheless, natural gas demand in the NZE Scenario can be met through continued
investment in existing assets and already approved projects but without any new long leadtime upstream conventional projects.

3

Low‐emissions fuels
Net zero emissions does not mean the total phase out of fuels. Fossil fuel use declines, butthere is rapid growth in low‐emissions fuels (including solid, liquid and gaseous modern
bioenergy, hydrogen and hydrogen‐based fuels) (Figure 3.8). These play a key role in
reducing emissions from long‐distance transport and high‐temperature industrial processes.
In the NZE Scenario, low‐emissions fuels comprise 20% of all liquid, solid and gaseous fuels
used worldwide in 2030 and 65% by 2050.
Figure 3.8 ⊳Bioenergy supply and hydrogen production by source in the
NZE Scenario, 2021-2050

Bioenergy supply
Modern solid bioenergy
Liquid biofuels
Biogases
Conversion losses
Traditional use of biomass

2021
2030
2050

Hydrogen production
2021

Fossil fuels without CCUS
Fossil fuels with CCUS
Offsite electrolysis
Onsite electrolysis
Other

2030
2050

25

50

75

100
EJ
IEA. CC BY 4.0.

Hydrogen production rises nearly fivefold from today to 2050, but modern
bioenergy supply, limited by sustainable potentials, increases by two-and-a-half-times

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Note: For hydrogen production, other includes refinery by‐products.

For bioenergy, around 24 EJ of current consumption comes from the traditional use of
biomass; this drops to zero as full access to modern cooking solutions is achieved by 2030 in
the NZE Scenario. Modern bioenergy use increases from around 41 EJ today to more than
75 EJ in 2030 and to 100 EJ in 2050. In 2050, around one‐third of this is used in the power
sector, providing an important source of low‐emissions dispatchable generation, and morethan one‐third is used in industry and buildings. Slightly less than 6 million barrels of oil
equivalent per day (mboe/d) of liquid biofuels and 400 billion cubic metres equivalent of
biogases are consumed in 2050. To avoid conflicts between food production andaffordability, there is a general shift in the NZE Scenario away from conventional bioenergy
sources towards advanced bioenergy, with around 50% of bioenergy supply coming fromorganic waste streams and forestry residues that do not require dedicated land use. Most of
the remaining supply is provided by dedicated short rotation woody crops grown on
cropland, pasture land and marginal lands that are not suited to food crops. There is no net
increase in cropland use for bioenergy, and no bioenergy crops are grown on existing
forested land in the NZE Scenario (see Chapter 9).
The supply of low‐emissions hydrogen increases from 0.3 Mt (45 petajoules) today to 90 Mt
in 2030 and 450 Mt in 2050.5 More than 95% of total hydrogen and hydrogen‐based fuel use
in 2050 is in transport, power and industry. Of the low‐emissions hydrogen produced in 2050,
a little less than three‐quarters is produced via water electrolysis, and a bit more than one‐quarter is produced from fossil fuels with CCUS. The installed capacity of electrolysers
reaches 720 gigawatts (GW) in 2030 and 3 670 GW in 2050 (existing electrolyser capacity isaround 510 MW). In 2050, more than 14 800 TWh of electricity is used to produce low‐emissions hydrogen, equivalent to more than half of today’s global electricity demand fromall sources. Around 25% of total low‐emissions hydrogen in 2050 is converted to low‐emissions hydrogen‐based fuels. Synthetic kerosene produced from hydrogen (andcombined with a non‐fossil fuel source of CO2) provides around 25% of energy use in theaviation sector, and ammonia and hydrogen provide more than 40% of energy use inshipping.

3.4

Electricity generation

5

This includes both low‐emissions hydrogen and the hydrogen contained in hydrogen‐based fuels. See
Chapter 5 and Annex C for definitions.

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Global electricity generation increases over two‐and‐a‐half‐times in the NZE Scenario from2021 to 2050. Total electricity generation increases by 3.2% per year to 2030 and then by
3.4% per year from 2030 to 2050, compared with 2.5% per year from 2010 to 2021. The
electrification of end‐uses ranging from EVs to space heating to industrial production raises
the share electricity in final consumption from 20% in 2021 to almost 30% in 2030, and morethan 50% in 2050. The rapid growth of low‐emissions hydrogen adds almost 3 000 TWh ofdemand growth by 2030, and more than 14 800 TWh by 2050.

Low‐emissions sources of electricity – renewables, nuclear power, fossil fuel power plants
with CCUS, hydrogen and ammonia – expand rapidly in the NZE Scenario, overtaking
unabated fossil fuels just after 2025 and reaching three‐quarters of total generation by 2030,
almost twice the share in 2021. Electricity sectors in advanced economies reach net zero
emissions by 2035 in the NZE Scenario, and globally by 2040, at which point low‐emissions
sources provide nearly all electricity generation (Figure 3.9). This makes electricity the firstenergy sector to reach net zero emissions in the NZE Scenario, and that helps bring about
emissions reductions in other sectors as they increasingly look to electricity to meet risingdemand for energy services.
Figure 3.9 ⊳CO2 emissions by source and key milestones in the electricity
sector in the NZE Scenario, 2020 to 2050
2025
Nearly 50% ofelectricity fromlow‐emissions
sources

Gt CO₂2022
No new unabatedcoal power plants
approved fordevelopment

Hydrogen andammonia start
to co‐fire withnatural gas
and coal

16

3

14
12

2030
Phase out
subcritical coal

2035

Over 40% ofelectricity fromwind and solar PV
Wind and solar
annual capacity
additions pass
1 050 GW

10Advanced
economies
net zero emissions
in the electricity
sectorOver 50% increasein nuclear power
capacity

2040
Global net zero
emissions in theelectricity sector
Phase out of all
unabated coal

Almost 70% ofelectricity fromwind and solar PV

Unabated natural
gas below 5% ofelectricity
generation

8
6

2050
1.5 Gt CO2
captured at power
plants annually

Nearly 90% ofelectricity fromrenewables

4
2
0
‐2
2020

2025

2030
27% of total final
consumption met
by electricity

Coal

Natural gas

Oil

2035

2040

2045

Over 40% of total
final consumption
met by electricity

Waste non‐renewable

2050

Over 14 800 TWh
used to producehydrogen

Bioenergy with CCUS
IEA. CC BY 4.0.

Electricity is the first sector to reach net zero emissions in 2040, tapping a wide set of lowemissions sources and enabling other sectors to cut emissions through electrification

Renewables rapidly become the foundation of the global electricity sector in the NZE
Scenario. The share of renewables in electricity generation rises from 28% in 2021 to over
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Notes: TWh = terawatt‐hour; CCUS = carbon capture, utilisation and storage. Waste non‐renewable represents
any non‐biogenic waste combusted for energy purposes.

60% in 2030, and nearly 90% in 2050. The total installed capacity of renewables triples to2030 and rises sevenfold to 2050. Annual renewables capacity additions quadruple from
290 GW in 2021 to nearly 1 200 GW in 2030, and average above 1 050 GW from 2031 to2050.
Solar PV and wind are the leading means of cutting electricity sector emissions: their global
share of electricity generation increases from 10% in 2021 to 40% by 2030, and 70% by 2050
(Figure 3.10). Solar PV additions expand more than fourfold to 650 GW by 2030, and windadditions to over 400 GW, with more than 20% of this from the developing offshore windindustry. Capacity additions of hydropower and other dispatchable renewables triple by2030 to over 125 GW, helping to cut emissions and providing low‐emissions means ofintegrating the growing amounts of solar PV and wind.
Figure 3.10 ⊳ Total installed capacity and electricity generation by source in
the NZE Scenario, 2010-2050
Electricity generation
Thousand TWh

Thousand GW

Installed capacity
40
30
20

30
20
10

10

2010 2021 2030 2040 2050
Solar PV
Bioenergy and waste
Hydrogen and ammonia
Natural gas unabated

2010

Wind
Other renewables
Fossil fuels with CCUS
Oil

2020

2030

2040

2050

Hydro
NuclearCoal unabatedBatteries
IEA. CC BY 4.0.

Total electricity generation nearly triples to 2050, with a rapid shift away fromunabated coal and natural gas to low-emissions sources, led by solar PV and wind

The use of low‐emissions hydrogen and ammonia in natural gas‐ and coal‐fired power plants
and the addition of carbon capture technologies both provide important means of cutting
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Nuclear power generation more than doubles in the NZE Scenario by 2050, although its sharefalls from 10% in 2021 to 8% in 2050, as total generation expands rapidly. More than
30 countries, where nuclear power is accepted, increase their use of nuclear power.
Widespread lifetime extensions in advanced economies provide a foundation. An annual
average of 30 GW of new nuclear capacity comes online in the 2030s, marking a major
comeback for the nuclear industry, and innovative technologies including small modular
reactors become available on the market.

emissions from existing power plants while supporting electricity security. The use ofhydrogen and ammonia blended with natural gas and coal scales up in the late 2020s, and a
total of 410 GW of natural gas‐fired power plants and 160 GW of coal‐fired plants are
retrofitted by 2050 to co‐fire ammonia and hydrogen, providing 2‐3% of global electricity
generation from 2030 to 2050. A total of over 60 GW of coal‐ and gas‐fired power plants are
retrofitted with CCUS by 2030, and this rises to over 330 GW by 2050. Fossil fuels with CCUS
provide 1‐2% of global electricity generation from 2030 to 2050

3

Phasing out unabated use of coal to generate electricity is a central pillar of the NZE Scenario
as coal is an emissions‐intensive fossil fuel still in widespread use. Emissions from unabatedcoal were 9.7 Gt CO2 in 2021, accounting for 74% of the electricity sector total and 26% of
total energy sector emissions. Despite a temporary boost from the current energy crisis asconsumers switch from natural gas because of concerns about high prices and security ofsupply, the share of unabated coal in global electricity generation falls rapidly from 36% in
2021 to 12% in 2030, and to zero percent by 2040 and beyond. Low‐emissions sources ofgeneration grow so rapidly that no new unabated coal plants beyond those already underconstruction are built in the NZE Scenario.
Phasing out unabated coal emissions from power generation by 2040 worldwide depends oncurrent power plants ceasing to provide regular baseload power. If the existing fleet of coal‐
fired power plants were to operate as they have in recent years, this alone would take up
more than half of the remaining carbon budget consistent with limiting the global averagetemperature rise to 1.5 °C. However, such phasing out is not an easy proposition with anexisting fleet of over 8 000 coal plants operating in some 90 countries and providing 2 million
jobs. Against this background, it is important for there to be a range of options from which
policy‐makers can choose, which should include repurposing plants to focus on flexibility,
retrofitting with carbon capture technologies, retrofitting to co‐fire ammonia or biomass,
and retiring them early.

Battery storage takes off in the NZE Scenario, expanding 30‐fold from 2021 to 2030. This
growth reflects its increasingly important role in helping to integrate rising shares of solar PV
and wind by regularly charging at times of plentiful renewables supply and discharging whenmost needed in the system. Battery storage is also able to bolster the stability and reliabilityof electricity networks, for example by providing fast frequency response. By 2030, global
battery capacity reaches 780 GW in the NZE Scenario and accounts for about 15% of all
dispatchable power capacity. By 2035, battery capacity surpasses natural gas‐fired capacity
as the principal source of flexibility in many markets. Other forms of storage, such as heat or
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Natural gas in the NZE Scenario faces a reduced role in this update compared with the 2021
version. This reflects current market conditions and changing perceptions of the affordability
and security of natural gas. In this updated NZE Scenario, natural gas‐fired generation peaks
by 2025 before starting a long‐term decline. By the time the global electricity sector reaches
net zero emissions in 2040, the unabated use of natural gas is 97% lower than it was in 2021.
Even as output falls, however, natural gas‐fired capacity remains a critical source of powersystem flexibility in many markets, particularly to address seasonal flexibility needs.

gravity‐based systems, are under development and may emerge to complement or competewith battery storage.
Electricity transmission and distribution grids expand to meet the growing demands ofelectrification, connect thousands of new renewable energy projects, and reinforce systems
that need to adapt to changing system dynamics. Global investment in grids to 2030 reaches
close to USD 750 billion per year in the NZE Scenario, and it remains at a high level throughto 2050. Close to 70% of this investment is for distribution grids with the aim of expanding,strengthening and digitalising networks.
Electricity security is of paramount importance in the NZE Scenario as the global economy
becomes more and more dependent on reliable and stable electricity supply. Security
depends on grids being modernised and digitalised to facilitate more advanced and smarter
operations as the number of users and uses of electricity expands and as the nature ofelectricity supply evolves. It also depends on system flexibility, which is fast becoming thecornerstone of electricity security. In the NZE Scenario, power system flexibility needs
quadruple between today and 2050, driven by the fast‐rising share of variable renewables
and changes in electricity demand patterns. Unabated coal and natural gas power plants andhydro have traditionally provided the lion’s share of flexibility to power systems. Thischanges dramatically in the NZE Scenario as electricity shifts to low‐emissions sources ofgeneration. Batteries and demand‐side response meet more than half of the flexibility needs
in 2050, with another quarter coming from hydropower and most of the rest from low‐emissions thermal power plants, including nuclear, fossil fuels equipped with CCUS andplants that co‐fire hydrogen or ammonia. Around 5% is still provided by unabated naturalgas.

Massive investment in renewables and other low‐emissions sources means that electricity
supply becomes more capital intensive. Capital recovery rises from about 40% of electricity
supply costs today to almost 80% in 2050 in the NZE Scenario, while fuel costs fall from one‐
third to just 5% in 2050. As a result, electricity system costs become more predictable andenergy market volatility declines. Both advanced economies and emerging market anddeveloping economies see lower electricity system costs by 2050. The costs of transitions inemerging market and developing economies are kept down by particularly low solar PV andwind costs, linked to lower technology costs and high quality solar resources in many
countries.
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The affordability of electricity is a critical concern for consumers and policy makers in energy
transitions, and it will become more critical still as electricity comes to represent an everlarger share of final consumption and total energy bills. In absolute terms, global electricity
supply costs – including generation, storage and grids ‐ more than double from today’s level
to USD 4.7 trillion annually in 2050. However, this increase in supply costs is less than thegrowth in electricity demand over the same period. In the NZE Scenario, electricity costs
come down from their current high levels as cost‐effective solar PV and wind are scaled up,
and total electricity supply costs per unit of electricity generation are broadly stable to 2030.
By 2050, the average cost of electricity is 10% below the level in 2021.

3.5

Industry

In 2021, the industry sector worldwide accounted for almost 170 EJ of energy consumption,
which is slightly more than the total energy supply of China. Industry represents more than
one‐third of total final energy consumption, and its 9 Gt CO2 emissions make up 45% of total
direct emissions from end‐use sectors. There is no way to reach net zero emissions without
strong and co‐ordinated action on emissions reduction in the industry sector.
Figure 3.11 ⊳ Emissions reductions and key milestones in the industry sector in3

the NZE Scenario relative to the STEPS, 2020-2050
2050
Clinker to cement
ratio: 0.56

2040
2030
8% of CO2 stored
8% near‐zerocarbon primary steel
production

2025

Gt CO₂Clinker to cement
ratio: 0.69

26% of plastics
collected for recycling

72% of electricity

95% of CO2 stored

53% near‐zerocarbon primary steel
production

96% near‐zerocarbon primary steel
production

2035

2045

All electric motor
sales are best in class

47% of plastics
collected for recycling

STEPS

10

Rest of industry

8
Light industries

6

Cement4

Iron and steel

2

Chemicals
NZE

2020

2025

2030

2035

2040

2045

2050

Energy intensity:
3.9 GJ/USD 1 000 VA

Energy intensity:
2.9 GJ/USD 1 000 VA

Energy intensity:
2.2 GJ/USD 1 000 VA

Energy intensity:
1.7 GJ/USD 1 000 VA

22% electricity in TFC

29% electricity in TFC

40% electricity in TFC

50% electricity in TFC

IEA. CC BY 4.0.

Industry requires a portfolio of technologies and measures to reach net zero emissions,

Notes: VA = value added; TFC = total final consumption. Innovative routes for iron and steel include hydrogen‐based and CCUS‐based routes. Milestones in green relate to the whole of the industry sector.

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such as energy and material efficiency, electrification, hydrogen and CCUS

The world has not yet reached peak materials demand in industry. In the STEPS, world output
of crude steel increases by around 10% by 2030, and around 30% by 2050, driven by India,
Southeast Asia, and Africa. Global output of cement also increases as Africa and India
continue the processes of urbanisation and industrialisation. A much stronger focus on more
efficient use of materials tempers this growth in the NZE Scenario, but it is not enough toprevent an overall increase in demand for industrial materials.
Several other challenges stand in the way of industry sector decarbonisation. First, manytechnologies required for the transition in the industry sector are still at prototype ordemonstration stage and not yet ready for deployment at scale. Second, in a number of cases
new production processes with substantially lower emissions intensities will – at least initially– have higher costs. Third, many heavy industry sector products, such as steel, are tradedinternationally in competitive markets, with margins that are too slim to absorb elevatedproduction costs or to encourage first movers to adopt new technologies. In addition, heavy
industrial facilities are long‐lived and capital intensive. These challenges call for a multi‐
pronged approach to decarbonisation in industry in the NZE Scenario.
Central to the pathway for the industry sector are measures to avoid energy demand growththrough improved energy and materials efficiency. In the NZE Scenario, total final
consumption in the sector is nearly 10% lower than in the STEPS by 2030 (Figure 3.12). Energy
efficiency contributes nearly half of the additional energy savings achieved in the NZE
Scenario. Policies to speed the deployment of best available technologies in electric motor
systems, and thermal and mechanical equipment are central to the achievement of thesesavings, together with process integration strategies. Materials efficiency reduces demand
for materials and accounts for nearly one‐fifth of the additional energy savings. Significant
measures include to increase light‐weighting and life extensions of equipment andinfrastructure and to support product reuse and recycling.
These measures are especially important in the near term to help avoid growth in unabatedproduction capacity while low‐emissions technologies are reaching market maturity andscaling up. However, changes in the industry sector fuel mix are already clearly visible by2030 in the NZE Scenario (Figure 3.12).
In steel, nearly three‐quarters of total final consumption is currently provided by coal, ahigher share than in any other sub‐sector. Coke, produced from coking coal, provides high‐temperature process heat and serves as a reducing agent for the reduction of iron ore in theblast furnace route. In the NZE Scenario, the share of unabated coal in total sector demand
falls to slightly more than 60% by 2030, while the share of electricity rises by eight percentage
points. By 2050, the share of electricity reaches nearly 60%, driven by increased secondary
steel production (only limited by scrap availability) and by increasing demand for onsite
electrolytic hydrogen production. This transition is facilitated by higher recycling rates
globally, which enable secondary steel production to rise from around 20% today to morethan 25% by 2030. Hydrogen‐based direct reduced iron (DRI) becomes a key technology for
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primary steel production in the long term: the electricity required for the onsite production
and use of hydrogen accounts for 3% of total steel making final energy consumption in 2030,
and this surges to more than 25% in 2050.
Figure 3.12 ⊳ Final energy consumption by source in industry sub-sectors in

EJ

the NZE Scenario, 2021-2050
Iron and steel

CementChemicals

Other industry

2021 2030 2050

2021 2030 2050

2021 2030 2050

2021 2030 2050

3

80

60

40

20

Coal: unabatedOil: unabated
Natural gas: unabatedElectricity
Modern solid bioenergy

Coal: with CCUS
Oil: with CCUS
Natural gas: with CCUS
Heat
Non renewable waste

Coal: feedstock
Oil: feedstock
Natural gas: feedstock
Hydrogen
Other renewables

STEPS

IEA. CC BY 4.0.

Electricity makes inroads in all industry sub-sectors; in some it is used to produce hydrogen
onsite. In 2050, the share of unabated fossil fuels is less than 5%, from around 50% today.
Notes: EJ = exajoules; CCUS = carbon capture, utilisation and storage; STEPS = Stated Policies Scenario. Onsite
electrolytic hydrogen use is reported as electricity demand rather than as hydrogen demand. Other industry
includes light industries and non‐specified industry.

These transformations in the iron and steel sector require strong policies, linking demand
pull and supply pull measures. Common definitions of near zero emissions material
production are an essential foundation for such policies (Box 3.2).

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Electricity is complemented by a range of additional low‐emissions fuels. From almost zero
today, the use of coal and natural gas with CCUS increases to meet 2% of steel sector demandby 2030 and more than 20% by 2050. CCUS is deployed in particular in regions where there
is stock of very young blast furnaces, notably in China, and where there is limited access tohigh quality renewable resources but easy access to competitive coal and natural gas. The
share of modern bioenergy, mainly solid bioenergy, reaches around 10% and merchanthydrogen, i.e. not produced onsite, accounts for around 5%.

Box 3.2 ⊳Near zero emissions material production: moving towards
common definitions

The IEA tracks the deployment of EVs in transport, heat pumps in buildings, and solar andwind generation in electricity. But what is the equivalent for industrial sub‐sectors suchas steel and cement? Defining what level of emissions intensity “makes the cut” for thetransition to net zero emissions is critical, particularly for measures designed to create
leading markets for near zero emissions products (demand pull) and to help direct
investment for deployment (supply push). For example, with commonly understooddefinitions in place, private and public sector actors could commit to procure near zero
emissions steel and cement at a premium, incentivising industry to scale up production.
The IEA undertook an analysis in the last year, at the request of the German G7
Presidency, to develop definitions for near zero emissions steel and cement production.
Incorporating input from a diverse group of stakeholders, the definitions were proposedin Achieving Net Zero Heavy Industry Sectors in G7 Members (IEA, 2022a). The objective
is to work towards internationally agreed definitions that can help to accelerate progress.
The near zero emissions definitions are designed to be stable, absolute and ambitious,and to be compatible with a global energy system trajectory that achieves net zero
emissions by mid‐century. The thresholds are:

Steel: The threshold is a function of the proportion of scrap use in total metallic
inputs – the more scrap used, the lower the threshold – as the use of scrap in steel
making inherently reduces emissions intensity and its use is already wellincentivised. For steel with no scrap use, the proposed threshold is 400 kilogrammes
CO2‐equivalent per tonne (kg CO2‐eq/t) of crude steel, and for 100% scrap use it is
50 kg CO2‐eq/t.

Cement: Similarly, the threshold for cement is a function of the proportion of clinker
use – the more clinker used, the higher the threshold – given that use of
supplementary cementitious materials (SCMs) leads to lower emissions intensity
and is already well incentivised. For cement with 100% clinker use, the proposed
threshold is 125 kg CO2‐eq/t cement, while for full use of SCMs the threshold is
40 kg CO2‐eq/t (noting that for most applications, the minimum practicallyachievable clinker content of cement is thought to be about 50%).

The IEA analysis was recognised by G7 ministers in the 2022 Climate, Energy andEnvironment meeting communiqué, and is already being put to use. For example, they
are used in the Clean Energy Ministerial (CEM) Industrial Deep Decarbonisation
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Interim measures that substantially lower the emissions intensity of materials
production, but fall short of the near zero emissions thresholds, should also berecognised. As such, complementary definitions for “low emissions production” of steel
and cement have been proposed in order to recognise the important interim steps taken
along a clear path towards near zero emissions intensity.

Initiative’s Green Public Procurement Pledge announced at the CEM in Pittsburgh,
Pennsylvania (United States) in September 2022. Further efforts to expand the use andrecognition of agreed thresholds and definitions will be important to enable accelerated
clean energy transitions for industry.
Cement production today is fuelled by a broader range of sources than steel, although coal
still accounts for around half of total energy consumption in the sub‐sector. In the near term,
reducing the amount of clinker in cement is a key strategy that prevents more than 250 Mt
CO2 of process and energy‐related emissions by 2030 in the NZE Scenario compared with the
STEPS. CCUS is the only other measure that simultaneously avoids both energy‐related andprocess emissions from cement production. The integration of CCUS in cement kilns istherefore central to the decarbonisation of the cement sub‐sector. In the NZE Scenario, theuse of CCUS results in 1.3 Gt CO2 being captured and stored from cement production by
2050, or almost 95% of the emissions generated in the sub‐sector.

3

There is also some switching to the use of low‐emissions fuels in cement kilns. This isdominated by modern solid bioenergy, whose share increases from slightly more than 5%
today to nearly 15% by 2030, and almost one‐third by 2050. Electricity, currently largely used
for mechanical energy in uses such as clinker grinding, increases its share of the cement
production market from 12% today to more than 20% by 2050 as electric kilns start to be
deployed after 2040. Merchant hydrogen is also deployed in cement production, reachingaround 5% of total consumption by 2050.
The chemicals sub‐sector is less emissions intensive than steel and cement. This is partly
because oil and natural gas are the dominant fuels instead of coal, but much more because
90% of oil consumption is for non‐energy uses as feedstock. In the NZE Scenario, materials
efficiency strategies such as single‐use plastics bans, plastic reuse and recycling are pursued
through targeted and stringent policies, which by 2050 result in the saving of around 30% of
the oil feedstock used in the STEPS.

The other industry sub‐sector includes a wide variety of industrial branches, most of whichhave lower energy intensity needs than steel, cement and chemicals. This sub‐sector isalmost completely decarbonised by 2050 in the NZE Scenario. Electricity already provides
nearly 35% of total final consumption, and this rises to nearly 50% by 2030, and to two‐thirds
by 2050. Electricity is complemented by increasing use of modern solid bioenergy andbiomethane, and other renewables including solar thermal and geothermal for low‐temperature needs.
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Electricity makes inroads by 2030, increasing its share in the chemical sub‐sector’s energy
consumption from a bit more than 10% today to around 15% by 2030, and 35% by 2050. Thisis mostly driven by the increasing production of onsite electrolytic hydrogen in place of fossil
feedstock for ammonia and methanol production in particular. Direct use of renewables,such as bioenergy, solar thermal and geothermal, provides around 10% of the sub‐sector’s
consumption by 2050, while merchant hydrogen used as a fuel provides around 5%.

3.6

Transport

The global transport sector consumes a quarter of total final energy consumption today andis responsible for nearly 40% of the emissions from end‐use sectors. Oil dominates intransport, accounting for 90% of consumption. From 2010 to 2019, increasing demand forpassenger and goods mobility resulted in the transport sector seeing the largest growth inemissions of all end‐use sectors. In 2021, global CO2 emissions from the sector rebounded to
7.7 Gt CO2, from 7.1 Gt CO2 in 2020 as mobility demand recovered from the pandemic.
Figure 3.13 ⊳ Emissions reductions and key milestones in transport in the NZE
Scenario relative to the STEPS, 2020-2050
2045
2035

2030

Gt CO₂

No new ICE heavy
truck sales

65% of rail is electric

No new ICE two/
three‐wheeler sales

60% EV sales forlight‐duty vehicles

No new ICE light‐duty
vehicles sales

2040

2050

60% of shippingis based on
low‐emissions fuels

Regional flights
shifted to high‐speed
rail where feasible

10
STEPS
Other

8

Shipping and aviation

6
Heavy trucks

4
Light‐duty vehicles

2

NZE

2020

2025

2030

2035

2040

2045

2050

USD 6 billion publiccharging investment

USD 40 billion publiccharging investment

USD 120 billion publiccharging investment

USD 170 billion publiccharging investment

5% low‐emissions
fuels in non‐road

20% low‐emissions
fuels in non‐road

55% low‐emissions
fuels in non‐road

85% low‐emissions
fuels in non‐road

IEA. CC BY 4.0.

Electrification of road transport and rail brings rapid and massive emissions reductions;

Notes: ICE = internal combustion engine. Light‐duty vehicles include passenger light‐duty vehicles and lightcommercial vehicles. Other includes two/three‐wheelers, buses, rail, pipeline and non‐specified. Non‐road
includes aviation, shipping and rail modes. Low‐emissions fuels include biofuels and low‐emissions hydrogenand hydrogen‐based fuels.

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behavioural changes and low-emissions fuels are key in aviation and shipping

Both passenger and freight activity are set to more than double by 2050 in the NZE Scenario,
driven by higher mobility needs in emerging market and developing economies as theireconomies and populations grow and living standards increase. Energy demand growth istempered in the NZE Scenario by improvements in technical and operational efficiency acrossall modes – road, aviation, shipping and rail – as well as by the deployment of highly efficient
vehicles, i.e. electric vehicles (EVs), and policies to promote modal and behavioural shifts(Figure 3.13).

3

Decarbonising the transport sector in the NZE Scenario depends primarily on two changes.
First is a switch to electricity, especially to the use of EVs6 and hydrogen fuel cell electricvehicles in road transport. Second is a move to both blending and direct use of low‐emissions
fuels such as biofuels, hydrogen and hydrogen‐based fuels, especially in aviation andshipping.
Figure 3.14 ⊳ Final energy consumption in transport by source and mode in

EJ

the NZE Scenario, 2021-2050
60Light‐duty vehicles

Heavy trucks

Aviation and shipping

Other2021 2030 2050

2021 2030 2050

2021 2030 2050

2021 2030 2050

40

20

Oil
Natural gas
STEPS

Coal

Electricity

Bioenergy

Hydrogen and hydrogen‐based fuels
IEA. CC BY 4.0.

Direct electricity use is key to decarbonising road transport and rail; hydrogen andhydrogen-based fuels play a major role in aviation and shipping
Note: Light‐duty vehicles include passenger light‐duty vehicles and light commercial vehicles. Other includes
two/three‐wheelers, buses, rail, pipeline and non‐specified. STEPS = Stated Policies Scenario.

6

EVs refer to full battery electric vehicles and plug‐in hybrid electric vehicles.

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In the NZE Scenario, the share of oil in transport final consumption drops to around 75% by2030 and to 10% by 2050. Electricity is the key substitute for oil, accounting for nearly 50%
of transport final energy consumption by 2050, but hydrogen and hydrogen‐based fuels (30%of final consumption in 2050) and biofuels (almost 15%) also play important roles. Light‐duty
vehicles such as cars, vans and two/three‐wheelers as well as most rail operations electrify
rapidly, and heavy‐duty vehicles including medium and heavy trucks follow suit on a longer

timescale. Biofuels are blended into other fuels in growing quantities in road transport
through to 2030, but are increasingly used instead in aviation and shipping beyond 2030 aselectrification becomes the most cost‐effective option for decarbonising the road sector.
Direct use of hydrogen, and of low‐emissions synthetic fuels such as synthetic kerosene andammonia, increases rapidly to meet demand in long‐distance modes of transport, mainly
aviation and shipping (Figure 3.14). Despite the high costs of these energy carriers and theconsiderable energy losses incurred in their production, hydrogen and low‐emissions
synthetic fuels play a key role in reducing carbon emissions from long‐distance modes thanks
to their high energy density.
Globally road vehicles emitted 5.9 Gt CO2 in 2021 – more than the entire energy‐related
carbon emissions of North America. Oil products accounted for around 90% of road transportenergy consumption, with biofuels and natural gas accounting for almost all remaining
demand. The share of electricity in road transport demand in 2021 was less than 1%.
In the NZE Scenario, the share of oil products in road transport demand decreases to 75% by2030, with electricity accounting for 10%, biofuels for more than 10%, and hydrogen,hydrogen‐based fuels and natural gas for the rest. New sales of internal combustion engine(ICE) cars, vans, two/three‐wheelers and urban buses come to an end by 2035, intercity
buses by 2040, and new sales of ICE heavy‐duty vehicles (heavy and medium trucks) ceaseby 2045. EVs offer the most cost‐effective low‐emissions technology in most segments inboth the short and long term, and they come to dominate in road transport. By 2030, 60% of
all new car sales are electric, but ICE vehicles still account for nearly 80% of the stock of cars,
meaning that fuel economy improvements and behavioural change remain criticallyimportant. The electrification of heavy‐duty vehicles proceeds at a slower pace, with EVs
accounting for almost 30% of sales by 2030. Hydrogen also plays a role, mainly for long‐
distance heavy freight trucks. Emerging market and developing economies initially focus on
the electrification of two/three‐wheelers and urban buses.
The rapid rollout of recharging infrastructure is essential to underpin the shift to EVs. In the
NZE Scenario, around USD 35 billion of investment goes to support public EV chargers every
year on average from 2022‐30, and efforts are also made to scale up the availability ofhydrogen refuelling stations in locations that are suitable for long‐distance trucking such asindustrial hubs. This requires tackling the financing gaps that exist in emerging market anddeveloping economies for the deployment of charging infrastructure.

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By 2050, the road transport sector is almost entirely decarbonised. Residual emissions
amount to around 200 Mt CO2 (3% of 2021 emissions) and are all attributable to oil productconsumption in the remaining ICE heavy trucks on the road. Electricity is the main fuel forroad transport, accounting for over two‐thirds of total energy consumption and nearly 90%
of total road activity by 2050. Hydrogen also plays an important part, and is responsible foralmost one‐quarter of energy consumption in the sector.

Aviation7 is almost entirely reliant on oil today. As pandemic‐related travel restrictions werelifted in most regions, surging demand for flights led CO2 emissions from aviation to rise by
over 20% year‐on‐year to 700 Mt in 2021, although they remained below 2019 levels.
The NZE Scenario sees lower growth of aviation activity (expressed in revenue‐passenger
kilometres) than the STEPS as policies to promote behavioural changes lead to shifts to high‐speed rail and to a reduction in business trips (see section 3.8). Growth in aviation activity is
kept down to around 2.5% per year to 2050 relative to 2019, and emissions fall to 200 Mt by
then. Global use of jet kerosene decreases to around 90% of total aviation energy demandby 2030 and to around 20% by 2050. The use of sustainable aviation fuel (SAF) starts toaccelerate in the 2030s. By 2030, over 10% of fuel consumption in aviation is SAF, most ofwhich is biojet kerosene. By 2050, biojet kerosene meets almost 45% of demand andsynthetic hydrogen‐based fuels meet a further 25%. Investments in SAF production facilities
scale up rapidly with support from governments in the form of blending mandates, low‐emissions fuel standards and tax credits, while prioritising sustainability criteria.

3

The NZE Scenario sees commercialisation of hydrogen aircraft from 2035. By 2050, half of all
regional and narrow body aircraft sold are hydrogen aircraft mainly serving short‐ to mid‐haul routes, and direct use of hydrogen accounts for 8% of total energy demand in aviation.
Growing use of hydrogen powered aircraft depends on technological advancements instorage tanks, on‐board fuel delivery systems, and combustion engines or fuel cell
technologies, as well as on investments in airport infrastructure for the storage and delivery
of hydrogen.
The NZE Scenario also sees a role for battery electric aircraft. Current battery density andweight significantly restrict the range and size of such aircraft. However, advances in battery
technologies are expected to open regional flights to battery electric aircraft. They meet 3%of aviation energy demand by 2050 in the NZE Scenario.
Maritime shipping is heavily reliant on oil, which meets virtually all its energy demand today.
In the NZE Scenario, the fuel mix for the sub‐sector undergoes a major transformation, andits global CO2 emissions fall from 840 Mt CO2 today to 110 Mt CO2 by 2050. A number offuels contribute to this decarbonisation progress. By 2050, ammonia meets around 45% of
demand for shipping fuel. Bioenergy and hydrogen each meet a further 20% of demand, withthe use of hydrogen in particular focussed on short‐ to mid‐range operations. Electricity plays
a minor role focussed on meeting demand from small ships and cruise ferries used for short‐
distance operations.
Ships have a lifetime of 20‐35 years, which inhibits the uptake of new low‐emissions
technologies and contributes to oil still constituting almost 15% of shipping fuel demand by
2050. Although it is possible to retrofit ships to run on low‐emissions hydrogen‐based fuels,
Aviation in this report includes both domestic and international flights. While the focus here is on commercial
passenger aviation, other dedicated freight and general (military and private) aviation, which collectively
account for more than 10% of fuel use and emissions, are also included in the energy and emissions
accounting.

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7

this is complicated by the need for major investments and co‐ordinated efforts among fuelsuppliers, ports, shipbuilders and shippers, especially when it comes to large transoceanic
vessels. Efficiency measures such as wind kites and rotor sails also have an important role toplay, since they help to reduce the need for fuel of any kind.
Rail is the most energy‐efficient and least emissions‐intensive mode of passenger transport,
even though oil currently meets over half of all rail energy needs, and two‐thirds of energy
needs in freight rail. In the NZE Scenario, passenger rail demand expands significantly, inparticular for urban metro rail and high‐speed rail travel which mainly relies on electricity.
Passenger activity on high‐speed rail increases more than three‐times by 2030 as travel
demand is increasingly shifted from short‐haul flights to rail as a lower emissions option. Railfreight demand also increases significantly. Despite this, global CO2 emissions from rail fallfrom 90 Mt CO2 in 2021 to almost zero by 2050 as all new tracks on high throughput corridors
are electrified from now on and as electricity’s share of rail energy demand rises from around
45% today to 65% by 2030, and almost 90% by 2050. Biodiesel accounts for a further 5% of
demand in 2050, and hydrogen for an additional 2%, while conventional diesel use is reduced
to only 3%. Fuel cell trains could potentially serve long‐distance rail travel without refuelling,
but are currently at a demonstration stage.

3.7

Buildings

The buildings sector accounted for 132 EJ of energy consumption in 2021, or 30% of total
global final energy consumption. The sector’s 3 Gt CO2 emissions accounted for 15% of total
emissions from end‐use sectors in 2021, but this share doubles if indirect emissions fromelectricity and heat production are included. Despite a gradual shift away from fossil fuels,
direct emissions from the buildings sector have risen by 0.5% per year since 2010, driven byrising demand for energy services.

At the same time, expanding the role of electricity in cooking, water heating and spaceheating is key to the decarbonisation of the buildings sector. Improving energy efficiency andincreasing electrification and renewables use in buildings, however, is complicated by the
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Activity levels in the buildings sector continue to rise. Access to electricity and clean cooking
is improving in emerging market and developing economies, albeit too slowly to meet SDG
goals and with recent reversals (see Chapter 5, section 5.6), and the ownership and use of
appliances is expanding as incomes rise and populations expand. Floor area in the buildings
sector worldwide is expected to increase 20% between 2021 and 2030, of which 80% is inemerging market and developing economies. The number of air conditioners in the global
stock is set to increase by 50% by 2030, compounded by the increasing effects of climatechange. In emerging market and developing economies alone, 590 million air conditioners
are added by 2030 in the NZE Scenario. Given that buildings are responsible for more thanhalf of total electricity consumption already today, tempering the impact of increasing
equipment and appliance use on future electricity demand growth is of major importance tothe decarbonisation of electricity generation.

long lifetimes of buildings and related infrastructure such as heat and electricity networks.
Much also depends on the decisions of individual consumers.
In the NZE Scenario, despite the projected growth in service demand, direct CO2 emissions
from the buildings sector decline by 45% to 2030 and more than 98% by 2050 (Figure 3.15).
Taken together, energy efficiency, electrification and behavioural change provide 80% of theemissions reductions in the buildings sector by 2030, and 70% by 2050.
Figure 3.15 ⊳ Emissions reductions and key milestones in the buildings sector in3

Gt CO2the NZE Scenario relative to the STEPS, 2020-2050
2025

2030

No new sales offossil fuel boilers

100% of sales forlighting are LEDs

2035

2045

Most appliances andcooling systems soldare best in class

50% of heating
demand met byheat pumps

3.0
2.5

STEPS

Other
Desalination

2.0
Cooking

1.5

Water heating

1.0
Space heating

0.5
NZE

2020

2025

2030

34% electricity in TFC

40% electricity in TFC

90% access toelectricity

Universal
energy access

2035

2040
50% of existingbuildings retrofitted
to zero carbon‐readylevels2045

2050

Natural gas use
reduced by 98%

All new buildings are
zero carbon‐ready

IEA. CC BY 4.0.

Space heating delivers 50% of emissions reductions in buildings, driven by

Notes: TFC = total final consumption; LEDs = light‐emitting diodes. A zero carbon‐ready building is highly
energy efficient and uses either renewable energy directly or an energy supply that will be fully decarbonisedby 2050 in the NZE Scenario (such as electricity or district heat). By 2025 in the NZE Scenario, any gas boilers
that are sold are compatible with 100% low‐emissions gases and in areas where fuel supply will be completely
decarbonised before 2050.

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electrification and demand reductions from efficiency and behavioural changes

Energy efficiency is the first pillar of the transition in the buildings sector; in the NZE Scenario
it brings substantial benefits for affordability and consumer welfare. There is enormous
scope for efficiency gains from improved envelopes for new and existing buildings, heatpumps, energy‐efficient appliances, and energy and materials‐efficient building design. Mostof these technologies are available on the market, and some are already economicallycompetitive, or on course to become competitive as technology costs decline.
In the NZE Scenario, efficiency measures are front‐loaded, playing their largest role in curbing
energy demand and emissions in the period to 2030. In the NZE Scenario, the energy intensityof the buildings sector needs to drop almost ten‐times more quickly over the current decadethan it did in the past. This means the energy consumed per square metre in 2030 is 45% lessthan in 2021.
The lifetime of the stock of buildings is typically very long, and the stock is expanding rapidly,
particularly in emerging market and developing economies. In advanced economies, almost
three‐quarters of the buildings that will be in use in 2050 have already been built. In emerging
market and developing economies the equivalent figure is much lower: 13% of the 2050
buildings stock will be constructed between today and 2030, and almost 40% in the 2030s
and 2040s. Therefore, the NZE Scenario requires actions to simultaneously address emissions
from both the existing and new buildings stock.
For all new buildings, mandatory zero carbon‐ready building energy codes are introduced in
all regions in the NZE Scenario no later than 2030 to avoid locked in emissions. For existingbuildings, retrofit rates increase from less than 1% per year today to nearly 2.5% per year by2030 in advanced economies, which means that around 10 million dwellings are retrofitted
every year. This number rises to 20 million dwellings per year in emerging market anddeveloping economies.
Strong retrofit rates result in 20% of the existing building stock being zero carbon‐ready assoon as 2030, and more than 85% by 2050.8 To achieve savings at the lowest cost and tominimise disruption, retrofits should be comprehensive. Deep renovations can be delivered
through policies that require a gradual increase in renovation rates, starting with the worst
performing buildings. Building envelope improvements in existing and new buildings accountfor the majority of heating and cooling energy intensity reductions in the NZE Scenario.

8

A zero carbon‐ready building is highly energy efficient and either uses renewable energy directly or an energy
supply that can be fully decarbonised, such as electricity or district heat.

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Energy demand in the sector depends on the efficiency of energy consuming equipment, as
well as on the efficiency of the building envelope. In the NZE Scenario, over 80% of all
appliances and air conditioners sold are the most efficient models by 2025 in advanced
economies, and by the mid‐2030s worldwide. Nonetheless, the upfront costs of key
technologies to reduce direct emissions and improve energy efficiency, such as heat pumps,
insulation and retrofits, create economic barriers to their adoption.

Behavioural changes are also important in the NZE Scenario, reducing energy demand by 8 EJ
in 2030 through actions such as making temperature adjustments to space heating andcooling. The ability of behavioural changes to achieve demand reductions rapidly and at no
cost means that they can help provide an emergency response to the current energy crisis in
the short term and facilitate the net zero emissions transition in the long term.
Electrification and switching to low‐emissions fuels is the second pillar of the transition in
the buildings sector. Today electricity makes up 34% of total final energy consumption in thebuildings sector, making it the largest fuel in its energy mix, followed by natural gas with 23%.
All end‐uses dominated today by fossil fuels are increasingly electrified in the NZE Scenario.
Liquefied petroleum gas (LPG) still plays a limited role for cooking in some emerging market
and developing economies in 2050, but 95% of cooking energy needs are met by electricity
and modern bioenergy by then. Coal, oil and gas cease to be used for space and water heating
almost entirely by 2050. Some 30% of homes are heated by natural gas today, but this drops
to almost zero.

3

Figure 3.16 ⊳ Total final consumption in buildings by source and end-use in the
NZE Scenario, 2021-2050

EJ

Space heating

Cooking

Water heating

Other

2021 2030 2050

2021 2030 2050

2021 2030 2050

80
60
40
20

2021 2030 2050
Coal
Electricity

Natural gas
Hydrogen

Oil
District heat

Traditional use of biomass
Renewables
STEPS
IEA. CC BY 4.0.

Efficiency, fuel switching and behavioural change reduce energy consumption in buildings
significantly compared to the STEPS, and the mix shifts to electricity and renewables

No new fossil fuel boilers are sold from 2025 in the NZE Scenario, except where they are to
be operated with 100% hydrogen or synthetic hydrogen‐based fuels, or are to be connected
to fully decarbonised gas networks using low‐emissions gases such as biomethane. Hybrid
heat pumps, combining a standard air‐to‐water heat pump with a high efficiency gas boiler,
play a limited role in the short term: in the longer term, they are used only where natural gas
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Note: Other includes energy demand from appliances, lighting, space cooling and desalination. STEPS = Stated
Policies Scenario.

networks are maintained and use low‐emissions gases. Electricity becomes the principal
source of energy for decarbonised heating: homes using electricity for heating rise from 20%of the total today to 30% in 2030, and more than 50% in 2050, with high efficiency electricheat pumps becoming the primary technology choice.9 Worldwide, the installation of heatpumps increases from 1 million per month today to around 8 million per month by 2030, and14 million per month by 2050. Overall, the share of electricity in the buildings sector energy
mix reaches almost 50% by 2030 and 67% by 2050, making it the most electrified of all end‐
use sectors.
Renewables used in buildings are mainly for water and space heating in the NZE Scenario,
with solar thermal seeing the biggest increase. Renewables are also used for cooking, withvarious forms of modern bioenergy meeting 40% of cooking energy demand in 2050
(Figure 3.16). Overall, the direct use of renewable energy rises from about 6% of buildings
energy demand in 2021 to almost 30% in 2050, with about two‐thirds of the increase taking
the form of solar thermal and geothermal energy. District heating networks and low‐emissions gases such as biomethane, hydrogen, and synthetic hydrogen‐based fuels play abigger role in 2050 in regions with high heating needs, dense urban populations and existing
natural gas or district heat networks.
Box 3.3 ⊳Clean cooking access in the NZE Scenario

In 2021, 2.4 billion people worldwide had no access to clean cooking technologies, downfrom 2.9 billion in 2010. The net decrease was mainly due to rapid improvements indeveloping Asia (in particular in China 10 , India and Indonesia). These outweighed anincrease of 200 million in the number of people without access in sub‐Saharan Africa
during the same period. Improvements have slowed significantly since 2019 because of
the Covid‐19 pandemic and the current energy crisis (see Chapter 5).
In emerging market and developing economies, the rate of improvement in access wason average 1.7 percentage points each year between 2015 and 2019. In the NZE Scenario,
this rate improves by 2.7‐times on average between 2022 and 2030 (Figure 3.17).
However, there are major regional divergences: to make progress as rapidly as projectedin the NZE Scenario, sub‐Saharan Africa needs to improve its historical rate of progressby 15‐times and in developing Asia by only 1.5‐times, mainly reflecting strong
improvements already seen in China, Indonesia and India.
The NZE Scenario provides a pathway to reach the SDG 7.1 goals, but it requires
determined action be taken quickly. Improved biomass cookstoves (ICS) provide accessto 35% of those who gain it in the NZE Scenario and play a major role in ensuring that the9

The IEA will release a report on heat pumps and their role in energy security and transitions in November
2022.
The World Health Organisation recently published revised historical data for clean cooking access in China
based on information from recent surveys (WHO, 2022). This suggests that progress in China has been fasterthan estimated in previous reports.

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10

poorest (mainly in rural areas) are able to make use of an affordable and readily available
fuel. Liquefied petroleum gas provides access to almost 40% of those that gain it with therest of the gap being closed by electricity (14%), biodigesters (8%) and ethanol (3%).
Figure 3.17 ⊳ Annual improvement in access rate to clean cooking and bytechnology in the NZE Scenario, 2015-2030
People gaining accessby technology 2022‐30
2.6 billion

Annual improvementin access rate
EMDE
Sub‐Saharan Africa

3

ICS
35%

Other Asia
Other Southeast Asia
Ethanol
3%

India
China
Indonesia
5%
2015‐1910%2022‐30

Biogas8%
Electricity
14%

LPG
40%

IEA. CC BY 4.0.

Clean cooking access in emerging market and developing economies needs toimprove 2.7-times faster between 2022 and 2030 than on average in recent years
Notes: EMDE = emerging market and developing economies; ICS = improved biomass cook stoves (ISOTier > 1); LPG = liquefied petroleum gas.

Key themes
3.8

Avoiding growth in energy demand

Overview of measures

In industry, around half of the reductions in energy use in 2030 are due to measures which
avoid demand in the NZE Scenario compared to the STEPS, such as gains in materials
efficiency. Most of the remaining reductions come from energy efficiency measures
supported by a mixture of technical innovation, standards and regulations, including a
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The decarbonisation pathway in the NZE Scenario cannot be achieved without the rapid andlarge‐scale adoption of measures that limit growth in energy demand. Absent such measures,
deployment of clean energy sources would be outpaced by fast rising demand for energy
services. Measures include energy efficiency, fuel switching (notably electrification) andbehavioural changes, and together they cut demand by 110 EJ relative to the STEPS in 2030
(Figure 3.18). They ensure that the energy intensity of GDP falls by 4% per year on averageover the next eight years. Reductions in energy demand also play an important role in energy
security and affordability.

systematic preference for best‐in‐class electric motors and other equipment, and digitalenergy management systems. There is also a role for changes in behaviour by consumers to
consume less and recycle more, thereby reducing demand for industrial products, especiallyprimary steel and plastics.
Figure 3.18 ⊳ Total final consumption in the STEPS and demand avoided bymeasure in the NZE Scenario

EJ

Industry

Buildings

Transport

200
150
100
50

2021
2030
2050 2021
2030
TFC: STEPS
NZE
Avoided due to: Energy efficiency Fuel switching

2050

2021

2030

Avoided demand

2050
Behaviour
IEA. CC BY 4.0.

Energy efficiency, behavioural changes and other mitigation measures in the NZE Scenario
cut total final energy demand by almost 40% compared to the STEPS in 2050
Notes: Fuel switching includes electrification. Avoided demand includes materials efficiency gains, circular
economy effects, and structural and economic effects, such as the response of consumers to higher prices.

In transport, behavioural changes have a bigger impact than any other measure in 2030,
accounting for one‐third of the difference in energy demand between the STEPS and the NZE
Scenario. These changes are particularly important in aviation, where there is little technicalpotential for fuel switching and limited room in the near term for energy efficiency gains
beyond those in the STEPS. For road transport, fuel switching measures (mainly to EVs) andenergy efficiency improvements underpinned by stringent fuel economy standards play animportant role to curb growth in energy demand in 2030. But energy savings fromelectrification really come into their own after 2030, and there is a more than fourfold
improvement in the average fuel economy of a car on the road in 2050 relative to today.

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In buildings, energy efficiency measures in the NZE Scenario avoid around one‐quarter of theexcess energy demand in the STEPS in 2030 and just over one‐half of this in 2050. Fuelswitching, largely from fossil fuel space heating to electric heat pumps, shaves a further one‐
fifth from this energy demand gap. The remainder is avoided by behavioural changes thatmoderate demand, notably for space heating and air conditioning.

Focus on behavioural changes
The NZE Scenario incorporates a number of behavioural changes in the way consumers use
energy services. 11 In part these function in the same way as energy efficiency and othertechnical options to reduce energy demand. Yet there are also important distinctions.
Behavioural changes can tackle emissions from the existing stock of emissions‐intensive
assets without the need to wait for stock turnover and the advance of clean energy
technologies. For example, while over 60% of cars sold in the NZE Scenario are EVs in2030, almost 80% of cars on the road are still ICE vehicles by that time and many of themwill continue to be driven for years to come. By contrast, behavioural changes that leadpeople to drive less or in a more fuel‐efficient manner, e.g. more slowly, cut emissions
from all vehicles without any transitional period. For that reason behavioural changes
can also provide rapid responses when necessary to energy security concerns (IEA,
2022b).

3

In some areas such as aviation, technical options are unlikely to exist at the scalerequired to reduce emissions to net zero by 2050. Behavioural changes which curb
activity therefore have a critical part to play in reducing demand and minimising theneed to rely on negative emissions technologies, which may be costly or fail tomaterialise at the requisite scale. In 2050, the behavioural changes in the NZE Scenario
reduce the requirement for negative emissions technologies by around one‐third, or
820 Mt CO2.

Figure 3.19 ⊳ CO2 emissions reductions due to behavioural changes
in the NZE Scenario
Reductions by measure type, 2021‐50

Discretionary25%
Of which require
infrastructure

Reductions by measure, 2030
1 152 Mt CO₂

Of which do
not require
infrastructure

Influenced or
mandated by policy 75%

Transport 760 Mt CO₂
Fuel efficient driving
Low car cities
Cleaner cars
Work from home
Reduced flying
Buildings 390 Mt CO₂
Space heating
Space cooling
Eco‐household
Industry 2 Mt CO₂
Reuse and recycling
IEA. CC BY 4.0.

Behavioural changes cut CO2 emissions, but most depend on targeted policies
and some require new infrastructure

Behavioural changes are active changes by end‐users of energy‐related services that reduce excessive or
wasteful energy consumption. This means, for example, that the purchase of clean energy technologies, suchas an EV, is not considered as a behavioural change.

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11

By 2030, behavioural changes in the NZE Scenario reduce CO2 emissions by around 1 150 Mt(or 9% of total emissions reductions) compared to levels in the STEPS (Figure 3.19). Between
2021‐50 around three‐quarters of cumulative emissions reductions from behaviouralchanges stem from measures directly shaped or mandated by government policies, such ascongestion charging or speed limit reductions; around one‐half of these require the supportof infrastructure, such as high‐speed rail networks. The remaining reductions are associatedwith discretionary behavioural changes which could be encouraged by information andawareness campaigns, such as product labelling and home energy consumption reports.
Buildings account for just over one‐third of the total CO2 emissions reductions frombehavioural changes in 2030. For example, adjusting thermostats to 19‐20 °C in winter andair conditioning to a maximum of 24 °C in summer reduces CO2 emissions by almost 300 Mt(when including the indirect CO2 emissions associated with electricity generation and heatproduction).
Transport accounts for just under two‐thirds of the reductions in CO2 emissions frombehavioural changes in 2030 in the NZE Scenario. For road transport, measures to promote
fuel‐efficient driving, including reducing speed limits on motorways to 100 kilometres perhour (km/hour) and eco‐driving,12 reduce CO2 emissions by 170 Mt in 2030. Other measuresencourage working from home three days per week in jobs where it is possible to do so andincreased carpooling.13 Action is taken to phase out the use of ICE cars in large city centres,
and reduce speed limits to 20 km/hour to discourage car use and make it easier and moreenjoyable to cycle or walk. A shift towards cleaner cars is brought about by corporate targets
to end the use of ICE cars in commercial ride‐hailing fleets, e.g. Uber, and by policies todiscourage ownership of sport utility vehicles (SUV) including by banning their use in city
centres.
In aviation, a combination of frequent flyer levies, a 50% reduction in business‐related long‐
haul trips in favour of teleconferencing and a shift to high‐speed rail for regional flights cuts
CO2 emissions by 110 Mt in 2030 in the NZE Scenario relative to the level in STEPS.

S P O T L I G H T
Future of flying in the NZE Scenario

12Note: Eco‐driving involves pre‐emptive stopping and starting and early up‐shifting.

13

We estimate that around one‐fifth of jobs worldwide can be done at home (IEA, 2020).

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Technical options to decarbonise aviation are deployed at unprecedented speed in the
NZE Scenario. For example, the share of sustainable aviation fuels rises to over 10% in
2030 from next to nothing today, reaching 70% in 2050, and the energy efficiency of new
aircraft improves by 2% each year on average to 2050. Despite these efforts, rapid
demand growth means that aviation would be one of the largest emitters of residual CO2
in 2050 absent additional measures to limit demand growth (Figure 3.20). As a result of

the use of cleaner technologies coupled with these additional measures, demand in
emerging market and developing economies increases by 3.5% per year on average
between 2019‐50 in the NZE Scenario (compared with 4.1% in the STEPS), and inadvanced economies by 1.1% per year (compared with 2.2% in the STEPS).
Figure 3.20 ⊳ Aviation activity growth per capita and emissions reductions

3

RPK per capita
Advanced economies

2

1

Mt CO2

Index (Advanced economies 2015 = 1)

due to behavioural changes in the STEPS and NZE Scenario
300

Avoided due tobehaviour
High‐speed
rail
Less businesstravelFrequent
flyer levy

200

100

Emerging market anddeveloping economies

2015

NZE

2050
STEPS

NZE

3

CO2 Emissions in 2050

Advanced EMDE
economies
IEA. CC BY 4.0.

Policies are introduced in the NZE Scenario to curb the growth in aviation demand seenin the STEPS. Without these, emissions from aviation would be twice as high in 2050
Notes: RPK = revenue passenger kilometres, i.e. kilometres travelled by paying customers.

Frequent flyers. There are very large variations in aviation demand between
countries and income groups. It is estimated that 1% of the global populationaccounted for over half of all emissions from commercial aviation in 2018 (Gösslingand Humpe, 2020). Our new analysis indicates that around 90% of the global
population flies only once per year or not at all, whereas around 6% fly more than
twice per year and just 1% fly more than five‐times per year. Frequent flyer levies
aim to reduce aviation demand in an equitable way (Büchs and Mattioli, 2022). They
work by progressively taxing frequent flying, thereby curbing overall demand, while
not making aviation unaffordable for the less well‐off. A well designed levy could
reduce aviation demand from the wealthiest 20% of the population by around 30%,
while having little impact on those who fly once or twice a year (Chapman et al.,2021). Our analysis shows that this would reduce demand in 2050 by around 17% in
advanced economies and 6% in emerging market and developing economies. In the
NZE Scenario, frequent flyer levies reduce CO2 emissions by around 90 Mt in 2050.

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A number of levers mitigate demand growth in the NZE Scenario:

Business trips. Based on analysis of passenger survey data, we estimate that around
20% of air travel in advanced economies is for business purposes. This rises toaround 30% in emerging market and developing economies. In response to the
Covid‐19 pandemic, virtual business interactions have become more common, andmany companies have invested heavily in enhancing the experience of remotemeetings. In the NZE Scenario, teleconferencing substitutes for around one‐in‐twolong‐haul business trips in 2050, cutting CO2 emissions by more than 100 Mt.



High‐speed rail. The opportunity to take high‐speed rail instead of flying varies
strongly by region.14 Globally, in the NZE Scenario, sustained investment in new high‐speed rail infrastructure combined with existing tracks enables around 17% of flightsthat serve routes shorter than 800 km to be shifted by 2050, saving around
30 Mt CO2. Sustained investment in new high‐speed rail infrastructure is critical tounlock the potential for rail to displace regional flights where possible. Some of theadditional funding required to build this infrastructure could come from reductionsin the funding needed for other infrastructure development, such as airport capacity
expansions in advanced economies.

Many of the behavioural changes in the NZE Scenario target wasteful or excessive energy
consumption, predominantly in wealthier parts of the world. Their main purpose is to reduce
emissions, but some also act to reduce global inequalities in per capita energy consumption
and CO2 emissions, making the clean energy transition more equitable.
Policies that discourage car use in cities are one example. Such policies have an impact on
private car ownership levels, particularly in wealthy households that own multiple cars.15 In
the NZE Scenario, car sales are around one‐quarter above 2021 levels in 2030, but are around
10% lower than in the STEPS in that year (Figure 3.21).
Policies that discourage ownership and use of SUVs is another example, and with a starker
effect. Almost half of cars sold today are SUVs, and this rises to 55% in the STEPS by 2030.
SUV ownership is highly concentrated: in 2021, almost five‐times more SUVs were sold per
capita in advanced economies than in emerging market and developing economies. In the
NZE Scenario, the growing trend in SUV sales reverses and their market share falls to around
35% in 2030 and around 25% by 2050. Because SUVs are around one‐quarter less fuelefficient than a standard car, the reduction in their popularity saves almost 60 Mt CO2 in 2030
in the NZE Scenario. About 95% of the savings are associated with reduced direct emissions(tailpipe), with the remainder from reduced emissions in industry due to a drop in demand
for steel. The benefits of discouraging SUV sales remain even as car fleets electrify in the NZE
14
Air travel is assumed to be substituted by high‐speed rail on existing or potential routes where trains canprovide a similar travel time, and when demand is sufficiently large to enable economically viable operation,
while new rail routes avoid water bodies and tunnelling through elevated terrains (IEA, 2021).

Studies indicate that the provision of good public transport networks and access to ride‐hailing services andshared mobility schemes can reduce ownership levels by 35%, with the biggest impacts on the ownership ofmultiple cars by the same household (IEA, 2021).

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15

Scenario, not least because a stronger preference for smaller and lighter vehicles reduces
the need for critical minerals for batteries, easing the burden on supply chains as they scale
up to meet rapidly increasing EV demand (see section 3.10).
Figure 3.21 ⊳ Energy consumption per capita in the NZE Scenario andcar sales and SUV share in the STEPS and NZE Scenario, 2030
Energy consumption by sector in 2030 in NZE

3Aviation
10 EJ
Cars
Buildings

0

5

10

NZE
No behavioural changes

15

60

80

40%

40

40

20%

20

Car sales

Mt CO260%

STEPS NZE
2030
SUV share (right axis)

30
35
GJ per capita

Emissions reductions due to lower SUV sales

120

2021

25

Advanced economies
Emerging market and developing economies

Global car sales and SUV share
Million units

20

Avoided steel
production
Reduced tailpipe
emissions

NZE
2030
IEA. CC BY 4.0.

Behavioural changes in the NZE reduce emissions and make per capita energy
consumption more equitable by tackling excessive energy consumption such as SUVs

The behavioural changes in the NZE Scenario reflect regional differences in social norms andcultural values, as well as differences in geography, climate, urbanisation and the ability ofexisting infrastructure to support the changes. However, the speed and scale of behaviouralchanges is arguably more uncertain than that which characterises some other parts of theclean energy transition (for instance the deployment of solar PV, for which a clear trend has
emerged in recent years). Consumer choices and habits often depend on trends that are
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Note: GJ = gigajoule; SUV = sport utility vehicle.

hard to anticipate and can be subject to the influence of companies via marketing andadvertising. In the NZE Scenario, governments introduce bold and consistent policies toencourage and make commercially viable those corporate strategies and business models
which divert consumer demand away from wasteful or high‐emitting consumption towards
sustainable and low‐emissions energy‐related goods and services, for example by mandating
the phasing out of frequent flyer programmes and promoting the implementation of similar
schemes for rail travel. There would also be a role for policies to tackle activities linked toexcessive and highly unequitable emissions, such as the use of private jets, which emit up totwenty‐times more CO2 than an average commercial flight for every passenger‐kilometre
flown (Mumbower and Sobieralski, 2022; Gössling and Humpe, 2020).
Box 3.4 ⊳Keeping the temperature rise below 1.5 °C: Role of diets

The NZE Scenario achieves net zero CO2 emissions for the energy sector in 2050 without
relying on offsets from other sectors. However, as about one‐quarter of today’s GHG
emissions originate from outside the energy sector, mainly from agriculture, forestry andother land use (AFOLU), cutting these other emissions quickly is essential to have areasonable chance of limiting the temperature rise to below 1.5 °C (IPCC, 2021).
Around one‐third of all food produced is currently wasted rather than eaten (WFP, 2020).
It is not realistic to think that all food waste could be eliminated, but a significant
reduction in food waste nevertheless could significantly reduce emissions fromagriculture production. So could a move to healthier and more sustainable diets involving
less meat, the global production of which has more than tripled since 1961, reachingaround 340 Mt in 2018 (Ritchie and Roser, 2017). Plant‐based foods tend to have a muchsmaller emissions footprint than meat: for example, the volume of GHG released pergramme of protein from peas is on average around 17‐times less than for a gramme ofprotein from pork, and 110‐times less than for beef (Ritchie and Roser, 2020). In
collaboration with the International Institute for Applied Systems Analysis (IIASA), we
have explored the possible consequences for GHG emissions of reducing food waste andshifting a portion of protein intake. We estimate that, if sustainable and healthy diets
were adopted worldwide16 and food waste halved, GHG emissions would be reduced byaround 700 million tonnes of carbon‐dioxide equivalent (Mt CO2‐eq) annually. Around
90% of this reduction would come from lower nitrous oxide and methane emissions inagriculture, with the remainder from reduced deforestation and the planting of newforests on agricultural land no longer needed for livestock feed production. About
240 million hectares (one‐third the size of Australia) of pasture and cropland would befreed up, and fertiliser demand would be around one‐fifth lower in 2050 than would
otherwise be the case.

This implies that animal calorie intake would not exceed 430 kilocalories per capita per day by 2030
following US Department of Agriculture recommendations for a healthy diet and that consumption inhouseholds with the highest levels of per capita consumption today would be reduced over time. Local societal
and cultural preferences would determine what constitutes a so‐called sustainable and healthy diet indifferent parts of the world.

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3.9

What are the public and private investments needed to 2030?

The NZE Scenario requires a large increase in investment in clean energy. Energy investment
accounted for just over 2% of global GDP annually between 2017 and 2021, and this rises tonearly 4% by 2030 in the NZE Scenario. This growth in investment is driven primarily by
spending on clean energy technologies, which increases more than a factor of three over thisperiod (Figure 3.22). Recent trends do not reflect the need for an increase of this magnitude:
clean energy investment is expected to reach a record high in 2022 but this was only 25%
larger than the 2017‐21 average (IEA, 2022c).

3

Figure 3.22 ⊳ Global average annual energy investment by sector
and technology in the NZE Scenario
Fuels
Oil

2017‐21Natural gas

2030

Coal

2040

Low‐emissions fuels

2050
Electricity and heat

Fossil fuels without CCUS

2017‐21

Fossil fuels with CCUS

2030

Nuclear2040

Renewables

2050

Battery storage
Other

Infrastructure
2017‐21

Electricity grids

2030

EV chargers

2040

Hydrogen infrastructure

2050

Direct air capture
End‐use2017‐21

Renewables

2030

Hydrogen
Efficiency

2040

Electrification

2050

Fossil fuels with CCUS
0.5

1.0

1.5

2.0
2.5
Trillion USD (2021)

Investment increases rapidly in electricity, infrastructure and end-use sectors;
fossil fuel investments decrease and low-emissions fuel investments increase

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Declining fossil fuel demand can be met in the NZE Scenario through continued investment
in existing production assets without the need for any new long lead time projects. Annual
spending on fossil fuels falls from its current level of around USD 830 billion to around
USD 455 billion in 2030. This investment is needed to ensure that supply from existing fossil
fuel projects does not fall faster than the decline in demand, and to reduce the emissions
that occur along the supply chain. The rise in clean energy spending, including on low‐emissions fuels, means that the share of fossil fuels in total energy investment falls from its
current level of 35% to 10% in 2030.
Investment in low‐emissions fuels, including biofuels, low‐emissions hydrogen andhydrogen‐based fuels, increases from its current level of USD 18 billion to USD 235 billion in
2030. By 2050, low‐emissions fuels account for over 65% of total investment in fuels, up from
1% in recent years.
Investment in electricity and infrastructure more than doubles, while investment in end‐use
sectors increase more than fourfold to 2030 in the NZE Scenario. Electricity generation fromrenewables sees one of the largest increases, rising from USD 390 billion today to around
USD 1 300 billion by 2030. This level of spending in 2030 is equal to the highest level everspent on fossil fuel supply (USD 1.3 trillion spent on fossil fuels in 2014). In order to support
the increase in renewables deployment, spending on electricity grids increases from
USD 320 billion today to just over USD 740 billion in 2030. Spending on renewables for use
in buildings and industry increases nearly threefold to 2030.
Reaching net zero emissions requires an unprecedented acceleration in efficiency
improvements and a significant reduction in energy intensity. In the NZE Scenario, this isachieved through the rapid electrification of transport, heating, cooling and industrial
production and a massive wave of retrofits and spending on new energy‐efficient buildings.
As a result, the share of investment directed to energy efficiency and electrification moves
from 17% of the total today to 32% in 2030 and 40% in 2050.

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Investment trends vary significantly between countries and regions. The level of clean energy
investment is at present significantly lower in emerging market and developing economies
than it is in advanced economies. As a result, clean energy investment levels in emerging
market and developing economies see a nearly fourfold increase by 2030 in the NZE Scenario,
compared with a less than threefold increase in advanced economies (Figure 3.23). This
dramatic growth is necessary to support economic development and industrialisation as wellas provide access to electricity and clean cooking to the 774 million and 2.4 billion people
respectively that still lack it. Investment also peaks later in emerging market and developing
economies than in advanced economies as a result of the need to meet rising demand overa longer period.

Figure 3.23 ⊳ Energy investment trends by region in the NZE Scenario,
2017-2050

Billion USD (2021)

Advanced economies
3 000

Emerging markets anddeveloping economies
Other end‐use
Energy efficiency
Clean fuels
Networks and storage
Clean power
Fossil fuels

2 000

1 000

2017‐ 2030 2040 2050
2021

3

2017‐ 2030 2040 2050
2021
IEA. CC BY 4.0.

Clean energy investment increases four-times in emerging market and developing
economies by 2030 and less than three-times in advanced economies
Note: Other end‐use includes investment in electrification and direct use of renewables or low‐emissions
technologies in end‐use sectors.

Box 3.5 ⊳Sources of finance

Financing the USD 4.2 trillion of clean energy investment needed in the NZE Scenario in
2030 will involve redirecting existing capital from fossil fuels towards clean energy
technologies. However, that will not be enough on its own: there also needs to be a
substantial increase in the overall level of investment in energy.
Private sources contribute around USD 3 trillion to clean energy investment in 2030 in
the NZE Scenario (an over threefold increase from recent levels). This is mobilised bypublic policies that create incentives, set appropriate regulatory frameworks, and sendmarket signals that unlock new business models. Reducing risks for investors will beessential to ensure successful and affordable clean energy transitions.

Public spending currently plays a larger role in emerging market and developing
economies than elsewhere, accounting for nearly 60% of clean energy investment inrecent years. In the NZE Scenario, policy reforms that ensure a pipeline of bankable
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Public spending in clean energy technologies also rises, by slightly less than
USD 800 billion from recent levels by 2030. This is needed to boost the development of
new infrastructure projects, accelerate innovation in technologies that are in thedemonstration or prototype phase today, and provide de‐risking measures that mobilise
private capital and reduce financing costs.

projects, combined with an increase in targeted concessional public finance, help toreduce capital costs and incentivise private investors. By 2030, private capital accounts
for nearly 60% of clean energy spending – behind the level of around 85% seen inadvanced economies (Figure 3.24).
Figure 3.24 ⊳ Clean energy investment and sources of financein the NZE Scenario to 2030

Billion USD (2021)

Clean energy investment

Sources of finance

4 500

Investment
EMDE
AE
Sources of financePublic in EMDE
Private in EMDE
Public in AE
Private in AE

3 000

1 500

2017‐21 2025

2030

2017‐21 2025

2030
IEA. CC BY 4.0.

Reaching the NZE Scenario investment levels requires a larger contribution from private
finance than seen today, particularly in emerging market and developing economies
Note: AE = advanced economies, EMDE = emerging market and developing economies.

3.10

Can we ramp up low‐emissions technologies fast enough?

In this section we examine current and announced production capacity and project pipelines
for four clean energy technologies: batteries for transport, solar PV, electrolysers forhydrogen production, and CCUS. We also assess how projected production capacity andannounced project pipelines match with the levels of deployment required in the NZE
Scenario.

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The NZE Scenario requires an extraordinarily rapid deployment of clean energy technologies.
The huge increase in their deployment in this scenario calls for rapid growth in the
manufacturing of these technologies, as well as the production of essential material andmineral inputs. There are signs of recent progress, particularly in the case of thosetechnologies that benefit from mass manufacturing and economies of scale, and many
governments have committed during the current energy crisis to faster deployment of clean
energy technologies. There is much more to do to reach the scale of deployment required by
the NZE Scenario, however, and the next few years will be crucial.

Batteries
Automotive lithium‐ion battery demand was 340 gigawatt‐hours (GWh) in 2021—more than
twice the level in 2020. This increase was driven by the 120% increase in electric passenger
car registrations in 2021. Battery demand for other transport modes, including medium‐ andheavy‐duty trucks and two/three‐wheelers, rose by more than 50%, less than the increasefor passenger cars, but still huge.
China accounted for the largest share of global automotive battery demand in 2021 withalmost 200 GWh of battery demand, up 140% from 2020. The United States saw demand
more than double in 2021, albeit from a lower base. Demand growth in Europe was slightly
slower than last year, but it still increased more than 70%. Prices for batteries have fallen by
86% over the last decade thanks to economies of scale and continuous innovation
throughout the supply chain. Despite the recent commodity price surge, battery prices
declined further in 2021, with the Bloomberg New Energy Finance annual battery pricesurvey recording a 6% decrease from 2020. However, the impact of rising commodity prices
has yet to fully materialise. If metal prices remain at the levels seen from January to
September in 2022, then this could pose upward cost pressure on lithium‐ion battery packs
estimated at around 35% compared with 2021 levels.

3

Annual battery demand increases from 340 GWh in 2021 to 5 600 GWh by 2030 in the NZE
Scenario. Battery demand is driven by electric cars which account for three‐quarters of the
projected total by 2030. Achieving such production levels requires the additional output ofaround 150 gigafactories of 35 GWh annual production capacity operating at full capacity.
Figure 3.25 ⊳ Battery demand growth in transport in the NZE Scenario andGWhannounced battery manufacturing capacity expansion,
2010-2030
6 000
5 000

NZE transport
battery demand

4 000

Announced
battery capacity

3 000
2 000
1 000

2010

2015

2020

2025

2030
IEA. CC BY 4.0.

Sources: IEA analysis and Benchmark Mineral Intelligence (2022).

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Announced battery manufacturing capacities for 2030 are close to– but still insufficient – to meet the surge in battery demand by 2030

However, the industry is well placed to respond to this surge in demand, having undertaken
strategic early investments in battery plant capacity to prepare for projected demand growth(Figure 3.25). According to a recent study by Benchmark Mineral Intelligence, the battery
production capacity announced by private companies for EVs in 2030 amounts to over
4 700 GWh (Benchmark Mineral Intelligence, 2022). This would be about 15% lower than thelevel of battery demand seen in the NZE Scenario in 2030. Battery production capacity will
still be concentrated in China (70%), although more investments are now being planned inother regions, with a quarter of battery production capacity expected to be in Europe andthe United States by 2030.
While battery production factories can be built in under two years, raw material extraction
requires investment long before production reaches scale. Investments in new mines willneed to increase quickly and significantly if supply is to keep up with the rapid pace ofdemand growth (Box 3.6).
There is scope for new investment to be supplemented by additional steps to minimise
battery metals demand. Average battery sizes increased by 60% between 2015 and 2021,
and – if current trends continue – they may increase by a further 45% by 2030. In the NZE
Scenario, this trend is curbed by policies that discourage the production of vehicles withextremely large batteries, for example by linking purchasing incentives to vehicle weight.
Robust deployment of such policies reduces battery demand by around 7% by 2030 in the
NZE Scenario.
There is also scope for innovative battery chemistries to help minimise battery metals
demand. Innovations are developed and commercialised more rapidly in the NZE Scenario
than in the STEPS, and novel extraction and processing technologies are also brought
forward. Moreover, if the current context of high commodity prices focusses innovation
efforts on minimising the material footprint of batteries, preferences for battery chemistries
could adapt accordingly, moving away from high‐nickel cathode chemistries. In time, this
could result in a further decrease in demand for key battery metals of around one‐quartercompared to that in the NZE Scenario.

Electrolysers for hydrogen production

But now the industry is experiencing very dynamic growth (Figure 3.26). Global installed
electrolyser capacity increased 70% in 2021, albeit from a low base. Around 460 electrolyser
projects are currently under development. By the end of 2022, global installed capacity could
reach 1.4 gigawatts (GW). By 2030, current capacity and announced projects would result in
an installed capacity of around 134 GW. Taking into account more uncertain, very early stage
projects, global installed capacity could reach 240 GW by 2030.

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Almost all hydrogen today is produced from unabated fossil fuels. With global installedcapacity of 510 megawatt (MW), electrolysers supplied only 0.1% of a total hydrogen
demand of 94 Mt in 2021.

Figure 3.26 ⊳ Announced manufacturing capacity and installed electrolyser
capacity projected on the basis of manufacturing capacity
relative to the NZE Scenario, 2021-2030
Installed electrolyser capacity
GW

GW

Announced manufacturing capacity
120

800

90

600

60

400

30

200

2021 2022 2023 2024 2025 2030
EuropeNorth America
China
India
Oceania
ROW
Unspecified
Unspecified year

3

2021

PMO:

2025
NZE
All

2030
Project pipeline
No start years
IEA. CC BY 4.0.

Plans in the electrolyser industry are to ramp up hydrogen production very rapidly,
but additional efforts are needed to reach the NZE Scenario 2030 level
Notes: PMO = Potential manufacturing output. Unspecified region includes manufacturing facilities for which
the geographical location is unknown. Unspecified year includes manufacturing facilities for which the startyear is unknown.

The prospects for a rapid scaling up of deployment are also reflected in the size ofelectrolyser projects. While the average plant size of new electrolysers starting operationin 2021 was 5 MW, the average size of new plants could be around 260 MW in 2025 andover 1 GW by 2030. Of the projects under construction or development today, 22 (5%) areabove 1 GW.

Alongside the expanding pipeline of projects for electrolysers, electrolyser manufacturers
are already expanding their manufacturing capacity in anticipation of future growth. By 2030,
global manufacturing capacity could reach 65 GW annually, and that could rise to 105 GW
annually if plans with unknown start years are also taken into account. The cumulative
output of projected manufacturing capacity with known start years would reach 270 GW by
2030 – an enormous increase over the current level of around 7 GW – but only a little morethan one‐third of the requirement in the NZE Scenario for 2030. Assuming that
manufacturing capacity with an unknown start year becomes operational by 2030, theChapter 3 | An updated roadmap to Net Zero Emissions by 2050

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Global demand reaches 180 Mt hydrogen by 2030 and 475 Mt hydrogen by 2050 in the NZE
Scenario (of which 90 Mt in 2030 and 450 Mt in 2050 are low‐emissions). Electrolysers meeta third of this demand in 2030 and 70% in 2050. This requires installed electrolyser capacityof 720 GW by 2030 and 3 670 GW by 2050. Electricity generation capacity is also needed toprovide electricity for the electrolysers: over 1 000 GW of wind and solar PV are needed by2030 for electrolytic hydrogen production in the NZE Scenario.

cumulative output could reach 380 GW, which is still little more than half of 2030 needs in
the NZE Scenario.
Electrolysers also require minerals for their production, in particular nickel and platinumgroup metals, depending on the technology type. Key metal inputs for alkaline electrolysers
are nickel (800 kilogramme per megawatt [kg/MW]), steel (10 000 kg/MW) and aluminium(500 kg/MW). With current metal prices, this results in costs of around USD 25 per kilowatt(kW), representing around 3.5% of total alkaline electrolyser costs. For proton exchange
membrane (PEM) electrolysers, which use platinum (0.3 kg/MW) and iridium (0.7 kg/MW),the situation is somewhat different. Taking into account demands for steel, aluminium andtitanium, the metal costs for PEM electrolysers, at USD 125/kW, currently account for around
12% of total electrolyser equipment costs, largely due to the cost of platinum and iridium.
While it is hard to predict how future prices for these metals will evolve, efforts are underway
to reduce the requirement for platinum group metals in PEM electrolysers. A reduction of
specific iridium needs per MW by a factor of ten seems feasible in the next decade.

Solar PV
Solar PV provided over 3% of global electricity generation in 2021. Annual PV capacity
additions reached 150 GW, making 2021 another record year. Of this, 95% was in the formof crystalline silicon modules, while thin‐film PV technology accounted for the remainder.
Prices for PV modules have fallen by 80% over the last decade thanks to economies of scaleand continuous innovation throughout the supply chain. As a result, solar PV has become themost affordable electricity generation technology in many parts of the world. In 2021, theaverage selling price of modules increased for the first time – by around 20% compared with2020 – due to higher freight and commodity prices, in particular for polysilicon. Whilemodule prices remained at high levels in the first‐half of 2022, continuous innovation tofurther improve material and energy efficiency is expected to drive further cost reductions.
Raw materials account for 35‐50% of the total cost of a solar PV module. For example, forcrystalline silicon modules, silver and polysilicon together make up less than 5% of themodule weight, but represent nearly two‐thirds of material costs at 2021 prices. Material
intensity improvements have already been realised in the past. For example, the polysilicon
intensity for crystalline silicon modules was reduced by a factor of six between 2004 and2020; silver intensity fell by one‐third between 2009 and 2018. Further material intensity
improvements are expected over the next decade, though at a slower pace.

Global manufacturing capacity for solar PV modules stood at 250 GW in 2021. China
dominates the global market today with a share of at least 80% across all steps of the supply
chain. This share may soon rise further to 95% for polysilicon, ingot and wafer production(IEA, 2022d). Production capacity differs across the various parts of the PV supply chain. In
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Annual solar PV capacity additions more than quadruple from 150 GW in 2021 to 650 GW by
2030 in the NZE Scenario. Similar growth in relative terms has occurred in the past: solar PV
capacity additions quadrupled in eight years from 37 GW in 2013 to 150 GW in 2021.

2021, there was much more capacity than needed for manufacturing wafers and cells(360 GW manufacturing capacity for wafers and 410 GW for cells), while polysilicon
production capacity of 250 GW was the tightest along the supply chain: this meant that in
effect it determined overall manufacturing capacity.
Figure 3.27 ⊳ Solar PV capacity additions and mineral demandin the NZE Scenario, 2021 and 2030
PV critical mineral demand

1 500

15

400

1 000

10

200

500

5

2030

Annual capacity additions
Required manufacturing capacity

2021

Silver

2021

kt

600

3

Other CM

20

Zinc

2 000

Tellurium

800

Silicon25

Copper

2 500

kt

GW

PV capacity additions
1 000

2030
IEA. CC BY 4.0.

Solar PV capacity additions expand by more than four-times from the 2021 level by 2030,
while technology improvements mitigate growth in critical minerals demand
Note: kt = kilotonnes; CM = critical minerals.

Material supplies will need to expand as well. In 2021, solar PV demand accounted for 11%
of global silver production, over 6% of metallurgical‐grade silicon and over 40% of all refined
tellurium. In the NZE Scenario, demand for critical materials rises by 200‐300% by 2030
compared to 2021, depending on the material. For silver, for example, this means thatdemand for solar PV manufacturing triples between 2021 and 2030, reaching levels in 2030
equivalent to 35% of global silver production in 2021, despite a projected one‐quarter
decline in silver intensity.
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To reach the deployment levels projected in the NZE Scenario, overall production capacities
need to expand for the entire value chain to reach manufacturing capacity of more than
800 GW by 2030 (Figure 3.27). Taking into account expected manufacturing capacity
additions of 150 GW, global polysilicon production capacity could reach 400 GW by the endof 2022, which is roughly half of the manufacturing capacity needed by 2030 in the NZE
Scenario. Significant further manufacturing capacity additions are needed in the years to2030 if deployment is to increase to the levels projected in the NZE Scenario. Estimatessuggest that announced expansion plans could reach the levels of deployment seen in the
NZE Scenario, although there is much uncertainty surrounding these announcements.

CCUS technologies
A rapid acceleration in the deployment of carbon capture, utilisation and storage is neededin the NZE Scenario to deliver deep emissions reductions across the industry, power and fueltransformation sectors and to remove CO2 from the atmosphere through direct air capture(DAC) and bioenergy equipped with CCUS (BECCS).
Around 35 commercial CCUS facilities are in operation today with the collective capacity tocapture almost 45 Mt CO2 each year. This needs to increase to 1.2 Gt per year in 2030 and
6.2 Gt per year in 2050 in the NZE Scenario. In 2030, annual CO2 capture from both new
construction and retrofits amounts to around 270 Mt from hydrogen production, 300 Mt
from coal‐, gas‐ and biomass‐fired power plants, and 300 Mt from industrial facilities, e.g.
cement, steel, chemicals. On average, the NZE Scenario requires more than ten new CCUS‐
equipped facilities to be commissioned each month between now and 2030.
Figure 3.28 ⊳ Global CO2 capture by operating and planned source

Mt CO₂

relative to the NZE Scenario, 2030
1 400

DAC
Direct air capture

1 200

Fuel supply
Other fuel supply
Hydrogen production
Biofuels production

1 000
800
600

Industry
Industry

400

Electricity sector
Bioenergy
Natural gas
Coal

200
Operational

Planned by 2030

NZE 2030
IEA. CC BY 4.0.

Despite the progress being made on CCUS, currently planned capacityfor 2030 represents just 20% of the CCUS required in the NZE Scenario
Note: DAC = direct air capture.

17
Section 45Q of the US Internal Revenue Code provides a tax credit for certain types of CO2 use and for CO2
injected for enhanced oil recovery or permanent geological storage.

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Recent momentum provides cause for optimism that the next decade will see meaningfulprogress in deploying CCUS technologies. In 2021, governments around the world
announced initiatives with around USD 20 billion in new funds specifically targeting CCUS,
and further funds have been announced in 2022. The US Infrastructure Investment and Jobs
Act provides approximately USD 12 billion across the CCUS value chain over the next five
years and the US Inflation Reduction Act expanded the existing 45Q tax credit.17 The 2022

federal budget in Canada introduced an investment tax credit for CCUS projects from 2022
to 2030 that covers industrial CCUS applications, hydrogen and DAC projects. In Europe,countries continued competitive funding opportunities for CCUS projects through regional
funding programmes, such as the Connecting Europe Facility and the Innovation Fund, as
well as national subsidy schemes, such as those in Denmark and the SDE++ in the
Netherlands.
Driven by net zero emissions commitments, policy progress and an improved investment
environment, the number of planned CCUS facilities has increased more than ninefold since
2018, when only around 30 new facilities were in the early stages of development. Plans formore than 130 new CCUS facilities were announced in 2021, and a total of 260 facilities are
now in various stages of planning and development worldwide. If all of these projects
proceed to operation, around 260 Mt CO2 would be captured in 2030 (Figure 3.28). This
represents a sixfold increase on current deployment yet only around 20% of what is requiredin the NZE Scenario.

3

Interest in capturing CO2 directly from the atmosphere is expanding as governments andindustry look for ways to meet their net zero emissions commitments. Since the start of 2020,
almost USD 5 billion in public funding has been earmarked for DAC technologies, including
USD 3.5 billion to establish DAC hubs in the United States, while leading DAC technology
providers have raised over USD 1 billion in private capital.
DAC technologies play a growing role in the NZE Scenario, capturing around 70 Mt CO2 in
2030 and around 600 Mt CO2 in 2050. Their ability to capture CO2 from the atmosphere that
can then be permanently stored gives carbon dioxide removal technologies like DACS and
BECCS a vital role in balancing emissions that are difficult to avoid. An alternative topermanent storage is for CO2 captured by DAC or from BECC technologies to be used as aclimate‐neutral feedstock for a range of products that require a source of carbon, including
synthetic aviation fuels. In the NZE Scenario, over 85% of BECC and DAC CO2 is permanently
stored, and under 15% is used as feedstock.
The 18 DAC plants currently operating worldwide are all small scale, with a combined CO2
capture capacity of less than 0.01 Mt CO2 per year. The first large‐scale DAC plant of up to
1 Mt CO2 per year is in advanced development and is expected to be operating in the UnitedStates by the mid‐2020s. Plans for a total of 11 facilities are now in development, includingin North America, Norway and the United Kingdom. If all planned projects go ahead, DAC
deployment could reach more than 5 Mt CO2 by 2030.18 This is around 700‐times today’s
capture rate, yet only less than 10% of the level projected in the NZE Scenario in 2030.

This does not include a recent announcement by companies 1PointFive and Carbon Engineering to deploy
70 DAC facilities (each with a capture capacity of up to 1 Mt CO2 per year) by 2035, which could significantly
increase DAC deployment plans.

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18

Scaling up supply chains across sectors and regions

Box 3.6 ⊳This section highlights the prospects for a rapid scaling‐up of a number of clean
technology supply chains, while also drawing attention to the gaps that need to be
bridged to reach the levels of deployment seen in the NZE Scenario. Some clean
technology value chains have announced expansion plans which would see them getclose to the level of deployment in the NZE Scenario by 2030: the main examples arebatteries and solar PV (Figure 3.29). Some are slated to see huge expansion, but still fallshort of the required level by 2030: these include electrolysers.
Figure 3.29 ⊳ Production or throughput capacity in 2021, assuming
full implementation of announced project pipelines
and NZE Scenario deployment levels in 2030
NZE deployment

100%
80%
60%
40%
20%

Batteries
2021

Solar PVElectrolysers

2030 announced pipeline

Lithium

CopperStill needed to reach 2030 NZE
IEA. CC BY 4.0.

A number of clean technology value chains have announced supply capacitythat approaches the level required in the NZE Scenario by 2030
Note: This figure assumes full implementation of announced project pipelines, including speculative
projects. For all technologies, the figure shows annual production capacity in 2030 relative to the level ofannual demand or capacity addition in the NZE in the same year.



174

Diversity: Currently, many clean technology supply chains are geographicallyconcentrated, particularly in China. For example, 75% of global production capacity
for battery cells is located in China, and as much as 97% of global capacity for wafer
manufacturing for PV cells (with around 14% of global wafer production taking place
in a single Chinese factory). Such concentration raises the risks of supply chain
disruptions. Maintaining the economic efficiency benefits of trade while diversifying
supply chains will be critical to accelerate clean energy transitions.
International Energy Agency | World Energy Outlook 2022

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Clean technology supply chains need to be developed with diversity, co‐ordination andefficiency in mind:Co‐ordination: Clean energy technologies are delivered via highly complex supply
chains with numerous inputs and manufacturing steps. While some parts of thechain are moving ahead almost in line with the NZE Scenario, others are lagging. For
example, while almost 85% of the battery manufacturing capacity needed in the NZE
Scenario in 2030 is already in place or in the pipeline, the lithium supply chain faces
a much bigger stretch. Announced capacity expansions and potential new projects
would increase current production capacity three‐and‐a‐half‐times, but anothertripling of current capacity would be required to meet the level seen in the NZE
Scenario in 2030. Similarly, even though announced solar PV capacity growth isessentially sufficient to meet the NZE Scenario demand in 2030, achieving this rateof capacity additions may face bottlenecks on issues such as land acquisition, gridconnections (notable also in the context of the projected shortfall in copper supply),and secure grid integration of this variable renewable energy source.

3

Efficiency: A focus on supply chains does not imply that all solutions to bottlenecks
must come from supply. For example, while current and announced production
capacity for copper might be able to cover around 80% of the projected demand in
the NZE Scenario, meeting the additional demand could be very challenging given
the long lead times of projects and depletion of those reserves that are easiest to
exploit. In such cases, measures to enhance recycling, reduce material use where
possible and accelerate the deployment of substitutes could reduce pressure on the
supply side to meet the huge increase in demand seen in the NZE Scenario.

The complexity of – and current tensions in – global clean energy supply chains is one
reason that the IEA is placing increased focus on this issue, which will be at the heart of
the next Energy Technology Perspectives report forthcoming in 2023.

3.11

Energy employment: an opportunity and a bottleneck in the
NZE Scenario

Despite some growth in bioenergy and hydrogen supply jobs, employment in the NZE
Scenario shifts away from fuel supply and becomes more heavily concentrated in the power
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Rapid expansion of clean energy technologies in the NZE Scenario is accompanied by acommensurate expansion of the energy sector workforce. Energy sector employment
increases from just over 65 million today to 90 million in 2030, taking into account both
direct jobs in energy sectors and indirect jobs in the manufacturing of essential components
for energy technologies and infrastructure. There are almost 40 million new jobs in clean
energy by 2030, outweighing job losses in fossil fuel‐related industries, and the share ofenergy sector employment related to clean energy increases from around half today to 80%
by 2030. Achieving this growth in clean energy jobs within the decade will require strategic
and proactive planning by industry, governments, and educational and training institutions
in order to prevent shortages of skilled labour from becoming a bottleneck for energy
transitions.

and end‐use sectors (Figure 3.30). Fossil fuel supply jobs decrease by 7 million by 2030 in the
NZE Scenario, with coal supply seeing the sharpest decline as mechanisation anddecarbonisation efforts lead to further downsizing of the coal industry. Many skilled workers
in the fossil fuel industry, in particular those in the oil and gas industries, have skills that arehighly applicable to emerging clean energy sectors, though some will also still be needed tooperate oil and gas assets that persist beyond 2030. Coal miners, particularly those inmodern, mechanised mining operations, may have skills that would be useful in criticalminerals production, although the scope for this transition may be limited by the relatively
smaller volumes of minerals needed and by the different geographic locations of coal andmineral deposits. People‐centred and just transitions policies will be vital to provide support
for fossil fuel workers with limited transition prospects in energy or parallel industries.
Figure 3.30 ⊳ Energy employment by technology in the NZE Scenario,
2019 and 2030

Million employees

Fuel supplyPower

End‐uses40

Fuel supply
Critical minerals
Low‐emissions fuels
Oil and gas
Coal
Power
Grids and storage
Low‐emissions
Unabated fossil fuels
End‐uses
End‐use efficiency
Vehicles: EVs and batteries
Vehicles: ICEs

30

20

10

2019 2030

2019 2030

2019 2030
IEA. CC BY 4.0.

The share of energy sector employment related to clean energy
increases from around half today to 80% by 2030

The power sector leads the way in the NZE Scenario in terms of job growth to 2030, witharound 9 million additional jobs in power generation complemented by 4 million new jobs inpower grids and electricity storage. Employment opportunities related to solar PV and wind
power increase by around 10% each year to keep pace with steady growth in capacity
additions, while power grids maintain 4% annual employment growth thanks to rising
electrification rates and new investment in grid upgrades and expansion. Employment also
increases substantially in vehicle manufacturing and in businesses concerned with improving
the efficiency of equipment, industry and buildings.

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Note: EVs = electric vehicles; ICEs = internal combustion engines.

In vehicle manufacturing, three‐fifths of current jobs shift to EVs and their batteries. WhileEVs have fewer components and are less labour‐intensive to assemble, additional jobs will
be needed along the related battery supply chain, although they may not be in the same
location as current manufacturing jobs. Efficiency improvements in the industry andbuildings sectors require an additional 8 million workers to retrofit buildings, install more
efficient heating and cooling and improve industrial process efficiency.
Energy sector employment spans several value chain segments.19 Project construction andmanufacturing are of particular importance for the delivery of new energy infrastructure,seeing the creation of over 10 million new jobs by 2030 in the NZE Scenario. Construction
jobs are typically located where new projects are deployed. By contrast, manufacturing jobs
are currently concentrated in the Asia Pacific region, where active industrial policies and well‐established manufacturing competitiveness are enabling the emergence of significant clean
energy manufacturing hubs that supply projects worldwide (IEA, 2022e). However, several
countries including the United States and India are making efforts to bring critical supply
chains onshore as they accelerate clean energy investment, and others may follow suit. The
global distribution of manufacturing job gains in the coming decade depends on how
countries balance diversity, resilience and affordability as clean technology supply chainsdevelop and grow.

3

19
As grouped in the ISIC International Standard Industrial Classification revision 4 structure:https://unstats.un.org/unsd/publication/seriesm/seriesm_4rev4e.pdf.

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Shortages of skilled labour in clean energy construction projects are already starting to beseen, underlining the importance of strategic and proactive labour policies to build theworkforce needed for the rapid expansion of clean energy technologies. Training andreskilling take time, and close collaboration between governments, companies, labour
organisations, academia and training institutions would help to prevent hiring bottlenecks.
Those with jobs that are edged out as decarbonisation proceeds should be offered retraining
to enable them to work in fast growing low‐emissions sectors of the economy. Efforts toimprove the quality, inclusivity and wages of clean energy jobs would help to attract moreworkers, as would recognised qualifications or the certification of skills tailored to particularclean technology sectors.

PART C
KEY ENERGY TRENDS
Part C of the World Energy Outlook takes an in‐depth lookat the impact of the current energy crisis and how policy
responses and technology and investment choices maychange the future of energy. It does this for all energy
sources, sectors and regions to 2050, using the mostup‐to‐date data. It also provides some guidelines for policy
makers and other stakeholders that can help to safeguardenergy security in an era of rapid change.

IEA. CC BY 4.0.

These chapters utilise scenario analysis to explore various
potential pathways that the energy sector could take, how
they may be achieved, and what may be the implications forenergy security, energy demand and electricity, oil, gas, andcoal markets as well as for low‐emissions fuels.

OVERVIEW BY CHAPTER
Chapter 4 presents ten elements of a pragmatic agenda to ensure energy security
during clean energy transitions and covers a range of risks that may arise. It includes
traditional energy security concerns as the global energy sector evolves as well as newvulnerabilities that may emerge, and highlights the policies and approaches that can
mitigate these risks.
Chapter 5 examines the outlook for energy demand. Alongside updated projections by
scenario, it examines in detail the outlook for energy access as well as the increasing
demand for space cooling. In addition, it details the prospects for oil use in roadtransport in light of the rapid rise in electric vehicles.
Chapter 6 focusses on the power sector. It looks in depth at the importance of system
flexibility for electricity security, the essential role of networks to accelerate emissions
reductions from electricity generation, and the increasing needs of critical minerals forclean electricity systems.
Chapter 7 assesses the outlook for liquid fuels. It looks in detail at the use of oil inplastics, the extent to which new conventional oil projects are needed to balance oilmarkets in the scenarios, and the immediate and longer term challenges facing therefining sector.
Chapter 8 tackles the outlook for gaseous fuels. It considers in detail the current crisis
and its potential impacts on domestic production and on pipeline and LNG flows in
Europe and beyond. It also considers the prospects for low‐emissions hydrogen, andthe future role of natural gas in emerging market and developing economies in Asia.

IEA. CC BY 4.0.

Chapter 9 explores the outlook for solid fuels. It highlights some key findings of the
updated projections for coal and solid bioenergy as a precursor to the forthcoming
World Energy Outlook Special Report, Coal in the Global Net Zero Transition.

Chapter 4
Energy security in energy transitions
A pragmatic agenda for secure and rapid change
S U M M A R Y
 High and volatile fossil fuel prices in the wake of Russia’s invasion of Ukraine
underscore the risks inherent in today’s energy system and the importance of energy
security to our economies and daily lives. Energy transitions offer the chance to build
a safer and more sustainable energy system that reduces exposure to fuel pricevolatility and brings down energy bills, but there is no guarantee that the journey will
be a smooth one. Traditional security threats remain, even as new potential
vulnerabilities emerge. This chapter proposes the following ten guidelines to help
buttress energy security in the “mid‐transition”, when the clean energy and fossil fuelsystems co‐exist and are both required to deliver reliable energy services.

 Synchronise scaling up a range of clean energy technologies with scaling back offossil fuels. Investing in clean energy is key to avoid future crises while reducing
emissions. In the Net Zero Emissions by 2050 (NZE) Scenario, around USD 9 is spenton clean energy by 2030 for every USD 1 spent on fossil fuels. Cutting investment infossil fuels ahead of scaling up investment in clean energy pushes up prices but does
not necessarily advance secure transitions. High fossil fuel prices could make it
10‐25% more expensive for fossil fuel importers to meet climate goals.

 Tackle the demand side and prioritise energy efficiency. The energy crisis highlights
the crucial role of energy efficiency and behavioural measures in helping to avoid
mismatches between demand and supply. Since 2000, efficiency measures have
reduced unit energy consumption significantly, but the pace of improvement has
slowed in recent years. Policies that accelerate the rate of retrofits are crucial as overhalf of the buildings that will be in use in 2050 have already been built.

 Reverse the slide into energy poverty and give poor communities a lift into the newenergy economy. As a result of the pandemic and the energy crisis, 75 million people
have lost the ability to pay for extended electricity services and 100 million for clean
cooking solutions. In emerging market and developing economies, the poorest
households consume nine‐times less energy than the wealthiest but spend a far
greater proportion of their income on energy. Turning these worsening energy
poverty trends around is essential for secure, people‐centred energy transitions.
economies. The cost of capital for a solar photovoltaics (PV) plant in 2021 in key
emerging economies was between two‐ and three‐times higher than in advanced
economies and China. Tackling related risks and lowering the cost of capital inemerging and developing economies by 200 basis points reduces the cumulative
financing costs of getting to net zero emissions by USD 15 trillion through to 2050.

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 Collaborate to bring down the cost of capital in emerging market and developing Manage the retirement and reuse of existing infrastructure carefully. Some parts ofthe existing fossil fuel infrastructure perform functions that will remain critical forsome time, even in rapid energy transitions. They include gas‐fired plants forelectricity security ‐ in the European Union peak requirements for natural gas rise to2030 even as overall demand goes down by 50% ‐ or refineries to fuel the residualinternal combustion engine car fleet. Unplanned or premature retirement of thisinfrastructure can have negative consequences for energy security.

 Tackle the specific risks facing producer economies. Diversification will be crucial tomitigate risks. Some countries are investing part of their current windfall oil and gas
profits in renewables and low‐emissions hydrogen. Potential export earnings fromhydrogen are no substitute for those from oil and gas, but low cost renewables andcarbon capture, storage and utilisation (CCUS) can provide a durable source ofeconomic advantage by attracting investment in energy‐intensive sectors.

 Invest in flexibility – a new watchword for electricity security. Reliable electricity iscentral to transitions as its share in final consumption rises from 20% today to 40% in
the Announced Pledges Scenario (APS) in 2050 and 50% in the NZE Scenario.
Increasing variability in electricity supply and demand means that the requirement for
flexibility quadruples by mid‐century in both scenarios. Battery storage anddemand‐side response become increasingly important, each providing a quarter ofthe flexibility needs in 2050 in the APS.

 Ensure diverse and resilient clean energy supply chains. Mineral demand for clean
energy technologies is set to quadruple by 2050 in both the APS and NZE Scenario,
with annual revenues reaching USD 400 billion. High and volatile critical mineralprices and highly concentrated supply chains could delay energy transitions or makethem more costly. Minimising this risk requires action to scale up and diversify
supplies alongside recycling and other measures to moderate demand growth.

 Foster the climate resilience of energy infrastructure. The growing frequency andintensity of extreme weather events presents major risks to the security of energy
supplies. IEA analysis of the risks facing four illustrative assets shows that the potential
financial impact from flooding could amount to 1.2% of their total asset value in 2050,
and in one case would be four‐times higher than this without flood defences in place.
Governments need to anticipate the risks and ensure that energy systems have theability to absorb and recover from adverse climate impacts.
markets. Governments need to take the lead in ensuring secure energy transitions bytackling market distortions – notably fossil fuel subsidies – as well as correcting formarket failures. However, transitions are unlikely to be efficient if they are managed
on a top‐down basis alone. Governments need to harness the vast resources ofmarkets and incentivise private actors to play their part. Some 70% of the investments
required in transitions need to come from private sources.
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 Provide strategic direction and address market failures, but do not dismantle

Clean energy investment
and energy efficiency are key
to a secure exit from today’s crisis
1

Synchronise scaling up a rangeof clean energy technologies
with scaling back of fossil fuels

2

Tackle the demand sideandprioritise energy efficiency

10 guidelines
for secureenergy transitions

Global energy security cannot
be achieved without everyone on board
3

Reverse the slide into energy poverty
and give poor communities a lift
into the new energy economy

4

Collaborate to bring down the costof capitalin emerging market
and developing economies

The transition away from oil and gas
needs to be handled with care
Manage the retirement and reuseof existinginfrastructure carefully,
5
some of it will be essentialfora secure journey to net zero
Tackle the specific risks facing
6
producer economies

New vulnerabilities emerge as the worldbuilds a new clean energy system
Invest in flexibility, a new7
watchword for electricity security
Ensure diverse and resilient
8clean energy supply chains
Foster the climate resilience
9of energy infrastructure

Governments have to take the lead,but cost-effective transitions alsoneed well-functioning markets
Provide strategic direction

10 and address market failures,but do not dismantle markets

Introduction
Energy security is not just about having uninterrupted access to energy, but also about
securing energy supplies at an affordable price. It is a topic of perennial importance, and isonce again high on the policy agenda as a result of the global energy crisis sparked by Russia’s
invasion of Ukraine. The surge in energy prices has been on a large enough scale to worsen
considerably the global economic outlook, causing difficulties for households and industrial
operations alike, and leading many governments to recalibrate their policy priorities(see Chapter 2, Box 2.4).
The immediate policy focus is understandably on dealing with the impacts of high energy
prices on consumers and coping with the disruption of energy supplies. Many countries aretaking action to: make the most of existing power plants, e.g. Japan’s restart of nuclear
reactors; diversify sources of supply, e.g. European imports of liquefied natural gas (LNG);
accelerate the deployment of clean energy technologies, e.g. through the European Union
REPowerEU Plan and the US Inflation Reduction Act; or enact programmes to protect
consumers from high prices, e.g. by setting price caps, expanding targeted support or cutting
fuel taxes. In some cases, actions have involved trade‐offs between short‐term security
benefits and emissions reduction goals, for example when relying more on coal‐fired power
plants for electricity generation.

While achieving net zero emissions goals ultimately brings energy security benefits, it should
not be taken for granted that pathways to get there will be smooth. Energy transitions
require adding new clean energy infrastructure while reducing reliance on existing carbon
emitting infrastructure, and managing the co‐existence of these systems is challenging(Grubert and Hastings‐Simon, 2022). Nor should it be assumed that there will be no newenergy security risks in a net zero emissions world. New areas of concern may emerge as
massive deployment of clean energy technologies puts strains on supply chains, notably forcritical minerals, while a reorientation of global energy trade flows could bring about new
geopolitical tensions. Rising reliance on electricity generated from variable renewables calls
for an ever higher degree of power system flexibility that could pose risks if not carefully
managed. A lack of preparation for the challenges stemming from a changing climate,
inadequate energy systems resilience and looming cyber threats could expose consumers tomore frequent supply disruptions and price spikes.
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Nonetheless, the need to move towards net zero emissions to ward off catastrophic climatechange remains as important as ever. In the Net Zero Emissions by 2050 (NZE) Scenario,
traditional risks surrounding oil and gas supplies ease as demand for fossil fuels falls, but they
do not vanish. Huge additional investments are required to scale up clean energy provision,and they are accompanied by large reductions in fossil fuel import bills in many regions(Figure 4.1). Efficiency gains also mean that household energy bills in 2030 in this scenario
are also lower than in the Stated Policies Scenario (STEPS). As highlighted in the IEA 10‐Point
Plan to Reduce the European Union Reliance on Russian Natural Gas, moving towards a moresustainable energy system provides a clear answer to predicaments such as the current crisis(IEA, 2022a).

Billion USD (2021, MER)

Figure 4.1 ⊳900

Clean energy investment and reduction in fossil fuel import bills
in developing economies in Asia in the NZE Scenario relative to
the STEPS

Additional clean energy
investment

600
300

4

0
‐300
‐600

Reduction infossil fuel import bills
2022

2030

2040

2050
IEA. CC BY 4.0.

Significant additional investment in clean energy is required in the NZE Scenario,
but this delivers steadily lower import bills over time
Note: NZE = Net Zero Emissions by 2050 Scenario; STEPS = Stated Policies Scenario; MER = market exchangerate.

In this chapter, we present ten key elements of a pragmatic agenda to safeguard energy
security during energy transitions. This agenda is not focused on the current energy crisis,
although many of the items are relevant to it. Nor is it designed to provide a comprehensive
overview of all aspects of energy security, although it covers a wide range of potential
hazards. Rather, the intention is to explore specific energy security risks that arise as theworld moves through a much needed transformation of the energy sector, and to examine
policies and approaches that mitigate these risks. As such, we focus on how some traditionalenergy security concerns might evolve as we move through transitions and on newvulnerabilities that might emerge. The overarching aim is to map ways to avoid clean energy
transitions running into problems that could lead to extreme price volatility, social
disruptions, consumer discontent or supply chain bottlenecks.

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The need to look at a broad range of energy security issues during energy transitions was acore pillar of new mandates given to the IEA at its Ministerial meeting in March 2022. The
Ministerial Communiqué recognised the need for the IEA to remain vigilant in an increasingly
complex energy security environment. Building on core principles, notably the benefits ofdiversified energy sources, supplies, routes and means of transport, the communiqué
reflects on evolving security issues for oil, gas and electricity markets and infrastructure aswell as new areas such as climate resilience, clean energy supply chains and critical minerals.

Ten essentials for secure energy transitions
A major push on scaling up investment in clean energy technologies (section 4.1) andreducing demand and improving energy efficiency (section 4.2) are fundamental to achieving
secure energy transitions, and also offer the lasting solutions to the immediate energy crisis.
Energy transitions require an inclusive approach if they are to be secure. This means
reversing the slide into energy poverty and giving poor communities a lift into the new energy
economy (section 4.3). It also means avoiding the emergence of new dividing lines in energy
by facilitating faster change in emerging market and developing economies. Collaborating tobring down the cost of capital in the developing world is essential to unlock timely, cost‐effective clean energy investment (section 4.4).
The energy transition involves building a clean energy system while winding down existingfossil fuel supply and emissions, but some parts of the fossil fuel system remain vital forenergy security, and there is a need to manage the retirement and reuse of existing
infrastructure carefully (section 4.5). Producer economies that export oil or gas (and that rely
heavily on hydrocarbon income) remain important to global energy security even as relianceon these fuels diminishes; their long‐term stability requires that they diversify theireconomies and adapt their energy systems to the new market and policy environment(section 4.6).
New vulnerabilities may also emerge as the world builds a new clean energy system. The
increasing role of electricity in final consumption puts a premium on investing in system
flexibility (section 4.7). Diverse and resilient clean energy supply chains, including those for
critical minerals and metals, are essential to avoid costly or delayed energy transitions(section 4.8). Since the climate is already changing, both existing and new infrastructure willneed to factor in climate resilience (section 4.9). All this implies a crucial role forgovernments, who are taking on increasingly expansive roles to accelerate transitions but
also need to retain the benefits of competitive, reliable energy markets based on transparent
rules (section 4.10).

4.1

Synchronise scaling up a range of clean energy technologies withscaling back of fossil fuels

The world has not been investing enough in energy. Since 2017, annual clean energy
investment has averaged USD 1.2 trillion, well below the investment levels for clean energy
seen in the STEPS in 2030, and annual investment in fossil fuels has averaged USD 0.8 trillion,
similar to the investment levels that feature in the Announced Pledges Scenario (APS) in 2030
(Figure 4.2). In other words, recent investment levels in clean energy technologies have been
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Boosting investment in clean energy rather than new long lead time fossil
fuel supply provides a more lasting solution to today’s energy crisis while
cutting emissions. Reductions in fossil fuel investment need to besequenced carefully to avoid sharp spikes in fuel prices.

far below what is needed to bring about a peak and decline in fossil fuel demand, yetinvestment in fossil fuel supply has been geared towards a world of stagnant or evendeclining demand for these fuels. This underlying mismatch has made the energy system
more vulnerable to the sorts of shocks that came in 2022 with Russia’s invasion of Ukraine.
Annual average investment in fossil fuel supply, clean power,
infrastructure, end-uses and low-emissions fuels by scenario
Power

Grids

End‐useLow‐emissions fuels

150

1 000

100

500

50

2030

2030

2030

2017‐21
STEPS
APS
NZE

1 500

2017‐21
STEPS
APS
NZE

200

2017‐21
STEPS
APS
NZE

2 000

2017‐21
STEPS
APS
NZE

Billion USD (2021, MER)

Fossil fuel supply

2030

4

2017‐21
STEPS
APS
NZE

Figure 4.2 ⊳2030

IEA. CC BY 4.0.

The world is not investing enough in energy. Fossil fuel investment is geared to stagnant
or falling demand, while clean energy investment is not rising fast enough.
Note: MER = market exchange rate; APS = Announced Pledges Scenario.

In the NZE Scenario, governments rapidly introduce policies to reduce emissions fromexisting fossil fuel infrastructure and to scale up investment in clean energy technologies by
a factor of three by 2030. The clean energy investment surge in the NZE Scenario means thatdemand for fossil fuels declines with sufficient speed that it is possible to satisfy oil and gas
demand without approving new long lead time upstream conventional projects, althoughcontinued investment in existing assets is still necessary (see Chapter 1). Annual fossil fuelinvestment in the NZE Scenario in 2030 falls to around USD 450 billion, half of the levels seen
over the past five years. Reducing fossil fuel investment to these levels in advance of – orinstead of – the threefold scale up in clean energy spending would not lead to the sameoutcomes as in the NZE Scenario. It would instead lead to high and volatile fossil fuel prices
during energy transitions (Spotlight).
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In the STEPS, fossil fuel demand rises in the coming years, requiring new upstream
conventional projects to avoid a shortfall in supply in the mid‐2020s (see Chapter 7). In the
APS, global demand for fossil fuels soon peaks and starts to decline. This means that there isless need for new conventional upstream projects, but some remain essential to ensure asmooth match between supply and demand by the late‐2020s.

Russia’s invasion of Ukraine could lead to a substantial and prolonged reduction in energy
supplies from Russia, and any immediate shortfalls in fossil fuel production from Russia need
to be replaced by production elsewhere, even in a world working towards net zero emissions
by 2050. But governments looking to protect against the current disruption in energy
markets can do so in ways that do not risk undermining or slowing the energy transition. A
dramatic scaling up of energy efficiency and clean energy is key to lasting structural solutions
to the energy crisis. It is also key to getting on track towards net zero emissions. Governments
have a unique ability to act in this regard: they can provide strategic vision; policy signals;
incentives for consumers; and public finance that catalyses private investment and can spur
innovation.
Figure 4.3 ⊳Investment in clean energy and fossil fuels by scenario,
2025 and 2030

Trillion USD (2021, MER)

STEPS

APS

NZE

5

10

4

8

3

6

2

4

1

2
2025

2021
Fossil fuels:
Clean energy:

2030

2025

2030

2025

Coal
Natural gas
Power and fuels
Efficiency and end‐use
Ratio of clean energy to fossil fuels (right axis)

2030
Oil

IEA. CC BY 4.0.

Around USD 9 is invested in clean energy for every
USD 1 invested in fossil fuels in 2030 in the NZE Scenario

Reductions in fossil fuel investment need to be sequenced so they do not run ahead of thehuge scaling up in clean energy technologies that is required to get to net zero emissions.
Many companies and financial organisations have set goals and plans to scale down
investment in fossil fuels, but it makes little sense to consider these in isolation: much moreemphasis is needed on their goals and plans for the scaling‐up of investment in clean energy
technologies, and on what governments can do to incentivise this. For every USD 1 spentglobally on fossil fuels in the NZE Scenario in 2030, USD 5 is spent on clean energy supply andanother USD 4 on efficiency and end‐use. (Figure 4.3). This provides a useful guideline forunderstanding the alignment of financial flows of investor and company portfolios withachieving net zero emissions globally by 2050.
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Note: MER = market exchange rate.

Emissions from fossil fuel extraction, processing and transport account for more than 15% ofenergy‐related greenhouse gas (GHG) emissions today and need to be minimised as quickly
as possible. Reducing these emissions is also the primary way in which fossil fuel industries
can limit the potential impact of future climate policies on their operations. Oil and natural
gas with lower emissions intensities will be better positioned than higher emitting sources
as clean energy transitions speed up, may incur lower tax burdens, and are likely to be
increasingly preferred for continued production during transitions.
The extraordinary financial windfall for the oil and gas sector from today’s high prices could
provide a major boost to clean energy investment. Global net income from oil and gas
production is anticipated to reach nearly USD 4 trillion in 2022, which is double the level in
2021. If the global oil and gas industry were to invest this additional income in low‐emissions
fuels, such as hydrogen and biofuels, it would fund all of the investment needed in thesefuels for the remainder of this decade in the NZE Scenario. It would go even further if used
to catalyse spending by both private and public sources on clean energy more broadly. For
oil and gas producing economies, this could be a once‐in‐a‐generation opportunity todiversify their economic structures to adapt to the new global energy economy that is
emerging.

4

S P O T L I G H T
Do high fuel prices help or hinder the process of change?
Investment in clean energy technologies and fossil fuels in the NZE Scenario is calibrated
to minimise stranded assets and avoid energy market volatility. Wholesale fossil fuelprices fall to low levels as they are increasingly set by the operating costs of the marginal
project. 1 If supply were to transition faster than demand, with a drop in fossil fuelinvestment preceding a surge in clean energy technologies, this would lead to muchhigher prices – possibly for a prolonged period – even if the world is moving towards net
zero emissions. There are parallels with the situation in markets today, and responses tothe current crisis provide useful insights into what high fossil fuel prices could mean forenergy transitions.
Economics: Increases in the prices of the most polluting fuels improve the economic
advantages of cleaner alternatives (including energy efficiency measures). They act in asimilar way to a carbon dioxide (CO2) price in this respect.2 The oil price increase between
2021 and the first six months of 2022 is equivalent to a USD 70 per tonne of CO2 price on
oil use; the natural gas price increase seen in Europe is equivalent to a price of
USD 350/t CO2. But high fossil fuel prices are no substitute for climate policies. Fuel prices

1

2
A key difference, however, is that the increased revenues from higher fossil fuel prices are collected by the
producing country or company, while revenues from higher CO2 prices are collected by the consuming country.

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Ongoing operating costs include the cost of extraction, extraction taxes, cost to reduce scope 1 and2 emissions, and CO2 taxes from any residual emissions.

do not reflect the carbon content of the fuels and they can incentivise shifts towards
more polluting fuels, e.g. from natural gas to coal. In response to the current crisis, forexample, some countries have delayed planned coal power plant closures to reducereliance on natural gas, and new investments in coal supply have been announced in
China and India.
Political economy of transitions: Countries may see high fuel prices as a spur toaccelerate transitions, as for example seen in the European Union REPowerEU Plan andthe US Inflation Reduction Act, and a powerful boost to innovation, as happened during
the 1970s oil price crises. However, high fuel prices also create the risk that affordability
and security concerns reduce the attention and money that policy makers devote toemissions reductions. If importing countries end up spending much more on their fuelimport bills, this could squeeze funding to support clean energy transitions (Figure 4.4).
Fossil fuel exporters would receive windfalls as a result of such extra spending, but there
is no guarantee that these would be a net boost for transitions. This might reinforcehydrocarbon‐dependent development models rather than promote the need for reform.
Figure 4.4 ⊳Annual average investment and fossil fuel imports in the APS
with projected prices and with high fossil fuel prices, 2021-30

IEA. CC BY 4.0.

High fossil fuel prices would squeeze funds available to support transitions and make it
10-25% more expensive for fossil fuel importers to achieve their climate targets

Social implications: High fossil fuel prices are regressive and hit the poor hardest. They
often lead to price interventions such as fossil fuel subsidies that are rarely well designed

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Notes: MER = market exchange rate. APS+ = APS with high fossil fuel prices, which assumes that countries
reduce fossil fuel use and emissions in line with the APS, but with fossil fuel prices remaining aroundcurrent levels (oil ‐ USD 100/barrel; natural gas ‐ USD 15‐25 per million British thermal units; coal ‐USD 170‐250 per tonne of coal equivalent).

or targeted to the most vulnerable. This underlines the importance of ensuring thatclimate policies help poor households, including with the higher upfront costs of clean
energy investments (such as efficiency and clean electrification). If climate policies do not
do this, they risk being socially divisive, especially in a high price environment, with richer
segments of the population able to adjust to changing circumstances and the poor left
behind. This would make just transitions very difficult to achieve, and it would also risk
undermining support for climate policies.
The net impact of high fossil fuel prices and policy changes made in response to thecurrent energy crisis is to increase near‐term emissions in the STEPS slightly comparedwith the projections in the WEO‐2021. This demonstrates that while high prices can
reduce demand and emissions, they will not necessarily do so, and should not be viewed
as a viable or desirable substitute for climate policy.

4.2

4Tackle the demand side and prioritise energy efficiency
Efficiency is an indispensable tool for multiple policy aims, easingpressures on consumers and their vulnerability to high and volatile fuelprices, cutting reliance on fuel imports and driving progress towards
climate goals while supporting jobs and growth.

The uncertainties around long‐term fossil fuel demand and supply‐side fossil fuelinvestments mean that demand‐side responses are now more important than ever to keep
the energy system in balance. Today’s tight oil product markets, especially for diesel andkerosene, provide a good example of the energy security gains from improved efficiency.
Tight markets usually push up prices for these products and trigger investment in newrefining capacity, which then stabilises price levels. Some new refining facilities are slated tobe added in the coming years, most of which were planned well before the Covid‐19
pandemic. However, with clean energy transitions posing uncertainty about long‐term oil
demand, further new investment might not take place as it has in the past. If demand forthese products follows the trajectory in the STEPS, it could lead to tight supplies for many
years to come. In the APS, however, planned new capacity additions in the next few years
match the level of demand growth partly because more robust efforts on energy efficiency
dampen demand (see Chapter 7, section 7.3).
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The current energy crisis has put the spotlight on energy demand for both governments andthe public, not least of all in Europe. By dampening energy demand, energy efficiency plays
an indispensable role in lowering energy bills for households and businesses and shielding
consumers from volatile fuel prices. It also brings energy security benefits, especially at atime when the world is moving towards a decarbonised energy system, by reducing strains
on fuel markets and the need for costly and uncertain investments in new supply.

In the 1970s, energy efficiency played a major role in the response to oil price shocks.
Countries adopted a broad portfolio of efficiency policies that not only reduced demand but
also spurred technology improvements in all end‐use sectors, resulting in long‐term
efficiency gains. In the United States, for example, the average fuel consumption of new cars
declined from 18 litres per 100 kilometres (km) in the early 1970s to 11 litres per 100 km ten
years later. Building codes started to include energy targets/mandates during the crisis:
France and New Zealand added mandatory insulation measures in 1974 and 1977
respectively, while in 1978 California paved the way for other US states with the introductionof minimum energy efficiency requirements for appliances. Since then, technology has
continuously improved in all sectors, with notable demand reductions in the buildings sector
for lighting and refrigeration (Figure 4.5). For example, the phase‐out of incandescent lightbulbs in almost all countries and the rapid uptake of light‐emitting diodes (LEDs) (withpayback periods of less than a year in most regions) means that the energy consumption fora light bulb used in 2021 was on average between four‐ to eight‐times less than one used in
2000.

Index (2000 = 1)

Figure 4.5 ⊳Unit energy consumption for selected equipment in 2021 relative
to 2000

1.0

2021

0.8
Best
availabletechnology

0.6
0.4
0.2

Car

Truck

Refri‐
geratorLightingIndustrial
Clinker
electric production
motor
IEA. CC BY 4.0.

Thanks to energy efficiency, unit energy consumption has declined
significantly since 2000, but there is plenty of scope to do more

Energy efficiency measures adopted since 2000 saved a total of 125 exajoules (EJ) up to 2021,
or around 30% of current total final consumption. Around 45% of these savings are
attributable to energy efficiency gains in industry, largely a result of strict minimum energy
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Note: Unit energy consumption refers to: fuel economy for cars and heavy freight trucks measured in litres
per kilometre travelled; annual electricity consumption for refrigerators in kilowatt‐hours; lumens per wattfor lighting; average efficiency of the electric motor fleet in industry; energy intensity of clinker production (akey component in cement and concrete).

performance standards (MEPS) for electric motors. A further 35% of the savings were fromtransport, with the fuel economy of cars having improved by 20% since 2000 and of trucks
by 5%. Electrification is rising rapidly in transport leading to additional efficiency gains.
Almost all refrigerators, freezers and air conditioners are now subject to MEPS in advanced
economies, which have contributed in a major way to improve energy efficiency in end‐uses.
Emerging market and developing economies are making progress with about 80% of
refrigerators and air conditioners – a rapidly expanding end‐use – covered by MEPS. Wherein effect, these standards also had major impacts to reduce consumer energy bills compared
to what they would have been without energy efficiency improvements.
Recently, however, the pace of efficiency improvements has slowed. Between 2017 and2020, energy intensity has improved on average by 1% per year, down from 2.1% between
2011 and 2016 (IEA, 2022b). The rate of improvement further slowed to 0.5% in 2021.
Reversing the trends seen over the past few years is key to ensuring secure energy supplies
while reducing emissions. In the STEPS, energy intensity improves by 2% per year from 2021
to 2030, around twice the average rate achieved over the last two decades. In the APS, it
improves by 3% per year.3 By 2030, around 44 EJ (10% of total final consumption) is avoided
in the STEPS due to energy efficiency and electrification measures. In the APS, this rises to
59 EJ (13% of total final consumption), with notable improvements in emerging market anddeveloping economies.

4

Stock turnover remains a primary challenge in improving energy efficiency across all
end‐uses (Figure 4.6). More than a third of the cars, trucks and heavy industrial facilities thatwill be in use in 2050 are expected to be added in the next two decades. So how these assets
are made or built will have enduring implications for future energy intensity, CO2 emissions
and energy security. This underscores the value of effective policy interventions to ensurethat energy efficiency is foundational in new assets. In addition, it is also necessary to takeaction to improve the energy efficiency of the existing stock, particularly in some key sectors.
Buildings are a case in point, with some 55% of the buildings that will be in use in 2050 alreadyin place. Recent IEA analysis of what works well has led to the identification of best practices
that include putting in place “one‐stop” renovation offices and free audit programmes (IEA,
2022c).
Behavioural measures also have an important part to play in tandem with energy efficiency
measures, not least because they can make a significant impact in the short term. In response
to a possible cut‐off of Russian gas, European countries are implementing measures toencourage consumers to save energy. The IEA 10‐Point Plans, published in the immediate
aftermath of Russia’s invasion of Ukraine, highlights energy efficiency and specific behaviourchanges as key to reduce Europe’s reliance on fossil fuel imports from Russia (IEA, 2022a;
IEA, 2022d). Several of the IEA recommendations have found strong support in the European

Energy intensity is calculated using GDP in purchasing power parity (PPP) terms to enable differences in pricelevels among countries to be taken into account. In the IEA scenarios, PPP factors are adjusted as developing
countries become richer.

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3

Union member states. For example, Germany, Belgium, Luxembourg and Denmark
implemented regulations to accelerate replacement of natural gas boilers with heat pumps.
Germany, Austria, France, Portugal, Ireland and Spain implemented measures to make public
transport cheaper, in line with the IEA recommendation to reduce transport oil demand (IEA,
2022d).
Figure 4.6 ⊳Global stock by vintage for selected sectors, 2050

IEA. CC BY 4.0.

Efficiency policies over the next few years will play a crucial part indetermining future energy intensity and GHG emissions

Finding ways to encourage energy users to change behaviour is not always easy, and whatworks in one place may not be effective in another, since cultural norms and consumption
patterns vary widely. Nevertheless, there are many potential approaches and ample scope
for well targeted messages and effective communication. Policy makers can learn frombehavioural science and employ digital tools, nudges and incentives to stimulate energy
saving behaviour.

Setting energy saving defaults is also an effective way to encourage efficiency while
minimising consumer resistance. For example, India has mandated a 24 °C default coolingtemperature for all new air conditioners to reduce over cooling behaviour. Consumers can
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Good communication is vital as consumers often have limited visibility about pressures on
the system. For example, South Africa has provided real time information about electricity
shortfalls via a “power alert” message, which is communicated via the internet and television
between 17:30 and 20:30, to inform the public of immediate measures to reduce peak loads.
Providing actionable data can help consumers take informed decisions. In California, forexample, communication with citizens via apps, SMS and email is used to lower energy
demand at peak times, when the system is under the most strain.

adjust the settings, but many stay at the default, leading to significant energy savings.
Bringing all existing energy efficiency programmes and relevant subsidies under one
administrative agency can help overcome inertia. Ireland's Reduce Your Use campaign andthe UK Simple Energy Advice are cases in point. Both offer a clear list of existing grants,
incentives and tax rebates in one place (IEA, 2022e).
An energy crisis provides an opportunity to ramp up and take new actions to prompt energy
efficiency and behavioural changes. Experience in Japan suggests that such actions can yieldsustained benefits. A combination of public awareness campaigns and technical assistanceprogrammes in the aftermath of a devastating earthquake in 2011 reduced peak electricity
demand that summer by 15% compared with the previous year. Thanks to the continued
focus on energy efficiency, this reduction has largely been sustained to date. Electricity
demand has stayed below pre‐earthquake levels which helped avoid outages when there
were strains on the electricity system.

4.3

4Reverse the slide into energy poverty and give poor communities a lift
into the new energy economy
As a result of soaring energy prices, millions of people risk losing the mostfundamental form of energy security by becoming unable to afford basic
energy services. Targeted policy support is vital to ensure that
disadvantaged and vulnerable communities have improved access toaffordable, secure and sustainable modern energy.

The least well‐off often live in less efficient buildings and use older, inefficient appliances andequipment for services such as cooking and heating. Improving the efficiency of such homes
tends to be difficult, as they may be rentals and face the landlord/tenant barrier as well as
difficulty in making the upfront investment in retrofits and other efficiency measures.
Therefore, achieving a similar level of comfort and basic energy services typically requires
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The surge in energy prices has put a disproportionate burden on low income households andexacerbated energy insecurity. As a global average, households typically spend around 7% ofincome on energy, half for energy used in the home for a variety of end‐uses such as heating,cooling, lighting and cooking. However, this does not capture the reality that poor
households spend a far higher share of their income on energy than wealthy ones, eventhough the poorer ones consume less energy. New IEA analysis for this Outlook finds thatthe lowest quintile of households by income in advanced economies consume on averagejust a third of the energy used in households in the highest quintile (Figure 4.7). In emerging
market and developing economies, the poorest households consume nine‐times less modern
energy than the wealthiest households, with millions of poor households still lacking any
access to modern energy. These differences would be even wider if oil use for transport were
included.

more energy in poor households, driving up costs or obliging them to forego these services.
Moreover, the poorest households in emerging market and developing economies often
have no choice but to use low quality and polluting fuels combined with inefficientequipment to meet energy needs, inflating their energy bills. In some cases they may
purchase charcoal (and other cooking fuels) in informal markets, which expose them to low
grade products and seasonal price volatility.

Energy consumption per household (GJ)

Figure 4.7 ⊳Residential consumption of modern energy per householdby income quintile, 2021

80
5thAdvanced
economies

60
4th
40
2nd
1st

4th

20
1st
100

1 000

2nd

3rd
5th

Emerging market
and developing
economies

3rd

10 000100 000
1 000 000
Household income (USD)
IEA. CC BY 4.0.

The poorest households use nine-times less energy than the wealthiest ones,
but spend a much larger share of household income on energy
Notes: GJ = gigajoules. Quintiles are sequenced by total household income within all advanced economies orall emerging market and developing economies. Countries on the wealthier end of these categories tend to
be concentrated in the higher quintiles, and similarly lower income countries within these broad categories
are concentrated in lower quintiles. Excludes oil use for transportation.
Source: IEA analysis based on World Inequality Database (2022).

This is already causing problems for people that recently acquired access to electricity andmodern sources of energy for cooking (see Chapter 5, section 5.6). An estimated 75 million
people that were able to afford an extended bundle of electricity services are likely to
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These factors disproportionately expose the poorest households to energy price spikes. We
estimate that worldwide the number of people living in households spending at least 10% of
their income on energy used in the home increased by 160 million between 2019 and 2022
(assuming similar levels of household energy use in both years). While oil use for transport
is not considered in this estimate, high and volatile oil prices are also triggering rapid rises inretail prices, and this may lead to households that already have low per capita energy
consumption levels being forced to reduce energy consumption even further.

substantially cut energy use as a result of strains on household incomes. As a result of higher
prices for liquefied petroleum gases (LPG), an estimated 100 million people have had toswitch from LPG for cooking to traditional stoves (Figure 4.8). This is a clear manifestation of
extreme energy insecurity caused by the Covid‐19 pandemic and the energy crisis.

Million people

Figure 4.8 ⊳Number of people without access to modern energy and losing
the ability to afford modern energy in sub-Saharan Africa anddeveloping Asia, 2022

2 500

People with accesslosing ability to afford

2 000

4

People without access

1 500
1 000
500

Electricity

Clean cooking
IEA. CC BY 4.0.

75 million people recently lost the ability to pay for an extended bundle of electricity
services and 100 million people can no longer afford to cook with LPG

In the transition to cleaner energy, ensuring affordability for poor households will be criticalto gaining widespread public acceptance and avoiding a social backlash. During the current
crisis, governments have intervened in a variety of ways to try and protect consumers fromthe impact of high prices. The least efficient intervention is where direct fossil fuelconsumption subsidies, below market energy prices, are offered indiscriminately to all
consumers. These subsidies diminish or remove entirely the incentives to improve efficiency,
and disproportionately benefit wealthier households and businesses. They also burden
government finances at a time when fiscal leeway is important to accelerate clean energy
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Notes: People losing the ability to afford modern energy is defined here as those with access that are reducing
their use of modern fuels due to the combined effects on household income and energy prices resulting fromthe Covid‐19 pandemic and the current energy price spikes. For electricity, this is the number of people inhouseholds where the cost of an extended bundle of electricity services has risen above a region‐specificthreshold of their income. An extended bundle of electricity services includes four lightbulbs operating for
four hours per day, a fan for six hours per day, a radio or television for four hours per day and a refrigerator.
For clean cooking, this is the number of people that cook with LPG whose expenditure on fuel has risen abovea region‐specific threshold as a percentage of their income based on international LPG prices in June 2022.
These thresholds vary between 5% and 10% of household income depending on the region for both electricity
and LPG cooking.

transitions. In the STEPS, a failure to push ahead with direct fossil fuel subsidy reform could
see subsidies for household energy use and personal mobility rise by 15% to USD 370 billion
by 2030 (Figure 4.9).

Billion USD (2021, MER)

Figure 4.9 ⊳4 000

Consumer energy spending, subsidies and end-user investment
for efficient, low-emissions equipment in the buildings andtransport sectors in the STEPS and NZE Scenario by 2030
Spending and subsidies

End‐use investment
Direct fossil
fuel subsidies
Energyspending
End‐useinvestment

3 000

2 000

1 000

2021

STEPS
2030

NZE
2030

2021

STEPS
2030

NZE
2030
IEA. CC BY 4.0.

Poorly targeted subsidies in the buildings and transport sectors comeat the expense of much-needed structural changes in energy use
Note: MER = market exchange rate.

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In the NZE Scenario, more emphasis on energy efficiency and fuel switching lowers consumer
energy spending in 2030 compared to the STEPS. However, poor households still require
financial support if they are to spend less than 10% of their income on household energy.
This scenario sees direct fossil fuel subsidies eliminated. However targeted forms ofaffordability support may play a role, such as energy rebates, social tariffs or bill repayment
assistance. Energy‐ or carbon‐based taxes more than offset the value of these supports in
the NZE Scenario. This helps to channel government financial support to those most in needwhile reducing overall energy subsidy burdens substantially. It also frees fiscal resources tosupport the upfront costs required to improve end‐use energy efficiency. The reduction in
subsidy burdens in 2030 in the NZE Scenario relative to the STEPS could support households
bear up to half of the additional upfront investment costs for efficiency and fuel switching.

Table 4.1 ⊳Selected affordability and support measures specific to
low income households
Targeted Progressive Effective Implementable

Affordability support for energy use
Price caps, discounts or direct fuel subsidies

●

●

●

●

Low income tariffs

●

●

●

●

Energy rebates and direct transfers

●

●

●

●

Tax credits for retrofits/upgrades

●

●

●

●

On‐bill repayment or ESCO models

●

●

●

●

Low income rebates

●

●

●

●

Minimum efficiency level requirements for renting

●

●

●

●

Transferring repayment for upgrades with the property

●

●

●

●

Public, multi‐unit EV charging

●

●

●

●

Improving mass transit access

●

●

●

●

Efficient new construction of low income housing

●

●

●

●

● Moderate● Low

Financial support to manage upfront costs

4

Shifting onus to reduce energy cost

Investing in enabling infrastructure● Strong

Notes: ESCO = energy service company; EV = electric vehicle. Targeted refers to the ability of the policy
measure to be directed to a selected subset of the population. Progressive implies that the price support
benefits low income individuals more than others. Effective refers to the ability of the policy measure to enable
low income individuals to use the energy needed and benefit from energy cost‐saving measures.
Implementable refers to the ease with which these policy measures can be put in place, as well as to the costs
incurred by governments.

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This transformation is easier said than done, and progress has been mixed in recent years.
One challenge is garnering public support in the face of opposition from those who stand tolose access to direct fuel subsidies. Another is developing the capacity to target welfare
payments. In some cases this depends on better social security infrastructure as well as
improved data on energy use and household income. As these challenges are overcome,energy subsidies can shift over time towards better focused support, which ideally should betargeted, progressive, effective and implementable (Table 4.1).

4.4

Collaborate to bring down the cost of capital in emerging market anddeveloping economies
The high cost of capital is a major obstacle to deploying clean energy
infrastructure in many emerging and developing economies. Mitigating
economy‐wide and sector‐specific risks is essential to unlock timely,
cost‐effective investment.

The most recent evidence presented in the World Energy Investment 2022 (IEA, 2022f) showsthat, after remaining flat for several years, global clean energy spending is finally picking up
and is expected to exceed USD 1.4 trillion in 2022. However, almost all of the growth is taking
place in advanced economies and China. Moreover, over 90% of the USD 1.1 trillion
earmarked for clean energy as part of post‐pandemic stimulus packages is contained in theplans of advanced economies. Despite having two‐thirds of the global population, clean
energy investment in emerging market and developing economies, excluding China4, accountfor less than one‐fifth of the total.
This shortfall in investment in emerging market and developing economies is cause for alarm.
If there is no accessible pathway towards low‐emissions inclusive growth for these
economies, then either growth will be high carbon, or it will be constrained by a lack ofenergy. Both of these possibilities are associated with immense risks. Clean energy
investment is attractive from an economic perspective, especially during the current periodof high and volatile fossil fuel prices. It is also the most cost‐effective way for the world to
avoid future emissions: IEA analysis has shown that the average cost of emissions avoidancein emerging market and developing economies is around half the level in advanced
economies (IEA, 2021a). So why are these investments not taking place?
One of the key barriers hampering clean energy investment in emerging market anddeveloping economies is the high cost of capital. The cost of capital is a measure of the risk
associated with projects in different jurisdictions; it expresses the expected financial return,or the minimum required rate, for investing in a company or a project. This expected returnis closely linked with the degree of risk associated with a company or project cash flows (IEA,
2021b). A high cost of capital hampers prospects for investment, particularly for capital‐
intensive investments, including renewables that require large upfront capital costs but havevery low operating expenditures.

4

Emerging market and developing economies in this section exclude China.

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One obstacle to assessing this issue has been a lack of available data on the cost of capital at
the project and corporate level, especially for emerging market and developing economies.
This acts as a barrier to investors looking to direct capital into these regions, and also
undercuts the possibilities of evidence‐based conversations with policy makers on the main
perceived risks and ways to mitigate them. In recognition of wide data gaps, a Cost of CapitalObservatory was launched in September 2022 by the IEA, the World Economic Forum, ETH
Zurich and Imperial College London to increase the visibility and availability of data on
financing costs in the energy sector and to inspire investor confidence.
Table 4.2 ⊳Indicative weighted average cost of capitalof utility-scale solar PV projects, 2021
Cost of debt
(after tax)

Cost ofequityShare ofproject debt

WACC
(nominal, after tax)

Europe2.5% ‐ 3.0%

6.0% ‐ 11.0%

75% ‐ 85%

3.0% ‐ 5.0%

United States

3.0% ‐ 3.5%

5.0% ‐ 7.0%

55% ‐ 70%

3.5% ‐ 5.0%

China

3.5% ‐ 4.0%

7.0% ‐ 9.0%

70% ‐ 80%

4.0% ‐ 5.5%

Brazil

11.5% ‐ 12.0%

15.0% ‐ 15.5%

55% ‐ 65%

12.5% ‐ 13.5%

India

8.0% ‐ 9.0%

12.5% ‐ 13.5%

65% ‐ 75%

9.0% ‐ 10.5%

Indonesia

8.5% ‐ 9.5%

12.0% ‐ 12.5%

60% ‐ 70%

9.5% ‐ 10.5%

Mexico8.0% ‐ 8.5%

12.0% ‐ 12.5%

60% ‐ 70%

9.5% ‐ 10.0%

South Africa

8.0% ‐ 9.0%

12.0% ‐ 14.0%

65% ‐ 70%

9.5% ‐ 11.0%

4

Notes: WACC = weighted average cost of capital. Values are expressed in local currency. The values for Brazil,
India, Indonesia, Mexico and South Africa are based on the survey of the Cost of Capital Observatory,
https://www.iea.org/data‐and‐statistics/data‐tools/cost‐of‐capital‐observatory.

Higher costs of capital and rising borrowing costs threaten to undercut the economic
attractiveness of clean energy investment in emerging market and developing economies,
even in countries that possess rich renewable resources. Financing costs accounted foraround half of the total levelised costs of a solar PV plant that reached final investment
decision in these regions in 2021, notably higher than the 25‐30% equivalent in advanced
economies and China (Figure 4.10). This inevitably affects inward investment levels.

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Our analysis, based on a survey of investment practitioners and experts in various countries,
revealed that the cost of capital for a typical solar PV plant in 2021 was between two‐ andthree‐times higher in emerging market and developing economies than in advanced
economies and China (Table 4.2). This was driven not only by higher country risk, which isreflected in higher rates for sovereign bonds, but also by higher sectoral risks that translate
into higher premia for debt and equity, and by a lack of bankable projects. The risks include
regulatory risk, off‐taker risk and land acquisition risk. Regulatory risk arises from asuboptimal or unpredictable energy policy, the lack of robust infrastructure planning or
inefficient market designs. Off‐taker risk stems from the financially distressed position of
distribution companies, which are often the principal off‐takers for developers: this can leadto delays in the signature of power purchase agreements and in payments under thoseagreements, weighing on financing costs. Land acquisition risk comes from lengthy andcomplex permitting processes and the absence of available grid infrastructure. The lack ofbankable projects is often associated with lower market depth and experience in financing
clean energy projects.

Figure 4.10 ⊳ Composition of levelised cost for a utility-scale solar PV plantwith final investment decision secured in 2021
100%
80%
60%
40%
20%

EuropeUnitedChina
StatesFinancing costs

South
MexicoIndia
Indonesia
BrazilAfricaCapital cost
Operation and maintenance
IEA. CC BY 4.0.

Financing costs are around half of total levelised costs in emerging market and developing
economies, which is significantly more than in advanced economies and China

The current macro‐economic context weighs further on the prospects for lowering the costsof capital. A growing number of central banks are currently opting for contractionary
monetary policies to tackle inflation, and the US dollar is looking strong. In this kind ofenvironment, borrowing costs tend to rise faster in emerging market and developing
economies than in advanced economies because of higher economic uncertainty andinvestor preference for creditworthy issuers against projects with higher return and risk
profiles.

Improving access to domestic capital through more robust banking and capital markets is as
important as international measures. Governments and regulators have an important role inmitigating risks by providing revenue stability or other guarantees to enhance the cash flows
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Concerted efforts to lower the costs of capital in emerging market and developing economies
could bring major energy security benefits by unlocking capital flows to support clean energy
projects in those countries. The IEA, together with the World Bank and the World Economic
Forum, proposed a series of priority actions based on more than 40 on‐the‐ground casestudies (IEA, 2021a). Additional financial and technical support, including concessional
capital, private sector capital and inflows from international carbon markets, will all be
crucial. For example, financial support from Brazil’s national development bank (NDB) was
key to the provision of low cost, locally denominated loans to renewable power projects, ata time when market‐based interest rates were relatively high. As the sector matured, thebond market rose too and the role of the NDB shifted from direct financing to catalysing
capital.

of clean energy projects, incentivising the participation of private capital and putting
state‐owned enterprises on a sound financial footing. This applies especially to projects to
expand and modernise electricity grids. The issue of limited bankability projects could betackled with detailed least‐cost plans for infrastructure deployment and regional integration.
Figure 4.11 ⊳ Cumulative reduction in clean energy financing costs in

Trillion USD (2021, MER)

emerging market and developing economies by lowering costsof capital in the APS and NZE Scenario, 2023-2050

20
End‐use4

Supply
15
Power
10

5

APS

NZE
IEA. CC BY 4.0.

Lowering costs of capital by 200 basis points could reduce the cumulative clean energy
financing costs in emerging and developing economies by up to USD 15 trillion to 2050
Note: MER = market exchange rate.

5
One basis point is equal to 1/100th of 1%, or 0.01%. 200 basis points are equal to 2%. 200 basis points
correspond to roughly 15‐20% of current cost of capital on an after‐tax basis.

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If the costs of capital were to be lowered by 200 basis points 5 in emerging market anddeveloping economies, this would reduce the financing costs for clean energy by acumulative USD 11 trillion over the period to 2050 in the APS and by USD 15 trillion in the
NZE Scenario (Figure 4.11). These reductions correspond to 20% of total clean energy
investment requirements, including financing costs.

4.5Manage the retirement and reuse of existing infrastructure carefully,
some of it will be essential for a secure journey to net zero emissions
Unplanned, chaotic or premature retirement of existing fossil fuelinfrastructure could have negative consequences for energy security as
well as for people. New and old systems will exist side‐by‐side during thetransition, and effective management of their interactions is essential.

Shutting down fossil fuel infrastructure as quickly as possible is often assumed to be a
primary task of clean energy transitions, but this assumption needs some qualifications. The
speed at which fossil fuel infrastructure can safely be retired depends crucially on the speed
at which clean energy technologies are deployed and fossil fuel demand declines. Moreover,even in the NZE Scenario in 2050, when no CO2 is emitted on a net basis, fossil fuel use does
not fall to zero. Around 100 EJ of fossil fuels per year are still consumed in 2050 in this
scenario, either in conjunction with CCUS, or in sectors where clean technology options are
scarce, or for non‐energy purposes, notably as feedstock for the chemical industry. Anotherkey point is that some existing infrastructure can be reused and repurposed to support theclean energy economy. While much of the infrastructure for the clean energy economy has
to be built anew, electricity grids remain the backbone of electricity security, and natural gas
networks could be used to transport biomethane (without any modification) and hydrogen(with modifications). Parts of oil refineries could be recast as bio‐refineries. Some sites
previously used to store natural gas, notably salt caverns, could be repurposed to storehydrogen.
The energy security perspective is important, as consumers have very low tolerance forunreliable or very expensive energy. Even in very rapid energy transitions, fossil fuels andtheir infrastructure perform certain functions that will remain critical to the reliable
operation of the energy system as a whole, and the infrastructure in question will need to be
maintained. The task for policy makers is to identify what needs to be maintained andmanaged, and why, and then to ensure that the necessary work is carried out. Premature or
unplanned removal of these assets could be disruptive: three examples are highlighted.

Role of natural gas‐fired power in providing flexibility

There are already signs that investors are readying gas for this role. Open‐cycle gas turbines
are better suited than closed‐cycle gas turbines to business cases calling for flexibility andfirm capacity procurement, despite being less efficient. Among the gas‐fired plants that
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In energy transitions, the role of natural gas‐fired power in many energy systems has toadapt. Average utilisation rates fall over time and the main task for gas‐fired power plants
becomes the provision of flexibility, ramping output up and down in response to the needsof the system, rather than providing large volumes of electricity on a more consistent basis.
The average utilisation of gas‐fired plants in the APS worldwide falls from 40% today to 31%
by 2035, and to 18% in the NZE Scenario.

reached final investment decisions in 2021, the share of open‐cycle gas turbines increased
to 22%, twice the level in 2016.
As transitions progress towards net zero emissions, this role for gas‐fired power needs
eventually to be supplanted by other forms of flexibility that do not result in emissions. These
include supply‐side options such as low‐emissions gases (biogases and hydrogen) as well as
demand‐side measures, long duration energy storage and higher levels of interconnection
between systems. However, these alternatives take time to be available at scale. Meanwhilesome other existing forms of flexibility – notably coal‐fired power – decline quickly, and therequirement for flexibility rises rapidly as variability increases on both the supply anddemand sides (see section 4.7). More extreme variations in weather patterns may add to thisvariability in the years ahead, and thus to the requirement for flexibility. For these reasons,the importance of gas‐fired power for electricity security actually increases in many countries
before falling again, especially in systems with significant seasonal variations in demand. In
the European Union, natural gas demand for power generation halves to 70 bcm in 2030 in
the APS. However, peak requirements for natural gas go up over the same period eventhough overall or aggregate demand goes down (Figure 4.12).

4

Figure 4.12 ⊳ Load duration curve for natural gas-fired power generation

Capacity factor

in the European Union in the APS
100%
80%
60%
40%
2021
2025
2030

20%

Days (peak → trough)
IEA. CC BY 4.0.

Sorting gas-fired generation from the highest to lowest utilisation rates over a year reveals

Against this backdrop, maintaining reliable electricity systems requires that natural gas will
be deliverable and gas‐fired power plants remain available in times of stress for the system,
notably when high electricity and gas demand coincides with low availability of variable
renewables. This cannot be taken for granted.

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a vital balancing role, even as the annual contribution of gas to power demand declines

Lower utilisation can mean lower profitability, and gas‐fired power plants may close if
markets do not appropriately remunerate the flexibility and other services that they
provide.



Pressure on operators has been exacerbated by extremely high and volatile prices,which have led to discussions about capping revenues for gas‐fired capacity, and raised
broader questions about the role of gas in transitions (see Chapter 8).



Deliverability requires that networks and storage are still capable of managing peaklevels of gas demand (see discussion on gas infrastructure).

Against this backdrop, it is vital for governments to ensure that the design of electricity
markets recognises the value of flexibility from gas‐fired plants as well as other sources offlexibility, and that gas‐related contingencies are included in regular adequacy assessments
conducted by countries relying on this source of flexibility.

Refining and product supply for the residual ICE vehicle fleet
The rise of electric mobility necessarily involves an extended period during which vehicles
using gasoline or diesel will be operating side‐by‐side with electric vehicles (EVs), with eachrequiring well‐functioning infrastructure to deliver the fuel and electricity they need. Analysisof changes in the transport sector understandably focuses on the shift to EVs in new car sales,
which is proceeding rapidly in some markets. Even in those markets, however, it will taketime for the entire stock of vehicles to change (Figure 4.13).
Figure 4.13 ⊳ Stock and flow of passenger cars by type in the APS

Million vehicles

Sales

Stock

150

2 500

Naturalgas ICE

120

2 000

Gasoline/
diesel ICE

90

1 500

60

1 000

30

500

2021

2030

2040

2050

2021

FCEV
EV

2030

2040

2050
IEA. CC BY 4.0.

Even in scenarios that feature rapid reductions in sales of ICE cars,

Notes: FCEV = fuel cell electric vehicle; ICE = internal combustion engine; EV = electric vehicle, which includes
battery electric and plug‐in hybrid models.

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oil use in road transport does not disappear quicklyIn markets where ICE vehicles sales are banned, oil demand for transport does not disappear
immediately. For example, the European Union consumes just under 5 million barrels perday (mb/d) of oil products today for road transport. In the APS, this falls to just over 2 mb/din 2035, the year when ICE vehicle sales cease for passenger cars and light commercial
vehicles. Ten years later it stands at 0.6 mb/d, with freight making up an increasing share ofresidual consumption. A similar pattern is visible at the global level in the NZE Scenario,
where all sales of ICE passenger cars and two/three‐wheelers cease in 2035, but there is stilla sizeable tail of these vehicles on the road by mid‐century.
As with gas‐fired power, these transitions worsen the economics of traditional refinery
operations (see Chapter 7). Refiners do not just have to cope with a change in overall levelsof demand, but also with changes in the composition of demand, and both have major
implications for business models. Our transition scenarios all show an increase in the shareof lighter products (often used in petrochemicals, a sector where demand is relatively robust)alongside a reduction in the output of traditional refined products used in the transport
sector, such as gasoline and diesel.

4

Today, refiners typically earn most of their profit from selling gasoline, diesel and jet fuel.
Prices for petrochemical feedstocks – the main sources of demand growth – often trend
lower than crude oil prices. In theory, lower profits in one area could be compensated byhigher prices for products in high demand such as naphtha and LPG. While it is conceivablethat the revenues of these products may increase to some degree, it is hard to envisage arise that fully compensates for the reduction in road transport fuels sales. As we have seen
in recent years (and also in the mid‐1980s), low margins prompt rationalisation of refinery
capacity and closures. This is a natural response to changing market conditions, but it comeswith risks to security of supply: the retirement of refineries may leave gaps in product supply
or result in more vulnerable supply chains for the delivery of certain products to consumers.
There is a need for dialogue between governments and refiners on how to manage thisreduction in traditional refining activity, and for steps to be taken to monitor national andinternational supply chains for vulnerabilities that may require attention or action. Theremay be a case in some instances for governments to work with refiners to chart a way
forward in the interests of energy security. Australia, for example, is providing support to its
last two refineries to stay open, in return for accelerated commitments to switch to
producing low sulphur fuels.

A third area requiring close attention is natural gas networks. This is a particularly difficult
area, because the networks sit at the intersection of different visions of how transitions
should play out. On one side there is the “electrify everything” approach, in which electricity
not only increases its share substantially in final consumption (as it does in all our scenarios)
but becomes the dominant or even the sole vector for most consumers. This route requires
a massive build‐out of clean electricity generation and infrastructure, and the role of existinggas networks in this vision is marginal – the main policy issue is how to manage their decline.
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Right sizing and repurposing gas networks

On the other side are those arguing that most current natural gas pipelines can eventually
be repurposed to carry low‐emissions gases, whether biogases or low‐emissions hydrogen,so grids need to be maintained (and in some cases expanded).
Starting points for this debate differ. Nearly all countries have an extensive electricity gridfor delivering power to consumers, but the extent of gas infrastructure varies considerably.6
Where it has been built, in many cases the gas network provides a larger and more flexible
energy delivery mechanism than the electricity network. In Europe and the United States,
gas networks deliver between 50‐100% more energy on average to end‐consumers thanelectricity grids.
Switching from gas to electricity brings major efficiency gains, but replacing gas entirely withelectricity would bring practical challenges, especially if it proves difficult to expand theelectricity network quickly due to permitting issues or public opposition. There is an energy
security rationale for maintaining overlapping infrastructure and, indeed, most countries
that have considered how to realise rapid and wholesale emissions reductions are looking at
a future in which electricity and gas networks play complementary roles.
However, these roles are often not well defined in practice, and this creates risks. Without awell co‐ordinated approach to the provision of power, gases and heat, the different networks
are unlikely to evolve in a harmonious way. For example, there is a distinct possibility of gas
infrastructure suffering “death by a thousand cuts” as individual consumers migrate to using
electricity. Those making the move are likely to be better‐off households in a position to
make the upfront investment in electrified heating systems. This could in turn have
distributional implications as poorer consumers, along with some industries, would continue
to rely on existing infrastructure and, under existing tariff structures, would need to shoulder
a higher share of its fixed costs.
To avoid these kinds of outcomes, there is a need for early and co‐operative resource
planning among electric and gas utilities and network operators, mediated by governments
to ensure that the outcomes are consistent with rapid, secure transitions that minimise costs
to consumers. This kind of ongoing dialogue, informed by changing technology anddeployment trends, can contribute to developing a coherent vision of where gas networks
have long‐term viability (and where they need to be decommissioned), and how gas andelectricity grids can work together to contribute to rapid reductions in emissions.

The role of gas networks is determined in many cases by the need for winter heating; in countries where
seasonal fluctuations in demand are lower (including many developing economies), gas networks tend to besmaller in size.

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6

4.6

Tackle the specific risks facing producer economies
Countries that rely heavily on fossil fuel revenues face particularchallenges and potential strains in energy transitions, with major
potential knock‐on effects for energy security – and emissions – if they are
unsuccessful in moving to the new energy economy.

Producer economies today face a complex set of strategic choices. The need for change isunavoidable, and development prospects for any country or company pursuing business‐as‐usual will be bleak, but there are also downsides for those that move away from current
business models without a clear strategy for what comes next.

4

The world’s hydrocarbon producers and exporters have faced many periods of volatility inthe past, but few that have matched the wild swings seen in prices since 2019. In the past,these fluctuations have typically been correlated closely with changes in government
spending in oil and gas dependent economies, with a boom in spending when prices are high,and a bust when they fall. These pro‐cyclical patterns of spending have had destabilising
effects on domestic consumption, private investment and the economy as a whole.
In recent years, there has been a slew of announcements of new strategies that aim to breakthis cycle and promote more resilient economies, some taking the form of roadmaps fordiversification, such as the Vision 2030 in Saudi Arabia launched in 2016, and others focusing
on reforms to smooth spending cycles, such as the decision by the United Arab Emirates tointroduce five‐year budgets. The surge in oil prices and revenues in 2022 provides anopportunity to take stock and ask the question: is this time different?

There are some signs of change too in the way that increased revenues are being spent in
the energy sector. Spending on oil and gas infrastructure has increased, with upstream
investment above 2019 levels. But so too has spending on renewables, even among the morefiscally constrained producers: in 2021, renewables investment in the Middle East and North
Africa rose by 60% from 2019 levels, and 2022 is likely to see a further rise. Algeria, forinstance, launched a tender for 1 gigawatt (GW) of solar PV capacity in mid‐2022, while Iraq
announced an ambitious target to produce a third of its electricity with renewables by 2030
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It is likely too soon to tell definitively, and the answer may depend on how long oil and gas
prices stay at high levels and whether windfall revenues introduce a complacency that stifles
reform. However, there are a number of provisionally positive signs. For instance, Saudi
Arabia’s 2022 budget is based on an oil price of around USD 75/barrel, below the prevailing
price. This is coupled on the expenditure side by a 6% decrease in planned spending,reflecting a cautious approach that is geared to replenishing its financial buffers. In Iraq,
where oil revenues have broken historical records this year, windfalls are likewise being
saved, though this mostly reflects the political impasse that has prevented the country frompassing a budget, and has therefore forced it to constrain expenditure to the same level aslast year.

and is conducting talks with European, Middle Eastern and Chinese partners on renewables
projects with a combined capacity of 5 GW. In Saudi Arabia, a USD 5 billion project to developa renewable hydrogen sector was agreed in mid‐2020. Oman has made clear its intention to
use the current period of increased export revenue to boost investment in its zero‐carbonhydrogen sector, which it sees as essential to its efforts to decarbonise existing energy‐
intensive industries.
Box 4.1 ⊳Could hydrogen exports replace hydrocarbon income in the
Middle East?

Energy transitions present obvious challenges to development models dependent on oil
and gas, and therefore have huge implications for the hydrocarbon‐rich economies of the
Middle East (Figure 4.14). But could these countries have comparative advantages inproviding the fuels of the future as well? The idea is attracting a lot of attention, with
low‐emissions hydrogen providing a beguiling vision of continuity for some producers,
based on ample reserves of natural gas, plenty of options for geological storage of CO2,
and outstanding potential for renewables to produce hydrogen by electrolysis.
Figure 4.14 ⊳ Export revenue from oil and gas versus hydrogen in the
Middle East in the APS and NZE Scenario, 2021-2050

Billion USD (2021, MER)

APS

NZE

600

Fossil fuels
Coal

500

Natural gas
400

Oil

300

HydrogenSynfuels

200

Ammonia100

Hydrogen
2021

2030

2050

2030

2050
IEA. CC BY 4.0.

Exports of hydrogen and hydrogen-rich fuels are no substitute for the revenues coming

IEA analysis confirms the competitive edge that many Middle East countries have as
producers of hydrogen, but also that hydrogen exports are not going to be more than apartial substitute for current hydrocarbon revenues. In the STEPS, hydrogen is projectedto earn around USD 15 billion in revenues by mid‐century, which is only around 1% ofcombined oil and gas revenues in the same scenario. In the APS, hydrogen export

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from fossil fuels, though they could provide a durable source of economic advantage

revenues are expected to rise to levels equivalent to one‐fifth of the revenues from oil
and gas over the same period. It is only in the NZE Scenario that revenues cross over andhydrogen becomes more lucrative for the Middle East – albeit at significantly lower levels
than those seen historically for hydrocarbons.
Export earnings for hydrogen as a fuel are not likely to be more than a very partial
replacement for oil and gas exports (Box 4.1). This is hardly surprising, given that many
countries have the potential to produce hydrogen and that there are therefore very limited
resource rents on offer; the projected market size for hydrogen also remains well below thatof oil and gas today. Nonetheless there are very good reasons for countries with acomparative advantage in low‐emissions hydrogen to move in that direction. Export earnings
for fuels, however, are not the big prize on offer. The major long‐term opportunity is rather
the ability of today’s hydrocarbon exporters to become global leaders in the manufacture –and export – of low‐emissions industrial products and chemicals.

4

Several producers are studying ways to ensure that their energy transition efforts areintegrated into their economic diversification strategies, including by assessing how existing
supply chains, expertise and support industries might be repurposed for clean energy
technologies such as low‐emissions hydrogen. First movers stand to benefit not only fromexports of clean energy but also from the value created domestically by the establishmentof new clean energy industries. Oman, for example, is working to identify the potential touse low‐emissions hydrogen in industry, which currently accounts for half of its natural gas
consumption.7 As well as potentially creating anchor consumers for low‐emissions hydrogen,this approach could allow Omani industries to become competitive in markets where carbon
border adjustment mechanisms begin to reward the lowest emitting producers. Suchmechanisms including those that impose a price based on the emissions intensity of
production, or consumer pressure for low‐emissions goods, may lead other prominent
producer economies that have focussed diversification efforts on encouraging
energy‐intensive industries to follow Oman’s example (Spotlight).

S P O T L I G H T
New criteria for the location of energy-intensive industries?

7

Including chemical feedstock and energy sector own use.

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Energy‐intensive industries such as refining, chemicals, steel and iron, cement andaluminium production could be deeply affected by energy transitions and possible
accompanying price volatility. In Europe, high natural gas and electricity prices since
September 2021 have already reduced the region’s aluminium production capacity bynearly half (Eurometaux, 2022). The financial position of companies could be further
affected by a variety of carbon pricing schemes, including carbon border adjustment

mechanisms. All this is putting rising pressure on energy‐intensive industries to find ways
to reduce their emissions. Each energy‐intensive sector and technologies vary, but deep
emissions reductions are typically associated with switching to low‐emissions electricity,using low‐emissions fuels (which could be produced with renewables, as with electrolytic
low‐emissions hydrogen) or adopting CCUS.
Factors that influence decisions about the location of a plant traditionally include
proximity to consumers, access to raw materials and a skilled workforce, and tax andother financial incentives. These elements remain important, but additional criteria may
emerge in a world transitioning to clean energy. These could include access tolow‐emissions electricity, scope to make use of renewable resources and proximity to
CO2 storage sites. Future investment in energy‐intensive industries is likely to favour
regions with outstanding clean electricity and CCUS potential in particular.
Our detailed geospatial analysis suggests that sustainability and carbon considerations
have not featured prominently in past decisions regarding the location ofenergy‐intensive industries. Today some 40‐70% of plants are located in regions where
the carbon intensity of the grid is very high (above 600 tonnes of carbon dioxide
per‐gigawatt‐hour [t CO2/GWh]). Only around a third of plants are located in regions withhigh solar PV potential8 (the share is lower for the iron and steel sector). Around 70% of
capacity in key regions, e.g. China, the European Union and the United States, however,is located within 100 km of potential storage for CO2 (and 35% is located within 10 km)
although it does not necessarily mean that CCUS will be technically and commercially
feasible in any given location (Figure 4.15). To put these distances into context, theaverage distance over which CO2 is currently transported by pipeline between existing
CCUS facilities is around 180 km.

8Above 4.2 kilowatt‐hour per kilowatt peak.

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While the endowment of renewable resources and potential sites for CO2 storage are
more or less fixed, there is still a lot that individual countries can do to foster an attractive
low‐emissions environment for energy‐intensive industries. The carbon intensity of thegrid could be reduced significantly by scaling up the deployment of low‐emissions power
generation sources. Technology innovation means that solar power generation is now
affordable even in regions with less favourable resource potential, and wind power is also
becoming more affordable in a number of countries. The viability of CCUS could beboosted through a range of targeted measures, e.g. regulatory levers, public
procurement, low‐emissions product incentives and tax credits. Supporting industrial
clusters with shared CO2 transport and storage infrastructure is also proving to be aneffective development strategy. New business models separating the components of the
CCUS value chain and developing multi‐user transport and storage networks thatindustrial facilities can access (CCUS hubs) could also help. Other possible measures
include ensuring accessibility to renewables‐based electricity, for example via powerpurchase agreement contracts, and nurturing innovative technologies. As global efforts
to reduce emissions expand, building an environment conducive to decarbonisation is
likely to emerge as a key strategy to attract large‐scale industrial investment.
Figure 4.15 ⊳ Current distribution of energy-intensive industries by gridcarbon intensity, solar potential and proximity to CO2 storage
Refining

Grid carbon intensity
Solar PV potential

Chemicals

Proximity to CO2 storage

4

Grid carbon intensity
Solar PV potential

Iron and steel

Proximity to CO2 storage
Grid carbon intensity
Solar PV potential
Proximity to CO2 storage

CementGrid carbon intensity
Solar PV potential

Aluminium
smelter

Proximity to CO2 storage
Grid carbon intensity
Solar PV potential
Proximity to CO2 storage
20%
Grid carbon intensity (t CO2/GWh)
Solar PV potential (kWh/kWp)
Proximity to CO2 storage

> 600
<3.6
> 100 km40%
464‐600
3.6‐4.2
50‐100 km

60%
250‐464
4.2‐4.8
10‐50 km80%
100%
Share of capacity
< 250
> 4.8
< 10 km
IEA. CC BY 4.0.

Proximity to cheap renewables and geological storage are set to emerge as key
factors in determining the future location of energy-intensive industries
Notes: t CO2/GWh = tonne carbon dioxide per gigawatt‐hour; kWh/kWp = kilowatt‐hour per kilowatt peak.
The proximity assessment for CO2 storage sites has been done for selected regions only, i.e. China,
European Union and United States. Some facilities, such as aluminium smelters, have dedicated power
supply facilities separate from the grid and are thus less affected by grid carbon intensity.

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Sources: IEA analysis based on European Commission (2022); Global Solar Atlas (2022); US DOE (2018);
S&P Global (2022).

4.7

Invest in flexibility – a new watchword for electricity security
Modern economies depend on electricity, putting the spotlight onmeasures to ensure the reliable and flexible operation of a system thatfeatures higher variability in both supply and demand, and on steps toensure resilience against new cybersecurity threats.

Electricity is at the heart of modern economies, supporting many fundamental aspects ofdaily life across the economy. It accounts for about 20% of total final consumption today,
and this is set to increase in all scenarios, reaching 28% in the STEPS in 2050, 40% in the APS
and about 50% in the NZE Scenario. The rising share of electricity in final consumption puts
electricity security firmly in the overall energy security picture, along with oil and natural gas.
Electricity security means having a reliable and stable supply of electricity which is able tomeet demands at an affordable price. Electricity supply has always required the capability tomeet demand continuously, down to the scale of seconds or less, in order to maintain systemstability. This is currently achieved by means of a set of managed power generatorsconnected to demand centres through grid lines. However, power systems are becoming
more complex, and variability is increasing in terms of both supply and demand. Electricity’scentral role in modern life means that shortages or outages have the potential to do
immense damage and impose billions of dollars of costs per day on national economies;
these costs will only increase as electricity comes to account for an ever larger share ofoverall energy consumption.
Maintaining electricity security in the power systems of tomorrow calls for new tools andapproaches. Power generators will need to be more responsive and agile, consumers willneed to be more connected and adaptable, and grid infrastructure will need to bestrengthened and digitalised to support more dynamic flows of electricity and information.
Power systems will also need to adapt to both changing climate and weather patterns andchanging consumer behaviour.

The rising share of variable wind and solar PV electricity generation adds to the need for
future flexibility on the supply side. Changes in electricity demand and supply profiles
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The expansion of electricity into new sectors is one of the changes making the task ofmaintaining electricity security more challenging. The progressive electrification of roadtransport, heating, industrial processes and electrolytic hydrogen production will reshapeload curves and has the potential to make demand more variable. The increasing use ofelectric heat pumps and air conditioners, for example, will make demand more temperature‐sensitive, while the proliferation of EVs increases the risk of rapid variations in demandcaused by uncontrolled charging (although it also creates additional opportunities fordemand‐side response via smart charging or vehicle‐to‐grid technology). The variability ofelectricity demand is set to increase in all countries and in all scenarios, with the level ofvariation being higher in the APS than in the STEPS, and most of all in the NZE Scenario.

together are set to increase the call on the providers of power system flexibility.9 All thesefactors indicate that flexibility will be a new watchword for electricity security. In the STEPS,
global power system flexibility needs more than triple by 2050.10 In the APS, they double in
the period to 2030 and increase 3.5‐fold by 2050, while in the NZE Scenario, they more thanquadruple between today and 2050 (Figure 4.16).
Figure 4.16 ⊳ Flexibility needs and supply by region and scenario
Flexibility supply

Index (2021 = 1)

Flexibility needs

100%

6
APS

Demandresponse
Batteries
Other lowemissions
Other
renewables
Hydro
NuclearUnabatedfossil fuels

80%

4
60%

STEPS
2

40%

UnitedStatesEuropean
Union

China

2050

2030

2050

2030

2050

2030

2050

2030

20%

India

4

2021 STEPS APS
2050
IEA. CC BY 4.0.

Flexibility needs rise in all scenarios and vary substantially by country; a broad range oftechnologies and approaches is required to ensure electricity security

Most of the flexibility required to maintain power system reliability today is provided bydispatchable thermal power plants and hydropower. Sharply rising flexibility needs andchanges in the composition of the power plant fleet – with the phase‐out of large unabatedcoal‐fired thermal power stations in many regions – see the share of flexibility demand
served by thermal power plants drop to roughly a third in the STEPS and a quarter in the APS,
down from around two‐thirds today.
This increases the need for alternative sources of flexibility to maintain grid stability andsecurity of supply. Reinforced power grids and additional interconnections can help even out
fluctuations in the supply of weather‐dependent variable renewables, within and between
countries and regions; they can also connect additional providers of flexibility to the system.
Certain grid assets, such as high voltage direct current interconnections, can also provide
flexibility services like fast ramping or voltage control directly.

10
Flexibility needs are represented by the hour‐to‐hour ramping requirements after removing hourly windand solar PV production from hourly electricity demand, divided by the average hourly demand for the year.

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9Flexibility is defined as the ability of a power system to reliably and cost effectively manage the variability ofdemand and supply across all relevant timescales. It ranges from ensuring the instantaneous stability of thepower system to supporting long‐term security of supply.

All three scenarios show battery storage emerging as an important flexibility option in powersystems characterised by high shares of variable renewables. The pace of deployments picks
up dramatically: global battery storage capacity increases nearly 50‐fold in the STEPS, rising
to more than about 1 000 GW by 2050. In the APS this is 80% higher, reaching about
2 300 GW by2050, with over 420 GW already installed by 2030. In the APS, batteries provide
close to a quarter of the flexibility needed in 2050 in advanced economies and only slightly
less than that in emerging market and developing economies. Other storage technologies
also play important roles: pumped hydro is the largest source of electricity storage today andis set to increase further over the next ten years (IEA, 2021c). Hydrogen and ammonia are
emerging as solutions for the seasonal storage of renewable electricity (IEA, 2021d).
Demand‐side response is another emerging option for the provision of electricity system
flexibility. It helps to align consumption with the available supply, reducing the need for othersources of flexibility. The progressive electrification of further end‐uses is set to provide
additional opportunities for load shifting, with EVs and electric heating playing a major part.
In 2050, demand‐side response provides roughly a quarter of power system flexibility in bothadvanced economies and emerging market and developing economies in the STEPS and APS.
Tapping this potential, however, will require further changes to regulatory frameworks andsignificant investments in digital infrastructure (Box 4.2).
Box 4.2 ⊳Enhancing resilience in the face of increasing cybersecurity risks

Electricity systems are becoming increasingly digitalised, bringing many benefits toelectricity consumers, utilities and the system as a whole. However, increasing
connectivity and automation and the rising number of connected devices and distributed
energy resources are raising risks to cybersecurity. Threat actors are also becoming
increasingly sophisticated both in terms of their destructive capabilities and ability toidentify vulnerabilities. Although electric utilities and cybersecurity experts note the highand growing threat of cyberattacks, quantitative indicators of this growing threat are notavailable since most cybersecurity incidents are never publicly reported (or evenreported to authorities).

Electric utilities face several challenges to address growing cybersecurity risks, including
a lack of strategic attention, a tendency to harbour institutional silos, a limited set ofresources and personnel, and a lack of information sharing between organisations. While
preventing all cyberattacks is not possible, electricity systems can and must become
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Several cyberattacks on electricity systems have been documented over the past decade,including attacks on the power grid in the Ukraine in 2015 and 2016 that resulted in major
outages (IEA, 2021e). Recent attacks on electric utilities in India and Ukraine werethwarted and did not result in outages. While disruptions to electricity systems as a resultof cyberattacks have so far been relatively small compared to other causes, a successful
cyberattack could trigger an operator’s loss of control over devices and processes,
causing physical damage, service disruption and millions of dollars in damages.

more resilient to cyber attacks. This means designing systems in ways that enable themto withstand attacks and quickly absorb, recover or adapt, while preserving the continuityof critical infrastructure operations.
Policy makers, regulators, utilities and equipment providers all have important parts toplay in ensuring the cyber resilience of the entire electricity value chain. The role of policy
makers, however, is particularly central. They are best placed to take the lead in raisingawareness of the issues, and working continuously with stakeholders to identify, manage
and communicate emerging vulnerabilities and risks. Policy makers are also ideally placed
to facilitate partnerships and sector‐wide collaboration, develop information exchange
programmes and support research initiatives across the electricity sector and beyond.
Effective collaboration can help to improve understanding of the risks that eachstakeholder poses to the electricity system and vice‐versa.

4

Different countries have taken various policy and regulatory approaches: some haveadopted highly prescriptive approaches while others have chosen framework‐oriented,
performance‐based models. Regardless of the approach taken, cyber resilience policies
need continuous review and adaptation, particularly as further decentralisation anddigitalisation of the electricity sector shifts the risk exposure to the grid edge. Effective
policies now need to look beyond bulk utilities and consider the entire electricity chain,including supply chains.

4.8

Ensure diverse and resilient clean energy supply chains

Clean energy transitions require a strong focus not only on traditional elements ofinternational energy security relating to the supply of fossil fuels, but also on the supply ofthe minerals, materials and manufacturing capacity needed to deliver clean energy
technologies. As clean energy transitions accelerate, demand for critical minerals from theenergy sector is set to soar. In the APS, demand for critical minerals for clean energy
technologies is 2.5‐times higher by 2030 and quadruples by 2050 (Figure 4.17). In the NZE
Scenario, an even faster deployment of clean energy technologies implies four‐time higher
demand for critical minerals in 2030 and 2050 than today. In the NZE Scenario, lithium sees
the fastest rise among the key minerals, with demand surging by 26‐times between today
and 2050 while demand for cobalt (6‐times), nickel (12‐times) and graphite (9‐times) also
rises rapidly. At 2021 prices, the value of the minerals used in clean energy technologies
increases over fivefold, reaching around USD 400 billion by 2050 in the APS and in the NZE
Scenario.
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High and volatile critical material prices and highly concentrated clean
energy supply chains could delay energy transitions and make them morecostly. Policies to promote diversified supply as well as demand‐side
innovation are essential.

Figure 4.17 ⊳ Critical mineral demand by weight and value for clean energy
technologies by scenario
By value (at 2021 prices)

Billion USD (2021, MER)

Mt

By weight
40
30
20
10

400

Other
Cobalt300

Manganese
Lithium

200

Graphite
Nickel

100

APS
NZE

2050

APS
NZE

APS
NZE

2030

2021

APS
NZE

2021

Copper

2030

2050
IEA. CC BY 4.0.

Critical mineral demand for clean energy technologies quadruples already by 2050
in the NZE Scenario, with particularly high growth for EV-related minerals
Notes: Mt= million tonnes. 2021 prices are used to calculate the monetary value of critical minerals.

As energy sector dependence on minerals grows, so too will the importance of securing
adequate supplies of sustainable and affordable critical minerals. There are importantdistinctions to be made between critical mineral security and oil or gas security: a price spikefor oil affects all consumers driving oil‐fuelled cars; a shortage or price spike in criticalminerals affects only the production of new EVs or solar panels for the market. As recent
price increases make clear, however, supply chain disruptions and rising mineral costs
threaten to increase the cost of clean energy technologies and slow their deployment.

The risk of supply chain disruptions and volatile prices is exacerbated by the fact that clean
energy technology supply chains are highly concentrated. Critical minerals extraction isgeographically concentrated, with a single country accounting for over half of global
production of several key minerals, notably graphite (China, 79%), cobalt (Democratic
Republic of the Congo [DRC], 70%), rare earth elements (China, 60%) and lithium (Australia,55%). The level of concentration is even higher for processing operations, with China
dominating across the board.
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Higher mineral prices mean that critical minerals now account for a significant and rising
share of the total cost of clean energy technologies, contributing to an uptick in costs since2020, which reversed a longstanding trend of cost reductions (see Chapter 2). Getting thesecosts back on a continued downward trajectory requires more robust and resilient mineral
supplies, alongside a redoubling of efforts to reduce costs by other means, including throughtechnological innovation, recycling, efficiency improvements and economies of scale.

Chapter 4 | Energy security in energy transitions

Figure 4.18 ⊳ Indicative supply chains for oil and gas and selected clean energy technologies

IEA. CC BY 4.0.

Transition to a clean energy system brings new energy trade patterns, countries and geopolitical considerations into play219

Notes: DRC = Democratic Republic of the Congo. Largest producers and consumers are noted in each case to provide an indication, rather than a complete account.

IEA. CC BY 4.0.

4Clean energy technology manufacturing and assembly are also highly concentrated, with
China accounting for three‐quarters of the manufacturing and assembly of solar PV modules
and EV batteries (Figure 4.18). The capital‐intensive nature of manufacturing and its
technical complexities also mean that it also tends to be dominated by a small number ofcompanies. Just three companies accounted for 65% of global battery cell production in
2021, for example.
Alongside risks from high prices and supply chain issues, there are also significant risks
associated with the environmental, social and governance (ESG) impacts of mining projects.
Ensuring an adequate supply of minerals for clean energy transitions requires concerted
efforts to address and minimise the ESG impacts of mining and mineral processing, such as
human rights violations, bribery and corruption, tailings management, water use, air
pollution, CO2 emissions and loss of biodiversity. Clean energy transitions must be carriedforward using minerals that prioritise the mitigation of these impacts to align withsustainable and people‐centred transitions that policy makers and the public are increasingly
demanding.
Figure 4.19 ⊳ Public reports of governance-related risks by mineral
supply chain and region, 2017-2019
MineralCobaltCopperLithium
NickelAluminium
Other CM
RegionDRC
Rest of Africa
Asia Pacific
C & S America
Rest of world

Child labour
Corruption
Forced labor
Non‐state armed groups
Human rights abuses
Abuse of force by
security forces
Non‐payment of taxes
Other
50

100

150

200

250 300 350
Number of reports
IEA. CC BY 4.0.

ESG risks could impact mineral supply chains across every region,
particularly for cobalt and copper
Notes: CM = critical minerals; DRC = Democratic Republic of the Congo; C & S America = Central and SouthAmerica. Other critical minerals include chromium, graphite, lead, manganese, molybdenum, niobium,
platinum, silicon, silver, tantalum, tin, titanium, tungsten, uranium, vanadium, zinc and zirconium.

ESG‐related incidents may also give rise to short‐term mineral supply disruptions with
implications for supply chains and prices (Figure 4.19). After specific incidents of corruption
or human rights abuses come to light, governments may intervene to stop production at
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Source: IEA analysis based on OECD (2021).

projects where illegal activities are going on. Efforts to bring such sites into compliance may
also lead to temporary shutdowns that impact production. These types of risks are especiallyprominent in the cobalt supply chain in the DRC, where artisanal and small‐scale mining isprevalent and where significant allegations of child labour, forced labour and other humanrights abuses have been made (OECD, 2019).
Investing in projects with high standards of treatment for communities and the environmentis essential to improve the resilience of supply chains, as is credibly and transparently
addressing concerns with higher risk projects. In a world with ambitions to reach net zero
emissions by mid‐century, the demand for ethically sourced and sustainably produced
materials is likely to grow rapidly, along with increasing demand for supply chaintransparency and traceability. If supply is unable to keep pace with this growing demand thencompanies may end up competing for a limited pool of these “green materials”, leading tobottlenecks in supply chains.

4

There are also risks in other value chains. Far‐reaching energy transitions imply burgeoning
demand for low‐emissions industrial products such as green steel, green aluminium, green
plastics and near‐zero cement. However, as things stand, there is uncertainty over how
quickly this demand will materialise and at what scale, and no guarantee that theseambitions will be matched by adequate supply. Production costs for many of these
low‐emissions products generally are not competitive with their traditional counterparts,and some technologies such as green steel or near‐zero cement are still at the demonstration
stage. If demand materialises and industry ambition does not scale up in time, the tightsupply of green materials could push up their prices in the coming decades.

From a policy perspective, a comprehensive and co‐ordinated approach is required todevelop and expand global clean energy technology supply chains that are secure, resilientand sustainable. This requires both the scaling‐up and diversification of supplies as well as
the implementation of measures to moderate growth in demand. An increasing number ofprojects have recently been announced to develop domestic supply chains for criticalminerals and clean energy equipment. While these would help diversify supply chains,international trade also has a vital part to play to enable cost reductions and promote
efficiency.

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Early demand signals along with comprehensive policy support are important to send a clear
market signal to suppliers. Incentivising investment in green materials will help to boost
supply and prevent consumers from switching to high emitting materials. This is a matter forcompanies as well as governments, and a growing number of joint governmental andcorporate sectoral initiatives are now seeking to increase the use of green materials. For
example, the First Mover Coalition, including more than 50 participating companies such as
Volvo, Eiffage and Moller‐Maersk, is sending a demand signal for near‐zero aluminium,chemicals, concrete and steel. These initiatives are also establishing a strong link between
improving the overall emissions intensity of heavy industries and the ESG performance ofraw material mining and supply.

Policy should also support further technological innovation, which has already shown its
ability to relieve some of the pressure on primary supplies while also reducing costs. For
instance, silver and silicon use in solar cells over the past decade has been reduced by
40‐50%, while recent low cobalt EV batteries contain 75‐90% less cobalt than earlier versions,although they use twice as much nickel. Reuse and recycling also have a part to play in
reducing the need for primary supplies, while shifting consumer preferences and behaviour
could play a significant role in reducing mineral demand from EVs (Box 4.3). Following a new
mandate from IEA member governments in March 2022, the IEA is expanding its work to help
ensure reliable and sustainable international supplies of critical minerals through market
monitoring, policy tracking and facilitating international collaboration on technology
innovation, supply chain resilience, recycling, and environmental and social standards.
Box 4.3 ⊳Security benefits of shifting consumer preferences and behaviour

Shifts in consumer preferences and behaviour could play an important role in reaching
net zero emissions by 2050, while also offering opportunities to reduce mineral demand,
particularly in transport. For example, consumers tend to prefer larger batteries in EVs
than they actually need, reflecting both range anxiety and a growing preference for larger
and more powerful vehicles such as sport utility vehicles. Between 2015 and 2021,
average battery sizes in light‐duty EVs increased by 60%. If these trends continue, battery
sizes could increase by up to a further 30% by 2030.

Increasing the utilisation of each EV could also reduce mineral demand by reducing theneed for additional new EVs while providing the same level of mobility. Whileconventional mantra posits that the more EVs sold, the better for the climate, in reality,
the emissions benefits of EVs are accrued through its utilisation, not simply its purchase.
This means that attention also needs to be given to the utilisation rate of vehicles (andfor PHEVs, its electric use factor). Encouraging higher and more efficient utilisation ofeach EV could achieve the same (or larger) emissions reductions with fewer new EVs,
helping to alleviate strains on material supply in the near term. Support for car‐sharing
could pay dividends here: vehicles used for car‐ and ride‐sharing typically have muchhigher utilisation rates than privately owned vehicles, and a single shared car could
potentially displace up to 20 private cars (Jochem et al.,2020). Policy measures and222

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Targeted measures to promote EVs with smaller batteries (including plug‐in hybrid
electric vehicles [PHEVs]) could help to reduce mineral requirements, while lighter
vehicles could improve operational energy efficiency and yield safety benefits (Shaffer,
Auffhammer and Samaras, 2021). Measures could include differentiating subsidies bybattery size (or taxing heavier vehicles in the longer term), accelerating the deploymentof charging points to reduce range anxiety and promoting technology innovation aimed
at increasing the energy density of batteries. If the current average range of electric cars
is maintained – resulting in 20‐25% smaller batteries than our base case assumptions
between 2030 and 2050 – mineral demand from EV batteries could be around 20% lower
in 2030 in the NZE Scenario, equivalent to two years of current demand from EV batteries.

investments in public transport and infrastructure could at the same time encourage ashift away from private cars to shared mobility services, active transport and public
transport (see Chapter 3, section 3.8). In the NZE Scenario, these measures result in a
reduction of almost 20% in new passenger car sales in 2050 compared with the STEPS,
avoiding nearly 3 million tonnes (Mt) of material demand for batteries, equivalent toaround three years of current demand.

4.9

Foster the climate resilience of energy infrastructure

4

The growing frequency and intensity of extreme weather events presents
major risks to energy infrastructure and supply, so governments need to act
to ensure that the system has the ability to anticipate, absorb, accommodate
and recover from adverse impacts.
There are growing signs that climate change is driving more frequent extreme weather
events as well as systemic changes in climatic conditions. Average global temperatures havecontinued to rise over the past few decades, and heatwaves have become a regular featureduring the summer period in a variety of regions. Many countries are experiencing marked
changes in rainfall, while tropical cyclones and wind storms are getting more intense. Our
analysis suggests that over 85% of IEA member and association countries 11 are already
exposed to a medium or high level of climate hazard risks. If emissions remain unabated, theworld is likely to experience more frequent and intense climate‐related anomalies.
This poses serious risks to energy infrastructure and threatens reliable energy supplies. For
example, a warmer climate reduces the efficiency of power plants. Maximum electricity
output from a natural gas‐fired plant (combined cycle) begins to decline above a temperatureof 15 °C, while the efficiency of a solar panel generally degrades by 0.3‐0.5% per degree
above a temperature of 25 °C. Standard wind power installations are usually designed for a
25 °C environment and may be shut down above 45 °C to protect critical components fromadditional wear and tear. Thermal power generation has to be curtailed if watertemperatures rise above regulatory thresholds in countries such as the United States, Franceand Germany. In the United States, 13 out of 18 incidents involving power curtailment atcoal‐fired power plants between 2000 and 2015 were related to water temperature needed
for cooling purposes. In an Intergovernmental Panel on Climate Change (IPCC) scenario that
leads to a higher long‐term temperature outcome, the number of thermal power plants
exposed to temperature levels exceeding these thresholds is materially higher than in a
scenario with low‐temperature outcomes (Figure 4.20) (IPCC, 2021).

IEA Association countries include Argentina, Brazil, China, Egypt, India, Indonesia, Morocco, Singapore,
South Africa, Thailand and Ukraine. Ukraine joined as an Association country on 19 July 2022, and so is notincluded in this analysis.

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11

Figure 4.20 ⊳ Share of installed power plant capacity exposed to global
temperature rise under various IPCC AR6 scenarios
Maximum temperature above 35 °C

Coal

SSP1‐2.6
SSP2‐4.5

Gas

SSP1‐2.6
SSP2‐4.5

NuclearSurface temperature

SSP1‐2.6
SSP2‐4.525%<2 °C
3‐4 °C50%75%
2‐3 °C
>4 °C

100%

25%

50%

<20 days
40‐60 days

75%

100%

20‐40 days
>60 days
IEA. CC BY 4.0.

Failure to reduce GHG emissions could expose a large number of fossil fuel andnuclear plants to severe heat stress, endangering reliable electricity supply
Note: Results show long‐term climate projections (2080‐2100) compared to preindustrial levels based on two
IPCC scenarios representing different temperature outcomes (SSP1: 2.6‐2 oC and SSP2: 4.5‐3 oC).
Source: IPCC (2021).

Changes in wind patterns may reduce the output from wind farms and cause electricity grid
failures. The latest IPCC report suggests that global mean wind speed is likely to decrease,with the potential decline being highest in the regions where current major wind power
generators are located, e.g. western United States, northern Europe and East Asia (IPCC,
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Increasing water shortages in dry regions are another source of concern. The production ofmany fuels and minerals such as shale resources, coal mining, copper and lithium mining,
biofuels, and hydrogen production, currently require a considerable amount of water. A
projected decrease in water availability at major production sites could disrupt supply.
Hydropower is also very sensitive to water availability. Hydro generation could decline
significantly in regions where water flows are likely to decrease, such as southern Europe,
North Africa and the Middle East. Thermal power plants could be interrupted by shortages
that affect the water they rely on for cooling. In France, the Chooz nuclear power plant wasclosed for around two months when a severe drought hit in 2020, and several other plants
had to reduce their output in 2022 due to the lack of cooling water. Increasing water stresscould also hinder the deployment of CCUS technology: a plant equipped with CCUS requires
over 50% more water than one without it. Extreme droughts also pose risks to energy supply
chains that rely on the transport of fuels and materials. In 2022, for example, droughts
caused by severe heatwaves in Europe exacerbated low water levels in key rivers such as theRhine River that transport significant volumes of coal, chemicals and other materials.

2021). Wind power generation is proportional to the cube of the wind speed, which meansthat a 10% decrease in wind speed leads to around a 27% reduction in wind power output.12
Lower mean wind speeds are set to co‐exist with the projected intensification of tropical
cyclones. Tropical cyclones that exceed the limit of wind power plants could temporarily halt
their operation and may cause physical damage to turbines. They also risk causing electricity
grid failures by damaging transmission and distribution lines, poles and transformers. It is
worth noting in this context that the active storm season that hit the United States in 2020
led to historical highs in the frequency and length of power outages.
Floods caused by storms and heavy rainfalls could well be another cause of disruption toenergy supplies even though thermal power plants are generally equipped with flood
protection structures. In Bangladesh, for example, more than five gas‐fired power stations inSylhet were shut down pre‐emptively when flood water engulfed them in June 2022. In the
United States, flooding along the Missouri River in June 2011 caused the Fort Calhoun nuclear
power station to close for nearly three years after water leaked into the turbine building.
Floods and heavy rainfall may also lead to disruptions in coal mining and coal‐fired power
plants. When a severe flood hit the Rhenish lignite mining area in Germany in 2021, theconnected 2 GW Weisweiler power station was suspended for several days. Similarly,
three‐out‐of‐four units in coal power plants at Yallourn in Australia were shut for a few daysin 2021 when the coal mine supplying them stopped operations as a result of flooding. Given
that heavy rainfall and floods are likely to increase in many parts of the world, disruptions of
this kind may become more frequent.

4

S P O T L I G H T
What is the financial impact on energy assets from climate risks?
The increase in frequency and severity of climate hazards such as floods or droughts will
have an increasing impact on energy infrastructure assets and their financial viability. By
causing damage to assets such as power plants and refineries and interrupting theirnormal business operations, climate risks can impair the value of assets and in turnnegatively impact company balance sheets.

12

When the wind speed is within the range between cut‐in speed and rated speed.

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We conducted an illustrative analysis of flood risk at four energy infrastructure sites: acoal power plant in Southeast India; a gas‐fired plant in southern Viet Nam, and refineries
in northern Europe and the southern United States (Figure 4.21). A refinery in thesouthern United States currently suffers the highest annual average loss from flooding at
1.1% of its asset value, but this increases only marginally by 2100. A refinery in northern
Europe is also projected to face relatively small increases in annual average losses. The
two power plants in India and Viet Nam have lower annual average losses today than thetwo refineries, but those losses are projected to increase much more rapidly. Both plantscould experience average annual losses that increase to 0.3‐0.6% of asset value by 2050
and reach up to 1.2% by 2100. This reflects the significant projected increase in more
severe and frequent floods at these locations.
The financial impact analysis also shows the benefits of investing in flood defences. The
US refinery used in our analysis has flood defences installed: were it not for this, its
annual average loss would be around four‐times higher.
Figure 4.21 ⊳ Annual average loss of asset value from flooding at four
indicative energy supply infrastructure sites based on two
IPCC scenarios
Coal‐fired plantin southeast India

Gas‐fired plantin southern Viet Nam

Refinery innorthern Europe

SSP1‐2.6

SSP1‐2.6

SSP1‐2.6 SSP2‐4.5
2050

Refinery in
US Gulf Coast

1.5%

1.0%

0.5%

SSP2‐4.5
2021

SSP2‐4.5
2030

SSP1‐2.6
2100

SSP2‐4.5
IEA. CC BY 4.0.

The average annual financial impact of floods could
amount to 0.3-1.2% of total asset value by 2050
Notes: Annual average loss is the mean expected loss per year with changes in severity and frequency(including the probability of hazard events of different scales occurring) taken into account. In any one
year, a large‐scale hazard event such as a flood that happens every 100 years could cause much higher
loss than the annual average. For the purpose of this illustrative analysis, four assets in distinct locations
that have at least some flood risks based on historical data were selected. Projected flood data is basedon the IPCC scenarios: SSP1‐2.6 and SSP2‐4.5 representing different temperature outcomes (SSP1: 2.6‐
2 °C, SSP2: 4.5‐3 °C).

Performing full‐fledged and forward‐looking climate risk assessments and calculating thepotential financial impact caused by climate hazards is still a novel exercise for most
governments and energy suppliers. However, assessments of this kind can support
energy infrastructure planning, identify worthwhile adaptation investments, help protect
the value of energy assets and safeguard their normal operation. Governments should
consider incentivising the uptake and improvement of climate risk assessments by
including them in planning and corporate disclosure regulations as well as in climate risk
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Sources: IEA analysis based on data from Jupiter Intelligence (2022); IPCC (2021); European Commission
JRC (2017).

stress tests. Regulators, central banks and market authorities in jurisdictions such as
Brazil, Canada, European Union, Singapore, United Kingdom and United States have
either already implemented mandatory climate risk assessments or announced theirsupport for them.
A growing catalogue of extreme weather events could also have direct impacts on energy
demand in key end‐use sectors. Rising global temperatures are likely to increase energy
demand for cooling in regions such as southern Europe, south and southeast Asia and the
Middle East, and air conditioner ownership is set to expand rapidly as a result. This may put
extra strain on electricity grids at times of peak demand. Cooling demand in buildings alreadyaccounts for as much as 30% of peak electricity loads in some major markets. Hightemperatures tend to increase it, and the power grid operator in Texas (United States) had
to take emergency measures to avoid blackouts during a heatwave in 2022. Periods ofintense cold also tend to increase electricity demand. In 2022, a cold snap in Australia led toincreased electricity demand that strained the grid system and triggered the first evercurtailment of gas exports and actions to cap energy prices.

4

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Governments need to act to ensure that electricity systems have the ability to accommodate
and recover from adverse impacts caused by extreme weather events. Making reliableclimate and weather data publicly available could help energy suppliers better understandpotential climate risks and impacts, and a combination of regulations and financial support
could facilitate private investment in resilience measures. There is also scope to incentivise
switching to more resilient technologies such as dry cooling systems for thermal power
plants, new designs with enhanced ventilation to enable wind turbines to operate at
temperatures of up to 45 °C and state‐of‐art solar PV cooling technologies. Physical systemhardening has a part to play too, for example by improving floodwalls and dikes aroundpower plants and relocating substations to higher ground and increasing the spillway
capacity at hydropower facilities. Deploying wind power plants with stronger towers,
customised rotor sizes and reinforced foundations in areas prone to tropical cyclones canalso help. Improvement of electricity networks with underground lines, upgraded towers andhighly meshed systems can also reduce potential physical damages from extreme weather
events. Our analysis suggests that the benefits of these measures would generally outweighthe costs over the longer term. Nonetheless, it needs to be noted that reducing emissions is
one of the most powerful measures to limit the exposure of energy infrastructure to various
climate risks.

4.10 Provide strategic direction and address market failures, but do not
dismantle markets
Governments have to take the lead in ensuring secure energy transitions, butthey can be significantly assisted by well‐functioning markets and market
mechanisms that reflect the costs of pollution, by bringing in private capitaland allocating it efficiently.
How should governments view the role of markets in delivering reliable and secure energy
transitions? For some, the urgency of tackling climate change points towards a stronglyinterventionist role for policy and regulation in determining where the energy sector needs
to go; the severity of today’s energy security crisis arguably supports that view. Intervention
is undoubtedly required to deliver emissions reductions and security of supply. Yet the muchneeded transformation of the energy system is unlikely to be efficient if it is managed on a
top‐down basis alone, especially given the scale of the investment required. One way or
another, governments need to harness the vast resources of markets and incentivise private
actors to play their part. To do this effectively they need to put in place stable, predictable
long‐term market frameworks designed to support the achievement of their goals.
One early task for governments is to eliminate distortions and barriers that actively hinder
energy transitions such as lengthy permitting procedures, unnecessary trade barriers,
inefficient fossil fuel subsidies, and outdated market arrangements that favour incumbent
producers and technologies. Fossil fuel subsidies remain pervasive, despite longstanding
efforts to phase them out, including a commitment in the Glasgow Climate Pact to accelerate
efforts for their removal (Box 4.4).
Box 4.4 ⊳Fossil fuel subsidies are back on the rise

One of the most visible costs of fossil fuel consumption subsidies is the fiscal burden thatit imposes on countries. This has been particularly severe among fuel importing countries
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Fossil fuel subsidies are a roadblock to a more sustainable future, but the difficulty thatgovernments face in removing them is underscored at times of high and volatile fuelprices. Consumers demand protection from a rising cost of living, and there is a social
imperative to protect the most vulnerable in society. In the short term, governments
have few instruments at their disposal to respond so they tend to intervene to fix prices
or temporarily suspend levies or other taxes. In addition to these short‐term measures,some governments habitually keep the prices for certain categories of fuels at low levels.
When these interventions hold end‐user prices below a reference price that reflects themarket value of the energy source in question, then we consider these to be a fossil fuelconsumption subsidy. The IEA has tracked these subsidies for many years and, after a
noticeable dip in 2020, they were on the rise again in 2021 (Figure 4.22). The global
energy crisis will certainly prompt another sharp increase in the estimate for 2022.

in 2022. For example, in Malaysia, the government estimates that the budget for fuelsubsidies will reach MYR 30 billion (around USD 7 billion) in 2022, which is equivalent to
12% of national fiscal revenue; MYR 5 billion (about USD 1 billion) was spent in June
alone. In Indonesia, state subsidy spending in 2021 surpassed the budget allocation by
40%, and is set to do the same again in 2022. In fuel exporting countries, the subsidy isthe opportunity cost of foregone revenue, rather than an explicit budget item. The lessvisible costs are felt in the way that subsidies encourage excess consumption of fossil
fuels, and the distorted incentives that they introduce for investment.
Pricing reform is essential, but politically difficult; low cost fuels are often part of theimplicit social contract in many developing economies, especially those with largehydrocarbon resources. Subsidy removal, on its own, is a blunt tool, so efforts in this area
need to be part of a broader strategy that includes efficiency policies to improve thesupply of more energy‐efficient goods and services as well as measures to protect
vulnerable groups. There are a number of examples of successful reform for countries todraw upon. For example, the United Arab Emirates started to gradually phase out
gasoline and diesel subsidies in 2015, when global oil prices were relatively low, thussmoothing the impact on citizens affected by the reform. By 2022, gasoline and diesel
prices in the country were near the global average.

4

Billion USD (2021, MER)

Figure 4.22 ⊳ Fossil fuel consumption subsidies in selected countries
800

600

400

200

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
IEA. CC BY 4.0.

High fossil fuel prices and additional measures to protect consumers during theNotes: MER = market exchange rate. Fossil fuel consumption subsidies in the following countries areincluded in this analysis: Algeria, Angola, Argentina, Azerbaijan, Bahrain, Bangladesh, Bolivia, Brunei,
China, Colombia, Ecuador, Egypt, El Salvador, Gabon, Ghana, India, Indonesia, Iran, Iraq, Kazakhstan,
Korea, Kuwait, Libya, Malaysia, Mexico, Nigeria, Pakistan, Qatar, Russia, Saudi Arabia, South Africa,
Sri Lanka, Chinese Taipei, Thailand, Trinidad and Tobago, Turkmenistan, United Arab Emirates, Ukraine,
Uzbekistan, Venezuela and Viet Nam.

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energy crisis are set to lead to a further sharp increase in fossil fuel subsidies in 2022

Improving market functioning requires attention to be paid to the changing nature of energy
markets, especially in electricity where more and more variable renewables are being added
to systems, complemented by more expensive but dispatchable sources of generation toensure reliability. Most of the latter are currently natural gas‐fired plants, and the current
energy crisis has sparked a debate in many countries about the merits of a market design inwhich expensive gas‐fired power has pushed wholesale prices to very high levels. As theenergy regulatory authority in the United Kingdom recently concluded, current wholesale
electricity markets “may not be configured to deliver net zero at lowest cost to consumers”(Ofgem, 2022).
Another important job for governments is to intervene to correct for market failures. The
over consumption of fossil fuels that cause climate change is a textbook example. In effect,
the absence of a price for carbon makes clean energy technologies less competitive, slowing
the transition from fossil fuels, accentuating energy security vulnerabilities and ultimately
adding to the damage done by climate change. Putting a price on carbon is one way tointernalise these external costs; for the moment, however, less than one‐quarter of global
energy consumption is covered by a carbon price of some description. Carbon pricing has
proved politically difficult to implement in many countries and sectors and, where it exists,
in most cases it plays a supplementary role among a broader suite of regulatory measuresand targets.

The overall scale of investment required to get to a net zero emissions energy system is wellbeyond the capacity of governments to mobilise directly. Over the course of the current
decade, investment in key elements of energy transitions needs to – at least triple – in orderto get on track for net zero emissions by 2050. Private capital will have to provide the bulkof the investment, although public finance institutions will be essential in a number ofmarkets to catalyse this spending and help improve the bankability of clean energy projects
where the private sector does not yet see the right balance of risk and reward (Figure 4.23).
Overall, we estimate that 70% of the investment required in energy transitions needs tocome from private sources. This does not mean leaving everything to the market: over 95%
of current investments in the electricity sector worldwide rely on regulated revenues ormechanisms to manage price risks. But competitive procurement, such as auctions, is vitalto deliver efficient investment on this scale, and to keep costs down for consumers.
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Technology innovation and early stage deployment is an area where markets tend to underinvest because of high costs and risks. Deploying public funds or providing tax incentives
helps to counteract these obstacles; in order to get to net zero emissions by 2050, innovation
cycles for early stage clean energy technologies need to be more rapid than has typically
been achieved historically. Bringing early stage clean energy technologies to market by 2030
requires going from first prototype to market around 20% faster on average than thequickest energy technology developments in the past, and around 40% faster than was thecase for solar PV. Demonstration projects in sectors where economies of scale favour large
installations, such as for sustainable fuels and industrial decarbonisation, are generally thehardest to fund without public support (IEA, 2022g).

Figure 4.23 ⊳ Sources of finance by sector in the NZE Scenario, 2026-2030
100%
Private80%
Public
60%
40%
20%

4
Energyefficiency

Low‐emissions
fuels

Solar PVWindElectricity
networks
IEA. CC BY 4.0.

Public finance, though its role varies by sector, cannot cover more than a fraction of
total investment requirements, yet it needs to act as a catalyst for private capital

Proceeding with energy transitions in a secure way also requires work by governments to set
frameworks and to co‐ordinate actions. The energy sector in most countries consist of a mixof regulated monopolies, state‐owned enterprises and market‐driven private players, whiletransitions require involvement from various levels of government and buy‐in fromconsumers. Markets will need to be guided by overall government strategy and to operate
within regulatory frameworks informed by this strategy in order to ensure coherent andwell‐sequenced actions across multiple areas (see section 4.5).

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Well‐functioning international markets are also valuable to energy security because they
allow trade flows to respond to price signals and scarcity. This was demonstrated in 2022
when higher natural gas prices in Europe were able to attract additional destination‐flexible
LNG cargoes, albeit at the expense of buyers elsewhere. There are also hopes thatinternational carbon markets may play a positive role in advancing energy transitions, nowthat governments have reached an agreement on the rules governing international carbon
markets (Article 6 of the Paris Agreement) at COP26. Around 85% of new or updated
Nationally Determined Contributions (NDCs) have indicated that they plan to use or will
possibly use these markets to reach and go beyond NDCs ambition, and voluntary markets –mostly used by corporate entities – have also been expanding rapidly. These markets are stilldeveloping, and will need more transparency to counter scepticism about theirenvironmental integrity if they are to flourish, but could play a useful role in complementing
large‐scale direct mitigation.

Conclusion
The global energy sector is going through a fundamental transformation. While moving
towards net zero emissions brings clear and sustained security benefits, the process oftransition also entails risks. As energy systems become more interconnected, complex anddiverse, new security considerations are emerging alongside traditional energy security risks.
The traditional watchwords for energy security – notably the importance of diverse energy
sources, supplies and routes – remain as relevant as ever, but they are joined by new
considerations and challenges. Tackling new potential hazards may look daunting in light ofthe current crisis, but ignoring them would be infinitely worse.

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It is worth remembering that, although the crisis in the 1970s brought a great deal of
economic difficulty and hardship, it also acted as a trigger for energy diversification and rapid
technological innovation. It should also be noted that a secure energy system can only beachieved with proper investment in security mechanisms that provide appropriate buffers inthe system. Since the oil crisis in the 1970s, the world has long invested in traditional aspectsof energy security, including the foundation of the IEA, which provided a backbone of today’s
energy security framework. The current energy crisis reaffirms the need to invest in theframework that anticipates new energy security risks in an era of decarbonisation.

Chapter 5
Outlook for energy demand
Old habits hard to kick?
S U M M A R Y
 A gloomy economic outlook leads to lower projections of energy demand growth in
this Outlook than in last year’s edition. High energy prices, heightened energy security
concerns and strengthened climate policies are putting an end to a decade of rapid
progression for natural gas; its annual demand growth slows to 0.4% from now to2030 in the Stated Policies Scenario (STEPS), down from 2.3% from 2010 to 2019. Coalsees a temporary surge in demand in some regions from the power and industry
sectors in response to increases in natural gas prices, but efforts to reduce emissions
soon put coal into decline again, ending the decade with demand 9% lower than
today. Renewables, notably solar PV and wind, gain the most ground of any energy
source this decade, accounting for 43% of electricity generation worldwide in 2030,
up from 28% today. Oil demand rises 0.8% per year to 2030, but peaks soon after ataround 103 million barrels per day as electric vehicles (EVs) and efficiency gains
undermine its prospects.

 The tone for accelerated clean energy development this decade in advanced
economies is being set by new policy packages and government plans and targets,notably those set out in: Inflation Reduction Act (United States); RePowerEU plan and
Fit for 55 package (European Union); Climate Change Bill (Australia); and GX Green
Transformation (Japan). While not all national energy and emissions targets arereached in the STEPS, advanced economies still see declining demand for all fossil
fuels by 2030 – a first in the STEPS. However, these measures take time to roll out.
Short‐term actions are needed to reduce dependency on fossil fuel imports thiswinter, especially in Europe, which includes an important role for consumers in termsof behaviour change. In emerging market and developing economies, demand forfossil fuel rises more slowly than in previous versions of the STEPS, notably for natural
gas in Asia. The slowdown in fossil fuel demand growth is led by China, where slowing
economic growth and policy efforts lead to a peak in emissions during this decade.
in the STEPS on the assumption that countries meet their national net zero emissions
pledges, including those announced by India and Indonesia since the World Energy
Outlook 2021 (WEO‐2021). All sectors accelerate progress on electrification andenergy efficiency compared to the STEPS, with notable acceleration of EVs and electricheating in the transport and buildings sectors. Renewables meanwhile rise rapidly inthe power sector and account for nearly 50% of electricity generation by 2030. These
outcomes require end‐users to spend more upfront in the APS on efficient and low‐emissions equipment, but the cost of this equipment declines faster in the APS thanin the STEPS due to economies of scale.

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 In the Announced Pledges Scenario (APS), fossil fuel use declines further by 2030 than Energy‐related emissions in the STEPS continue to increase in the next two years
before starting to decline in the mid‐2020s. They fall to 36.2 gigatonnes of carbon
dioxide (Gt CO2) in 2030 – slightly below current levels. In the APS, they are down
further to 31.5 Gt CO2 by 2030 as governments take early and ambitious action withthe aim of delivering significant reductions in emissions in this decade, together withimprovements in air quality. The private sector plays an important role in the APS,
with almost 800 companies pledged to reach net zero emissions, including throughsector‐wide initiatives for steel, cement, aviation and shipping. However, even theactions in the APS are well short of what is needed in the Net Zero Emissions by 2050
(NZE) Scenario.

 In the developing world, high prices and inflation are slowing progress towards
universal access to modern energy. The number of people without electricity is likely
to rise in 2022 for the first time in decades. Setbacks in sub‐Saharan Africa threaten
to erase nearly all the progress made there since 2013. Meanwhile surging prices forliquefied petroleum gas (LPG) may drive up to 100 million people that use it forcooking to revert to traditional fuels. These headwinds mean that the projected
number of people without access in 2030 is higher in the STEPS this year than it wasin the WEO‐2021. The APS projects more progress, but achieving all relevant country‐
level access targets still only gets halfway to universal access for both electricity andclean cooking by 2030. Full achievement of universal access by 2030 will require more
ambitious targets, effective implementation measures and higher levels ofinvestment.

 Around 5 billion people live today in areas with substantial needs for space cooling.
However, only one‐third of households have an air conditioner, mostly in advanced
economies. By 2050, climate change and population growth increase the number ofpeople with substantial cooling needs to 7 billion. Electricity demand for space coolingapproaches 5 200 terawatt‐hours (TWh) in the STEPS as the number of air
conditioners rises from the current 1.5 billion to 4.4 billion by 2050, with 90% of theincrease in emerging market and developing economies. Growth in demand is cut by
more than 50% in the APS as a result of determined efforts to improve the efficiencyof air conditioners and with the use of passive cooling measures in buildings.

 Peak oil demand moves forward from the mid‐2030s in the STEPS to the mid‐2020s in

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the APS, largely as a result of the faster adoption of EVs. In the APS, EVs account forover 35% of global car sales by 2030, and for more than 50% of sales in China, theEuropean Union and the United States. As a result, the electric car market in 2030 is
six‐times its size in 2021. This reflects targets to phase out internal combustion engine(ICE) vehicles in 36 countries as well as plans by major manufacturers to pivot to EV
production.

Clean cooking

Progressing towards
universal access tomodern energy
0.75

STEPS 2030
1.88

APS 2030
0.78Electricity

0.66

2021
2.38 Billion people without access to...

0.29

Universal accessin NZE 2030

Decoupling emissions
from growing demand

Progress made in the STEPS by2030 falls short of countries’
targets in the APS. The APS is alittle over halfway to reaching
SDG 7.1: universal access toclean cooking and electricity.

Renewables are the fastest growing energy source in many
regions, and CO2 emissions fall to 36.2 Gt in the STEPS – slightly
below current levels, and to 31.5 Gt in the APS, a 14% reduction
compared to current levels.

EJ

Gt CO2CO2 emissions

40

4
2010-1920

STEPS
2021-302

APS
2021-30

0

0

-20

-2

-40

Coal
United States
European Union
China
India
Southeast Asia
International aviation and shipping

Oil

Natural gas

Renewables

Other advanced economies
Other emerging market and developing economies
Middle East
Africa-4

Introduction
The current energy crisis is reshaping previously well‐established demand trends. Industries
exposed to global prices are facing real threats of rationing and are curbing their production.
Consumers are adjusting their patterns of energy use in response to high prices and, in somecases, emergency demand reduction campaigns. Policy responses vary, but in many
instances they include determined efforts to accelerate clean energy investment. This means
an even stronger push for renewables in the power sector and faster electrification ofindustrial processes, vehicles and heating. 1 As many of the solutions to the current crisis
coincide with those needed to meet global climate goals, the crisis may end up being seen in
retrospect as marking a critical turning point in the drive for both energy security andemissions reductions.
This chapter explores how these developments come together to reshape energy demand
trends. In the first part, projections in the Stated Policies Scenario (STEPS) and Announced
Pledges Scenario (APS) are examined by fuel, by region and by sector, with a particular focus
on the period to 2030, and are compared to those from the Net Zero Emissions by 2050 (NZE)
Scenario. The chapter also analyses how CO2 emissions, air pollution and investment are
being affected by new developments, and looks at what further action is needed to meetnational net zero emissions pledges. In the second part of the chapter, three key themes are
explored: how the current crisis is affecting the drive to achieve universal access to electricity
and clean cooking; how energy efficiency policies can temper electricity demand for cooling;and how the rapid uptake of EVs is leading to an earlier peak in oil demand.

Scenarios
5.1

Overview

High energy prices, a sobering economic outlook and policy responses to energy security
concerns lead to lower projected energy demand growth to 2030 in this STEPS and APS thanin the WEO‐2021. Consumers are forgoing purchases in the face of market uncertainty andhigh prices, and industry is scaling back production. The duration of the energy crisis remains
highly uncertain, but there is likely to be a correlation between its duration and the damage
it does to long‐term economic prospects.

1

The Future of Heat Pumps, a forthcoming World Energy Outlook Special Report will be published in late 2022.

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Economic growth to 2030 is slower than previously projected, which means lower levels ofactivity in all sectors and in turn lower energy demand growth. Despite a strong economic
rebound from the Covid‐19 pandemic in 2021, the current crisis has reduced projections ofglobal GDP growth to 3.3% per year through to 2030 (see Chapter 2). Energy demand rises
more slowly in both the STEPS and APS as a result, and the energy sources used to meet thisdemand change substantially from previous projections. In the STEPS, the world grapples
with today’s energy price shocks, with some regions reverting to previous trends while otherswith stronger decarbonisation policies see a faster shift to renewables and end‐useelectrification. Primary energy demand is set to increase in the STEPS by around 1% a year
to 2030, which is largely met through increased use of renewables (Figure 5.1). The APS sees
the same trends, but governments, companies and citizens take additional measures toensure that the response to these trends is consistent with long‐term climate ambitions,which have been strengthened by new commitments since the WEO‐2021 (see section 5.3).
In the APS, energy demand is set to increase by 0.2% a year to 2030.
Total energy supply by fuel and CO2 emissions by scenario

800

40

600

30

400

20

200

10

2021

STEPS APS NZE
2030

Gt CO₂

EJ

Figure 5.1 ⊳Other
Renewables
NuclearNatural gas
OilCoal
CO₂ emissions(right axis)

5

STEPS APS NZE
2050
IEA. CC BY 4.0.

Renewable energy increases more than any other energy source in each scenario;
CO2 emissions hold at current levels in the STEPS to 2030, but drop14% in the APS

Natural gas sees the largest slowdown of any fuel in the STEPS compared to the WEO‐2021,
with annual growth falling to around 0.4% from 2021 to 2030, ending the decade withdemand at around 4 400 billion cubic metres (bcm) per year. Concerns about enduring highprices have lasting effects across all sectors. New gas power plant construction slows, withcountries opting for other sources to maintain system adequacy and flexibility while
accelerating renewables in parallel. Energy demand in industry also slows in the face of astronger push for the electrification of new industrial capacity. Policy interest in compressed
natural gas (CNG) vehicles wanes, and global efforts to reduce natural gas use accelerate theelectrification of heating in buildings. In the APS, natural gas use begins to decline this decadeand demand falls to less than 3 900 bcm in 2030, an 8% reduction from current levels.
Emerging market and developing economies still see growth, but this is more thanoutweighed by advanced economies using 460 bcm less natural gas in 2030 than today, withthe decreases primarily in the power and buildings sectors. In the NZE Scenario, natural gas
declines to under 3 300 bcm by 2030 as policies restrict the sale of fossil fuel boilers inbuildings after 2025 and as the use of renewables in power generation accelerates.
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Notes: EJ = exajoule; Gt CO2 = gigatonnes of carbon dioxide; STEPS = Stated Policies Scenario; APS = Announced
Pledges Scenario; NZE = Net Zero Emissions by 2050 Scenario.

Coal demand rebounded strongly in 2021 to over 5 600 million tonnes of coal equivalent(Mtce) as economies recovered from the pandemic and as some countries – notably India
and China – turned to domestically produced fuel sources in the interests of affordability andenergy security. This surge is not a long‐term one in any of our scenarios. In the STEPS, coaldemand remains near its historic peak for the first‐half of the decade, but returns to
structural decline in the second‐half of this decade. Increased demand in industry to 2030 isconcentrated in emerging market and developing economies, where coal already accounts
for 35% of energy use in industry. In the APS, coal demand declines more rapidly, falling by
175 Mtce each year from 2025 to 2030 to 4 540 Mtce in 2030, compared with 5 150 Mtce in
the STEPS. Coal use falls in power generation as the use of renewables increases. It also
declines in industry, where there is an acceleration of green steel production, a general shift
away from coal in cement kilns and a sharp reduction in the use of coal for the provision of
low‐temperature heat in light industries. In the NZE Scenario, coal demand falls to around
3 000 Mtce in 2030 and all coal subcritical power plants are phased out by that date.
Oil demand is set to increase by 0.8% per year this decade in the STEPS, but the uptake ofEVs causes oil demand to peak at around 103 million barrels per day (mb/d) in the mid‐2030s
as declining demand in advanced economies outweighs continuing demand growth inemerging market and developing economies. In the APS, oil demand reaches a peak in themid‐2020s as sales of passenger EVs rise reflecting national and corporate targets, withcurrent oil prices and policy support increasing consumer appetite for all‐electric or plug‐in
hybrid vehicles. EVs account for 20% of global car sales by 2025, up from 9% today (seesection 5.8). In the NZE Scenario, oil demand declines to 75 mb/d in 2030 as the roadtransport sector undergoes rapid electrification, and electric cars account for 60% of global
car sales by 2030.

Nuclear power generation increases by 2030 in both the STEPS and APS, with China
accounting for the largest growth. (See Chapter 6, section 6.3 and IEA, 2022a). The use of
low‐emissions hydrogen and hydrogen based‐fuels also increase by 2030, thanks to early
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Renewables continue their rapid ascent in the STEPS, expanding faster than any other sourceof energy. Accelerated electrification creates more headroom for renewables and they
increasingly out‐compete other sources of generation in most regions. The share of
renewables in electricity generation rises from 28% in 2021 to 43% in 2030, with wind andsolar PV alone accounting for nearly 90% of the increase in electricity generation to 2030. In
the APS, renewables deliver nearly 50% of power generation globally by 2030 as theG7 countries make progress towards achieving their commitment to decarbonise power by2035. The increase of renewables worldwide outpaces electricity demand growth to 2030 in
the APS, decreasing the share of fossil fuel generation. Wind and solar PV continue todominate the growth in renewable electricity, complemented mainly by hydropower,
bioenergy and geothermal. The use of biofuels also increases to 5.5 million barrels of oil
equivalent (mboe/d) in 2030 from 2.2 mboe/d today, aided by wider adoption of blending
requirements. In the NZE Scenario, wind and solar PV expand even more rapidly; by 2030
annual capacity additions exceed 1 050 gigawatts (GW).

commercial‐scale projects in industry initiated by emerging public‐private partnerships(Box 5.1). In the NZE Scenario, the use of low‐emissions hydrogen and hydrogen‐based fuels
is three‐times higher in 2030 than in the APS.
In aggregate, these trends are projected to increase energy‐related CO2 emissions in the
STEPS in the coming years, although emissions are still set to peak by 2025. Emissions thenfall to 36 Gt CO2 by 2030, 0.4 Gt CO2 lower than today (Table 5.1). In the APS, annual
CO2 emissions peak before 2025 and then fall to 32 Gt CO2 by 2030. Progress is made onaccess to electricity and clean cooking in the APS as the pledges made by various countries
are met in full, but still falls short of achieving universal access by 2030 (see section 5.6).
Table 5.1 ⊳Key energy indicators by scenario, 2010-2050
STEPS

APS

NZE

2010

2021

2030

2050

2030

2050

Population without access to electricity

1 392

754

663

727

292

112

0

0

Population without access to clean cooking

2 916 2 386 1 880 1 601

783

535

0

0

5

2030 2050

Access (million people)

Premature deaths from (million people):
Ambient air pollution

n.a.

4.2

4.8

7.1

4.6

6.5

3.3

2.9

Household air pollution

n.a.

3.6

2.9

3.0

1.6

1.9

1.0

1.2

Energy‐related CO2 emissions (Gt)

32.9

36.6

36.2

32.0

31.5

12.4

22.8

0

0

0.04

0.1

0.4

0.5

4.3

1.2

6.2

CO2 captured via CCUS
Primary energy supply (EJ)

542

624

673

740

636

629

561

532

Share of unabated fossil fuels

81%

79%

74%

61%

69%

34%

59%

10%

Energy intensity of GDP (GJ per USD 1 000, PPP)

5.1

4.3

3.4

2.2

3.2

1.9

2.9

1.6

Electricity generation (1 000 TWh)

22

28

35

50

36

61

38

73

CO2 intensity of generation (g CO2/kWh)

524

459

325

158

280

41

165

‐5

Share of low‐emissions generation

32%

38%

53%

74%

59%

91%

74% 100%

Total final consumption (EJ)

383

439

485

544

451

433

398

337

Share of unabated fossil fuels

69%

66%

64%

57%

61%

36%

56%

15%

Share of electricity in TFC

17%

20%

22%

28%

24%

39%

28%

52%

Notes: Gt = gigatonnes; CCUS = carbon capture, utilisation and storage; EJ = exajoule; GJ = gigajoule; PPP =purchasing power parity; TWh = terawatt‐hour; kWh = kilowatt‐hour; TFC = total final consumption. STEPS =Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050 Scenario.

Reporting volumes of low-emissions hydrogen

Nearly all hydrogen produced today comes from fossil fuels converted within industrial
facilities such as refineries and chemical plants. Much of this is onsite production, whichmeans the energy balances for these sectors report only the purchased fuel input, suchas natural gas, and not how much hydrogen is produced or used. The increasing interestin new methods of producing and consuming hydrogen means that alternative reporting
processes are needed to enable a full understanding of the roles that hydrogen plays in
the global energy economy in various scenarios.
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Box 5.1 ⊳This Outlook only reports volumes of low‐emissions hydrogen (Table 5.2). This type ofhydrogen is produced from electricity generated by renewables or nuclear, frombioenergy, or from fossil fuels with minimal methane emissions and used with carbon
capture, utilisation and storage (CCUS) or produced via pyrolysis. It can be used as a fuelor chemical feedstock, or transformed into other energy carriers, including electricity, oil
products, biofuels and low‐emissions hydrogen‐based fuels (ammonia, methanol,
synthetic kerosene and synthetic methane). Low‐emissions ammonia is treated as aliquid fuel.
Low‐emissions hydrogen reported in final energy consumption includes those volumes
produced in one facility and transported to another, typically under a merchant contract.
Total low‐emissions hydrogen production is calculated by adding the volumes of low‐emissions hydrogen in final energy consumption to volumes produced onsite and thevolumes used to produce other energy carriers. Reported trade volumes include both
low‐emissions hydrogen and low‐emissions hydrogen‐based fuels.
Table 5.2 ⊳Supply and demand of low-emissions hydrogen and fuels
STEPS

APS

NZE

Mt hydrogen equivalent (energy basis)

2030

2050

2030

2050

2030

2050

Total low‐emissions hydrogen production

6

24

30

225

90

452

Water electrolysis

4

17

21

167

58

329

Fossil fuels with CCUS

2

8

9

57

31

122

Bioenergy

0

0

0

1

0

2

Transformation

3

10

14

95

50

186

To power generation

0

1

4

19

27

60

To hydrogen‐based fuels

0

3

6

69

18

118

To oil refining

2

5

3

6

2

4

To biofuels

1

1

1

1

3

3

Demand by end‐use sector

3

15

16

131

40

266

Total final consumption

1

10

12

80

31

174

Onsite production

2

4

4

51

9

92

0

3

3

55

15

96

Total final consumption

0

1

3

39

7

68

Power generation

0

2

0

16

8

28

1

5

4

44

18

73

Low‐emissions hydrogen‐based fuels

Trade

IEA. CC BY 4.0.

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Notes: Mt = million tonnes. 1 Mt hydrogen = 120 petajoules. Transformation to hydrogen‐based fuels
incurs energy losses that are the difference between hydrogen inputs to hydrogen‐based fuels and thedemand for these fuels.

5.2

Energy demand

Regional trends
Energy demand in advanced economies declines over the rest of this decade by around 0.5%
per year in the STEPS. In the APS, renewables and electrification increase faster, and fossil
fuel demand is 17% lower in 2030 than in the STEPS. Energy demand is projected to continue
to increase in emerging market and developing economies by over 1.4% per year in the STEPS
through to 2030: China and India alone accounting for nearly half of this growth. Renewables,on average, meet over half of the overall increase in energy demand. Demand also increases
in the APS, although at the lower rate of 0.7% per year. These divergent trends in advanced
economies and in emerging market and developing economies lead to per capita energy
demand in China rising above the level in Europe in both the STEPS and the APS by 2030, but
the changes are not large enough to bring any other major alterations in existing regional
patterns of energy use (Figure 5.2).

5In the European Union, climate policies, high fossil fuel prices and efforts to reduce importdependency on Russia combine to reduce fossil fuel demand, despite a temporary
resurgence of coal in the current crisis (Spotlight). Government spending in favour of clean
energy transitions enacted in the framework of national Covid‐19 recovery plans and energy
crisis packages contribute around USD 389 billion to clean energy by 2030, helping spur thisreduction. In the STEPS, demand for coal declines by around half before 2030, and demand
for natural gas and for oil by almost a fifth. Wind and solar PV expand rapidly, and accountfor almost 30% and 15% of electricity generation respectively by 2030, up from 13% and 5%
in 2021. Nuclear power output in the STEPS is consistent with the latest announcements on
closures and extensions. Reductions in natural gas use in buildings and industry are also
responsible for the decline in fossil fuel demand, together with reductions in oil use thatreflect the rise in EV sales. In the APS, targets in the Fit for 55 plan are largely met – and insome cases exceeded – fulfilling the EU's NDC to reduce GHG emissions by 55% by 2030
relative to 1990. In the APS, the uptake of renewables accelerates, and the combined shareof wind and solar PV in power generation in the European Union rises to 50% in 2030. EV
sales also rise at a faster rate than in the STEPS.

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In the United States, the Inflation Reduction Act and the Bipartisan Infrastructure Act
together are set to provide nearly USD 560 billion in public support for clean energy, with
the Inflation Reduction Act alone contributing roughly USD 370 billion, mobilising much morein private investment. This helps to spur progress. In the STEPS, coal demand falls by three‐quarters to 2030, largely driven out by increasing shares of solar PV and wind (Figure 5.3).
Natural gas demand increases for a few years, but peaks before 2030, and ends the decade
just under the level it reached in 2021. Oil demand falls by 1 mb/d from nearly 18 mb/d today
to nearly 17 mb/d in 2030, driven largely by rising EV sales (EVs account for 30% of car sales
in 2030) and fuel economy improvements. In the APS, a more rapid uptake of EVs –accounting for 50% of car sales in 2030 – brings about a reduction in oil demand of over
1 mb/d by the end of the decade.

Total modern energy supply per capita by region in the STEPS
and APS, 2021 and 2030

Figure 5.2 ⊳GJ per capita

2021
200
100

No access tomodern energy

GJ per capita

1 000

2 000

3 000

5 000

6 000

7 000

8 000
9 000
Million people

6 000

7 000

8 000
9 000
Million people

6 000

7 000

8 000
9 000
Million people

STEPS 2030

200

100

4 000

No access tomodern energy
1 000

2 000

3 000

4 000

5 000

GJ per capita

APS 2030
200

100

No access tomodern energy
1 000

AfricaC & S America
Eurasia

2 000

3 000

4 000

Other developing Asia
EuropeOther Asia Pacific

5 000

India
China
North America

Southeast Asia
Middle East
IEA. CC BY 4.0.

Energy supply per capita declines in advanced economies to 2030 while increasing
elsewhere as incomes rise, but the shifts are modest and existing regional patterns remain

Japan is working to reduce its energy security risks while pushing forward with its climate
agenda through measures to decrease exposure to imported fossil fuels, increase its shareof nuclear and renewables, and improve energy efficiency. In the STEPS, these policies leadto an annual decline in total energy supply of 1% in line with the targets laid out in theStrategic Energy Plan approved in October 2021. In the APS, further electrification of industry
and boosted energy efficiency improvements based on the new Energy EfficientTechnological Strategies and strengthening of the Top Runner programme reduce demand
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Notes: GJ = gigajoule; C & S = Central and South America. Modern primary energy demand excludes traditionaluse of solid biomass. The country/regional blocks show only people with access to modern energy.

further, as do new materials standards for building construction and further electrificationof the transport sector, in line with national decarbonisation pledges. Decarbonisation of thepower sector in the APS reflects the recent Green Transformation Plan that aims to step up
the restart of its nuclear reactors and to introduce further measures to support
manufacturers of nuclear technology.

UnitedStates2010‐192021‐30 STEPS
2021‐30 APS

EuropeanUnion

2010‐192021‐30 STEPS
2021‐30 APS

Japan

2010‐192021‐30 STEPS
2021‐30 APS

China

2010‐192021‐30 STEPS
2021‐30 APS

India

2010‐192021‐30 STEPS
2021‐30 APSSoutheast
Asia

2010‐192021‐30 STEPS
2021‐30 APS

AfricaChange in total energy supply by region, fuel and scenario,
2010-2019 and 2021-2030

2010‐192021‐30 STEPS
2021‐30 APS

MiddleEast

Figure 5.3 ⊳2010‐192021‐30 STEPS
2021‐30 APS

5

‐20

0
Coal

Natural gas

20
Oil

Renewables

40
EJ
NuclearOther
IEA. CC BY 4.0.

demand for all sources rises in most emerging market and developing economies

Chapter 5 | Outlook for energy demand

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Advanced economies shift significantly from fossil fuels to renewables this decade, while

S P O T L I G H T
I save, you save, we save
Energy savings at the level of the individual or household can make a sizeable difference
to reductions in energy demand and related emissions, provided that policies are put inplace to enable and support individuals to change behaviour. In the wake of Russia’s
invasion of Ukraine, the IEA released A 10‐Point Plan to Reduce the European Union’s
Reliance on Russian Natural Gas and A 10‐Point Plan to Cut Oil Use in March and April
2022 (IEA, 2022b, IEA, 2022c). Drawing on these, the IEA also released Playing My Part in
April 2022, which identifies actions that national and local governments can take tosupport consumers to reduce demand and unlock more energy savings (IEA, 2022d). If all
the Playing My Part recommendations were to be implemented in full, it would save
220 million barrels of oil a year and around 17 bcm of natural gas, cutting households
energy bills on average by more than EUR 450 per year (Figure 5.4).2
Figure 5.4 ⊳ Oil, natural gas and electricity demand reductions from EU
citizen actions based on the Playing My Part recommendations
Oil (mb/d)Electricity (TWh)Natural gas (bcm)

0.2

5

10

0

0

0

‐0.2

‐5

‐10

‐0.4

‐10

‐20

‐0.6

‐15

‐30

‐0.8

‐20

‐40

Space heating and coolingtemperature
Boiler temperature
Working from home
Using cars economically
Reducing highway speeds
Car‐free Sundays
Walking and biking
Public transportation
Shifting short flights to rail
Net change

IEA. CC BY 4.0.

Behavioural changes could immediately save 0.6 mb/d of oil,17 bcm of gas and 30 TWh of electricity a year
Notes: mb/d = million barrels per day; bcm = billion cubic metres; TWh = terawatt‐hour. The hashed areafor natural gas shows the amount of gas that could be displaced from the reduction of electricity
consumption. Energy impacts of working from home and shifting short flights to rail are net negative andrepresent energy savings. In the Playing My Part report, 0.6 mb/d of oil savings and 17 bcm of natural gas
savings were calculated including indirect fuel savings from lower electricity consumption, which is shown
separately in this figure.

Analysis based on an average across all EU households which will vary between individual households. Energy
bill savings correspond to the savings that can be achieved for representative households, i.e. for households
that can apply these measures, for example, working from home cannot be done for all jobs, thus savings
related to this measure only apply to households for which it is possible.

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2

Citizens can play a major part in realising these reductions. A majority of therecommendations in Playing My Part are concerned with behavioural change. Seeking
behavioural change as part of crisis response is not a novelty and has successfully been
done in the past, notably during the 1970s oil crises and as part of the response in Japanto the Fukushima disaster. Ten countries in the European Union have already
implemented some form of policy to support the behaviour changes laid out in Playing
My Part. For example, Germany and Austria have reduced public transport fares, Belgium
is promoting car‐sharing, and the Netherlands and Italy are encouraging households toturn down their thermostats and at the same time requiring temperatures to bemoderated in public buildings. Continued policy support for measures of this kindthrough to 2030 and beyond would help to bring the world closer to the NZE Scenario
trajectory.

5

Around 15% of the savings in oil demand are emergency response measures to cushion
the impact of the current crisis, such as car‐free Sundays. These emergency measureswould temporarily inconvenience citizens and in some cases pose real challenges to theireveryday lives, but they have the potential to contribute 0.1 mb/d of oil savings in theEuropean Union. However, most behavioural measures proposed would reduce the day‐to‐day energy used by citizens without materially reducing energy service. These so‐called sustainable behavioural changes could become ingrained and contribute lastingenergy reductions beyond the present crisis.
The importance of behavioural change was highlighted in the IPCC Sixth Assessment
Report (AR 6) in many of the scenarios which limit global warming to below 1.5 °C(IPCC, 2022). Many of the behavioural changes proposed in this analysis play a lastingrole in the NZE Scenario (see Chapter 3).

Energy demand in India continues to rise at over 3% per year in the STEPS from 2021 to 2030,
spurred by GDP growth of more than 7% per year in the same period. Coal meets a third ofthis growth with demand rising above 770 Mtce by 2030, and continuing thereafter before
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Energy demand growth in China begins to slow this decade in the STEPS. It peaks just before
2030, as do emissions, in line with its Nationally Determined Contribution (NDC) and nationaltargets. Coal remains China’s largest energy source, but its dominance in the power sector isincreasingly squeezed by renewables, which are responsible for nearly 45% of electricity
generation in 2030 in the STEPS. Meanwhile, the coal‐based chemical industry in Chinareaches a plateau. Oil demand peaks in the second‐half of this decade, reaching around16.5 mb/d (the same level of demand as in the United States in 2030) and then begins to
decline. This decline reflects expanding electrification of transport, with EVs accounting for
more than 50% of car sales by 2030. These outcomes are consistent with the 14th Five‐Year
Plan (2021‐25). In the APS, the peak in emissions occurs slightly earlier and at a slightly lower
level as demand for renewables rises faster, particularly in the power sector. This faster
growth puts renewables on track to play their part in the achievement of carbon neutrality
in China before 2060.

peaking in the early 2030s. Oil demand meets a further quarter of the energy demand growth
and rises to nearly 7 mb/d by 2030. Government programmes, such as the Gati Shakti
National Master Plan and the Self‐Reliant India scheme, lead to increases in renewables andsales of EVs in the STEPS. Helped by these programmes, renewables meet 30% of demand
growth to 2030, notably through a rapid increase in solar PV deployment. By 2030,
renewables account for 35% of generation, and solar alone accounts for 15%. In the APS,
both electrification and renewables increase faster in line with the progress needed for India
to its reach net zero emissions target by 2070.
Southeast Asia also sees rapid growth in energy demand. In the STEPS, demand rises over
3% per year from 2021 to 2030, surpassing the level of growth over the last decade. Oil is thebiggest component of this increase in demand with consumption rising to 6.7 mb/d by 2030.
Renewables, natural gas and coal demand all rise quickly too. Coal continues to dominate
the electricity sector, though its share of generation declines from 42% today to 39% by 2030
in the STEPS. In the APS, renewables become the dominant source accounting for close to
40% while coal declines to a third by 2030. EV sales rise sharply, thanks in part to progress
towards Thailand’s commitment to end the sale of new internal combustion engine (ICE) cars
by 2035, Singapore’s commitment to do the same by 2040, and Indonesia’s target of 2 million
electric car fleet by 2030.
Africa sees a modest improvement in the number of people without access to electricity in
the STEPS by 2030, however, current energy price surges threaten near‐term progress. By
2030, the number of people without access to clean cooking reaches almost 1 billion from
965 million in 2021. Per capita energy use remains low and this hinders economic growth.
However, increases in low cost renewable power resources add substantially and accountfor more than 35% of Africa’s power supply by 2030. Most of the increase in renewables isfrom hydropower and solar PV, but some also derives from wind and geothermal resources.
Growth in demand for oil in transport and for LPG in cooking pushes demand to over 5 mb/dby 2030. As well, natural gas experiences an uptick in demand, supported by the discoveryof new reserves: it is used in particular in the expanding steel, cement, desalination andfertiliser industries. The effects of climate pledges by African countries and of reaching
universal access are explored in detail in Africa Energy Outlook 2022 (IEA, 2022e).
The Middle East sees increasing demand for natural gas, which meets over 60% of the overall
demand growth to 2030 in the STEPS, but renewables emerge as a notable contributor in the
power sector, thanks to some of the lowest cost solar in the world and to increasing interestin economic diversification.

Primary energy intensity improves by 2.4% a year over the period to 2030. The share ofelectricity in total final consumption in the STEPS rises from 20% in 2021 to 22% by 2030, andelectrification drives improvements in energy efficiency, notably via the faster adoption of
EVs and heat pumps that are more efficient than their fossil fuel counterparts. New industrial
facilities become more efficient through the electrification of low‐temperature heat
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Sectoral trendsapplications, the use of best‐in‐class electric motors in light industry and an increase in thenumber of electric arc furnaces in the steel industry. Insulation in buildings improves, andnew appliances meet higher energy efficiency standards. These changes are reinforced byunprecedented levels of financial support for energy efficiency in government recovery
packages, notably for building retrofits in advanced economies. End‐use efficiency
improvements and electrification are together able to curb the effects of activity growth,
resulting in total final consumption by 2030 in the STEPS being 10% higher than current
levels, well below the 20% increase in activity growth over the period (Figure 5.5).
In the APS, the more rapid gains from end‐use efficiency and electrification result in total
final consumption being lower by 2030 than in the STEPS. The share of electricity in total final
consumption increases to 24% in 2030 in the APS, with faster electrification in all sectors.
Innovation also makes a bigger difference in the APS, with new targets and increased
commitments reducing the risks of investing in demonstration projects for near zero
emissions technologies. This plays a large part in driving down costs and increasing the
deployment of clean energy technologies in hard‐to‐abate sectors.
Figure 5.5 ⊳Changes in global final energy consumption by lever and sector
in the STEPS and APS, 2021-2030

EJ

STEPS

APS

550

Total final consumption
SectorIndustry
Buildings
Transport
Other
Lever
Energy efficiency
Electrification
Other fuel shifts

500

2030

SectorLever

Activity

2021

2030

SectorLever

Activity

2021

450

400

5

IEA. CC BY 4.0.

Efficiency improvements and electrification moderate the impact of increasing demand forEnergy use in buildings continues to rise in the STEPS, ending the decade 3% higher than in
2021, driven by an overall expansion of floor area and growth in the ownership of appliancesin emerging market and developing economies. Electricity dominates demand growth,
increasing by 10 exajoules (EJ) to 2030 (Figure 5.6). Most of the increasing demand forelectricity is for appliances and air conditioners, but demand for electric heating and cooking
increases by 2.7 EJ, displacing fossil fuel use in some regions. Improvements in building codes
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services on final energy consumption in the STEPS, and almost eliminate it in the APS

and stronger support for building retrofits under the US Inflation Reduction Act and the EU
Energy Performance Buildings Directive, appliance efficiency standards and fuel switching
incentives in force or announced by governments are sufficient to improve the energy
intensity of the building stock by about 20% per square metre by 2030 in the STEPS. This
corresponds to energy efficiency savings in the global buildings sector of around 14 EJ by
2030, and offsets more than 60% of activity growth.
In the APS, energy demand in the buildings sector declines by 8% from current levels by 2030,
and is about 10% lower than in the STEPS by 2030. The divergence from the STEPS is driven
mostly by global advances in access to clean cooking; as people switch to cooking with more
efficient fuels and stoves, the traditional use of biomass drops by 15 EJ to 2030. It is also
driven by efforts to cut natural gas demand in Europe by improving the efficiency of building
envelopes, switching to heat pumps and placing more reliance on buildings management
systems (BMS). Emerging market and developing economies make notable strides toimprove efficiency in buildings and increase electrification. The net result is that efficiency
and electrification in buildings offset almost 1.5‐times the energy demand growth stimulatedby activity growth by 2030 in the APS.

EJ

Figure 5.6 ⊳30

Change in total final consumption by sector, fuel and scenario,
2010-2019 and 2021-2030

Buildings

Industry

Transport
Other
Renewables
Oil
Natural gas
Electricity
Coal
Net change

20
10
0
‐10
‐20
‐30

2010 STEPS APS‐19 2021‐30

2010 STEPS APS‐19 2021‐30

2010 STEPS APS‐19 2021‐30
IEA. CC BY 4.0.

Electricity grows the most in the STEPS as buildings, industry and increasingly transport areelectrified. In the APS deeper electrification and renewables uptake transforms the mix.

In transport, energy demand in the STEPS is projected to be 15% higher by 2030 than 2021,
most of which is met by oil. Accelerating uptake of EVs tempers this boost in oil demand, as
do more hybrid vehicles and energy efficiency gains in ICE road vehicles, ships and planes.
Between 2021 and 2030, efficiency in road vehicles saves around 3.5 mb/d, while
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Note: EJ = exajoule.

electrification of road transport (including hybridisation) saves around 4 mb/d. Together
these effects improve the energy intensity of the global road fleet by around 15% by 2030 in
the STEPS. Oil demand for road transport is already on the decline in advanced economies,
but is projected to continue to rise in emerging market and developing economies, except in
China. In emerging market and developing economies (excluding China), ICE vehicles
maintain a dominant share of sales in the STEPS, especially where the second‐hand vehicle
market plays a prominent role. Although aviation and shipping see shifts in demand, their
total energy consumption continues to rise, with few cost‐effective low‐emissions
alternatives beyond improving efficiency available out to 2030.
In the APS, EV sales expand fast in all regions; in 2030 over 35% of cars sold are electric.
Overall oil demand and demand for oil in transport both peak in the mid‐2020s and the latter
returns to its 2021 level by 2030, around 51 mb/d (see section 5.8).

5Energy demand in industry grows by 1.4% per year to 2030 in the STEPS. This is the only end‐
use sector where both advanced and emerging market and developing economies
experience demand growth. Energy efficiency reduces demand by around 15 EJ from 2021
to 2030; the installation of more efficient equipment in industrial facilities helps reducedemand, as does phasing out inefficient production capacity in heavy industry and shifting
to new, more efficient lines. In aggregate, energy intensity in industry improves by around
15% to 2030. The fuel mix does not change much over the course of the decade. Electricity
gains some ground, especially in light industries in advanced economies, but fossil fuelscontinue to dominate, especially for high‐temperature heat applications and for chemical
feedstock.
In the APS, industrial demand increases much more slowly, by around 0.7% per year to 2030.
Electrification proceeds more briskly than in the STEPS, with electricity increasingly being
used to provide low‐temperature heat in light industries. The APS also sees faster
deployment of large‐scale near zero emissions plants in energy‐intensive industries. Demand
for low‐emissions hydrogen – both produced onsite and offsite – rises to 11 million tonnes(Mt) in 2030 for use in the production of ammonia, steel and methanol.

5.3

Emissions

In 2021, energy‐related CO2 emissions reached 36.6 Gt CO2, with the largest annual increasein history (IEA, 2022f). This reflects strong economic rebound from the Covid‐19 pandemic,
amplified by adverse weather, but it also indicates that global energy systems have yet tomake significant structural changes to decouple energy use from emissions. This rise inemissions to new record level is at odds with what is needed to meet countries’ NDCs by
2030 and their pledges to reach net zero emissions. 3

The Paris Agreement requests each country to outline and communicate their post‐2020 climate actions,known as Nationally Determined Contributions. NDCs embody efforts by the country to reduce theirgreenhouse gas emissions and adapt to the impacts of climate change.

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3

Emissions reductions targets
By September 2022, 194 countries had submitted their first NDC, and 162 had formally
updated their NDC in line with the Paris Agreement (2015), which requests countries to
update their NDCs or submit new ones every five years (Table 5.3). Many countries, among
them twelve G20 countries and the European Union, have submitted updated NDCs withmore ambitious emissions reduction targets than in their first NDCs (Figure 5.7).
Table 5.3 ⊳Selected updated NDCs under the Paris Agreement

Country2030 reduction
targetBase year

Target type

43%

2005

Base year

Economy‐wide greenhouse gas emissions
Australia
CanadaEuropean Union

40‐45%

2005

Base year

At least 55%

1990

Base year

Japan

46%

2013

Base year

India

45%

2005

Emissions intensity

Kenya

32%*

2030

Business‐as‐usual

Korea

40%

2018

Base year

Morocco45.5%*

2030

Business‐as‐usual
Business‐as‐usual

Nigeria

47%*

2030

Peru

40%*

2030

Business‐as‐usual

United Arab Emirates

31%

2030

Business‐as‐usual

United Kingdom

68%

1990

Base year

United States

50‐52%

2005

Base year

Peak before 2030

2005

Emissions intensity

Economy‐wide CO2 only
China

In the STEPS, only some regions meet their stated ambitions; those where NDCs are reflectedin law or where credible policies have been put in place to meet or exceed their targets. The
APS assumes that all NDCs and net zero emissions pledges are delivered in full and on time.
For 2030, the APS projects that CO2 emissions to be more than 2 gigatonnes (Gt) lower than
the same scenario in the WEO‐2021. This reflects more ambitious targets stated in the
updated NDCs submitted since the publication of the last Outlook. However, this reduction
would have to be about five‐times larger – around 10 Gt – to be consistent with the NZE
Scenario which is based on keeping global temperature increase to below 1.5 °C by 2100.
The Intergovernmental Panel on Climate Change (IPCC) has reinforced the scientificunderstanding of the impacts of a warming world, and the need to keep global temperaturerise below 1.5 °C by the end of this century (IPCC, 2022; IPCC, 2021; IPCC, 2018). In the NZE
Scenario, this is achieved by reducing energy‐related emissions by 1.3 gigatonnes of carbon‐
dioxide equivalent (Gt CO2‐eq) on average every year until 2050.
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* Conditional on collective ambition or international financial and technical support.

Countries with NDCs, long-term strategies and net zero emissions
pledges, and their shares of global CO2 emissions

Number of countries

Figure 5.7 ⊳

200

100% Submissions

150

75%

100

50%

50

25%

Additional in
WEO‐2022
Included in
WEO‐2021

Share of global
2021 CO₂ emissions(right axis)

5
First
NDC

New orNZE
updated NDC pledges

Long‐term NZE targets
strategy
in law
IEA. CC BY 4.0.

New or updated NDCs and additional net zero emissions pledges in many countries
underpin more pronounced decarbonisation in this year’s APS
Notes: NDC = Nationally Determined Contributions; NZE = net zero emissions.

An increasing number of countries are setting long‐term net zero emissions targets. By
September 2022, 84 countries and the European Union had pledged to meet net zero
emissions targets, together accounting for around 85% of current global GDP, about thesame percentage of global energy‐related CO2 emissions, and more than half of energy‐
related methane emissions. Among the new announcements submitted, India’s net zero
emissions pledge and Indonesia’s net zero emissions target with its 2021 Long‐Term Low
Emissions Strategy are the most significant, and account for a high proportion of the reduced
level of emissions in 2030 in this Outlook compared with the APS in the WEO‐2021. Some of
the announced targets rely on CO2 removal technologies such as removal from theatmosphere through CCUS, or direct air capture (DAC), or through nature‐based solutions
which involve the absorption of atmospheric CO2 emissions in vegetation, soil and rocks.4
If the world is to keep the global temperature rise below 1.5 °C by the end of this century, it
must keep to very exacting limits on cumulative emissions, as in the NZE Scenario. These
cumulative CO2 emissions are currently being exhausted in a highly unequal manner bypeople in various age groups, locations and income segments, and climate justice and equity
issues are becoming central themes in the discussions leading up to the COP27 in Egypt inNovember 2022. In advanced economies, average annual energy‐related per capita

A net zero pledge for all GHG emissions does not necessarily mean that CO2 emissions from the energy sector
need to reach net zero. A country’s net zero plans may envisage some remaining energy‐related emissions areoffset by the absorption of emissions from the agriculture, forestry and other land use (AFOLU) sink.

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4emissions are 8 tonnes of carbon‐dioxide equivalent (t CO2‐eq), while in sub‐Saharan Africa
they are less than 1 t CO2‐eq. 5 If all countries were to produce the same level of carbon
emissions per capita as advanced economies, the cumulative CO2 emissions until 2050 in the
NZE Scenario would be exhausted by 2028 (Figure 5.8). If the world aims to stay within 1.5 °C
limit, the average person born in the 2020s will be able to emit only one‐tenth of the lifetime
emissions produced by their parents (IEA, 2022g).
Figure 5.8 ⊳Year when the cumulative CO2 emissions until 2050 in the NZE
Scenario would be exhausted if the global population had thesame per capita emissions as…

World
Advanced economies
Emerging market anddeveloping economies
RussiaChina
Middle East
South Africa
Southeast Asia
BrazilIndia
Africa
2020

2030

2040

2050

2060

2070
IEA. CC BY 4.0.

At the current level of emissions per capita, the global cumulative
CO2 emissions until 2050 in the NZE Scenario would be exhausted by 2033

Emissions outlook

5

Per capita emissions are assessed on a territorial rather than a consumption basis.

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Current policies fall far short of what is needed during the critical period for climate action
between now and 2030 to meet the collective emissions reduction commitments in the
NDCs. In the STEPS, energy‐related emissions peak in the mid‐2020s and then decline: by2030, they fall slightly below the level they were at in 2021 (36.2 Gt CO2). In the APS, thecommitments in the NDCs bring about a faster reduction in emissions: global emissions peak
before 2025 and fall to 31.5 Gt CO2 in 2030, which is around 15% lower than in the STEPS.
More than half of the additional CO2 emissions reductions in the APS compared with the
STEPS occur in China, the United States and the European Union (Figure 5.9).

Gt CO₂

Figure 5.9 ⊳40

CO2 emissions by scenario and by region, 2021 and 2030

CO₂ emissions by scenario

CO₂ emissions by region

STEPS

Bunkers
Other EMDE
India
China
Other advanced
economies
European Union
United States

APS
30
NZE
20

10

2021

2030

2021 2030
STEPS

5

2030
APS
IEA. CC BY 4.0.

While global emissions stay broadly flat in the STEPS to 2030, they fall by almost 5 Gt in the
APS, with more than half of the difference from China, United States and European Union
Notes: Gt CO2 = gigatonnes of carbon dioxide; EMDE = emerging market and developing economies.

The gap in CO2 emissions reductions between the APS and the NZE Scenario in 2030 is almost
twice as large as the amount between the STEPS and the APS, highlighting the size of theremaining global ambition gap. In 2030, CO2 emissions in the APS are almost 5 Gt CO2 lower
than in the STEPS, but around 9 Gt CO2 higher than in the NZE Scenario. Without the new or
updated NDCs and net zero emissions pledges announced in 2022, the gap between energy‐
related CO2 emissions in 2030 in the APS and the NZE Scenario would be 2 Gt bigger. In all
scenarios, the largest contribution to reducing emissions is replacing coal‐fired power
generation with renewable energy sources (Figure 5.10).6 Almost half of the difference inemissions reductions between the STEPS and the APS in 2030 is delivered by faster
deployment of renewables in the APS. Most of the rest is from more rapid energy efficiency
improvements and electrification of end‐uses in the APS. In industry, bigger emissions
reductions in the APS reflect more stringent efficiency standards than in the STEPS and wider
deployment of large‐scale near zero emissions plants in energy‐intensive industries. In roadtransport, accelerated roll out of EVs and supporting infrastructure deliver the emissions
reductions.

6
The IEA will release Coal in Net Zero Transitions: Strategies for rapid, secure and people‐centred change inNovember 2022.

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In hard‐to‐abate sectors, the risks associated with being a first mover deter some firms fromadopting innovative low‐emissions technologies during this decade. New sectoral net zero
initiatives aim to address this barrier. As of September 2022, firms participating in suchinitiatives and top‐20 companies with individual pledges cover around one‐third of emissions
from shipping and aviation as well as steel and cement production (Box 5.2).

Figure 5.10 ⊳ CO2 emissions reductions by sector and scenario, 2021-2030

Gt CO₂

1

Coal Intensive Other
power industries power

Cars

Space
Other
Other
Other
heating transport industry buildings
NZE

0

APS

‐1

STEPS

‐2
‐3
‐4
‐5
‐6
IEA. CC BY 4.0.

Across scenarios, around half of total emissions reductions to 2030 are from renewables
replacing coal power; industry delivers reductions from fuel switching and efficiency
Note: Gt CO2 = gigatonnes of carbon dioxide.

Box 5.2 ⊳Sectoral initiatives for net zero emissions pledges in hard-to-abate
sectors gain momentum

These initiatives often bring together public and private actors with the aim of reducing
the perceived risks of being an early adopter of innovative low‐emissions technologies.
They have the potential to accelerate adoption and secure off‐take agreements for low‐emissions offerings within this decade, but they depend upon consistent standards andtransparent reporting to ensure that all participating companies are making progressconsistent with sectoral ambitions: uneven progress between firms can undermine the254

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As of July 2022, almost 800 companies worldwide had made net zero emissions pledges(Net Zero Tracker, 2022). Increasingly, companies in hard‐to‐abate sectors are joining
sectoral initiatives, notably in the steel, cement, aviation and shipping industries. To date,roughly one‐third of current emissions from these sub‐sectors are covered by major
initiatives and pledges of top‐20 companies. The majority of the top‐20 companies ineach sub‐sector are either part of such initiatives or have individual net zero emissionscommitments (Figure 5.11). The International Air Transport Authority (IATA) Net Zero
Carbon Emissions from the Global Air Transport Industry by 2050 strategy covers around
80% of worldwide aviation activity and emissions. So far, other industries have much
lower levels of coverage, with initiatives and top‐20 company pledges in the steel,cement and shipping sub‐sectors each covering around 25% of their global emissions.
More than half of the companies participating in sectoral initiatives for emissions
reductions have their headquarters in advanced economies.

effectiveness of such collective agreements. It is also important that companies prioritise
reducing their own emissions in decarbonisation strategies, and that where they rely on
the use of carbon credits to compensate for their residual emissions, they use only highquality carbon credits that result in permanent, additional and verified emission
reductions or removals. Transparent data about company current and projected Scope 1,
2 and 3 emissions, as well as planned use of carbon credits to achieve targets, should
help to improve accountability and to fast track progress.
Figure 5.11 ⊳ Coverage of initiatives and additional corporate
net zero emissions pledges in selected sub-sectors
100%

Top‐20 companies:
Without pledges

80%

5With pledges and notmember of initatives

60%

Sectoral coverage:
Sectoral initiatives

40%
Share of global sectoral
emissions covered by pledges

20%

Steel

CementAviation

Privateshipping

Publicshipping
IEA. CC BY 4.0.

Sectoral initiatives and pledges made by top-20 companies in selected
hard-to-abate sub-sectors cover about one-third of their collective CO2 emissions
Notes: Initiatives analysed include: Net Zero Steel Initiative (steel); Concrete Action for Climate (cement);
Net Zero Carbon Emissions from the Global Air Transport Industry by 2050 (aviation); First Movers
Coalition on Shipping (private shipping); and the Declaration on Zero Emissions Shipping by 2050 (public
shipping). All sectoral initiatives are considered in the APS except for the IATA aviation initiative for whichgovernment support for international aviation to reach net zero emissions by 2050 was announced in
October 2022.

Air pollution

Polluted air has caused at least 19 000 excess deaths per day in recent years. In 2021, indoor
air pollution caused around 3.6 million premature deaths, while outdoor air pollution was
responsible for 4.2 million. Air pollution also comes with significant economic costs. Someare direct costs, such as those due to the provision of healthcare, and some are indirect, suchas those incurred as a result of labour productivity losses or crop damage. It is estimated thatthe global health cost of mortality and morbidity caused by exposure to fine particulatematter air pollution alone is equivalent to around 6% of global GDP and to more than 10% in
certain countries, most notably in India and China (World Bank, 2022).
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5.4

Figure 5.12 ⊳ Population exposed to heavily polluted air and change inpremature deaths from air pollution by region and scenario,
2021 and 2050
Exposure to heavily polluted air
Emerging market
and developing
economies
Advanced
economies

2050

2021
STEPS
APS
NZE
1

2

3
Billion people

STEPS

HAP
AAP

APS

HAP
AAP

NZE

Change in premature deaths

HAP
AAP

China
India
Southeast Asia
AfricaRest of world
Net change

‐3

‐2

‐1

0

1

2
3
Million people
IEA. CC BY 4.0.

The number of people exposed to heavily polluted air in 2050 in the STEPS and APS is higher
than today, but in the NZE Scenario it is reduced by almost 2 billion people
Notes: Heavily polluted air = PM2.5 concentrations ≥ 35 microgrammes per cubic metre. AAP = ambient air
pollution; HAP = household air pollution.

In the STEPS, a combination of minimum standards for tailpipe emissions from roadtransport, reduced use of coal for electricity generation and reduced use of fuelwood forheating and cooking, together result in a modest fall in global emissions of major air
pollutants 7 between 2021 and 2050. However, population growth and urbanisation,
particularly in parts of the world where emissions reductions are less pronounced, or evenabsent, mean that 640 million more people are exposed to high concentrations of fineparticulate matter (PM2.5) pollution in 2050 than in 2021 (Figure 5.12).8 As a result, there are
78
In this section, high concentration corresponds to a PM2.5 density greater than 35 microgrammes per cubic
metre, in accordance with the World Health Organisation Interim Target 1 (WHO, 2021).

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Fine particulate matter (PM2.5), nitrogen oxides (NOX) and sulphur dioxide (SO2) are the main energy‐related
air pollutants associated with premature morbidity and mortality.

almost 3 million more premature deaths due to ambient air pollution worldwide in 2050 thanthere were in 2021, despite an overall decrease in air pollutants (Rafaj, Kiesewetter and Krey,2021). Three‐fifths of these excess premature deaths occur in China, India and Southeast
Asia. Owing to a shift towards cleaner cooking fuels, premature deaths from household air
pollution fall by around 650 000 per year over the same period. This reflects a reduction inIndia and China, although there are increases in premature deaths from dirty household air
in Africa and elsewhere in 2050 compared to today due to population growth and insufficient
progress on access to clean cooking in the STEPS.
In the APS, the number of people exposed to high concentrations of PM2.5 rises marginally
between 2021 and 2050, but is almost 20% below the level in the STEPS by 2050. Just over2 million more premature deaths per year are caused by ambient air pollution in 2050 than
today, which is 560 000 fewer than in the STEPS. Fossil fuel use in emerging market anddeveloping economies does not dramatically decline in this scenario until after 2030, leaving
many exposed to high levels of pollution in the meantime. Together with the failure toachieve universal access to clean cooking by 2030, this accounts for the majority of thedifference between excess deaths in the APS and in the NZE Scenario.

5

In the NZE Scenario, exposure to high concentrations of PM2.5 declines dramatically fromtoday’s level: by 2050 almost 2 billion fewer people breathe heavily polluted air. This resultsin around 1.4 million fewer premature deaths from ambient air pollution in 2050 compared
to 2021, some 3.7 million fewer than in the APS Scenario in that year. Universal access toclean cooking solutions cuts exposure to dirty household air, resulting in around 2.3 million
fewer premature deaths from household air pollution in 2050 than today, an improvementof around 650 000 compared to the APS Scenario.

5.5

Investment

Clean energy investment was around USD 1.3 trillion per year in 2021. This increases by morethan 50% from current levels by 2030 in the STEPS, more than doubles in the APS, and triples
in the NZE Scenario (Figure 5.13). Investment in fossil fuels falls in both the APS and NZE
Scenario, but increases in the STEPS (see Chapters 6‐9 for fuel specific investments).

In the STEPS, end‐use investments represent half of the USD 700 billion increase in annual
clean investment over today’s levels, and are primarily driven by continued growth in EV
sales and investments in the buildings sector. End‐uses are not the primary driver ofinvestment increases in the APS and NZE, but moving from the STEPS to the NZE Scenario
requires an additional USD 900 billion per year by 2030, which is more than double theChapter 5 | Outlook for energy demand

257

IEA. CC BY 4.0.

End‐use investment is a major component of clean energy investment. It includes the cost ofenergy efficiency upgrades and fuel switching in buildings, appliances, industry and vehicles.
Energy efficiency and end‐use investment were about USD 500 billion in 2021. This is set toincrease in 2022, partly as a result of post‐pandemic government stimulus packages that areproviding support for retrofits, heat pumps and EVs. In particular, sales of EVs have risen with
spectacular speed.

growth in annual end‐use investment needed between today and 2030 in the STEPS. EVs andheat pumps are much more widely adopted in the APS and NZE than in the STEPS by 2030,
but the investment costs are much reduced by the falling costs of these technologies.
Figure 5.13 ⊳ Annual clean energy investment by sector and scenario,
2021 and 2030
Billion USD (2021, MER)

5 000

Efficiency andend‐use

4 000

Low‐emissions
fuels

3 000

Power

2 000
1 000

2021

STEPS
2030

APS
2030

NZE
2030
IEA. CC BY 4.0.

Investment in end-uses would need to almost quadruple by 2030 to reach the levels
required in the NZE Scenario; EV sales are already projected to quadruple in the STEPS
Note: EVs = electric vehicles; MER = market exchange rate.

In the NZE Scenario, renewables become the foundation of an electricity system that is four‐times larger in 2050 than it is today. By 2030 in the NZE Scenario, capital spending on clean
power doubles compared to the STEPS and is three‐times higher than in 2021, withinvestments across a wide range of options for low‐emissions electricity generation,
including wind, solar, nuclear, hydrogen, CCUS, storage and networks.

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Rising interest rates and inflation could sour the near‐term outlook for end‐use investment,
notably in the buildings and transport sectors, which are strongly tied to disposable income
and the ability of consumers to access affordable financing. Recovery packages havecommitted around USD 440 billion to the end‐use segments over the 2020‐50 period, andthat may help to support investment levels. This support, however, is concentrated inadvanced economies, and much of it is front‐loaded. As stimulus funding fades in the future,
it will be necessary to reinforce enabling conditions and support for new investment. This
will depend on the global economic outlook, the speed of technology cost reductions andthe pace of adoption of new, more efficient technologies. Some banks are starting to design
dedicated financing packages for energy efficiency and end‐use investment, which could help
boost private sector financing.

Key themes
5.6

Energy access

The current energy crisis is causing fuel prices, food prices and inflation to surge, pushing up
the number of people living in extreme poverty, especially in sub‐Saharan Africa. This is set
to slow progress towards universal access to electricity and clean cooking, compounding two
prior years of setbacks due to the Covid‐19 pandemic. It is also exacerbating an affordability
crisis that may push many into forgoing the use of modern energy. This section:
Provides 2022 estimates for electricity and clean cooking access based on a country‐by‐country assessment.

Quantifies how the effects of the Covid‐19 pandemic and the energy crisis change thetrajectory for global progress towards the goal of universal access to clean cooking andelectricity by 2030 (Sustainable Development Goal [SDG] 7.1) in the STEPS.



5

Assesses for the first time how country‐level access targets, if implemented on time andin full, measure up against the SDG 7.1 target of universal access realised in the NZE
Scenario.

Electricity access
For the first time in decades, the number of people around the world without access toelectricity is set to rise in 2022. It is likely to reach 774 million, which would mean an increaseof 20 million people from 2021, and coming after the pandemic‐related slowdown in both2020 and 2021 would take the number of those without access to electricity to levels last
seen in 2019 (Figure 5.14). The rise in the number of those without access occurs largely in
sub‐Saharan Africa, where the number of people without access is nearly back to the highest
level seen in 2013, and where almost 80% of those without access live.

9

These are year‐on‐year inflation rates.

Chapter 5 | Outlook for energy demand259

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Consumers are now facing rising inflation levels that make getting and maintaining access toelectricity less affordable (see Chapter 4). At the same time, investment in expansion of
distribution systems and new connections is slowing down as a result of the mounting
burden of debt that most utilities are facing related to the pandemic. During the pandemic,
utility electrification programmes continued in some parts of developing Asia, notably in
Myanmar (where 5% of the population has been connected annually). However, even front‐
runner countries on electricity access, such as Ghana and Ethiopia, are set to see a difficultyear for access gains against a background of rising inflation rates (30% inflation in Ghana
and 35% in Ethiopia by the end of the second‐quarter of 20229) (Ethiopian Statistics Service,2022; Ghana Statistical Service, 2022).

Figure 5.14 ⊳ Number of people without access to electricity

Million people

in sub-Saharan Africa and the world, 2012-2022
1 500
Covid‐19
pandemic
1 200

900

World

600

Sub‐SaharanAfrica

300

2012

2014

2016

2018

2020

2022e
IEA. CC BY 4.0.

On the heels of the Covid-19 pandemic, the 2022 energy crisis is leading to a reversal of
global progress on electricity access for the first time in more than a decadeNote: 2022e = estimated values for 2022.

Grid connections proved resilient in 2020 and 2021, but the rate of new connections is set
to slow for 2022. Projects in the pipeline from before the pandemic have largely been
completed, but new procurement has slowed. The budgets of many utilities were refocussed
during the pandemic, reducing funds available for energy access projects. Utilities in Africa
were already in a perilous financial situation heading into the pandemic. Operational losses
climbed substantially during the pandemic, and many utilities are still being asked to extend
lifeline tariffs while facing higher operational costs (Balabanyan, 2021). Cost‐reflective tariffreforms were also paused in many regions to avoid potentially exacerbating the affordability
crisis for the poorest households, further setting back institutional efforts to make utilities
more attractive to investors.

10

Based on personal communication with Africa Minigrid Developer Association (AMDA) officials, July 2022.

260

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The current inflationary environment is also affecting the already rising costs of off‐gridaccess components, especially solar PV modules, batteries and other electronic components
such as inverters. The costs of solar and hybrid mini‐grids are estimated to have increasedon average by at least 20% in 2022 compared to pre‐pandemic levels.10 Combined with thestrong depreciation of local currencies in developing countries, this is making new projects
less appealing for investors, especially in rural areas. It is also causing problems with respect
to contracts for new projects that have already been signed in cases where the contracts lackthe flexibility to permit adjustments in light of current economic conditions.

Solar home system (SHS) costs are also on the rise, with average market prices for a new SHS
increasing by 28‐36% since 2020 (Lighting Global/ESMAP, GOGLA, 2022). This is leading tohouseholds opting for smaller or lower quality systems. Sales of large SHS were 25% below
their 2019 peak in 2020 and 33% below it in 2021 (GOGLA, 2022).11
In the STEPS, the number of people without access to electricity is projected to reach
660 million by 2030, up by around 10 million from the STEPS projection in the WEO‐2021.
About 85% of those without access in 2030 will be in sub‐Saharan Africa, up by around six
percentage points from 2021.
Countries with targets for access to electricity and clean cooking

Table 5.4 ⊳AfricaDeveloping Asia

Universal
access by
2030

Angola, Benin, Botswana, Cameroon, Côte
d’Ivoire, Eritrea, Ethiopia, Gambia, Ghana,
Guinea, Kenya, Mauritania, Mozambique,
Nigeria, Rwanda, Senegal, Sudan, Togo

Bangladesh,
Myanmar, Pakistan

Othertargets

Burkina Faso, Burundi, Central African Republic, Papua New Guinea
Chad, Republic of the Congo, Djibouti, DRC,
Guinea‐Bissau, Lesotho, Liberia, Madagascar,
Malawi, Mali, Namibia, Niger, Sierra Leone,
Somalia, Tanzania, Uganda, Zambia, Zimbabwe

Central andSouth America

5

Access to electricity
Bolivia,
Guatemala,Honduras,
PanamaHaiti

Access to clean cooking
Universal
access by
2030

Angola, Kenya, Malawi, Mali, Mozambique,Rwanda, Sierra Leone, Sudan

Bangladesh, China,Fiji, India, Indonesia,
Nepal, Myanmar,
Mongolia, Viet Nam

Peru

Other
targets

Burkina Faso, Cameroon, Côte d’Ivoire, DRC,
Ethiopia, Ghana, Liberia, Mauritania, Nigeria,
Niger, Senegal, Tanzania, Uganda, Zimbabwe

Bhutan, Pakistan,ThailandHonduras,
Guatemala,Nicaragua

Notes: DRC = Democratic Republic of the Congo. Universal access by 2030 includes countries that have targets
to reach 100% access rates by 2030 or before. Other targets include countries with other less ambitious
targets. Includes only targets for countries with access rates lower than 95%.
Source: IEA analysis based on official country and third‐party publications.

11

Solar home systems larger than 20 Watts, which if coupled with high efficiency appliances can power
multiple lights, a television and a fan.

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In the APS, it is assumed that all targets, including those focussed on access to electricity, aremet on time and in full. Out of the 113 countries without universal access, 54 have targets
for access to electricity, of which 25 have targets to reach universal access prior to or by 2030
(Table 5.4 and Figure 5.15). Meeting all these targets reduces the number of people without
access to electricity to 290 million in 2030. However, only 20% of the countries with targets,e.g. Côte d’Ivoire, Kenya, Senegal, Rwanda, Myanmar, have comprehensive national
electrification strategies in place, have reasonably‐staffed national agencies responsible forelectrification, strong and timely tracking procedures, and the inclusion of off‐grid solutions
and affordability measures, e.g. social or lifeline tariffs. (The IEA has programmes for Africanaccess institutions with the objective to help build capacity for setting and delivering accesstargets [Box 5.3]).
Figure 5.15 ⊳ Number of people without access to electricity in 2021 and 2030
by scenario, and coverage with targets in the APS
People without accessCoverage of targets APS

Million people

800

Number of countries

People without access

600
10%
26%

400

52%
200

45%
45%

22%

2021
SSA

STEPS APS NZE
2030
Developing Asia Rest of world

No target

Target for full access by 2030

Other target
IEA. CC BY 4.0.

Achieving national targets for electricity access reduces the number of people without
access by 60% by 2030, while stated policies reduce this number by just 12%
Notes: SSA = sub‐Saharan Africa (excludes South Africa). The target for full access by 2030 category includes
countries with 100% access to electricity targets by 2030. The other target category includes countries withtargets less ambitious than full access by 2030. The share of countries with and without targets and thenumber of people without access living in those countries is based on their status as of 2021.

Box 5.3 ⊳IEA activities focussed on Africa

262

The IEA energy statistics and modelling training, in partnership with theEuropean Union Directorate General for International Partnerships, focusses on
improving energy data and supporting whole system energy modelling processes
within African ministries. This training has been delivered to ten countries and will
be extended to more in the future.
International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

The IEA has worked for two decades to advance the development of energy data andanalysis in Africa. The IEA collects energy and access data for all African countries and has
developed authoritative outlooks for various regions across Africa. The IEA counts three
African countries as Association members – Morocco, Egypt and South Africa –and has
an in‐depth partnership with Senegal. A continent‐wide outlook was published recently– Africa Energy Outlook 2022 – in collaboration with the African Union Commission andthe United Nations Economic Commission for Africa (IEA, 2022e). In addition, the IEA
provides capacity building programmes on energy statistics and energy system planning.



The IEA data‐driven electrification in Africa programme, in partnership with theUnited States Agency for International Development and Power Africa, addresses
electricity access data gaps to enhance strategic access planning. This programme
provides data collection guidelines, as well as support for implementing thoseguidelines in six countries and for integrating the use of geospatial tools forelectrification planning in three pilot countries.



The IEA Clean Energy Transition reports, with support from the Ministry of Foreign
Trade and Development Cooperation of the Netherlands, develops region‐specificclean energy transition roadmaps. These roadmaps include North Africa (IEA,
2020a), the Sahel (IEA, 2021) and Greater Horn of Africa (IEA, 2022h).

The IEA Clean Energy Transition Programme supports an energy efficiency policy
capacity building programme with African regulators and analytical support for low‐emissions hydrogen in Africa, supported by participating member countries
including Belgium and Japan.

5

Reaching universal access to electricity by 2030 – the target met in the NZE Scenario – would
require almost 110 million people to gain access every year from 2022, and over 30 countries
in sub‐Saharan Africa to connect more than 5% of their population every year. This is a tallorder, but progress on this scale has been achieved in other countries in the past.
In the NZE Scenario, 45% of people gaining electricity access for the first time do so with gridconnections, 30% with mini‐grids and 25% with stand‐alone systems. Almost 90% of newconnections are based on renewables. These projections are based on a country‐by‐country
geospatial least‐cost analysis, which considered technical barriers, commercial viability,
historic installation rates, and speed to market to develop a feasible route for achieving
universal access to electricity in the next eight years.

Clean cooking

International LPG prices are twice as high in 2022 as they were on average in 2019. Together
with soaring prices for food and other basic goods, the high cost of LPG may push up to
100 million people back to the use of traditional fuels for cooking absent effective
interventions. Most of the people at this risk are in developing Asia where LPG use is high,and where programmes which provided LPG canisters to the poor have begun to cut
subsidies. In Africa, this adds to substantial mark‐ups on delivered LPG prices, owing tounder‐developed fuel delivery infrastructure and a lack of transparent, competitive fuelmarkets.
Chapter 5 | Outlook for energy demand263

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In 2021, 2.4 billion people globally lacked access to clean cooking, 40% of them in sub‐Saharan Africa and 55% in developing Asia. We estimate that the number of people still
cooking with traditional biomass, coal and kerosene in 2022 is continuing to increase, as it
has since 2020 due to the pandemic. The setbacks this year are primarily driven by surging
fuel prices, particularly for LPG.

The financial burden of providing subsidised LPG is ballooning, pushing a number of countries
to remove or reduce financial support, including Kenya and India. There may be scope insome cases to move from broad‐based, fuel specific subsidies for LPG to more targeted
support so as to reduce subsidy burdens without sacrificing affordability for those withoutclean cooking access. In India, for example, LPG subsidies were removed in June 2020, butwere then reintroduced in May 2022 for a targeted number of households under the Ujjwala
scheme. Other countries, e.g. Indonesia, Kenya and Nepal, are continuing with programmes
to promote electric cooking in order to reduce import dependency on LPG and the costs ofproviding LPG subsidies.
Around 1.9 billion people remain without access to clean cooking in 2030 in the STEPS.12 Halfof those are in sub‐Saharan Africa, up from 40% in 2021. In the APS, it is assumed that all
clean cooking targets are met on time and in full. Around 128 countries lack universal accessto clean cooking, but only 39 countries have clean cooking targets, of which only 19 aim toachieve universal access by 2030 in line with the SDG 7.1 (Table 5.4). If all the targets areachieved, as assumed in the APS, 780 million people would remain without access by 2030,
about 60% fewer than in the STEPS (Figure 5.16). China and Indonesia are close to being on
track to achieve their targets, whereas many other countries with targets are currently fallingwell short of them, underlining that there is a need to improve implementation as well as toraise the current level of ambition.
In the NZE Scenario, around 290 million people gain access to clean cooking each year, anduniversal access is achieved by 2030. Of those, 40% gain access with LPG, 35% with improved
cook stoves13 (especially in rural areas), 15% with electricity and the remaining 10% withbiogas or ethanol. Electric cooking is becoming a more attractive option as the costs ofelectric appliances decline, and as the current price crisis leads to efforts to reduce
dependence on imported fuels. Electric cooking may not immediately meet all householdcooking needs, but it plays an important role in reducing demand for other fuels throughclean fuel stacking.14

12This number is significantly lower than previous editions of the World Energy Outlook, due to a downward
revision in the historic number of people cooking with traditional biomass in China. This revision by the World
Health Organisation is based on recent surveys, which suggest that around 200 million fewer people in China
were cooking with the traditional use of biomass or charcoal in 2021, changing the access rate from around
65% in 2021 to almost 80% (WHO, 2022). This is largely driven by national programmes to eliminate polluting
sources of cooking to improve air quality in urban centres. Many of those transitioning from traditional fuels
are reported to use electric cooking, but it is likely a combination of electric and LPG or natural gas wok
cooking. These revisions impact access rates for all years between 2000 and 2020. Based on the new data,
China reaches universal access by 2030 in the STEPS while in previous estimates this was projected by the late
2040s.
13

14

Clean fuel stacking refers to households using multiple cooking solutions, e.g. LPG stove and a microwave
and kettle.

264

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Improved cook stoves include intermediate and advanced improved biomass cook stoves (ISO tier > 1). It
excludes basic improved stoves (ISO tier 0‐1).

Figure 5.16 ⊳ Number of people without access to clean cooking in 2021
and 2030 by scenario, and coverage with targets in the APS

Million people

People without accessCoverage of targets APS

2 500
Number of countries

People without access

2 000
16%

1 500

32%

18%

15%

1 000

69%
500

50%

SSA

STEPS APS NZE
2030
Developing Asia
Rest of world

5

2021

No target

Target for full access by 2030

Other target
IEA. CC BY 4.0.

Universal clean cooking access struggles to find a place on the political agenda, thoughstated policies cut the number without access to clean cooking by 500 million by 2030
Notes: SSA = sub‐Saharan Africa (excludes South Africa). The target for full access category by 2030 includes
countries with 100% access to clean cooking targets by 2030. The other target category includes countries
with targets less ambitious than full access by 2030. The share of countries with and without targets and thenumber of people without access living in those countries is based on their status as of 2021.

Investment

International support is essential to catalyse higher investment, especially in today’s difficult
financial conditions. Concessional finance has a key role to play in helping to de‐risk
commercial participation. This includes supporting legal frameworks to open climate financeflows from organisations such as the Green Climate Fund, which has done much to advanceclean cooking programmes in some countries in Africa. Regional institutions and local
governments also have a key role to play in allocating capital to access projects and increating a healthier investment environment by developing local access agencies andChapter 5 | Outlook for energy demand265

IEA. CC BY 4.0.

Investment needed to achieve universal access to electricity and clean cooking in the NZE
Scenario amounts to around USD 36 billion per year, equivalent to 10% of what is spent in ayear by the upstream oil and gas sector (Figure 5.17). This compares with investment of
USD 23 billion per year in the APS in order to deliver stated targets. However, investment toimprove electricity access in 2019 was only around USD 10 billion, which is about 45% of theannual investment required in the APS, and less than 30% of what is needed in the NZE
Scenario. Investment levels for clean cooking are also well below what is needed to meet thetarget of universal access by 2030. The bulk of current investment is concentrated indeveloping Asia, and investment in Africa represents only around 6% of what is necessary toachieve universal clean cooking access by 2030.

programmes, improving regulatory and legal frameworks, reducing administrative burdensand delays, decreasing taxes on access components, and implementing cost‐reflective
reforms. An emerging area of interest is the provision of upfront support for the purchase of
efficient appliances, particularly for productive uses such as irrigation pumps (RMI, 2018).
Figure 5.17 ⊳ Annual investments for access to electricity and clean cooking
by scenario relative to tracked 2019 investments

Billion USD (2021, MER)

Electricity

Clean cooking
630Rest of world
Developing Asia

20

4

10

2

2019

APS
NZE
2022‐30

Sub‐Saharan Africa

2019

APS
NZE
2022‐30
IEA. CC BY 4.0.

Current investment in access to electricity is less than 30% of what is needed to achieve
universal access by 2030, while investment in clean cooking lags even further behind
Notes: MER = market exchange rate. Sub‐Saharan Africa excludes South Africa.
Sources: IEA analysis; SEforALL and CPI (2021).

5.7

Efficient cooling for a warming world

As temperatures have risen, those with access to air conditioners have been using them more
frequently. Many others have purchased cooling equipment. However, billions of people
living in hot areas do not have access to such equipment. Space cooling is already one of thefastest growing sources of electricity demand, and rapidly increasing air conditioner
ownership and use is likely to cause it to rise even faster. Against this background, the266International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

The seven years up to and including 2021 rank as the world’s seven hottest years on record;
global average mean temperatures in 2021 were around 1.1 °C above pre‐industrial levels(NASA Goddard Institute for Space Studies, 2022). This trend is set to continue for 2022.
August 2022 was one of the warmest August months ever, with heatwaves over central andeastern China and western regions of North America, while Europe experienced its hottest
summer on record, with temperatures that were 1.34 °C above the historical 1991‐2020
average (Copernicus Climate Change Service, 2022).

efficiency of cooling appliances and buildings envelopes will have major impacts onelectricity demand, emissions from electricity generation and household electricity bills.

Household space cooling needs and access today
Today around 7.5 billion people worldwide live in areas with some space cooling needs, ofwhich 5 billion live in climates with substantial cooling needs.15 Space cooling needs tend tovary substantially between advanced economies and emerging market and developing
economies. In advanced economies, which tend to be relatively northerly, energy use forspace heating is about eight‐times higher than demand for space cooling. This ratio is
reducing rapidly as climate change and urbanisation push temperatures higher, butadvanced economies nonetheless experienced an average of only 700 cooling degree days
(CDDs)16 per year between 2016 and 2021. This contrasts with 2 300 CDDs per year in Africa.
On average, emerging market and developing economies experience around 2 150 CDDs per
year.

5

The majority of the population with space cooling needs remain without access to adequatemeans to cool their homes. Around 35% of households have at least one air conditioner (upfrom 20% in 2000). Around 55% of households have access to a fan, providing at least someform of respite. Despite higher cooling needs in emerging market and developing economies,
these regions have significantly lower access to cooling than advanced economies, with only
30% of households having an air conditioner, and as few as 11% of households in India and
7% in Africa. This compares to 50% in advanced economies. On average there are 1.3 air
conditioners per household in advanced economies, and ownership is close to 100% in the
United States, with an average of 2.4 units per household.

Demand for cooling services set for growth
Heatwaves and wider cooling needs are expected to increase in frequency and intensity as
average temperatures rise and populations grow and become increasingly urbanised. The
number of people living in areas of the world with at least some cooling need is projected toincrease to 9.4 billion by 2050 (more than 95% of the global population), which is almost
2 billion more than today (Figure 5.18). As our climate changes, many more countries will
experience days in which temperatures pose a public health risk by 2050. Access to spacecooling services of one kind or another will become increasingly essential for public health,comfort and productivity, and by the same token lack of access to cooling services will
increasingly be seen as a hallmark of energy poverty.

15

16
Cooling degree days are a measure of cooling needs. This recognised standard metric allows comparison ofcooling needs between regions. A CDD measures how warm a given location is by comparing actual
temperatures with a standard base temperature. For this analysis, CDDs are calculated with a basetemperature of 18 °C and integrate the impact of humidity.

Chapter 5 | Outlook for energy demand

267

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Substantial cooling needs refer to areas that are hot and humid every day, or areas with high or very highcooling needs, as shown in Figure 5.18.

268

Figure 5.18 ⊳ Space cooling needs and household air conditioner stock in the STEPS, 2021-2050

International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

The number of people living in areas with cooling needs expands by 25% to 2050, a key driver in rising energy needs for cooling
Notes: EMDE = emerging market and developing economies. For more information on cooling needs classification see IEA (2020b).

IEA. CC BY 4.0.

In the STEPS, the global stock of household air conditioners increases from 1.5 billion units
today to 2.2 billion in 2030 and 4.4 billion in 2050. Rising incomes and cooling needs inemerging market and developing economies account for almost 90% of the increase in the
air conditioner stock to 2050. Average rates of air conditioner ownership in India increase
from 11% today to 85% in 2050; in Africa they increase from 7% today to 20% by 2050
(Figure 5.19). Two‐thirds of households in China today have an air conditioner, and almost
all households will have one by 2050, broadly in line with current levels in the United States.
Higher levels of electricity access in the APS and universal access to electricity by 2030 in the
NZE Scenario push the global stock slightly higher than in the STEPS in 2030, but by 2050 thisis offset by slightly lower cooling needs in the APS and especially the NZE Scenario as a resultof global temperatures being a little lower than in the STEPS.
Figure 5.19 ⊳ Household air conditioner ownership in selected regions in the

5

STEPS, 2021-2050

Million units

China

India

1 200

Southeast United
Asia
StatesAfricaC & S European
America Union

Japan
3

1 000
800

2

600
400

1

Air conditioner stock

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

2021
2030
2040
2050

200

Air conditioners per household (right axis)
IEA. CC BY 4.0.

Almost 90% of the growth of household air conditioners to 2050 is in emerging market anddeveloping economies, adding 2.4 billion units as incomes and temperatures rise
Note: C & S America = Central and South America.

Space cooling today is responsible for slightly more than 5% of final energy consumption
from residential and commercial buildings, or 15% of their electricity consumption. Energy
demand for space cooling has expanded rapidly over the last 20 years, more than doubling
to reach 2 000 terawatt‐hours (TWh) in 2021. Growth would have been higher without the
progressive implementation of minimum energy performance standards (MEPS) for coolingequipment. Today such standards are in place in 86 countries.

Chapter 5 | Outlook for energy demand269

IEA. CC BY 4.0.

Outlook for building cooling‐related electricity demandSpace cooling demand continues to increase on a similar trajectory in the STEPS, with global
demand rising to about 2 800 TWh in 2030, a 40% increase from 2021 (Figure 5.20). Coolingdemand approaches 5 200 TWh in 2050, double total electricity demand in the European
Union today. Nearly 90% of the total increase in space cooling electricity demand to2050 occurs in emerging market and developing markets, where MEPS are weaker than inadvanced economies.
Figure 5.20 ⊳ Space cooling demand by region in the STEPS and APS, 2021-

TWh

2050
6 000

12%

4 000

8%

2 000

4%

2021

STEPS APS
2030

Rest of world
Japan
AfricaEuropean Union
C & S America
Middle East
Southeast Asia
United States
China
India
Share of electricity
demand (right axis)

STEPS APS
2050
IEA. CC BY 4.0.

Electricity demand for cooling rises by 3 200 TWh to 2050 in the STEPS; growth is cut by morethan 50% in the APS thanks to air conditioner and building envelope efficiency gains
Note: TWh = terawatt‐hour; C & S America = Central and South America.

In the NZE Scenario, space cooling energy demand is kept down to 2 500 TWh in 2050, lessthan half the level in the STEPS. Energy efficiency and behavioural changes mean that coolingelectricity demand is only 25% higher than today, despite an additional 2.5 billion air
conditioners being in operation (see Chapter 3).

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Space cooling electricity demand in the APS is kept in check by further efficiency
improvements, notably an increase in the scope and stringency of MEPS and building energy
codes in countries with net zero emissions targets. Nonetheless, electricity demand forcooling still increases to 2 600 TWh in 2030 and over 3 400 TWh by 2050. The impact ofenergy efficiency improvements on cooling electricity demand in the APS is most significant
in the Asia Pacific region, where over 500 million additional residential air conditioners areprojected to be in use in 2030 compared with today. Half of the difference in electricity
demand for cooling between the APS and the STEPS reflects differing assumptions about
what happens in just two countries – India and China.

Energy efficiency is the key to cooling comfort that is compatible withnet zero emissions ambitions
The energy efficiency of space cooling has major implications not only for electricity demandand CO2 emissions from electricity generation but also for household energy bills andelectricity system operations. Households spent a total of USD 90 billion on electricity forspace cooling in 2021; this rises to USD 130 billion by 2030 and USD 300 billion by 2050 in
the STEPS. In the APS, energy efficiency offsets the impact of higher electricity prices in the
short term and reduces costs in the longer term: household spending on cooling in 2050 is
USD 120 billion lower than in the STEPS, with two‐thirds of the savings coming in emerging
market and developing economies. Improving the energy efficiency of cooling also reduces
energy requirements at times of peak demand for many electricity systems, which helps tokeep down the need for investment in electricity system flexibility, additional peaking
capacity and distribution networks.

5

In the STEPS, the efficiency of the air conditioner stock by 2030 is almost 10% higher than
today, and MEPS in most major markets together with mandatory efficiency labelling boost
sales of high efficiency air conditioners. However, rising average temperatures and increasing
wealth mean that units are used more often, resulting in higher average electricity
consumption per unit in 2030 than today, and energy efficiency improvements are
insufficient to offset this completely. The outlook is different in the APS, where the use of air
conditioners rises as it does in the STEPS, but more rapid energy efficiency improvements
mean that the average electricity consumption of an air conditioner drops by 5% to 2030.
Today, best‐in‐class air conditioners are more than twice as efficient as the average
equipment sold (IEA, 2022i). In several markets the efficiency of the average equipment soldis three‐times less than the best available technologies in the same market (IEA, 2022j).
Progressive increases in MEPS and mandatory energy efficiency labelling of appliances would
increase the energy efficiency of units without major increases in product costs for
consumers. MEPS and mandatory labelling might also help to discourage the sale of portable
packaged air conditioners, which are often purchased during heatwaves and are typicallymuch less efficient than split air conditioning systems. Efforts could also be made to convey
the message that alternative solutions to refrigerant‐cycle air conditioners may be best
suited to provide cooling comfort in certain contexts. 17 In households, this could include
dehumidifiers, and desiccant and evaporative cooling. In densely populated areas, districtcooling could meet needs more efficiently than individual cooling systems.
Improvements in building envelopes and passive cooling measures could also substantiallyreduce cooling demand, as well as making buildings more comfortable and resilient in theface of heatwaves and electricity outages. Passive cooling measures include shading, low
Refrigerants are an essential component to the functioning of most air conditioners. While refrigerants
operate in a closed loop, leaks may occur during the operation and maintenance of equipment. Due to theirhigh global warming potential (GWP), 138 countries have ratified the Kigali Amendment to the Montreal
Protocol, which aims to phase out the use of hydrofluorocarbons and to rely on alternatives as safe and stable
as their predecessors but with lower GWPs.

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17

emissivity glass (low‐E) windows, natural ventilation and reflective roofing materials. Passive
cooling and improvements to the energy performance of buildings could reduce the use of
air conditioners, and in some more temperate regions they could make them unnecessary.
The APS assumes that passive measures are encouraged by country‐specific zero carbon‐
ready building energy codes in countries with building energy efficiency targets in their NDC
or with broader net zero emissions targets.

5.8

Bringing forward the peak in oil use for road transport

Global oil demand grows at less than 1% per year this decade before peaking in the mid‐2030s at around 103 mb/d in the STEPS. In the APS, global oil demand peaks in the mid‐2020s
and returns to current levels by the end of this decade. Road transport is responsible for over
40% of oil demand today. Vehicle electrification is key to reducing oil demand in the roadtransport sector. In a special EV case, based on the STEPS trajectory augmented with theassumed EV penetration levels in the APS, the oil peak for the road sector is brought forward
almost one decade sooner than in the STEPS and the oil demand would be over 1.5 mb/dlower in 2030 relative to the STEPS (see EV case in Figure 5.21)
Figure 5.21 ⊳ Global road transport oil demand by scenario, 2010-2030,
and EV sales by scenario, 2021-2030
Electric LDVs

Market sharemb/dRoad oil demand
50

45

30%

40

20%

35

10%

30
2010
STEPS

2020
APS

2030
EV CaseElectric heavy trucks

40%

2021 2025 2030
2021 2025 2030
STEPS
Additional in APS
IEA. CC BY 4.0.

Oil demand in road transport increases slightly to 2030 in the STEPS despite the growth ofEVs, with faster growth for electric LDVs and heavy trucks it would peak a decade earlier

272International Energy Agency | World Energy Outlook 2022

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Notes: EV = electric vehicle; LDVs = light‐duty vehicles which include passenger cars and light trucks. Heavy
trucks include medium‐ and heavy‐freight vehicles. Electric refers to battery electric vehicles as well as plug‐in hybrid vehicles. The EV case shows the STEPS trajectory with the penetration of EVs at similar levels of the
APS.

Over 10 million electric cars are set to be sold in 2022. China remains the global leader, with
one‐out‐of‐four new cars sold being an EV in 2022. The United States is also on track for rapid
electrification of its car fleet: among other measures, the provisions of the recent Inflation
Reduction Act and the target set in California to phase out ICE car sales by 2035 will boost
electric car registrations and manufacturing capacity. The European Union has also taken
steps to promote EVs and electrification of the car fleet is set to proceed briskly there too.
The STEPS only takes account of policies for the road transport sector which are backed byexisting legislation, whereas the APS assumes that all targets and pledges are met on timeand in full. Currently, 36 countries and several US states have announced commitments tohalt the sales of ICE cars by a specified date, some also target light trucks. Major automobile
manufacturers have announced targets for production of EVs as a proportion of their total
production output, notably in Europe (Table 5.5).
Table 5.5 ⊳5Selected policies and targets to phase out sales of ICE LDVs
by country/state and automakerYear

Country/state

Type of vehicle2025

NorwayLDVs

2030

Austria, Slovenia, Washington (United States)

LDVs

Denmark, Iceland, Ireland, Netherlands, Singapore

Passenger cars

2035

European Union, Cape Verde, Canada, Chile, United Kingdom,
California, Massachusetts and New York (United States)

LDVs

2050

Costa Rica, New Zealand*, Connecticut, Maryland, New Jersey,
Oregon, Rhode Island, Vermont (United States)*

Passenger cars

Year

Automaker

Announcement(passenger cars)

2025

Jaguar

100% EV sales

2027

Alfa Romeo

100% EV sales

2028

Opel

100% EV sales in Europe

2030

Bentley, Cadillac, Fiat, Mini, Rolls‐Royce, Volvo

100% EV sales

Ford, Stellantis

100% EV sales in Europe

Honda

100% EV sales in China

2033

Audi

100% EV sales

2035

General Motors, Lexus

100% EV sales

Hyundai, Volkswagen

100% EV sales in Europe

Toyota

100% EV sales in West Europe

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*Country/states included based on their membership in the International Zero Emissions Vehicle Alliance.
Notes: LDVs = light‐duty vehicles which include passenger cars and light trucks. This table covers thosecountries and states with legislation, a target or stated ambition in place to phase out the sales of ICE LDVs.
Only automakers which have announced a complete phase out of ICE vehicles are included. West Europe
includes European Union, European Free Trade Association countries and the United Kingdom.

These targets are reflected in the APS, and as a result, sales of EVs rise faster in the APS thanin the STEPS. By 2030, EVs account for over 35% of total car sales in the APS, and for 8% of
total heavy truck sales. More than 40 million electric cars are being sold every year by 2030,
six‐times more than in 2021. In the United States, the European Union and China, one‐of‐every‐two new cars sold is electric (Figure 5.22). The shift to produce EVs means thateventually fewer ICE vehicles are sold on to developing economies, and that increases EV
sales in those countries. China, the European Union and the United States are currently
responsible for nearly 90% of electric car sales worldwide. This falls to just over 60% by 2030
as global electric car sales multiply in the APS.
Figure 5.22 ⊳ Market share of electric cars in key markets by scenario to 2030
United States

European Union

China

60%

Additionalin APS

50%

STEPS
40%
30%
20%

2030

2021

2022e

2020

2019

2030

2022e

2021

2020

2019

2030

2022e

2021

2020

2019

10%

IEA. CC BY 4.0.

Half of all the cars sold in the world's largest car markets are electric by 2030 in the APS,
building on recent momentum
Note: 2022e = estimated values for 2022.

Efficiency improvements have offset nearly 3.5 mb/d of growth in oil demand since 2015,
and fuel switching – mostly to biofuels – avoided a further 1 mb/d. Over the next decade,however, most of the avoided oil demand comes from the electrification of the vehicle fleet.
In the STEPS, energy efficiency, hybridisation and electrification all play significant roles intempering oil demand growth in the road transport sector to 2030 with electrification(including hybridisation) helping to reduce oil demand by around 4 mb/d. In the APS,
electrification proceeds at a faster pace as national targets and targets announced bymanufacturers are met, and savings reach over 5 mb/d by 2030 (Figure 5.23). Medium‐ andheavy‐duty trucks contribute twice as much to savings through electrification in the APS as
they do in the STEPS by 2040.

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Source: IEA analysis based on data from EV Volumes (2022).

Figure 5.23 ⊳ Change in road transport oil consumption by region and effectin the STEPS and APS, 2021-2030

mb/d

STEPS

APS

50

Advanced economies
Emerging market anddeveloping economies

40

EffectAvoid and shift
Efficiency
Hybridisation
Electricity
Alternative fuels

30
20
10

2021

2030

2021

5

2030
IEA. CC BY 4.0.

Electrification, efficiency improvements, hybridisation and shifting to alternative fuels curb
oil demand growth by 8 mb/d in the STEPS and by over 10 mb/d in the APS
Notes: mb/d = million barrels per day; EMDE = emerging market and developing economies. Alternative fuels
include natural gas, hydrogen, hydrogen‐based fuels and biofuels.

The ready availability of public charging infrastructure is crucial to overcome range anxiety
on the part of EV owners and potential owners, and to pave the way for the electrification oflong‐distance trucking. From now to 2030, investment of around USD 150 billion is devoted
to public charging infrastructure in the STEPS, and almost USD 190 billion in the APS. In the
United States, together the Inflation Reduction Act and the Infrastructure and Jobs Act haveearmarked nearly USD 11 billion for the establishment of a network of EV chargers. In
Europe, a number of governments are taking action, while automotive companies have
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Despite rapid expansion in EV sales, a slow turnover of stock limits reductions in oil demandin road transport. ICE cars remain in use long after their sales cease in the regions where
governments and car manufacturers have announced phase‐out dates. Despite being
responsible for two‐thirds of total new car sales by 2040 in the APS, EVs do not account for
two‐thirds of passenger cars on the road until a decade later. The brake on oil demand
reduction due to slow stock turnover reinforces the case for moving as fast as possible toencourage the uptake of EVs. While very few of the cars manufactured today will still be on
the road in 2050, this small car fleet nevertheless will contribute 9% of cumulative emissions
from the road transport sector between now and 2050. Cars sold in the next decadecontribute 24 Gt CO2 of cumulative emissions to 2050 in the STEPS, but only 12 Gt CO2 in the
APS (Figure 5.24). In the roadmap to net zero emissions, one of the key milestones is ending
new ICE car sales by no later than 2035 worldwide. This would reduce the cumulativeemissions to 2050 from cars sold in the next decade to 1.7 Gt CO2.

created joint ventures, e.g. Daimler, Traton and Volvo, to install high power charging points
near highways and logistics hubs.
Figure 5.24 ⊳ Cumulative emissions from cars and trucks by age bandand scenario, 2021-2050

Gt CO₂

Cars

Trucks100

2041‐502031‐4080

2021‐30
Existing before 2021

60
40
20

STEPS

APS

NZE

STEPS

APS

NZE
IEA. CC BY 4.0.

Timely restrictions on new ICE vehicles are key: cars and trucks yet to be purchased risk
locking in 120 Gt of CO2 to 2050 in the STEPS, more than triple the lock in from today’s fleets
Notes: Gt CO2 = gigatonnes of carbon dioxide. Trucks = light commercial vehicles, medium‐freight trucks andheavy‐freight trucks; ICE = internal combustion engine.

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Further efforts to scale up EV production are also needed to achieve the ambitious targets
that many countries have set. The current delays in delivery times for electric cars reflect not
only the popularity of EVs but also the supply challenges that have emerged. Much of this isbest left to the industry to work out, but governments could have a part to play here too, forexample to help create more resilient battery supply chains to minimise future energy
security risks. Additional investments in research and development could help to bring down
battery costs and incentivise battery recycling, fuel cell development and advanced biofuel
production. Progress in these areas would also help the shipping and aviation industries tomake progress on decarbonisation, as well as the vehicle industry.

Chapter 6
Outlook for electricity
Bright as the sun?
S U M M A R Y
 Global electricity demand rises by 5 900 terawatt‐hours (TWh) in the Stated Policies
Scenario (STEPS) and over 7 000 TWh in the Announced Pledges Scenario (APS) by
2030, equivalent to adding the current level of demand in the United States and theEuropean Union. In advanced economies, transport is the largest contributor toincreased electricity demand as the market share of electric cars rises from about 8%
in 2021 to 32% in the STEPS and almost 50% in the APS by 2030. In emerging market
and developing economies, population growth and rising demand for cooling
contribute to increasing electricity demand. In China, air conditioner ownership
expands by around 40% from current levels in the STEPS and APS by 2030. Electricity
provides a rising share of total final energy consumption in all economies. Global
electricity demand in 2050 is over 75% higher in the STEPS than it is today, 120%higher in the APS and 150% higher in the Net Zero Emissions by 2050 (NZE) Scenario.

 Recently, coal use in the electricity sector has seen an uptick in many countries in
response to strong demand, high natural gas prices and energy security concerns, but
this is expected to be temporary. Even in the STEPS, unabated coal falls from 36% ofgeneration in 2021 to 26% in 2030 and 12% in 2050, reflecting renewables growth,
led by solar PV and wind. In the APS, pledges including net zero emissions targets in
83 countries and the European Union, are met on time and in full. This accelerates
clean energy transitions. Renewables in electricity generation rise from 28% in 2021
to about 50% by 2030 and 80% by 2050. Unabated coal falls to just 3% in 2050.
Solar PV capacity additions expand from 151 gigawatts (GW) in 2021 to 370 GW in
2030 and almost 600 GW in 2050, while wind capacity additions double to 210 GW in
2030 and rise to 275 GW in 2050. Recent events, market conditions and policies are
shifting views on natural gas and limiting its role, while underlining the potential for
nuclear power to cut emissions and strengthen electricity security.
last year. We estimate that market conditions and the energy crisis are raising the
global average cost of electricity supply by almost 30% in 2022. The European Unionis facing particular pressures following a tripling of wholesale electricity prices in thefirst‐half of 2022 relative to the previous year. This is mainly a consequence of record
high natural gas prices, but it also reflects higher coal, oil and CO2 prices, exacerbatedby reduced availability of nuclear and hydropower. Actions to reduce energy use,
projected reductions in fuel prices, planned nuclear restarts and possible market
design reforms all offer potential future relief. Climate‐related risks, including
heatwaves, droughts, extreme cold and extreme weather events, have strained
electricity grids and caused outages around the world. The evolving electricity mix islikely to improve some aspects of climate resilience but exacerbate others.
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 Electricity systems faced a number of challenges to affordability and security over the The electricity sector emitted 13 gigatonnes of carbon dioxide (Gt CO₂) in 2021,
accounting for over one‐third of global energy‐related CO₂ emissions. Electricity
sector CO2 emissions peak in the near future in all our scenarios, with steep reductionsof 40% in the STEPS and over 80% in the APS by 2050. In the NZE Scenario, netemissions from electricity reach zero by 2040. In advanced economies, electricity
sector emissions have been declining since 2007, with a temporary rise in 2021 dueto the recovery from Covid‐19, and fall by 5% per year in the STEPS and 14% in the
APS. In emerging market and developing economies, emissions peak soon and thendecline by over 1% annually in the STEPS to 2050 and 6% in the APS. Higher electricity
sector investment enables these reductions, rising from an annual average of
USD 860 billion in 2017‐2021 to about USD 1.2 trillion in 2022‐2050 in the STEPS,
USD 1.6 trillion in the APS and USD 2.1 trillion in the NZE Scenario.

 System flexibility is the cornerstone of electricity security. Changing demand patterns
and rising solar PV and wind shares double flexibility needs in the APS by 2030 andincrease them almost fourfold by 2050. Flexibility needs also rise rapidly in the STEPS,
where they more than triple by 2050. Today, power system flexibility is mainly
provided by unabated coal, natural gas and hydro, but tomorrow’s systems will rely
increasingly on batteries, demand response, bioenergy and other dispatchable
renewables, fossil fuels with carbon capture, hydrogen and ammonia.

 Electricity networks are the backbone of electricity systems, and need to expand andmodernise to support energy transitions. Total grid lengths increase by about 90%
from 2021 to 2050 in the STEPS, and another 30% in the APS. Annual investment risesin the STEPS from around USD 300 billion in recent years to USD 550 billion by
2030 and averages USD 580 billion per year to 2050. In the APS, investment rises
further to USD 630 billion in 2030 and USD 830 billion in 2050. However, complex
projects can take a decade or more to deliver, which is twice as long in most cases asdeveloping solar PV, wind or electric vehicle charging infrastructure. Long‐termplanning is vital and must account for, among other things, demand growth,
increasing amounts of variable renewables, as well as opportunities for digitalisation.

 Critical mineral demand linked to the electricity sector is set to rise from 7 Mt per year

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in 2021 to reach 11 Mt in 2030 and 13 Mt in 2050 in the STEPS as a result of increasing
deployment of renewables, battery storage and networks. It grows much faster in the
APS and NZE Scenario, reaching 20 Mt per year by 2050. Copper for grids, silicon forsolar PV, rare earth elements for wind turbine motors and lithium for battery storage
will be pivotal; critical minerals are a key component of the energy and electricity
security landscape. Additional R&D is needed to reduce mineral intensity and enable
mineral substitution in key applications, along with recycling, reuse of electric vehicle
batteries and end‐user energy efficiency measures.

How is the electricity
mix changing?

How to read

2010

2021

STEPS

APS
2030

Low-emissions sources of electricity, led by renewables, arepoised to overtake fossil fuels by 2030 in the STEPS and
APS, ending decades of growth for coal.

10%

13%

Coal unabated

9 040

1%

Share

TWh

8 670

Nuclear20%

10 200

10%

3 350

3 550

Renewables
4 230

8 060

15 07017 570

Solar PV

28%
43%

30

49%

4 010

8 080

1 000
4 840

Wind

6 550

67%

340

62%
47%

6 100

6 850

2 780

10%

Natural gas unabated
4 860

2 760

41%

Other

4 600

1 870

5 820

Other renewables
1 020

740

520

580

2021

STEPS 2030

Unabated fossil fuels

Renewables

2010

2021

APS 2030

Nuclear

Other

3 860

5 190

6 460

6 920

What drives electricity
demand growth?

What new power
capacity will be built?

Global electricity demand rises by 25-30% to 2030
in the STEPS and APS due to more electric motors,
EVs, heat pumps and hydrogen.

Renewables are set to dominate global capacity
additions, accounting for 75-80% of all new capacity to2050 in the STEPS and APS, led by solar PV and wind.

2010
Change 2010-21

STEPS 2021-30
APS 2021-30

80%
Electric cars

20 000 units in 2010
+17

40%

+167
+214

Million units
HydrogenAluminium
ChemicalsSpace heating
Space cooling

0

750

1 500

2 250

3 000 TWh0%
AfricaChina European India
Korea
Middle
Union
East
United States
Japan
Central andSoutheast Asia
World
South America
Solar PV
Hydro
BioenergyWind
APS 2050
Other renewables

Introduction
Electricity accounts for about 20% of the world’s total final consumption of energy, but its
share of energy services is higher due to its efficiency. It is central to many aspects of daily
life and becomes more so as electricity spreads to new end‐uses, such as electric vehicles(EVs) and heat pumps. The electricity sector accounted for 59% of all the coal used globallyin 2021, together with 34% of natural gas, 4% of oil, 52% of all renewables and nearly 100%of nuclear power. It also accounted for over one‐third of all energy‐related CO2 emissions in
2021.
This chapter mainly draws on two scenarios, the Stated Policies Scenario (STEPS) and theAnnounced Pledges Scenario (APS). As described in Chapter 2, the STEPS maps out a
trajectory that reflects current policies, while the APS assumes that all long‐term emissions
and energy access pledges and targets are met on time and in full. This chapter also draws
on the updated Net Zero Emissions by 2050 (NZE) Scenario, which describes a cost‐effective
pathway for the world to achieve net zero emissions by mid‐century in the energy sector that
also limits cumulative emissions in line with a 50% chance of limiting the global averagetemperature increase to 1.5 °C by 2100.
This outlook for electricity is produced through simulations in the Global Energy and Climate
Model (GEC‐M), which assesses energy demand sectors at the end‐use level in 26 regions. It
takes account of over 100 electricity generation technologies, plus energy storage andnetwork infrastructure, and makes use of an hourly model of electricity demand and supply
by end‐use and technology for major markets.
Section 6.1 provides an overview of the outlook for supply and demand in the global
electricity sector.
Section 6.2 takes a deeper look at electricity demand by region, sector and end‐use acrossthe scenarios. It also examines the importance of energy efficiency in clean energy
transitions.
Section 6.3 highlights key trends in electricity supply, including the speed of the shift fromunabated fossil fuels to renewables, nuclear and other low‐emissions options. It also
provides a regional view of major supply trends.
Sections 6.4 deals with CO2 emissions from electricity generation.
Section 6.5 considers the investment needs of the electricity sector in each scenario.

Power system flexibility needs and how to meet them, with a focus on battery storage.



Grid expansion and the challenge of timely development to support transitions.



Rising demand for critical minerals in electricity and options to moderate demand.

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Sections 6.6 to 6.8 explores three key themes for the electricity outlook:Scenarios
6.1

Overview

Global electricity demand increases significantly in all the three scenarios by 2050. It rises
from 24 700 terawatt‐hours (TWh) in 2021 by about 80% in the STEPS, by 120% in the APS
and by 150% in the NZE Scenario (Table 6.1). Electricity demand growth to 2030 is 2.4% peryear in the STEPS, which is below the annual average of 2.6% from 2010 to 2021, but is 2.8%
in the APS and 3.5% in the NZE Scenario, reflecting faster electrification of end‐uses. From
2030 to 2050, electricity demand growth slows in the STEPS, but in the APS and NZE Scenario
robust growth continues until 2040 before slowing. The buildings sector is the largest
consuming electricity sector today and remains so in the STEPS and APS through to 2050,
with industry the second‐largest. Other uses of electricity rise rapidly, especially in the APS
and NZE Scenario, as more EVs (battery electric vehicles and plug‐in hybrids) hit the road andas the use of clean hydrogen ramps up.

6

Global electricity demand and supply by scenario (TWh)
STEPS

APS

NZE

2010

2021

2030

2050

2030

2050

2030

2050

Buildings

9 637

12 59415 38321 94014 88919 62313 29315 850Industry

7 450

10 166

12 03615 07312 47118 33213 776

21 697

Transport

295

441

1 169

3 607

1 570

7 845

2 236

10 243

‐

2

159

663

879

5 714

2 464

11 43318 54824 70030 62143 67231 75253 81033 73362 159Unabated coal

8 670

10 201

9 044

5 892

8 076

1 580

4 666

0

Unabated natural gas

4 855

6 552

6 848

6 658

6 100

3 577

4 977

82

969

682

432

312

363

175

180

3

‐

1

5

133

75

1 338

282

1 317

Nuclear

2 756

2 776

3 351

4 260

3 547

5 103

3 896

5 810

Hydropower

3 449

4 327

5 078

6 809

5 213

7 543

5 725

8 251

342

1 870

4 604

10 691

5 816

17 4167 840

23 486

Solar PV

32

1 003

4 011

12 1184 838

18 761

7 551

27 006

Other renewables

411

859

1 380

2 833

1 707

5 153

1 948

5 762

Hydrogen production
Global electricity demand

Unabated oil
Fossil fuels with CCUS

Wind

Hydrogen and ammonia

‐

‐

9

44

79

567

603

1 467

Global electricity supply

21 53928 33434 83449 84535 87861 26837 72373 232

20%

28%

43%

65%

49%

80%

61%

88%

Renewables share

Notes: TWh = terawatt‐hours; CCUS = carbon capture, utilisation and storage; PV = photovoltaics. STEPS =Stated Policies Scenario, APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050 Scenario.
Electricity demand is defined as total gross electricity generated less own use generation, plus imports, lessexports and transmission and distribution losses. Other sources are included in electricity supply.

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Table 6.1 ⊳Global electricity supply is projected to shift away from unabated fossil fuels after recoveringfrom current market disruptions. A number of countries marked a return to coal‐fired power
in 2022 as the economic recovery from Covid‐19 pushed up electricity demand and asconcerns rise about high natural gas prices and energy security. In the STEPS, the share ofunabated coal in global electricity generation declines from 36% in 2021 to 26% in 2030 and
12% in 2050, while the share of unabated natural gas falls from 23% in 2021 to 20% in 2030
and 13% in 2050. Emissions pledges and goals drive faster reductions in the APS, where
unabated coal falls to 23% of generation in 2030 and just 3% in 2050, and unabated natural
gas drops to 17% in 2030 and just 6% by 2050 – the lowest share in 50 years. Oil makes up
2% of electricity supply today, and is mainly used in remote areas or near oil production sites:
its use is set to decline further in all scenarios as generators turn to cheaper and low‐emissions alternatives. Unabated coal, natural gas and oil decline even faster in the NZE
Scenario, with electricity reaching net zero emissions globally by 2040.
Figure 6.1 ⊳Global growth in renewable electricity relative to total electricity
generation growth by scenario, 2021-2050
2030‐50

Thousand TWh

2021‐30
25

50

20

40

15

30

10

20

5

10

Solar PV

STEPS
Wind

APS
NZE
STEPS
Hydro Bioenergy and other renewables

APS
NZE
Total electricity generation
IEA. CC BY 4.0.

Renewables outpace the increase of total generation in the STEPS,
while they grow faster in the APS and displace more unabated fossil fuels

Renewable energy technologies currently provide close to 30% of electricity generation andare set for rapid growth in all scenarios, led by solar photovoltaics (PV) and wind. Whilerenewables now represent the cheapest source of new electricity in most markets, the paceof their expansion depends on the retirement or reuse of existing sources of electricity
generation as well as on new capacity, and therefore still rests largely in the hands of policy
makers. In the STEPS, the growth of renewables generation exceeds the increase in total
generation to 2030 and to 2050 (Figure 6.1), reducing the need for unabated fossil fuels.
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Note: TWh = terawatt‐hours; STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net
Zero Emissions by 2050 Scenario.

In the APS, solar PV and wind alone outpace even higher demand growth to 2030 and 2050,
unlocking deeper emissions reductions. In the NZE Scenario, renewables growth is 40% fasterto 2030 and 20% faster to 2050 than in the APS, and this leads to electricity being rapidly
decarbonised.

6.2

Electricity demand

Global electricity demand climbed to 24 700 TWh in 2021 – an increase of 6% from theprevious year and the biggest annual increase since 2010 – reflecting a rebound in many
economies following the pandemic. Nearly three‐quarters of the global increase in electricity
demand in 2021 was in emerging market and developing economies, with China alone
accounting for about 700 TWh, or 50% of the global increase, an amount equivalent to total
electricity demand in Africa today. Worldwide the current share of electricity in total final
energy consumption is 20%. The largest electricity consumers are China, United States andEurope; together they account for over 60% of global electricity demand (Table 6.2).
Table 6.2 ⊳6Electricity demand by region and scenario, 2010-2050 (TWh)

STEPS

APS

2010

2021

2030

2050

2030

2050

North America

4 632

4 852

5 266

6 830

5 544

8 786

United States

3 880

4 004

4 281

5 482

4 529

7 187

932

1 097

1 308

2 168

1 447

2 940

Central and South America
Brazil

451

541

622

985

637

1 138

Europe

3 567

3 645

4 182

5 060

4 639

6 561

2 574

2 608

2 922

3 327

3 271

4 348

570

707

994

2 041

1 128

3 355

214

194

229

365

248

494

709

1 064

1 372

2 430

1 343

2 878

European Union
AfricaSouth Africa
Middle East
Eurasia

985

1 181

1 291

1 669

1 280

1 652

Asia Pacific

7 154

12 16416 20823 47516 37127 638

China

3 659

7 556

9 969

12 8689 940

14 504

India

717

1 273

2 117

4 293

2 107

5 314

Japan

1 071

934

893

922

952

1 153

607

1 037

1 537

2 848

1 580

3 214

18 54824 70030 62143 67231 75253 810Southeast Asia
Global electricity demand

Electricity demand increases at 2.4% per year in the STEPS over the rest of this decade toreach more than 30 600 TWh by 2030. Demand grows faster in the APS, reaching around
31 750 TWh in 2030. Between 2030 and 2050, electricity demand growth in the STEPS slows
to 1.8% per year to reach around 43 700 TWh by 2050. In the APS, annual demand growth is
2.7% after 2030 to reach nearly 54 000 TWh by 2050.
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Note: TWh = terawatt‐hours.

Today’s unfolding global energy crisis has led to soaring electricity prices for consumers. For
example, the average residential electricity price in the European Union was about 30%
higher in the first‐half of 2022 than during the same period in 2021 (IEA, 2022a; Energie‐Control Austria, MEKH and VaasaETT, 2022). To tackle the crisis in the short‐term and limit
the impact of high wholesale electricity prices, some European governments have introduced
measures such as price caps on retail electricity prices, subsidies for fossil fuel power
generators, windfall taxes on profits and payments to shield end‐users from rising electricity
bills (Spotlight). Action to cushion the impact on end‐users is understandable, nevertheless,there is a risk that muted electricity price signals may discourage the essential behaviourchanges and efficiency improvements that reduce demand and, by doing so, help reduce
prices. In a search for longer term solutions, the European Union is exploring whether thecurrent electricity market design needs to be overhauled.
Despite the turbulence in today’s electricity markets, the momentum for further
electrification is strong across the world, with the deployment of electric cars and theinstallation of heat pumps set to increase, and with electricity being used to meet new end‐
uses. Electricity prices have risen dramatically, but so have prices for oil, natural gas and coal.
Electricity generation moreover is set to reduce its dependence on fossil fuels in the years
ahead, thus reducing emissions and enhancing its attractiveness. Reduced dependence on
fossil fuels could also bring energy security benefits, provided that electricity grids areenhanced to help ensure resilience. In the STEPS, the share of electricity in total final
consumption reaches 22% in 2030 and 28% in 2050. In the APS, these shares rise to 24% andnearly 40% respectively, and in the NZE Scenario they rise further to 28% and over 50% by
2050.

Electricity demand by region

In advanced economies, average electricity demand per capita declined by 0.2% per year
since 2010, but is projected to increase by 0.8% per year by 2030 in the STEPS and twice as
fast in the APS. Transport emerges as the largest contributor to electricity demand growth inboth scenarios, mainly due to the rapidly increasing number of EVs. In the United States, themarket share of electric cars increases from less than 5% in 2021 to 30% in the STEPS and
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A more granular look at regional trends reveals important differences in the evolution ofelectricity demand around the world. One of the most rapid increases in electricity
consumption in recent years has been in China, where it doubled between 2010 and 2021 asa result of rapid economic and industrial growth (Figure 6.2). By far, China is now the world’s
largest consumer of electricity: it accounts for 30% of the global total, almost twice as muchas the United States, the second‐largest consumer with 16% of the global total. Advanced
economies have seen a decline of over ten percentage points in their share of global
electricity demand since 2010 as demand has surged in emerging market and developing
economies. This trend continues in both the STEPS and APS as continuing rapid energy
demand growth and electrification take place in China, India, Middle East and Africa,
especially in the industry and buildings sectors.

50% in the APS by 2030, with the increase stemming predominantly from the lnflation
Reduction Act and state‐level targets. The share of electricity in total final consumption in
the United States increases from 21% in 2021 to 23% in the STEPS and to 24% in the APS by
2030. In the European Union, the accelerated deployment of heat pumps in buildings andindustry and the expansion of the electric car fleet by around 35 million help to increase theshare of electricity in total final consumption from 21% in 2021 to 25% in the STEPS and 29%
in the APS by 2030. Efficiency gains from modern appliances and heating and cooling systems
temper the growth in demand and the relatively high levels of electricity demand per capita.
Electricity demand in key regions by scenario, 2010-2030

Figure 6.2 ⊳Emerging market and developing economies

Index (2021=1)

Advanced economies
1.6

1.2

6

0.8

0.4
2010
STEPS
APS

2020

2030 2010
United States
China

2020
European Union
India

2030
Japan
AfricaIEA. CC BY 4.0.

Electricity demand rebounds in most advanced economies after a decade of flat demand,

In emerging market and developing economies, average annual electricity demand per capita
increased by 3.5% between 2010 and 2021. It continues to grow at an annual average rateof 2.2% in the STEPS and 2.3% in the APS through to 2030. Electricity demand in China
increases in both scenarios by over 30% to 2030, and its share in global electricity demandrises in both scenarios in 2030 as its economy shifts towards services and high‐techindustries. Economic growth and rising standards of living in India increase household
appliance ownership and increase electricity demand by two‐thirds by 2030 in bothscenarios. A similar level of growth is projected in Indonesia: buildings account for the
majority of this, driven in large part by an increase in the number of people with air
conditioners as the country moves from an average of 0.1 units per household today to
0.4 per household by 2030. On the African continent, around 150 million people gain accessto modern electricity services in the STEPS by 2030 and nearly 480 million in the APS; there
is also a rise in ownership of appliances such as refrigerators and fans. These developments
lead to increases in electricity demand of more than 40% in the STEPS and around 60% in the
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while it continues to grow strongly in emerging market and developing economies

APS by the end of this decade. The progress made in improving access to electricity in Africa
by 2030 accounts for nearly 70% of the progress made worldwide in the STEPS: this rises toover 80% in the APS.
Global electricity demand increases by around 5 900 TWh between 2021 and 2030 in the
STEPS, which means an annual rate of growth slightly lower than over the last decade.
Demand growth is faster in the APS, which sees an increase in demand of over 7 000 TWh
between 2021 and 2030, equivalent to nearly 70% of current electricity demand in advanced
economies (Figure 6.3). Announced pledges lead in the APS to a more rapid deployment of
EVs across all vehicle categories, and of heat pumps in buildings and for industrial processes.
In the NZE Scenario, electrification goes even further than the APS as electricity demandsurpasses 62 000 TWh by 2050, 40% higher than the STEPS levels. By 2030, the increase in
the NZE relative to the STEPS is similar in both advanced economies and emerging market
and developing economies.

TWhFigure 6.3 ⊳Electricity demand growth by region and scenario, 2012-2030

8 000

Other EMDE
India
China
Other advanced
economies
European Union
North America

6 000

4 000

2 000

2012‐212021‐30
STEPS

2021‐30APS
IEA. CC BY 4.0.

Global electricity demand growth picks up over the next decade, as a slowing
in China is more than counterbalanced by strong increases in many other markets

The rapid penetration of electric motors in industrial processes and higher levels ofownership of appliances and air conditioners bring about a sharp rise in electricity demandin a number of emerging market and developing economies, notably in India and otheremerging Asian economies. China’s demand for electricity increases too, but at a slower rate.
This changes the landscape of electricity demand over time. Between today and 2030,
China’s share of global electricity demand growth in emerging market and developing
economies declines from the level of two‐thirds seen over the last decade to about half inboth the STEPS and the APS.
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Note: EMDE = emerging market and developing economies.

Electricity demand by sector
The biggest consumers of electricity today are the buildings and industry sectors, which
together account for over 90% of global electricity consumption and have contributed over
90% (around 5 700 TWh) of global electricity demand growth since 2010. In buildings,
electricity is consumed largely by appliances (45%) and by space cooling and heating (nearly30%). By 2030, electricity demand for heating in buildings is smaller in the APS than in the
STEPS as a higher level of efficiency improvements in the APS more than compensates thehigher rate of electrification (Figure 6.4). In industry, electricity is mainly used for electricmotors, but also for aluminium smelting and electric arc furnaces. Industry is the end‐use
sector that accounts for one‐third of the total electricity demand increase in the STEPS and
the APS by 2030: economic growth drives industrial output in emerging market anddeveloping economies, and policies to reduce emissions spur the electrification of industrial
equipment.

TWhFigure 6.4 ⊳Global electricity demand and share of electricity in energy
consumption in selected applications by scenario, 2021 and 2030

7 500

100%

6 000

80%

4 500

60%

3 000

40%

1 500

20%
Hydrogen

Intensiveindustries

Other
industry

Appliances

Electricity demand:
Electricity share in consumption (right axis):

Coolingand heating

2021
2021

2030:
2030

6

Light‐duty
vehicles

STEPS
STEPS

APS
APS
IEA. CC BY 4.0.

The electrification of many end-uses moves forward, though to varying degrees, raising
electricity demand from established uses and new ones, like EVs and hydrogen production

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Notes: Hydrogen corresponds to electricity needs for its production and the share of electricity in the totalenergy consumed during the process of hydrogen production. Appliances include refrigerators, washing anddishwashing machines, dryers, brown appliances (relatively light electronic appliances such as computers or
televisions) and other electric appliances (excluding cooking, lighting, cooling, cleaning and desalination).
Cooling and heating include space and water heating as well as space cooling in buildings. Intensive industries(Energy‐intensive industries) include iron and steel, chemicals, non‐metallic minerals, non‐ferrous metals, andpaper, pulp and printing industries. Other industry includes the remaining industrial sub‐sectors, i.e.
construction, mining and textiles.

Transport is the one of the leading contributors to electricity demand growth in the
projections, especially in advanced economies. The number of EVs has increased rapidly inrecent years; the current global EV fleet consumes nearly 100 TWh of electricity per year.
Electric car sales reached 6.6 million in 2021 and are expected to surpass 10 million in 2022.
In the STEPS, electric cars gain a market share of 25% by 2030; in the APS, this rises to over
35%. This rapid electrification of mobility is brought about by national and regional policies
as well as ambitious targets from vehicle manufacturers (see Chapter 5). By far, rail was thelargest consumer of electricity in transport over the last decade, but electricity demand inroad transport surpasses rail by 2027 in the STEPS and a year earlier in the APS.
In the STEPS, the global electric car fleet expands eleven‐fold in the coming decade, adding
over 380 TWh to current global electricity demand (and boosting the scope for the use of EVs
to balance grids and demand‐side management alleviating potential integration challenges).
Electrification is mainly focused on passenger vehicles (passenger cars, urban buses andtwo/three‐wheelers), with progress on heavy trucks slowed by more complicatedinfrastructure needs such as deployment of high power chargers.

TWh

Figure 6.5 ⊳Electricity demand growth by application in the APS, 2021-2050

6 000

2021‐30:
Advanced
economies

5 000
4 000

EMDE

3 000
2 000

2030‐50:
Advanced
economies

1 000

EMDE

0
‐1 000Industry

Hydrogen

LDVs

Cooling Appliancesand heating

EnergyaccessIEA. CC BY 4.0.

Industry, hydrogen production and light-duty vehicles contribute significantly
to electricity demand growth in economies around the world

The rapidly rising demand for cooling in emerging market and developing economies makes
it a large contributor to electricity demand growth, with climate change compounding thedemand for cooling (see Chapter 5). In emerging market and developing economies, coolingneeds rise, adding another 2 800 TWh to global electricity demand by 2050 in the STEPS. For
example, the ownership of air conditioners is projected to increase by 40% from the current
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Notes: EMDE = emerging market and developing economies; LDVs = light‐duty vehicles. Energy accessrepresents the electricity demand that satisfies basic energy needs of people gaining energy access for the
first time. Cooling and heating corresponds to electricity demand for space cooling and heating needs.

level in China by 2030. Energy efficiency policies are effective in tempering electricity
demand (Box 6.1), therefore keeping this increase down to 1 400 TWh in the APS. Even more
stringent efficiency standards for air conditioners, together with better insulation in homes,
help to restrict additional electricity demand to only 765 TWh in the NZE Scenario, despite
additional acceleration of electrification in this scenario.
Energy access constitutes a minor part of the increase in electricity demand, even though
cumulatively over 580 million people gain access from today to 2030 and over 1 billion by
2050 in the APS. This reflects the low average electricity consumption of a person gaining
access to electricity for the first time, and it shows that energy poverty reduction can beachieved with only a relatively small increase in global electricity demand (Figure 6.5).
Box 6.1 ⊳Energy efficiency tempers electricity demand growth
and reduces raw material needs

A major shift towards EVs and heat pumps takes place across the world in the STEPS.
Increasing cooling and heating needs, especially in emerging market and developing
economies, also increase electricity consumption. Global total electricity consumption
rises by nearly 18 000 TWh by 2050, which is roughly equivalent to current electricity
demand in China and advanced economies combined. This implies a need to expand
global electricity generation by three‐quarters by 2050. Without energy efficiency gains,
however, this level would be around 10 000 TWh higher (Figure 6.6).

TWh

Figure 6.6 ⊳6Global total electricity consumption with and without
energy efficiency gains in the STEPS, 2015-2050

50 000Electricity demand without
efficiency savings
Other
Road transport
AppliancesSpace heating
Space cooling
Other industry
Energy‐intensive
industries

40 00030 000Electricity
demand20 000
2015

2020

2025

2030

2035

2040

2045

2050
IEA. CC BY 4.0.

Energy efficiency gains cut electricity consumption

Note: Efficiency gains are mainly due to stricter fuel economy standards in road transport; minimum
energy performance standards and labels in the buildings sector; technological improvements andmaterial recycling in industry.

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growth by around 10 000 TWh in the STEPS by 2050

In the STEPS, improved efficiency standards for appliances and motors, better insulationin buildings, optimised logistics and energy efficiency improvements in vehicles together
lead to global electricity demand being about 10% lower than it otherwise would be in2030 and around 20% lower two decades later. These gains highlight the huge part thatenergy efficiency has to play to moderate electricity demand, reduce requirements for
additional power capacity and temper demand for the critical minerals needed in low‐emissions power systems, grids, EVs and storage batteries (see section 6.8).

6.3

Electricity supply

The global share of fossil fuels in electricity generation declined from around 65% in 2018 to
62% in 2021 reflecting the rapid rise of solar PV and wind in power generation over the past
decade. Current market conditions are also driving change. Global prices for oil and natural
gas began rising rapidly in late 2020 as demand recovered with the easing of Covid‐19
restrictions. This trend was hugely exacerbated in early 2022 by Russia’s invasion of Ukraine.
Concerns about the price of natural gas and energy security have led to a temporary return
to coal‐fired generation in some cases, but they have also sparked an ambition in somecountries to make faster progress on reaching net zero emissions through enhanced support
for combinations of renewables, nuclear power, carbon capture, hydrogen and ammonia, as
well as earlier coal phase outs. This ambition builds on technology innovation and progress,
including declining costs for solar PV, wind and batteries, together with advances in thedevelopment of small modular nuclear reactors and the use of hydrogen and ammonia infossil fuelled power plants.

Recent policy developments

During or after the COP26 in November 2021, several additional countries pledged to reachnet zero emissions, e.g. Indonesia in 2060 or earlier and India by 2070. As of September 2022,
83 countries and the European Union had established net zero emissions targets.
G7 members have also committed to ensuring that their power sectors are fully or
predominantly decarbonised by 2035, and the measures they take to this end may help toclear a path for other countries (IEA, 2022b). The number of countries with renewable power
policies rose from 145 in 2020 to 156 in 2021, continuing a multi‐year trend. By the end of2021, most countries worldwide had a renewable energy support policy in place, with most
support continuing to focus on the power sector and less effort being made to accelerate
renewables in the buildings, transport and industry sectors. The total number of countries
with economy‐wide targets for 100% renewables increased to 36 by the end of 2021, up from32 the previous year (REN21, 2022).
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The policy landscape is a key determinant of the outlook for the electricity sector and it
continues to evolve in the light of market conditions and world events. There have been anumber of recent policy developments that will have an impact on the electricity supply
outlook (Table 6.3).

Recent policy changes and announcements regarding
electricity supply
Policy change

Authority

European Union Phase out coal‐fired power plants in Czech
Republic, Slovenia and Romania (emergency law).

Governments(January and June 2022)

United States

 Inflation Reduction Act provides funding forenergy and climate programmes, including
expanding and extending tax credits andincentives to promote clean energy technologies.

Federal government(in law August 2022)

 Five states updated their renewable portfolio
standard policies.

Various state governments

China New Plan for Renewable Energy Development:
higher targets for renewables.

National Development andReform Commission(June 2022)

Canada 2030 Emissions Reduction Plan outlines a sector‐
by‐sector path to reach its emissions reduction
target of 40% below 2005 levels by 2030 and net
zero emissions by 2050.

Federal government(June 2022)

Korea

 Increase renewables in electricity generation toover 20% and nuclear power to over 30%, anddecrease coal‐fired power by 2030 under the
New Energy Policy Direction.

State Council(July 2022)

Australia

 Climate Change Bill 2022 enshrines in law twonational greenhouse gas emissions targets: 43%
cut below 2005 levels by 2030 and achieve net
zero emissions by 2050.

Federal government(in law July 2022)

Japan

 Restart nuclear power plants aligned with the
6th Strategic Energy Plan and the Green
Transformation (GX) policy initiative.

Ministry of Economy, Tradeand Industry (Aug 2022)

Announced policy

Authority

G7 members

 Achieve predominantly decarbonised electricity
sectors by 2035.

G7 Ministers of Climate,
Energy and the Environment(May 2022)

European Union Fit for 55: Council agrees on binding 40% EU‐leveltarget for renewables in overall energy mix.

Council of theEuropean Union (June 2022)

Germany Green energy law reforms set higher targets forwind and solar.

Government (July 2022)

Australia,
Côte d’Ivoire, Israel,
Nauru, United ArabEmirates, Viet Nam

 Net zero emissions targets by 2050.

Various national
governments

Bahrain, Indonesia,
Nigeria, Saudi Arabia

 Net zero emissions targets by 2060.

Various national
governments

India Net zero emissions target by 2070.

Prime Minister (Nov 2021)

United Kingdom

 Energy Security Strategy sets new ambitions foroffshore wind, nuclear and hydrogen.

Prime Minister (April 2022)

Japan Accelerated nuclear expansion, including SMRs,
envisioned in the GX initiative.

(June 2022)

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Table 6.3 ⊳In addition to action on renewables, Germany and several other European countries arereverting to coal‐fired power plants to cut their reliance on natural gas imported from Russia
and to bolster energy security. This is a temporary measure: the current natural gas crisis
looks likely in the medium term to lead to a determination to reduce reliance on imported
fossil fuels in the name of energy security. Moreover, all G7 Members committed to“prioritising concrete and timely steps towards the goal of accelerating phase‐out ofdomestic unabated coal power” (European Council, 2022).
A rising number of countries have announced plans to support new nuclear investment. For
example, in February 2022, France announced plans to build six new large reactors startingin 2028 at a cost of about EUR 50 billion, with an option to build eight more by 2050. Chinaplans to continue its current pace of construction of nuclear reactors in order to help meetits goal of carbon neutrality by 2060. Korea has recently reversed its nuclear phase‐out policy
and now supports lifetime extensions of existing facilities, the restarting of construction at
two sites and an increase in the share of nuclear in electricity generation.
Other recent policy developments affect a range of low‐emissions energy sources. In the
United States, the Inflation Reduction Act provides additional funding and tax credits toincentivise multiple sources of clean energy, including energy storage, nuclear power, clean
energy vehicles, hydrogen and carbon capture, utilisation and storage (CCUS), while the US
Bipartisan Infrastructure Law will help fund new transmission lines to facilitate the expansionof renewables and clean energy. Canada recently announced a tax credit for capital invested
in new CCUS projects. Plans to use hydrogen and ammonia in the power sector haveadvanced, with strengthened policies or targets in many countries, including in Europe,
Japan, Korea and India (IEA, 2022c).

Electricity supply by source

Renewables are projected to account for the majority of capacity additions in every region
over the outlook period (Figure 6.8). By far, wind and solar PV are the largest contributors tothis development, and total installed solar PV capacity in particular is projected to far outstripthat of any other source in both the STEPS and the APS from the 2030s onwards. In the STEPS,
wind and solar PV together set new records every year to 2030 and then continue robust
annual growth through to 2050. In all regions, they account for between 45% and 85% of all
capacity additions over the period to 2050. Both solar PV and wind assume an even larger
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Renewables are set to become the dominant source of electricity worldwide in the longterm. Total electricity generation from renewables increased by more than 500 TWh from its
2020 level to reach a record high of over 8 000 TWh in 2021, driven mostly by rising solar PV
and wind generation (Figure 6.7). As a result, the share of renewables in global electricity
generation rose by 0.2 percentage points to reach nearly 29% for the first time. Renewables
continue to scale up rapidly in the STEPS, with their share of generation rising to 43% by 2030
and 65% by 2050. The APS sees an even faster transition to renewables, with 35% higher
growth than in the STEPS to 2030.

role in the APS: annual wind capacity additions increase from 95 GW in 2021 to 210 GW in
2030 and 270 GW in 2050, while solar PV capacity additions rise from 151 GW in 2021 to
370 GW in 2030 and nearly 600 GW in 2050. In the NZE Scenario, renewables increase evenmore rapidly, with their share of total generation increasing from 29% in 2021 to over 60%
in 2030 and nearly 90% in 2050. The huge rise in the share of solar PV and wind in total
generation in all scenarios fundamentally reshapes power systems and significantly increases
the demand for power system flexibility (see section 6.6).
Figure 6.7 ⊳Global electricity generation by source and scenario,
2010-2050
Unabated coal
Unabated natural gas
Fossil fuels with CCUS
Nuclear
Hydro
Wind
Solar PV
Other renewables
Hydrogen and ammonia
Other

STEPS

2030
2050

APS

2030
2050

NZE

2010
2021

2030
2050
20

40

6

60
80
Thousand TWh
IEA. CC BY 4.0.

Electricity generation from unabated fossil fuels peak by 2030, as low-emissions sources
ramp up and renewables dominate electricity supply in all scenarios by 2050
Note: Other renewables include bioenergy and renewable waste, geothermal, concentrating solar power andmarine power.

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Hydropower and other dispatchable renewables continue to play an important role in all
the scenarios. In the STEPS, hydropower remains the largest source of renewable electricity
until after 2030, when it is surpassed by both wind and solar PV. In the APS, hydropower andother dispatchable renewables such as bioenergy, geothermal and concentrating solar
power (CSP) increase faster to help cut electricity sector emissions more quickly andintegrate the fast rising share of variable wind and solar PV electricity generation. The roleof hydropower to help provide power system balance and stability, however, may beaffected by climate‐related events, which have reduced its availability in many regions overthe last year, straining power grids and raising questions about the resilience of electricity
systems (Box 6.2).

Figure 6.8 ⊳Share of renewables in total power capacity additions
by region in the STEPS, 2022-2050
Solar PV

China
C & S America

Wind

European Union

Hydro

Japan

Bioenergy

India

Other renewables

World

APS

Korea
United States
AfricaSoutheast Asia
Middle East
20%

40%

60%

80%

100%
IEA. CC BY 4.0.

Renewables account for the majority of capacity additions in all regions,with massive growth for solar PV and wind in all markets, followed by hydro in many
Note: C & S = Central and South America.

The continued role of nuclear power in the electricity sector relies on decisions to extend
the lifetime of existing reactors and the success of programmes to build new ones. In the
STEPS, nuclear maintains its share of about 10% in total electricity generation. This requires
the completion of 120 GW of new nuclear capacity over the 2022‐30 period, as well as the
addition of another 300 GW worth of new reactors (the equivalent of almost three‐quartersof the current global fleet) between 2030 and 2050 in over 30 countries. In the APS, around
18 GW of new nuclear capacity is added per year over the outlook period, over a quartermore than in the STEPS, but the higher level of electricity demand in this scenario means thatthe nuclear share of the electricity supply mix remains at close to 10%. In the NZE Scenario,a wave of lifetime extensions in advanced economies in the 2020s helps limit global
emissions, and an average of 24 GW of capacity added each year between 2022 and2050 more than doubles nuclear power capacity by 2050. The nuclear share of the electricity
mix, however, falls to 8% in 2050 due to very strong growth in electricity demand in the NZE
Scenario. More information on the potential and challenges for nuclear energy, including
new, small modular reactors, is provided in the IEA special report Nuclear Power and Secure
Energy Transitions (IEA, 2022d).

1

Hydrogen in gas‐fired power plants includes both co‐firing and full conversions.

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Other dispatchable low‐emissions technologies include fossil fuels with CCUS, and co‐firingwith ammonia in coal plants and hydrogen in gas‐fired power plants.1 These technologies
are currently at the pre‐commercial stage of development and significant efforts would berequired for them to start being deployed at scale before 2030. In the STEPS, CCUS
technologies gain a limited amount of traction over the outlook period, as the commitments
to deep CO₂ emission reductions that provide the impetus for the deployment of CCUS have
not yet been converted into concrete implementation plans in most countries. In the APS, bycontrast, the first CCUS retrofits are completed before 2030, and over 200 GW of coal‐fired
capacity and over 80 GW of gas‐fired plants equipped with CCUS are in operation by 2050
(Figure 6.9), together accounting for 2% of total global electricity generation. Most CCUS
deployments take place in China; other significant applications are in Indonesia, Japan andthe United States.

GW

Figure 6.9 ⊳Global installed electricity capacity by source and scenario,
2010-2050
Stated Policies

12 000

Announced Pledges

10 000

6

8 000
6 000
4 000
2 000
2010

2021

Unabated coal
Unabated natural gas
Oil
Fossil fuels with CCUS

2050 2021
Solar PV
Wind
Hydro
Other renewables

2050
NuclearHydrogen and ammonia
Battery
IEA. CC BY 4.0.

Solar PV and wind installed capacity moves well beyond any other source by 2050,

Similarly, the co‐firing of ammonia or hydrogen remains very limited in the STEPS, andaccounts for less than 0.1% of total electricity generation in 2050. The notable exception isJapan, where plans to co‐fire ammonia in coal plants are under development and where co‐fired ammonia and hydrogen are projected to reach a share of close to 5% of electricity
generation in 2050. In the APS, co‐firing makes strong inroads from 2030 onwards in otheradvanced economies too, and in particular in European Union, Korea and United States, withhydrogen seen as a tool to help achieve emissions reduction goals. In the NZE Scenario,
nearly 190 GW is retrofitted to co‐fire hydrogen or ammonia by 2030, rising to 580 GW by
2050. However, due to high cost, these fuels are primarily used as a source of flexibility tobalance variable wind and solar PV output. Their overall contribution to the global electricity
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taking the lead from coal- and natural gas-fired power todaysupply mix thus remains limited even in the APS (less than 1% in 2050) and NZE Scenario(close to 2% in 2050). The enormous size of the electricity sector nevertheless makes it oneof the primary drivers of global hydrogen demand.
Unabated natural gas supplied 23% of global electricity in 2021. After a short‐term decline,
gas‐fired generation rebounds in the STEPS, with increased demand in emerging market anddeveloping economies more than offsetting reductions in advanced economies, in particularin Europe. However, unlike in the World Energy Outlook (WEO)‐2021 (IEA, 2021a), which
projected growth, gas‐fired generation is now expected to stay at broadly the same level
until 2050. This is the result of a shift in perceptions about the role of natural gas that stems
from the current energy crisis and record prices for natural gas in all major markets. In the
NZE Scenario, natural gas‐fired generation increases slightly in the near term as a result ofcoal‐to‐gas switching, but peaks by 2025. Even as output falls, however, natural gas‐fired
capacity remains a critical source of power system flexibility in many markets.
Unabated coal met almost half of the increase in electricity demand in 2021, with its shareof total electricity generation exceeding 36%. Coal‐fired power plants under construction at
the start of 2022 represented over 175 GW of capacity with many more plants in the planningstage. In the STEPS, coal‐fired power plant capacity reflects this and continues to grow,peaking by 2025. Coal‐fired generation, however, is projected to enter a decline and falls
more rapidly as 2030 approaches. Unabated coal accounts for 26% of global electricity
generation in 2030, declining to 12% by 2050. Most advanced economies are pursuing coalphase‐out policies and they cut unabated coal use in the power sector by 60% from 2021 to2030. Coal use increases by 3% to 2030 in emerging market and developing economies, but
it then also enters a long‐term decline.
Coal sees the largest impact among all fuels from the fulfilment of announced pledges bygovernments. In the APS, unabated coal declines steeply from 2025 onwards, with its sharein electricity generation dropping to 23% by 2030 and just 3% in 2050. In advanced
economies, unabated coal generation falls nearly 80% by 2030 and is phased out completelyby 2050. In emerging market and developing economies, unabated coal use continues to rise
until 2025 before declining significantly, driven mostly by net zero emissions pledges in
China, India and Indonesia. In the NZE Scenario, no unabated coal plants beyond the ones
already under construction are commissioned. The share of unabated coal in global
electricity generation declines rapidly to 12% in 2030 and falls to zero by 2040. CCUS retrofits
play an important role in mitigating emissions from the relatively young coal fleet inemerging market and developing economies.
Will electricity systems be more resilient to climate risks in the future?

In addition to other threats to electricity security, global power systems faced a numberof climate‐related challenges over the last year. Heatwaves and droughts were significant
in many parts of the world, e.g. China, Europe, India, Myanmar, Pakistan, Sri Lanka, South
Africa and the United States. As a result, the availability of hydropower and cooling water
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Box 6.2 ⊳for thermal power plants was reduced, straining the ability of electricity systems to meetdemand, including for space cooling. Very cold temperatures also affected natural gas
infrastructure and caused electricity outages in countries including the United States.
Other extreme weather events caused damage to electricity infrastructure and extended
outages. For example, the 2021 Atlantic hurricane season brought the third‐highest
number of named storms on record, impacting Latin America and the Caribbean inparticular, while devastating flooding from heavy rains in 2022 affected millions ofpeople, notably in Bangladesh, India, Nigeria and Pakistan.
Climate risks are set to increase in all scenarios due to rising global temperatures,changing rainfall patterns, rising sea levels and extreme weather events. Changes in theelectricity sector will reduce exposure to some of these risks, but increase exposure toothers. The electrification of heating and cooling in all scenarios will place more strain onelectricity grids during extremely hot or cold periods. Electricity demand for cooling is set
to increase strongly in emerging market and developing economies in particular, risingnearly fourfold from 2021 to 2050 in the STEPS. Electric heating expands fastest in
emerging market and developing economies too, where the related consumption ofelectricity more than doubles to 2050 in the STEPS. In both cases, energy efficiency
efforts in the APS cut the electricity demand growth for heating and cooling to 2050 seenin the STEPS, reducing the strain on electricity networks during peak demand periods.
While adding to overall electricity demand, the expansion of EVs has the potential to help
alleviate the impacts of extreme hot and cold weather by helping to smooth demand
patterns through smart charging and vehicle‐to‐grid arrangements.

6

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In electricity supply, the resilience of fossil fuel infrastructure, particularly for natural gas,remains critical for electricity security even as the use of fossil fuels declines (seeChapter 4). However, the shift away from unabated fossil fuels in all the scenarios is likely
to increase resilience by reducing their use of cooling water. The increase in nuclear
power in all scenarios partly offsets this reduction in cooling water demand, but it also
reduces dependence on imported fossil fuels. The expansion of solar PV and wind in all
scenarios improves the resilience of electricity systems to some climate impacts, but it
also increases their exposure to seasonal weather patterns such as long periods of cold
and low wind in Europe. Electricity security will depend on having sufficient flexibility
available at all times. Flexibility will be especially important in the APS and NZE Scenario,
where solar PV and wind play a much larger role than in the STEPS (see section 6.6). There
are a number of effective steps that can be taken to improve the climate resilience ofelectricity systems, and thus to avoid outages, minimise repair costs and facilitate clean
energy transitions. These include steps to assess risks, incorporate climate resilience inenergy and climate plans, identify cost‐effective measures, incentivise utilities to takeaction, implement resilience measures and evaluate and adjust them to continuously
improve system resilience (IEA, 2021b).

Electricity supply by region
The electricity supply mix differs from region to region, reflecting available resources, policy
choices and the relative economic competitiveness of various power generation
technologies. Most power sector investment today is driven by policies, which play a majorrole in shaping the development of regional power mixes over the outlook period. A common
trend across all regions is the expanding contribution from wind and solar PV generation,
driven mainly by declining costs and robust policy support in many countries (Figure 6.10).
Figure 6.10 ⊳ Electricity generation by source, key region and scenario,
2021 and 2050

Japan
India

2021
2050 STEPS
2050 APS

Hydro

European
Union

2021
2050 STEPS
2050 APS

Other renewables

2021
2050 STEPS
2050 APS

China

Unabated natural gas

UnitedStatesUnabated coal
2021
2050 STEPS
2050 APS

Fossil fuels with CCUS
NuclearWind
Solar PV
Hydrogen and ammonia
Other

2 000

4 000

6 000

8 000

4 000

8 000

12 000

16 000TWh

2021
2050 STEPS
2050 APS

IEA. CC BY 4.0.

Electricity supply is set to shift away from unabated fossil fuels in all major markets,as renewables, nuclear, hydrogen, ammonia and carbon capture scale up

In China, unabated coal‐fired electricity generation accounts for more than 60% of electricity
supply and is still expanding, but the peak is approaching in all scenarios. In the STEPS,
unabated coal starts to decline before 2030 and falls by over 40% from its peak by 2050. In
the APS, coal use falls faster, with its share of the generating mix declining to 9% by 2050,
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Note: Other renewables includes bioenergy and renewable wastes, concentrating solar power and marine
power. Other includes non‐renewable waste and other sources.

nearly half of it from plants equipped with CCUS. Overall, China sees a profoundtransformation of its electricity supply mix over the period to 2050, with steps towards thisset out in 14th Five‐Year Plan to 2025. While total generation in 2050 rises by two‐thirds in
the STEPS and nearly doubles in the APS, the share of low‐emissions sources increases to
76% in the STEPS and close to 95% in the APS, up from 34% today. By far, the most significant
growth is from wind and solar PV. In the STEPS, these two technologies account for 80% of
all additional capacity installed between 2021 and 2050. With the world’s largest new build
programme, nuclear power too is set to rise significantly: the STEPS projects the constructionof more than 120 GW of additional nuclear capacity on top of the more than 50 GW which isoperational today.
In India, the primary challenge is how to meet rising electricity demand with renewables andnuclear on a large enough scale to reduce the use of unabated coal‐fired generation, which
provides nearly three‐quarters of electricity supply today. In both the STEPS and the APS,
coal generation is projected to continue rise in absolute terms, peaking around 2030, though
its share of electricity generation declines. Expanding renewables is the central means ofmeeting demand growth and limiting coal use, with solar PV leading the way and wind also
playing an important part. The APS shows that meeting current pledges in full calls forcontinued expansion of renewables and a scaling up India’s nuclear fleet so as to enable analmost complete phase‐down of unabated coal‐fired electricity generation by 2050, while
also maintaining grid reliability.

6

In the European Union, an emphasis on energy security and reducing reliance on imported
natural gas is expected to speed up the deployment of renewables. In the STEPS, thecombined share of wind and solar PV in the generation mix rises from 18% today to 42% in
2030 and 56% in 2050, with wind and solar PV accounting for more than 70% of all new
power capacity installed between 2021 and 2050. The expansion of solar PV and wind could
offer a degree of protection for consumers from market fuel price volatility of the kindcurrently being experienced (Spotlight). In the APS, the near term and medium‐term
expansion of renewables is even more rapid. In the long‐run, the European Union moves
towards an electricity system dominated by onshore and offshore wind, with bothaccounting for more than 40% of total generation in 2050 in the STEPS and over 50% in the
APS and NZE Scenario.
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In the United States, the electricity sector is continuing its transition away from coal. The
Inflation Reduction Act supports the accelerated deployment of wind and solar PV, among
other technologies, which leads to a long‐term reduction in natural gas use as well. In the
STEPS, unabated coal almost disappears from the electricity generating mix by 2050, with its
share dropping to below 1% from nearly 23% today. At the same time, strong growth inrenewables leads to gas‐fired generation peaking before 2030 and then falling rapidly: it isnearly two‐thirds lower than today by 2050. Recent policy changes also provide support forlifetime extensions for the ageing fleet of nuclear power plants. In the APS, the United States
pursues its ambition of net zero emissions electricity around 2035 through accelerated
deployment of renewables, CCUS, hydrogen and ammonia together with an expansion of
nuclear power, including small modular reactors.

S P O T L I G H T
Are high electricity prices here to stay in the European Union?
Retail electricity prices in the European Union were about 30% higher on average forresidential consumers in the first‐half of 2022 than they were a year before. This increasereflects high wholesale electricity market prices in the European Union, which soared to
EUR 200 per megawatt‐hour (MWh) on average during the first‐half of 2022 ‐ more than
three‐times the average in the first‐half of 2021. This is one of the most extreme near‐term impacts of the current energy crisis, and it is not confined to the European Union,although it is starkest there: costs to generate electricity are set to rise by an estimatedone‐third worldwide in 2022 (see Chapter 1).
Figure 6.11 ⊳ Hourly wholesale electricity price duration curve and price

EUR per MWhsetting technology in the European Union, first-half of 2022
600
500
400
300
200
100

1
Nuclear

1 000
Coal

Lignite2 000
Gas CCGT

Gas GT

3 000
4 344
Ranked hours (highest price = 1)Oil

CO₂ cost

First‐half 2021 prices
IEA. CC BY 4.0.

Average EU wholesale electricity prices in the first-half of 2022 were over three-times
higher than in the first-half of 2021, with hourly prices set by gas, oil and coal plants

We have carried out an analysis of wholesale electricity prices in the European Union in
the first half of 2022. We combined electricity market price data, CO2 prices, fossil fuelprices, power plant capacities and efficiencies in the Global Energy and Climate Model todetermine the price setting technology in each hour. Our analysis indicates that higher
fossil fuel prices account for over 70% of the overall wholesale electricity price increase.
Higher natural gas prices alone make up about half of the increase, with natural gas‐fired
power plants setting the price in close to half of hours from January through June
(Figure 6.11). Coal and oil prices, which have also been high, set the wholesale electricity
price in about 25% and 10% of the hours respectively.
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Note: MWh = megawatt‐hour; CCGT = combined‐cycle gas turbine; GT = gas turbine.

Besides higher fossil fuel prices, we found two other important factors that drove up theprice of wholesale electricity in the European Union. First, we estimate that CO2 prices –at an average of EUR 85/tonne during the first‐half of 2022 compared with EUR 45/tonne
the previous year – led to about 20% of the increase. Second, we find that the reduced
availability of nuclear power, hydropower and other factors accounted for nearly 10% of
the increase. In the first‐half of 2022, nuclear power produced 17% (62 TWh) lesselectricity in the European Union than the same period in 2021. In France, in May 2022,
29 out of 56 reactors were offline for regular maintenance, repairs or safety checks. In
Germany, 3 reactors operated in 2022, following the closure of 3 reactors at the end of
2021. Hydropower output was meanwhile 24% (47 TWh) lower in the first‐half of 2022
compared with the first‐half of 2021. Increased grid congestion also contributed to higher
prices.
Figure 6.12 ⊳ EU hourly wholesale electricity prices by shares of renewables

EUR per MWh

and natural gas in electricity generation, first-half of 2022

6

500
400
300
200
100

0%

20%
40%
Share of renewables

60%

0%

20%
40%
Share of natural gas

60%
IEA. CC BY 4.0.

High shares of renewables in electricity supply drove down wholesaleWind and solar PV reduced the impact of higher wholesale electricity prices on
consumers. They provided 23% of total EU electricity generation in the first‐half of 2022,
mostly under long‐term fixed‐price contracts, such as feed‐in tariffs or power purchaseagreements (PPAs). Higher shares of wind and solar PV in generation have put downward
pressure on wholesale prices. When the share of renewables was above 40% – in nearly
half of the hours from January through June 2022 – the average wholesale electricity was
about EUR 170/MWh, 15% below the average of the first‐half of 2022 (Figure 6.12). We
estimate that the cost of electricity supply would have been EUR 40 billion lower if thecontribution of renewables had been at least 40% throughout the first‐half of the year.
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electricity prices in 2022, while high shares of natural gas pushed them upSeveral supply‐side factors offer potential future relief from such high wholesale
electricity prices. Some will make a difference very quickly. The availability of EU nuclear
power is anticipated to improve significantly, notably as a result of France’s intention torestart all its reactors during the coming winter. Wind and solar PV are set to expand
significantly over the course of 2023, adding 45 GW of new capacity – a nearly 10%
increase. Other factors will make a difference over the next few years. In particular, fossil
fuel prices, and especially natural gas prices, are projected to move lower in the medium
term as market tightness moderates. Wind and solar PV are meanwhile expected tocontinue to grow steadily year after year.
In addition, European Union member states formally adopted emergency measures in
October 2022 to mitigate the impact of high electricity prices on consumers while not
impairing future investment in low‐emissions technologies. Alongside efforts to reducedemand, the European Commission has put forward a proposal for two temporary
measures. The first is to introduce revenue caps for low marginal cost power generation,such as nuclear power, lignite and renewables. The second is to seek contributions fromsurplus profits that have arisen during periods of high prices in upstream oil, gas and coal
activities and refining. Together, these measures could generate over EUR 140 billion that
could provide financial support measures to households, especially vulnerable ones, andhard‐hit companies to mitigate the impacts of high energy prices and help the reductionof energy consumption (European Commission, 2022).
Consumers can take a number of actions to mitigate wholesale electricity prices and theirimpacts. To the extent that customers are able to reduce their electricity demand, it will
reduce their energy bills. It will also help indirectly to reduce prices for everyone: lower
overall demand means less need to call on the most expensive power plants. The
European Commission has proposed a voluntary target of reducing overall electricity
demand by 10% or more, and a mandatory reduction of demand during peak price hours
by at least 5%. We estimate that this scale of reductions would have saved at least
EUR 30 billion in the first‐half of 2022.

Japan approved its Sixth Strategic Energy Plan in October 2021, outlining its electricity mix
plans for 2030 and its ambition to achieve carbon neutrality by 2050. A key element is torestart its nuclear reactors and lift the share of nuclear in the electricity mix back to 20% by2030. Raising the share of renewables in the mix is also important, from 23% in 2021 up to

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Other actions by consumers can also make a difference. Energy efficiency measures, suchas improving home insulation or purchasing more efficient appliances, offer permanent
reductions in demand. Behavioural changes, e.g. moderating the use of space heating,can offer permanent or temporary reductions. Major industrial consumers may also beable to mitigate the impacts of high wholesale electricity prices through the use of long‐term PPAs with producers and through hedging strategies.

36‐38% in 2030. Another element is retrofitting coal plants to co‐fire with ammonia; Japan isthe only country deploying this technology at significant scale in the STEPS.
Other emerging market and developing economies also face the challenge of meeting rapidly
rising electricity demand while limiting the use of fossil fuels, particularly when they areimported. In Southeast Asia, unabated coal‐fired generation continues to expand in the
STEPS, although its share in the electricity mix slowly declines. With the implementation ofannounced pledges in full, unabated coal generation falls 60% by 2050 in the APS, and its
share of generation drops from more than 40% today to 6% in 2050. Africa experiences
extremely rapid growth in electricity production over the period, with generation almost
tripling by 2050 in the STEPS and quadrupling in the APS. Renewables account for most of
the incremental generation. In the APS, solar PV makes the biggest contribution, though windand hydropower also see significant growth. In‐depth analyses and projections for Africa areprovided in the recent Africa Energy Outlook 2022 (IEA, 2022e). The power systems of many
countries in Central and South America are dominated by hydropower. In both the STEPS
and the APS, rising shares of wind and solar PV account for most of the new capacity added
over the outlook period.

6.4

6

CO₂ emissions from electricity generation

The electricity sector emitted 13 Gt CO₂ emissions in 2021, or over one‐third of the global
energy‐related total, but its emissions are set to decline over the coming decades in all three
scenarios. In the STEPS, global annual CO₂ emissions from electricity generation fall morethan 10% by 2030 and around 40% by 2050. In the APS, emissions drop around 80% by 2050.
Emissions fall faster in the APS because of more rapid reductions in the use of coal andnatural gas. Emissions from coal‐fired power plants decrease by almost 85% from 2021 to2050 in the APS compared with over 45% in the STEPS (Table 6.4). CO₂ emissions from theuse of natural gas in the electricity sector over the same period fall by more than 50% in the
APS, whereas they remain broadly stable in the STEPS. In the NZE Scenario, annual CO₂
emissions fall rapidly and reach zero by 2040.
CO₂ emissions from electricity generation by source and scenario,
2010-2050 (Mt)
STEPS

APS

NZE

2010

2021

2030

2050

2030

2050

2030

2050

Coal

8 342

9 670

8 324

5 242

7 423

1 442

4 179

27

Natural gas

2 186

2 798

2 678

2 407

2 380

1 278

1 969

36

751

523

333

242

286

140

135

2

5

4

4

8

‐31

‐362

‐65

‐434

11 285

12 996

11 3387 899

10 057

2 498

6 218

‐369

‐

1

7

96

81

1 484

304

1 479

Oil
Bioenergy and waste
Total (net)Total CO2 captured

Notes: Mt = million tonnes. CO2 emissions include CO2 removals such as captured and stored emissions fromthe combustion of bioenergy and renewable wastes.

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Table 6.4 ⊳In advanced economies, efforts to phase out coal in electricity generation reflect nationaland sub‐national policies, as well as collective initiatives such as the Powering Past Coal
Alliance and the Global Coal to Clean Power Transition Statement. Annual CO₂ emissions
from coal‐fired power plants in advanced economies decrease from 2021 levels by more than
60% in 2030 in the STEPS, and by 80% in the APS. As a result of this shift away from coal,natural gas becomes the main source of CO₂ emissions from 2030 in both the STEPS and the
APS. After 2030, net electricity sector emissions continue to fall with the fulfilment ofannounced pledges bringing the total in the APS down to 40 Mt CO₂ in 2050.
For most emerging market and developing economies, there is a big and growing gap in
future years between emissions reductions based on stated policies in the STEPS and thosewhich fulfil all announced pledges on time in the APS. The APS leads to nearly 60 Gt CO₂
emissions avoided cumulatively from 2021 to 2050 compared to the STEPS, although this is
still far short of what is needed in the NZE Scenario (Figure 6.13).
Figure 6.13 ⊳ Annual CO₂ emissions from electricity generation for regionalgroupings by scenario, 2010-2050

Gt CO₂

Advanced economies

Emerging market and developing economies

10
8
6
4
2
0
‐2
2010

2030
STEPS

2050 2010
APS

2030

2050
NZE
IEA. CC BY 4.0.

Electricity sector CO₂ emissions fall in all scenarios, but the different pathways in the STEPS

Additional pledges and announcements over the last year have helped close the electricity
sector emissions gap between the APS and NZE Scenario. In advanced economies, theWEO‐2021 estimated that the APS would cover 70% of the gap between the STEPS and the
NZE Scenario in terms of cumulative emissions to 2050. Our updated assessment indicatesthat now the gap between the STEPS and NZE Scenario has narrowed due to stronger actionin the STEPS, and deeper reductions in the APS still close about 70% of the remaining gap to
the NZE Scenario. In emerging market and developing economies, the pledges in the APS
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and APS illustrate the importance of countries fulfilling their pledges on time and in fullnow close almost 40% of the gap between the STEPS and NZE Scenario, up from 15% in theWEO‐2021.
The global average CO₂ intensity of electricity generation declines in all scenarios from its
level of 459 grammes of carbon dioxide per kilowatt‐hour (g CO2 /kWh) in 2021, falling by
2030 to 330 g CO2/kWh in the STEPS, 280 g CO2/kWh in the APS and 165 g CO2/kWh in the
NZE Scenario. By 2050, the average intensity of electricity generation ranges from
160 g CO2/kWh in STEPS to slightly below zero in the NZE Scenario. However, countries startfrom different places in 2021 and their pathways vary. In general, the rapid growth of powersystems in emerging market and developing economies and higher use of unabated coalresult in an average CO2 intensity of electricity generation that is 70% higher than the averagein advanced economies (Figure 6.14). In advanced economies, while stated policies lead tosignificant reductions in annual emissions, announced pledges lead to faster reductions, with
the United States and the European Union reaching net zero emissions electricity by 2040,
and Japan and Korea by 2050. A number of emerging market and developing economies havealso pledged to reach net zero emissions, and this leads in the APS to deep reductions in theCO2 intensity of electricity by 2050 in Africa, China, India, Middle East and Southeast Asia.

6

Figure 6.14 ⊳ Average CO₂ intensity of electricity generation for selected
regions by scenario, 2020-2050

g CO2/kWhAdvanced economies

Emerging market and developing

800

United States
European Union
Korea
Japan

600

AfricaMiddle East
China
India
Southeast Asia

400

200

STEPS
APS
2020

2030

2040

2050 2020

2030

2040

2050
IEA. CC BY 4.0.

CO₂ intensity of electricity generation varies widely today, but all regions see a decline in
future years and many have declared net zero emissions ambitions by around 2050

Investment

Global power sector investment rose 7% in 2021 as economies rebound in the wake of theCovid‐19 pandemic. Such investment is expected to rise an additional 6% in 2022 to nearly
USD 1 trillion. Investment continues to rise in all three scenarios. In the STEPS, an average ofChapter 6 | Outlook for electricity

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6.5

around USD 1 trillion per year is invested over the next decade, which represents an increaseof more than 10% over the 2017‐21 period (Figure 6.15). By 2050, annual investment in the
power sector nears USD 1.1 trillion. Investment is concentrated in regions where energy
transitions are at a more advanced stage, and more than 70% of power sector investments
are in advanced economies and China. As energy transitions in emerging market anddeveloping economies gather pace, the balance starts to change. Emerging market anddeveloping economies represent around 50% of global power sector investment by 2030. In
the APS, investment increases by around 30% from current levels to reach an annual averageof USD 1.2 trillion over the next decade and USD 1.8 trillion by 2050. In the NZE Scenario,
investments rise to USD 1.7 trillion per year over the next decade.
Figure 6.15 ⊳ Average annual investment in the power sector by type andscenario, 2017-2050

Billion USD (2021, MER)

STEPS

APS

2 000

100%

Battery storage
Other low emissions

1 600

75%

NuclearRenewables

1 200
50%

Fossil fuels unabatedElectricity grids

800
25%

400

2017‐
21

2026‐ 2046‐
30
50

EMDE share(right axis)

2026‐ 2046‐
30
50
IEA. CC BY 4.0.

Power sector investment is set to increase; up from an annual average of USD 860 billion in
the 2017-21 period, with renewables and grids representing the largest shares

Despite a rise in costs in recent months, renewable energy technologies such as wind andsolar PV remain the cheapest option for new power capacity in many countries, even without
taking into account the exceptionally high prices seen in 2022 for coal and gas. Accordingly,
these technologies attract a large share of money being committed. Investment inrenewables amounts to an average of USD 480 billion per year from 2022 to 2030 in the
STEPS and around USD 630 billion per year in the APS. Annual global investment in nuclear
power also increases from USD 30 billion during the 2010s to over USD 60 billion by 2030 in
the STEPS and USD 80 billion in the APS. In faster transitions, other low‐emissions fuels andtechnologies such as CCUS take a progressively larger share of investment in the power
sector, reaching an annual average of USD 7 billion by 2050 in the APS. Investment in
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Note: MER = market exchange rates; EMDE = emerging market and developing economies.

unabated fossil fuel power plants drops to around USD 50 billion 2030 in the STEPS andaround USD 40 billion in the APS.
Transmission and distribution grids capture a rising share of total power sector investment
in recognition of their critical role in supporting modern electricity systems and clean energy
transitions. This investment supports the expansion, modernisation and further digitalisationof transmission and distribution networks. Battery storage gains ground as a source of powersystem flexibility, with annual investment increasing more than threefold to USD 33 billion
by 2030.

Key themes
6.6

Power system flexibility is key to electricity security

Flexibility needs
Power system flexibility2 needs are driven primarily by the rising share of variable wind andsolar PV in electricity generation and changes in electricity demand profiles. Rising shares ofnon‐dispatchable wind and solar PV increase the variability of the net load (the load thatremains after removing wind and solar production from electricity demand), while theelectrification of additional end‐uses, e.g. electric heating, road transport or industrial
processes, raises peaks and increases the hourly, daily and seasonal variability of electricity
demand. 3 Although seasonal variations play an increasingly important role in systems
characterised by rising shares of variable renewables, the change in net load from one hourto the next remains a useful indicator for flexibility needs and is used in this analysis.

6

All three scenarios see a significant rise in the share of variable renewables in power systems
worldwide. In the STEPS, the combined share of wind and solar PV in the electricity mix
doubles by 2030 and exceeds 40% by 2050. In the APS, where all announced emissions
reduction pledges and renewable energy targets are met in full, it rises to nearly 30% by 2030
and close to 60% by 2050. This significantly raises the demand for additional system flexibility
to balance electricity supply and demand continuously and to maintain grid stability. In the
STEPS, hour‐to‐hour flexibility needs more than triple by 2050. In the APS, the needs double
by 2030 and increase more than 3.5‐times by 2050, while they more than quadruple between
today and 2050 in the NZE Scenario.
The relative change is biggest in systems which start from a low base but see the rapid
introduction of variable renewables. In India, for example, flexibility requirements rise
threefold in the APS by 2030 and sixfold by 2050, while in China they double by 2030 and rise
3.5‐fold by 2050 (Figure 6.16). The United States and the European Union also see dramatic
2

3
The electrification of additional end‐uses also raises the potential to provide flexibility through demand‐side
response measures.

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Flexibility is defined as the ability of a power system to reliably and cost effectively manage the near
instantaneous, hourly, daily, weekly and seasonal variability of demand and supply. It ranges from ensuring
the instantaneous stability of the power system to supporting long‐term security of supply.

increases in the need for flexibility to 2030 as the share of variable renewables in the powermix rises to almost 45% in the former and 50% in the latter.
Figure 6.16 ⊳ Hour-to-hour flexibility needs in the United States,
European Union, China and India in the APS, 2021 and 2030
50%

United States

European Union

China

India
2021
2030

25%

0%

‐25%

‐50%
IEA. CC BY 4.0.

Hour-to-hour flexibility needs rise significantly by 2030 in major markets,driven by increasing shares of variable renewables and changes in demand patterns
Note: Flexibility needs are represented by the hour‐to‐hour ramping requirements after removing hourly windand solar PV production from hourly electricity demand, divided by the average hourly demand for the year.

Flexibility supply
The provision of flexibility in power systems is a cornerstone of electricity security today andin the future. There are four main sources of flexibility: power plants, grids, demand‐side
response and energy storage.4

4
While solar PV and wind are able to provide some flexibility through curtailment, doing so raises theirlevelised cost and could negatively impact their profitability depending on compensation.

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Thermal power plants provide most of the flexibility required to maintain the reliability of
power systems today, with the remainder supplied mainly by hydropower (including pumped
storage). By 2050, the rise of renewables means that the share of thermal power plants inthe overall supply of flexibility declines from around two‐thirds today to around a third in the
STEPS and a quarter in the APS (Figure 6.17). The technology mix of the remaining fleet ofthermal power plants changes considerably over the outlook period, especially in advanced
economies. There is a move away from less flexible, base load thermal generation such as
coal‐fired power plants to more flexible technologies such as gas turbines, which are able tostart and ramp up or down much faster, making them a more suitable match with high sharesof variable renewables. In countries with nuclear generation, it remains an important, low‐emissions source of flexibility and provides stability to power grids. In the APS, plants that

co‐fire hydrogen or ammonia and fossil fuel power plants with CCUS also enter the flexibility
supply mix, mostly in advanced economies. While unabated coal continues to play asignificant role as a provider of system flexibility in emerging market and developing
economies in the STEPS, it is almost completely phased out in advanced economies.
Figure 6.17 ⊳ Flexibility supply by source, region and scenario, 2021 and 2050
Advanced economies
Unabated coal
Unabated natural gas
Oil
Fossil fuels with CCUS
Hydrogen and ammonia
Nuclear
Hydro
Other renewables
Batteries
Demand response

2050

2021
STEPS
APS
Emerging market and developing economies

2050

2021
STEPS

6

APS
0%

25%

50%

75%

100%
IEA. CC BY 4.0.

The provision of power system flexibility becomes less reliant on unabated fossil fuels overtime, moving towards low-emissions sources, battery storage and demand response

Demand‐side response helps to align consumption with available supply, thus reducing theneed for other sources of flexibility. With the projected increase in the use of electricity by
air conditioners, heat pumps, EVs, electrolysers and other potentially flexible sources ofdemand, there is potential for significant load shifting in all three scenarios. In 2050, demand‐side response provides roughly a quarter of power system flexibility in both advanced
economies and emerging market and developing economies in the STEPS and APS. Tapping
this potential, however, will require significant investment in digital infrastructure, as well as
in technologies such as thermal storage that help decouple electricity consumption from final
demand. Regulatory frameworks will also need to evolve in order to enable suppliers to offer
tariffs that reward demand response to end‐users, and to permit aggregators, industrial

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Power grids and interconnections can help even out fluctuations in demand and in the supplyof weather‐dependent variable renewables such as wind. They do so by connecting
generators dispersed over a wide area within and between countries and regions. They thus
help reduce the demand for flexibility from other sources while at the same time connecting
further potential providers of flexibility. Certain grid assets, such as high voltage direct
current (HVDC) interconnections, can also provide flexibility services, including fast active
and reactive power and voltage control (see section 6.7).

consumers and other potential providers of demand‐side response to offer flexibility inelectricity, capacity and ancillary service markets.
Energy storage, in particular battery energy storage, is set to play an increasingly importantrole in system flexibility. Battery storage is projected to be the fastest growing source ofpower system flexibility in all scenarios over the outlook period. Battery systems are
modular, which allows them to be deployed and scaled up rapidly in almost any location. In
addition to energy storage, utility‐scale batteries can offer important system services, forexample by helping with the restoration of grid operations following a blackout, supporting
short‐term balancing or providing operating reserves. Their provision of localised flexibility
may also reduce the need for investment in new transmission and distribution infrastructure.
Although dwarfed by the projected increase in battery storage capacity, other storage
technologies play contributing roles in system flexibility as well. With around 160 GW of
installed capacity globally, pumped storage hydro is the largest source of electricity storage
today, and it is set to expand further over the next ten years (IEA, 2021c). Other grid‐levelstorage options include compressed and liquid air energy storage, gravity storage, andhydrogen and ammonia. Hydrogen and ammonia in particular hold significant promise assources of seasonal storage for large amounts of renewable energy (IEA, 2021d).
As the power generation mix evolves, ensuring an adequate supply of flexibility will be
critical. However, current market designs are sending weak signals for investment inflexibility, and this could present a risk to electricity security in clean power systems
characterised by high shares of variable renewables. Policies and regulatory frameworks
need to evolve in order to bring about the levels of investment in new sources of flexibility
seen in the APS and NZE Scenario. Legacy regulations that could potentially diminish theeconomic case for various types of flexibility should be reviewed and reformed if necessary.
In countries with liberalised electricity markets, several options could help better incentivise
investment in sources of flexibility. These include decreasing the market settlement period,
i.e. the interval in which electricity is traded; reforming market gate‐closure, i.e. the time
between the last trade and the physical delivery of the electricity, to bring it closer to realtime; introducing capacity remuneration mechanisms; and further opening of ancillary
service markets. A recent IEA report provides more information on design choices to tailor
power markets for tomorrow’s electricity systems (IEA, 2022f).

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In addition to adapting market designs, there is a strong case for considering flexibility inlong‐range energy planning and considering options to incentivise the deployment of flexible
capacity through instruments that improve long‐term revenue visibility. For example, so‐called hybrid auctions for renewables and storage could provide the necessary revenue
stability for investment in storage.

Focus on battery storage
Installed battery storage capacity, including both utility‐scale and behind‐the‐meter systems,
totalled more than 27 GW at the end of 2021. For the second year in a row, capacity additions
increased strongly in 2021, rising to more than 9 GW (nearly 90% higher compared to 2020).
The pace of deployment is set to pick up significantly: global battery storage capacity
increases nearly 50‐fold in the STEPS, rising to more than 1 000 GW by 2050. In the APS, thisdoubles to more than 2 000 GW, with more than 400 GW installed by 2030. The strongest
growth occurs in the NZE Scenario, which sees about 780 GW installed in 2030 and morethan 3 500 GW by 2050.
The increase in battery storage capacity is underpinned by a steady decline in their costs
which is brought about by continuing innovation in battery chemistry and economies ofscale. There is some risk in the short and medium term that difficulties related to availability
and affordability of specific critical minerals needed to produce batteries could slow the
decline in cost, but there are options to mitigate these concerns (see section 6.8).

6Figure 6.18 ⊳ Share of batteries in total dispatchable capacity andShare of batteries in total
dispatchable capacity

share of variable renewables in electricity generation for
selected regions by scenario, 2021-2050
50%

STEPS
2050

India

40%

2030
UnitedStates30%
20%European Union

10%

2021
APS
2050
2030

China

0%

10%

20%

30%

40%

2021

50%
60%
70%
80%
Share of wind and solar PV
IEA. CC BY 4.0.

Battery storage capacity rises in tandem with the share of wind and solar PV,

Battery storage capacity expansion is closely correlated with the rising share of variable
renewables in power systems. This highlights its role as an important source of additional
flexibility as renewables are scaled up and traditional providers of flexibility such as coal‐fired
power plants are retired. Since batteries are primarily for short duration storage, they are
well suited to smooth the daily cycle of solar PV‐based electricity generation (battery storage

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helping to provide flexibility and security for power systems

volumes commonly range from one to eight hours of storage at full capacity, with most
systems currently at the lower end of the range). Behind‐the‐meter battery systems are often
paired with rooftop solar, for example. Regions with high shares of solar PV relative to wind,such as the United States or India, thus tend to see higher relative levels of battery
deployment than regions in which wind power predominates, such as China or the European
Union (Figure 6.18).
In the STEPS, the United States maintains its position as the leading market for battery
storage, with installed capacity rising from more than 7 GW in 2021 to nearly 370 GW by
2050. In the APS, China becomes the largest market for battery storage with installedcapacity rising from close to 6 GW today to 570 GW in 2050. China’s share of batteries intotal dispatchable capacity remains low in relative terms compared to other regions, but its
market is huge in absolute terms.
The installed capacity of battery storage rises faster relative to renewables capacity in the
APS than in the STEPS. This reflects the greater urgency shown in the APS outlook to provide
additional flexibility to the grid and lower battery storage costs that come with that: as higher
numbers of batteries are deployed, learning effects and improved economies of scale drive
down the cost of battery packs and the other components constituting the balance ofsystem. Spillover effects from the EV industry, which is by far the largest user of batteries,
also play an important role.
To get on track for the levels of battery storage capacity in the APS or NZE Scenario, policies
and regulatory frameworks will have to evolve to reflect the importance of the contribution
made by battery storage to different system services. For storage assets, ownership is often
an important question: typically, storage is considered a generation asset and grid operators
are not allowed to own it. This could impede progress. A potential solution might be to allow
transmission or distribution system operators to procure storage services from third parties,
for example through tenders or local flexibility markets.

Electricity networks are the backbone of clean power systems

Electricity transmission and distribution systems currently include around 80 million
kilometres (km) of lines. The way in which these are developed and operated will determine
the economic viability and reliability of the entire electricity system as demand grows and as
energy transitions accelerate in the coming years. Most electricity systems were originallydesigned and operated by vertically integrated utilities with a focus on maintaining reliablelocal supply. The liberalisation of many electricity markets changed this arrangement by
splitting the integrated utilities into separate grid and generation services. The rising shareof variable renewables in the generation mix and alterations in the way that electricity
systems operate, e.g. in terms of demand management, however are now changing
requirements for the interface between the distribution and transmission grids, raisingquestions about how best to meet the challenges ahead.

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6.7

Grid infrastructure development
The electricity network – the essential link between generation and demand – continues toexpand in all three scenarios. In the STEPS, 13 million km of distribution lines and about
1.6 million km of transmission lines are constructed by 2030 (Figure 6.19). By 2050, morethan 45 million km of distribution lines and a further 4 million km of transmission lines areadded along with primary equipment, power transformers and associated control andprotection equipment, increasing the existing grid by more than 80%. In the APS, theexpansion of the network proceeds even more rapidly, with 14 million km of distributionlines and 1.8 million km of transmission lines added by 2030.
Figure 6.19 ⊳ Grid development by type, region and scenario, 2022-2050
Transmission

Distribution

Japan
European Union
United States
Other adv. economies
Southeast Asia
India
AfricaChina
Other EMDE

6

1
Existing
New

2

Remains in 2050
STEPS 2022‐30

34Million km
Replaced in 2022‐50
STEPS 2031‐50

10

20

30
Million km

Additional in APS to 2050
IEA. CC BY 4.0.

Electricity networks need to be expanded and replaced in all regions, providing
opportunities for modernisation to accommodate tomorrow's power systems
Note: Adv. = advanced; EMDE = emerging market and developing economies.

The need for new capacity in the transmission grid has two main causes. First is rapid growthin electricity demand, which increases by one‐quarter before 2030 in the APS and more thandoubles by 2050. Second is the rapid rise in new sources of generation and demand. The
strong growth of renewables, often more distant from existing grids to tap high quality
resources, add to the growth of transmission around the world.

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In emerging market and developing economies, over 14 million km of new lines are built in
the STEPS by 2030. Rising demand accounts for over 90% of this enlargement. Almost a thirdof the total expansion takes place in China (5.3 million km). Some of these new lines take theform of large‐scale ultra‐high voltage electricity transmission links over distances of up to
3 300 km to connect remote solar PV and wind power installations. Many emerging market

and developing economies make significant progress in expanding access to electricity,
notably in Africa (IEA, 2022e) and Southeast Asia (IEA, 2022g). Indonesia has already raised
access rates from two‐thirds of the population a decade ago to nearly 100% today.
In advanced economies, where electricity networks are well developed and generally older,
there is more focus on replacement and less on new lines. Almost 21 million km of grid lines
have to be renewed in advanced economies until 2050, including over 7 million km in theEuropean Union and more than 8 million km in the United States. This corresponds to two‐
thirds of those networks in place today.
Lines, cables and transformer capacity will remain the mainstays of electricity networks, butinvestment in digital technologies is also critically important. Most operational decisions
today are based on load flow analysis in local monitoring systems. This approach to system
operations works well when the power flows from centralised generation capacity toconsumers are largely predictable within a local or national framework. Integration of energy
flows over longer distances and the rise of variable generation sources is changing the levelof predictability of electricity flows through the system. Depending on the equipment, thesepower flows can lead to system conditions that are more dynamic, leading to local line
overloads. Digital technologies have a key part to play in meeting the challenges that arise
from these changes.
New monitoring and control devices and the corresponding software can provide system
information in real time. Dynamic line assessment sensors placed throughout the network
can help transform the stationary assessment of larger power supply regions into real‐timemeasurements and uncover the dynamics of power flows in a broader and meshed system,
while smart meters can improve the visibility of load flows. Real‐time knowledge of system
health allows fuller utilisation of existing resources, enables networks to operate closer totheir true limits without sacrificing reliability, and makes it easier to contain system failures
into smaller areas and prevent cascading power outages. Higher levels of co‐operation andknowledge sharing between transmission and distribution grid operators will help toenhance energy security, as will the sharing of best practices relating to the co‐ordinatedoperation and planning of transmission and distribution systems and data exchange between
operators.

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The ability to act on the basis of a detailed view of a broad network area depends on digitaltechnologies such as Static Synchronous Compensator and Thyristor Controlled Series
Compensation, both of which are part of the family of flexible alternating current
transmission devices. These allow control of power flows, voltage levels and other stability
characteristics nearly in real time, while generating corresponding reactive power thatfurther increases power transmission capacity and stabilises the grid. HVDC is anotherimportant technology in this context that can help system operations by transporting large
amounts of electricity while offering full bi‐directional load flow control and black startcapabilities.

Grids support secure energy transitions
Successful clean energy transitions depend on modern electricity networks, and theirdevelopment requires long‐term vision and planning. For example, large projects involving
transmission systems can often take a decade or longer to complete. Such long lead times
put a premium on strategic thinking and accurate estimates of future supply and demand sothat tomorrow's networks are ready to meet the requirements placed on them and do not
act as a bottleneck in clean energy transitions.
To ensure security of supply, grid development must be considered at the system level,taking account of increasing electricity demand and rising levels of variable renewables.
Energy from utility‐scale wind or solar PV installations, which are often located far fromdensely populated cities and other demand centres, will need to be transferred over long
distances through a network that may have been designed for a different type of operation.
Networks are complex systems with many variables; keeping them up‐to‐date is a never‐ending challenge. For example, when the network plan in Germany was updated in 2019,just two years after its previous revision, the need for more than 100 new reinforcement
measures was identified. Failure to plan ahead sufficiently can lead to transmission
bottlenecks. This was experienced recently in Viet Nam, which announced in early 2022 that
it would not connect any new solar PV or wind projects for the rest of the year, and also in
Mongolia, where 12% of the electricity generated by wind turbines in 2021 could not betransported to end‐users.

6

Electricity network projects, especially high voltage interconnections, are very complex interms of both permitting and construction. Line route plans and reports have to be drawn
up covering the entire length, conditions and specifications have to be assessed, andstakeholders must be engaged. People living near proposed line routes may oppose theirdevelopment.

There are a number of ways to address the challenge of electricity network development.
The likelihood of success is increased where there is effective long‐term grid planning
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Typical permitting and construction times for power lines vary widely. The visual impact ofhigh voltage power lines often produces a concerted level of local resistance. It is not unusual
for the permitting and construction of a single extra‐high voltage overhead power line(>220 kilovolt [kV]) to take 5‐13 years, depending on the length of the line and other factors,
especially in advanced economies (Figure 6.20). Lower voltage level projects often take4‐7 years. Distribution grid projects are usually completed within four years. As an example
for an advanced economy, in Germany, out of the 1 655 km of line projects approved in a2009 network development plan, less than 50% were operational a decade later. The use ofunderground cables instead of overhead power lines can help deal with concerns aboutvisual and environmental impacts, especially in advanced economies, but cables add
significantly to costs. They generally have been used primarily for low voltage power lines,
but are now increasingly being deployed for high voltage lines of up to 525 kV.

incorporating forward planning in supply and demand, where there is clarity about the roles
and responsibilities of regulatory authorities, network operators and investors, and where
the number of permits required is reduced to the minimum necessary through integrated
procedures which set the clear requirements for substations in all regions of the country.
Effective and binding deadlines are important in order to give network operators andinvestors legal certainty with regard to the timely completion of approval procedures. Thisimplies adequate staffing levels and professional competence on the part of the regulatory
authorities. High priority projects can be accelerated by the designation of so‐called"infrastructure corridors" with provision for quick initial permitting decisions. The
importance of network‐wide co‐ordination has already been recognised in countries such as
Australia, Japan and United States, while the European Union has agreed on a new Trans‐
European Networks for Energy Regulation that offers the prospect of accelerated permitting
procedures and funding support for over 150 power transmission and storage projects ofcommon interest.
Figure 6.20 ⊳ Typical deployment time for electricity grids, solar PV, wind
and EV charging stations
China
India
European Union
United States

Utility solar PV
Onshore wind
Offshore wind
Car charging hub
Truck charging hub
Distribution line
High voltage line
Extra‐high voltage line
36

9

12 Years
IEA. CC BY 4.0.

Electricity grid deployment is complex, involves many stakeholders and can take many
years, which makes advanced planning critical to support clean energy transitions
Notes: Ranges reflect typical projects commissioned in the last three years. Distribution line = 1‐36 kV
overhead line; transmission is split between high voltage line = 36‐220 kV overhead line and extra‐high voltage
line = 220‐765 kV overhead line. To date, India has not developed offshore wind projects.

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Source: IEA analysis.

Grid investment
In the STEPS, annual grid investment rises to USD 550 billion by 2030 compared with
USD 300 billion per year from 2012 to 2021, and to about USD 580 billion in the 2030s and2040s (Figure 6.21). This increase reflects rising levels of electricity demand, the need forsystems to adjust to expanding levels of variable renewables generation capacity, and thedevelopment of smart grids. Grid investments in advanced economies rise till 2040 to about
USD 250 billion per year where they remain stable and are largely focussed on ensuring gridreliability during the transition to a decarbonised power sector that needs to be increasingly
flexible while meeting rising levels of demand and maintaining affordability and resilience. In
emerging market and developing economies, investments rise from about USD 135 billion toover 330 billion by 2030, and stabilise at about this level through 2050, as demand for energy
grows rapidly and more of that demand is served by electricity as well as extending access tomillions of people for first time. Most grid investment in emerging market and developing
economies today is made by the public sector, and the rising levels of investment requiredin the future underline the case for finding ways of attracting some proportion of thisinvestment from the private sector.5

6

Figure 6.21 ⊳ Average annual electricity grid investment by type andBillion USD (2021, MER)

scenario, 2012-2050
STEPS

1 000

APS
Advanced
economies

800

Transmission
Distribution

600

EMDE
400

Transmission
Distribution

200

2012‐
21

2022‐ 2031‐ 2041‐
30
40
50

2022‐ 2031‐ 2041‐
30
40
50
IEA. CC BY 4.0.

Annual grid investment ramps up from the recent average of USD 300 billion per year
to an average of USD 580 billion in the 2030s in the STEPS and USD 770 billion in the APS

5
For further information concerning attracting private investment in emerging market and developing
economies, see Africa Energy Outlook 2022 (IEA, 2022e).

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Note: MER = market exchange rates; EMDE = emerging market and developing economies.

In the APS, grid investment rises to USD 630 billion by 2030 and USD 830 billion by 2050, with
distribution grids accounting for the largest share. This represents a marked step up from thelevels seen in the STEPS. Investment in advanced economies falls after 2040 as fulldecarbonisation is nearly achieved and electricity demand growth slows and efficiency
measures take effect. Meanwhile it continues to rise in emerging market and developing
economies, driven by electricity demand more than doubling from 2021 to 2050 in the STEPS
and APS. Large interconnections remain a major investment focus, with projects underconstruction or planned in Africa, Australia, China, Europe, India and North America.
Regulators and policy makers face the task of ensuring that the necessary grid investment
takes place while managing costs and maintaining system stability. Cost allocation
frameworks need to ensure fair remuneration for grid operators and investors while
protecting consumer affordability. The integration of rising shares of renewables increases
the complexity of grid operations and may raise new questions about asset ownership andthe distribution of responsibilities. Whatever the overall framework, however, clear vision,
long‐term energy planning and transparency can help reduce uncertainty for grid operatorsand investors, facilitating timely and efficient investment in grid infrastructure. Where they
exist, regional bodies can also help regulators by promoting better understanding about
regional power systems, sharing lessons learned and supporting the development ofinnovative collaboration models and joint training initiatives.

6.8

Critical minerals underpin future clean electricity systems

A low‐emissions electricity system differs profoundly from one fuelled by traditional fossil
fuel resources. Among others, it depends much more on critical minerals. A solar PV
installation requires around six‐times more critical mineral inputs (7 000 kilogrammes per
megawatt [kg/MW] of installed power capacity) than a natural gas‐fired power plant. An
onshore wind installation requires nine‐times more critical mineral inputs (10 000 kg/MW),and an offshore wind installation requires 13‐times more critical mineral inputs(15 000 kg/MW) (IEA, 2021b). At just over 5 000 kg/MW, nuclear power is the least criticalmineral‐intensive technology among the suite of low‐emissions power generation
technologies (IEA, 2021b). This implies that a transformation of the electricity system will be
inevitably accompanied by expanding demand for these critical minerals. As clean energy
transitions gather pace, there accordingly will be a shift of focus from the supply of traditional
fuels to the supply of critical minerals (see Chapter 4). Rising mineral prices and volatile
supply chains which could be affected by geopolitical events should be seen as warning signs
to policy makers to pay closer attention to the importance of these minerals for a secure andsustainable energy transition (IEA, 2022h).

The rapid deployment of low‐emissions power, electricity grids and grid storage in the APS
and NZE Scenario implies rapidly growing demand for critical mineral from the electricity
sector. Despite technology innovation leading to material intensity improvements over time,
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System transition comes with new challenges

critical mineral demand rises from 7 Mt in 2021 to reach 11 Mt in 2030 and 13 Mt in 2050 in
the STEPS. It grows much faster in the APS and NZE Scenario, reaching over 18 Mt in 2050 in
the APS and 20 Mt in the NZE Scenario (Figure 6.22). Even in the STEPS, the transitions tolow‐emissions power, grids and storage lead to cumulative demand for critical minerals thisdecade being 20% higher than between 2010 and 2020, and cumulative demand after 2030
until mid‐century is nearly four‐times as large as the demand of the last decade.
Figure 6.22 ⊳ Annual demand for critical minerals for low-emissions electricity

Mt

supply, storage and networks by scenario, 2021-2050
20

Wind
Solar PV
Geothermal
Bioenergy
CSP
Nuclear
Hydro
Transformers
Electricity transmission
Electricity distribution
Grid battery storage

16
12
8
4

2021

STEPS APS NZE
2030

6STEPS APS NZE
2050
IEA. CC BY 4.0.

Annual demand for critical minerals in low-emissions electricity generation, battery storageand networks increases almost 200% from 7 Mt today to 20 Mt by 2050 in the NZE Scenario
Note: CSP = concentrating solar power.

In terms of absolute volumes, copper dominates total demand for critical minerals from theelectricity sector: current demand of over 5 Mt per year rises to 10 Mt by 2030 in the APS
and 13 Mt in the NZE Scenario (Figure 6.23). Relative to current levels, demand for lithiumfor battery storage systems rises most sharply, by over 20‐fold by 2030 and almost 50‐fold
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Among the minerals which are crucial for the future of power systems are copper, rare earth
elements, silicon and lithium. Copper is used extensively in the electricity transmission anddistribution grids, but its conductive properties also make it an essential component for low‐emissions power generation technologies such as solar PV panels, wind turbines andbatteries. Rare earth elements (REEs) are used to manufacture the permanent magnets forthe motors of direct drive and hybrid wind turbines (accounting for 30% of wind power
installations in 2021). Silicon is used to manufacture solar panels. As deployment of variable
renewable technologies increases, the need for storage technologies to complement
renewable electricity also rises rapidly. Lithium‐ion batteries are the fastest growing storage
technology in the world, making lithium indispensable for future electricity systems.

by 2050 in the NZE Scenario. Demand for copper, silicon and REEs nearly doubles to 2030 in
the APS, and rises by around three‐times in the NZE Scenario relative to 2021.
Figure 6.23 ⊳ Annual demand for selected critical minerals used in

Copper15

Mt

Mt

low-emissions electricity supply, storage and networks by
scenario, 2021-2050

10

2

5

1

2021

2030

2021

2050
kt

kt

Rare earth elements
40

60

20

40

10

20

2030
STEPS

2021

2050
APS

2030

2050

Lithium

80

30

2021

Silicon

3

2030

2050
NZE
IEA. CC BY 4.0.

More copper for grids, rare earth elements for wind turbine motors, silicon for solar panels
and lithium for battery storage are required to transition to low-emissions power systems
Notes: Mt = million tonnes; kt = kilotonnes. In this figure, battery storage is limited to utility‐scale and homeenergy storage and does not include demand for EV batteries. Copper demand excludes demand for EV
motors. Lithium demand excludes demand for EV batteries.

Copper and aluminium currently account for around 16% and 4% respectively of total gridinvestment costs (IEA, 2021b). To reduce raw material costs, grid operators could switchfrom copper in underground cables to use aluminium, which is less expensive. Increased useof aluminium in underground cables could reduce copper demand nearly 45%. Recent
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Support for R&D is crucial to achieve mineral intensity improvements andmineral alternatives

developments in cable insulation technology also widen the possibility of higher transmission
capacity using the same amount of conducting materials.
Today’s electricity networks are largely operated using an alternating current (AC) system,
which require a minimum of three wires per cable to transmit electricity. HVDC systems use
two wires, which implies a direct saving on metal demand of at least one‐third compared toAC systems. HVDC systems are also capable of transporting more electricity than AC systems,
which could reduce copper and aluminium demand as well as the extent of a need for grid
expansion. Wider adoption of HVDC systems could raise costs, but would reduce bothaluminium and copper demand by around 10% each by 2050 in the NZE Scenario.
Crystalline silicon (c‐Si) modules dominate the solar PV market today, accounting for around
95% of global capacity additions. A slowdown in production of crystalline polysilicon in China
over the last year has created a bottleneck in the solar PV supply chain, leading to aquadrupling of polysilicon prices (IEA, 2022i). Nevertheless, innovation in the manufacturing
and design of c‐Si solar panels over the past decade has contributed to major improvements
in material intensity; since 2008, silicon intensity has more than halved as wafer thickness
has diminished substantially, and silver use has been cut by 80%. During the same period,
module costs have declined by 80%, leading to spectacular growth in solar PV deployment
worldwide. While c‐Si modules are expected to continue to dominate the market, further
R&D work on alternative technologies such as cadmium telluride (CdTe), perovskite or
gallium arsenide (GaAs) solar cells could see these technologies achieve increasing market
shares to 2050.

6

Material intensity depends not only on turbine size, but also on turbine type. The rapid
expansion of wind power generation brings with it more demand for the rare earth elements
required to manufacture the permanent magnets for many of the motors. In the NZE
Scenario, demand for REEs in wind, neodymium and praseodymium in particular, is projected
to triple by 2050, driven by a shift from technologies using induction generators in favour of
those using permanent magnet generators. Given concerns about competing for REE supply
with EV motors, rising prices and geopolitical events, further R&D efforts are needed todevelop non‐magnet technologies or hybrid configurations with smaller magnets orpermanent magnets without REEs to reduce overall REE demand (IEA, 2021b). Successful
R&D could lead to significant reductions in demand for REEs (Figure 6.24).

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Global installed wind power capacity has nearly quadrupled over the past decade, spurredby an average 40% reduction in costs and strong policy support in more than 130 countries.
Average rated capacity for wind turbines has also increased considerably over the last
decade, almost doubling for onshore wind turbines and shooting up even more rapidly foroffshore wind turbines: the most recent offshore wind turbine designs are 10‐14 MW, andplans for up to 20 MW turbines are in the pipeline. These changes have important
implications for the use of materials. On a kilogramme per megawatt basis, a turbine of
3.45 MW contains around 15% less concrete, 50% less fibreglass, 50% less copper and 60%
less aluminium than a 2 MW turbine (Elia, 2020).

Figure 6.24 ⊳ Demand for selected minerals used in electricity networks,
solar PV and wind relative to 2021 in alternative technology
cases in the NZE Scenario, 2050

Index (2021 = 1)

Grids

Solar PV

Wind

6

Grids
Base caseHigher Al in grids
Rise of HVDC grids

5
4

Solar PV
Base case
Comeback of CdTe
Rise of GaAs solar cell
Rise of perovskite
Wind
Base case
Constrained REE supply

3
2
1
Aluminium

CopperSiliconREE
IEA. CC BY 4.0.

Enhanced R&D efforts could help commercialise technologies that provide substitutes forcertain critical minerals or reduce the amount of minerals required per unit of power
Note: Al = aluminium; CdTe = cadmium telluride; GaAs = gallium arsenide; REE = rare earth element; HVDC =high voltage direct current systems.

Recycling and reuse could reduce the burden on primary supply to meet demand
Metal recycling has the potential to be a significant source of secondary supply to meet thegrowing demand for critical minerals, although it comes with its own set of challenges.
Recycling comprises the physical collection and separation of metals and the metallurgicalprocesses to recover them. It includes multiple pathways and a wide range of technologies
and practices.

By mass, 95% of solar panel components are recyclable, but only around 10% of end‐of‐life
solar panels are currently being recycled. With average lifespans of about 25 years, manysolar panels worldwide are now approaching the end of their lives. In the NZE Scenario,
capacity retirements for solar PV increase almost 150‐fold from 3 GW in 2030 to around
400 GW in 2050. By mass, 90% of the components of a wind turbine are recyclable, and likesolar panels their lifespan is about 25 years. In the NZE Scenario, capacity retirements for
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Recycling metals used in the energy transition will not only ease the burden on their primary
supply via mining, but better treatment of waste streams will reduce the risk of several
hazardous materials entering the environment and polluting land and water resources.
Although recycling will not eliminate the need for significant investment in primary supply, aslightly reduced burden on mining through recycling will eventually lead to lower social andenvironmental impacts from mining.

wind turbines increase from 16 GW in 2030 to 240 GW in 2050. Further policy efforts areneeded to boost recycling of metals and to ensure that at the end of their useful life that
solar panels and wind turbines do not end up in landfills.
It has proved possible to achieve high rates of recycling for metals such as aluminium, ironand nickel and, in some cases, copper when simple, bulk products are involved or when the
raw material is relatively easy to collect from industrial applications. This suggests that these
metals have relatively high potential for continuous recycling, including from clean energy
technology waste streams. The same is not true for other energy transition minerals such as
REEs, lithium and cobalt. High levels of recycling focused on the metals needed for clean
energy technologies depend on further investment and R&D, as well as on international
collaboration and co‐operation between various manufacturers.
Targeted policies in support of recycling of solar panels, wind turbines and batteries,
including minimum recycled content requirements, tradeable recycling credits and virginmaterial taxes have the potential to incentivise the recycling of energy transition minerals
and to drive the rise of secondary supplies (Söderholm, 2020). Policy intervention andinvestment in R&D both need to be stepped up considerably in order to ensure a circular
economy is created for low‐emissions electricity generation technologies.

6

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The immensely rapid progress in innovation and corresponding cost declines for EV lithium‐
ion batteries over the last decade have brought spillover benefits for grid‐scale battery
storage systems. There is now scope for the automotive industry to provide a second type of
benefit for grid storage. This stems from the growing pool of EV batteries which could havesecond‐life applications in energy storage. Spent EV batteries tend to have terawatt‐hours ofunused energy that no longer meet the standards for use in an EV but can be used for otherapplications (Söderholm, 2020). The amounts of unused energy involved are significant:these spent batteries typically maintain about 80% of their total usable capacity. Initial trials
for second‐life batteries have already begun, but a number of technological and regulatory
challenges remain for their application to grow at scale. Clear guidance on the repackaging,certification, standardisation and warranty liability of used EV batteries will be needed toovercome these challenges. The proposed update of the European Union Battery Directiveis attempting to tackle some of these issues, for example through requirements for minimum
levels of recycled metals in batteries, new targets for recycling and open information
requirements that enhance battery traceability.

Chapter 7
Outlook for liquid fuels
A combustible mix
S U M M A R Y
 The oil market today is grappling with huge near‐term and long‐term uncertainties.
Fears of recession loom large over the immediate prospects for demand, although
China could boost oil use as it emerges from renewed lockdowns. Sanctions on Russia
and dwindling spare capacity cast a shadow over the adequacy of supply. High prices
are generating a historic windfall for the oil and gas industry, accompanied byhesitation on how this can best be invested given the likelihood of structural shifts in
oil use in the decades to come.

 Our scenarios provide different perspectives on the strength of these shifts and theirimplications. In the Stated Policies Scenario (STEPS), global oil demand rebounds andsurpasses 2019 levels by 2023, despite high prices; demand peaks in the mid‐2030s at
103 million barrels per day (mb/d). In the Announced Pledges Scenario (APS), stronger
policy action brings forward the peak in oil demand to the mid‐2020s. In the Net Zero
Emissions by 2050 (NZE) Scenario, faster global action to cut emissions means oil
demand never returns to its 2019 level and falls to 75 mb/d by 2030.

 Around 10% of cars sold in 2021 were electric. This rises to 25% in the STEPS and to
60% in the NZE Scenario by 2030. Electric and fuel cell heavy trucks struggle to gain
market share in the STEPS, but they comprise 35% of trucks sold in 2030 in the NZE
Scenario. Road transport oil demand increases by 1.5 mb/d between 2021 and 2030
in the STEPS, but falls by 13 mb/d in the NZE Scenario.

 Aviation and shipping consumed 10 mb/d of oil in 2021, which is 20% less than before
the Covid‐19 pandemic. In the STEPS, economic growth drives up trade and travel,and demand grows by 4 mb/d between 2021 and 2030. In the APS, action is taken toincrease the use of alternative fuels and cut emissions to achieve the climate goals ofgovernments and targets set by industry organisations, and demand increases by
3 mb/d to 2030. In the NZE Scenario, behaviour changes and increases inlow‐emissions liquid fuels mean oil demand barely increases to 2030.

 The chemical sector was the only sector in which oil use increased in 2020, and it is
set to account for a rising share of oil use in each scenario. Around 70% of oil used asa petrochemical feedstock is currently used to produce plastics. A number of countries
are announcing policies to ban or reduce single‐use plastics, improve recycling rates
and promote alternative feedstocks. Global average recycling rates for plastics
increase from the current level of 17% to 27% in 2050 in the STEPS, 50% in the APS,
and 54% in the NZE Scenario.
mean that new conventional upstream projects are required to ensure that supply
and demand stay in balance. Around USD 470 billion annual upstream investment is
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 In the STEPS, rising demand and declining output from existing sources of production

spent on average to 2030, which is 50% more than has been invested in recent years.
In the APS, demand is lower, but there is still a need for new conventional projects,
and USD 380 billion is invested annually on average to 2030. In the NZE Scenario,
declining fossil fuel demand can be met without the need for the development of newoil fields, but with continued investment in existing assets, and this requires
USD 300 billion annual average upstream investment to 2030.

 The impact of the Covid‐19 pandemic and the low level of investment in recent years
mean there are few new resources under development and few discovered resources
available to be developed. New oil resources discovered in 2021 were at their lowest
level since the 1930s. The implications of this vary by scenario. In the STEPS, thelargest increases in production to 2030 come from US tight oil, Middle East membersof OPEC, Guyana and Brazil.

 High oil prices and energy security concerns are encouraging some countries to revisit
the case for issuing exploration licences for new domestic oil projects. Such licences
are unlikely to provide any relief in the short term: in the past it has taken 20 years on
average to move from a new exploration licence to the start of production. Projects
with shorter lead times and quick payback periods – such as tight oil and projects toextend production from existing fields – are better candidates for making good any
short‐term shortfalls in supply. They play an important role in all our scenarios.

 Global refining capacity fell in 2021 for the first time in more than 30 years. As demandrebounded in 2022 and oil product exports from Russia and China have fallen, refining
margins surged to record highs. In the STEPS, rising demand for diesel and kerosenemeans markets are likely to remain very tight for a number of years. In the APS, strong
policy measures to curb demand significantly reduce this tightness. The APS and the
NZE Scenario see major changes in the composition of product demand, requiring
refiners to adapt refinery configurations and business models, and to invest moreheavily in emissions reductions, hydrogen and biofuels.

 Disruption to food supply chains and high fertiliser prices mean liquid biofuel costs
have soared. A growing focus on ensuring sustainability meanwhile has led toincreasing attention being paid to advanced liquid biofuels that do not directlycompete with food and feed crops, and that avoid adverse sustainability impacts.
Liquid biofuels grow from 2.2 million barrels of oil equivalent per day (mboe/d) in
2021 to 3.4 mboe/d in the STEPS, 5.5 mboe/d in the APS and 5.7 mboe/d in the NZE
Scenario in 2030.

 Low‐emissions hydrogen‐based liquid fuels offer an alternative to oil, but they326

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currently have high costs of production and suffer from limited enabling
infrastructure. The development and deployment of new projects over the next
decade will be essential to lower costs and improve performance so that these fuels
can play a significant role in the future.

…and what new
supplies areneededWhen does oil demand peak…
APS

STEPS

2024

98.1 mb/d

2015

Oil demand increases by 8 mb/d in
the STEPS and falls by 1.5 mb/d in
the APS between 2021 and 2030.
Production from existing fields dropsby 18 mb/d over this period, leaving
a large gap in 2030 that needs to be
filled by new sources of supply.

2035

103.2 mb/d

2021

STEPS
APS

STEPS

APS

NZE

Tight oil

Peaks in oil demand rest on changes in transport.
Oil use in petrochemicals is harder to shift.
STEPS

APS

NGLs
Already approved
New approvals

NZE
mb/d

2021 2050

25.9Road passenger

25

21

16

0.4

3.5

2.7

Road freight

15

18

8

1

16.5

5.7

2.3
1.0

Aviation and shipping

10

18

10

Petrochemicals

14

19

15

2

5.7

14
7.6

13

mb/d

Introduction
The situation for oil markets today could hardly be more different from what it was in 2020.
Two years ago, lockdowns imposed in response to the Covid‐19 pandemic caused a hugeoversupply of oil, leading prices to collapse to an average of USD 44/barrel. Today, global
supply is struggling to keep pace with demand, with many producers bumping up against
capacity constraints and Russia’s invasion of Ukraine sharply accentuating market tightness.
Prices have soared to an average of USD 105/barrel so far in 2022.
Global oil use is subject to sharply conflicting pressures. Some sectors, notably aviation, arestill recovering from the shock of the pandemic. Others, such as the chemical sector, haveremained robust throughout. Road transport, which has traditionally been the heartland ofoil consumption, is undergoing structural changes, especially for personal mobility; nearly
one‐in‐ten passenger cars sold worldwide in 2021 was an electric vehicle. And now highprices – and their economic impacts – are contributing further to near‐term uncertainty.
On the supply side, the major near‐term question regards Russia and the extent to whichtighter sanctions will force a reduction in output. Behind that lies a host of strategic questions
for other producers, including members of the Organization of Petroleum ExportingCountries (OPEC), over how much of current windfall revenues they will invest in large‐scale
new production assets. For the moment, the reaction of producers to higher prices has been
relatively muted. Upstream investment is expected to rise by around 10% in 2022, but thisremains well below the pre‐pandemic level of investment in 2019, and most of the rise stems
from cost inflation rather than an increase in activity.
The global energy crisis has also put the spotlight on refining, where a deficit of available
capacity led to oil product prices in 2022 rising even more than crude oil prices; and on the
biofuels sector, where higher oil prices would normally encourage new production, but
disruption to food supply chains and high fertiliser prices are complicating the picture.

What do recent bans and recycling policies mean for plastics? Oil demand for
petrochemicals has been strong, but might this be undercut by new policy initiatives?



Are new conventional oil projects part of the answer to today’s energy crisis? Is therea need for new conventional oil projects to balance markets?

What do tight oil product markets mean for refining? How much of a buffer does thesystem have and how might sanctions and embargoes affect oil trade?

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Where do we go from here? This chapter looks at three scenarios for guidance. As ever, they
provide different answers to this question. In the Stated Policies Scenario (STEPS), robust oil
demand growth leads to demand in 2030 of 102 million barrels per day (mb/d). In the
Announced Pledges Scenario (APS), demand soon peaks and drops to 93 mb/d in 2030. In
the Net Zero Emissions by 2050 (NZE) Scenario, demand drops rapidly to 75 mb/d in 2030.
Against this backdrop, this chapter also examines in detail three key issues that will shape
the future of oil markets:

Scenarios
7.1 Overview
Table 7.1 ⊳Global liquids demand and supply by scenario (mb/d)
STEPS

Road transport

APS

NZE

2010

2021

2030

2050

2030

2050

2030

2050

36.5

40.5

41.9

39.0

37.8

17.3

27.5

1.3

Aviation and shipping

9.9

9.9

14.0

18.1

12.8

9.5

10.0

2.0

Industry and petrochemicals

17.2

20.5

23.7

25.5

21.5

18.1

20.1

13.4

Buildings and power

12.4

11.4

9.3

7.0

8.3

3.7

6.5

0.6

Other sectors

11.2

12.2

13.6

12.5

12.6

8.6

11.1

5.6

World oil demand

87.2

94.5

102.4

102.1

93.0

57.2

75.3

22.8

Liquid biofuels

1.2

2.2

3.4

5.3

5.5

9.2

5.7

5.7

‐

‐

0.0

0.2

0.2

3.2

0.9

5.6

World liquids demand

88.4

96.7

105.8

107.6

98.7

69.5

81.9

34.1

Conventional crude oil

66.8

60.1

62.5

62.6

56.8

31.0

44.2

12.6

Tight oil

0.7

7.4

10.9

9.9

9.7

6.7

9.2

1.6

Natural gas liquids

12.7

18.2

20.9

19.3

19.2

13.9

16.4

6.1

Extra‐heavy oil and bitumen

2.6

3.7

4.4

6.2

4.1

3.4

3.3

2.0

Low‐emissions hydrogen‐based fuels

Other production

0.6

0.9

1.2

1.4

1.0

0.3

0.3

0.0

World oil production

83.4

90.3

99.9

99.3

90.7

55.3

73.5

22.2

OPEC share

40%

35%

36%

43%

36%

43%

36%

52%

World processing gains

2.2

2.3

2.5

2.8

2.3

1.9

1.8

0.6

World oil supply

85.5

92.6

102.4

102.1

93.0

57.2

75.4

22.8

96

69

82

95

64

60

35

24

IEA crude oil price (USD[2021]/barrel)

7

In the STEPS, global oil demand surpasses 2019 levels by 2023, undeterred by high oil prices.
Demand peaks in the mid‐2030s at 103 mb/d and then declines slightly to 2050 (Table 7.1).
There is continued growth in the use of oil for aviation and shipping, as a petrochemical
feedstock, and as fuel in heavy trucks, but from the mid‐2030s this is more than offset by
declining oil use in other sectors, especially in passenger cars, buildings, and power
generation. It is assumed that production from Russia in the near term falls by 2 mb/d due
to European and US sanctions, and that in the long term it remains well below projections
made prior to its invasion of Ukraine. The largest increases in production to 2030 come fromthe United States, Middle East members of OPEC, Guyana and Brazil. The OPEC share of oil
production rises from 35% in 2021 to 36% in 2030 and 43% in 2050. The supply of liquidbiofuels more than doubles to 2050, and there is also a small increase in low‐emissions
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Notes: mb/d = million barrels per day; STEPS = Stated Policies Scenario, APS = Announced Pledges Scenario;
NZE = Net Zero Emissions by 2050 Scenario. Other production includes coal‐to‐liquids, gas‐to‐liquids, additives
and kerogen oil. Historical supply and demand volumes differ due to changes in stocks. Liquid biofuels andlow‐emissions hydrogen‐based liquid fuels are expressed in energy equivalent volumes of gasoline and diesel,reported in million barrels of oil equivalent per day. See Annex C for definitions.

hydrogen‐based fuels. Upstream oil investment rises from current levels to offset losses insupply and meet rising demand and, as markets rebalance, the oil price falls from the very
high levels in 2022 to around USD 82/barrel in 2030.
In the APS, stronger policy action leads global oil demand to peak in the mid‐2020s, justabove the level of demand in 2019, before dropping to 93 mb/d in 2030 (Figure 7.1). Demandthen falls by around 40% between 2030 and 2050, with passenger cars, road freight andindustry responsible for the largest reductions. The use of oil as a petrochemical feedstockincreases by 0.9 mb/d between 2021 and 2050, and this is one of the few areas where oil
demand rises in this scenario. Lower demand eases the task of offsetting the near‐term
reductions in Russian oil production, but from 2030 onwards it leads inexorably to falls in
production in nearly all producer countries. The oil price falls to just under USD 65/barrel in
2030 and continues to decline slowly thereafter as demand falls.
Figure 7.1 ⊳Global oil demand and crude oil price by scenario
Oil price
USD/barrel

mb/d

Oil demand
125
100

150
120

75

90

50

60

25

30

2000 2010 2020 2030 2040 2050
STEPS

2000 2010 2020 2030 2040 2050
APS

NZE
IEA. CC BY 4.0.

Demand peaks in the mid-2030s in the STEPS, in the mid-2020s in the APS, and policy-led
declines in demand in the NZE Scenario mean a radically different future for oil markets

In the NZE Scenario, oil demand never returns to its 2019 level. Demand falls by 2.5% eachyear on average between 2021 and 2030, and by just under 6% each year from 2030 to 2050.
Reductions in oil use in road transport are particularly significant, and assume that policy
makers mandate a strong global push towards cleaner alternatives: no new cars with internal
combustion engines are sold after 2035 and nearly all trucks sold from 2040 use electricity
or hydrogen. The global effort to increase recycling of plastics pushes the rate from 17% in
2021 to 54% in 2050. Around 11 million barrels of oil equivalent (mboe/d) of low‐emissions

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Notes: STEPS = Stated Policies Scenario, APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario; mb/d = million barrels per day.

liquid fuels are consumed in 2050, mainly in aviation and shipping. 1 Even with the rapid
decline in oil demand in the NZE Scenario, there is a need for continued investment in existingproduction assets, but the declines are sufficiently steep to avoid the need for any new longlead time conventional fields. The oil price is increasingly set by the operating cost of themarginal project and it falls to around USD 35/barrel in 2030 and to USD 24/barrel in 2050.

7.2

Oil demand by region and sector

Table 7.2 ⊳Liquids demand by region and scenario (mb/d)
STEPS

APS

2010

2021

2030

2040

2050

2030

2040

2050

North America

22.2

21.4

20.5

17.8

16.2

18.2

10.8

6.9

United States

17.8

17.7

16.7

14.1

12.6

15.0

8.4

5.0

5.5

5.3

5.5

5.8

5.8

4.8

3.5

2.4

Brazil

2.3

2.4

2.4

2.5

2.4

2.0

1.4

0.9

Europe

13.9

12.4

10.9

8.6

7.1

9.2

4.7

2.7

10.6

9.2

7.7

5.8

4.5

6.5

3.1

1.7

3.3

3.8

5.0

6.7

8.5

4.9

5.8

6.1

0.5

0.5

0.6

0.7

0.7

0.5

0.4

0.3

Middle East

7.1

7.7

8.9

10.4

10.9

8.0

8.4

7.9

Eurasia

3.2

4.1

4.2

4.5

4.5

4.1

4.0

3.9

Asia Pacific

25.0

33.3

38.2

38.7

36.7

35.1

28.1

20.6

China

8.8

15.1

16.2

14.3

12.5

15.2

11.0

7.6

India

3.3

4.7

6.7

8.4

8.3

5.9

5.4

3.9

Japan

4.2

3.3

2.7

2.1

1.7

2.4

1.3

0.7

Southeast Asia

4.0

4.9

6.7

7.4

7.4

6.0

5.2

3.9

International bunkers

7.1

6.6

9.3

10.4

12.4

8.6

7.5

6.8

World oil

87.2

94.5

102.4

102.8

102.1

93.0

72.9

57.2

Liquid biofuels
Low‐emissionshydrogen‐based fuels
World liquids

1.2

2.2

3.4

4.6

5.3

5.5

8.7

9.2

0.0

0.0

0.0

0.1

0.2

0.2

1.2

3.2

88.4

96.7

105.8

107.5

107.6

98.7

82.8

69.5

Central and South America

European Union
AfricaSouth Africa

7

Notes: Liquid biofuels and low‐emissions hydrogen‐based liquid fuels are reported in million barrels of oil
equivalent per day. See Annex C for definitions.

1
Low‐emissions liquid fuels include liquid biofuels and low‐emissions hydrogen‐based liquid fuels, including
ammonia, methanol and other synthetic liquid hydrocarbons.

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The last few years have been very volatile ones for oil markets. Oil demand fell by nearly
9 mb/d in 2020 and rose by around 5.5 mb/d in 2021. Demand in 2021 surpassed 2019 levels
in only a few countries, including China, Poland, Sweden and Kazakhstan. Oil use in passenger
cars in 2021 was about 5% lower than pre‐pandemic levels globally, and in aviation it wasaround 30% lower.

Oil prices increased steadily during 2021 and jumped to USD 105/barrel in the first‐half of2022 following Russia’s invasion of Ukraine. A number of countries, including the UnitedStates and Indonesia, have seen gasoline prices increase by more than 30% between 2019
and the first‐half of 2022, and gasoline prices at the pump have surpassed USD 2/litre in morethan 20 countries (equivalent to more than USD 7.5/US gallon). Several governments haveintroduced measures to reduce prices at the pump, for example by reducing taxes and excise
duties (Chapter 2). The IEA set out a 10‐Point Plan to Cut Oil Use (IEA, 2022a) for consumers
in advanced economies that could quickly reduce oil demand by around 2.7 mb/d in order tohelp alleviate some of the current market tightness (Chapter 5). Despite growing pressuresand uncertainties, global oil demand is set to increase by 1.7 mb/d in 2022 as economic andtransport activity rebounds.
In the STEPS, oil demand surpasses 2019 levels by 2023 and increases to 102 mb/d in 2030
(Table 7.2), with China, India and Southeast Asia together accounting for more than 60% of
the increase in global demand. In advanced economies, demand falls by 3 mb/d to 2030,
mainly because of reductions in road transport, and only a few countries see demand exceed
2019 levels. In emerging market and developing economies, demand increases by 8 mb/d to2030 as car fleets expand and the use of oil use as a petrochemical feedstock rises rapidly.
Demand peaks globally in the mid‐2030s as reductions in advanced economies (a drop from2030 to 2050 of 10 mb/d) just outweigh growth in emerging market and developing
economies (6 mb/d increase) and international bunkers (3 mb/d increase).
In the APS, global oil demand peaks in the mid‐2020s at 98 mb/d. Faster electrification in thetransport and buildings sectors helps governments to deliver on their climate pledges, while
the use of oil for petrochemical feedstocks grows more slowly than in the STEPS. Oil demandin advanced economies falls by around 7.5 mb/d between 2021 and 2030 and increases by
4 mb/d in emerging market and developing economies.
In the NZE Scenario, strong policy action worldwide means global oil demand never recovers
to its 2019 level and it falls by nearly 20 mb/d between 2021 and 2030. There is a 15 mb/ddecrease in demand in advanced economies to 2030 and a 5 mb/d decrease in emerging
market and developing economies.

There are 1.3 billion passenger cars on the road today and they accounted for nearly 25% of
global oil demand in 2021 (Figure 7.2). Despite high gasoline and diesel prices, demand is set
to increase slightly in 2022 as the world economy recovers from the Covid‐19 pandemic. The
outlook to 2030 varies by scenario: demand is broadly flat in the STEPS and falls by nearly
3 mb/d in the APS. Electric car sales grow faster in the APS than in the STEPS and this is
responsible for around 50% of the difference between the two scenarios in 2030; stronger
fuel economy improvements in the APS account for another 25% of the difference (seeChapter 5). In the NZE Scenario, 60% of cars sold worldwide are electric in 2030 and oil
demand falls by around 9.5 mb/d.

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Demand trends to 2030

Figure 7.2 ⊳Oil demand by sector and scenario to 2030

2030

Transport
2021
STEPS
APS
NZE

Passenger vehicles
Road freight
Aviation and shipping

2030

Industry and energy production
2021
STEPS
APS
NZE

Chemicals andpetrochemicals
Oil refineries

2030

Other sectors
2021
STEPS
APS
NZE

Buildings
Power

Other
10

20

30

40

50

7

60
mb/d
IEA. CC BY 4.0.

Road transport remains by far the most important sector for oil demand,and it sees the biggest changes to 2030
Notes: Passenger vehicles = cars, buses and two/three‐wheelers.

Road freight accounts for more than 15% of global oil demand today. Rising demand for
freight transport causes oil demand to rise by 1.5 mb/d to 2030 in the STEPS and by 0.3 mb/din the APS despite increases in the uptake of electric and fuel cell heavy‐duty trucks and liquidbiofuels. The NZE Scenario sees a 3 mb/d reduction in demand to 2030.

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Aviation and shipping both experienced increased oil demand in 2021. In aviation, oil use
rose to 5 mb/d, but this was still 30% lower than in 2019. In shipping, maritime traderebounded strongly from the lows in 2020 and oil use rose to around 5 mb/d in 2021,
meaning that both sectors used broadly equivalent amounts of oil in 2021. All the scenarios
take account of expected increases in trade and travel stemming from the 35% growth in thesize of the global economy to 2030. In the STEPS, this leads to a 4 mb/d increase in oil use inaviation and shipping to 2030. In the APS, various policies – including the European Union
ReFuelEU Plan and targets to increase the use of sustainable aviation fuels in the UnitedStates – reduce this increase to 3 mb/d to 2030. In the NZE Scenario, demand only increases
marginally to 2030 as behaviour changes slow activity growth in aviation (see Chapter 3) andthe uptake of low‐emissions liquid fuels increases (Figure 7.3).

Growth in alternatives to oil in transport by scenario to 2030

60%

Heavy trucks
Share of EV and FCEV sales

Share of EV sales

Passenger cars

40%

20%

2021

60%

40%

20%

2030

2021
STEPS

Aviation and shipping
Low‐emissions fuel share

Figure 7.3 ⊳

2030
APS

15%

10%

5%

2021

2030

NZE
IEA. CC BY 4.0.

Moves away from oil use in all transport modes are evident in the STEPS and APS, but thesefall far short of what is needed to meet the climate goals embodied in the NZE Scenario
Notes: EV = electric vehicle; FCEV = fuel cell vehicle; heavy trucks = medium‐ and heavy‐freight trucks.
Low‐emissions fuels include biofuels, low‐emissions hydrogen and hydrogen‐based fuels.

The chemical sector was the only sector in which oil use increased in 2020, and it now
accounts for around 15% of global oil demand. An increasing number of countries haveintroduced or announced policies to reduce single‐use plastics and improve recycling levels,
but demand nevertheless grows by more than 2 mb/d in the STEPS between 2021 and 2030,
and by more than 1 mb/d in the APS. In the NZE Scenario, demand only rises marginally to2030 thanks to strengthened reuse and recycling strategies for plastics globally, backed bytargeted policies that lead to much lower plastic demand per capita levels (see section 7.8).
The buildings sector accounts for just under 10% of oil use today. Demand falls in advanced
economies as an increasing number of countries and jurisdictions have banned sales of new
fossil fuel boilers. It is however set to grow in emerging market and developing economies
as a result of increasing demand for liquefied petroleum gas (LPG), especially for cooking in
Asia and Africa. Net oil use in buildings decreases globally by almost 1 mb/d in the STEPS, by
1.5 mb/d in the APS, and by nearly 2.5 mb/d in the NZE Scenario. The decrease in the NZE
Scenario occurs even though it incorporates universal access to clean cooking by 2030.

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Oil use for power generation has fallen by around 30% since 2010 and currently stands ataround 3.5 mb/d, with Middle East countries accounting for 40% of this total. With strong
growth in renewables, demand to 2030 falls by one‐third in the STEPS, by 45% in the APS,
and by 70% in the NZE Scenario.

Demand trends after 2030

mb/d

Figure 7.4 ⊳Change in oil demand by scenario, 2030-2050
Sectors

10

Regions
Sectors
Other
Power
Buildings
ChemicalOil refineries
Aviation and shipping
Road freight
Passenger vehicles
Regions
Advanced economies
Emerging market anddeveloping economies

0

‐10
‐20
‐30
‐40
‐50
‐60

STEPS

APS

NZE

STEPS

APS

NZE

Net change
IEA. CC BY 4.0.

Oil demand in the STEPS falls only marginally from its peak in 2035; it falls much7

more sharply in the APS as current climate pledges are met on time and in full
Notes: Other = rail, pipeline transport, non‐specified transport, agriculture, oil and gas extraction, non‐energy
use and industry apart from use in the chemical sector.

In the APS, oil demand falls by nearly 40% between 2030 and 2050 to 57 mb/d in 2050.
Achieving national climate pledges leads to a strong reduction in oil use in transport and thisis supported by the electric vehicle targets of manufacturers. Over 70% of passenger cars on
the road in 2050 are electric or fuel cell vehicles, and so are 40% of heavy trucks. In theaviation and shipping sectors, the International Civil Aviation Organization requires
international airlines to offset emissions growth above 2019 levels (ICAO, 2020), and theInternational Maritime Organisation has a target to cut emissions from maritime transport
by at least half by 2050 (relative to 2008 levels) (IMO, 2018). Achieving these goals in the APS
leads to a 25% reduction in oil use in aviation and shipping between 2030 and 2050. Oil use
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In the STEPS, global oil demand levels off in 2035 at around 103 mb/d and then drops byaround 1 mb/d to 2050 (Figure 7.4). Demand reductions in road transport, buildings andpower after 2030 are offset by growth in feedstocks, aviation and shipping. By 2050, policy
support and falling battery costs mean that around 40% of cars and 10% of heavy trucks on
the road are electric or fuel cell vehicles. Efficiency measures and the use of alternative fuelscurtail the growth of oil use in shipping and aviation. Between 2030 and 2050, global
international shipping activity doubles while oil use increases by 25%, and international
aviation activity increases by two‐thirds while oil use increases by 40%. Oil use as apetrochemical feedstock increases by 2.5 mb/d between 2030 and 2050 as growth inemerging market and developing economies outweighs efforts to reduce and recycle
plastics.

as a petrochemical feedstock also falls slightly between 2030 and 2050 as a result of stronger
efforts to reuse and recycle plastics.
In the NZE Scenario, strenuous policy efforts to reduce emissions lead to a 6% average annual
reduction in oil demand between 2030 and 2050, and demand in 2050 falls to less than
25 mb/d. Three‐quarters of this is used as a petrochemical feedstock and in other processes
in which the oil is not combusted, such as in lubricants, paraffin waxes and asphalt; a further
10% is used in aviation and shipping. Around 10 mboe/d of low‐emissions liquid fuels are
consumed in 2050. Most of this is used in aviation and shipping where low‐emissions liquid
fuels account for 80% of all liquid fuels used in 2050; the share of oil in total final
consumption falls to 20% in aviation and 15% in shipping.

Oil supply

Table 7.3 ⊳Oil production by scenario (mb/d)
STEPS

APS

2010

2021

2030

2040

2050

2030

2040

2050

North America

14.2

24.4

28.6

27.0

24.6

25.8

19.2

14.7

CanadaUnited States
Central and South America
BrazilGuyanaVenezuela
EuropeNorwayUnited Kingdom
AfricaAngolaNigeria
Middle East
Iraq
Iran
KuwaitSaudi Arabia
United Arab Emirates
Eurasia
RussiaAsia Pacific
China

3.5
7.8
7.4
2.2
0.0
2.8
4.4
2.1
1.4
10.2
1.8
2.5
25.4
2.4
4.2
2.5
10.0
2.8
13.4
10.4
8.4
4.0

5.6
16.8
5.9
3.0
0.1
0.6
3.6
2.0
0.9
7.4
1.2
1.7
27.9
4.1
3.4
2.7
11.0
3.6
13.7
10.9
7.4
4.0

6.2
20.7
9.0
4.5
1.6
0.8
3.1
2.0
0.6
7.0
0.9
1.3
33.9
4.6
3.9
3.3
13.5
4.8
11.9
8.8
6.3
3.6

6.4
18.6
10.1
4.3
2.0
1.4
2.2
1.3
0.4
6.4
0.8
1.3
38.2
5.5
4.6
3.4
14.8
5.4
10.8
7.7
5.4
3.1

5.5
16.7
11.4
5.1
1.1
2.7
1.3
0.6
0.3
6.1
0.9
1.3
40.4
6.2
5.0
3.5
15.9
5.5
10.6
7.7
4.8
2.7

5.4
18.8
8.3
4.4
1.4
0.7
2.7
1.9
0.5
5.8
0.8
1.2
31.2
4.6
3.7
3.0
12.3
4.1
11.2
8.5
5.7
3.3

4.1
14.0
7.7
3.8
1.5
1.2
1.3
1.0
0.2
4.0
0.6
0.9
27.5
3.7
4.0
2.6
10.9
3.2
7.6
5.5
3.5
1.9

3.2
10.7
6.5
3.3
1.0
1.3
0.6
0.5
0.1
2.9
0.5
0.7
22.9
2.7
2.8
2.3
10.0
2.5
5.4
3.9
2.2
1.1

Conventional crude oil
Tight oil
United States
Natural gas liquids
Canada oil sands
Other production

66.8
0.7
0.6
12.7
1.6
1.6

60.1
7.4
6.9
18.2
3.4
1.3

62.5
10.9
9.9
20.9
3.9
1.7

62.5
11.3
9.7
19.9
3.8
2.6

62.6
9.9
8.6
19.3
3.7
3.8

56.8
9.7
8.8
19.2
3.5
1.6

41.9
8.3
7.8
15.9
2.8
1.8

31.0
6.7
6.2
13.9
2.2
1.6

Total
OPEC share (%)

83.4
40%

90.3
35%

99.9
36%

100.1
40%

99.3
43%

90.7
40%

70.7
40%

55.3
43%

Note: See Annex C for definitions.

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7.3

Supply trends to 2030
Figure 7.5 ⊳Oil production in the STEPS and change by scenario, 2021-2030
Change 2021‐2030

mb/d

STEPS
100

10

75
0
50
‐10
25
‐20
2015

2020

Conventional onshore

2025
Offshore

2030
Tight oil

EHOB

STEPS
Other

APS
OPEC

NZE
Non‐OPEC

7

IEA. CC BY 4.0.

US tight oil, oil produced by OPEC members, and new Brazil and Guyana deepwater oil allplay a major part in meeting the near-term increases in demand in the STEPS and APS
Notes: EHOB = extra‐heavy oil and bitumen. Other = enhanced oil recovery, Arctic crude, gas‐to‐liquids, coal‐to‐liquids, additives and oil shale.

High oil prices and concerns about energy security have led countries around the world toreassess the economic, political and climate impacts of bringing on new sources of domestic
oil supply. In the wake of the pandemic and low investment levels in recent years, there ishowever a limited pipeline of new resources under development and of discovered resources
available to be developed. New oil resources discovered in 2021 were at their lowest level
since the 1930s. Access to financing has proved challenging, supply chains have become
stretched, and costs are rising across the industry.

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In the STEPS, there is 8 mb/d of demand growth to 2030 and 6 mb/d of production declines
in mature producers (Table 7.3). More than 80% of this gap is met through increases in
production in Middle East OPEC member countries, US tight oil, and Brazil and Guyana
deepwater developments (Figure 7.5). Production from Russia is assumed to fall by around2 mb/d as European and US sanctions take hold, but declines stabilise as new routes aredeveloped to markets outside Europe, despite continuation of the sanctions. There is a
gradual normalisation of the international situation in a number of other major resource‐
holders subject to sanctions, notably Iran and Venezuela, and production from thesecountries rises to 2030.

In the APS, global oil demand falls back to 2021 levels by 2030, but declines in mature
producers means just over 8 mb/d of production increases elsewhere are needed to 2030.
Countries with net zero emissions pledges make efforts to minimise emissions from theirdomestic oil and gas operations and this tends to increase their financing and production
costs. Countries without net zero emissions pledges also come under pressure to reduce oil‐and gas‐related emissions as consumers in export markets start to differentiate imports by
the emissions intensity of production. This leads to a 25% reduction in the global average
emissions intensity of oil production by 2030 in the APS, compared with a 15% reduction in
the STEPS.
In the NZE Scenario, falling demand is met without any need to approve the development of
new long lead time projects. There is continued investment in existing fields, and thisincludes some low cost extensions of existing fields, e.g. for example through the use of in‐
fill drilling, enhanced oil recovery and tight oil drilling, to ensure that supply does not fall
faster than the decline in demand. There is also investment to reduce emissions from oil andgas production, and the global average emissions intensity of oil production falls by morethan 50% to 2030.
In the United States, oil production increases by just under 4 mb/d to 2030 in the STEPS, andtotal US production in 2030 is around 50% higher than in the next largest producer country(Saudi Arabia). Tight oil operators choose to prioritise returns over aggressive production
growth but high prices in the near term encourage increased drilling. Tight oil and natural
gas liquids (NGLs) from shale plays account for nearly all of the increase in US production to2030. In the APS, lower oil and gas prices mean a smaller increase in tight oil and NGLs fromshale plays but US production still increases by 2 mb/d to 2030.
In Russia, oil production in the STEPS is assumed to decline by 2 mb/d to 2030 as sanctions
take hold. Russia has been under sanctions since 2014 but the financial and technology
restrictions bite much harder now. As access to technologies, oil field service expertise,equipment and assets is removed, Russia struggles to maintain production in existing fields
and to develop large new fields in the Arctic, tight oil and other offshore areas. In the APS,
lower prices and fewer export opportunities mean Russian production in 2030 is around
2.5 mb/d lower than in 2021.

In Europe, production declines by 0.5 mb/d in the STEPS and by 0.8 mb/d in the APS in 2030.
New fields brought online in Norway mean its production rises to the mid‐2020s before
declining to current levels by 2030. The United Kingdom sees some inward investment, but
production in 2030 is 0.2 mb/d lower than it is now in both the STEPS and the APS.
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In Canada, oil production rises by 0.6 mb/d to 2030 in the STEPS. The increase comes fromextra‐heavy oil and bitumen (EHOB) projects currently under development and fromincreased tight oil production. No new large‐scale EHOB projects are approved fordevelopment in the STEPS, but there are some smaller scale extensions of existing projects.
In the APS, there are increased efforts to reduce domestic emissions from oil and gas
operations and total production falls slightly to 2030.

Saudi Arabia has recently invested more than USD 18 billion to raise capacity at its Berri andMarjan fields, and is set to make further investments. Together with measures to remove
bottlenecks, this spending leads to production rising from around 11 mb/d in 2021 to
13 mb/d in the STEPS (of which 11 mb/d is crude oil) and to 12 mb/d in the APS by 2030.
Iraq roughly doubled its production during the 2010s but has suffered from low capital
investment since the 2014 oil price drop, difficulties in ensuring sufficient water for injection,and political disagreements. As a result, it has been unable to expand production further inline with its large resource base. Our scenarios assume that internal relationships arenormalised, that progress is made on providing water for oil recovery, and that production
rises by around 0.5 mb/d to 2030 in both the STEPS and the APS.
United Arab Emirates increased investment to USD 20 billion in 2022 against a backdrop ofmultiple large discoveries. Production increases by 1.2 mb/d to 2030 in the STEPS from both
onshore and offshore fields (including an expansion of the Upper Zakum oil field).
Iran faces limitations on its production as a result of international sanctions. Our scenarios
assume a gradual normalisation in relations over time and a rise in production of
0.3‐0.5 mb/d by 2030 in the STEPS and APS.

7

Venezuela faces political uncertainty and economic difficulties. Our scenarios assume agradual normalisation of the international situation, and a slight rise in output in both the
STEPS and APS.
Brazil has invested heavily in recent years in its large pre‐salt deepwater fields and it hasannounced plans to nearly double annual investment between 2021 and 2026. A number ofits development projects have suffered from delays and cost overruns, but these projects
come steadily online in both the STEPS and APS, and total production grows by 1.4 mb/d toaround 4.4 mb/d in 2030. As a result, Brazil accounts for around 45% of global deepwaterproduction in 2030 in both scenarios.
Guyana has seen a number of major deepwater discoveries in recent years and companies
have been looking to develop these quickly. Production began at its Liza field in 2019 only
four years after it was discovered and is continuing to ramp up. Overall production increases
by around 1.5 mb/d to 2030 in the STEPS and APS.

African members of OPEC have seen a 30% drop in production since 2010, with output inboth Angola and Nigeria beset by technical and operational difficulties. Both countries are
now developing new deepwater fields, but compensating for declines from existing fields
looks unlikely as investment in supply has been 45% lower since 2016 compared to the
2010‐15 period. Accordingly, production by African members of OPEC between 2021 and
2030 falls by 1 mb/d in the STEPS and by 2 mb/d in the APS.
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Argentina has been looking to expand production from its tight oil plays and the government
has eased capital control restrictions to encourage inward investment. Total production
increases marginally in the STEPS and APS as increases in tight oil production are offset by
declines in conventional oil production.

Supply trends after 2030

mb/d

Figure 7.6 ⊳Changes in oil production by region and scenario, 2021-2050

50

2021
2030
STEPS

40

APS

30

NZE
2050
STEPS
APS
NZE

20
10

MiddleEast

North
AmericaEurasia

Asia
Pacific

AfricaC&S
America

EuropeIEA. CC BY 4.0.

Increases in the Middle East and Central and South America offset declines elsewherein the STEPS after 2030; both the APS and NZE Scenario see declines in all regions

In the APS, demand declines by around 2.5% each year on average between 2030 and 2050,
and this means that much lower levels of new production are required than in the STEPS.
The biggest fall in production takes place in the United States over this period (8.5 mb/d) as
conventional fields mature and lower prices mean less investment in tight oil and shale gas.
There are also declines in Russia (4.5 mb/d) and Canada (2 mb/d). Among members of OPEC,
Iraq and Saudi Arabia see some of the largest declines. Overall OPEC production falls by justunder 9 mb/d, but its share of the market still increases to 43% in 2050.

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In the STEPS, demand remains largely flat between 2030 and 2050. As a result, investment
in new supply is needed chiefly to compensate for underlying declines in existing sources of
production. The largest declines in production to 2050 are in North America (Figure 7.6). As
the most productive US tight oil areas become depleted, US production drops by 4 mb/d
between 2030 and 2050. Without new large‐scale projects, EHOB production in Canada
starts to decline over this period. Global deepwater production grows to 9.5 mb/d in 2035,
supported by new output from Brazil and Guyana, before declining to around 7.5 mb/d in
2050. Production in Russia declines by just over 1 mb/d between 2030 and 2050. OPEC
members increase their production by 7 mb/d between 2030 and 2050 to offset declining
output elsewhere. One third of the increase in OPEC production comes from Saudi Arabia,
with Venezuela providing a further 25% and Iraq 10%; there are declines in production fromAfrican members of OPEC. OPEC’s share of the global oil market increases to 43%, its highest
level since 1979.

In the NZE Scenario, demand declines by around 6% on average each year between 2030 and
2050. Production accordingly falls in all regions and the oil price drops to very low levels(USD 25/barrel in 2050). Oil production is increasingly concentrated in resource‐richcountries due to the large size and slow decline rates of their existing fields. OPEC’s share ofa much smaller oil market increases to 52% in 2050, higher than at any point in the historyof oil markets. The combination of falling demand and a low oil price results in a sharp drop
in income and GDP in many fossil fuel producers, including some where revenues from oil
and gas sales often cover a large share of public spending on essential services. The oil pricein the NZE Scenario would in principle be sufficient for some of the lowest cost producers tocover the cost of developing new fields, but we assume that they do not do so as this would
lead to even lower prices and might herald greater market volatility depending on theresilience of these countries to such a sharp contraction in income.

7.4

Oil trade2

Table 7.4 ⊳Oil trade by region and scenario
STEPS

APS

Net imports(mb/d)

Share ofdemandNet imports(mb/d)Net importer in 2021

2021

2030

2050

2021

2030

2050

2030

2050

2030

2050

China

12.3

13.0

10.6

78%

75%

76%

12.2

6.9

75%

82%

European Union

9.7

8.9

5.7

93%

95%

92%

7.6

2.0

95%

93%

Other Asia Pacific

6.4

10.0

13.5

70%

82%

87%

9.3

7.9

83%

87%

Japan and Korea

5.8

5.5

4.1

96%

98%

98%

5.0

2.3

98%

97%

India

4.1

6.2

8.0

87%

89%

92%

5.4

3.8

90%

90%

Other Europe

0.3

0.9

2.2

7%

25%

67%

0.7

0.9

21%

60%

Net exports(mb/d)

Share ofproduction

7

Share ofdemandNet exports(mb/d)

Share ofproduction

Net exporter in 2021

2021

2030

2050

2021

2030

2050

2030

2050

2030

2050

Middle East

19.6

24.3

28.5

70%

72%

71%

22.4

14.4

72%

63%

Russia

7.2

5.3

4.4

66%

61%

58%

5.1

1.0

60%

27%

Africa

3.4

1.7

n.a.

46%

25%

n.a.

0.6

n.a.

11%

n.a.

North America

2.5

7.9

7.7

10%

27%

31%

7.3

7.5

28%

51%

Caspian

2.0

2.0

1.4

72%

66%

49%

1.8

0.4

64%

26%

Central & South America

0.4

3.1

5.0

8%

34%

44%

3.1

3.8

37%

59%

2
Trade figures reflect volumes traded between regions modelled in the World Energy Outlook and do notinclude intra‐regional trade. Oil trade includes both crude oil and oil products.

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Note: n.a. = not applicable.

In the STEPS, the European Union ban on imports from Russia and the sanctions imposed on
Russia together result in a major reorientation of oil trade. Russian net oil exports drop by
25% to 2030 and by more than 40% to 2050 (Table 7.4). The Middle East increases exports to
help offset this reduction and its share of global export markets rises from 52% in 2021 to
60% in 2050. North America overtakes Russia to become the world’s second‐largest oil
exporting region in the mid‐2020s. China remains the world’s largest oil importer to 2050
although its imports peak and fall slightly from 2030 onwards. India’s oil imports double
between 2021 and 2050. Despite ample crude supply, countries in Central and South Americaand Africa increasingly import oil products due to a lack of domestic refining capacity.
In the APS, a number of countries including large producers such as the United States andBrazil cut demand faster than supply, and this enables them to increase exports by more thanin the STEPS. This means a smaller share of the market for producers in the Middle East, andtheir share of export markets in 2050 is lower than in the STEPS. China’s imports in 2050 arearound one‐third lower than in the STEPS; India’s imports peak in the 2030s and fall below
the current level by 2050.
In the NZE Scenario, oil imports fall across the board. Around 10 mb/d of oil is still tradedglobally in 2050, most of which takes the form of exports from the Middle East and North
America to demand centres in the Asia Pacific region.

7.5

Oil investment

Figure 7.7 ⊳Average annual investment in oil by scenario
STEPS

APS

NZE

2018 2019 2020 2021 2022e

2023 2031‐2030 ‐2050

2023 2031‐2030 ‐2050

2023 2031‐2030 ‐2050

Upstream

Refining

Billion USD (2021)

600

400

200

Transport
IEA. CC BY 4.0.

Oil investment to 2030 in the APS is broadly in line with the levels seen in recent years;

Note: 2022e = estimated value for 2022 based on IEA (2022b).

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much lower demand in the NZE Scenario can be met without new long lead time projects

Total oil investment is expected to increase to around USD 450 billion in 2022, around 25%
more than in 2020. After years of relative stability, cost inflation has raised upstream costs
sharply, largely as a result of increased material costs, and this has significantly diminishedthe impact of higher spending on activity levels.
In the STEPS, average annual oil investment to 2030 is USD 580 billion, which is 30% higher
than the average since 2018 (Figure 7.7). Meeting the increase in oil demand to 2030 while
also offsetting declines from existing sources of supply requires annual average upstream oil
investment of USD 470 billion to 2030. Between 2022 and 2050, cumulative upstream oil
investment is USD 12 trillion, and there is a further USD 2.5 trillion of investment in transportand refining. Cumulative clean energy investment to 2050 meanwhile reaches
USD 60 trillion.
In the APS, aggregate average annual oil investment to 2030 is USD 470 billion, which isbroadly similar to levels over the past five years. Although demand peaks in the mid‐2020s,
declining production in existing sources of supply means that investment is needed at both
new and existing fields, and average annual upstream oil investment is USD 380 billion.
Cumulative upstream oil investment between 2022 and 2050 is USD 7.5 trillion, and a further
USD 1.5 trillion is invested in oil transport and refining. These levels of investment are
dwarfed by cumulative clean energy investment to 2050, which totals USD 95 trillion.

7

In the NZE Scenario, annual oil investment averages about USD 350 billion to 2030. The surge
in clean energy technology deployment means that oil demand falls at a rapid rate, and thatmakes it possible to meet demand without any new oil exploration or development of longlead time projects (see section 7.9). Reducing oil investment to this level would lead to a very
different outcome if done in advance of – or instead of – the huge scaling up in clean energy
spending and consequent reduction in oil demand that features in this scenario (seeChapter 4).

7.6

Liquid biofuels

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Over 80 countries have liquid biofuel blending mandates in place today. The drop in the oil
price in 2020 and changes in government priorities following the pandemic mean a numberof targets and plans have been delayed or scaled back, including in Indonesia, Malaysia,
Thailand and Brazil (IEA, 2021). Prices for biofuels have doubled since 2020 as a result of
increases in feedstock and energy costs stemming from Russia’s invasion of Ukraine andother disruptions to global crop production. During the first‐half of 2022, the price of
conventional biofuels averaged USD 270 per barrel of oil equivalent (boe) in the UnitedStates (around USD 70/boe higher than average US gasoline prices at the pump) and
USD 335/boe in Europe (similar to European average gasoline prices at the pump). Prices ofadvanced biofuels have increased by 70% since 2020 and have so far averaged between
USD 350‐400/boe in 2022.

mboe/dFigure 7.8 ⊳Liquid biofuel demand and supply by scenario
SupplyDemand

10
8
6
4

STEPS
APS
NZE
Passenger cars
TrucksAdvanced:
Aviation and shipping
Other
Conventional:

STEPS
Ethanol
Ethanol

APS
Biodiesel
Biodiesel

2050

2030

2050

2030

2050

2030

2021

2050

2030

2050

2030

2050

2030

2021

2

NZE
Biojet fuelIEA. CC BY 4.0.

Liquid biofuel use increases in all scenarios, more than doubling to 2030 in the APS andNZE Scenario, with increasing shares produced from non-food crop feedstocks
Note: Other includes other transport, industry, buildings and agriculture.

In the STEPS, demand for liquid biofuels grows from 2.2 mboe/d in 2021 to 3.4 mboe/d in
2030 and 5.3 mboe/d in 2050 (Figure 7.8). This comes mainly from blending mandates forpassenger cars that lead to an increase in the use of ethanol, which is produced using
advanced feedstocks. Passenger cars consume 50% of total liquid biofuels in 2030 and almost
40% in 2050. Ethanol comprises 55% of total biofuels production in 2030, down from 60%
today.

In the NZE Scenario, demand for liquid biofuels increases to 5.7 mboe/d in 2030 and thenremains around this level to 2050. The high penetration of electric cars and trucks leads to asignificant reduction in biofuels consumption in road transport after 2030, and more of thelimited supply of sustainable bioenergy available is used in the form of solid bioenergy inpower generation and in industrial applications where electrification is challenging. As aresult, demand for liquid biofuels in 2050 is 40% lower than in the APS. In the NZE Scenario,
around 90% of liquid biofuels produced in 2050 are advanced biofuels and 75% areconsumed in aviation and shipping. More than 40% of the fuel used in aviation in 2050 takes
the form of liquid biofuels (Box 7.1).
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In the APS, demand for liquid biofuels increases to 5.5 mboe/d in 2030 with much higher useof liquid biofuels in road transport in the United States, China, India and Canada. After 2030,
increasing sales of electric cars mean that liquid biofuels demand plateaus in road transport,
and a much higher share is used in aviation and shipping. In 2050, total liquid biofuelsconsumption is over 9 mboe/d, 75% of which consists of advanced biofuels. Around 40% of
this total is consumed in aviation and shipping, and liquid biofuels provide just over 25% of
total fuel use in aviation.

Box 7.1 ⊳Policy support needed for advanced liquid biofuels

Over 90% of liquid biofuels produced today are “conventional” biofuels produced fromfood crop feedstocks. These feedstocks include sugar cane ethanol, starch‐based
ethanol, fatty acid methyl ester, straight vegetable oil and hydrotreated vegetable oil
produced from palm, rapeseed or soybean oil. There is growing interest in the use ofalternative feedstocks that can avoid the potential sustainability concerns associatedwith some conventional biofuels. These advanced biofuels are produced from non‐foodcrop feedstocks, provide a large reduction in life cycle greenhouse gas (GHG) emissions
compared with fossil fuels, and do not directly compete with food and feed crops for
agricultural land or cause adverse sustainability impacts. The production of advanced
liquid biofuels increases in all scenarios, but is critically dependent on:

Developing sufficient quantities of sustainable feedstocks such as municipal solid
waste, wheat straw and non‐food crops. This implies comprehensive waste
management policies and regulations to enhance collection, sorting andpre-treatment, together with a robust certification system to ensure that feedstocks
are sustainable.



Demonstrating and scaling up ways of deriving sustainable feedstocks from non‐food energy crop production on non‐arable and degraded land. Sisal, for example,
grows on semi‐arid lands and is often used in the textile industry in processes that
produce large amounts of organic waste. This waste could be turned into liquidbiofuels and could generate additional streams of income for textile companies.

Regulatory stability to support the long‐term investments needed to scale up
production. The number of producers of advanced biofuels is small today, and newinvestors need visibility on policies and plans so that they can assess market
potential.

7.7

7

Low‐emissions hydrogen‐based liquid fuels

3
Hydrogen‐based synthetic hydrocarbons need to be made using a non‐fossil source of CO2, such as biogenic
or atmospheric CO2, to be a low‐emissions fuel. Sourcing this CO2 can add considerably to overall costs.

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Low‐emissions hydrogen‐based liquid fuels include ammonia, methanol and other synthetic
liquid hydrocarbons made from hydrogen with very low‐emissions intensity.3 They offer analternative to the use of oil, can often use existing infrastructure and combustion equipment,
and are expected to gain market share in sectors such as aviation and shipping that willotherwise struggle to reduce oil demand. However, they currently have high costs ofproduction, suffer from limited enabling infrastructure, can involve large energy losses fromproduction to consumption, and in some cases need to be handled more carefully than
traditional liquid fuels.

The future uptake of low‐emissions hydrogen‐based liquid fuels depends crucially on finding
ways to reduce production costs. Cheaper renewable energy and carbon capture, utilisationand storage (CCUS) will make a big difference, but dedicated projects are also needed to
improve low‐emissions hydrogen and ammonia production technologies and to reduce
efficiency losses across the value chain. There has been recent progress on this front. The
largest power generation company in Japan, JERA, issued a tender in 2022 for up to 0.5 Mt
of low‐emissions ammonia (around 5 thousand barrels of oil equivalent per day [kboe/d]) to
replace 20% of the coal at a large power plant unit from 2027. Maersk, a leading shipping
company, has commissioned 19 methanol‐fuelled container ships and it is studying how toensure that the methanol they use is produced from sustainable biomass. In Germany, a
350 tonne per year plant for the production of synthetic kerosene opened in 2022 next to an
existing synthetic methane plant and a source of CO2 from biogas upgrading.
Figure 7.9 ⊳Low-emissions hydrogen-based liquid fuel demand by scenario
and the declining cost gap with oil products in the NZE Scenario
End‐user prices and costs
USD/toe

1 500

Shipping

2030
Aviation

NZE

APS

500

STEPS

2

APS

1 000

NZE

4

STEPS

mboe/dDemand
6

2050
Power generation

2030
Marine fuelAmmonia

2050
Kerosene
Synth. kerosene
IEA. CC BY 4.0.

Rapidly rising demand for hydrogen-based liquid fuels helps bring down costs
through economies of scale and innovation, while prices of oil products rise

In the STEPS, there is limited uptake of hydrogen‐based fuels globally to 2030, reflecting the
low level of current policy support for their use (Figure 7.9). In the APS, more progress ismade, with 0.2 mboe/d of low‐emissions hydrogen‐based fuels being used globally fortransport in 2030. In the NZE Scenario, this figure rises to 0.4 mboe/d, most of which is usedin shipping. Achieving the levels of use seen in the APS and the NZE Scenario will require
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Notes: mboe/day = million barrels of oil equivalent per day; toe = tonne of oil equivalent. Synth.
kerosene = synthetic kerosene. Ammonia and synthetic kerosene costs are the average levelised production
costs for the Middle East and China. Final prices of marine fuel and kerosene include CO2 prices and otherlevies.

rapid progress on standards, notably for the safe transport and use of ammonia. There arelikely to be large regional variations in production costs for low‐emissions hydrogen‐based
fuels, and international trade will depend on international co‐operation on standards.
Progress between 2030 and 2050 obviously depends crucially on what is achieved by 2030,
including on deployment, innovation and economies of scale that help to narrow the cost
gap with oil products, as well as on standards. In the NZE Scenario, the steps taken by 2030
lay a solid foundation for the future. Taking into account the cost of CO2, the cost of
producing low‐emissions hydrogen‐based fuels in the NZE Scenario is lower than the price ofmaritime fuel in the 2030s in a number of regions, and lower than the price of aviation fuelin the 2040s. Nearly 6 mboe/d of low‐emissions hydrogen‐based liquid fuels are consumed
in 2050, roughly evenly split between aviation, power generation and shipping. This rests on
the production of 120 million tonnes of low‐emissions hydrogen fed by 1.2 terawatts ofrenewable power capacity (equivalent to 70% of today’s global installed solar and windcapacity) as well as 0.5 gigatonnes (Gt) CO2 per year of CCUS capacity.

Key themes
7

7.8 Oil use in plastics
Petrochemicals are integral to modern societies. They are used for plastics, fertilisers,
packaging, clothing, digital devices, medical equipment, detergents and tyres, among manyother things. They also feature in many parts of the modern energy system, including solar
PV panels, wind turbine blades, batteries, thermal insulation for buildings and electric vehicle
parts. The chemical sector today uses around 15 mb/d of oil and is set to be a major sourceof future demand growth. In this section, we look at the drivers of petrochemical feedstock
demand – with a particular focus on plastics – and at recent policy and technology
developments that could reduce oil use in petrochemicals.

Plastics are very useful. However, they do have downsides in terms of emissions from theirproduction, they account for a significant share of overall oil use in a number of countries,
and result in large amounts of waste, for example, plastic waste can end up in water streams
in the form of microplastics. The use of feedstock based on low‐emissions hydrogen‐based
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Around 90% of the oil consumed in the chemical sector today is used as a feedstock: theremainder provides heat and energy for production processes. Oil that is used as apetrochemical feedstock is converted into chemical products: this limits direct CO2 emissions
from its use, although in some instances the final products are eventually combusted andthis can result in a higher level of emissions. Around 70% of oil feedstock (10 mb/d) is used
to produce plastics, demand for which has grown rapidly in recent years. Demand for plastics
varies significantly between countries: for example, more than 250 kilogrammes (kg) of
plastic is used per capita every year in the United States and less than 25 kg of plastic per
capita is used each year in India (Figure 7.10). Around 30% of the use of plastics today is for
packaging.

fuels and bioenergy, for example produced by converting bioethanol to ethylene, could help
reduce emissions and oil dependency, but they are currently expensive, require large
quantities of sustainable bioenergy, and do not solve issues related to plastic waste.

kg plastic/capita

Figure 7.10 ⊳ Plastic demand per capita and recycling collection rates, 2019
250

25%

200

20%

150

15%

100

10%

50

5%

United EuropeanStates
Union

China

India

Other
TextileConsumer andinstitutional products
Transport
Building and construction
Packaging
Recycling collection
rate (right axis)

World
IEA. CC BY 4.0.

Packaging represents the biggest use of plastics in nearly all regions;plastic demand per capita and plastic recycling collection rates vary widely

There is growing momentum behind policies and initiatives that aim to reduce plastic use.
Particular attention is being paid to single‐use plastics, which are commonly used for
packaging and food utensils, and more than 60 countries so far have taken relevant action.
This includes China, which has restricted the production, sale and use of plastic bags as well
as some other disposable plastic products, and India, which has banned the production, saleand use of 19 single‐use plastic items.

4

Plastic waste includes all post‐consumer plastic waste with a life span of more than one year.

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Recycling of plastics is another option to cut down on waste and emissions. Globally, 17% ofplastic waste4 is collected for recycling today although there are large differences between
regions: for example, 25% is collected for recycling in Europe and less than 10% in the UnitedStates. Recycling rates for plastics are much lower than recycling rates for steel (80%),
aluminium (80%) and paper (60%). This is because of the complex processes required toremove impurities and avoid discolouration of recycled plastic material and because
processing facilities are capital intensive. Advanced sorting and recycling techniques arebeing developed to help solve these challenges, including chemical recycling and pyrolysis‐
based waste‐to‐feedstock. Policy makers are also looking to boost recycling rates throughtaxes, subsidies, landfill regulations and charges, and international treaties (Table 7.5).

Table 7.5 ⊳RegionSelected recent policies addressing consumption andrecycling of plastics

Policy name

Description

Year

Global pledges and treaties
UnitedNations

End Plastic Pollution:
Towards an international
legally binding
instrument

Establishes an Intergovernmental Negotiating
Committee to develop an international legallybinding instrument on plastic pollution, includingin the marine environment.

Announced
March 2022,
targetingend‐2024

G7 andbeyondOcean Plastics Charter

Sets goals on plastics related to product design,
recycling, education and innovation, which havebeen endorsed by multiple countries andcompanies.

Launched in
2018

Bans
China

Law of the People’s
Prohibits and restricts the production, sale and use
Republic of China on the of non‐degradable plastic bags and other
Prevention and Control
disposable plastic products.
of Environmental
Pollution by Solid Wastes

In force since
September
2020

India

Plastic Waste
Management
Amendment Rules

Prohibits the manufacture, import, stocking,distribution, sale and use of identified single‐use
plastic items, including cutlery, foodservice ware,stirrers, plastic flags, candy sticks, etc.

In force since
July 2022

European
Union

Directive on single‐use
plastics

Prohibits certain single‐use plastics (cotton bud
sticks, cutlery, plates, straws, stirrers, sticks forballoons and some food and beverage containers)
and limits the use of others.

In force since
July 2021

CanadaSingle‐use plastics
prohibition regulations

Prohibits the manufacture, import, sale and exportof six categories of single‐use plastics: checkoutbags, cutlery, foodservice ware made from orcontaining problematic plastics, ring carriers,
stirrers and straws.

In force instages from
December
2022 toJune 2026

Targets a plastic packaging recycling rate of 50% by
2025 and 55% by 2030.

Announced
20187

Recycling targets
European
Union

Packaging Directive

Japan

Advanced plastic
recycling in National
Budget 2021

USD 55 million allocated to support thedevelopment of advanced plastic recycling
equipment.

Announced
2021

UnitedStatesDepartment of Energy
R&D funding for plastics

USD 13.4 million awarded in R&D funding to sevenprojects for next‐generation plastic technologies.
Aims include more upcycling of recycled plastics
and the development of new plastics that are morerecyclable and biodegradable.

Announced
2022

DenmarkInnovation Fund Green
Mission: Circular
economy with focus onplastics and textiles

Co‐financing in research and innovation related toreuse, recycling and reduced consumption ofplastics.

Call forfunding in
2022

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Investment in recycling of plastics

Figure 7.11 ⊳ Oil use in the chemical sector by scenario

mb/d

2030

2050

20

60%

15

45%

10

30%

5

15%

Plastics

2021
STEPS APS NZEOther petrochemicals Process energy

STEPS APS NZEPlastics recycling collection rate (right axis)
IEA. CC BY 4.0.

Oil use as petrochemical feedstock falls in the NZE Scenario due to alternative feedstocks
and more recycling, but still accounts for more than half of global oil demand in 2050

In the STEPS, policies to scale up recycling, limit single‐use plastics, and invest in waste
management and recycling facilities result in an increase in recycling collection rates from
17% in 2021, to 20% in 2030 and 27% in 2050 (Figure 7.11). This is not enough tocounterbalance the strong growth in demand for primary plastics; oil use as a petrochemical
feedstock for plastics rises by 3 mb/d between 2021 and 2050.
In the APS, there is a much stronger push for recycling of plastics in fulfilment of countries’
net zero emissions pledges, and the global average recycling collection rate increases to 25%
in 2030 and 50% in 2050. Demand for oil as a petrochemical feedstock to produce plastics
nonetheless rises by around 0.5 mb/d between 2021 and 2050.

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In the NZE Scenario, the global average recycling collection rate increases to 26% in 2030 and
54% in 2050; oil use as a petrochemical feedstock falls by 1 mb/d between 2021 and 2050.
Total oil use in the chemical sector, including oil that is currently used for process energy,
falls by just over 20% between 2021 and 2050. This is a much shallower decline than in allother sectors: oil use in passenger cars falls by 98% over this period, for example. As a result,the chemical sector ends up accounting for more than half of global oil demand in the NZE
Scenario in 2050.

Box 7.2 ⊳What’s the sustainable choice for packaging drinks?

Most drinks come in plastic bottles, aluminium cans, paper‐based packaging or glass
bottles. We explore here how the different options compare on the basis of a life cycle
assessment of energy and emissions of each of these options in the European Union(Samuel Schlecht, 2020) (Carmen Ferrara, 2021).
In the absence of recycling, the answers are fairly simple. Paper‐based packaging andplastic bottles require about 3‐4 MJ/litre and are the least energy‐intensive tomanufacture (Figure 7.12); glass bottles are next, requiring about 70% more energy to
produce; and aluminium cans require the highest amount of energy to produce. The
associated CO2 emissions follow the same hierarchy, but vary depending on the balanceof fuels and electricity used in each process as well as on the location of the
manufacturing facilities. The production of aluminium, for example, is electricity‐
intensive. A can produced in France generates less than half of the emissions of a can
produced in Poland because of the different emissions intensity of electricity in eachcountry.
Figure 7.12 ⊳ Energy content of various packaging types in the

7

MJ/L

European Union
8

Aluminium

Plastic

Paper

Glass

6
4
2

No
RecyclingNo
RecyclingNo
RecyclingNo
Recycling Reuse
Recycling
Recycling
Recycling
Recycling
Fossil fuelsElectricity and heat

Renewables
IEA. CC BY 4.0.

Plastic bottles and paper-based packaging options use 35-75% lessenergy per litre of packaged drink than aluminium cans and glass bottles

Introducing recycling and reuse makes comparisons much more complex. Aluminium is
one of the most recycled of all materials worldwide. Using recycled aluminium brings
down the energy required to produce a new can by around one‐quarter. Glass bottles
can be recycled, which requires around 15% less energy than making a new one, orChapter 7 | Outlook for liquid fuels351

IEA. CC BY 4.0.

Notes: MJ/L = megajoule per litre; reuse is the energy required to transport, wash, sterilise and dry an
existing glass bottle.

reused, which requires less than half the energy of making a new bottle. Our analysis
indicates that reusing a glass bottle five times requires less energy than producing five
new plastic bottles, while reusing a glass bottle ten times requires less energy than
producing paper‐based packaging for ten drinks.
Price naturally plays a significant role in determining the choices made by manufacturers
and consumers. Plastics bottles are four‐ to five‐times cheaper than glass bottles andthey retain a cost advantage even with reuse schemes. Many glass reuse schemes havedeclined or been discontinued for this reason. Taxes or incentives to reduce plastic use
and pollution could help reverse this trend. A push for more glass reuse schemes in
Europe or a single scheme across Europe, aided by broader standardisation in bottle
design, would also improve resource use and cut waste. This would need to be combinedwith efforts involving retailers and consumer groups to increase the use of reusablebottles and their return.

7.9 Are new conventional oil projects an answer to today’s energy crisis?
In recent years, oil supply has increased relatively quickly when market conditions havewarranted, largely because of the ability of US tight oil production to ramp up relatively fast,
as well as the existence of OPEC spare capacity – the traditional buffer for the oil market. Butquestions are now being asked about whether recent trends for these avenues will prove agood guide to the future. Tight oil operators are now more focussed on returns than near‐term production growth, and oil field service providers are hesitant to reinvest in tight oil
supply chains. Many members of OPEC are struggling to increase production, and some of
the notional OPEC spare capacity buffer is also subject to political constraints.
Here we look at what combination of factors could fill any gap between supply and demandand help the global oil market to stay in balance. We find that the long lead time of
conventional projects and the depleted existing pipeline of potential projects mean that new
conventional projects are unlikely to provide large‐scale relief to the immediate energy crisis.
Looking beyond the next few years, the need for new conventional projects to balance themarket is contingent on the demand outlook, which varies widely by scenario. In the STEPS,
the combination of underlying declines in existing sources of production and rising demandmeans new conventional projects are needed to ensure a smooth match between supply anddemand. In the APS, demand is lower and there is less need for new conventional projects.
In the NZE Scenario, declining fossil fuel demand can be met through continued investment
in existing production assets without any need for new long lead time oil fields.

The development of a typical new conventional upstream oil project occurs in a number ofstages. A host country or land owner first announces an intention to allow companies to bid
for exploration licences. An interested company (or group of companies) conducts
subsurface studies and chooses whether to bid for a licence. After an exploration licence is352

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Lead times for conventional projects

awarded, the licence holder has to secure further regulatory approvals before exploration
activities can take place. If resources are discovered, additional analysis is conducted todecide whether the resources can be produced economically and how best to develop the
project. After securing regulatory approval for development, a final investment decision (FID)
is taken to develop the project. 5 Physical development work commences and later the
project starts producing. Most conventional projects increase production gradually from thispoint. Production eventually peaks and starts to decline.
Figure 7.13 ⊳ Years needed to discover, approve and develop newYearsconventional upstream oil projects since 2010
12

Offshore

10

Onshore

8
6

7

4
2

Exploration award
to discovery

Discovery to approval

Approval to start‐up
IEA. CC BY 4.0.

It takes around 20 years on average from the granting of an exploration
licence for a new conventional project to begin production
Note: Includes projects awarded exploration licences since 1980 that started production between 2010‐20,
weighted by technically recoverable resources.
Source: IEA analysis based on Rystad Energy data.

5

The point at which a project undergoes its FID is also known as the project “receiving development approval”.

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The time required to develop a new conventional oil project can vary substantially anddepends on factors such as regulatory oversight and management, political stability,
subsurface complexity and whether new facilities and export connections need to beconstructed. For conventional upstream projects that have started production since 2010, it
took on average around six years from the award of an exploration licence to discovery; nine
years from discovery to project approval; and just over four years from approval to first
production (Figure 7.13). It then took a further three to five years for projects to ramp up to
their maximum level of production after they started producing. Companies have recently
tried to focus on projects that can be brought to market relatively quickly. For example,

offshore projects that started operation since 2019 have taken less than five years to go fromapproval to start up compared with eight years for similar projects that started up in 2016.
Since the oil price crash in 2014, exploration activity and levels of discoveries have been at
historic lows, and relatively few conventional oil projects are now available to be developed(Figure 7.14). Any already‐discovered resources that are approved for development could
bring some oil to the market within the next few years, but they are unlikely to make an
immediate major contribution to the global oil balance. Resources that have not yet been
discovered are unlikely to make a meaningful contribution to alleviating the current energy
crisis.
Figure 7.14 ⊳ Annual average resources discovered, approved forBillion barrels

development and consumed since 1970
40
30
20
10

1970‐ 1975‐ 1980‐ 1985‐ 1990‐ 1995‐ 2000‐ 2005‐ 2010‐ 2015‐ 2020‐
74
79
84
89
94
99
04
09
14
19
21
Discovered

Approved

Consumption
IEA. CC BY 4.0.

Resource discoveries and new approvals have been at historic lows in recent years
and the pipeline of projects available to be developed is now small

Tight oil and OPEC spare capacity

In the STEPS, US tight oil production increases by around 3 mb/d over the next five years andannual average investment is around USD 65 billion, which is broadly similar to investment
levels between 2015 and 2020. If prices were to be higher than in the STEPS or operators
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Tight oil has been a key source of new production in recent years, and it met around 85% of
the overall increase in global oil supply between 2015 and 2019. It can take as little as threemonths for a tight oil operator to move from securing development approval to the start ofproduction and tight oil wells produce around 80% of their cumulative production in the firsttwo years of production (compared with less than 10% for conventional wells). However,annual production dipped in 2020 and only rose slightly in 2021 as operators focussed on
profitability and capital discipline rather than production growth (Figure 7.15).

were to focus more on growth, this could lead to a higher level of spending. Without someeasing of current tight supply chains, however, any such increases in activity could
exacerbate the cost inflation currently being experienced by the industry in the UnitedStates. 6 If annual investment were to average USD 100 billion over the period to 2030 –which would be the highest annual level of investment seen in recent years – we estimatethat US tight oil production could increase by around 5 mb/d to 2030.
Figure 7.15 ⊳ US tight oil production at different levels of investment

mb/d

Production

Production increase from 2021‐2030

15

6

10

4

5

2

7
2015

2020

2025

2030

Annual level of investment in tight oil (2022‐2030):
USD 65 billion (STEPS)USD 80 billion

USD 90 billion

USD 100 billion
IEA. CC BY 4.0.

Increases in tight oil will be essential to balance demand to 2030: higher investment levels
than in the STEPS could lead to more growth, but risks exacerbating cost inflation
Notes: Includes tight crude oil and tight condensate volumes.

Tight oil in other countries also has some scope for growth, but it is limited in scale. Canadianshale plays are generally more suited to natural gas than oil production, though the sector
could scale up oil production from plays such as the Duvernay‐Montney. Argentina also has
scope to increase tight oil output: in the STEPS, its production rises by just under 150 kb/d
within the next five years. Tight oil resources also exist in a number of other countries,
including Saudi Arabia, United Arab Emirates and China, but new production from thesecountries is unlikely to contribute meaningful volumes in the immediate future.

6
Costs for tight oil production increased by around 15% between 2019 and 2022, mainly because of increases
in steel, steel products, aluminium and other raw materials prices (IEA, 2022b).

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OPEC has sustainable crude oil production capacity of around 34 mb/d and produced
28.5 mb/d in the first half of 2022 (a utilisation rate of 84%). Production by OPEC has notexceeded 94% of its capacity since 2000, and a number of countries might struggle toproduce as much oil as they are supposed to be capable of delivering (nameplate capacity).
In addition, political unrest in Libya and long‐term sanctions on Venezuela and Iran haveseverely impacted the ability of those countries to maintain production levels over the last
decade. It might therefore be a struggle for members of OPEC to produce considerably morethan current volumes.

How much new oil supply is needed?
In assessing future supply needs, a key consideration is the level of projected decline inproduction from existing sources of supply. As fields mature and projects reach the end of
their lives, existing sources of oil supply are expected to decline by around 18 mb/d to 2030.
Some of this drop is likely to be offset by conventional projects approved for development
in recent years, including in Brazil, Saudi Arabia and United States, and these are set toprovide around 6 mb/d of new production by 2030. Some increases in NGLs are also likely asa result of changes in natural gas production.
Figure 7.16 ⊳ Contribution of increased production of tight oil and NGLs,
and new and approved projects in the STEPS and APS
STEPS

mb/d

110

APS

100
90
80
70
2015

2020

Increased production
Tight oil
NGLs

2025

2030 2015

Projects
Already approved
New approvals

2020

2025

2030

DemandDeclines from existing
IEA. CC BY 4.0.

Although tight oil is set to grow strongly, declining output from existing sources of
production means new conventional projects are essential in both the STEPS and APS

The trajectory of oil demand is the final element in determining new supply needs. In the
STEPS, oil demand rises by 8 mb/d to 2030. Without new long lead time conventional
projects, this would mean a major shortfall in supply from the mid‐2020s (Figure 7.16). In the
APS, global demand peaks in the near future and starts to decline. Conventional upstream
projects remain essential to ensure a smooth match between supply and demand: without
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Note: Already approved = fields that have received an FID, but were not producing at the beginning of 2022.

them, a significant shortfall in supply would emerge by the late‐2020s. In the NZE Scenario,
demand falls by nearly 20 mb/d to 2030 and no new conventional oil projects need to beapproved for development (Table 7.6).
Table 7.6 ⊳Average annual upstream oil investment by scenario
STEPS

APS

NZE

2021

2022‐302031‐502022‐302031‐502022‐302031‐50

Existing fields

142

216

191

212

137

243

120

New fields

94

189

171

117

62

18

0

Tight oil

70

62

50

53

25

42

5

Total

305

466

411

382

225

302

126

Notes: New fields include fields that have received an FID but were not producing at the beginning of 2022,
and new approvals.

New long lead time and long‐lived conventional projects still carry a number of risks, even if
they are needed in the STEPS and APS. They could lock in fossil fuel use that would preventthe world from meeting its climate goals or they could fail to recover their upfront
development costs if the world is successful at bringing down demand quickly enough toreach net zero emissions by mid‐century. Governments and developers can mitigate someof these risks by ensuring that new projects result in as few direct emissions as possible, forexample by ensuring there are no methane leaks, that there is no flaring, that low‐emissions
options are used to power operations, and that new project developments are linked to
CCUS.

7

7.10 Refining: immediate and longer term challenges
Immediate challenges: Tightness in product markets and reduced Russian exports
A strong rebound in oil consumption in 2021 following the global Covid pandemic coincidedwith the first net reduction in capacity in 30 years in the refining sector. New capacity wasadded in China and the Middle East, but this was surpassed by 1.8 mb/d of capacity
retirements. There have also been reduced product exports from Russia and China. Refining
margins have surged to record highs in the wake of these developments.

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Two other important developments are currently in train. First, oil product exports from
Russia, which decreased by 600 kb/d between February and June 2022 as a result of
sanctions, are set to decline further when the recently agreed European Union import ban
comes into force in 2023. Russia does not play a significant role in gasoline and kerosene
markets but it is currently one of the largest exporters of diesel, naphtha, fuel oil, andrefinery feedstocks. Second, China has set an explicit goal of phasing out refined productexports by 2025 to reduce emissions from the refining sector. Chinese refined productexports so far in 2022 are 45% below pre‐pandemic levels.

Figure 7.17 ⊳ Regional refining margins and crack spreads by product

40
20
0

Crack spreads by product
USGC medium
sour cracking
Singapore
medium sourcracking
NWE light
sweet
cracking

USD/barrel

USD/barrel

Regional refining margins
60

60
40

Diesel
JetKero20

Gasoline

0

‐ 20

‐ 20

‐ 40
Jan‐2015‐ 40
Jan‐2021

Jul‐2022

NaphthaHSFO
Jul‐2022
IEA. CC BY 4.0.

A strong rebound in demand and a reduction in global refining capacity contributed to therecent extraordinary rise in refining margins and crack spreads for transport fuels
Notes: USGC = US Gulf Coast; NWE = northwest Europe. JetKero = jet kerosene; HSFO = high sulphur fuel oil.
Product crack spreads are based on northwest Europe indices.

Together with much lower inventories, these factors have combined to create a very tightmarket. Oil product differentials have risen to record highs across premium transport fuelssuch as diesel, gasoline and kerosene (naphtha and high sulphur fuel oil have not exhibitedthe same trends due to weak industrial growth) (Figure 7.17). Product crack spreads fellslightly in July 2022, but they still remain much higher than in the past, especially for middle
distillates such as diesel and kerosene.
As things stand, there are few supply‐side measures that could tackle the immediatetightness in product markets. One option would be to bring back mothballed refining
capacity located in the Atlantic Basin, but this would require major financial commitments
and a significant amount of time for repair work. Supply‐side tensions may start easing in
2023 as new refineries in Mexico and Nigeria come online7 and expansion projects in the
United States and the Middle East are completed. However, with reduced Chinese andRussian product exports, the global refining system is likely to remain tight for several years
to come if middle distillates demand (diesel and kerosene) keeps rising at the current rapid
rate.

7

Mexico and Nigeria have also initiated rehabilitation programmes to restart mothballed refining assets andincrease utilisation rates, although securing financing remains a major hurdle.

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In the STEPS, middle distillates demand (excluding biodiesel, renewable fuels, coal‐to‐liquids
and gas‐to‐liquids) increases by 2.6 mb/d between 2022 and 2025. Without yield
adjustments, this would require more than 6 mb/d of refinery throughput growth (onaverage, one barrel of incremental refinery throughput can produce up to 0.3‐0.5 barrels of
middle distillates). This compares with a likely net capacity increase of 4.2 mb/d over the
next three years. Refineries that are currently operating have largely maximised theircapacity utilisation, implying that refinery processing may lag behind demand growth. Thereis some flexibility in the refining system to shift yields from other products to diesel andkerosene as gasoline demand flattens but this may not be enough to plug the remaining gap
in middle distillates supply. This brings into sharp focus the importance of demand‐sidemeasures to ease product supply tensions.
In the APS, strong policy measures to reduce the use of diesel and kerosene and to revamp
idled capacity bring about a significant reduction of the tightness in the middle distillate
market (Figure 7.18).
Figure 7.18 ⊳ Expected refining throughput growth and required throughput

mb/dincrease to meet middle distillate demand, 2022-20258

Required in APS
Required in STEPS

7

6
Potential restarts
Planned4

2

Throughput
increase

STEPS

APS
IEA. CC BY 4.0.

Reductions in demand for middle distillates are needed toease product supply tensions in the coming years
Note: Projected capacity and throughput increase do not include additional yield adjustments. Refineries are
assumed to yield 42% of middle distillates.

Russia accounted for around 12% of global crude oil and 15% of oil products trade in 2021.
Since the invasion, oil markets have had to deal with major changes to global crude oil andproduct flows in a very short period of time. The United States, Canada, Australia and the
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The effects of sanctions and embargoes on Russian oil trade flows are a key variable that
could affect global oil markets in the coming years. Even before Russia’s invasion of Ukraine,
global oil markets were in a highly volatile phase. Inventories were low after draws since thesecond‐half of 2020, and capacity constraints in the refining sector magnified the impact of
supply‐demand fundamentals on product prices.

United Kingdom announced plans to ban imports of crude oil and certain oil products from
Russia. The European Union, which last year took 35% of its net oil imports from Russia, hasalso imposed a ban, but has allowed for a six‐month phase‐in period for crude oil (expiringin December 2022) and eight months for oil products imports (expiring in February 2023).
Crude oil imports into Hungary, Slovakia and the Czech Republic via the Druzhba pipeline,
seaborne crude oil imports into Bulgaria and refinery feedstock imports into Croatia were
given exceptions. These account for 10% of pre‐sanction import volumes from Russia. The
European Union is also in the process of banning maritime insurance for vessels transporting
Russian oil to third countries.
Despite the sanctions already in place, and a fall in Russian exports to the European Union inadvance of sanctions there coming into effect, overall Russian crude oil export volumes have
not yet dropped significantly. This points to a reallocation of trade flows. Between Februaryand August 2022, India increased Russian crude oil purchases from 0.1 mb/d to 1 mb/d andChina increased imports of Russian oil from about 1.6 mb/d to close to 2 mb/d. Given that
their combined crude oil import requirements amount to 15 mb/d, there is further scope forboth India and China to increase imports of Russian crude oil if they choose to do so. Whether
India and China will choose to continue to do so depends on several factors, including
geopolitical considerations. Smaller Asian importers may also choose to import some Russiancrude oil. A complete cessation of Russian crude oil imports by the European Union would
mean that it needs to find around 1.6 mb/d of crude oil from alternative sources in addition
to volumes that have already been replaced.

The ban on maritime insurance could also have a major impact on oil products trade. Most
maritime trade insurers and reinsurers are domiciled in the European Union, so the ban couldin effect prevent Russian cargo carriers from obtaining insurance. In the past, China and India
have provided sovereign insurance for other sanctioned crude oil imports, notably of Iranianoil. However, there are unlikely to be other counterparties in products trade with the samelevel of financial and operational strength as China and India. If the ban causes the cessationof Russian seaborne oil product exports, this could further strain global product markets.
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Any reallocation of trade in oil products is likely to be more challenging than for crude oil,
not least because oil products trade involves complex operations including storage andblending. No meaningful geographical reallocation of oil product flows has yet taken place.
China and India are both oil product exporters and therefore are unlikely to be interested in
Russian product imports, while many smaller product importers are likely to find it difficult
to negotiate, finance and manage the logistics of long‐distance products trade. Russia wasalso undertaking a refinery modernisation programme to increase yields of gasoline anddiesel, but this could see significant delays as sanctions on the provision of refinery
technology, catalysts and maintenance services come into effect. Meanwhile the European
Union will need to ramp up purchases from alternative providers when its ban on Russian
product imports comes into force, and it is likely to turn to the United States, the Middle Eastand India for these purchases. This will reduce oil product flows to Latin America and Africa
and potentially redirect Russian volumes towards these regions.

Western governments are currently considering whether to relax the maritime insurance banfor Russian oil as long as the deals are concluded under a price cap mechanism that aims tocurb Russian revenues while allowing oil to flow to international markets.

Longer term challenges: Adapting business models in a decarbonising world
Table 7.7 ⊳World liquids demand by scenario (mb/d)
STEPS

APS

2020

2021

2030

2040

2050

2030

2040

2050

Total liquids

90.9

96.7

105.8

107.5

107.6

98.7

82.8

69.6

Biofuels

2.0

2.2

3.4

4.6

5.3

5.5

8.7

9.2

Low‐emissions hydrogen‐based fuels

0.0

0.0

0.0

0.1

0.2

0.2

1.2

3.2

Total oil

88.9

94.5

102.4

102.8

102.1

93.0

72.9

57.2

CTL, GTL and additives

0.8

0.9

1.1

1.3

1.3

1.0

0.7

0.3

Direct use of crude oil

1.0

0.8

0.5

0.4

0.3

0.4

0.3

0.2

Oil products

87.1

92.8

100.8

101.1

100.5

91.6

71.9

56.7

LPG and ethane

13.3

13.6

15.6

16.2

15.8

14.4

12.4

10.4

Naphtha

6.4

6.9

7.7

8.6

9.5

7.3

7.4

7.4

Gasoline

21.9

23.6

23.2

21.4

19.3

20.6

13.1

8.2

Kerosene

4.7

5.7

9.2

10.3

11.8

8.7

8.0

7.6

Diesel

25.0

26.5

28.2

28.4

28.2

25.0

18.3

12.6

Fuel oil

5.7

5.9

5.5

5.6

6.3

4.8

3.4

2.5

Other products

10.1

10.6

11.4

10.6

9.6

10.8

9.3

8.0

Fractionated products from NGLs

11.3

11.5

13.4

12.1

11.6

12.7

10.1

8.8

Refinery products

75.8

81.3

87.4

89.0

88.9

78.9

61.8

47.9

Refinery market share

83%

84%

83%

83%

83%

80%

75%

69%

7

Notes: CTL = coal‐to‐liquids; GTL = gas‐to‐liquids; NGLs = natural gas liquids; LPG = liquefied petroleum gas.
See Annex C for definitions.

American and European refineries have recently been operating at high utilisation rates andaccounted for 45% of the growth in refinery throughput between 2020 and 2022. In the APS
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While the refining sector has seen record margins and high utilisation rates in 2022, recent
trends may not be a good guide to the future. Gasoline, diesel and kerosene accounted foraround three‐quarters of total oil demand growth between 2020 and 2022 as economies
recovered from the Covid‐19 pandemic, while demand for petrochemical feedstocks
remained subdued. However, the APS and the NZE Scenario see major changes in thecomposition of oil product demand in the years ahead, and these require refiners to adapt
their configuration and business models (Table 7.7). The share of petrochemical feedstocks
such as ethane, LPG and naphtha rises from around 20% of total oil demand today to 30% in
2050 in the APS and to 55% in the NZE Scenario. The share of middle distillates remains
around the current level in the APS and halves to 15% by 2050 in the NZE Scenario aselectrification and alternative fuels are increasingly adopted in trucks, ships and planes. The
share of gasoline falls in both scenarios.

and NZE Scenario, however, they lose market share to new refiners in developing economies
in Asia and the Middle East. The share of the global refining market accounted for bytraditional refining centres (North America, Europe and advanced economies in Asia) shrinks
from over 40% today to around 30% by 2050 in the APS and to a quarter in the NZE Scenario(Table 7.8).
Table 7.8 ⊳Refining capacity and runs by region and scenario (mb/d)
Refining capacity
STEPS

Refinery runs
APS

STEPS

APS

2021

2030

2050

2030

2050

2021

2030

2050

2030

2050

North America

21.6

21.1

20.8

20.1

11.1

17.6

18.5

18.1

16.5

7.5

Europe

15.8

14.5

13.3

14.0

6.9

12.0

11.4

9.4

10.2

3.9

Asia Pacific

37.1

40.3

41.5

39.4

28.3

29.2

33.1

34.7

30.5

18.9

Japan and Korea

6.9

6.3

5.8

6.2

3.5

5.2

5.0

4.6

4.6

2.2

China

17.5

19.0

19.0

18.5

11.1

14.2

14.5

14.1

13.4

6.4

India

5.3

6.6

7.8

6.4

5.4

4.8

6.4

7.6

5.7

4.0

Southeast Asia

5.3

6.3

6.8

6.3

6.3

3.7

5.5

6.4

5.1

4.7

Middle East

9.6

11.2

12.0

11.0

9.7

7.6

9.6

10.6

8.5

6.6

Russia

6.9

6.5

6.3

6.1

4.6

5.6

4.0

3.5

3.6

2.4

Africa

3.4

4.5

4.8

4.2

4.2

1.8

3.1

3.9

2.7

2.6

Brazil

2.2

2.3

2.3

2.0

1.6

1.8

2.1

2.2

1.7

1.2

Other

4.6

4.8

4.8

4.7

4.2

2.3

2.9

3.5

2.8

2.6

World

101.2

105.2

105.8

101.5

70.6

77.9

84.7

85.9

76.5

45.7

Atlantic Basin

54.1

53.6

52.2

51.0

32.5

40.9

41.9

40.4

37.3

20.1

East of Suez

47.1

51.6

53.6

50.5

38.1

37.0

42.9

45.5

39.1

25.6

Note: Capacity at risk can be found in the online Annex.

Many refiners are looking to expand into liquid biofuels, plastic recycling and low‐emissionshydrogen to secure new revenue streams. Some refiners have also been actively
participating in the production of renewable diesel through co‐processing, facility conversion
or building new facilities. Traditional refiners, such as TotalEnergies, Eni, Neste and Valero,currently own the majority of operating capacity for renewable diesel, and they also accountfor a sizeable share of planned capacity (Figure 7.19). This is the case for sustainable aviation
fuels as well, although there are now a growing number of dedicated producers. The interest
shown by refiners in producing these fuels has been driven by policy measures, including the
EU Renewable Energy Directive and the US Blenders Tax Credit, and by the lower capitalrequirements involved. For example, TotalEnergies is now converting its Grandpuits refinery
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Despite today’s scramble for oil products, the APS and the NZE Scenario imply longer termpressures for refiners. In the APS, more than half of current refining capacity faces the risk oflower utilisation or closure by 2050, and there are few new capacity additions after projects
under construction come online. Those refiners that survive invest to reduce emissions fromrefining operations, notably via low‐emissions hydrogen, CCUS and efficiency improvements.

in France to a bio‐refinery because this requires less capital than would be needed tomaintain and repair the existing facility. There is also growing interest in chemical plastic
recycling and waste‐to‐feedstock technologies. For example, OMV took a final investment
decision at the end of 2021 to expand its pilot plastic waste‐to‐crude recycling plant at its
Schwechat refinery in Austria.
Figure 7.19 ⊳ Operating and planned production capacity for renewablebiodiesel and biojet fuels by company type

Billion litres per year

Renewable diesel

Biojet30

Others
Dedicated biofuel
producers

20

Refiners
10

7Operating Planned
capacity projects

Operating Planned
capacity projects
IEA. CC BY 4.0.

Refiners are increasingly expanding into the biofuels supply chain, representing around
80% of today’s production capacity and over half of planned renewable diesel projects

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Today, most investment by refiners is for maintenance, upgrades and expansion into thechemical sector. In the APS and the NZE Scenario, however, emissions reductions, hydrogen,biofuels and plastic recycling account for an increasing share of overall investment. The
feedstock landscape is also likely to be more diverse, as an exclusive focus on crude oil
widens to encompass biomass and wastes. Looking beyond immediate market conditions,
there are growing signs that refiners are going to have to redefine their business model
before too long.

Chapter 8
Outlook for gaseous fuels
Is natural gas losing steam?
S U M M A R Y
 The traditional arguments in favour of natural gas have focused on its role as a reliable
partner for the clean energy transition and its ability to step in to fill the gap left by
declining coal and oil. These are currently being tested by the global repercussions of
Russia’s actions in Europe. In the midst of a global energy crisis, fundamental
questions are now being asked about natural gas: how can supply be assured, now
and in the future, and at what price?

 The depth and intensity of today’s crisis have led to concerns about the future costand availability of natural gas which have damaged confidence in its reliability and put
a major dent in the idea of it serving as a transition fuel. As a result, the era of rapid
global growth in natural gas demand is drawing to a close. In the Stated Policies
Scenario (STEPS), demand rises by less than 5% between 2021 and 2030, comparedwith a 20% rise between 2011 and 2020. It then remains flat from 2030 at around
4 400 billion cubic metres (bcm) through to 2050, with growth in emerging market
and developing economies offset by declines in advanced economies. In the
Announced Pledges Scenario (APS), demand soon peaks and is 10% lower than 2021
levels by 2030. In the Net Zero Emissions by 2050 (NZE) Scenario, demand falls by 20%
to 2030, and is 75% lower than today by 2050.

 Global natural gas demand in 2050 in this year’s version of the STEPS is 750 bcm lower
than projected in last year’s version. Half of this downward revision comes from more
rapid moves away from unabated natural gas consumption in advanced economies.
The United States alone accounts for one‐third of the total downward revision: its
recent Inflation Reduction Act is set to speed up the deployment of renewables in the
power sector and to provide stronger support for efficiency and heat pumps inbuildings. The other major downward revision comes from price‐sensitive emerging
market and developing economies, where high natural gas prices mean that prospects
for coal‐to‐gas switching are now more muted.

 Russian pipeline gas exports to the European Union more than halved over the lastyear to an estimated total of 60 bcm in 2022. They decline by an additional 45 bcm in
the STEPS by 2030, and fall to zero in the APS. Additional liquefied natural gas (LNG)
and non‐Russian pipeline gas play important roles in making up the shortfall in bothscenarios, but the APS sees a stronger surge in wind and solar capacity additions anda bigger push to retrofit buildings and install heat pumps: these help to bring EU
natural gas demand down by 40%, or 180 bcm, between 2021 and 2030. The annual
investment cost of USD 65 billion is offset over time by lower gas import costs.
projects mean that natural gas prices in importing regions remain high over the next
few years in the STEPS and APS, especially in Europe. In the NZE Scenario, rapid
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 Europe’s drive to reduce reliance on Russian imports and a dearth of new gas exportdemand reductions in all regions ease the strains on global supplies, and gas importprices fall quickly. Prices come down more gradually in the STEPS and APS from themid‐2020s as gas demand flattens and new supply projects currently underconstruction come onstream. Declines in domestic demand in the United States open
opportunities for higher LNG exports; in both the STEPS and APS, the United Statessoon overtakes Russia to become the world’s largest natural gas exporter.

 Natural gas demand growth in China slows considerably in the STEPS, falling to 2% peryear between 2021 and 2030, compared with an average growth rate of 12% per year
between 2010 and 2021. Large volumes of LNG have been contracted for the next
fifteen years: together with expected supply from existing pipelines and new domestic
projects, these more than cover China’s demand requirements in the STEPS to 2035.

 High gas prices have dampened prospects for coal‐to‐gas switching, but they have notextinguished them. In emerging and developing markets in Asia, long‐term gas importcontracts with prices indexed to oil offer partial protection to consumers from highand volatile gas prices, and in some cases this is buttressed by domestic subsidies. A
growing population and robust economic development provide a strong foundation
for growth: gas demand in the APS in these emerging markets in Asia rises by 20% to
120 bcm in 2030. Around 70% of this growth is met by imported LNG.

 Rising natural gas demand in parts of Asia alongside European Union efforts to importnon‐Russian gas underpin LNG demand growth in all scenarios until the mid‐2020s,
but there are sharp divergences thereafter. In the STEPS, an additional 240 bcm per
year of export capacity is needed by 2050 over and above projects already underconstruction. In the APS, only projects currently under construction are required. In
the NZE Scenario, a sharp decrease in natural gas demand globally means that eventhese projects are in many cases no longer necessary. This highlights a key dilemma
for investors considering large, capital‐intensive LNG projects: how to reconcile strong
near‐term demand growth with uncertain but possibly declining longer term demand.

 There are no easy options for Russia in its search for new markets for the gas it wasexporting to Europe. Sanctions undercut the prospects for large new Russian LNG
projects, and long distances to alternative markets make new pipeline links difficult.
In the APS, Russia’s share of internationally traded gas, which stood at 30% in 2021,
falls by 2030 to less than 15%, and its net income from gas exports (revenue minus
costs) falls from USD 75 billion in 2021 to USD 25 billion in 2030.
production rises from low levels today to over 30 million tonnes (Mt) per year in 2030.
This is equivalent to over 100 bcm of natural gas. The APS also sees a rise inbiomethane production that reflects the ambitious targets now being established.
Governments have a key co‐ordinating role to play in the growth of low‐emissions
gases, in particular in setting standards and ensuring reliable, long‐term demand. At
the moment, the 24 Mt per year of projects seeking to export hydrogen or hydrogen‐based fuels are running ahead of plans for the corresponding import infrastructure.
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 Prospects for low‐emissions gases look bright. In the APS, low‐emissions hydrogen

How will global
natural gas trade evolvein the APS?
Import2021

Export2021

Today’s turbulence in gas markets reshapes
global gas trade. Russia’s exports dwindle and theEuropean Union competes with countries in Asia
for LNG supplies. Demand for LNG in Europe thenfalls steadily as it moves away from gas to meet its
climate goals. Developing Asia is the main
destination for exports in 2050.
Export2030

Import2030

Import2050

European
Union

European
Union

RussiaDeveloping
Japan
Asia
and Korea

Developing
Japan
Asia
and Korea

North
America
MiddleEast

AfricaRest ofworld

Rest ofworld

Rest of
world

830

880

bcm

Natural gas may berunning out of steam…
The era of rapid growth in natural gas demandis drawing to a close, but doors are opening forlow-emissions gases, which get a boost in the APS
and flourish in the NZE scenario.
STEPS

APS

NZE

500

What price tag for
reduced EU dependence
on natural gas?
In the APS, the European Union doubles down on
clean energy, spending USD 65 billion per year tobring natural gas demand down by 60% by 2030.
These investments are offset over time by much
lower gas import costs.
STEPS
Billion USD

2021

2050

120

APS

60
2 680
3 560

4 250
4 660

Biogasesbcm-equivalent
Low-emissions
Natural gashydrogen production
Unabated
With CCUS
With CCUS
Electrolysis and bioenergy
Losses0

2016-212022-30

Gas import costs
RussiaNon-Russia

2031-502022-30

2031-50

Clean energy investment
to reduce natural gas demand
Low-emissions fuels
Efficiency
Electrification
Renewables

Introduction
Global demand for natural gas held up better than demand for other fossil fuels during thefirst year of the Covid‐19 pandemic, and then increased by 5% in 2021, double its average
growth rate over the past decade. A dearth of new projects, weather‐related increases indemand, LNG outages and reduced Russian exports tightened the global gas supply balancefrom mid‐2021 and put upward pressure on prices, especially in Europe where the Title
Transfer Facility (TTF) benchmark rose from less than USD 10 per million British thermal units(MBtu) in the first‐half of 2021 to over 30 USD/MBtu by December 2021.
Russia’s invasion of Ukraine in February 2022 had a huge impact on an already fragile global
gas balance. European Union efforts to fill gas storage ahead of the winter have run up
against Russia’s strategic withholding of gas supply and the prospect of possible supply
shortages bringing high levels of market volatility and exceptionally high prices. Europe’s TTF
benchmark price saw peaks exceeding USD 90/MBtu in 2022, even as the European Unionand its partners debate ways to reduce reliance on Russian gas and curtail its revenue fromenergy sales. The strains on gas supply have also led to energy shortages in several parts ofthe developing world that rely on imported gas, notably Pakistan and Bangladesh. Major
growth markets for gas such as India and China have meanwhile sharply reduced their LNG
imports in 2022.
Amid a scramble to squeeze supply out of existing fields and maximise the use of export andimport facilities, the crisis has prompted policy discussions about reforming gas markets,
better managing supply shortfalls and shielding customers from high and volatile prices. Suchissues inevitably involve consideration of the role of natural gas in energy transitions and thecontractual structures that might accommodate various visions of the future role of gas.
This chapter examines what our scenarios imply for the future of natural gas. All the
scenarios take account of the current gas crisis, while also looking ahead to the longer term.
In the Stated Policies Scenario, natural gas demand grows less than 5% over the remainderof the decade, reaching 4 400 bcm in 2030. In the Announced Pledges Scenario, demandplateaus and drops below 4 000 bcm in 2030. In the Net Zero Emissions by 2050 Scenario,
demand drops rapidly to around 3 300 bcm in 2030.

What now for the natural gas balance in the European Union? What impact will thecurrent crisis have on pipeline and LNG flows, and domestic production in Europe andbeyond?

What are the prospects for hydrogen? Interest in low‐emissions hydrogen is higher thanever, but what needs to happen to get international hydrogen trade up and running?

How long a transition role for natural gas? How has the crisis affected the prospects forgas in emerging market and developing economies in Asia?

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Against the backdrop of these three very different views of the future, this chapter also
examines three key issues that will shape the future not just of natural gas, but all gaseous
fuels:

Scenarios
Overview

Table 8.1 ⊳Global gases by scenario (bcme)
STEPS

APS

NZE

2010

2021

2030

2050

2030

2050

2030

2050

Total gas demand

3 351

4 248

4 456

4 661

4 069

3 568

3 666

2 681

Natural gas demand

3 329

4 213

4 372

4 357

3 874

2 661

3 268

1 159

Power

1 345

1 633

1 590

1 469

1 422

880

1 177

119

Industry

701

882

1 003

1 116

891

644

802

213

Buildings

757

886

890

852

737

372

486

‐

Transport

108

147

159

172

126

58

99

12
566

Low‐emissions H2 production inputs
Other
Natural gas abated with CCUS
Losses from low‐emissions H2 production

‐

1

10

32

41

266

145

417

664

720

717

658

441

559

248

2

12

24

74

103

420

223

738

‐

‐

3

10

13

82

45

175

Natural gas production

3 274

4 149

4 372

4 355

3 878

2 660

3 264

1 178

Conventional gas
Unconventional gas

2 768
506

2 964
1 185

2 962
1 410

3 025
1 329

2 731
1 147

2 016
644

2 292
972

827
351

Natural gas trade

641

878

944

991

833

497

667

224

LNG
Pipeline

275
366

450
428

559
385

649
342

545
288

324
173

443
224

153
71

Low‐emissions H2 demand

‐

1

21

81

100

752

299

1 509

Power

‐

‐

1

2

14

63

91

200

Industry

‐

‐

7

20

36

248

84

451

Buildings

‐

‐

‐

3

6

30

10

40

Transport

‐

‐

2

25

11

158

38

396
395

Input for H2 based fuels

‐

‐

1

11

19

229

60

Other

‐

1

10

20

15

24

16

27

Low‐emissions H2 production

.

1

21

81

100

752

299

1509

Fossil fuel‐based (with CCUS)

‐

1

8

25

29

192

103

406

Electrolytic

‐

‐

13

56

70

557

195

1 097

Bioenergy‐based

‐

‐

‐

‐

1

4

1

7

Biogas demand

22

35

70

244

123

339

199

404

Biogas

21

27

46

102

58

142

59

138

Biomethane

1

8

24

143

65

197

140

267

Notes: bcme = billion cubic metres equivalent; H2 = hydrogen; CCUS = carbon capture, utilisation and storage;
STEPS = Stated Policies Scenario, APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario. Values are reported in bcm equivalent (bcme) accounting for energy per unit of volume of low‐emissions gases. Total gas demand includes the total demand for gaseous fuels by users, including power andother transformation sectors, net of any conversions between different gaseous fuels, such as from natural
gas to low‐emissions hydrogen or low‐emissions hydrogen to synthetic methane. Natural gas use in industry
includes onsite hydrogen production. Production and demand volumes differ due to stock changes andinternational bunkers. World trade reflects net trade between regions modelled in the World Energy Outlook
and therefore excludes intra‐regional trade. Other for natural gas demand includes other non‐energy use,
agriculture and other energy sector. Other for hydrogen demand includes use in refineries, agriculture andbiofuels production. See Annex C for definitions.

Chapter 8 | Outlook for gaseous fuels

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8.1

In the Stated Policies Scenario (STEPS), natural gas demand rises at an average rate of 0.4%
per year between 2021 and 2030, well below the 2.2% average rate of growth seen between
2010 and 2021 (Table 8.1). Demand reaches 4 400 bcm in 2030 and stays at that level to2050. A variety of drivers have led to the downward revision in this year’s STEPS comparedto the World Energy Outlook 2021 (WEO‐2021); the global supply squeeze has led to record
high prices in several gas markets around the world and the balance is not expected to ease
until mid‐decade, when large new LNG exports come onstream. This has dampened
prospects for demand growth in several emerging gas markets in Asia, and accelerates
European efforts to reduce gas demand. There is a faster increase in renewables deployment,a larger uptake of other flexibility options in the power sector, and an acceleration in
efficiency, all boosted in particular by the passage of the Inflation Reduction Act in the UnitedStates. Coupled with a downward adjustment to GDP growth, global gas demand is 750 bcm
lower by 2050 than projected in the WEO‐2021.
In the Announced Pledges Scenario (APS), global natural gas demand soon peaks, and by2030 is nearly 10% lower than it was in 2021. A modest net increase in demand in emerging
market and developing economies between 2021 and 2030 is more than offset by reductionsin advanced economies, where gas is gradually replaced by renewables and offset by
efficiency gains, notably in the buildings sector. The European Union reduces its natural gas
demand by nearly 45% to 2030, easing the task of reducing dependence on Russian imports.
By 2050, global natural gas demand is 40% below 2021 levels. Low‐emissions gases –hydrogen, biogases and synthetic methane – reach more than 1 000 billion cubic metre
equivalent (bcme)1 by 2050, accounting for almost one‐third of total gaseous fuel demand.
In the Net Zero Emissions by 2050 (NZE) Scenario, natural gas demand is over 900 bcm lower
in 2030 than in 2021, a drop of around 20%. By 2050, unabated natural gas meets less than
15% of total demand for gaseous fuels; low‐emissions gases account for over 70% of total
gaseous fuel demand and natural gas used either for non‐combustion purposes or equippedwith carbon capture, utilisation and storage (CCUS) for the remainder. Around 500 bcm ofnatural gas is used with CCUS to produce low‐emissions hydrogen in 2050, providing around
25% of total hydrogen demand (with most of the rest produced from electrolysis).
Inter‐regional natural gas trade increases by 65 bcm in the STEPS between 2021 and 2030, a
rate of growth which is one‐fifth of the levels of the last five years. An average of 20 bcm per
year of new LNG export capacity comes online between 2022 and 2024, well below historicalrates of around 35 bcm per year. LNG imports to the European Union double to over 150 bcm
by 2025, helping to offset a reduction by over 100 bcm of Russian pipeline supply to theEuropean Union. LNG increases by 90 bcm between 2030 and 2050, even as total global gas
demand contracts slightly over the same period. In the APS, global gas trade peaks in themid‐2020s and falls to 470 bcm in 2050, half of 2021 levels. In the NZE Scenario, global gas
trade much peaks sooner, and falls to less than 300 bcm in 2050.
Billion cubic metre equivalent (bcme) represents energy content expressed in standardised units of natural
gas volume. For hydrogen, biogas and biomethane it is calculated from the energy content of these fuels andnot their volume. A conversion factor of 36 petajoules per bcme is used.

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1

PricesIn the STEPS, the weighted average import price of natural gas in the European Union, whichis calculated as a composite of prices reported at major EU gas hubs, e.g. the TTF, nationallyreported import prices and a calculated oil‐indexed reference price, is projected to remain
between USD 20‐30/MBtu to the mid‐2020s. It then gradually falls as more LNG comes online
to ease international gas market tightness; prices settle at USD 8.50/MBtu by 2030. Natural
gas prices in the United States are projected to come down from recent highs as additional
shale gas production comes online. Average prices in importing countries in Asia range
between USD 12‐ 17/MBtu through to 2025, with buyers in northeast Asia partly shieldedfrom higher spot market prices by their use of long‐term gas contracts in which the gas priceis linked to the price of oil (Figure 8.1).
In the APS, robust action to move away from Russian gas exports in line with the Versailles
Declaration means that prices in the European Union are slightly higher to 2025 than in the
STEPS, but sharper reductions in demand bring them below the level in the STEPS before
2030. As the market rebalances, prices in Asia fall to a USD 9‐11/MBtu range.
Figure 8.1 ⊳Natural gas prices by region and scenario

USD/MBtu

United States

European Union

Japan

30

8

25
20
15
10
5
2010

2030

2050 2010
STEPS

2030
APS

2050 2010

2030
NZE

2050
IEA. CC BY 4.0.

The speed at which the natural gas price shock recedes varies by scenario,
and depends in particular on demand levels and LNG supply dynamics

In the NZE Scenario, a sharp drop in natural gas demand globally quickly eases the strains on
global supply, leading to gas import prices falling across the board to around USD 7/MBtu on
average by 2025. Prices in gas‐importing regions subsequently fall further to a floor set by
the short‐run marginal cost of delivering gas from existing export projects, and averagearound USD 5/MBtu by 2030.
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Note: MBtu = million British thermal units; STEPS = Stated Policies Scenario, APS = Announced Pledges
Scenario; NZE = Net Zero Emissions by 2050 Scenario.

8.2

Gas demand

Table 8.2 ⊳Gas demand by region in the STEPS and APS (bcme)
STEPS
2010

2021

2030

North America

835

1 106

United States

678

871

147

BrazilEuropeCentral and South America

European Union
AfricaNorth Africa

APS
2050

2030

2050

1 118

820

933

396

864

575

716

252

161

159

179

141

96

29

42

34

37

28

17

698

625

511

395

394

122

446

421

340

235

242

45

105

172

215

292

189

193

85

132

155

182

137

120

Middle East

391

567

689

833

638

582

Eurasia

578

662

626

635

587

532

Russia

472

543

498

470

470

424

Asia Pacific

576

920

1 043

1 173

983

731

China

110

368

443

442

406

238

India

64

66

115

170

110

102

Japan

95

103

64

43

57

17

Southeast Asia

150

162

203

272

194

177

International bunkers
World natural gas
World low‐emissions gases
World total gases

0

0

11

30

8

8

3 329

4 213

4 372

4 357

3 874

2 661

22

36

91

326

223

1 091

3 351

4 248

4 456

4 661

4 069

3 568

Notes: World natural gas and world low‐emissions gases do not sum to world total gases because natural gas
includes inputs to produce low‐emissions hydrogen and low‐emissions gases includes the hydrogen as an
output. See Annex C for definitions.

Demand trends to 2030

The buildings sector sees falling demand for natural gas in advanced economies across all
the scenarios. In the STEPS, a rapid acceleration in efficiency improvements and broad‐based
adoption of heat pumps reduces natural gas demand by 65 bcm in advanced economies
between 2021 and 2030. In the APS, the rate of decline triples, with gas use in buildings
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The industry sector drives total natural gas demand growth in the STEPS and accounts for
90% of overall growth between 2021 and 2030. However, many industrial sectors are
sensitive to changes in gas prices, and higher equilibrium gas prices contribute to a nearly
30% downward revision to industrial natural gas demand growth between 2021 and 2030
compared to the STEPS projections in the WEO‐2021. Natural gas demand in industry falls by
2% between 2021 and 2030 in the APS and 7% in the NZE Scenario. Around 35 bcm ofcoal‐to‐gas switching props up industry demand in the APS, due to higher carbon prices andpolicy pressure to shift to less polluting technologies.

falling by 170 bcm between 2021 and 2030, or 30% of demand in 2021. These reductions
however are partly offset by increases in emerging market and developing economies.
Globally, natural gas use in the buildings sector stays flat in the STEPS to 2030, declines by
17% in the APS, and falls by 45% in the NZE Scenario.
The power sector sees natural gas demand decline slightly, by about 3%, in the STEPS
between 2021 and 2030. There is a geographical redistribution of demand; in advanced
economies, gas use in the power sector falls over 100 bcm, while in emerging market anddeveloping economies it rises by about 65 bcm. In the APS, faster growth in renewables
means that more natural gas‐fired power plants move from baseload to flexible providers ofelectricity generation, meaning less gas is consumed in the power sector even as additional
capacity is added for flexibility purposes; there is limited coal‐to‐gas switching as demand
shifts directly to renewables or other low‐emissions options. This effect is more pronounced
in the NZE Scenario, where power sector gas demand falls by 450 bcm, or 25% of 2021 levels,by 2030 (Figure 8.2).

bcm

Figure 8.2 ⊳Change in natural gas demand by sector, region and scenario,
2021-2030

500

Sector:Other
Transport
Industry
Power sector inputs
Buildings

0Region:Advanced economies
Emerging market anddeveloping economies‐ 500‐1 0008

Net change
STEPS APS

NZE

STEPS

APS

NZE
IEA. CC BY 4.0.

Gas use in industry is more resilient to increased climate ambition than in buildings and the

The transport sector currently accounts for 3.5% of global natural gas demand, of which
about half, 70 bcm, is for road vehicles. Volatile natural gas markets have dampened thepolicy momentum behind its use as a fuel in road transport (Box 8.1); nonetheless, several
countries are exploring the use of biomethane as a transport fuel. Natural gas use intransport is set to increase by 12 bcm by 2030 in the STEPS, mainly due to increased demandin shipping.

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power sector. Gas demand does not increase in advanced economies in any scenario

Box 8.1 ⊳A fork in the road for compressed natural gas vehicles

Historically, the price advantage of natural gas compared to oil‐based fuels has been themain factor behind rising use of compressed natural gas (CNG) in vehicles, though energy
security and air pollution concerns have also played a part. Today 90% of the CNG fleet
consists of light‐duty vehicles. However, the rising popularity of electric vehicles (EVs),
which are more efficient and more effective at avoiding air pollution, has dampened thepolicy momentum for CNG, leading to a downward revision of over 20 bcm in natural gas
demand for road vehicles by 2030 in the STEPS compared to the WEO‐2021.
In China, the stock of CNG vehicles shrank in 2020 for the first time as incentives for its
use came to an end, while growth in the use of LNG for trucks lost momentum in 2021.
The large CNG fleet in Pakistan has been challenged by natural gas price increases andsupply shortages; the government has responded by banning new CNG filling stations.
Gas‐based vehicles may also fall foul of bans on internal combustion engine vehicles
planned in the European Union as well as in Thailand, unless they are powered bybiomethane rather than natural gas. In the United States, the CNG car market has beenstagnant for nearly a decade despite policy incentives designed to help it.
Figure 8.3 ⊳Natural gas demand in the vehicle fleet related to policy
support in 2019 and the outlook by scenario
Road sector natural gas demandbcm

Million vehicles

CNG vehicles fleet in 2019
20

80

15

60

10

40

5

20

With policy
supportNo or declining
support

Iran India Argentina China Pakistan
Emerging market and developing economies

2021

STEPS APS
2030

Brazil European Union
Advanced economies

Uzbekistan

Other

IEA. CC BY 4.0.

Except in markets with reliable access to ample gas supplies, widespread adoption

Growth, however, is projected to remain strong in those emerging market anddeveloping economies that possess significant natural gas reserves or have access torelatively cheap sources of supply. In Iran – home to 4 million CNG vehicles – supply
infrastructure capacity is struggling to keep pace with the popularity of subsidised CNG.
Russia has also seen CNG demand rise, and it put in place new targets and subsidies in2020 to incentivise the use of natural gas as a transport fuel. CNG vehicle sales in India
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of CNG vehicles is challenged by high prices and the competitiveness of EVs

and parts of South America are still rising thanks to government support, including insome cases for bio‐CNG. Several other countries, such as Egypt, Israel and Nigeria, areplanning CNG support schemes.
In the STEPS, road vehicle gas demand is set to increase by around 10 bcm, to reachalmost 80 bcm by 2030, with India accounting for nearly two‐thirds of the increase(Figure 8.3). In the APS, natural gas consumption in the road sector declines by 6 bcm,
mostly due to a shift towards the use of EVs to help meet net zero emissions targets.
The Middle East stands out for the size of its per capita growth in natural gas consumption
between 2021 and 2030 in the STEPS, of around 130 cubic metres per capita, driven by
growth in the use of gas in power, industry and desalination plants. This offsets a broadly
equivalent decline in gas consumption per capita in Europe, which is driven by a nearly 20%
reduction in gas use in buildings and a 30% reduction in the power sector. Demand in the
Middle East remains relatively resilient in the APS, rising by 70 bcm between 2021 and 2030
compared to 120 bcm in the STEPS.
In the United States – the world’s largest natural gas consumer – there is modest growth innatural gas demand to the mid‐2020s, thereafter demand begins to decline. The Inflation
Reduction Act spurs increased deployment of renewables, improved energy efficiency
measures and cost declines for heat pumps, leaving natural gas demand in the power andbuildings sectors lower by around 45 bcm. Natural gas use in industry and other sectors
increases over the same period, leaving overall demand roughly at the same level in 2030 astoday. In the APS, total natural gas demand falls at a rate of around 2% per year between
2021 and 2030, with gas use in power falling by nearly 90 bcm.

8

In China, natural gas demand in the STEPS increases by 2% per year between 2021 and 2030,
well below the average growth rate of around 12% per year between 2010 and 2021. The
coal‐to‐gas switching which started in the 2010s continues into the 2020s, but at a more
moderate pace. The share of gas in the residential sector rises from 12% in 2021 to 16% by2030, contributing to a reduction in coal use. The majority of industrial demand growth ismet by electricity, but natural gas use in industry still increases by around 35 bcm (comparedwith 75 bcm from 2011 to 2020). In the APS, natural gas demand in China rises less than 1%
per year between 2021 and 2030.

In Southeast Asia, natural gas demand rises in both the STEPS and APS at a rate around 2%
per year, to reach around 200 bcm by 2030. Power generation accounts for more than halfof demand increases while industry accounts for most of the remainder.
Chapter 8 | Outlook for gaseous fuels

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In India, natural gas demand in the STEPS reaches 115 bcm by 2030. Most of the growthcomes from manufacturing and other industry, helped by the expansion of city gas
distribution networks. Gas satisfies less than 5% of the increase in total power generation,
but this is enough to raise demand by 10 bcm. The use of gas in transport, including bothnatural gas and biomethane, increase more than twofold, to reach over 10 bcm by 2030. Gas
demand trends in the APS are broadly similar to those in the STEPS.

Demand trends after 2030
In the STEPS, natural gas demand declines slowly from about 22% of global energy demandin 2030 to 20% in 2050. Growth for natural gas in industry, about 120 bcm, offsets more than
90% of the decline in demand arising from growth in renewables and reduced coal‐to‐gas
switching. Natural gas also loses market share after 2030 in residential space heating, ceding
ground to district heating and electricity in the form of heat pumps and, in some cases,
electric heaters. Solar thermal heating also gains ground in the 2030s, displacing the use ofgas to provide hot water. By 2050, global natural gas demand is about 4 400 bcm, or roughly
the same level of demand as in 2030.
In the APS, the share of natural gas in the global energy mix falls from 23% in 2021 to 15%
by 2050. Most of the decline occurs after 2030, and the 2% decline in natural gas demand
per year between 2030 and 2040 is comparable to that of coal between 2021 and 2030. Low‐
emissions gases in the APS meet around 35% of total gaseous fuel demand in industry by
2050 as well as around 20% of total gaseous fuel demand in the power and buildings sectors.
Around 80 bcm of the natural gas that is consumed in industrial plants is equipped with CCUS,
mainly in the production of petrochemicals and non‐metallic minerals. Around 250 bcme ofhydrogen is consumed in industry. Around 340 bcme of biogases are used in 2050 across all
sectors (Figure 8.4).
Figure 8.4 ⊳Gas flows to meet demand for low-emissions fuels by sector in
the APS and the NZE Scenario, 2050
APS

NZE

HydrogenTransformation
TFC
Natural gas with CCUS
Transformation
TFC
Biogases
Transformation
TFC
250
500
750 bcme
250
500 bcme
Industry
Buildings
Transport
Power
Losses from hydrogen conversion
Inputs to ammonia production
Inputs to other hydrogen‐based fuels
Other
IEA. CC BY 4.0.

Low-emissions gases and CCUS increase rapidly from a low base in both scenarios andNotes: TFC = total final consumption. Other hydrogen‐based fuels include hydrogen used in refineries and forbiofuel production. Other for biogases includes agriculture, other non‐energy use and the other energy sector.
To avoid double counting, the energy originating from natural gas that is transferred to low‐emissionshydrogen is shown only once, as demand for low‐emissions hydrogen. The losses from the hydrogen
conversion are estimated only for the merchant hydrogen production.

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are essential to lower emissions in sectors where electrification options are challenging

In the NZE Scenario, natural gas demand is 70% lower in 2050 than 2021. Demand falls at a
rate of around 5% per year after 2030 (coal declines 8% per year over the same period). In
2050, 190 bcm of natural gas is used in non‐combustion sectors such as chemicals, 100 bcm
is used in power plants equipped with carbon capture and storage, over 560 bcm is used with
CCUS to produce hydrogen and a further 150 bcm is used with CCUS in industry. Totalhydrogen production reaches over 1 500 bcme by 2050. Over 25% of the hydrogen produced
in 2050 is converted to hydrogen‐based fuels such as ammonia, methanol and synthetichydrocarbons. The remainder is used directly in industry, transport and buildings. Biogases
reach more than 400 bcm by 2050; around 65% is biomethane, which is mostly injected into
gas networks or otherwise in containers as bio‐CNG mainly for use in the transport sector.
The overall share of low‐emissions gases in total gaseous fuels reaches over 70%, from lessthan 1% today.

Gas supply

Table 8.3 ⊳Natural gas production in the STEPS and APS (bcm)
STEPS

North America
CanadaMexicoUnited States
Central and South America
Argentina
BrazilEuropeEuropean Union
NorwayAfricaAlgeria
Egypt
Mozambique
Nigeria
Middle East
Iran
Iraq
Qatar
Saudi Arabia
Eurasia
Azerbaijan
RussiaTurkmenistan
Asia Pacific
Australia
China
India
Indonesia
Rest of Asia Pacific
World

2010
811
156
51
604
160
41
16
341
148
110
203
85
57
3
33
463
144
5
121
73
807
17
657
45
488
53
96
51
86
203
3 274

2021
1 189
189
31
969
151
41
25
239
51
119
265
103
72
4
44
660
236
12
169
100
998
33
793
90
648
151
200
32
58
206
4 149

2030
1 283
189
31
1 063
149
53
25
247
39
126
313
103
74
23
51
853
248
32
247
150
831
35
633
91
694
165
250
48
57
174
4 372

APS
2050
1 017
200
34
784
195
107
38
208
34
78
369
65
58
83
57
1 030
319
44
326
191
857
24
612
155
678
150
285
78
38
126
4 355

2030
1 098
154
31
913
133
51
19
177
17
80
285
97
74
14
48
798
245
29
236
148
751
35
584
73
636
154
228
47
50
156
3 878

2050
485
87
34
364
95
60
11
65
2
20
239
39
50
43
41
690
154
28
225
189
654
29
483
100
432
121
120
53
33
106
2 660

Note: See Annex C for definitions.

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8.3

Supply trends to 2030

bcm

Figure 8.5 ⊳Change in natural gas production by scenario, 2021-2030

1 500
2021
1 200

2030
STEPS
APS
NZE

900
600
300

North
AmericaEurasia

MiddleEast

Asia
Pacific

AfricaEuropeC&S
America
IEA. CC BY 4.0.

There are sharp reductions in Russian gas production in all scenarios, while the Middle East
leads supply growth. North America sees the largest variation between scenarios.
Note: C & S America = Central and South America.

In the STEPS, the Middle East is the largest near‐term source of supply growth (Table 8.3).
New supplies are underpinned by the North Field expansion in Qatar, where volumes areprimarily earmarked for export, as well as a 60 bcm rise in non‐associated gas productionthat meets domestic demand growth in Iran, Saudi Arabia and the United Arab Emirates. In
the APS, natural gas production is underpinned by resilient domestic demand growth and byincreased LNG trade.

In Russia, gas production falls in all scenarios. In the STEPS, it is 155 bcm per year lower in
2030 than it was in 2021. In the APS it is 210 bcm lower, taking production back to 590 bcm
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In the United States, total gas production rises in the STEPS from 970 bcm in 2021 to justover 1 050 bcm by 2030; this growth rate of 1% per year is much lower than the 5% seen in
the previous decade. Around 120 bcm of additional supply comes from unconventional drygas production led by the Marcellus and Utica plays, and associated gas in the Permian Basin
adds an additional 30 bcm. These additional supplies more than offset declines inconventional gas output. Around 55 bcm, or over half of net production growth, is exported
in the form of LNG. In the APS, even as gas production falls 7% below 2021 levels due todeclining domestic demand, LNG exports increase by 45 bcm from today, almost as much as
in the STEPS. In Canada, unconventional gas production increases by more than 50 bcm
between 2021 to 2030 in the STEPS, with over 40% exported as LNG. Overall, North American
gas production sees the biggest differences between scenarios; supply increases by morethan 90 bcm to 2030 in the STEPS, but contracts by 340 bcm in the NZE Scenario (Figure 8.5).

per year, a level last seen in 2002. The upstream projects designed to serve Nord Stream II –Kharasavey and the Bovanenkovo expansion – struggle in the near term to find alternative
outlets. The Tambey field expansion to underpin new LNG projects is unlikely to ramp up to
its original capacity. The flaring of associated gas has recently increased, and there is a short‐term risk in all scenarios of large‐scale flaring or venting to ease system pipeline pressures.
Russia’s efforts to diversify its export markets have mixed success. Deliveries to China in the
STEPS rise from 10 bcm in 2021 to 50 bcm by 2030. This is largely achieved through theramping up of the Power of Siberia pipeline, which delivers about 38 bcm per year and is
supplied by the Chayandinskoye and Kovyktinskoye fields in Eastern Siberia. Russia and China
agreed early in 2022 to a new pipeline routing up to 10 bcm of production from Sakhalin into
northeast China. Overall, however, Russia’s increased pipeline natural gas deliveries to China
cover less than half of the drop in exports to Europe by 2030. In some of the more maturefields in Western Siberia which currently serve Europe, such as Urengoy and Yamburg,
production is gradually shut in. Reduced gas extraction reduces field productivity and thepipeline pressures needed to support natural gas flows over long distances. In the APS andNZE Scenario, lower levels of demand for natural gas intensify these difficulties.
Europe’s efforts to secure supplies to displace Russian gas unlocks near‐term growth in Egypt
and in parts of sub‐Saharan Africa, notably in the Republic of the Congo, where a 4.5 bcm
per year LNG project is expected to start in 2023. By the mid‐2020s, Norway expands its
second‐largest gas field, Ormen Lange Phase 3, which has up to 40 bcm of recoverable gas,along with smaller new fields including Tommeliten A. However, declining production frommature basins means that Norwegian gas production peaks before 2030 in each scenario.

8

China’s most recent Five‐Year Plan (2021‐2025) is focussed on boosting domestic productionof natural gas including shale gas, coalbed methane, tight gas and other unconventional
resources. By 2030, China emerges in each scenario in the top‐five largest natural gas
producers, along with the United States, Russia, Iran and Qatar.
In India, the government recently announced a doubling of its licence area for oil and gas
exploration; however, this is unlikely to contribute significant volumes in this decade. In the
STEPS, gas production rises by over 15 bcm, with incremental volume mostly from theoffshore Krishna Godavari basin, covering around one‐third of domestic demand growth.
Production growth to 2030 is similar in the APS.

In Africa, production rises by about 20% in the STEPS between 2021 and 2030, with most of
the incremental volume coming from Mozambique. In the APS, gas production increases byless than 10%; there is very little growth in net trade and a more modest increase in domestic
demand relative to the STEPS.
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Elsewhere in Asia, gas production in Indonesia and Malaysia remains flat to 2030 in the
STEPS and drop by more than 10% in the APS, with recent upstream investments largely
offset by declining production from maturing fields. In Australia, gas production increases by
8% to 2030 in the STEPS and remains flat in the APS with incremental contributions fromconventional, coalbed methane and shale gas.

Gas production in Central and South America remains largely flat in the STEPS, with supply
rising from Trinidad and Tobago (Matapal and Colibri, around 3 bcm) and Argentina (Vaca
Muerta, 12 bcm). These are largely offset by declines elsewhere in countries such as Bolivia,
Venezuela and Peru. In the APS, gas production falls 12% below 2021 levels by 2030.

Supply trends after 2030
Figure 8.6 ⊳Total gaseous fuel supply by scenario

STEPS

APS

NZE

bcme

5 000
4 000
3 000
2 000
1 000

2050
2050 2020
2050 2020
Natural gas UnabatedWith CCUS
Fossil fuels with CCUS
Low‐emissions hydrogen (by source) Electrolysis and bioenergy
Losses from H₂ conversion
Biogases
2020

IEA. CC BY 4.0.

Total gases increase in the STEPS, while in the APS and the NZE Scenario the drop in supply
for unabated uses is partly offset by a rise in hydrogen, biogas and gas use with CCUS
Notes: H2 = hydrogen. Includes all gases supplied to the system for transformation (to electricity, heat orhydrogen‐based liquid fuels) or final consumption. The energy content of low‐emissions hydrogen produced
from natural gas is subtracted from natural gas use with CCUS. Losses from hydrogen conversion are formerchant production.

The production of low‐emissions gases ramps up in both the APS and the NZE Scenario(Figure 8.6). In the APS, low‐emissions gases reach nearly 1 100 bcme by 2050, equivalent tomore than 25% of global natural gas demand in 2021. Biogas rises to nearly 340 bcme by2050 from about 35 bcme today. Over 40% of biomethane and biogas are developed in the
Asia Pacific region. Low‐emissions hydrogen supply reaches about 750 bcme by 2050 in the
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In the STEPS, natural gas production stays flat between 2030 to 2050. Shale gas production
remains largely unchanged in North America, and there is some growth in the Middle East
and Central and South America. New gas producers in Africa, such as Mozambique, Tanzania
and Senegal, see a late surge in export‐led production, underpinning 110 bcm of growth.
Overall production in Russia declines by an additional 25 bcm between 2030 and 2050.
Global natural gas supply in the APS declines by over 1 200 bcm between 2030 and 2050, tolevels seen before the shale gas revolution. In the NZE Scenario, global gas production
declines at a rate of 5% per year, and is just under 1 100 bcm by 2050.

APS and over 1 500 bcm in the NZE Scenario. Most low‐emissions hydrogen is produced andused domestically, but global trade in low‐emissions hydrogen‐based gases begins to rise in
the NZE Scenario from the mid‐2020s, to reach around 240 bcme by 2050.

8.4

Gas tradebcm

Figure 8.7 ⊳400

Change in natural gas net trade in selected regionsin the STEPS and APS

European
Union

Japan and
Korea

China

India

Other
developing Asia
Other
AfricaNorth America
Middle East
Australia
Russia
APS

300
200

2021
2030
2050

2021
2030
2050

2021
2030
2050

2021
2030
2050

2021
2030
2050

100

8
IEA. CC BY 4.0.

Europe’s near-term need for non-Russian gas imports leads to a rebalancing of global gas
flows and to increased competition for LNG with emerging gas markets in Asia

In the STEPS, global natural gas trade increases at an annual average rate of less than 1% peryear from 2021 to 2030, compared to 3% between 2010 and 2021. LNG rapidly gains market
share from long‐distance pipeline trade and so grows at a faster rate than overall trade, atmore than 2% per year. With Russian pipeline gas to the European Union falling by nearly
90%, or 130 bcm between 2021 and 2030, competition heats up between Europe and Asia
for LNG, overturning the conventional wisdom that Europe acts as a balancing market for
global LNG supply (Figure 8.7).

In 2030, the European Union imports an additional 65 bcm of LNG in the STEPS compared to2021, while there is a 50 bcm decline in LNG imports in Korea and Japan. Emerging market
and developing economies in Asia import an additional 80 bcm of LNG, with imports mostly
flat elsewhere.
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Around 85% of the growth in global LNG supply to 2030 in the STEPS originates in the UnitedStates and the Middle East. The United States soon overtakes Russia to become the world’s
largest natural gas exporter. US LNG exports increase by 60% from 2021 levels to reach nearly
150 bcm by 2030, of which about 60 bcm is transported to the European Union.

Russia’s share of globally traded gas falls from almost one‐third in 2021 to less than 15% in
the STEPS by 2030. The increase in Russian pipeline flows to China cover less than a third of
the drop in deliveries to the European Union. Since China has minimal additional importrequirements beyond what is currently contracted, Russia is only able to redirect around25 bcm per year by 2040 from its Western Siberian gas fields to China through an additional
pipeline. Expansion in LNG capacity in Russia is constrained by sanctions; some projects are
shelved, while others see significant delays to commissioning dates. Around 10 bcm of new
LNG export capacity is added in Russia by 2030, taking total export capacity to 45 bcm peryear, but this falls far short of what Russia needs by that date to be on course to achieve its
stated aim of 200 bcm per year of capacity by 2035.
China – currently the world’s largest natural gas importer – sees imports meet 35% of
demand growth between 2021 and 2030 in the STEPS. The share of pipeline gas in its total
gas imports increases from 25% in 2021 to 45% in 2030 as deliveries from Russia through thePower of Siberia pipeline and the planned 10 bcm Far East pipeline are ramped up. By 2050,
China accounts for nearly a quarter of all long‐distance pipeline gas trade.
Around 65 bcm per year of LNG regasification capacity is under construction in China, adding
to the existing capacity of 100 bcm per year. Since the start of 2021, China has also
contracted for around 75 bcm per year of additional LNG over the period to 2030. All thiscontracting and infrastructure expansion hinges on expectations of strong demand growth,whereas in the STEPS demand moderates to around 2% per year between 2021 and 2030.
With continued growth in domestic production, LNG demand grows slower than contracted
supply, and so some of China’s flexible LNG import contracts (around 45 bcm per year) arediverted to other markets, easing some of the global LNG supply tightness in the mid‐2020s.
In India, gas imports double and reach nearly 70 bcm by 2030; growth moderates thereafterand imports reach 90 bcm by 2050. The remaining major gas markets in emerging market
and developing economies in Asia, primarily in Southeast Asia, Pakistan and Bangladesh,grow by over 250 bcm between 2021 and 2050.

In the APS, global gas trade falls slightly between 2021 and 2030, driven by faster declines inpipeline gas and slower growth in LNG demand in emerging market and developing
economies in Asia. Global LNG trade peaks at around 550 bcm before 2030 and then falls to
320 bcm by 2050, about 30% below 2021 levels. Inter‐regional pipeline trade declines fromabout 430 bcm today to less than 200 bcm by 2050, meaning overall natural gas trade is 45%
lower than in 2021. In emerging natural gas markets in Asia, import volumes in the APS by
2050 are about 40% lower compared with the STEPS, as the role of gas as a transition fuel islargely limited to this decade (see section 8.8).
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In the STEPS, an additional 240 bcm per year of LNG export capacity is needed by 2050 above
what currently exists or is under construction (Figure 8.8). Inter‐regional LNG trade in the
STEPS expands an additional 15% from 2030 to 2050, to reach 650 bcm by 2050. East Africa
is the main source of LNG supply growth, with exports rising by nearly 80 bcm between 2030
and 2050, more than offsetting declines in other parts of Africa.

In the NZE Scenario, global LNG trade peaks in the mid‐2020s and then falls to 2021 levels by
2030, before declining sharply to 150 bcm by 2050. In this scenario, there is no further needfor additional capacity beyond what exists or is under construction.

bcm

Figure 8.8 ⊳Existing and under construction LNG capacity and totalinter-regional LNG trade by scenario, 2015-2050

800

Trade
STEPS
APS
NZE

Under construction
600

400
Existing LNG capacity

200

2015

2020

2025

2030

2035

2040

2045

2050
IEA. CC BY 4.0.

8There is near-term growth in LNG trade in all scenarios, but sharp divergences thereafter
Note: LNG capacity is adjusted to reflect inter‐regional trade between regions modelled in the Global Energy
and Climate Model, and de‐rated to 80% of nameplate capacity.

8.5

Investment

The sharp decline in natural gas investment in the NZE Scenario after 2030 is accompanied
by a parallel ramp up in investment in low‐emissions hydrogen. This increases to overUSD 220 billion in the NZE Scenario by 2050, which is broadly equivalent to the reduction in
investment in natural gas over the same period. The majority of investment in low‐emissionshydrogen supports the production of hydrogen from electrolysers (USD 150 billion on
average between 2030‐50, which includes investment in dedicated low‐emissions electricity
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In the STEPS, around USD 300 billion in capital per year is spent on natural gas between 2022
and 2050. Around a further USD 30 billion is spent on LNG infrastructure, mainly on newliquefaction capacity. In the APS, growth in total investment spending is slower, andinvestment falls to half of 2021 levels by 2050. In the NZE Scenario, upstream investment innatural gas is limited to maintaining supply at existing fields and minimising the emissions
intensity of production. Total spending on natural gas transport between 2022 and 2030 issimilar between the STEPS and NZE Scenario, and the level of spending on transport means
the average of total investment in natural gas in the NZE Scenario in 2022‐30 are broadly
similar to levels in 2021 (Figure 8.9).

supply), but it also includes spending on fossil fuels equipped with CCUS (USD 20 billion ayear on average). The remaining investment is in new pipelines, shipping and port
infrastructure. In the NZE Scenario, around 15% of hydrogen is blended into natural gas
networks by 2050, and this requires relatively minor investment in natural gas infrastructure.
Hydrogen production in the NZE Scenario is relatively capital intensive compared withnatural gas, requiring double the level of investment per unit of equivalent energy.
Figure 8.9 ⊳Average annual natural gas and hydrogen investment
by scenario
HydrogenNatural gas

2022‐30

STEPS
APS
NZE

2031‐50

2016‐21

STEPS
APS
NZE
100

200

Production

300
USD billion

100

200

300
USD billion

Transportation
IEA. CC BY 4.0.

In the NZE Scenario, the amount invested annually for low-emissions hydrogen
becomes as large as what is spent on natural gas today
Notes: Production for hydrogen includes merchant hydrogen and onsite production from electrolysers.
Transportation includes liquefaction and regasification terminals, ships, pipelines and storage. Only the costsof dedicated renewables for offsite hydrogen production are included; it excludes costs associated with theuse of grid‐based electricity. Some of the investment in natural gas production results in supply for natural
gas‐based low‐emissions hydrogen production.

Box 8.2 ⊳What are the implications for natural gas of the European Union
taxonomy of sustainable financial investments?

We assessed the life cycle emissions associated with natural gas extraction, processing,transport and consumption for both heat (in buildings and industry) and electricity
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The European Union taxonomy of sustainable financial investments sets out theconditions that activities such as natural gas investment must meet in order to beconsidered sustainable. To meet these conditions, an activity must produce less than
270 kilogrammes of carbon‐dioxide equivalent per megawatt‐hour (kg CO2‐eq/MWh) of
output energy, and annual direct emissions must not exceed an average of
550 kg CO2‐eq/kW of the facility’s capacity over 20 years.

generation in order to evaluate how the taxonomy thresholds would affect natural gas‐
related investments worldwide. This assessment takes account of the flaring andmethane emissions associated with the production and transport of natural gas in 2021.
An upward slope in the supply curve reflects higher emitting sources of supply.
Figure 8.10 ⊳ European Union gas taxonomy thresholds compared with
global life cycle emissions of natural gas, 2021
Power generation

kg CO2‐eq/MWhHeat in industry and buildings
1 000
800
600
400
200

0%

50%

100%

Natural gas emissions

0%

50%

100%

Taxonomy threshold

8

IEA. CC BY 4.0.

Natural gas to produce heat for buildings and industry mostly falls below thetaxonomy thresholds, but unabated power plants exceed themNote: Values on the x‐axis show, in percentage terms, all the natural gas consumed worldwide for heat
(1 400 bcm) and electricity (1 650 bcm) in 2021.

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The taxonomy thresholds imply that most of the natural gas use to generate heat inbuildings and industry can still technically qualify as a sustainable activity, as long as
methane leaks and other upstream emissions are minimised. However, the use of natural
gas to generate electricity involves efficiency losses that increase its combustion
emissions intensity, meaning unabated gas‐fired power plants would exceed thethreshold by a significant margin. There are provisions in the taxonomy for unabatedplants to be designated sustainable as long as the total emissions do not exceed
550 kg CO2/kW of installed capacity each year over 20 years. In practice, this would mean
flexible gas generators, with an average combustion intensity of 500 kg CO2/MWh, could
operate at a load factor of around 10% on average per year before exceeding thesenorms. Many power producers and the financial sector might consider such restrictions
to be too significant a barrier to investment.

Key themes
8.6

Outlook for natural gas in the European Union after Russia’s
invasion of Ukraine

Curtailments of supply after Russia's invasion of Ukraine have left the natural gas sector in
the European Union in disarray. Deliveries from Russia to the European Union fell by nearly
40% in the first‐half of 2022, with Russia terminating supply contracts for multiple EU
countries due to buyer refusal to accept a unilateral change in the payment system. Exports
to former subsidiaries of Gazprom in Germany have ceased, and large importers such as
Germany and Italy are planning a phase out of Russian gas over the course of the 2020s. With
its RePowerEU Plan, the European Union is setting in motion a process to dismantle astructural dependence on energy imports from Russia built over several decades. During thewinter ahead, the amount of Russian gas supplied to Europe may well be dictated by Russia’s
own political ends rather than by European policies, raising the risk of possible supply
shortfalls and rationing. In this section, however, we look beyond immediate events to
explore the longer term challenges and uncertainties for the European Union as it seeks to
reduce the role of natural gas in the energy mix while diversifying its supplies.
The role of natural gas, and the level of dependence on Russian gas in particular, varyconsiderably across the European Union (Table 8.4). Around 40% of the European Union’s
total residential space and water heating demand and 30% of its cooking fuel demand iscurrently met by natural gas. Gas also powers 20% of total electricity generation and meets
25% of its industrial energy demand, playing an outsized role in sectors such as chemicals,
textiles and food production. Options to substitute for natural gas are a crucial determinantof the near‐term ability of the European Union to adjust to potential supply shortages.
Natural gas use is embodied in goods and services derived from multiple industries, meaning
the effects of a cessation of supply could affect various industrial and services sector value
chains. This makes it very difficult to assess substitutability in a straightforward way.

Natural gas demand in the European Union declines by 180 bcm from 2021 to 2030 in the
APS, an average fall of 6% per year. Gas use in the power sector over this period drops at afaster pace than coal use did in the European Union from 2010 to 2020. There is a parallel
ramp up of renewables, especially wind and solar capacity, which increase by 600 gigawatts(GW) to 2030, while coal declines by 100 GW. Building retrofits nearly triple from the current
rate of less than 1% per year and 40 million heat pumps are deployed (equivalent toinstallations in nearly one‐third of the EU building stock). Together these actions help reduce
the use of gas in buildings by 45% from 2021 to 2030, or roughly double the pace of the
reduction in oil use in the EU residential heating sector in the 1980s. Natural gas demand in
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In the APS, the European Union targets in the Fit for 55 package are fully met, and in somecases exceeded. The acceleration of key measures, such as rapid deployment of renewablesin the power sector and energy efficiency, means that greenhouse gas (GHG) emissions
reductions targets are met and that EU imports of Russian natural gas end well before 2030
– the key objective of the REPowerEU Plan (Figure 8.11).

industry falls around 4 bcm per year, faster than the decline seen in 2020 immediately after
the onset of the Covid‐19 pandemic. Most of this is in energy‐intensive industry such as steel
and chemicals, offset by higher rates of electrification.
Table 8.4 ⊳Share of Russian gas in total natural gas demand and share ofgas in sectoral demand by European Union member states andthe United Kingdom, 2021

Market size Country>20 bcm

10‐20 bcm

5‐10 bcm<5 bcmRussian share

Share of gas in sectoral demandPower

Industry

Buildings

Germany*

46%

20%

31%

38%

United Kingdom

3%

43%

32%

55%

Italy*

41%

51%

31%

50%

France*

20%

9%

31%

29%

Netherlands**

36%

58%

30%

59%

Spain

11%

31%

38%

22%

Poland**

46%

9%

28%

19%

Belgium

7%

30%

28%

41%

Romania

6%

28%

37%

34%

Hungary

78%

37%

30%

50%

Austria*

74%

21%

34%

20%

Czech Republic*

67%

13%

24%

30%

Portugal

10%

40%

23%

12%

Slovak Republic*

76%

20%

28%

40%

Ireland

0%

52%

42%

22%

Denmark**

60%

11%

30%

13%

Greece

39%

29%

23%

9%

Bulgaria**

100%

15%

34%

5%

Croatia

0%

32%

51%

22%

Finland**

68%

8%

6%

1%

Lithuania**

50%

17%

59%

11%

Latvia*

100%

48%

11%

13%

Sweden

14%

1%

5%

1%

Slovenia

12%

7%

34%

9%

Luxembourg

25%

27%

44%

36%

Estonia**

46%

9%

21%

9%

8

* Denotes a partial cut. ** Denotes a full cut.

Source: Share of Russia in total natural gas demand calculated using trade data from ACER (2022); Cedigaz(2022); Eurostat (2022).

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Notes: Asterisks denote countries that stopped receiving natural gas from Russia in 2022. Table is orderedfrom highest to lowest natural gas demand.

Figure 8.11 ⊳ Drivers of reduced natural gas supply from Russia to thebcmEuropean Union in the APS
160
Other
Building efficiency
120
Wind and solar
80
Pipeline imports
LNG ‐ Middle East
LNG ‐ Africa
LNG ‐ North America
Hydrogen

40

Bioenergy
2021

DemandSupply2027
IEA. CC BY 4.0.

A mix of supply- and demand-side measures are required
for the European Union to reduce reliance on Russian gas to zero before 2030
Note: Other includes reductions in industrial natural gas demand and gas‐to‐coal switching.

Part of the EU supplies in summertime are used to build up storage capacity. In the APS, thevolumes required by the EU gas storage injection and withdrawal cycle reduce as seasonalvariations in demand diminish and as LNG meets a higher share of demand: a net of 40 bcm
of storage is withdrawn during the winter in 2030 in the APS compared to an average net
withdrawal of 65 bcm between 2016 and 2021 (Figure 8.12). However, the amount of gas
stored and ultimately withdrawn in 2030 is similar as a share of remaining gas demand as in
2021, meaning that storage still plays a vital role in security of supply. And unexpected events
could still cause problems. For example, colder than expected winters or failure to deliver
the targeted reduction in natural gas demand in buildings would increase the seasonality ofdemand: in the absence of adequate storage, this would increase reliance on LNG, which
would be likely to push up prices.
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On the supply side, deliveries from Russia gradually fall to zero before 2030 in the APS. In
parallel, European gas buyers maximise LNG shipments to existing facilities while also
developing new facilities for LNG imports (announced plans total an extra 120 bcm per yearof new capacity, of which around 40 bcm per year are floating storage and regasification
units). LNG imports average 140 bcm per year over the 2022‐27 period, meeting almost 60%of the EU non‐Russian import requirements. Around 40 bcm per year of LNG on average isimported from the United States. Gas imports from Norway drop to around 60 bcm per year.
There are some additional pipeline supplies from Algeria and Azerbaijan.

bcm

Figure 8.12 ⊳ European Union monthly natural gas supply balance in the APS
60
50

Storagewithdrawal
LNG

40

Other pipe

30

Norway20

Russia10

Production2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
IEA. CC BY 4.0.

Russian gas is gradually phased out in favour of LNG. The seasonality of EU gas
demand falls, but gas storage remains a crucial asset for security of supply
Notes: Values match EU annual natural gas demand in the APS. Gas volumes used to fill storage are netted off
and included in storage withdrawal.

8

S P O T L I G H T
Cutting flaring and methane leaks can provide a double
dividend for environment and energy security

If countries that are current or potential exporters of natural gas to the European Union
were to implement flaring and methane reduction measures, the gas saved would meanthat they could increase gas exports by more than 53 bcm using existing and planned
infrastructure. This is equivalent to about one‐third of Russian gas exports to theEuropean Union in 2021 or the full use of the Nord Stream 1 pipeline annual capacity(Figure 8.13). Rapid action to deploy all available flaring and methane abatement
technologies over the next decade would have the same effect on the global temperaturerise by mid‐century as immediately eliminating the GHG emissions from all of the world’s
cars, trucks, buses and two/three‐wheelers.
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Over 260 bcm of natural gas was flared, vented or lost to leaks in 2021. Of this, weestimate that nearly 210 bcm could be made available to gas markets by a global effort
to eliminate non‐emergency flaring and reduce methane emissions from oil and gas
operations (IEA, 2022a). This would bring a double dividend: relief for very tight gas
markets along with reduced GHG emissions. As the flaring intensity of oil imported by theEuropean Union is five‐and‐a‐half‐times larger than that produced in the region(Capterio, 2021), the European Union has a clear incentive to act. Reducing imports from
Russia will lower this intensity as Russia flares more gas than any other country, with anestimated total of more than 20 bcm in 2021 (Zhizhin et al., 2021).

Figure 8.13 ⊳ Potential for flaring and methane abatement to satisfy EU gas
import demand compared with the capacity of Nord Stream I

Nordstream I
capacity (bcm/year)

Savings fromflaring andmethane abatement
10
RussiaLibya

20

United States
Egypt

30

40

50

60
bcm

Algeria
Nigeria
Other current and potential exporters
IEA. CC BY 4.0.

Flaring, venting and leaks are wasting gas that could be exported to theEuropean Union at a level equivalent to the full capacity of the Nord Stream I pipeline

Some of the largest flaring reduction opportunities are in North Africa: Algeria and Egypt
lost about 12 bcm of natural gas from their upstream assets in 2021 as a result of flaring
and related combustion inefficiency losses. According to satellite imaging analysis carriedout by analytics firm Capterio, close to 80% of flaring in Algeria and Egypt occurs within
20 kilometres (km) of existing gas pipelines with ready access to an existing export
pipeline or LNG terminal (Davis et al. 2022). Most flares operate continuously and manyare candidates for cost‐effective abatement options.

A rising number of countries have set targets to cut flaring and methane emissions.
Achievement of the targets will rely on governments establishing flaring and methane390

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The logistical and economic challenges involved in capturing large quantities of flared gas
include multiple point sources, varying levels of potential natural gas capture andcomplicated ownership structures across the supply chain. In North Africa there areseveral recent examples of flare capture projects that have reduced emissions,contributed to emissions reduction targets and created value. Kuwait Energy and United
Oil and Gas built a dedicated gas pipeline in less than one year in Egypt to move up to
0.05 bcm of natural gas per year to an existing gas processing facility some 20 km awayrather than flaring it. In another example, Apache and Shell (and partners including
BAPETCO) recently installed gas‐fired plants to power operations that previously flaredgas: this reduced flaring by 0.04 bcm year while also cutting diesel consumption by up to
3 million litres per month.

reduction plans underpinned by robust and transparent data. Governments could
improve the investment climate by amending existing commercial contracts toincentivise operators to take action, e.g. by granting them ownership of the gas. For its
part, the European Union could encourage supplier action by providing preferential
funding for flaring abatement and related infrastructure to help overcome the logisticaland economic hurdles common to these emissions reduction opportunities, orcontracting for the saved gas.

Contracting dilemmas
Demand for imported natural gas in the European Union is projected to fall from 370 bcm
per year in 2021 to 230 bcm per year by 2030 before declining to 140 bcm per year in 2035
and then 40 bcm per year by 2050 in the APS. Russian deliveries are assumed to fall at a rapid
pace, irrespective of the constraints of the take‐or‐pay supply contracts that remain in force.
On that basis, a maximum of 170 bcm per year of additional natural gas is required to 2030
above the existing firm non‐Russian gas contracts; this requirement falls to 70 bcm per yearby 2035 (Figure 8.14).
Figure 8.14 ⊳ European Union natural gas contract balance compared withbcm

import requirements in the APS, 2022-2035

8400

Take or pay
Russian contracts
Maximum contracted
Non‐Russian pipeline
Non‐Russian LNG

300

200

APS importrequirements

2035

2034

2033

2032

2031

2030

2029

2028

2027

2026

2025

2024

2023

2022

100

IEA. CC BY 4.0.

Assuming demand falls in line with the APS, gas buyers in the European Union need

The dilemma for EU gas buyers is whether to contract for new capacity or rely on the spot
market to fill the gap. In principle, the EU supply gap to a large extent can be filled byattracting LNG cargoes from the spot market, through paying a premium that diverts themfrom other markets. Around 50% of current global LNG trade, or 250 bcm, can be considered
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anywhere from 70-170 bcm of additional supply to 2030, depending on Russian importscontractually flexible, and therefore open to competition to determine its end destination.
The rest is governed by fixed point‐to‐point delivery arrangements. This proportion increases
slightly over the coming years, as existing contracts expire and around 55% of the 200 bcm
per year of LNG export capacity coming online between 2022 and 2026 is also flexible.
However, a high level of exposure to short‐term markets may put European gas buyers at
the mercy of volatile global LNG supply dynamics, especially in the near term. Flexible
volumes may also be converted to firm, long‐term contracts by other buyers seeking assured
supply.
Another solution is to sponsor new LNG export projects, thereby securing firm off‐take.
However, this requires long‐term commitment, as capital‐intensive LNG projects require longlead times to construct, a minimum take‐or‐pay volume commitment lasting around20 years, and an operational lifetime of at least 30 years. Many gas buyers in the European
Union meanwhile would be looking to phase out gas demand well before 2050.
To illustrate a potential way of resolving this difficulty, we conducted an assessment of
200 bcm worth of recently commissioned and under construction LNG projects around theworld to calculate the gas price required if they were to recoup investment costs with 10‐year
contracts rather than 20‐year contracts. The weighted average break‐even price of gas overa 20‐year contract lifetime is around USD 7.50/MBtu, with an average rate of return of nearly
20%. At the lower end of the cost scale are projects like the North Field expansion in Qatar,
which enjoys low cost gas and associated liquids supplies that improve project economics.
At the upper end of the scale are greenfield projects such as LNG Canada, which requires
additional infrastructure to connect upstream gas fields to the liquefaction terminal.
Figure 8.15 ⊳ Contract prices required to cover break-even costs of
LNG supply for recently approved projects

IEA. CC BY 4.0.

with net zero emissions targets would mean significantly higher delivered costs

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Shortening the contract length for LNG supplies to Europe to improve alignment

Shortening the contract tenure to ten years would increase the break‐even gas price needed
to fully recoup investment costs for recently approved projects by around 20% on average(Figure 8.15). This illustrates the magnitude of contract price increases that could be required
for the next crop of LNG export projects: if the additional uncontracted LNG requirements of
EU members in the APS over the 2022‐30 period were to be filled by new projects financed
under ten‐year contracts instead of twenty‐year contracts, the additional cost to natural gas
importers in the European Union would be around USD 140 billion.
An alternative approach would be for buyers in the European Union to contract flexible
volumes for 20 years, for example from the United States, to ensure projects are permitted
and to aim to sell the gas they do not need in later years to Asia. This is plausible in the STEPS,
where LNG demand continues to increase to 2050, but global LNG demand peaks before
2030 in both the APS and NZE Scenario. Indeed, the rapid fall in LNG after 2030 in the NZE
Scenario implies no need for additional capacity beyond what is existing or underconstruction; any new LNG projects approved after 2022 are at risk of not recovering theirinvested capital in the NZE Scenario.

Assessing the investment costs of transitioning away from Russian gas
The RePowerEU Plan sets out the investments required to reduce the European Union
reliance on Russian energy imports. Many of the measures build on the Fit for 55 package,
which also contains ambitious investment targets.

8

In the APS, investment in clean energy in the European Union averages around
USD 360 billion per year between 2022 and 2030, an 80% increase on average levels over the
past five years. Through a detailed sectoral decomposition of spending, we have assessed
the contribution of clean energy investment to reduce natural gas demand (as distinct fromreducing demand for oil or coal, or meeting new demand for energy arising from population
or economic growth).

The combined cost of these measures is USD 65 billion per year on average over the 2022‐
30 period, around double the sums spent in the STEPS. However, the additional investments
to transition away from natural gas in the APS result in much lower import costs in the longterm, which are nearly USD 45 billion lower per year than in the STEPS from 2031 to 2050
(Figure 8.16). Moreover, a large portion of the transition costs go toward domestic jobs andservice industries. Russian gas export earnings to the European Union over the 2016‐21
period of around USD 30 billion per year are reduced to zero before 2030 in the APS; Russia
fails to recover most of the income lost to reduced gas supply to Europe.
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Our calculations indicate that around one‐fifth of total investment in clean energy in theEuropean Union yields a reduction in natural gas demand in the APS. The main investment
categories that contribute to this reduction are building retrofits, electrification of energy
services that would otherwise use natural gas (mainly through wide scale purchasing of heatpumps for use in buildings), and measures that lead to the replacement of gas withrenewables in the power sector or boost investment in low‐emissions fuels such as
biomethane and hydrogen.

Figure 8.16 ⊳ Average annual investment in clean energy to transition from

Billion USD (2021, MER)

natural gas in the European Union and gas import costs, 2016-50
150

2016‐212022‐302031‐50
Clean investment
Low‐emissions fuelsElectrification
Efficiency
Renewables

120
90

Import costs
Non‐Russia
Russia

60
30

STEPS

APS

STEPS

APS
IEA. CC BY 4.0.

In the APS, USD 65 billion of investment per year is required to cut natural gas demand in
the European Union by 180 bcm by 2030, a sum offset over time by lower gas import costs
Note: MER = market exchange rate.

Scaling up biomethane
The European Union is supporting the scaling‐up of biomethane, where there is significant
potential across the region (Figure 8.17). Around 3 bcm of biomethane and 9 bcme of biogas
is currently produced (most of the latter is directly consumed in local production of electricity
and heat). The growth in biomethane production envisioned in the RePowerEU Plan implies
a 35% average annual growth rate from 2022‐30 compared to 20% in 2015‐21.

Biomethane can also yield a significant quantity of digestate, a by‐product which can be used
as a biofertiliser. Digestate yields vary depending on the volatile solids content and methane
potential of different feedstocks; 35 bcm of biomethane production could yield significant
quantities of nitrogen biofertiliser, reducing mineral fertiliser use. In addition, it could avoid
methane emissions if the digestate is responsibly handled and stored. There is also potential
to use the relatively pure stream of CO2 associated with the biogas upgrading process to
produce synthetic methane.
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IEA analysis suggests that 35 bcm of biomethane could be produced in the European Union
for less than USD 20/MBtu. This is below the average price seen since July 2021, but well
above the average of the past decade. However, it does not include injection costs into
pipelines, or compression and liquefaction costs. Factors that could accelerate cost reduction
and production growth include streamlined permitting procedures, factory‐style fabricationof standardised biodigesters and related equipment, pooling of feedstocks, dedicated biogas
financing facilities, and policy measures such as quotas, feed‐in tariffs and contracts fordifference.

Figure 8.17 ⊳ Biomethane potential in the European Union by 2030
compared with share of natural gas demand in 2021
By country
25%

50%

75%

100%

Germany
FranceSpain
Italy
PolandSwedenFinlandRomania
Netherlands
Denmark
Rest of EU

Crop
residues
Forestry
Municipal
waste
Manure5Potential

By feedstock
80 bcm10
15
20 bcmeShare of natural gas demand (top axis)
IEA. CC BY 4.0.

Up to 80 bcm of biomethane could be produced sustainably in the European Union by
2030; some countries have potential exceeding their current natural gas demand
Notes: EU = European Union; Rest of EU = average of the 17 member states not shown individually.

8.7

8

Scaling up hydrogen

Capital flows indicate where investors and companies see opportunities in the coming years.
Two of the world’s largest electrolysers started operations in 2022. In China, the capacity ofa captive electrolyser supplying a methanol and chemical plant was expanded fivefold to150 MW. In Spain, a solar‐powered 20 MW electrolyser was commissioned at an existingfertiliser plant. Two large electrolyser projects received final investment decisions. First is a
260 MW electrolyser that aims to start supplying a refinery in China from 2023. Second is a
200 MW plant operating on wind power in the Netherlands, which is due to start in 2025,
and is coupled with an existing refinery with high hydrogen demand. Overall, capitalspending in 2021 on hydrogen electrolyser projects starting operation or under construction
was around USD 1.5 billion, more than three‐times as much as in 2020. In each project, theinvestment case was supported by the simplicity of the value chain.

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Momentum behind the global low‐emissions hydrogen sector has been given a major boost
by Russia’s invasion of Ukraine. By 2021 the sector was already converting more of its bulging
project pipeline into investment decisions, and hydrogen‐focussed companies were raisingmore money than ever before. With EU member states now aiming to reduce natural gas
and oil demand by increasing low‐emissions hydrogen use, and higher formal targets in the
United Kingdom and elsewhere, it seems likely that major projects around the world will start
construction in the near term.

The large pipeline of projects on which investment decisions are due to be taken in the nearterm depends on the scaling‐up of companies across the value chain. Investors have takennote and are directing money to companies all along the hydrogen value chain. The 33 “pureplay” hydrogen companies tracked by the IEA have increased their capitalisation by around
USD 20 billion since mid‐2020. Investors looking even further ahead allocated
USD 700 million in 2021 of early stage venture capital to start‐ups that are developinghydrogen technologies, which is nearly five‐times the amount invested in 2020. This increase
was driven by investor confidence in start‐ups that offer project development services, which
reinforces the perception that projects will soon be built, and in innovative technologies forhydrogen end‐uses as well as for potential non‐electrolysis routes to low‐emissions hydrogenproduction, such as methane pyrolysis.
Figure 8.18 ⊳ Domestic supply and trade of low-emissions hydrogenfor key regions in the APS by 2050
China
United States
European Union
Latin America
Middle East
CanadaAustralia
Korea
Japan
North Africa‐500Domestic supply

50
Net exports

100

150
bcme

Net imports
IEA. CC BY 4.0.

Low-emissions hydrogen production exceeds 50 bcm of natural gas equivalent in several
regions, with exports as the main driver in Australia, Middle East and North Africa

Global low‐emissions hydrogen production reaches 30 Mt of hydrogen per year (Mt H2/year)
in 2030 in the APS, including hydrogen produced onsite in industry and refineries as well asthat used to produce hydrogen‐based liquid fuels. This is equivalent to the energy content of
100 bcm of natural gas and would represent an enormous ramp up from much less than 1 Mtof low‐emissions hydrogen today. Producing and delivering this volume of hydrogen by 2030
in the APS would require cumulative investment of USD 170 billion in electrolysers and CCUS
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Notes: bcme = billion cubic metres of natural gas equivalent. Low‐emissions hydrogen trade includes trade inhydrogen‐based fuels as a means of exporting clean energy via its transformation to hydrogen. Inclusion inthis figure does not imply that the traded products are all used in the form of gaseous hydrogen in importing
countries. Values are given in bcme based on a conversion factor of 36 petajoules of traded energy productper bcme.

equipment, and nearly three‐times this sum for new renewable electricity capacity,
infrastructure and plants for conversion to hydrogen‐based fuels. Installed electrolyser
capacity in 2030 reaches 260 GW in the APS, fed by over 1 000 terawatt‐hours (TWh) of low‐emissions electricity. While much of the demand is initially concentrated in China, Europe,
Japan and North America, investment becomes more evenly spread as trade between
countries gets underway later this decade. By 2050, trade patterns become well established,with Australia and the Middle East as the largest exporting regions (Figure 8.18).

2030 investment challenge for hydrogen
A major driver of hydrogen‐related activity is the political determination of the European
Union to develop and use hydrogen. In 2021, the European Commission proposed that by
2030 the industrial and transport sectors in the European Union should use approximately
11 Mt H2/year made from the electrolysis of water by renewable electricity. In May 2022, theEuropean Commission proposed nearly doubling this to 20 Mt H2/year across all end‐use andtransformation sectors, with half of the total imported into the European Union from othercountries.2 To put this in context, EU industry currently produces and uses around
7 Mt H2/year of hydrogen, nearly all of it from natural gas, and its transport sector uses lessthan 1 thousand tonnes per year. The proposal, which is calculated to displace 27 bcm ofnatural gas and 80 thousand barrels per day (kb/d) of oil, is too large a scale to realisticallybe met solely by replacing existing hydrogen sources with electrolysis. New sources ofdemand will also be required.

8

Based on a possible configuration of assets that could produce 10 Mt H2/year within theEuropean Union and deliver an additional 10 Mt H2/year to the European Union in 2030, we
estimate the total capital investment at USD 700‐850 billion, almost half of it related toassets outside the European Union (Figure 8.19).3 This more than doubles when the cost ofcapital is included. The largest single cost component would be the purchase and installationof around 440 GW of renewable electricity generation, mostly solar PV and wind, to power
the electrolysis process. The purchase and installation of 290 GW of electrolysers accounts
for 15% of the estimated total, less than infrastructure such as pipelines, port terminals, ships
and hydrogen storage. Repurposing existing natural gas pipelines could cost less than half as
much as building new ones for hydrogen, but this would have to be aligned with the phasingout of natural gas. In the APS, repurposed natural gas pipelines account for around 50% of
new installed hydrogen pipeline capacity in the 2030s.

2

These proposals are yet to be officially adopted by the European Union or translated into enabling legislation.

The lower end of the range of estimates assumes that by 2030 5 Mt H2/year could be imported by undersea
pipelines, while the higher end assumes that the pipelines cannot be commissioned in this timeframe and thevast majority of imported hydrogen will be shipped in the form of ammonia, building on existing ammonia
infrastructure. Shipping of liquefied hydrogen is not expected to make a significant contribution by 2030. It
assumes that hydrogen will be produced from renewable electricity installations constructed for the purposeof electrolysis, which is broadly in line with proposed EU regulations but may lead to a slight overestimationof costs. Capital requirements for pipelines, hydrogen storage, new ships, ammonia production and someammonia cracking are included.

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3Figure 8.19 ⊳ Cost shares of a possible investment package to secure 20 Mt H2
for the European Union from local and imported supplies by 2030
Costs by location

Costs by value chain component
Renewables
Infrastructure (incl. storage)

14%
2%

40%

Electrolysers
Ammonia conversions

19%

CCUS

25%

46%
54%

European Union assets
Assets outside the EU

IEA. CC BY 4.0.

Investments to supply hydrogen to reduce oil and gas demand in the European Union aremostly needed in renewable electricity projects and half would fund non-EU assets
Notes: CCUS = carbon capture, storage and utilisation; EU = European Union. Ships and pipelines entering theEuropean Union are considered as assets outside the European Union.

The European Union is not alone in pursuing hydrogen and hydrogen‐based fuel imports.
Japan is aiming for a 20% rate of co‐firing imported ammonia at its coal‐fired power plants
in 2030, and this is estimated to require 0.5 Mt H2/year. To back this up, JERA, Japan's largest
electricity generator and a major gas trader, issued a tender for supply up to 0.5 Mt of low‐emissions ammonia (requiring almost 0.1 Mt H2) to Japan’s largest coal‐fired power plantfrom 2027. Korea aims to commercialise 20% ammonia co‐fired power generation by 2030.
Both countries are actively developing partnerships with a range of potential exporter
countries and technology providers. In June 2022, BP took a 40% stake in a project that could
produce 9 Mt/year of low‐emissions ammonia (or 1.6 Mt H2/year) in Australia, with Japanand Korea listed as the primary initial export targets. To be successful, the developers
anticipate that they will need to raise over USD 35 billion.

If all projects under development are successful at raising funds and meeting their schedules,
there would be enough global capacity to export 12 Mt H2/year of low‐emissions hydrogenor its equivalent in hydrogen‐based fuels by 2030, of which 11 Mt H2/year would come fromoutside the European Union (IEA, 2022b). Much of this proposed capacity would be in Chile,
Argentina and Brazil, but there would also be significant amounts in Australia, Denmark,Mauritania and United States. Among Middle East and African countries, the largest
proposed projects are in Egypt, Mauritania, Oman, Saudi Arabia and United Arab Emirates.
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Pipeline of hydrogen trading projects has swelledFigure 8.20 ⊳ Capacity of proposed international hydrogen trade projects
targeting operation by 2030 by exporter or importer country
Imports

Latin America

Exports

Australia
EuropeAfricaNorth America
Middle East
Asia
1

2

3
4
5
6
7
Million tonnes of hydrogen equivalent capacity
IEA. CC BY 4.0.

If all export projects under development proceed, they could supply 12 Mt of low-emissionshydrogen equivalent by 2030, subject to the availability of import infrastructure
Notes: Projects included are those with a named location for the planned import or export facility, such as anexisting port. Proposed exports within regions, such as Europe, are included.

8

Projects seeking to export hydrogen or hydrogen‐based fuels are more numerous and moreadvanced than those for the corresponding import infrastructure (Figure 8.20). Of the
12 Mt H2/year of proposed exports, projects accounting for 2 Mt H2/year have named
potential or agreed off‐takers and a further 3 Mt H2/year cite export to a specific region.
However, there are currently only five ports around the world developing hydrogen importplans. These are for Amsterdam, Brünsbuttel, Rotterdam and Wilhelmshaven in Europe andKobe in Japan.

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Ammonia is emerging as the most common form for the export and import of hydrogen by
sea in 2030. While around half of announced projects have not yet stated a clear preference,ammonia represents over 85% of planned capacity for those that have expressed an
intention to date. Liquefied hydrogen and liquid organic hydrogen carriers are not expected
to take a high share during this decade. While Europe has existing infrastructure which makes
it possible to import several million tonnes of ammonia each year for chemical uses,
significant additional capacity is needed if meaningful amounts of low‐emissions hydrogenare to be exported to Europe as ammonia. Expanding existing facilities would be a much
lower cost option for providing capacity expansion than greenfield developments. Undersea
pipelines for transporting hydrogen to the European Union are also under discussion, withGermany and Norway exploring how soon such infrastructure could connect their countries.

Unlocking project investment requires global co‐ordination
New contractual relationships need to be established throughout the low‐emissionshydrogen value chain if the challenge of scaling up is to be met. Robust contracts that canremain in place for 10‐20 years or more are essential to unlock the investment required.
There are very few precedents or standards for these kinds of contracts, but they will need
to be put in place and aligned to enable multiple billion dollar projects to proceed in parallel
and to avoid mismatches between supply, distribution and demand.
Launching a new hydrogen value chain may need as little as three contractual relationships(two purchase agreements and one engineering, procurement and construction [EPC]
contract) or as many as 20 (seven purchase agreements and 13 EPC contracts), dependingon the need for new energy inputs and the intermediaries involved in trade. Most of thelargest integrated projects to date have simple value chains, for example with projects being
developed at fertiliser or refinery sites with existing hydrogen demand, which suggests thatit may be desirable to minimise the number of contracts as far as possible.
At one end of this value chain is the manufacture of electrolysers, equipment for CO2 captureand devices for hydrogen transport and storage. Investors in the companies and projects thatwill deliver the required factory output, including the supply of raw materials such as
platinum for catalysts, have shown interest in the initial prospects of this business, but much
more capital will be needed to achieve the 260 GW of electrolyser installations in 2030 in the
APS, given that manufacturing capacity is currently around 8 GW per year. The value chain
includes the installation of hydrogen production capacity and upstream contractual
relationships with renewable electricity suppliers, power grid operators, electricity markets,
gas suppliers, CO2 storage companies and EPC firms. For hydrogen trade, the value chain
expands to include the construction and operation of new port infrastructure, buffer storage,
pipelines, ships, refuelling stations and plants to convert the hydrogen into a more readilytransportable commodity (and potentially back to hydrogen). At the other end of the value
chain are the off‐take contracts agreed with the users of low‐emissions hydrogen thatguarantee revenue: all the preceding steps ultimately depend on these. Many users will alsoneed to make significant investments in new equipment and procedures to switch from otherfuels, for which they will be reliant on new manufacturing facilities for tanks, meters,
burners, turbines and other hydrogen‐specific apparatus.

Standards for guaranteeing that hydrogen‐based commodities meet environmental criteria
have emerged as an especially important issue for project developers. Investors seek upfront
certainty that output from a project will be valued by hydrogen users, but the value to users
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Governments around the world have critical roles to play in facilitating co‐ordinated andtimely investments, and this means in particular setting clear policy frameworks that arecompatible across borders. This does not mean that governments have to dictate the precise
format of the traded hydrogen products, but rather that agreed standards are needed forenvironmental criteria, and that policies are needed to incentivise end‐users to commit tolong‐term purchases and manage off‐take risk. In both areas, international co‐ordination isessential if cross‐border trade is to emerge as implied by government pledges.

depends on whether the product meets their regulatory obligations and market incentives.
Regulatory obligations could include requirements to meet a share of total hydrogen demandwith low‐emissions hydrogen, something that is envisaged by the draft EU Renewable Energy
Directive. Market incentives could come, for example, from manufacturers that anticipate
charging a premium for a car made from low‐emissions steel or which have set emissions
targets for financial or ethical reasons, or from government contracts or CO2 pricing.
Emissions requirements for selected hydrogen labels andprogrammes

Jurisdiction

Label

Publication
year

Requirements

PurposeEuropean
Union

Renewable
fuel of non‐biologicalorigin2022(proposal
not yetadopted)70% lower life cycle GHG emissions
than an equivalent fossil fuel(3.4 kg CO2‐eq/kg H2) delivered to acustomer, or 80% after 2026 if used forelectricity or heat. Only electrolysis
hydrogen from renewables is eligible,
and must prove additionality.

Eligible fuels(including hydrogen‐based fuels) cancontribute to national
renewables targets.

EuropeanUnion

EUtaxonomy‐alignedhydrogen2022

73.4% lower life cycle GHG emissions
Guide investments
than an equivalent fossil fuelinto climate change(3 kg CO2‐eq/kg H2 life cycle emissions mitigation.
at the point of production, or 70% for ahydrogen‐based fuel).

United States

Cleanhydrogen2022

Less than 4 kg CO2‐eq/kg H2 life cycle
GHG emissions up to the point of
production.

Eligibility for funding
instruments, withlower emissions
eligible for more
support.

Victoria,
Australia in
partnershipwith Germany

Zero‐carbonhydrogen2020

Hydrogen comes solely fromrenewable sources.

To receive
guarantees of origin
from the Smart
Energy Council andHydrogen Australia.

Independent

Carbon‐neutralhydrogen2020

Zero emissions, including upstream,
net of offsets. For hydrogen produced
from fossil fuels, 50% or more of theCO2 must be stored and any solidcarbon permanently secured.

Accreditation undervoluntary TÜV
Rheinland Standard
H2.21.

Independent(originally
funded by theEuropeanCommission)

Low‐carbonhydrogen2017

60% lower life cycle GHG emissions
than hydrogen from natural gas,
excluding emissions from equipment
manufacturers (4.4 kg CO2‐eq/kg H2).

Accreditation undervoluntary CertifHy
system.

There is still a long way to go on the development and agreement of internationallyrecognised standards. Several governments and commercial entities have proposed labels
for various purposes, but they are not consistent with one another (Table 8.5). Not all of themethodologies for these standards and labels take a life cycle approach to emissions
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Table 8.5 ⊳accounting. Moreover, none have so far tackled the question of how to account for the
potential leakage of hydrogen itself. This may emerge as an important point: there is someevidence that fugitive emissions of hydrogen and other pollutants will need to be carefully
avoided if the desired climate benefits of low‐emissions hydrogen or ammonia at large scale
are to be realised (BEIS, 2022; Wolfram et al., 2022).
Investments that will lead to trade of low‐emissions hydrogen and hydrogen‐based fuels
between countries this decade will rely on international recognition of standards. Regionsthat expect to be first‐movers in importing large volumes will have some flexibility todetermine standards, but dialogue with exporters will be essential: a project developer
deciding whether to contract with off‐takers in the European Union, Japan or Korea will be
influenced by the risks related to meeting emissions criteria. Importers have the opportunity
in the near term to work on ensuring compatibility between regimes.
Reliable long‐term demand for low‐emissions hydrogen will be the main driver of investment
for scaling up. In the first decade of hydrogen sector scale up, this demand is likely to beunderpinned to a significant extent by government funding support. In the longer term, thefocus is likely to shift to regulatory standards and fiscal penalties. Two instruments inparticular are currently being explored in Europe: carbon contracts for difference (CCfD) andso‐called double auctions. In the Netherlands, the first CCfD for an electrolyser project wasawarded in 2021: it guarantees that the government will top up any difference between themarket price and the cost of producing the low‐emissions product for 15 years. In Germany,
the H2Global double auction platform, funded by the government, was launched in 2021: itwill offer ten‐year contracts to the cheapest suppliers of hydrogen from renewable electricity
and the buyers with the highest willingness to pay. As part of the REPowerEU Plan, theEuropean Commission is exploring adopting these two types of mechanisms at the EU level.
In addition to standards and demand creation, a range of other measures will be needed tostimulate investment. These include safety regulations, infrastructure funds, permitting
processes and risk management tools such as concessional debt and insurance. In all cases,
reaching international agreement is likely to take several years and there may be a need forrisk management provisions for final investment decisions before such agreements arereached. For example, the hydrogen provisions in the proposed revision of the EU Renewable
Energy Directive, which include sectoral targets, may not materialise in full or, if agreed, may
not be transposed into national law before 2025.

Is natural gas still a transition fuel in emerging market and developing
economies in Asia?

The traditional case for natural gas in emerging market and developing economies is that it
is a flexible and versatile source of dispatchable energy, supporting the rapid build up of
renewables while underpinning a transition away from coal. Gas can be employed in the
power sector as a back‐up for renewables and help to balance grids in real time. The coal, oilor biomass for process heat used by small‐ and medium‐scale industries can also be
progressively replaced by natural gas, which brings with it advantages such as improved
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8.8

efficiency and cleaner air, while reducing the cost of operating flexibly. Investments intransmission and distribution grids can allow gas to meet demand for cooking fuel and water
heating. In more temperate parts of the developing world, natural gas can also help meetseasonal energy demand.
The strains on global natural gas supply that have been emerging since 2021 cast doubt onthese propositions. The surge in LNG prices arising from high demand in Europe has pulled
supply away from price‐sensitive markets such as Pakistan and Bangladesh, leading toshortfalls in the power sector and industrial demand destruction in those countries. Althoughsome markets have been somewhat shielded from volatility thanks to long‐term supply
contracts with fixed volume commitments and prices that are linked to oil, the price of gas
for end‐users in emerging markets in Asia can be expected to rise by about 55% in 2022
compared with the five‐year average (Figure 8.21). There is limited fiscal headroom inemerging markets to sustain interventions that shield consumers from higher prices, such as
caps on tariff increases or subsidies for bills targeted at lower income households, and so theprice increases seen in 2022 have pushed up the costs of electricity as well as a wide range
of industrial products and processes, stoking inflation and aggravating a cost‐of‐living crisis.
Increased climate ambition in some emerging market and developing countries in Asia
implies that natural gas now faces existential questions about its long‐term future. In thissection we explore the role of natural gas in this region in the APS, a scenario which reflects
recent net zero emissions pledges announced in some of the major growth markets in Asia –China, India, Malaysia, Singapore, Thailand and Viet Nam.

8

Figure 8.21 ⊳ End-user prices for natural gas by sector emerging market
and developing economies in Asia

USD/MBtu

China

India

Southeast
Asia

20

Rest ofdeveloping Asia
Additionalin 2022

16

Average,
2016‐21

12
8

Buildings

Power

Industry

Buildings

Power

Industry

Buildings

Power

Industry

Buildings

Power

Industry

4

IEA. CC BY 4.0.

challenging the affordability of gas in price-sensitive regions

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End-user prices for natural gas are estimated to increase by more than 55% in 2022,

Can emerging gas markets in Asia continue to thrive on imports?
In 2010, emerging market and developing economies in Asia were, in aggregate, net gas
exporters. Flat or declining production in mature gas fields in countries such as Indonesia andMalaysia, along with strong demand growth in China and India, meant gas imports rose
quickly to cover 30% of total gas demand by 2021. In the APS, import dependence increases
further to over 40% by 2030 (Figure 8.22).
Figure 8.22 ⊳ Natural gas supply balance in emerging market
and developing economies in Asia in the APS, 2010-2050

bcm

China

India

Other Asia

Southeast Asia

400
300
200
100

Production for domestic use

2050

2010

2050

2010

2050

2010

2050

‐ 100

2010

0

Remaining supply balance (net trade)
IEA. CC BY 4.0.

Demand growth in emerging market and developing economies in Asia
requires a large increase in gas imports and associatedThis increasing reliance on natural gas imports – especially LNG – has recently beenchallenged by high prices. There is around 200 bcm per year of existing LNG import capacity
in the region (of which 45% is in China). A further 120 bcm per year is under construction. To
meet the requirements of the APS, a further 85 bcm per year of import capacity is requiredby 2030. To date, however, potential new entrants to the LNG market, such as the Philippines
and Viet Nam, have yet to secure long‐term contracts for supply that could underpin theconstruction of LNG regasification terminals. Utilities in the region have low credit ratings
and the limited ability of off‐takers to absorb higher prices brings with it significant
commodity price risk, particularly against the background of a stronger US dollar. Countries
such as Indonesia, Myanmar and Viet Nam are attempting to contract floating storage andregasification units, which are cheaper and quicker to build than land‐based terminals andcan be flexibly redirected to areas in need of short‐term gas supply. However, Europe’s callon these units to meet near‐term LNG supply has tightened supply chains and increased
competition.
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investment in LNG terminals and domestic gas networks

How resilient is natural gas demand?
It is possible to look past the current market turbulence and make a case that natural gas
demand in emerging and developing economies in Asia might turn out to be quite resilient,at least for the next decade. In the APS, natural gas satisfies nearly 20% of total energy
demand growth in these economies between 2021 and 2030 – a higher percentage than in
the previous decade. Although coal is widely viewed as a cheaper and more readily available
alternative to natural gas in several parts of Asia, its own supply dynamics are challenged bya lack of upstream investment and constraints on access to finance. Prices have also moved
higher: thermal coal import prices averaged around USD 60/tonne in 2020, but doubled in
2021 and then rose again to an average of around USD 200/tonne in the first‐half of 2022.
The extent to which consumers feel the effects of natural gas price increases also varies
widely between countries and sectors. Cheaper domestic gas is sometimes allocated to
specific consumer groups, as in India, or regulated at a price that is capped at a maximum
level regardless of changes in wholesale prices, as in Indonesia. Through tariff decisions anddifferent tax regimes, the price charged for natural gas can fall below the cost of import or
production, keeping demand resilient in certain segments, as in parts of India’s city gas
distribution sector.
Despite gas‐fired power plants being more exposed to changes in wholesale gas prices, theyremain a relatively cheap thermal plant type to build and are able to operate flexibly. In 2021,
final investment decisions for new gas‐fired capacity reached 20 GW, 15% above the five‐
year average, and growth remained strong into 2022. Although the prospects for coal‐to‐gas
switching have been adversely affected by higher gas prices, it would be technically possible,
for example, for one‐third of coal‐fired power output in Southeast Asia to be substituted byexisting gas‐fired power capacity (which totals around 100 GW and currently operates at a
45% annual load factor). Doing this would avoid around 120 Mt CO2 emissions, equivalent to
22% of emissions from coal‐fired power plants in Southeast Asia (IEA, 2022c).

8

An increasing population and strong economic growth sustain the increase in natural gas
consumption in emerging market and developing economies in Asia over the next decade,notably in industry, despite the near‐term risks brought about by the recent supply squeeze.
As prices come down from the mid‐2020s, these markets see a big increase in natural gas
Chapter 8 | Outlook for gaseous fuels405

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In the APS, around 90 GW of new natural gas‐fired power generation capacity comes online
in emerging market and developing economies in Asia between 2021 and 2030, an increaseof over 20%. Natural gas‐fired generation increases at a slightly slower pace than generation
capacity, reaching 1 200 TWh by 2030, or 25% more than in 2021. This reflects increasing use
of natural gas capacity as a flexible tool to balance electricity grids rather than as a baseload
source of power supply (see Chapter 4, section 4.5). Using natural gas in this way requires
flexible contracting arrangements for LNG supplies and additional investment in gas storage.
In China, the 15 bcm of storage capacity equates to less than 5% of annual gas consumption,
despite growing seasonality of demand (although there are ambitious plans to increasestorage capacity to 50‐60 bcm by 2025). Large‐scale gas storage facilities are virtually non‐existent in most other parts of Asia.

use by 2030 as a result of coal‐to‐gas switching, and this helps countries with net zero
emissions targets to rapidly transition away from coal. With a clouded outlook for the use ofnatural gas in transport (Box 8.1), industry remains the anchor for demand growth and the
focal point for large‐scale infrastructure investment in LNG import capacity, storage andonshore transmission and distribution grids. In the APS, gas demand in industry in emerging
gas markets in Asia, not including China, is over 60% higher in 2050 than in 2021.
Figure 8.23 ⊳ Natural gas demand in emerging market and developing

bcm

economies in Asia in the APS
China

400

India

Other Asia

Southeast Asia

300
200

Buildings

2050

2010

Industry

2050

2050

Power generation

2010

2010

2050

2010

100

Other
IEA. CC BY 4.0.

In the APS, natural gas demand peaks before 2040 inemerging market and developing economies in Asia

After 2030, natural gas demand growth slows in the APS for a number of reasons(Figure 8.24). Renewables meet all of the growth in power generation between 2030 and
2050, while electricity and the direct use of renewables meet all of the growth in buildings
sector energy demand. With the exception of northern China, growth markets for gas in Asia
do not have significant need for seasonal heating in buildings, and electricity and solar‐basedheating offers a cost‐competitive alternative to the use of gas in households for cooking andhot water. Between 2030 to 2050 in industry, the growth of electricity and low‐emissions
fuels such as hydrogen helps to push the share of natural gas in total demand to below 9%.
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Ultimately, however, the prospects for natural gas in emerging market and developing
economies in Asia have a limited duration. Although the trajectory varies, demand peaks inall emerging gas markets in Asia before 2040 in the APS (Figure 8.23). The share of natural
gas in total power generation remains flat in the years ahead, but then falls to less than 5%
by 2050 as other sources of power system flexibility drop in price and step in to replace gas.
The levelised cost of electricity (LCOE) of battery storage combined with utility‐scale solar –a benchmark of the competitiveness of renewables against dispatchable thermal capacity –drops by around 50% between 2021 and 2050, falling below the LCOE of a new combined‐
cycle gas turbine.

Figure 8.24 ⊳ Drivers of change in natural gas demand in emerging market

bcm

and developing economies in Asia in the APS
200

Activity
Switching:
Coal/oil to gas
Gas to electricity
Gas to low‐emissions fuels
Gas to renewables
Net change

100
0
‐100
‐200
‐300

2021‐302031‐402041‐50
IEA. CC BY 4.0.

Population and economic growth increase natural gas demand for a while, but
renewables, low-emissions fuels and electrification diminish gas demand in the long termBox 8.3 ⊳Is the golden age of natural gas over?

8

The IEA released a special report in 2011, Are We Entering a Golden Age of Gas?, which
explored the potential for a golden age of natural gas based on supportive assumptions
about the availability and price of natural gas and about demand‐side policies that could
support its use in the emerging world (IEA, 2011). More than a decade later, the growthin global natural gas consumption to 2021 turns out to have been very much in line withthe projections made in that report. In developing Asia, natural gas demand from2010‐21 ended up being 8% higher than projected in the report. However, current longer
term projections indicate a diminished role for natural gas overall and particularly indeveloping Asia.

The competitiveness of natural gas, however, has come under pressure, and competition
from low cost renewables such as solar PV and wind has now narrowed the space for
growth in natural gas. There are also reasons to think that the age of supportive policies
for natural gas may be drawing to a close. Near‐term supply scarcity and energy security
concerns have not only driven up natural gas prices but have also sparked long‐term gas
affordability concerns, and net zero emissions pledges have focussed minds on an
eventual phase out of unabated natural gas.
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The key pillars for growth in the Golden Age scenario were the competitiveness of natural
gas as large volumes of shale gas were developed in the United States, strong economic
growth across Asia, and supportive policies which valued the advantages that natural gas
had compared with alternative fuels such as coal, oil or traditional biomass, notably interms of lower emissions and cleaner air.

The outlook for natural gas in emerging market and developing economies in Asia by
2035 is about 310 bcm lower in the STEPS this year than it was in the Golden Age of Gas
Scenario in 2011 (Figure 8.25). In the APS, it is lower by 420 bcm. This change in theoutlook to 2035 is not confined to developing Asian markets. For example, the projectionof combined European Union and United Kingdom natural gas demand by 2035 in the
APS is 45% lower than it was in the Golden Age of Gas report in 2011, reflecting current
market concerns, increased climate ambitions and revised assumptions about economic
growth.
Figure 8.25 ⊳ Natural gas demand in emerging market and developing

bcm

economies in Asia by WEO-2022 scenario and outlook of theGolden Age of Gas Scenario in 2011
1 200

WEO‐2011
Golden Age of Gas

1 000

WEO‐2022
STEPS
APS

800
600
400
200

2010

2021

2035
IEA. CC BY 4.0.

The contribution of natural gas to meet energy demand in developing Asia
from now to 2035 appears less significant than projected a decade ago

408International Energy Agency | World Energy Outlook 2022

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While some may cheer the clouded outlook for natural gas, it remains an important partof the energy system in developing Asia. There is also a risk that declining prospects forgas may mean that emerging market and developing economies in Asia hold on to theircoal‐fired power generation for longer, resulting in unfavourable emissions outcomes(unless there is a historic acceleration in investment in CCUS). This has happened before.
In energy‐hungry India and Southeast Asia, for example, a challenging environment fordomestic gas production between 2010 and 2021 meant natural gas became lesscompetitive with coal. The result was around 30 bcm of natural gas demand lost to gas‐
to‐coal switching, leading to a 50 Mt CO2 increase in emissions which would have been
avoided if natural gas had been used instead.

Chapter 9
Outlook for solid fuels
Phase down postponed?
S U M M A R Y
 Global coal demand rebounded strongly in 2021 to 5 640 million tonnes of coalequivalent (Mtce) as economies recovered from the pandemic and coal‐fired power
generation reached a historic high in 2021. Both China and India have boosted
investment in domestic coal production, but global production struggled to keep pacewith demand increases, causing coal prices to surge. Russia – the world’s third‐largest
coal exporter – and its invasion of Ukraine complicated coal market dynamics andbrought additional pressure on prices.

 The outlook for coal is heavily dependent on the strength of the world’s resolve toaddress climate change. In the Stated Policies Scenario (STEPS), coal demand declines
gradually. In the Announced Pledges Scenario (APS), it declines about 20% below
current levels by 2030, and 70% by 2050; coal demand peaks in China in the early2020s and in India in the late 2020s. In the Net Zero Emissions by 2050 (NZE) Scenario,
demand falls 45% by 2030 and 90% by 2050.

 There is very limited use of carbon capture, utilisation and storage (CCUS) with coal in
the STEPS. Around 500 Mtce of coal consumed in 2050 is equipped with CCUS in both
the APS and NZE Scenario, corresponding to around 30% of coal demand in the APS
and more than 80% in the NZE Scenario in 2050. Unabated coal use drops by 99%
between 2021 and 2050 in the NZE Scenario.

 Following the European Union ban on Russian imports, a short‐lived increase in coalconsumption in Europe is supplied from a variety of sources including South Africa
and Colombia. The Asia Pacific region accounted for more than three‐quarters ofglobal coal imports in 2021 and this share is set to rise. Despite efforts to increase
domestic production, India becomes the world’s largest coal importer in the STEPS in
the mid‐2020s, while, by far, China remains the largest producer and consumer. In the
APS, coal trade falls by 60% to 2050; in the NZE Scenario, it falls by 90%.

 Nearly 25 exajoules (EJ) of biomass (equivalent to 830 Mtce) was used for traditional
cooking and heating in 2021, mainly in developing economies in Africa and Asia. This
falls by 20% to 2030 in the STEPS, which still leaves around 2 billion people without
access to clean cooking. In the APS, the traditional use of biomass falls by more than
60% to 2030. In the NZE Scenario, universal access to clean cooking is achieved by2030 and the traditional use of biomass is fully phased out.
power generation, and conversion into liquid and gaseous biofuels. This increases by2030 in each scenario, rising by 30% in the STEPS, by 50% in the APS, and by just over
60% in the NZE Scenario.

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 Around 35 EJ of modern solid bioenergy was consumed in 2021, mainly for heat,Coal demand declines in all scenarios, with a faster
Future coal use depends
phase-down in advanced economies than in emerging
heavily on efforts to address market and developing economies.
climate change
China remains by far the most influential market
for coal throughout the outlook.

2021

5 640 Mtce
Advanced economies

Emerging market anddeveloping economies

STEPS 2050

3 830

56%
China

APS 2050

49%

1 610

NZE 2050

49%

Steam coal is mainly used forheat and electricity where it isincreasingly replaced by renewables.
Coking coal is mainly used in steel
making where there are fewer readily
available alternatives.

NZE 2030

Traditional use of biomass falls as people gain access to clean
cooking, while modern bioenergy grows, mainly in the power sector
and for biofuel production. In the NZE Scenario, bioenergy resources
are responsibly managed and do not compete with other land uses.

2021

2030

Coking
1 030 Mtce

60 EJ

66

-50%

80

-9%
62

-22%

2050

APS

-12%

Traditional use of biomass gives
way to modern solid bioenergy

-17%

58

-30%

87

NZE

APS 2030

STEPS 2030

Steam
4 560 Mtce

61%

STEPS

Steam coaldeclines further
and faster thancoking coal

540

Traditional use of biomass
Conversion losses

Buildings and agriculture
IndustryPower

74

Introduction
Recent developments have dealt a blow to the idea that global coal demand might soon
subside. The drop in coal demand in 2020 was more than offset by a strong rebound in 2021,
taking it very close to its all‐time high. In advanced economies, where coal use had been
declining, demand increased by nearly 10%. In emerging market and developing economies,
which account for just over 80% of global coal use today, demand rose by 5%.
Coal production in 2021 struggled to keep pace with one of the largest ever annual increases
in demand. Markets have been further upended by Russia’s invasion of Ukraine. Russia was
responsible for around half of the coal imports in the European Union in 2021, but thattrading relationship ended with the EU ban on Russian coal imports. Meanwhile there havebeen limited short‐term fuel switching opportunities to ease demand pressures. The overall
result is that global coal prices reached historic highs in the first‐half of 2022.
Coal‐fired power generation reached a historic high in 2021, with China, India and Southeast
Asia all setting new records. So far in 2022, record high natural gas prices have led togas‐to‐coal switching in a number of markets, including in the European Union, and a numberof coal power plants have increased utilisation or been granted lifetime extensions.
Global coal supply increased by over 5% in 2021, even though production was hampered fora number of producers by supply chain disruptions, Covid‐19 containment measures andadverse weather conditions. The largest increase was in China, where production rose byaround 160 million tonnes of coal equivalent (Mtce) (a 6% increase), followed by the UnitedStates with 65 Mtce (18%) and India with 50 Mtce (13%). China and India are looking toincrease investment in domestic supply, but difficulties securing financing and insurance are
increasingly restricting investment in new coal mines in other countries.

9

Solid bioenergy accounts for 10% of global energy supply today. Just over 40%, around
25 exajoules (EJ), is traditional biomass for cooking and heating, which is used by around
2.4 billion people worldwide that do not have access to clean cooking facilities. The
remainder, around 35 EJ, is modern solid bioenergy, which is mainly used to generate
electricity, provide heat for industry and buildings, and as feedstock for biofuels.

The chapter highlights the key findings of our updated projections. Much more detail is
included in a forthcoming World Energy Outlook Special Report, Coal in Net Zero Transitions:
Strategies for rapid, secure and people‐centred change to be released in November 2022.
Against the backdrop of current strong coal consumption and a reappraisal of energy security
concerns, the report examines how policy makers and other stakeholders can implement andfinance a reduction in coal emissions without compromising electricity security or economic
growth, while taking into account the social consequences of change.
Chapter 9 | Outlook for solid fuels

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The outlook for coal and other solid fuels depends on government policies and different
assumptions about how these will develop. This yields very wide variations in the outlook forsolid fuel demand. Coal consumption falls in each of our scenarios; it declines by around 10%
to 2030 in the Stated Policies Scenario (STEPS), by 20% in the Announced Pledges Scenario(APS), and by 45% in the Net Zero Emissions by 2050 (NZE) Scenario.

Scenarios
9.1

Overview

Table 9.1 ⊳Global coal demand, production and trade, and solid bioenergy
use by scenario (Mtce)
STEPS

APS

NZE

2010

2021

2030

2050

2030

2050

2030

2050

World coal demand

5 220

5 644

5 149

3 828

4 539

1 613

3 024

539

Power

3 108

3 642

3 174

2 086

2 852

938

1 685

306

Industry

1 690

1 629

1 684

1 520

1 426

640

1 159

206

Other sectors

423

373

291

222

261

36

180

28

Share of demand with CCUS

0%

0%

0%

1%

1%

31%

3%

89%

Advanced economies
Emerging market anddeveloping economies

1 585

1 024

526

297

375

127

267

84

3 636

4 620

4 623

3 532

4 164

1 486

2 762

455

World coal production

5 235

5 825

5 149

3 829

4 539

1 613

3 024

539

Steam coal

4 069

4 560

4 026

2 954

3 538

1 177

2 271

407

Coking coal

866

1 030

936

736

855

381

716

120

Peat and lignite

300

235

187

139

146

56

38

12

1 512

1 124

729

590

522

186

362

99

3 723

4 702

4 420

3 239

4 017

1 427

2 662

443

Advanced economies
Emerging market anddeveloping economies
World coal trade

948

1 135

999

958

859

470

539

137

Trade as share of production

18%

19%

19%

25%

19%

29%

18%

25%

Coastal China steam coal price

142

155

81

67

66

56

52

44

Solid bioenergy (EJ)

49

60

66

80

62

87

58

74

Traditional use of biomass

25

24

20

18

9

6

‐

‐

Modern bioenergy and losses

24

36

46

62

53

81

58

74

Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario. Coastal China steam coal price reported in USD (2021)/tonne adjusted to 6 000 kcal/kg. See Annex
C for definitions. Solid bioenergy losses are conversion losses for solid, liquid and gaseous biofuels production.

Global coal demand is set to rise slightly in 2022 as countries look to meet rising energy
demand while struggling with lower economic growth. The speed of the coal decline in
subsequent years depends on the stringency with which countries pursue climate andenvironmental targets.

1
Steam coal is mainly used for heat production or steam‐raising in power plants and, to a lesser extent, inindustry; coking coal is mainly for steel making as a chemical reductant and a source of heat.

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In the STEPS, global coal demand falls by around 10% from 2021 to 2030, with a near 50%
decline in advanced economies and a slight increase in emerging market and developing
economies (Figure 9.1). Steam coal production falls by more than 10% to 2030 (Table 9.1);
declines in coking coal are smaller, mainly because of increases in steel production in India.1

The European Union halts coal imports from Russia and replaces them with imports from avariety of sources including South Africa and Colombia. This change in the source of imports
takes place amid a backdrop of about a 50% cut in total coal imports by the European Union
in the period to 2030. By 2030, more than 80% of global coal trade takes place in the PacificBasin (up from about 75% in 2021). The traditional use of biomass falls by 20% to 2030 as aresult of efforts to move to cleaner cooking fuels, but nearly 2 billion people worldwide still
rely on it for cooking and heating in 2030. The use of modern solid bioenergy increases by
30% to 2030. Between 2030 and 2050, the use of coal in industry falls by less than 10%, but
its use in the power sector drops by 35% as older coal‐fired power plants are retired and newrenewables capacity is preferred in many cases to new coal‐fired power plants.

EJ

Figure 9.1 ⊳Coal and solid bioenergy demand by scenario
2030

2040

2050

STEPS APS NZESTEPS APS NZESTEPS APS NZE

250
200
150
100
50

2010 2021
Unabated coal

Abated coal

Modern solid bioenergy

9

Traditional use of biomass
IEA. CC BY 4.0.

Coal demand falls and modern solid bioenergy increases in all scenarios,
but the pace and scale of change differ dramaticallyNote: EJ = exajoule; STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero
Emissions by 2050 Scenario.

In the NZE Scenario, global coal demand falls by 45% to 2030, with a 75% decline in advanced
economies and a 40% decline in emerging market and developing economies. Somecoal‐fired power plants are retrofitted with carbon capture, utilisation and storage (CCUS) or
Chapter 9 | Outlook for solid fuels

413

IEA. CC BY 4.0.

In the APS, global coal demand falls by 20% to 2030 and by 70% to 2050. Demand in advanced
economies declines by 65% to 2030 as coal use in the power and industry sectors falls rapidly.
Coal demand peaks in China in the early 2020s and in India in the late 2020s. The traditionaluse of biomass falls by more than 60% to 2030, mainly as a result of reductions in China,
India, Kenya and Nigeria. The use of modern solid bioenergy increases by 50% to 2030 andby 130% to 2050, with large increases in the power and industry sectors, and in biofuels
conversion.

fire coal with low‐emissions fuels, such as bioenergy or ammonia, to cut emissions andreduce the need to retire existing plants before the end of their lifetimes. Unabated coal use
drops by 99% between 2021 and 2050, and in 2050 just under 90% of remaining coal power
generation comes from plants equipped with CCUS. Universal access to clean cooking isachieved in 2030, and this brings to an end to the traditional use of biomass. Modern
bioenergy demand increases at a similar rate to the APS, but a higher share is used in the
power sector and less is transformed into biofuels.

9.2

Coal demand

Table 9.2 ⊳Coal demand by region and scenario (Mtce)
STEPS

APS

2010

2021

2030

2040

2050

2030

2040

2050

North America

768

389

107

50

42

80

37

30

United States

716

363

91

32

26

64

24

17

Central and South America

37

46

40

52

60

28

25

20

Brazil

21

25

23

27

29

16

14

12

Europe

539

369

229

176

167

157

99

72

360

238

125

69

56

79

35

20

156

152

148

132

131

119

59

30

144

129

113

87

78

95

34

6

5

5

8

11

12

7

8

9

Eurasia

203

222

172

158

160

162

131

121

Russia

151

166

114

104

102

113

100

95

Asia Pacific

3 513

4 460

4 444

3 816

3 258

3 986

2 449

1 332

China

2 565

3 157

2 974

2 342

1 866

2 691

1 603

789

India

399

614

773

738

671

704

420

243

Indonesia

45

102

136

164

160

124

90

41

Japan

165

143

103

87

62

97

58

35

Rest of Southeast Asia

76

166

201

243

263

171

138

110

5 220

5 644

5 149

4 394

3 828

4 539

2 808

1 613

European Union
AfricaSouth Africa
Middle EastWorld

China is the world’s largest coal consuming country today. It accounts for about 55% of global
coal consumption (Table 9.2). Coal demand in China increased by an average of 100 Mtce
each year between 2000 and 2020 as it rapidly expanded its power and industry sectors. Thiswas equivalent to adding the current coal consumption of Indonesia every year. Coal demandin China rose again by around 2% in 2020, despite the impacts of the Covid‐19 pandemic, andby a further 4% in 2021. India is the world’s second‐largest coal consumer today. It accounts
for just over 10% of global coal consumption. Coal demand in India rose rapidly between
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Note: See Annex C for definitions.

2010 and 2019, mainly as increases in electricity demand were largely met through coal‐fired
power. Coal use in India dropped by 7% in 2020 due to the pandemic, but increased by 13%
in 2021, therefore already surpassing 2019 levels.
Advanced economies consumed around 1 000 Mtce of coal in 2021, accounting for just under
20% of global coal demand. Three‐quarters of this was used in the power sector. Demandfell by around 15% in 2020: it then increased by 10% in 2021 as economies rebound after the
pandemic, but it remains below 2019 levels. In 2022, Russia’s invasion of Ukraine has led anumber of European countries to delay the retirement of coal‐fired power plants, reconnect
previously retired units to the grid, and to temporarily expand coal use to reduce natural gas
consumption.

Demand trends to 2030
Figure 9.2 ⊳Change in coal demand by scenario, 2021-2030

Mtce

Advanced economies

Emerging market and developing economies

500
0
‐ 500
‐1 0009‐1 500‐2 000

STEPS
Power

APS

NZE
Industry

STEPS
Other

APS

NZE

Net change
IEA. CC BY 4.0.

Outlook for coal in emerging market and developing economies
varies much more by scenario than in advanced economies
Notes: Mtce = million tonnes of coal equivalent. Other includes buildings, agriculture and other energy sector.

In the APS, demand for coal in the power sector in advanced economies falls by 80% to 2030
as more renewables are deployed, mostly solar PV and wind. Coal‐fired generation capacity
drops from 520 gigawatts (GW) in 2021 to 210 GW in 2030, and coal plants in 2030 are mainly
used to provide flexibility: their average utilisation drops from 50% to 30%. Around 25 GW
of coal‐fired capacity is retrofitted and repurposed to co‐fire ammonia and bioenergy by
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In advanced economies, solar PV and wind replace a large share of coal‐fired power
generation in the STEPS. Coal use in power generation declines by 60% between 2021 and
2030 (Figure 9.2). More than 200 Mtce of coal is consumed in industry today in advanced
economies, and this remains broadly constant through to 2030.

2030. Coal use in industry falls by 20% to 2030, in part reflecting an increase in the productionof near zero emissions primary steel and near zero emissions clinker for use in cement.
In China, around 60% of the 3 150 Mtce of coal consumed today is in the power sector and
30% in industry. In the STEPS, there is a small increase in coal demand to the late 2020s
followed by a decline to around 3 000 Mtce in 2030. Coal use in power generation and in theiron and steel sub‐sectors peaks in the late 2020s as electricity generation from renewables
increases and as more electric arc furnaces are deployed. These reductions are partly offset
by increases in coal use in the chemicals industry and in the production of synthetic fuels.
Coal use in the buildings sector, which accounts for just under 5% of total demand today,
falls by 80% to 2030 in response to policies to reduce air pollution. In the APS, coal demandin China peaks in the mid‐2020s and declines to 2 700 Mtce in 2030. Coal use in industry falls
by 20% to 2030 (compared with a 5% reduction in the STEPS) as a result of fuel switching tonatural gas, more electrification and energy efficiency improvements. There are alsoenhanced efforts to reduce coal use in the power sector, which falls by 10% to 2030.
In India, coal demand in the STEPS rises by 25% to 2030. Strong economic growth – theeconomy expands 90% between 2021 and 2030 – brings with it more demand for coal‐fired
power generation and in the use of coal to produce iron and steel and cement. Coal‐fired
power capacity increases from 240 GW in 2021 to 275 GW in 2030, while there is limited useof electric arc furnaces in industry. In the APS, coal demand in India increases by just under
15% between 2021 and 2030, reflecting increased deployment of renewables, improvements
in energy efficiency, and the installation of gas and electricity‐based equipment in industry.
The increase in coal demand in the industry sector is around half of that seen in STEPS, andthe increase in the power sector is about 20% less.
In Southeast Asia, coal demand increases by nearly 30% to 2030 in the STEPS and by justunder 10% in the APS. Growth is driven by increases in electricity demand from the industry
and buildings sectors.
In Africa, coal demand remains broadly constant to 2030 in the STEPS: a decrease in demandin South Africa, led by fuel switching to less polluting alternatives, is largely offset byincreases elsewhere. In the APS, much wider deployment of renewables across the continent
leads to a 20% fall in total coal demand by 2030.
In Russia, coal demand drops by 30% to 2030 in both the STEPS and APS as natural gas andrenewables replace coal use in power generation and industry.

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In the Caspian region, coal demand remains relatively flat in the STEPS and falls by only 10%
through to 2030 in the APS.

Demand trends after 2030

Mtce

Figure 9.3 ⊳Global coal demand by region and scenario to 2050
STEPS

6 000

APS

NZE

100%

4 500

75%

3 000

50%

1 500

25%

2021

2030 2040 2050

Advanced economies
Share of coal with CCUS (right axis)

2030 2040 2050

2030 2040 2050

Emerging market and developing economies
IEA. CC BY 4.0.

Global coal demand decreases to 2050 in each scenario, but at very different speeds.
Nearly 90% of coal use is equipped with CCUS by 2050 in the NZE Scenario
Notes: Mtce = million tonnes of coal equivalent; CCUS = carbon capture, utilisation and storage.

In the STEPS, global coal demand falls to 4 000 Mtce (a 25% drop) between 2030 and 2050
(Figure 9.3). Demand falls by 45% in advanced economies over this period and by 40% in
China. Coal‐fired power plant capacity in China shrinks from 1 140 GW today to 890 GW in
2050, and utilisation drops from 50% to 40%. In India, coal demand peaks in the early 2030s
and then declines gradually, mainly due to rapid deployment of renewables in the power
sector. However, total coal demand in India in 2050 is still around 10% higher than in 2021.
Coal demand in Southeast Asia increases by 60% between 2021 and 2050, driven mainly byincreases in the power, and iron and steel sectors.

9

In the NZE Scenario, coal demand drops to 540 Mtce in 2050, around 90% below the current
level. Unabated coal use drops by 99% over this period; around half of the remaining 60 Mtceof unabated coal consumption in 2050 is used in the iron and steel industry.
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IEA. CC BY 4.0.

In the APS, coal demand declines rapidly after 2030, with a 65% reduction in the power sector
to 2050 and a 55% decline in industry use. Demand in China falls by more than 1 000 Mtce inthe 2030s, a rate of decline that mirrors its rate of increase between 2000 and 2020. China’s
coal‐fired power plant capacity drops to 850 GW in 2050, and its utilisation rate declines to
20% as plants are increasingly used for flexibility rather than base load generation. In India,
coal demand peaks in the late 2020s and falls by 65% between 2030 and 2050. CCUS is
increasingly used in a wide range of sectors and regions across the world: around 10% of coal
power plants worldwide are equipped with CCUS in 2040 and almost 20% in 2050. By then,more than 120 GW of plants worldwide co‐fire ammonia or bioenergy with coal.

9.3

Coal supply

Table 9.3 ⊳Coal production by region and scenario (Mtce)
STEPS

APS
2050

2010

2021

2030

2040

2050

2030

2040

North America

818

478

188

105

106

138

57

32

United States

758

433

156

79

80

115

50

29

79

62

41

42

41

24

10

3

73

58

37

38

37

22

10

3

331

200

126

80

59

79

27

20

220

138

71

29

10

46

10

8

210

212

188

158

171

162

87

47

206

199

162

114

109

138

58

19

Central and South America
Colombia
EuropeEuropean Union
AfricaSouth Africa
Middle East
Eurasia

1

1

1

1

1

0

0

0

309

444

323

307

274

292

245

216

Russia

238

371

265

250

215

239

212

187

Asia Pacific

3 487

4 428

4 282

3 701

3 177

3 843

2 382

1 295

Australia

352

421

408

425

419

304

255

138

China

2 461

3 004

2 808

2 228

1 776

2 554

1 522

733

India

304

447

546

508

436

509

251

109

Indonesia

266

438

393

405

402

364

247

210

Rest of Southeast Asia

52

60

67

70

72

59

52

53

5 235

5 826

5 149

4 395

3 829

4 539

2 808

1 613

World

Notes: Mtce = million tonnes of coal equivalent. See Annex C for definitions.

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Coal production in 2021 struggled to meet rising demand, especially during the first‐half ofthe year, cutting into stock levels and pushing up prices. In China and India, coal shortages
caused in part by transport bottlenecks led to power outages and factory shutdowns. Policies
to ramp up domestic production and reduce coal shortages have been implemented,
facilitated by the existence of large state‐owned production companies. Outside China andIndia, most of the additional coal production in 2021 came from existing mines or reopened
mines that had ceased to operate during periods of low prices: this is a reflection of thelimited investment in new mines that has taken place in recent years.

Supply trends to 2030
Coal supply in the STEPS to 2030 and change by scenario
STEPS

6 000

Change 2021‐30

Mtce

Mtce

Figure 9.4 ⊳4 000‐1 0002 000‐2 000‐3 000
2010

2015

2020

Advanced economies

2025
China

2030

STEPS

APS

NZE

Other emerging market and developing economies
IEA. CC BY 4.0.

Global coal demand falls by 45% to 2030 in the NZE Scenario and this means
there is no need for supply from new coal mines or mine lifetime extensions
Note: Mtce = million tonnes of coal equivalent.

China keeps coal production around the current level of 3 000 Mtce for a number of years
but with coal demand falling as renewables account for an increasing share of power
generation, production declines to around 2 800 Mtce in 2030 (Figure 9.4). In the APS, coalproduction declines more rapidly from the mid‐2020s and supply in 2030 is around 15%
below 2021 levels (Table 9.3).

9India became the world’s second‐largest coal producer in 2021 (in energy terms), overtaking
Australia and Indonesia, and it plans to increase domestic production by more than 100 Mtce
from current levels to 2025. Coal supply increases from about 450 Mtce in 2021 to 550 Mtce
in 2030 in the STEPS and just over 500 Mtce in the APS.
Indonesia sees coal production fall by 10% in the period to 2030 in the STEPS and by 20% in
the APS. Indonesia currently exports close to 80% of its coal output, which is almost 100%
steam coal, and exports fall significantly in the years to 2030 in both the STEPS and APS.

In Australia, coal production plateaus between 2021 and 2030 in the STEPS, with a slight fallin domestic demand being partially offset by an increase in exports. In the APS, its coalproduction falls over this period by about 25%. Coking coal production remains steady, andAustralia exports about 190 Mtce coking coal each year through to 2030. Steam coal
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In the United States, declining domestic demand for coal and limited opportunities to tap
into export markets means production in 2030 is around 65% lower than in 2021 in the STEPS,
and around 75% lower in the APS.

production falls by about 40% over the same period as demand declines quickly in key
importing countries such as Japan and Korea.
Europe is looking to replace Russian imports, but there are limited opportunities to boost
indigenous coal production in ways that are consistent with long‐term emissions reduction
goals. Supply declines broadly in line with decreasing demand, falling by around 40% to 2030
in the STEPS and by over 55% in the APS.
Colombia saw coal production rebound in 2021 as existing operations ramped up and as
mines that had closed during the Covid‐19 pandemic were reopened. More than 80% of its
production is steam coal for exports, with Europe as its main market. As countries in Europe
transition from coal‐fired generation, coal production in Colombia to 2030 falls by about 35%
in the STEPS, and by 60% in the APS.
In the NZE Scenario, there is no need for any new coal mines or mine lifetime extensions.
Steam coal production falls by 50% to 2030 as coal is rapidly eliminated from the power
sector in all countries. Coking coal production falls by about 30% to 2030, a smaller decline
than for steam coal since the steel industry has fewer readily available alternatives.

Supply trends after 2030
Figure 9.5 ⊳Coal supply by scenario, 2010-2050
Coal type

Mtce

Coal supply
6 000

Lignite and peat

5 000

Coking coal
Steam coal

4 000
STEPS
3 000
APS

2 000
1 000

NZE
2010

2020

2030

2040

2050

2021

STEPS APS NZE
2050
IEA. CC BY 4.0.

Coal production falls by about 30% between 2021 and 2050 in the STEPS, 70% in the APS
and 90% in the NZE Scenario; coking coal production declines much less than steam coalIn the STEPS, global coal supply falls by about 25% from 2030 to 2050 (Figure 9.5). China cuts
its production by around 35%, and India and advanced economies by almost 20%. Productionin Indonesia is broadly constant between 2030 and 2050.

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Note: Mtce = million tonnes of coal equivalent.

In the APS, global coal supply declines by 65% between 2030 and 2050. Steam coal falls by
2 400 Mtce (70% reduction) as a result of efforts to reduce emissions from the power sector,
while coking coal falls by 470 Mtce (55% reduction) reflecting fuel switching and energy
efficiency improvements. Production in China falls by 1 800 Mtce (70% reduction): thisaccounts for close to two‐thirds of the global decline in supply. Production in India falls by
400 Mtce (80% reduction). The leading exporters, Australia and Indonesia, see production
fall by around 55% and 40% respectively between 2030 and 2050.
In the NZE Scenario, global coal production declines by 80% between 2030 and 2050 toaround 10% of the level in 2021, with production in 2050 down to around 410 Mtce of steamcoal and 120 Mtce of coking coal.

9.4

Coal trade

Figure 9.6 ⊳ Top coal importers and exporters by scenario, 2021, 2030 and 2050
Importers

Exporters
Importers
China
India
Japan
Korea
EuropeOther importers
Exporters
Australia
Indonesia
RussiaOther exporters

2030

STEPS

2050

2021

STEPS

APS

APS
‐1 200

‐ 600

0

600

9

1 200
Mtce
IEA. CC BY 4.0.

Falling demand in advanced economies and China reduces coal tradein the APS by 25% to 2030 and by 60% to 2050 from 2021 levels
Note: Mtce = million tonnes of coal equivalent.

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The Asia Pacific region is the main driver of international coal trade, accounting for morethan three‐quarters of global coal imports in 2021 (Figure 9.6). China was the largest
importer in 2021 (around 250 Mtce), followed by India (around 165 Mtce). Australia andIndonesia are the two main coal exporters, together accounting for 60% of coal exports in
2021. Australia alone provided more than half of all coking coal exports. Russia is the third‐
largest coal exporter. It provided around half of the coal imports to the European Union in
2021 (about 20% of total EU coal demand). However, its invasion of Ukraine led the European
Union to introduce a ban from August 2022 on all forms of coal imports from Russia.

In the STEPS, there is a short‐term increase in imports to the European Union from South
Africa, United States and Colombia to replace imports from Russia. However, the amount ofcoal imported by the European Union drops by around 50% between 2021 and 2030, andexports from South Africa and Colombia fall by over 30% over this period. India becomes theworld’s largest importer in the mid‐2020s: its imports rise by 35% to 2030 while China’s
decrease by 35%. In 2050, India imports 40% more coal than in 2021, most of which is coking
coal. This changes the dynamics of exporting economies: Australian exports, which aremainly coking coal, increase by 10% to 2050, while Indonesia, mainly a steam coal exporter,
sees exports fall by 30%.
In the APS, global coal trade falls by 25% to 2030 and by 60% to 2050. There is 470 Mtce ofcoal imported in 2050, mainly by countries with large distances between domestic
production and consumption hubs and where differences in coal quality require domestic
production to be supplemented with imports. Imports of coking coal in India increase by 40%
to 2030 as it expands steel production. Indonesian exports drop by 30% to 2030 as themarket for steam coal shrinks. Australia fares better, with coal exports falling by less than
20% to 2030, although its exports fall by about 50% between 2030 and 2050 as the use ofclean energy technologies increases.
In the NZE Scenario, global coal trade declines by 90% between 2021 and 2050 as clean
energy technologies progressively and speedily displace coal across the energy system.

9.5

Coal investment

Figure 9.7 ⊳Average annual investment in coal supply and coal-fired
electricity generation by scenario

Billion USD (2021)

STEPS

APS

NZE

200
150
100
50

2019 2020 2021
China

2022‐ 2031‐
2022‐ 2031‐
2022‐ 2031‐
30
50
30
50
30
50
Other emerging market and developing economies
Advanced economies
IEA. CC BY 4.0.

Investment in coal falls in all scenarios this decade: investment to 2030 is 30% lower than422

International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

recent years in the STEPS, 50% lower in the APS, and two-thirds lower in the NZE Scenario

Investment in coal supply and coal‐fired power generation worldwide has fallen by morethan 20% since 2015. Most investment in recent years has been in China and India, together
accounting for about 70% of global investment in coal‐fired power plants and supply in 2021.
Investment in coal supply is set to rise in the immediate future in response to energy security
concerns triggered by Russia’s invasion of Ukraine, recent rebound in economic activity, andrising industrial output in emerging market and developing economies.
In the STEPS, bans by some countries on financing new coal‐fired power plants and supply
projects abroad together with coal phase‐out policies cause average annual investment to2030 to fall by 30% from recent levels with continued declines thereafter (Figure 9.7).
In the APS, there is a larger drop in spending, especially in advanced economies. By 2030,
there is virtually no coal investment in the European Union, and advanced economies in Asia
significantly reduce investments in coal. There is a big increase in investment in CCUS, whichby 2030 accounts for half of the total coal‐related investment in power generation.
In the NZE Scenario, there is no need for new coal mines or mine lifetime extensions, and no
new coal‐fired power plants are approved. Average annual investment in coal to 2030 is two‐
thirds lower than in recent years, and the remaining coal‐related investment is focussed on
maintaining production at existing mines as they wind down and on reducing their emissions
intensity as much as possible, for example through reducing coal mine methane emissions.

9.6

Solid bioenergy

Figure 9.8 ⊳Solid bioenergy demand by scenario

EJ

STEPS

APS

9

NZE

100

Traditional use of biomass
Conversion losses

80

Buildings and agriculture
Industry

60

Power
40
20

2021

2030 2050

2030 2050

2030 2050
IEA. CC BY 4.0.

Modern solid bioenergy plays a key role in meeting net zero emissions pledges; traditionaluse of biomass decreases substantially in the APS and is eliminated in the NZE Scenario

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Notes: EJ = exajoule. Conversion losses occur during the production of solid, liquid and gaseous biofuels.

Worldwide, around 60 EJ (2 000 Mtce) of solid bioenergy was used in 2021 (Figure 9.8). The
inefficient traditional use of biomass for cooking and heating in developing countries
accounted for around 25 EJ, mainly in Africa (50% of the total) and Asia (45%).2 The
traditional use of biomass is the main cause of the 3.6 million premature deaths caused byhousehold air pollution every year, is a source of greenhouse gas (GHG) emissions, and is amajor barrier to women being able to pursue education and participate in the workforce (seeChapter 5).
Around 25 EJ of modern solid bioenergy was used in 2021 for power generation and in
end‐use sectors: 40% of this provided heat for industry, 40% was consumed in the power
sector (generating 670 terawatt‐hours of electricity and 1 EJ of commercial heat), and 20%
was used in the buildings and agriculture sectors. The remaining 10 EJ of solid bioenergy waslost during conversion to solid, liquid and gaseous biofuels.
In the STEPS, there is limited progress on universal access to clean cooking and the traditionaluse of biomass falls by only 20% to 2030. In 2050, there is still nearly 20 EJ of the traditionaluse of biomass globally, 75% of which is used in Africa. Modern solid bioenergy use in power
generation and final consumption increases by 30% to 2030, with large increases in China
and Europe for use in power generation.
In the APS, commitments made by governments on clean cooking targets are achieved ontime and in full. The traditional use of biomass falls by 60% from 2021 levels to 2030 and byaround 75% to 2050. The remaining 6 EJ of traditional biomass in 2050 is consumed mainly
in countries in Africa. Modern solid bioenergy use in power generation and final consumption
increases by 50% to 2030 and more than doubles to 2050. Around 1.1 gigatonnes (Gt) CO2
per year is captured through the use of bioenergy with carbon capture, utilisation andstorage (BECCS) by 2050.3 In total, modern bioenergy avoids around 1 Gt CO2 by 2030 and
4.5 Gt CO2 by 2050 through the displacement of fossil fuels and use of BECCS.
In the NZE Scenario, the traditional use of biomass is phased out worldwide by2030 (Box 9.1). Overall modern solid bioenergy levels are broadly similar to those in the APS
and 1.3 Gt CO2 per year is captured through BECCS in 2050. Modern solid bioenergy avoids
1.8 Gt CO2 emissions by 2030 and 5 Gt CO2 emissions by 2050 through the displacement offossil fuels and BECCS, and is thus responsible for just over 10% of total emissions reductionsin the NZE Scenario.

2

3

BECCS leads to net negative emissions when the bioenergy is sustainably sourced and the carbon emissions
resulting from its use are captured and stored on a permanent basis.

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The traditional use of biomass is the combustion of solid biomass in basic stoves that are inefficient andpolluting. This includes the use of wood, wood waste, charcoal, agricultural residues and other bio‐sourced
fuels such as animal dung. Modern solid bioenergy is the use of solid bioenergy in improved cook stoves andmodern technologies with higher combustion efficiencies, often using processed biomass such as pellets.

Box 9.1 ⊳What would achieving universal energy access mean for
GHG emissions?

In the NZE Scenario, around 40% of people that gain access to clean cooking in the period
to 2030 do so through the use of liquefied petroleum gas (LPG), 35% through improved
biomass cook stoves and 15% via electricity. Increased use of LPG and electricity brings
about an overall increase in fossil fuel use and CO2 emissions. However, the traditionaluse of biomass currently results in methane and nitrous oxide emissions and shifting toalternative fuels avoids these emissions. Achieving universal access to clean cooking in
the NZE Scenario results in an overall 870 Mt CO2‐eq reduction of GHG emissions in 2030
(Figure 9.9).
These reductions could be even larger. Some of the solid biomass used for cooking or
converted into charcoal in developing countries is currently harvested unsustainably,leading to deforestation and related CO2 emissions. The traditional use of biomass is alsoa major source of black carbon emissions, a short‐lived aerosol with high global warming
potential.
Figure 9.9 ⊳Net GHG emissions savings from clean cooking access in the
APS and NZE Scenario by 2030
NZE

Gt CO₂‐eq

APS
0.5

9

0

‐0.5

‐1.0

Increase Avoided

Netsavings

Increase Avoided

Netsavings
IEA. CC BY 4.0.

Achieving clean cooking targets in the APS reduces GHG emissions by 580 Mt CO2-eq
in 2030, while universal access in the NZE Scenario reduces emissions by 870 Mt CO2-eq

In addition to the 75 EJ of modern solid bioenergy used in 2050 in the NZE Scenario, a further
25 EJ of modern bioenergy is used in the form of biogas or liquid biofuels. More than half oftotal bioenergy supply in 2050 in the NZE Scenario is from sources that do not require
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Notes: Gt CO2‐eq = gigatonnes of carbon‐dioxide equivalent. Methane is assumed to be equivalent to
30 tonnes CO2 and nitrous oxide equivalent to 273 tonnes CO2. Black carbon emissions and avoided CO2
emissions from the combustion of unsustainably harvested biomass are not included.

dedicated land use (Box 9.2). Total bioenergy supply of 100 EJ is at the bottom‐end of therange of estimates (100‐170 EJ) of global sustainable bioenergy potential in 2050, and ismuch lower than the level of bioenergy use in comparable 1.5 °C scenarios assessed in the
Sixth Assessment Report of the Intergovernmental Panel on Climate Change, which have amedian of 240 EJ of bioenergy use in 2050 (IPCC, 2021).
The NZE Scenario does not rely on offsets from outside the energy sector to achieve net zero
emissions in 2050. But commensurate action on reducing emissions from agriculture,
forestry and other land uses (AFOLU) would help limit climate change and provide otherbenefits. Such action could include measures to: halt deforestation; improve forest
management practices; institute farming practices that increase soil carbon levels; andsupport afforestation. A number of companies and countries have recently expressedinterest in such “nature‐based solutions” to offset emissions from their operations. The useof offsets can be a cost‐effective mechanism to reduce emissions from parts of value chains
where direct emissions reductions are challenging, provided that schemes to generate
emissions credits result in permanent, additional and verified emissions reductions.
However, there is likely to be a limited supply of emissions credits consistent with net zero
emissions globally.
Box 9.2 ⊳Where does bioenergy come from in the NZE Scenario?

There are a number of sustainability concerns linked to the use of land for bioenergy
production. In the NZE Scenario, bioenergy resources are responsibly managed and do
not compete with other land uses. Of the 100 EJ of total modern bioenergy supply in 2050
in the NZE Scenario, just over half is from sustainable waste streams that do not require
any specific land use. This includes agriculture residues, forest and wood residues andother organic waste streams. The remaining 45 EJ of modern bioenergy demand requires
land to be dedicated to bioenergy supply.
To avoid conflicts between food production and affordability, there is a general shift in
the NZE Scenario away from conventional bioenergy sources towards advanced
bioenergy (see Chapter 7). The focus is on the production of bioenergy from dedicatedshort rotation woody crops grown on cropland, pasture land and marginal lands that are
not suited to food crops.4 In the NZE Scenario, there is no net increase in cropland use
for bioenergy, and no bioenergy crops are grown on existing forested land.

4
Cropland here refers to agricultural land used for food, animal feed and bioenergy production but excludes
short‐rotation woody crops not established on existing agricultural cropland.

426International Energy Agency | World Energy Outlook 2022

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Short rotation woody crops provide just over 40 EJ of bioenergy supply in 2050 in the NZE
Scenario (Figure 9.10). These can produce twice as much bioenergy per hectare as many
conventional bioenergy crops and can lead to additional CO2 removal from theatmosphere. Bioenergy supply from conventional crops falls from around 6 EJ today toless than 1 EJ in 2050 in the NZE Scenario.

The remaining modern bioenergy comes from sustainably managed forestry plantations
and tree planting integrated with agricultural production via agroforestry systems. These
do not conflict with food production or biodiversity. Such plantations can reduce CO2
emissions in the atmosphere, produce biomass in a sustainable way and increase
agriculture and forestry incomes.
Based on land area modelling using the GLOBIOM model (Havlík et al., 2014), the area ofland estimated to be available is much larger than the area of land used to produce
bioenergy in the NZE Scenario. This is even after taking into account sustainability
considerations such as the need to protect biodiversity and to meet the UN Sustainable
Development Goal 15 on biodiversity and land use. Nevertheless, it is critical to ensurethat bioenergy feedstocks are certified and that there are strict controls in place to avoid
land‐use conflicts.

EJ

Figure 9.10 ⊳ Bioenergy supply in the NZE Scenario
100

Forestry planting
Short‐rotation woody crops

80

Forest and wood residues
Organic waste streams

60

Traditional use of biomass
Conventional bioenergy crops

40

9

20

2010

2021

2030

2040

2050
IEA. CC BY 4.0.

There is no increase in cropland use for bioenergy in the NZE Scenario
and no bioenergy crops are developed on existing forested land

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Note: EJ = exajoule.

IEA. CC BY 4.0.

ANNEXESBox A.1 ⊳World Energy Outlook links

WEO homepage
General information
WEO‐2022 information

iea.org/weo
iea.li/weo22

WEO‐2022 datasets
Data in Annex A is available to download free in electronic format at:
iea.li/weo2022‐freedata
An extended dataset, including the data behind figures, tables
and the WEO‐2022 slide deck is available to purchase at:
iea.li/weo2022‐extendeddata

Modelling
Documentation and methodology / Investment costs
iea.li/model

Recent analysis
An Energy Sector Roadmap to
Net Zero Emissions in Indonesia
World Energy Employment
Nuclear Power and Secure Energy Transitions
World Energy Investment 2022
Africa Energy Outlook 2022
Southeast Asia Energy Outlook 2022
Sustainable Recovery Tracker

iea.li/indonesia
iea.li/employmentiea.li/nuclear‐power
iea.li/wei22
iea.li/africa‐outlook22
iea.li/se‐asia22
iea.li/recoverytracker

Playing my partiea.li/my‐part

A 10‐Point Plan to Cut Oil Useiea.li/oil‐use

A 10‐Point Plan to Reduce the European
Union’s Reliance on Russian Natural Gas

iea.li/gas‐reliance

Global Methane Tracker 2022

iea.li/methane‐tracker22

The Role of Critical Minerals

iea.li/minerals

Net Zero by 2050

iea.li/netzero

Databases

Energy subsidies:
Tracking the impact of fossil‐fuel subsidies

iea.li/policies‐databaseiea.li/SDG
iea.li/subsidies

CC BY-NC-SA 4.0.

Policy Databases
Sustainable Development Goal 7

Annex A
Tables for scenario projections
General note to the tables
This annex includes global historical and projected data by scenario for the following four
datasets:

A.1: Energy supply.



A.2: Total final consumption.



A.3: Electricity sector: gross electricity generation and electrical capacity.



A.4: CO₂ emissions: carbon dioxide (CO2) emissions from fossil fuel combustion andindustrial processes.

Each dataset is given for the following scenarios: (a) Stated Policies Scenario (STEPS) [Tables
A.1a. to A.4a]; (b) Announced Pledges Scenario (APS) [Tables A.1b. to A.4b]; and (c) Net Zero
Emissions by 2050 (NZE) Scenario [Tables A.1c. to A.4c].
This annex also includes regional historical and projected data for STEPS and APS for thefollowing datasets:


Tables A.5 – A.6: Total energy supply, renewables energy supply in exajoules (EJ).



Tables A.7 – A.10: Oil production, oil demand, world liquids demand, and, refining
capacity and runs in million barrels per day (mb/d).

Tables A.11 – A.12: Natural gas production, natural gas demand in billion cubic metres(bcm).



Tables A.13 – A.14: Coal production, coal demand in million tonnes of coal equivalent(Mtce).



Tables A.15 – A.21: Electricity generation by total and by source (renewables, solar
photovoltaics [PV], wind, nuclear, natural gas, coal) in terawatt‐hours (TWh).



Tables A.22 – A.25: Total final consumption and consumption by sector (industry,transport and buildings) in exajoules (EJ).



Tables A.26 – A.27: Hydrogen demand (PJ) and the hydrogen balance in million tonnesof hydrogen equivalent (Mt H2 equivalent).1



Tables A.28 – A.30: Total CO₂ emissions, electricity and heat sectors CO₂ emissions, final
consumption in million tonnes of CO₂ emissions (Mt CO₂).

Tables A.5 to A.30 cover: World, North America, United States, Central and South America,
Brazil, Europe, European Union, Africa, Middle East, Eurasia, Russia, Asia Pacific, China, India,
Japan and Southeast Asia.

1

The hydrogen balance table also includes the NZE Scenario.

Annex A | Tables for scenario projections

431

CC BY-NC-SA 4.0.

The definitions for regions, fuels and sectors are in Annex C.

Common abbreviations used in the tables include: CAAGR = compound average annual
growth rate; CCUS = carbon capture, utilisation and storage. Combustion of fossil fuels in
facilities without CCUS is classified as “unabated”.
Both in the text of this report and in these annex tables, rounding may lead to minor
differences between totals and the sum of their individual components. Growth rates arecalculated on a compound average annual basis and are marked “n.a.” when the base year
is zero or the value exceeds 200%. Nil values are marked “‐”.
Please see Box A.1 for details on where to download the World Energy Outlook (WEO) tables
in Excel format. In addition, Box A.1 lists the links relating to the main WEO website,
documentation and methodology of the Global Energy and Climate (GEC) Model, investment
costs, policy databases and recent WEO special reports.

Data sources
The Global Energy and Climate (GEC) Model is a very data‐intensive model covering thewhole global energy system. Detailed references on databases and publications used in themodelling and analysis may be found in Annex E.
The formal base year for this year’s projections is 2020, as this is the last year for which acomplete picture of energy demand and production is in place. However, we have used more
recent data wherever available, and we include our 2021 estimates for energy production
and demand in this annex (Tables A.1 to A.3). Estimates for the year 2021 are based on
updates of the Global Energy Review reports which are derived from a number of sources,
including the latest monthly data submissions to the IEA Energy Data Centre, other statisticalreleases from national administrations, and recent market data from the IEA Market Report
Series that cover coal, oil, natural gas, renewables and power. Investment estimates include
the year 2021, based on the IEA World Energy Investment 2022 report.
Historical data for gross power generation capacity (Tables A.2 and A.3) are drawn from the
S&P Global Market Intelligence World Electric Power Plants Database (March 2022 version)and the International Atomic Energy Agency PRIS database.

Total energy supply (TES) is equivalent to electricity and heat generation plus the otherenergy sector, excluding electricity, heat and hydrogen, plus total final consumption (TFC),
excluding electricity, heat and hydrogen. TES does not include ambient heat from heatpumps or electricity trade. Solar in TES includes solar PV generation, concentrating solar
power and final consumption of solar thermal. Other renewables in TES include geothermal
and marine (tide and wave) energy for electricity and heat generation. Biofuels conversion
losses are the conversion losses to produce biofuels (mainly from modern solid bioenergy)
used in the energy sector. Low‐emissions hydrogen production is merchant low‐emissionshydrogen production (excluding onsite production at industrial facilities and refineries),

432

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CC BY-NC-SA 4.0.

Definitional note: Energy supply and transformation tables

with inputs referring to total fuel inputs and outputs to produced hydrogen. While notitemised separately, non‐renewable waste and other sources are included in TES.

Definitional note: Fossil fuel production and demand tables
Oil production and demand is expressed in million barrels per day (mb/d). Tight oil includes
tight crude oil and condensate production except for the United States, which includes tightcrude oil only (US tight condensate volumes are included in natural gas liquids). Processing
gains cover volume increases that occur during crude oil refining. Biofuels and their inclusion
in liquids demand is expressed in energy‐equivalent volumes of gasoline and diesel. Natural
gas production and demand is expressed in billion cubic metres (bcm). Coal production anddemand is expressed in million tonnes of coal equivalent (Mtce). Differences between
historical production and demand volumes for oil, gas and coal are due to changes in stocks.
Bunkers include both international marine and aviation fuels. Refining capacity at risk isdefined as the difference between refinery capacity and refinery runs, with the latterincluding a 14% allowance for downtime. Projected shutdowns beyond those publicly
announced are also counted as capacity at risk.

Definitional note: Electricity tables
Electricity generation expressed in terawatt‐hours (TWh) and installed electrical capacity
data expressed in gigawatts (GW) are both provided on a gross basis (i.e. includes own use
by the generator). Projected gross electrical capacity is the sum of existing capacity andadditions, less retirements. While not itemised separately, other sources are included in total
electricity generation. Installed capacity for hydrogen and ammonia refers to full conversion
only, not including co‐firing with natural gas or coal.

Definitional note: Energy demand tables
Sectors comprising total final consumption (TFC) include industry (energy use andfeedstock), transport, buildings (residential, services and non‐specified other) and other(agriculture and other non‐energy use). Energy demand from international marine andaviation bunkers are included in global transport totals.

Total hydrogen demand includes merchant (or offsite) hydrogen demand and hydrogen
demand in industry and refineries covered by onsite production. It also includes hydrogenused in the production of hydrogen‐based fuels (ammonia, synthetic hydrocarbon fuels). The
hydrogen balance table A.27 is expressed in hydrogen‐equivalent terms, which means forhydrogen‐based fuels the hydrogen input to produce these fuels is reported. Hydrogen
demand in end‐use sectors includes total final consumption of hydrogen and hydrogen‐based fuels as well as hydrogen demand in industry covered by onsite production within
industrial facilities.

Annex A | Tables for scenario projections

433

CC BY-NC-SA 4.0.

Definitional note: Hydrogen tables

ADefinitional note: CO2 emissions tables
Total CO2 includes carbon dioxide emissions: from the combustion of fossil fuels andnon‐renewable wastes, from industrial and fuel transformation processes (process
emissions); and CO2 emissions from flaring and CO2 removal. CO2 removal includes: captured
and stored emissions from the combustion of bioenergy and renewable wastes; from
biofuels production; and from direct air capture (DAC).
The first two entries are often reported as bioenergy with carbon capture and storage(BECCS). Note that some of the CO2 captured from biofuels production and direct air capture
is used to produce synthetic fuels, which is not included as CO2 removal.
Total CO2 captured includes the carbon dioxide captured from CCUS facilities (such as
electricity generation or industry) and atmospheric CO2 captured through direct air capture,but excludes that captured and used for urea production.

Annex A licencing

434

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CC BY-NC-SA 4.0.

Subject to the IEA’s Notice for CC‐licenced Content, this Annex A of the World Energy Outlook
2022 is licenced under a Creative Commons Attribution‐NonCommercial‐ShareAlike 4.0
International Licence.

Energy supply: World
STEPS

STEPS
STEPS
STEPS
STEPS
STEPS
Table
A.1a:
World
energysupply929

Energy supply: WorldCAAGR (%)
2021 to:Shares (%)

Stated Policies Scenario (EJ)
2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total energy supply

542

592

624

673

708

740

100

100

100

0.8

0.6

Renewables

45

69

74

116

169

215

12

17

29

5.2

3.8

Solar

1

5

5

18

36

52

1

3

7

14

8.1

Wind

1

6

7

17

29

38

1

2

5

11

6.2

Hydro

12

16

16

18

21

25

2

3

3

1.8

1.6

Modern solid bioenergy

24

33

36

46

54

62

6

7

8

3.0

1.9

Modern liquid bioenergy

2

4

4

7

9

11

1

1

1

5.2

3.2

Modern gaseous bioenergy

1

1

1

3

5

9

0

0

1

8.1

7.0

Other renewables

3

4

5

8

14

19

1

1

3

6.4

4.9

Traditional use of biomass

25

24

24

20

19

18

4

3

2

‐2.3

‐1.1
1.5

Nuclear

30

29

30

37

43

46

5

5

6

2.1

Unabated natural gas

115

139

146

150

147

147

23

22

20

0.3

0.0

Natural gas with CCUS

0

0

0

1

2

3

0

0

0

8.1

6.5

173

172

183

197

198

197

29

29

27

0.8

0.2

25

29

31

37

41

42

5

6

6

2.1

1.0

Unabated coal

153

157

165

151

128

111

26

22

15

‐1.0

‐1.4

Coal with CCUS

‐

0

0

0

1

1

0

0

0

33

17

Electricity and heat sectors

200

228

242

261

287

312

100

100

100

0.9

0.9

Renewables

21

37

40

71

113

149

17

27

48

6.6

4.6

Solar PV

0

3

4

14

30

44

1

6

14

17

9.0

Oil
of which non‐energy use

Wind

1

6

7

17

29

38

3

6

12

11

6.2

Hydro

12

16

16

18

21

25

6

7

8

1.8

1.6

Bioenergy

5

9

10

15

19

23

4

6

7

4.1

2.8

Other renewables

2

4

4

7

13

19

2

3

6

7.3

5.8

Hydrogen

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Ammonia

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Nuclear

30

29

30

37

43

46

13

14

15

2.1

1.5

Unabated natural gas

47

55

57

55

51

50

24

21

16

‐0.3

‐0.4

‐

‐

‐

‐

0

1

‐

‐

0

n.a.

n.a.

Oil

11

7

8

5

4

3

3

2

1

‐4.7

‐2.7

Unabated coal

91

99

107

93

74

60

44

36

19

‐1.5

‐1.9

Coal with CCUS

‐

0

0

0

1

1

0

0

0

25

17

Other energy sector

51

59

61

68

72

77

100

100

100

1.2

0.8

‐

5

6

8

10

12

100

100

100

4.4

2.5

Production inputs

‐

0

0

1

2

3

100

100

100

64

23

Production outputs

‐

0

0

1

1

2

100

100

100

68

24

For hydrogen‐based fuels

‐

‐

‐

0

0

0

‐

6

17

n.a.

n.a.

For other energy sector

‐

‐

‐

0

1

1

‐

59

28

n.a.

n.a.

Natural gas with CCUS

Biofuels conversion losses

Annex A | Tables for scenario projections

435

CC BY-NC-SA 4.0.

Low‐emissions hydrogenATotal final consumption: World
STEPS

STEPS
STEPS
STEPS
STEPS
Table
A.2a:
World
final STEPS
consumption

929

Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Total final consumption

383

417

439

485

518

544

100

100

100

1.1

0.7

Electricity

64

82

87

107

130

151

20

22

28

2.3

1.9

Liquid fuels

154

159

170

189

194

196

39

39

36

1.2

0.5

Biofuels

2

4

4

7

9

11

1

1

2

5.2

3.2

Ammonia

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Synthetic oil

‐

‐

‐

‐

‐

‐

‐

‐

‐

n.a.

n.a.

151

155

166

183

185

185

38

38

34

1.1

0.4

58

68

72

79

84

88

17

16

16

0.9

0.7

Biomethane

0

0

0

1

2

4

0

0

1

13

11

Hydrogen

‐

0

0

0

1

1

0

0

0

48

21

Synthetic methane

‐

‐

‐

‐

‐

‐

‐

‐

‐

n.a.

n.a.

57

68

72

77

81

81

16

16

15

0.8

0.4

95

92

94

91

89

87

21

19

16

‐0.3

‐0.3

Solid bioenergy

38

39

40

39

40

41

9

8

7

‐0.4

0.0

Coal

56

52

53

52

49

46

12

11

8

‐0.2

‐0.5

Heat

12

13

13

14

14

14

3

3

3

0.5

0.2

Other

1

2

3

4

6

8

1

1

1

5.1

3.7

Industry

143

160

167

189

202

209

100

100

100

1.4

0.8

Electricity

27

34

37

43

49

54

22

23

26

1.9

1.4

Liquid fuels

29

32

33

40

44

44

20

21

21

2.1

0.9

Oil

29

32

33

40

43

44

20

21

21

2.1

0.9

24

30

31

35

39

42

18

19

20

1.6

1.1

Biomethane

0

0

0

0

1

2

0

0

1

16

13

Hydrogen

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Unabated natural gas

24

29

31

35

38

39

18

18

19

1.5

0.8

Natural gas with CCUS

0

0

0

0

0

0

0

0

0

17

11

58

58

59

63

63

61

36

33

29

0.7

0.1

Solid bioenergy

8

10

11

13

15

16

7

7

8

2.0

1.3

Unabated coal

50

47

48

49

47

45

29

26

21

0.4

‐0.2

Oil
Gaseous fuels

Natural gas
Solid fuels

Gaseous fuels

Solid fuels

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Heat

Coal with CCUS

5

6

7

7

7

7

4

4

4

0.9

0.4

Other

0

0

0

0

0

0

0

0

0

13

7.6

Iron and steel

31

35

36

38

38

38

22

20

18

0.6

0.1

Chemicals

37

46

48

58

63

65

29

30

31

2.0

1.0

Cement

10

12

12

13

13

12

7

7

6

0.5

‐0.0

436

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CC BY-NC-SA 4.0.

Stated Policies Scenario (EJ)

Total final consumption: World

Table A.2a: World final consumption (continued)
Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Transport

102

105

113

130

139

147

100

100

100

1.5

0.9

Electricity

1

1

2

4

9

13

1

3

9

11

7.5

Liquid fuels

97

99

107

120

123

126

94

92

86

1.3

0.6

Biofuels

2

4

4

6

9

10

4

5

7

5.0

3.1

Oil

95

95

103

113

114

116

90

87

79

1.1

0.4

Gaseous fuels

4

5

5

6

7

8

5

4

5

1.3

1.4

Biomethane

0

0

0

0

0

1

0

0

1

11

8.7

Hydrogen

‐

0

0

0

0

1

0

0

1

40

21

Natural gas

4

5

5

6

6

6

5

4

4

0.9

0.5

Road

76

81

87

94

98

100

77

73

68

0.9

0.5

Passenger cars

39

42

45

47

47

46

40

36

31

0.4

0.1

Heavy‐duty trucks

21

25

26

31

36

39

23

24

27

1.9

1.4

11

8

10

18

21

25

9

14

17

6.7

3.2
1.4

Aviation
Shipping

10

10

11

12

14

16

10

9

11

1.2

Buildings

117

128

132

136

147

158

100

100

100

0.3

0.6

Electricity

35

43

45

55

68

79

34

41

50

2.2

1.9

Liquid fuels

13

13

14

12

10

9

10

9

6

‐1.6

‐1.5

Biofuels

0

0

0

0

0

0

0

0

0

3.9

2.3

Oil

13

13

14

12

10

9

10

9

6

‐1.6

‐1.5
0.1

Gaseous fuels

27

30

31

32

32

32

24

23

20

0.1

Biomethane

0

0

0

0

1

1

0

0

1

12

10

Hydrogen

‐

‐

‐

0

0

0

‐

0

0

n.a.

n.a.

Natural gas
Solid fuels

26

29

31

31

30

30

23

23

19

0.0

‐0.1

35

33

33

27

25

24

25

20

15

‐2.2

‐1.0

Modern biomass

4

4

4

5

6

6

3

4

4

2.3

1.3

Traditional use of biomass

25

24

24

20

19

18

18

15

11

‐2.3

‐1.1

Coal

6

4

4

2

1

0

3

1

0

‐10

‐8.6

Heat

6

7

7

7

7

7

5

5

4

0.2

0.1

Other

1

2

3

4

6

7

2

3

5

4.8

3.6

Residential

83

91

94

92

98

106

71

67

67

‐0.2

0.4

Services

33

37

39

44

49

52

29

33

33

1.5

1.0

Other

22

24

26

29

30

29

100

100

100

0.9

0.4

Annex A | Tables for scenario projections

437

CC BY-NC-SA 4.0.

Stated Policies Scenario (EJ)A

Electricity sector: World
STEPS

STEPS

STEPS

STEPS

STEPS

STEPS

9

Table A.3a: World electricity sector

29Electricity sector: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total generation

21 53926 70828 33434 83442 64249 845

100

100

100

2.3

2.0

Renewables

4 234

7 539

8 060

15 07324 44232 452

28

43

65

7.2

4.9

Solar PV

32

824

1 003

4 011

8 356

12 118

4

12

24

17

9.0

Wind

342

1 597

1 870

4 604

8 107

10 691

7

13

21

11

6.2

Hydro

3 449

4 343

4 327

5 078

5 890

6 809

15

15

14

1.8

1.6

341

666

746

1 145

1 540

1 951

3

3

4

4.9

3.4

‐

‐

‐

4

5

5

‐

0

0

n.a.

n.a.

CSP

2

14

15

45

166

329

0

0

1

13

11

Geothermal

68

95

97

183

335

458

0

1

1

7.2

5.5

Bioenergyof which BECCS

MarineNuclear

1

1

1

8

47

96

0

0

0

24

17

2 756

2 673

2 776

3 351

3 897

4 260

10

10

9

2.1

1.5
n.a.

Hydrogen and ammonia

‐

‐

‐

9

32

44

‐

0

0

n.a.

Fossil fuels with CCUS

‐

1

1

5

112

133

0

0

0

21

19

Coal with CCUS

‐

1

1

5

51

61

0

0

0

21

16

Natural gas with CCUS

‐

‐

‐

‐

61

72

‐

‐

0

n.a.

n.a.

14 49416 43517 43616 32414 07412 862

62

47

26

‐0.7

‐1.0

Coal

8 670

9 439

10 201

9 044

7 211

5 892

36

26

12

‐1.3

‐1.9

Natural gas

4 855

6 333

6 552

6 848

6 501

6 658

23

20

13

0.5

0.1

969

664

682

432

362

312

2

1

1

‐5.0

‐2.7

Unabated fossil fuels

OilStated Policies Scenario (GW)CAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total capacity

5 198

7 849

8 185

11 95416 46819 792

100

100

100

4.3

3.1

Renewables

1 343

2 989

3 278

6 707

10 666

13 653

40

56

69

8.3

5.0

Solar PV

39

741

892

3 020

5 573

7 464

11

25

38

15

7.6

Wind

181

737

832

1 830

2 853

3 564

10

15

18

9.2

5.1

Hydro

1 027

1 329

1 358

1 563

1 795

2 027

17

13

10

1.6

1.4

Bioenergy

83

160

173

246

327

406

2

2

2

4.0

3.0

of which BECCS

‐

‐

‐

1

1

1

‐

0

0

n.a.

n.a.

CSP

1

6

7

17

49

90

0

0

0

10

9.2

Geothermal

11

15

16

28

50

66

0

0

0

7.0

5.1

MarineNuclear

0

1

1

4

19

37

0

0

0

18

14

403

415

413

471

545

590

5

4

3

1.5

1.2

Hydrogen and ammonia

‐

‐

‐

3

13

13

‐

0

0

n.a.

n.a.

Fossil fuels with CCUS

‐

0

0

1

26

33

0

0

0

28

21

Coal with CCUS

‐

0

0

1

10

13

0

0

0

28

18

Natural gas with CCUS

‐

‐

‐

‐

16

20

‐

‐

0

n.a.

n.a.

Unabated fossil fuels

3 448

4 421

4 462

4 495

4 441

4 196

55

38

21

0.1

‐0.2

Coal

1 621

2 161

2 184

2 129

1 936

1 583

27

18

8

‐0.3

‐1.1

Natural gas

1 389

1 830

1 850

2 074

2 268

2 422

23

17

12

1.3

0.9

438

430

427

292

237

192

5

2

1

‐4.1

‐2.7

1

18

27

270

768

1 296

0

2

7

29

14

Oil
Battery storage

438

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Stated Policies Scenario (TWh)CO₂ emissions: World
STEPS

STEPS
STEPS
STEPS
Table
A.4a: STEPSWorld CO
2 emissions

STEPS

9

29

CO₂ emissions: WorldCAAGR (%)
2021 to:Stated Policies Scenario (Mt CO2)
2010

2020

2021

2030

2040

2050

2030

Total CO2*

32 89334 77936 63936 21133 86131 979

‐0.1

2050
‐0.5

Combustion activities (+)

30 64331 90433 68033 13530 80028 946

‐0.2

‐0.5

Coal

13 85514 33515 106

13 695

11 553

9 863

‐1.1

‐1.5

Oil

10 576

10 19410 85011 412

11 248

11 0940.6

0.1

Natural gas

6 067

7 162

7 520

7 774

7 675

7 629

0.4

0.0

146

213

204

254

324

360

2.5

2.0

Industry removals (‐)

‐

1

2

9

28

59

20

13

Biofuels production

‐

1

1

1

1

1

0.0

0.0

Bioenergy and waste

‐

‐

1

8

27

58

27

15

Electricity and heat sectors

Direct air capture

12 47413 50214 37812 75910 676

9 308

‐1.3

‐1.5

Coal

8 946

9 750

10 507

9 128

7 282

5 938

‐1.6

‐1.9

Oil

828

557

574

372

309

260

‐4.7

‐2.7

2 623

3 095

3 195

3 105

2 863

2 842

‐0.3

‐0.4

Bioenergy and waste

78

99

101

154

223

267

4.8

3.4

Other energy sector**

1 438

1 487

1 522

1 698

1 695

1 659

1.2

0.3

Final consumption**18 72019 52220 46821 62721 501

21 056

0.6

0.1

Coal

4 707

4 474

4 499

4 458

4 170

3 830

‐0.1

‐0.6

Natural gas

Oil

9 117

9 080

9 704

10 456

10 38810 331

0.8

0.2

Natural gas

2 859

3 321

3 561

3 800

3 929

3 904

0.7

0.3
‐0.3

Bioenergy and waste

67

114

102

100

101

94

‐0.3

8 379

9 132

9 316

10 037

10 061

9 669

0.8

0.1

Iron and steel**

2 104

2 724

2 755

2 929

2 798

2 653

0.7

‐0.1

Chemicals**

1 183

1 287

1 342

1 492

1 492

1 429

1.2

0.2

Cement**

1 928

2 458

2 526

2 648

2 699

2 585

0.5

0.1

Transport

7 011

7 113

7 670

8 472

8 571

8 700

1.1

0.4

Road

5 214

5 485

5 858

6 065

5 925

5 667

0.4

‐0.1

Passenger cars

2 622

2 803

3 018

2 962

2 761

2 470

‐0.2

‐0.7

Heavy‐duty trucks

1 468

1 688

1 791

2 070

2 274

2 435

1.6

1.1

Aviation

753

586

713

1 259

1 440

1 675

6.5

3.0

Shipping

796

796

838

905

979

1 145

0.9

1.1

2 892

2 851

3 045

2 680

2 446

2 293

‐1.4

‐1.0

Residential

1 963

1 983

2 066

1 747

1 528

1 415

‐1.8

‐1.3

Services

929

868

979

934

919

878

‐0.5

‐0.4

Total CO2 removals**

‐

1

2

11

35

70

22

13

Total CO2 captured**

4

42

43

92

272

396

8.9

8.0

Industry**

Buildings*Includes emissions from industrial processes and flaring.

Annex A | Tables for scenario projections

439

CC BY-NC-SA 4.0.

**Includes emissions from industrial processes.

AEnergy supply: World
STEPS

STEPS
STEPS
APS
APS
APS
Table
A.1b:
World
energysupply929

Energy supply: WorldCAAGR (%)
2021 to:Shares (%)

Announced Pledges Scenario (EJ)
2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total energy supply

542

592

624

636

626

629

100

100

100

0.2

0.0

Renewables

45

69

74

141

239

319

12

22

51

7.5

5.2

Solar

1

5

5

23

56

89

1

4

14

17

10

Wind

1

6

7

21

44

63

1

3

10

13

8.0
1.9

Hydro

12

16

16

19

23

27

2

3

4

2.1

Modern solid bioenergy

24

33

36

53

70

81

6

8

13

4.6

2.9

Modern liquid bioenergy

2

4

4

11

18

19

1

2

3

11

5.3

Modern gaseous bioenergy

1

1

1

4

8

12

0

1

2

15

8.2

Other renewables

3

4

5

10

20

28

1

2

4

9.2

6.4

Traditional use of biomass

25

24

24

9

7

6

4

1

1

‐10

‐4.8

Nuclear

30

29

30

39

49

56

5

6

9

2.8

2.1

Unabated natural gas

115

139

146

130

99

77

23

20

12

‐1.3

‐2.2

Natural gas with CCUS
Oilof which non‐energy use
Unabated coal

0

0

0

4

10

15

0

1

2

27

13

173

172

183

179

139

108

29

28

17

‐0.3

‐1.8

25

29

31

36

36

35

5

6

6

1.7

0.4

153

157

165

132

73

33

26

21

5

‐2.5

‐5.4

‐

0

0

1

9

15

0

0

2

64

29

Electricity and heat sectors

200

228

242

260

302

349

100

100

100

0.8

1.3

Renewables

21

37

40

83

160

229

17

32

66

8.5

6.2

Solar PV

0

3

4

17

42

68

1

7

19

19

11

Wind

1

6

7

21

44

63

3

8

18

13

8.0

Hydro

12

16

16

19

23

27

6

7

8

2.1

1.9

Bioenergy

5

9

10

17

28

37

4

7

11

5.8

4.5

Other renewables

2

4

4

9

22

35

2

4

10

11

8.0

‐

‐

‐

0

2

2

‐

0

1

n.a.

n.a.
n.a.

Coal with CCUS

HydrogenAmmonia

‐

‐

‐

0

1

2

‐

0

1

n.a.

Nuclear

30

29

30

39

49

56

13

15

16

2.8

2.1

Unabated natural gas

47

55

57

49

36

28

24

19

8

‐1.6

‐2.4

‐

‐

‐

0

2

2

‐

0

1

n.a.

n.a.

Oil

11

7

8

4

3

2

3

2

1

‐6.2

‐4.4

Unabated coal

91

99

107

83

43

17

44

32

5

‐2.7

‐6.1

Coal with CCUS

‐

0

0

0

7

10

0

0

3

54

29

Other energy sector

51

59

61

69

72

78

100

100

100

1.3

0.8

‐

5

6

13

19

19

100

100

100

9.3

4.3

Production inputs

‐

0

0

4

15

28

100

100

100

99

32

Production outputs

‐

0

0

3

11

20

100

100

100

103

33

For hydrogen‐based fuels

‐

‐

‐

1

3

8

‐

23

40

n.a.

n.a.

For other energy sector

‐

‐

‐

0

0

0

‐

13

1

n.a.

n.a.

Natural gas with CCUS

Biofuels conversion losses

440International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Low‐emissions hydrogenTotal final consumption: World
STEPS

STEPS

STEPS

APS

APS

APS

9

Table A.2b: World final consumption

29

Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Total final consumption

383

417

439

451

439

433

100

100

100

0.3

‐0.1

Electricity

64

82

87

108

140

169

20

24

39

2.5

2.3

Liquid fuels

154

159

170

177

149

125

39

39

29

0.4

‐1.1

Biofuels

2

4

4

11

18

19

1

2

4

11

5.3

Ammonia

‐

‐

‐

0

1

3

‐

0

1

n.a.

n.a.

Synthetic oil
Oil
Gaseous fuels

‐

‐

‐

0

1

2

‐

0

0

n.a.

n.a.

151

155

166

165

129

101

38

37

23

‐0.0

‐1.7

58

68

72

71

65

61

17

16

14

‐0.3

‐0.6

Biomethane

0

0

0

2

3

5

0

0

1

25

11

Hydrogen

‐

0

0

1

5

10

0

0

2

87

30

Synthetic methane

‐

‐

‐

‐

‐

‐

‐

‐

‐

n.a.

n.a.

57

68

72

67

55

45

16

15

10

‐0.8

‐1.6

95

92

94

76

62

53

21

17

12

‐2.3

‐1.9

Solid bioenergy

38

39

40

32

32

34

9

7

8

‐2.6

‐0.6

Coal

56

52

53

44

30

19

12

10

4

‐2.1

‐3.4

Heat

12

13

13

13

12

10

3

3

2

‐0.1

‐1.0

Other

1

2

3

6

11

15

1

1

3

9.7

5.9

Industry

143

160

167

178

178

174

100

100

100

0.7

0.1

Electricity

27

34

37

45

56

66

22

25

38

2.3

2.1

Liquid fuels

29

32

33

37

35

32

20

21

18

1.0

‐0.2

Oil

29

32

33

36

34

30

20

20

17

0.9

‐0.3

24

30

31

33

33

30

18

18

17

0.7

‐0.1

Biomethane

0

0

0

1

2

3

0

0

2

28

13

Hydrogen

‐

‐

‐

1

2

3

‐

0

2

n.a.

n.a.

Unabated natural gas

24

29

31

31

27

22

18

17

12

0.1

‐1.2

Natural gas with CCUS

0

0

0

0

1

3

0

0

2

29

17

58

58

59

56

47

39

36

32

22

‐0.6

‐1.5

Natural gas
Solid fuels

Gaseous fuels

Solid fuels
Solid bioenergy

8

10

11

14

17

20

7

8

11

2.8

2.0

Unabated coal

50

47

48

42

27

15

29

23

9

‐1.5

‐4.0

Coal with CCUS
Heat

‐

‐

‐

0

2

4

‐

0

2

n.a.

n.a.

5

6

7

7

5

4

4

4

2

‐0.0

‐1.5

Other

0

0

0

1

2

3

0

1

2

42

16

Iron and steel

31

35

36

35

33

31

22

20

18

‐0.3

‐0.5

Chemicals

37

46

48

55

56

55

29

31

32

1.4

0.4

Cement

10

12

12

12

12

12

7

7

7

‐0.2

‐0.2

Annex A | Tables for scenario projections

441

CC BY-NC-SA 4.0.

Announced Pledges Scenario (EJ)A

Total final consumption: World

Table A.2b: World final consumption (continued)
Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Transport

102

105

113

124

115

112

100

100

100

1.0

‐0.0

Electricity

1

1

2

6

17

28

1

5

25

15

10

Liquid fuels

97

99

107

113

93

76

94

91

67

0.6

‐1.2

Biofuels

2

4

4

10

16

17

4

8

15

11

5.0

Oil

95

95

103

102

75

54

90

83

48

‐0.0

‐2.2

Gaseous fuels

4

5

5

5

6

8

5

4

7

‐0.3

1.6

Biomethane

0

0

0

0

0

0

0

0

0

15

6.7

Hydrogen

‐

0

0

0

2

6

0

0

5

67

28

Natural gas

4

5

5

4

3

2

5

4

2

‐1.7

‐3.2

Road

76

81

87

90

80

73

77

73

65

0.3

‐0.6

Passenger cars

39

42

45

43

35

30

40

35

27

‐0.4

‐1.4

Heavy‐duty trucks

21

25

26

30

31

31

23

24

27

1.5

0.5

11

8

10

18

20

24

9

14

21

6.5

3.0

Aviation
Shipping

10

10

11

11

10

11

10

9

9

0.4

‐0.1

Buildings

117

128

132

121

118

122

100

100

100

‐1.0

‐0.3

Electricity

35

43

45

54

63

71

34

44

58

1.9

1.5

Liquid fuels

13

13

14

11

6

5

10

9

4

‐2.8

‐3.7

Biofuels

0

0

0

0

0

0

0

0

0

11

5.4

Oil

13

13

14

11

6

4

10

9

4

‐2.8

‐3.8
‐2.1

Gaseous fuels

27

30

31

27

21

17

24

22

14

‐1.5

Biomethane

0

0

0

1

1

2

0

1

1

28

11

Hydrogen

‐

‐

‐

0

1

1

‐

0

1

n.a.

n.a.

Natural gas
Solid fuels

26

29

31

26

18

13

23

21

11

‐2.0

‐3.0

35

33

33

18

14

14

25

15

11

‐6.3

‐3.0

Modern biomass

4

4

4

8

7

8

3

6

6

6.8

2.0

Traditional use of biomass

25

24

24

9

7

6

18

7

5

‐10

‐4.8

Coal

6

4

4

1

0

0

3

1

0

‐12

‐13

6

7

7

7

6

6

5

5

5

‐0.3

‐0.5

Heat
Other

1

2

3

5

8

11

2

4

9

7.8

5.0

Residential

83

91

94

80

77

80

71

66

66

‐1.7

‐0.5

Services

33

37

39

41

41

42

29

34

34

0.6

0.3

Other

22

24

26

28

27

24

100

100

100

0.5

‐0.3

442

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Announced Pledges Scenario (EJ)Electricity sector: World
STEPS

STEPS

STEPS

APS

APS

APS

9

Table A.3b: World electricity sector

29Electricity sector: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total generation

21 53926 70828 33435 87848 65461 268

100

100

100

2.7

2.7

Renewables

4 234

7 539

8 060

17 57533 97148 873

28

49

80

9.0

6.4

Solar PV

32

824

1 003

4 838

11 76718 761

4

13

31

19

11

Wind

342

1 597

1 870

5 816

12 30017 416

7

16

28

13

8.0

Hydro

3 449

4 343

4 327

5 213

6 460

7 543

15

15

12

2.1

1.9

341

666

746

1 355

2 288

3 179

3

4

5

6.9

5.1

‐

‐

‐

46

304

532

‐

0

1

n.a.

n.a.

CSP

2

14

15

100

614

1 166

0

0

2

23

16

Geothermal

68

95

97

237

479

686

0

1

1

10

7.0

Bioenergyof which BECCS

MarineNuclear

1

1

1

15

64

122

0

0

0

34

18

2 756

2 673

2 776

3 547

4 471

5 103

10

10

8

2.8

2.1
n.a.

Hydrogen and ammonia

‐

‐

‐

79

336

567

‐

0

1

n.a.

Fossil fuels with CCUS

‐

1

1

75

890

1 338

0

0

2

66

29

Coal with CCUS

‐

1

1

34

642

1 013

0

0

2

51

28

Natural gas with CCUS

‐

‐

‐

42

249

325

‐

0

1

n.a.

n.a.

14 49416 43517 436

14 539

8 935

5 332

62

41

9

‐2.0

‐4.0

Coal

8 670

9 439

10 201

8 076

4 219

1 580

36

23

3

‐2.6

‐6.2

Natural gas

4 855

6 333

6 552

6 100

4 461

3 577

23

17

6

‐0.8

‐2.1

969

664

682

364

254

175

2

1

0

‐6.8

‐4.6

Unabated fossil fuels

Oil

Announced Pledges Scenario (GW)CAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total capacity

5 198

7 849

8 185

12 93220 25826 541

100

100

100

5.2

4.1

Renewables

1 343

2 989

3 278

7 744

14 51020 290

40

60

76

10

6.5

Solar PV

39

741

892

3 498

7 471

11 065

11

27

42

16

9.1

Wind

181

737

832

2 251

4 246

5 727

10

17

22

12

6.9

Hydro

1 027

1 329

1 358

1 609

1 988

2 325

17

12

9

1.9

1.9

Bioenergy

83

160

173

307

529

707

2

2

3

6.6

5.0

of which BECCS

‐

‐

‐

11

57

94

‐

0

0

n.a.

n.a.

CSP

1

6

7

35

177

318

0

0

1

20

14

Geothermal

11

15

16

37

72

102

0

0

0

10

6.7

MarineNuclear

0

1

1

7

26

47

0

0

0

27

15

403

415

413

487

622

716

5

4

3

1.9

1.9

Hydrogen and ammonia

‐

‐

‐

30

180

228

‐

0

1

n.a.

n.a.

Fossil fuels with CCUS

‐

0

0

18

192

288

0

0

1

74

31

Coal with CCUS

‐

0

0

6

130

207

0

0

1

54

29

Natural gas with CCUS

‐

‐

‐

12

62

81

‐

0

0

n.a.

n.a.

Unabated fossil fuels

3 448

4 421

4 462

4 223

3 506

2 729

55

33

10

‐0.6

‐1.7

Coal

1 621

2 161

2 184

1 988

1 535

942

27

15

4

‐1.0

‐2.9

Natural gas

1 389

1 830

1 850

1 949

1 754

1 623

23

15

6

0.6

‐0.5

438

430

427

286

217

164

5

2

1

‐4.4

‐3.3

1

18

27

425

1 246

2 286

0

3

9

36

17

Oil
Battery storage

Annex A | Tables for scenario projections

443

CC BY-NC-SA 4.0.

Announced Pledges Scenario (TWh)A

CO₂ emissions: World
STEPS

STEPS

STEPS

APS

APS

APS

Table A.4b: World CO2 emissions

929

CO₂ emissions: WorldCAAGR (%)
2021 to:Announced Pledges Scenario (Mt CO2)
2010

2020

2021

2030

2040

2050

2030

Total CO2*

32 89334 77936 63931 51120 53912 399

‐1.7

2050
‐3.7

Combustion activities (+)

30 64331 90433 68028 80318 554

11 347

‐1.7

‐3.7

Coal

13 85514 33515 106

11 881

6 594

2 973

‐2.6

‐5.5

Oil

10 576

10 19410 850

10 093

7 169

5 078

‐0.8

‐2.6

Natural gas

6 067

7 162

7 520

6 680

4 967

3 758

‐1.3

‐2.4

146

213

204

149

‐ 176

‐ 463

‐3.4

n.a.

Industry removals (‐)

‐

1

2

50

164

406

45

21

Biofuels production

‐

1

1

42

136

346

55

23

Bioenergy and waste

‐

‐

1

8

28

60

26

15

Electricity and heat sectors

Direct air capture

12 47413 50214 37811 330

6 389

3 138

‐2.6

‐5.1

Coal

8 946

9 750

10 507

8 163

4 292

1 713

‐2.8

‐6.1

Oil

828

557

574

322

230

156

‐6.2

‐4.4

2 623

3 095

3 195

2 759

2 022

1 598

‐1.6

‐2.4

Bioenergy and waste

78

99

101

85

‐ 155

‐ 329

‐1.9

n.a.

Other energy sector**

1 438

1 487

1 522

1 334

730

191

‐1.5

‐6.9

Final consumption**18 72019 52220 46818 78513 438

9 124

‐0.9

‐2.7

Coal

4 707

4 474

4 499

3 621

2 239

1 239

‐2.4

‐4.3

Oil

9 117

9 080

9 704

9 302

6 670

4 755

‐0.5

‐2.4

Natural gas

2 859

3 321

3 561

3 225

2 465

1 803

‐1.1

‐2.3

67

114

102

64

‐ 21

‐ 125

‐5.0

n.a.

8 379

9 132

9 316

8 569

6 234

3 946

‐0.9

‐2.9

Natural gas

Bioenergy and waste
Industry**
Iron and steel**

2 104

2 724

2 755

2 512

1 808

1 120

‐1.0

‐3.1

Chemicals**

1 183

1 287

1 342

1 315

925

548

‐0.2

‐3.0

Cement**

1 928

2 458

2 526

2 329

1 758

1 084

‐0.9

‐2.9

Transport

7 011

7 113

7 670

7 616

5 557

4 025

‐0.1

‐2.2

Road

5 214

5 485

5 858

5 459

3 773

2 509

‐0.8

‐2.9

Passenger cars

2 622

2 803

3 018

2 589

1 598

997

‐1.7

‐3.7

Heavy‐duty trucks

‐1.6

1 468

1 688

1 791

1 909

1 549

1 137

0.7

Aviation

753

586

713

1 197

1 136

1 074

5.9

1.4

Shipping

796

796

838

778

525

362

‐0.8

‐2.9

Buildings

2 892

2 851

3 045

2 267

1 434

1 029

‐3.2

‐3.7

Residential

1 963

1 983

2 066

1 559

1 002

748

‐3.1

‐3.4

Services

929

868

979

708

432

282

‐3.5

‐4.2

Total CO2 removals**

‐

1

2

86

431

918

53

24

Total CO2 captured**

4

42

43

517

2 428

4 299

32

17

*Includes emissions from industrial processes and flaring.

444

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

**Includes emissions from industrial processes.

Energy supply: World
STEPS

STEPS

STEPS

NZE

NZE

NZE

9

Table A.1c: World energy supply

29

Energy supply: WorldCAAGR (%)
2021 to:Shares (%)

Net Zero Emissions by 2050 Scenario (EJ)
2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total energy supply

542

592

624

561

524

532

100

100

100

‐1.2

‐0.5

Renewables

45

69

74

172

307

373

12

31

70

9.9

5.8

Solar

1

5

5

34

87

124

1

6

23

23

11

Wind

1

6

7

28

67

85

1

5

16

17

9.1
2.3

Hydro

12

16

16

21

27

30

2

4

6

3.2

Modern solid bioenergy

24

33

36

58

73

74

6

10

14

5.5

2.6

Modern liquid bioenergy

2

4

4

12

14

12

1

2

2

12

3.6

Modern gaseous bioenergy

1

1

1

7

12

15

0

1

3

21

8.8

Other renewables

3

4

5

13

26

34

1

2

6

12

7.1

Traditional use of biomass

25

24

24

‐

‐

‐

4

‐

‐

n.a.

n.a.

Nuclear

30

29

30

43

59

63

5

8

12

3.8

2.6

Unabated natural gas

115

139

146

105

34

14

23

19

3

‐3.6

‐7.8

Natural gas with CCUS
Oil

0

0

0

8

21

27

0

1

5

38

15

173

172

183

143

76

40

29

26

7

‐2.7

‐5.1

25

29

31

34

32

29

5

6

5

1.1

‐0.2

Unabated coal

153

157

165

86

15

2

26

15

0

‐7.1

‐14

Coal with CCUS

‐

0

0

3

13

14

0

1

3

91

29

Electricity and heat sectors

200

228

242

246

311

381

100

100

100

0.2

1.6

Renewables

21

37

40

107

228

293

17

43

77

12

7.1

Solar PV

0

3

4

27

69

97

1

11

26

25

12

Wind

1

6

7

28

67

85

3

11

22

17

9.1

Hydro

12

16

16

21

27

30

6

8

8

3.2

2.3

Bioenergy

5

9

10

18

33

38

4

7

10

6.5

4.6

Other renewables

2

4

4

13

31

44

2

5

12

15

8.9

‐

‐

‐

3

7

7

‐

1

2

n.a.

n.a.
n.a.

of which non‐energy use

HydrogenAmmonia

‐

‐

‐

1

3

3

‐

0

1

n.a.

Nuclear

30

29

30

43

59

63

13

17

17

3.8

2.6

Unabated natural gas

47

55

57

40

1

1

24

16

0

‐3.8

‐14

‐

‐

‐

1

3

4

‐

0

1

n.a.

n.a.

Oil

11

7

8

2

0

0

3

1

0

‐13

‐17

Unabated coal

91

99

107

47

0

0

44

19

0

‐8.6

‐33

Coal with CCUS

‐

0

0

2

8

9

0

1

2

89

28

51

59

61

65

72

75

100

100

100

0.6

0.7

‐

5

6

14

16

13

100

100

100

10

2.7

Production inputs

‐

0

0

14

41

58

100

100

100

126

35

Production outputs

‐

0

0

9

28

42

100

100

100

131

37

For hydrogen‐based fuels

‐

‐

‐

2

9

14

‐

23

34

n.a.

n.a.

For other energy sector

‐

‐

‐

0

0

0

‐

5

1

n.a.

n.a.

Natural gas with CCUS

Other energy sector
Biofuels conversion losses

Annex A | Tables for scenario projections

445

CC BY-NC-SA 4.0.

Low‐emissions hydrogenATotal final consumption: World
STEPS

STEPS
STEPS
NZE
NZE
Table
A.2c:
World
final NZE
consumption

929

Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Total final consumption

383

417

439

398

356

337

100

100

100

‐1.1

‐0.9

Electricity

64

82

87

110

149

176

20

28

52

2.6

2.5

Liquid fuels

154

159

170

146

91

59

39

37

17

‐1.7

‐3.6

Biofuels

2

4

4

12

14

12

1

3

4

12

3.6

Ammonia

‐

‐

‐

1

2

4

‐

0

1

n.a.

n.a.

Synthetic oil
Oil
Gaseous fuels

‐

‐

‐

0

2

4

‐

0

1

n.a.

n.a.

151

155

166

134

72

39

38

34

11

‐2.4

‐4.9

58

68

72

64

53

46

17

16

14

‐1.4

‐1.6

Biomethane

0

0

0

5

7

7

0

1

2

40

13

Hydrogen

‐

0

0

4

12

21

0

1

6

109

33

Synthetic methane

‐

‐

‐

‐

‐

‐

‐

‐

‐

n.a.

n.a.

57

68

72

54

32

16

16

14

5

‐3.1

‐5.1

95

92

94

62

44

34

21

15

10

‐4.6

‐3.4

Solid bioenergy

38

39

40

26

26

28

9

6

8

‐4.8

‐1.2

Coal

56

52

53

35

17

6

12

9

2

‐4.4

‐7.1

Heat

12

13

13

10

7

5

3

3

2

‐2.9

‐3.2

Other

1

2

3

7

13

17

1

2

5

11

6.5

Industry

143

160

167

172

165

155

100

100

100

0.3

‐0.2

Electricity

27

34

37

50

66

78

22

29

50

3.4

2.6

Liquid fuels

29

32

33

34

28

23

20

20

15

0.2

‐1.3

Oil

29

32

33

34

27

22

20

20

14

0.1

‐1.5

24

30

31

32

28

21

18

19

14

0.5

‐1.3

Biomethane

0

0

0

2

3

5

0

1

3

42

16

Hydrogen

‐

‐

‐

2

4

5

‐

1

3

n.a.

n.a.

Unabated natural gas

24

29

31

28

17

6

18

16

4

‐1.1

‐5.6

Natural gas with CCUS

0

0

0

1

3

5

0

1

3

47

20

58

58

59

50

36

27

36

29

17

‐2.0

‐2.7

Natural gas
Solid fuels

Gaseous fuels

Solid fuels
Solid bioenergy

8

10

11

15

19

20

7

9

13

3.7

2.2

Unabated coal

50

47

48

33

13

1

29

19

1

‐3.9

‐12

Coal with CCUS
Heat

‐

‐

‐

1

4

5

‐

0

3

n.a.

n.a.

5

6

7

5

3

1

4

3

1

‐3.6

‐5.6

Other

0

0

0

2

4

5

0

1

3

51

18

Iron and steel

31

35

36

33

31

27

22

19

17

‐0.9

‐1.1

Chemicals

37

46

48

53

52

49

29

31

31

1.0

0.0

Cement

10

12

12

12

11

10

7

7

7

‐0.5

‐0.7

446

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Net Zero Emissions by 2050 Scenario (EJ)

Total final consumption: World

Table A.2c: World final consumption (continued)
Total final consumption: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021

2030

2050

2030

2050

Transport

102

105

113

101

80

77

100

100

100

‐1.3

‐1.3

Electricity

1

1

2

8

24

37

1

8

48

20

11

Liquid fuels

97

99

107

88

46

25

94

87

32

‐2.1

‐4.9

Biofuels

2

4

4

11

12

10

4

11

13

11

3.0

Oil

95

95

103

76

30

7

90

76

9

‐3.2

‐8.8

Gaseous fuels

4

5

5

5

9

15

5

5

20

‐0.4

3.8

Biomethane

0

0

0

0

0

0

0

0

1

11

6.6

Hydrogen

‐

0

0

1

7

14

0

1

18

91

33

Natural gas

4

5

5

3

2

0

5

3

1

‐4.3

‐8.2

Road

76

81

87

72

52

48

77

71

62

‐2.1

‐2.1

Passenger cars

39

42

45

31

19

17

40

31

22

‐4.2

‐3.3

Heavy‐duty trucks

21

25

26

27

24

21

23

27

28

0.4

‐0.7

Aviation

11

8

10

14

13

14

9

14

19

3.7

1.3

Shipping

10

10

11

11

10

10

10

11

13

0.1

‐0.3

Buildings

117

128

132

99

88

85

100

100

100

‐3.2

‐1.5

Electricity

35

43

45

48

54

57

34

48

67

0.6

0.8

Liquid fuels

13

13

14

9

4

1

10

9

1

‐4.3

‐8.0

Biofuels

0

0

0

0

0

0

0

0

0

16

9.9

Oil

13

13

14

9

3

1

10

9

1

‐4.4

‐9.1
‐6.4

Gaseous fuels

27

30

31

21

10

5

24

21

5

‐4.4

Biomethane

0

0

0

3

3

1

0

3

2

49

11

Hydrogen

‐

‐

‐

0

1

1

‐

0

2

n.a.

n.a.

Natural gas
Solid fuels

26

29

31

17

4

‐

23

17

‐

‐6.5

n.a.

35

33

33

11

7

7

25

11

8

‐12

‐5.3

Modern biomass

4

4

4

10

7

7

3

10

8

9.8

1.6

Traditional use of biomass

25

24

24

‐

‐

‐

18

‐

‐

n.a.

n.a.

Coal

6

4

4

1

0

0

3

1

0

‐17

‐21

6

7

7

5

5

4

5

5

5

‐2.2

‐1.8

Heat
Other

1

2

3

5

9

11

2

5

13

7.5

5.1

Residential

83

91

94

65

57

56

71

65

66

‐4.0

‐1.8

Services

33

37

39

34

32

29

29

35

34

‐1.3

‐1.0

Other

22

24

26

26

23

20

100

100

100

‐0.2

‐1.0

Annex A | Tables for scenario projections

447

CC BY-NC-SA 4.0.

Net Zero Emissions by 2050 Scenario (EJ)A

Electricity sector: World
STEPS

STEPS
STEPS
NZE
NZE
NZE
Table
A.3c:
World
electricity
sector9

29

Electricity sector: WorldCAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total generation

21 53926 70828 33437 72357 92473 231

100

100

100

3.2

3.3

Renewables

4 234

7 539

8 060

23 06449 67564 506

28

61

88

12

7.4

Solar PV

32

824

1 003

7 552

19 23927 006

4

20

37

25

12

Wind

342

1 597

1 870

7 840

18 55523 486

7

21

32

17

9.1

Hydro

3 449

4 343

4 327

5 725

7 637

8 251

15

15

11

3.2

2.3

341

666

746

1 442

2 610

3 280

3

4

4

7.6

5.2

‐

‐

‐

96

510

639

‐

0

1

n.a.

n.a.

CSP

2

14

15

175

911

1 500

0

0

2

31

17

Geothermal

68

95

97

312

655

857

0

1

1

14

7.8

Bioenergyof which BECCS

MarineNuclear

1

1

1

20

69

125

0

0

0

38

18

2 756

2 673

2 776

3 896

5 413

5 810

10

10

8

3.8

2.6
n.a.

Hydrogen and ammonia

‐

‐

‐

603

1 415

1 467

‐

2

2

n.a.

Fossil fuels with CCUS

‐

1

1

282

1 211

1 317

0

1

2

92

29

Coal with CCUS

‐

1

1

198

765

827

0

1

1

84

27

Natural gas with CCUS

‐

‐

‐

84

446

490

‐

0

1

n.a.

n.a.

14 49416 43517 436

9 824

168

85

62

26

0

‐6.2

‐17

Coal

8 670

9 439

10 201

4 666

0

0

36

12

0

‐8.3

‐32

Natural gas

4 855

6 333

6 552

4 977

164

82

23

13

0

‐3.0

‐14

969

664

682

180

4

3

2

0

0

‐14

‐17

Unabated fossil fuels

Oil

Net Zero Emissions by 2050 Scenario (GW)CAAGR (%)
2021 to:Shares (%)

2010

2020

2021

2030

2040

2050

2021 2030 2050

2030

2050

Total capacity

5 198

7 849

8 185

15 30626 87033 878

100

100

100

7.2

5.0

Renewables

1 343

2 989

3 278

10 34921 39827 304

40

68

81

14

7.6

Solar PV

39

741

892

5 052

11 62015 468

11

33

46

21

10

Wind

181

737

832

3 072

6 435

7 795

10

20

23

16

8.0

Hydro

2.4

1 027

1 329

1 358

1 782

2 349

2 685

17

12

8

3.1

Bioenergy

83

160

173

320

585

744

2

2

2

7.1

5.2

of which BECCS

‐

‐

‐

22

98

119

‐

0

0

n.a.

n.a.

CSP

1

6

7

64

283

437

0

0

1

28

15

Geothermal

11

15

16

50

98

126

0

0

0

14

7.5

MarineNuclear

0

1

1

9

28

49

0

0

0

30

15

403

415

413

535

777

871

5

3

3

2.9

2.6

Hydrogen and ammonia

‐

‐

‐

189

640

573

‐

1

2

n.a.

n.a.

Fossil fuels with CCUS

‐

0

0

62

266

335

0

0

1

100

31

Coal with CCUS

‐

0

0

44

168

201

0

0

1

92

29

Natural gas with CCUS

‐

‐

‐

18

98

134

‐

0

0

n.a.

n.a.
‐5.3

Unabated fossil fuels

3 448

4 421

4 462

3 389

1 476

932

55

22

3

‐3.0

Coal

1 621

2 161

2 184

1 452

401

184

27

9

1

‐4.4

‐8.2

Natural gas

1 389

1 830

1 850

1 724

1 004

711

23

11

2

‐0.8

‐3.2

438

430

427

213

71

38

5

1

0

‐7.5

‐8.0

1

18

27

778

2 311

3 860

0

5

11

45

19

Oil
Battery storage

448

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Net Zero Emissions by 2050 Scenario (TWh)CO₂ emissions: World
STEPS

STEPS
NZE
NZE
Table
A.4c: STEPSWorld CO
2 emissions

NZE

9

29

CO₂ emissions: WorldCAAGR (%)
2021 to:Net Zero Emissions by 2050 Scenario (Mt CO2)
2010

2020

2021

2030

2040

2050

2030

2050

Total CO2*

32 89334 77936 63922 846

5 799

‐

‐5.1

n.a.

Combustion activities (+)

30 64331 90433 68020 590

5 103

510

‐5.3

‐13

Coal

13 85514 33515 106

7 578

1 140

114

‐7.4

‐16

Oil

10 576

10 19410 850

7 710

3 030

722

‐3.7

‐8.9

Natural gas

6 067

7 162

7 520

5 282

1 391

405

‐3.8

‐9.6

146

213

204

19

‐ 458

‐ 731

‐23

n.a.

Industry removals (‐)

‐

1

2

156

530

787

65

23

Biofuels production

‐

1

1

102

308

394

71

24

Direct air capture

‐

‐

1

54

222

393

57

23

Electricity and heat sectors

12 47413 50214 378

7 076

‐ 189

‐ 351

‐7.6

‐188

Coal

8 946

9 750

10 507

4 653

49

27

‐8.7

‐19

Oil

828

557

574

167

18

2

‐13

‐17

2 623

3 095

3 195

2 264

80

42

‐3.8

‐14

Bioenergy and waste

Natural gas
Bioenergy and waste

78

99

101

‐9

‐ 335

‐ 421

‐176

n.a.

Other energy sector**

1 438

1 487

1 522

966

112

‐ 266

‐4.9

‐194

Final consumption**18 72019 52220 46814 765

6 092

1 005

‐3.6

‐9.9

Coal

4 707

4 474

4 499

2 835

1 043

73

‐5.0

‐13

Oil

9 117

9 080

9 704

7 162

2 865

651

‐3.3

‐8.9

Natural gas

2 859

3 321

3 561

2 491

1 094

213

‐3.9

‐9.3

67

114

102

29

‐ 96

‐ 205

‐13

n.a.

8 379

9 132

9 316

7 168

3 246

396

‐2.9

‐10

Iron and steel**

2 104

2 724

2 755

2 091

965

177

‐3.0

‐9.0

Chemicals**

1 183

1 287

1 342

1 137

546

38

‐1.8

‐12

Cement**

1 928

2 458

2 526

1 910

869

76

‐3.1

‐11

7 011

7 113

7 670

5 687

2 258

535

‐3.3

‐8.8

Bioenergy and waste
Industry**

Transport
Road

5 214

5 485

5 858

3 988

1 370

195

‐4.2

‐11

Passenger cars

2 622

2 803

3 018

1 691

422

45

‐6.2

‐13

Heavy‐duty trucks

1 468

1 688

1 791

1 574

746

136

‐1.4

‐8.5

753

586

713

884

511

199

2.4

‐4.3

Aviation
Shipping

796

796

838

673

304

107

‐2.4

‐6.8

2 892

2 851

3 045

1 632

475

55

‐6.7

‐13

Residential

1 963

1 983

2 066

1 197

369

55

‐5.9

‐12

Services

929

868

979

435

106

1

‐8.6

‐22

Total CO2 removals**

‐

1

2

234

1 008

1 526

70

26

Total CO2 captured**

4

42

43

1 224

4 422

6 231

45

19

Buildings*Includes emissions from industrial processes and flaring.

Annex A | Tables for scenario projections

449

CC BY-NC-SA 4.0.

**Includes emissions from industrial processes.

A

Table A.5: Total energy supply (EJ)
Total energy supply (EJ)

StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

World

542.0

592.3

624.2

673.3

740.0

635.6

629.1

North America

112.5

106.7

111.4

108.8

103.3

103.8

88.0

United States

94.1

87.2

91.4

87.3

80.4

83.2

69.1

26.7

26.8

28.5

32.2

41.1

32.8

37.0

12.1

13.3

14.1

16.0

19.8

16.7

17.6
59.7

Central and South America
BrazilEuropeEuropean Union
Africa

89.4

77.9

82.3

76.4

70.0

72.3

64.5

55.6

59.3

53.2

45.2

49.9

38.7

28.9

35.1

36.4

44.0

64.7

37.0

53.0

Middle East

27.0

33.6

34.8

41.8

55.0

39.5

47.9

Eurasia

35.4

38.9

41.1

39.1

42.0

37.5

37.9

Russia

28.7

31.8

33.6

30.7

31.0

29.6

28.9

Asia Pacific

207.0

260.9

275.6

310.7

335.6

293.5

286.4
133.3

China

107.3

147.7

156.8

166.4

156.5

158.3

India

27.9

36.6

39.5

53.3

70.2

48.1

56.3

Japan

20.9

16.1

16.5

14.9

12.3

14.6

10.9

Southeast Asia

22.8

29.2

30.2

40.0

53.7

38.2

45.2

Table
Table A.6:
A.6: Renewables
Renewables energy
energy supply
supply (EJ)
(EJ)
Renewables energy supply (EJ)

2010

2020

2021

2030

2050

2030

2050

44.5

68.7

73.6

116.2

214.9

141.5

319.0

North America

9.2

12.1

12.8

19.7

33.5

26.1

49.8

United States

6.8

9.3

9.9

15.8

27.9

20.8

41.6

World

Central and South America

7.9

9.7

10.0

13.3

20.7

16.5

27.3

Brazil

5.6

6.9

6.9

9.0

12.6

10.9

14.2

Europe

10.1

14.2

14.9

20.6

28.1

25.6

39.2

7.9

10.5

11.1

15.1

19.9

18.6

27.0

3.7

5.1

5.4

9.3

20.5

9.7

27.9
12.2

European Union
Africa450

Announced
Pledges

Middle East

0.1

0.2

0.3

1.0

5.2

2.0

Eurasia

1.1

1.4

1.5

1.8

3.4

2.1

5.1

Russia

0.9

1.2

1.3

1.4

2.6

1.4

2.9

Asia Pacific

12.4

25.8

28.6

50.3

102.3

58.7

152.8

China

4.7

12.4

14.0

25.8

49.7

28.6

70.9

India

2.8

5.3

5.5

9.6

23.6

10.9

34.2

Japan

0.9

1.3

1.4

2.1

3.3

2.6

5.0

Southeast Asia

2.8

5.1

5.4

8.7

16.2

10.3

25.1

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalTable A.7: Oil production (mb/d)
Oil production (mb/d)StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

85.5

91.2

92.6

102.4

102.1

93.0

57.2

Processing gains

2.2

2.1

2.3

2.5

2.8

2.3

1.9

World production

83.4

89.1

90.3

99.9

99.3

90.7

55.3

Conventional crude oil

66.8

59.7

60.1

62.5

62.6

56.8

31.0

Tight oil

0.7

7.3

7.4

10.9

9.9

9.7

6.7

Natural gas liquids

12.7

17.9

18.2

20.9

19.3

19.2

13.9

Extra‐heavy oil & bitumen

2.6

3.4

3.7

4.4

6.2

4.1

3.4

Other

0.6

0.8

0.9

1.2

1.3

0.9

0.3

Non‐OPEC

50.0

58.3

58.8

64.0

56.2

58.2

31.6

OPEC

33.3

30.8

31.5

35.9

43.1

32.5

23.7

North America

14.2

23.9

24.4

28.6

24.6

25.8

14.7

Central and South America

7.4

5.9

5.9

9.0

11.4

8.3

6.5

Europe

4.4

3.8

3.6

3.1

1.3

2.7

0.6

0.7

0.5

0.5

0.4

0.3

0.3

0.1

Africa

10.2

7.0

7.4

7.0

6.1

5.8

2.9

Middle East

25.4

27.6

27.9

33.9

40.4

31.2

22.9

Eurasia

13.4

13.4

13.7

11.9

10.6

11.2

5.4

Asia Pacific

8.4

7.5

7.4

6.3

4.8

5.7

2.2

2.6

2.1

1.9

1.5

0.9

1.3

0.5

World supply

European Union

Southeast Asia

Table A.8: Oil demand (mb/d)
Table A.8: Oil demand (mb/d)
Oil demand (mb/d)

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

World

87.2

88.9

94.5

102.4

102.1

93.0

57.2

North America

22.2

20.1

21.4

20.5

16.2

18.2

6.9

United States

17.8

16.5

17.7

16.7

12.6

15.0

5.0

Central and South America
BrazilEurope

5.5

4.9

5.3

5.5

5.8

4.8

2.4

2.3

2.2

2.4

2.4

2.4

2.0

0.9

13.9

11.9

12.4

10.9

7.1

9.2

2.7

10.6

8.9

9.2

7.7

4.5

6.5

1.7

Africa

3.3

3.6

3.8

5.0

8.5

4.9

6.1

Middle East

7.1

7.4

7.7

8.9

10.9

8.0

7.9

Eurasia

3.2

3.8

4.1

4.2

4.5

4.1

3.9

Russia

2.6

3.1

3.3

3.2

3.1

3.1

2.8

Asia Pacific

25.0

31.4

33.3

38.2

36.7

35.1

20.6

China

8.8

13.9

15.1

16.2

12.5

15.2

7.6

India

3.3

4.5

4.7

6.7

8.3

5.9

3.9

European Union

Japan

4.2

3.2

3.3

2.7

1.7

2.4

0.7

Southeast Asia

4.0

4.7

4.9

6.7

7.4

6.0

3.9

International bunkers

7.1

5.8

6.6

9.3

12.4

8.6

6.8

Annex A | Tables for scenario projections

451

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalATable A.9: World liquids demand (mb/d)World liquids demand (mb/d)StatedPolicies

Historical

Announced
Pledges

2020

2021

2030

2050

2030

2050

Total liquids

90.9

96.7

105.8

107.6

98.7

69.6

Biofuels

2.0

2.2

3.4

5.3

5.5

9.2

‐

‐

‐

0.2

0.2

3.2

88.9

94.5

102.4

102.1

93.0

57.2

Hydrogen based fuels
Total oil
CTL, GTL and additives

0.8

0.9

1.1

1.3

1.0

0.3

Direct use of crude oil

1.0

0.8

0.5

0.3

0.4

0.2

87.1

92.8

100.8

100.5

91.6

56.7

13.3

13.6

15.6

15.8

14.4

10.4

Oil products
LPG and ethane
Naphtha

6.4

6.9

7.7

9.5

7.3

7.4

Gasoline

21.9

23.6

23.2

19.3

20.6

8.2

Kerosene

4.7

5.7

9.2

11.8

8.7

7.6

Diesel

25.0

26.5

28.2

28.2

25.0

12.6

Fuel oil

5.7

5.9

5.5

6.3

4.8

2.5

Other products

10.1

10.6

11.4

9.6

10.8

8.0

Products from NGLs

11.3

11.5

13.4

11.6

12.7

8.8

Refinery products
Refinery market share

75.8
83%

81.3
84%

87.4
83%

88.9
83%

78.9
80%

47.9
69%

Note: CTL = coal‐to‐liquids; GTL = gas‐to‐liquids; LPG = liquefied petroleum gas;
NGLs = natural gas liquids.

Table A.10: Refining capacity and runs (mb/d)
Table A.10: Refining capacity and runs (mb/d)
Refining capacity and refinery runs (mb/d)

Refinery runs
STEPS

APS

APS

2021

2030

2050

2030

2050

2021

2030

2050

2030

2050

North America

21.6

21.1

20.8

20.1

11.1

17.6

18.5

18.1

16.5

7.5

Europe

15.8

14.5

13.3

14.0

6.9

12.0

11.4

9.4

10.2

3.9

Asia Pacific

37.1

40.3

41.5

39.4

28.3

29.2

33.1

34.7

30.5

18.9

Japan and Korea

7.0

6.3

5.8

6.2

3.5

5.1

5.0

4.6

4.6

2.2

China

17.5

19.0

19.0

18.5

11.1

14.2

14.5

14.1

13.4

6.4

India

5.3

6.6

7.8

6.4

5.4

4.8

6.4

7.6

5.7

4.0

Southeast Asia

5.3

6.3

6.8

6.3

6.3

3.7

5.5

6.4

5.1

4.7

Middle East

9.6

11.2

12.0

11.0

9.7

7.6

9.6

10.6

8.5

6.6

Russia

6.9

6.5

6.3

6.1

4.6

5.6

4.0

3.5

3.6

2.4

Africa

3.4

4.5

4.8

4.2

4.2

1.8

3.1

3.9

2.7

2.6

Brazil

2.2

2.3

2.3

2.0

1.6

1.8

2.1

2.2

1.7

1.2

Other
World

4.6

4.8

4.8

4.7

4.2

2.3

2.9

3.5

2.8

2.6

101.2

105.2

105.8

101.5

70.6

77.9

84.7

85.9

76.5

45.7

Atlantic Basin

54.1

53.6

52.2

51.0

32.5

40.9

41.9

40.4

37.3

20.1

East of Suez

47.1

51.6

53.6

50.5

38.1

37.0

42.9

45.5

39.1

25.6

452

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

Refining capacity
STEPS

Table A.11: Natural gas production (bcm)
Natural gas production (bcm)World
Conventional gas

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

3 274

3 996

4 149

4 372

4 355

3 874

2 660
2 016

2 768

2 854

2 964

2 962

3 025

2 727

Tight gas

274

311

306

317

139

191

37

Shale gas

155

747

790

995

1 091

874

557

Coalbed methane

77

80

82

74

75

58

50

‐

4

7

24

25

24

‐

811

1 164

1 189

1 283

1 017

1 098

485

Other
North America
Central and South America

160

154

151

149

195

133

95

Europe

341

245

239

247

208

176

65

European Union
Africa

148

56

51

39

34

16

2

203

237

265

313

369

281

239

Middle East

463

646

660

853

1 030

798

690

Eurasia

807

911

998

831

857

751

654

Asia Pacific

488

639

648

694

678

636

432

216

194

195

183

129

162

109

Southeast Asia

Table A.12: Natural gas demand (bcm)
Natural gas demand (bcm)
Table A.12: Natural gas demand (bcm)StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

3 329

4 027

4 213

4 372

4 357

3 874

2 661

North America

835

1 096

1 106

1 118

820

933

396

United States

678

867

871

864

575

716

252

147

149

161

159

179

141

96

29

34

42

34

37

28

17
122

World

Central and South America
BrazilEurope

698

594

625

511

395

394

446

397

421

340

235

242

45

Africa

105

164

172

215

292

189

193

Middle East

391

554

567

689

833

638

582

Eurasia

578

611

662

626

635

587

532

Russia

472

501

543

498

470

470

424

Asia Pacific

576

859

920

1 043

1 173

983

731

China

110

324

368

443

442

406

238

India

64

61

66

115

170

110

102

Japan

95

104

103

64

43

57

17

Southeast Asia

150

160

162

203

272

194

177

International bunkers

‐

‐

‐

11

30

8

8

European Union

Annex A | Tables for scenario projections

453

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalATable A.13: Coal production (Mtce)
Coal production (Mtce)

StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

5 235

5 459

5 826

5 149

3 829

4 539

1 613

Steam coal

4 069

4 293

4 560

4 026

2 954

3 538

1 177

Coking coal

866

939

1 030

936

736

855

381

Lignite and peat

300

227

235

187

139

146

56

818

409

478

188

106

138

32

World

North America
Central and South America

79

53

62

41

41

24

3

Europe

331

185

200

126

59

79

20

220

125

138

71

10

46

8

210

211

212

188

171

162

47

European Union
AfricaMiddle East
Eurasia
Asia PacificSoutheast Asia

1

1

1

1

1

‐

‐

309

400

444

323

274

292

216

3 487

4 200

4 428

4 282

3 177

3 843

1 295

318

481

499

460

474

423

262

Table A.14: Coal demand (Mtce)
Coal demand (Mtce)

Announced
Pledges

World

2020

2021

2030

2050

2030

2050

5 347

5 644

5 149

3 828

4 539

1 613

North America

768

342

389

107

42

80

30

United States

716

317

363

91

26

64

17

37

41

46

40

60

28

20

21

20

25

23

29

16

12

Central and South America
BrazilEuropeEuropean Union
AfricaMiddle East
Eurasia

454

2010

5 220

539

334

369

229

167

157

72

360

206

238

125

56

79

20

156

153

152

148

131

119

30

5

5

5

8

12

7

9

203

218

222

172

160

162

121

Russia

151

164

166

114

102

113

95

Asia Pacific

3 513

4 254

4 460

4 444

3 258

3 986

1 332

China

2 565

3 037

3 157

2 974

1 866

2 691

789

India

399

542

614

773

671

704

243

Japan

165

146

143

103

62

97

35

Southeast Asia

122

258

269

337

422

295

151

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

StatedPolicies

Historical

Table A.14: Coal demand (Mtce)

Table A.15: Electricity generation (TWh)Electricity generation (TWh)StatedPolicies

HistoricalWorld

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

21 53926 70828 33434 83449 84535 87861 268

North America

5 233

5 205

5 357

5 771

7 816

6 043

9 749

United States

4 354

4 239

4 371

4 625

6 270

4 869

7 937

1 130

1 276

1 331

1 605

2 592

1 789

3 543

516

621

639

762

1 174

811

1 387

Central and South America
BrazilEuropeEuropean Union

4 120

3 956

4 182

4 691

5 703

5 165

7 539

2 956

2 758

2 963

3 238

3 689

3 583

5 017

Africa

687

835

869

1 204

2 337

1 330

3 704

Middle East

829

1 203

1 233

1 651

2 886

1 606

3 460

Eurasia

1 251

1 367

1 455

1 540

1 937

1 525

1 925

Russia

1 036

1 087

1 158

1 177

1 376

1 149

1 296

Asia Pacific

8 288

12 866

13 90818 371

26 57318 42031 350

China

4 236

7 767

8 539

11 13614 34210 95816 109

India

974

1 533

1 686

2 708

5 298

2 689

6 553

Japan

1 164

1 009

1 024

969

992

1 036

1 303

685

1 116

1 164

1 704

3 143

1 751

3 561

Southeast Asia

Table A.16:
A.16: Renewables
Renewables generation
generation (TWh)
(TWh)
Table
Renewables generation (TWh)Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

4 234

7 539

8 060

15 07332 45217 57548 873

North America

860

1 334

1 385

2 668

5 858

3 361

7 895

United States

445

833

874

2 034

4 849

2 620

6 573
3 365

World

Central and South America

743

888

910

1 287

2 287

1 501

Brazil

437

525

509

700

1 099

761

1 329

Europe

963

1 596

1 631

2 836

4 249

3 491

6 422
4 318

660

1 069

1 112

1 971

2 854

2 470

AfricaEuropean Union

115

184

197

440

1 429

665

3 234

Middle East

18

35

48

166

966

234

2 227

Eurasia

229

279

285

340

545

384

786

Russia

170

219

222

249

399

252

416

Asia Pacific

1 306

3 223

3 604

7 334

17 1177 938

24 944

China

791

2 192

2 466

4 901

9 658

5 056

12 704

India

162

325

337

956

3 866

990

5 745

Japan

115

216

232

356

586

391

768

Southeast Asia

105

266

296

506

1 463

668

2 802

Annex A | Tables for scenario projections

455

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalATable A.17: Solar PV generation (TWh)Solar PV generation (TWh)StatedPolicies

HistoricalWorld

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

32

824

1 003

4 011

12 1184 838

18 761

North America

3

130

162

708

2 556

947

3 286

United States

3

116

145

668

2 350

894

2 963
1 104

Central and South America

0

25

32

189

568

290

Brazil

0

11

14

119

340

137

446

Europe

23

176

198

553

764

688

1 184

22

139

151

461

584

567

777

0

12

15

88

384

177

1 380
1 153

European Union
AfricaMiddle East

0

10

12

89

522

114

Eurasia

0

4

4

14

31

16

45

Russia

0

2

2

5

12

5

14
10 609Asia Pacific

6

467

580

2 371

7 294

2 606

China

1

261

326

1 474

3 911

1 586

5 442

India

0

61

73

424

2 163

453

3 144

Japan

4

79

91

147

203

154

205

Southeast Asia

0

19

29

106

473

131

911

Table
Table A.18:
A.18: Wind
Wind generation
generation (TWh)(TWh)
Wind generation (TWh)

2010

2020

2021

2030

2050

2030

2050

World

342

1 597

1 870

4 604

10 691

5 816

17 416

North America

105

397

436

1 047

2 192

1 415

3 290

United States

95

342

379

948

1 931

1 235

2 801

3

85

108

219

457

289

893

2

57

73

137

259

152

305

Central and South America
BrazilEurope

154

513

503

1 196

2 081

1 626

3 575

140

397

396

893

1 495

1 226

2 608

Africa

2

18

22

81

295

143

724

Middle East

0

2

4

26

246

58

704
213

European Union

456

Announced
Pledges

Eurasia

0

1

5

23

91

51

Russia

0

0

3

14

70

16

83

Asia Pacific

77

581

794

2 011

5 329

2 236

8 017

China

45

466

655

1 543

3 312

1 577

4 345

India

20

67

77

211

1 116

213

1 550

Japan

4

9

9

59

186

75

299

Southeast Asia

0

6

12

53

232

124

602

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalTable A.19: Nuclear generation (TWh)
Nuclear generation (TWh)StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

2 756

2 673

2 776

3 351

4 260

3 547

5 103

North America

935

929

913

905

885

924

1 086

United States

839

823

813

807

755

826

914

22

25

25

30

60

34

70

Brazil

15

14

15

21

34

24

39

Europe

1 032

834

889

844

778

896

825
603

World

Central and South America

854

684

733

656

570

705

AfricaEuropean Union

12

10

13

25

45

30

75

Middle East

0

6

14

51

96

62

138

Eurasia

173

219

219

232

293

235

306

Russia

170

216

217

230

283

232

289

Asia Pacific

582

650

702

1 264

2 103

1 367

2 603

China

74

366

408

643

1 209

718

1 494

India

26

43

42

128

337

131

358

Japan

288

39

56

190

206

219

271

0

0

0

0

25

0

98

Southeast Asia

Table
Table A.20:
A.20: Natural
Natural gas
gas generation
generation (TWh)(TWh)
Natural gas generation (TWh)World

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

4 855

6 333

6 551

6 848

6 730

6 142

3 902

North America

1 217

1 931

1 908

1 953

1 024

1 550

599

United States

1 018

1 679

1 641

1 555

620

1 231

283

Central and South America

178

229

256

222

213

214

89

Brazil

36

53

76

27

30

21

10

Europe

946

844

902

606

402

531

127

589

555

587

400

219

292

30

234

346

360

470

680

390

308

European Union
AfricaMiddle East

527

873

888

1 198

1 606

1 128

988

Eurasia

603

604

682

762

897

711

697

Russia

521

469

535

589

598

554

501

Asia Pacific

1 151

1 506

1 555

1 636

1 908

1 617

1 094

China

92

256

291

345

344

316

330

India

107

66

70

115

156

107

70

Japan

332

395

386

198

74

192

69

Southeast Asia

336

350

361

529

787

503

334

Annex A | Tables for scenario projections

457

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalATable A.21: Coal generation (TWh)Coal generation (TWh)StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

World

8 670

9 439

10 202

9 049

5 952

8 109

2 594

North America

2 106

912

1 045

213

32

139

38

United States

1 994

856

994

201

31

128

37
1

Central and South America

42

61

68

33

21

8

Brazil

11

18

27

10

8

1

0

Europe

1 068

603

678

352

233

201

113

755

383

460

168

16

78

23

259

248

244

205

115

171

22

0

1

1

4

16

3

15

Eurasia

235

256

258

203

202

193

137

Russia

166

176

175

107

96

110

91

Asia Pacific

4 958

7 359

7 908

8 040

5 335

7 394

2 268

European Union
AfricaMiddle East

China

3 263

4 941

5 363

5 239

3 118

4 855

1 511

India

658

1 097

1 234

1 504

937

1 458

307

Japan

317

311

294

187

63

192

50

Southeast Asia

185

487

493

656

858

571

231

Table
Table A.22:
A.22: Total
Total final
final consumption
consumption (EJ)
(EJ)
Total final consumption (EJ)

2010

2020

2021

2030

2050

2030

2050

383.2

417.5

439.1

484.5

543.6

450.8

432.7

North America

76.6

73.7

77.5

78.5

75.1

73.8

57.7

United States

63.8

61.6

65.1

64.8

60.2

60.9

46.3
22.0

World

Central and South America

19.2

19.3

20.4

23.3

29.1

21.9

Brazil

9.1

9.5

10.0

11.1

13.4

10.5

10.4

Europe

63.1

57.2

60.0

57.4

51.6

53.4

39.7

European Union
Africa458

Announced
Pledges

45.9

41.3

43.5

40.5

34.0

37.6

26.1

20.9

25.3

26.2

31.8

47.4

27.4

37.0

Middle East

19.2

23.1

24.1

29.6

40.0

27.9

34.2

Eurasia

23.8

27.0

28.5

28.2

30.7

27.3

27.6

Russia

19.2

22.1

23.3

22.1

22.5

21.5

21.0

Asia Pacific

145.4

179.5

188.4

215.6

241.2

199.7

191.6

China

76.3

100.2

105.7

114.0

111.2

107.8

91.0

India

19.0

25.8

27.5

37.3

53.8

32.2

39.6

Japan

14.2

11.8

12.1

11.1

9.3

10.5

7.3

Southeast Asia

16.1

19.3

19.8

26.5

34.7

24.5

27.1

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalTable A.23: Industry consumption (EJ)
Industry consumption (EJ)

StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

143.2

160.4

166.7

189.4

208.8

178.1

173.7

North America

17.9

18.3

18.6

20.9

22.1

20.0

18.4

United States

14.2

14.5

14.7

16.2

16.8

15.6

13.8
8.2

World

Central and South America

7.2

6.7

7.0

8.2

9.8

7.7

Brazil

4.0

3.8

4.0

4.5

5.1

4.2

4.3

Europe

19.6

18.4

18.9

18.9

17.7

18.1

15.5
10.3

14.3

13.4

13.9

13.7

11.7

13.1

AfricaEuropean Union

3.9

4.0

4.2

6.1

10.3

5.9

8.7

Middle East

7.8

9.7

10.2

12.7

15.3

11.9

12.9

Eurasia

8.4

9.3

9.5

9.3

10.3

9.0

9.3

Russia

6.9

8.1

8.2

7.8

8.4

7.6

7.7

Asia Pacific

78.4

94.1

98.3

113.3

123.4

105.5

100.7

China

49.4

59.4

61.5

66.7

62.4

62.4

51.2

India

7.9

11.5

12.4

18.1

27.5

16.1

21.6

Japan

6.1

5.0

5.3

5.1

4.5

4.8

3.8

Southeast Asia

6.2

8.4

8.8

11.4

15.2

10.7

12.6

Table A.24:
A.24: Transport
Transport consumption
consumption (EJ)
(EJ)
Table
Transport consumption (EJ)World

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

101.7

105.0

113.4

129.8

147.0

123.7

112.5

North America

29.6

26.9

29.1

28.4

24.9

26.7

18.0

United States

25.0

23.0

25.1

24.0

20.4

22.5

15.0

6.1

6.5

7.2

8.3

10.6

7.9

7.3

2.9

3.4

3.6

4.0

4.6

3.8

3.4
8.4

Central and South America
BrazilEurope

15.6

14.4

15.3

14.5

11.7

13.6

11.7

10.6

11.1

10.0

7.5

9.4

5.5

Africa

3.7

4.7

5.0

6.3

11.3

6.3

10.1

Middle East

4.9

5.3

5.7

6.4

8.9

6.1

6.9

Eurasia

4.7

4.8

5.2

5.4

5.8

5.2

5.1

Russia

4.0

3.8

4.1

3.8

3.3

3.8

3.0

Asia Pacific

22.1

30.1

32.0

40.3

45.5

38.4

33.7

China

8.3

13.6

15.0

16.9

15.3

16.2

11.8

India

2.7

3.9

4.2

6.8

10.3

6.5

7.5

Japan

3.3

2.6

2.5

2.2

1.7

2.1

1.1

Southeast Asia

3.7

5.3

5.4

8.4

9.9

7.8

6.9

European Union

Annex A | Tables for scenario projections

459

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalATable A.25: Buildings consumption (EJ)
Buildings consumption (EJ)
StatedPolicies

HistoricalWorld

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

116.8

127.6

132.4

136.5

158.3

121.3

122.0

North America

23.7

23.8

24.2

23.3

22.6

21.3

16.4

United States

20.5

20.3

20.8

19.7

18.4

18.2

13.6

4.4

4.8

4.9

5.4

7.1

4.9

5.2

1.4

1.7

1.7

1.9

2.9

1.7

2.1
13.3

Central and South America
BrazilEuropeEuropean Union
Africa

24.3

21.2

22.2

20.3

19.0

18.4

17.6

15.1

15.9

14.4

12.7

12.8

8.6

12.5

15.8

16.2

18.3

24.0

14.2

16.5
13.1

Middle East

5.3

6.5

6.7

8.9

14.3

8.4

Eurasia

8.4

9.9

10.5

10.2

10.8

9.8

9.8

Russia

6.2

7.4

7.8

7.4

7.2

7.1

7.0

Asia Pacific

38.2

45.5

47.7

50.0

60.6

44.3

47.8

China

15.6

22.2

23.7

24.4

28.8

23.6

24.2

India

7.0

8.1

8.5

9.2

12.2

6.6

7.8

Japan

4.3

3.8

3.9

3.5

3.0

3.2

2.2

Southeast Asia

5.3

4.5

4.5

5.4

8.0

4.6

6.3

Table
Table A.26:
A.26: Hydrogen
Hydrogen demand
demand (PJ)
(PJ)
Total hydrogen demand (PJ)

World

2020

2021

2030

2050

2030

2050

10 730

11 31913 43816 82215 06434 575

North America

1 822

1 937

2 173

2 674

2 835

6 960

United States

1 418

1 530

1 710

2 118

2 335

6 135
1 528

Central and South America

314

344

453

758

580

Brazil

19

22

57

113

81

350

Europe

1 055

1 046

1 109

1 207

1 746

3 890

827

800

827

844

1 308

2 825

331

358

497

769

492

1 322

1 286

1 407

1 914

2 325

1 876

2 939

Eurasia

876

869

879

942

774

861

Russia

815

802

805

859

699

759

Asia Pacific

5 047

5 358

6 409

8 107

6 717

16 348European Union
AfricaMiddle East

460

Announced
Pledges

China

2 879

3 082

3 610

3 936

3 791

7 298

India

975

1 045

1 342

2 134

1 284

3 585

Japan

210

217

244

343

349

1 119

Southeast Asia

452

468

602

848

593

1 566

International bunkers

‐

‐

4

41

46

728

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

StatedPolicies

HistoricalTable A.27: Hydrogen balance (Mt H2 equivalent)Hydrogen balance (Mt H2 equivalent)
STEPS

APS

NZE

2021

2030

2050

2030

2050

2030

2050

1
0

6
4

24
17

30
21

225
167

90
58

452
329

Fossil fuels with CCUS

1

2

8

9

57

31

122

Bioenergy and other

0

0

0

0

1

0

2

Transformation of hydrogen
To power generation

0
‐

3
0

10
1

14
4

95
19

50
27

186
60

To hydrogen‐based fuels

0

0

3

6

69

18

118

In oil refining

0

2

5

3

6

2

4

To biofuels

0

1

1

1

1

3

3

Hydrogen demand for end‐use sectors

0

3

15

16

131

40

266

Low‐emissions hydrogen‐based fuels
Total final consumption

0
0

0
0

3
1

3
3

55
39

15
7

96
68

‐

0

2

0

16

8

28

0
0%

1
10%

5
22%

4
13%

44
19%

18
20%

73
16%

Low‐emission hydrogen production
Water electrolysis

Power generation
Trade
Trade as share of demand

Table A.28: Total CO2 emissions* (Mt CO2)
Total CO₂ emissions* (Mt CO₂)
StatedHistorical

Table A.28: Total CO₂₂ emissions*Policies(Mt CO₂)World

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

32 89334 77936 63936 21131 97931 511

12 399450

North America

6 489

5 319

5 563

4 579

3 167

3 648

United States

5 469

4 382

4 610

3 583

2 180

2 861

43

1 149

1 095

1 187

1 199

1 315

1 002

507

Central and South America
Brazil

412

425

474

460

491

361

166

Europe

4 732

3 748

3 974

3 126

2 280

2 365

417

European Union
Africa

3 312

2 546

2 726

2 020

1 229

1 468

116

1 174

1 315

1 372

1 592

2 179

1 429

1 305

Middle East

1 637

1 942

2 073

2 307

2 706

2 052

1 730

Eurasia

2 159

2 200

2 309

2 107

2 097

1 968

1 649

Russia

1 694

1 731

1 811

1 561

1 414

1 476

1 221

Asia Pacific

14 43318 22719 10919 83916 266

17 690

5 300

China

8 792

11 59312 12911 840

7 970

10 597

2 255

India

1 686

2 229

2 472

3 275

3 325

2 934

977

Japan

1 188

1 025

1 027

755

461

660

32

Southeast Asia

1 162

1 667

1 724

2 186

2 610

1 952

1 063

Annex A | Tables for scenario projections

461

CC BY-NC-SA 4.0.

*Includes emissions from industrial processes and flaring.

ATable A.29: Electricity and heat sectors CO₂₂ emissions (Mt CO₂)
Electricity and heat sectors CO₂ emissions (Mt CO₂)
StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

World

12 47413 50214 37812 7599 308

11 330

3 138

North America

2 596

1 730

1 841

1 000

438

695

49

United States

2 346

1 526

1 633

823

281

548

‐ 57
42

Central and South America

235

224

250

147

106

119

Brazil

46

56

79

27

24

13

6

Europe

1 731

1 131

1 229

744

546

509

82

1 188

732

822

432

200

259

‐7

421

454

473

455

400

388

163

European Union
AfricaMiddle East

550

676

682

710

792

638

461

Eurasia

1 034

949

993

879

880

811

656

Russia

892

771

800

678

625

632

517

Asia Pacific

5 907

8 338

8 910

8 824

6 145

8 170

1 685
986

China

3 486

5 375

5 798

5 605

3 515

5 188

India

785

1 055

1 199

1 446

892

1 395

111

Japan

489

460

446

235

78

226

‐ 12

Southeast Asia

397

692

708

886

1 103

811

339

Table A.30:
A.30: Total
Total final
final consumption
consumption CO₂
CO₂2 emissions*(Mt CO₂)
CO2)
Tableemissions* (MtFinal consumption CO₂ emissions* (Mt CO₂)
StatedPolicies

Historical

Announced
Pledges

2010

2020

2021

2030

2050

2030

2050

World

18 72019 52220 46821 62721 05618 785

9 124

North America

3 474

3 164

3 324

3 149

2 370

2 665

556

United States

2 863

2 601

2 752

2 524

1 743

2 148

259

803

775

842

948

1 095

803

426

342

342

368

397

430

322

147

Central and South America
BrazilEuropeEuropean Union

2 825

2 470

2 585

2 240

1 628

1 767

320

2 010

1 716

1 795

1 496

962

1 159

116

Africa

568

690

727

963

1 610

901

1 101

Middle East

924

1 023

1 134

1 321

1 650

1 198

1 154

Eurasia

930

1 118

1 178

1 114

1 125

1 061

945

Russia

678

859

903

801

727

772

671

Asia Pacific

8 077

9 347

9 625

10 429

9 608

9 033

3 581

China

5 043

5 894

5 994

5 889

4 188

5 121

1 348
843

India

867

1 109

1 205

1 742

2 350

1 474

Japan

671

548

564

506

393

421

65

Southeast Asia

690

904

934

1 231

1 422

1 081

671

462

International Energy Agency | World Energy Outlook 2022

CC BY-NC-SA 4.0.

* Includes emissions from industrial processes.

Annex B
Design of the scenarios

The Net Zero Emissions by 2050 (NZE) Scenario shows a narrow but achievable pathway
for the global energy sector to achieve net zero CO2 emissions by 2050, with advanced
economies reaching net zero emissions in advance of the other scenarios. This scenario
also meets key energy‐related United Nations Sustainable Development Goals (SDGs),
in particular achieving universal energy access by 2030. The NZE Scenario does not relyon emissions reductions from outside the energy sector to achieve its goals, but assumes
that non‐energy emissions will be reduced in the same proportion as energy emissions.
It is consistent with limiting the global temperature rise to 1.5 °C without a temperature
overshoot (with a 50% probability).



The Announced Pledges Scenario (APS) takes account of all the climate commitments
made by governments around the world including Nationally Determined Contributions
as well as longer term net zero emissions targets, and assumes that they will be met infull and on time. The global trends in this scenario represent the cumulative extent of
the world’s ambition to tackle climate change as of mid‐2022. The remaining difference
in global emissions between the APS and the goals in the NZE Scenario shows the“ambition gap” that needs to be closed to achieve the goals agreed in the Paris
Agreement in 2015.

The Stated Policies Scenario (STEPS) does not take for granted that governments willreach all announced goals. Instead, it explores where the energy system might gowithout additional policy implementation. As with the APS, it is not designed to achievea particular outcome. It takes a granular, sector‐by‐sector look at existing policies andmeasures and those under development. The remaining difference in global emissions
between the STEPS and the APS represents the “implementation gap” that needs to beclosed for countries to achieve their announced decarbonisation targets.

Annex B | Design of the scenarios

463

IEA. CC BY 4.0.

The World Energy Outlook‐2022 (WEO‐2022) explores three main scenarios in the analyses
in the chapters. These scenarios are not predictions – the IEA does not have a single view on
the future of the energy system. In contrast to the 2021 edition of the WEO, we do not vary
the assumptions about public health and economic recovery implications across the
scenarios. The scenarios are:

B.1

Population

Table B.1 ⊳Population assumptions by region
Compound averageannual growth rate
2000‐21 2021‐30 2021‐50

Population(million)

Urbanisation(share of population)

2021

2030

2050

2021

2030

2050

North America

0.9%

0.6%

0.5%

502

532

580

82%

84%

89%

United States

0.8%

0.5%

0.4%

335

352

381

83%

85%

89%

C & S America

1.1%

0.7%

0.5%

523

559

601

81%

83%

88%

Brazil

1.0%

0.5%

0.2%

214

224

229

87%

89%

92%

Europe

0.3%

0.0%

‐0.1%

700

701

690

76%

78%

84%

European Union

0.2%

‐0.1%

‐0.2%

451

448

429

75%

77%

84%

Africa

2.5%

2.3%

2.1%

1 372

1 686

2 487

44%

48%

59%

Middle East

2.1%

1.5%

1.1%

252

289

348

73%

76%

81%

Eurasia

0.4%

0.3%

0.2%

237

244

253

65%

67%

73%

Russia

‐0.1%

‐0.2%

‐0.2%

144

142

134

75%

77%

83%

Asia Pacific

1.0%

0.6%

0.4%

4 250

4 496

4 734

50%

55%

65%

China

0.5%

0.2%

‐0.1%

1 423

1 443

1 383

63%

71%

80%

India

1.3%

0.8%

0.6%

1 393

1 504

1 639

35%

40%

53%

Japan

‐0.1%

‐0.5%

‐0.6%

125

120

105

92%

93%

95%

Southeast Asia

1.2%

0.8%

0.6%

674

726

792

51%

56%

66%

World

1.2%

0.9%

0.7%

7 835

8 507

9 692

57%

60%

68%

Notes: C & S America = Central and South America. See Annex C for composition of regional groupings.

Population is a major determinant of many of the trends in the Outlook. We use themedium variant of the United Nations projections as the basis for population growth inall scenarios, but this is naturally subject to a degree of uncertainty.

The 2022 Revision of UN DESA's World Population Prospects could not be incorporated
in this modelling cycle as the modelling was already advanced by its publication time.

The rate of population growth is assumed to slow over time, but the global population
nonetheless exceeds 9.6 billion by 2050 (Table B.1).



More than half of the increase over the projection period to 2050 is in Africa and arounda further third is in the Asia Pacific region.

India adds around 250 million people to its population to become the world’s mostpopulous country, overtaking China, where the population is projected to decrease byaround 40 million.



The share of the world’s population living in towns and cities has been rising steadily, a
trend that is projected to continue over the period to 2050. In aggregate, this meansthat all of the 2 billion increase in global population over the period is added to cities
and towns.

464International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.

Sources: UN DESA (2018, 2019); World Bank (2022a); IEA databases and analysis.

B.2

CO2 prices

Table B.2 ⊳CO2 prices for electricity, industry and energy production
in selected regions by scenario

USD (2021) per tonne of CO2

2030

2040

2050

Canada54

62

77

Chile, Colombia

13

21

29

China

28

43

53

European Union

90

98

113

Korea

42

67

89

Advanced economies with net zero emissions pledges1

135

175

200

Emerging market and developing economies with net zero
emissions pledges 2

40

110

160

‐

17

47

Advanced economies with net zero emissions pledges

140

205

250

Emerging market and developing economies withnet zero emissions pledges

90

160

200

Other emerging market and developing economies

25

85

180

Stated Policies Scenario

Announced Pledges Scenario

Other emerging market and developing economies
Net Zero Emissions by 2050 Scenario

1

Includes all OECD countries except Mexico.

2

Includes China, India, Indonesia, Brazil and South Africa.



There are 68 direct carbon pricing instruments existing today, covering more than
40 countries. Global carbon pricing revenue in 2021 increased by almost 60% from 2020
levels, to around USD 84 billion (World Bank, 2022).



Existing and planned CO2 pricing schemes are reflected in the STEPS, covering electricity
generation, industry, energy production sectors and end‐use sectors, e.g. aviation, roadtransport and buildings, where applicable.

In the APS, higher CO2 prices are introduced across all regions with net zero emissions
pledges. No explicit pricing is assumed in sub‐Saharan Africa (excluding South Africa),
the Caspian region and Other Asia regions. Instead, these regions rely on direct policy
interventions to drive decarbonisation in the APS.

In the NZE Scenario, CO2 prices cover all regions and rise rapidly across all advanced
economies as well as in emerging economies with net zero emissions pledges, including
China, India, Indonesia, Brazil and South Africa. CO2 prices are lower, but nevertheless,rising in other emerging economies such as North Africa, Middle East, Russia andSoutheast Asia. CO2 prices are lower in all other emerging market and developing
economies, as it is assumed they pursue more direct policies to adapt and transformtheir energy systems.

Annex B | Design of the scenarios

465

IEA. CC BY 4.0.

Note: Values are rounded.

B

466

All scenarios consider the effects of other policy measures alongside CO2 pricing, suchas coal phase‐out plans, efficiency standards and renewable targets (Tables B.6 ‐ B.10).
These policies interact with carbon pricing; therefore, CO2 pricing is not the marginal
cost of abatement as is often the case in other modelling approaches

International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.



B.3

Fossil fuel resources

Table B.3 ⊳Remaining technically recoverable fossil fuel resources, 2021

Oil(billion barrels)

Proven Resources Conventional
reserves
crude oil

Tight
oil

NGLs

EHOB

Kerogenoil

North America

237

2424

237

217

172

798

1 000

Central and South America

291

856

253

57

49

493

3

Europe

15

112

57

19

28

3

6

Africa

125

444

304

54

84

2

‐

Middle East

887

1 139

887

29

179

14

30

Eurasia

146

940

228

85

57

552

18

Asia Pacific

50

277

122

72

65

3

16

World

1 752

6 192

2 088

533

633

1 865

1 073

Natural gas(trillion cubic metres)

Provenreserves

Resources Conventional
gas

Tight
gas

Shale
gas

CoalbedmethaneNorth America

16

148

50

10

81

7

Central and South America

8

84

28

15

41

‐

Europe

5

46

18

5

18

5

Africa

19

101

51

10

40

0

Middle East

81

120

101

9

11

‐

Eurasia

69

168

130

10

10

17

Asia Pacific

21

138

44

21

53

20

World

219

806

422

80

254

49

Coal
(billion tonnes)

Provenreserves

Resources

Coking
coal

Steam
coal

LigniteNorth America

257

8 389

1 031

5 840

1 519

Central and South America

14

60

3

32

25

Europe

137

982

164

415

403

Africa

15

343

45

297

0

Middle East
Eurasia

1

41

36

6

‐

191

2 015

387

996

632

Asia Pacific

460

8 974

1 737

5 809

1 428

World

1075

20 8033 401

13 395

4 007

Notes: NGLs = natural gas liquids; EHOB = extra‐heavy oil and bitumen. The breakdown of coal resources bytype is an IEA estimate. Coal world resources exclude Antarctica.

Annex B | Design of the scenarios

467

IEA. CC BY 4.0.

Sources: BGR (2021); BP (2022); CEDIGAZ (2022); OGJ (2022); US DOE/EIA (2013); US DOE/EIA (2015); USGS
(2012a); USGS (2012b); IEA databases and analysis.

B

The World Energy Outlook supply modelling relies on estimates of the remaining
technically recoverable resource, rather than the (often more widely quoted) numbers
for proven reserves. Resource estimates are subject to a considerable degree of
uncertainty, as well as the distinction in the analysis between conventional andunconventional resource types.

Overall, the remaining technical recoverable resources of fossil fuels remain similar to
the World Energy Outlook‐2021. All fuels are at a level comfortably sufficient to meetthe projections of global energy demand growth to 2050 in all scenarios. Remaining
technically recoverable resources of US tight oil (crude plus condensate) total more than
200 billion barrels.

World coal resources are made up of various types of coal: around 80% is steam andcoking coal and the remainder is lignite. Coal resources are more available in parts of
the world without substantial natural gas and oil resources, notably in Asia.

Overall, the gradual depletion of resources (at a pace that varies by scenario) means that
operators have to develop more difficult and complex reservoirs. This tends to push up
production costs over time, although this effect is offset by the assumed continuous
adoption of new, more efficient production technologies and practices.

468

International Energy Agency | World Energy Outlook 2022

IEA. CC BY 4.0.



B.4

Electricity generation technology costs

Table B.4a ⊳Technology costs in selected regions in theStated Policies Scenario

Capital costs(USD/kW)
2021

2030

2050

Capacity factor(%)

Fuel, CO2, O&M(USD/MWh)2021 2030 2050

2021 2030 2050

LCOE
(USD/MWh)

VALCOE(USD/MWh)2021 2030 2050 2021 2030 2050

United States
Nuclear

5 000 4 800 4 500

90

90

90

30

30

30

105 100

Coal

2 100 2 100 2 100

35

15 n.a.

25

25

25

95 210 n.a.

Gas CCGT

1 000 1 000 1 000

55

40

20

35

40

40

60

70 110607080Solar PV

1 090

510

21

22

23

10

10

10

50

30

60

50

60

Wind onshore 1 380 1 310 1 250

42

43

44

10

10

10

35

30

30

40

40

45

Wind offshore 4 040 2 460 1 820

42

46

49

35

20

15

120

70

50

120

75

60

80

35

35

35

140 120 105

140

120

105

215

n.a.

710

95

25

105 100

95

95 210 n.a.

European Union
Nuclear

6 600 5 100 4 500

80

80

Coal

2 000 2 000 2 000

40

20 n.a.

115 130 140

180 255 n.a.

165

Gas CCGT

1 000 1 000 1 000

20

10 n.a.

100 120 130

155 270 n.a.

135

220

n.a.

410

14

14

14

10

10

10

50

35

30

60

80

80

Wind onshore 1 590 1 510 1 450

29

30

30

15

15

15

55

50

45

65

60

60

Wind offshore 3 040 2 000 1 500

51

56

59

15

10

10

60

40

30

60

45

40
60

Solar PV

810

530

China

80

80

80

25

25

25

65

65

60

65

65

Coal

800

800

800

60

50

35

60

60

70

75

80

95

75

70

50

Gas CCGT

560

560

560

35

25

20

95 105 115

115 130 140

100

110

105

Solar PV

630

410

300

17

18

19

10

5

5

35

20

45

50

60

Wind onshore 1 160 1 090 1 050

26

27

28

15

10

10

45

40

40

50

50

50

Wind offshore 2 860 1 840 1 380

33

39

43

25

15

10

100

55

40

100

60

35

Nuclear

2 800 2 800 2 500

15

India
Nuclear

2 800 2 800 2 800

75

85

90

30

30

30

75

65

65

75

65

65

Coal

1 200 1 200 1 200

65

75

75

40

35

35

60

55

50

60

55

45

Gas CCGT

700

700

700

40

50

45

75

85

85

95 100 105

95

90

85

Solar PV

590

380

270

20

21

22

5

5

5

35

20

15

40

35

55

Wind onshore

930

880

830

26

28

30

10

10

10

45

40

35

50

45

45

Wind offshore 2 780 1 820 1 300

33

37

39

25

15

10

120

75

50

120

80

60

Notes: O&M = operation and maintenance; LCOE = levelised cost of electricity; VALCOE = value‐adjusted LCOE;
kW = kilowatt; MWh = megawatt‐hour; CCGT = combined‐cycle gas turbine. Cost components, LCOE andVALCOE figures are rounded. Lower values for VALCOE indicate improved competitiveness.

Annex B | Design of the scenarios

469

IEA. CC BY 4.0.

Sources: IEA analysis; IRENA Renewable Costing Alliance; (IRENA, 2022).

B

Table B.4b ⊳Technology costs in selected regions in the
Announced Pledges Scenario
Capital costs(USD/kW)

2021

2030

Capacity factor
(%)

2050

2021

2030

Fuel, CO2 and O&M(USD/MWh)

2050

2021

2030

LCOE
(USD/MWh)

2050

2021

2030

2050

United States
Nuclear

5 000 4 800 4 500

90

90

90

30

30

30

100

100

100

Coal

2 100 2 100 2 100

30

n.a.

n.a.

85

150

180

165

n.a.

n.a.

Gas CCGT

1 000 1 000 1 000

50

25

n.a.

60

85

95

85

130

n.a.

Solar PV

1 090

470

21

22

23

10

10

10

50

30

25

Wind onshore

1 380 1 290 1 220

42

43

44

10

10

10

35

30

30

Wind offshore

4 040 2 360 1 620

42

46

49

35

20

15

120

65

45

Nuclear

6 600 5 100 4 500

80

80

70

35

35

35

140

115

115

Coal

2 000 2 000 2 000

30

n.a.

n.a.

135

175

210

220

n.a.

n.a.

Gas CCGT

1 000 1 000 1 000

25

10

n.a.

110

130

135

160

240

n.a.

360

14

14

14

10

10

10

50

35

25

Wind onshore

1 590 1 490 1 410

29

30

30

15

15

15

55

50

45

Wind offshore

3 040 1 920 1 320

51

56

59

15

10

5

60

35

25

2 800 2 800 2 500

680

European Union

Solar PV

810

510

China

85

80

80

25

25

25

65

65

60

Coal

800

800

800

60

50

20

65

85

150

80

105

195

Gas CCGT

560

560

560

30

25

25

95

110

130

110

130

155

630

400

Nuclear

270

17

18

19

10

5

5

35

20

15

Wind onshore

1 160 1 080 1 020

26

27

28

15

10

10

45

40

35

Wind offshore

2 860 1 780 1 200

33

39

43

25

15

10

100

55

35

Nuclear

2 800 2 800 2 800

75

85

90

30

30

30

70

65

65

Coal

1 200 1 200 1 200

Solar PV

India

65

75

35

40

65

170

60

85

205

Gas CCGT

700

700

700

40

45

30

70

85

115

90

105

145

Solar PV

590

360

240

20

21

22

5

5

5

35

20

15

Wind onshore

930

870

800

26

28

30

10

10

10

45

40

35

2 780 1 740 1 140

33

37

39

25

15

10

120

70

45

Wind offshore

Notes: O&M = operation and maintenance; LCOE = levelised cost of electricity; kW = kilowatt; MWh =megawatt‐hour; CCGT = combined‐cycle gas turbine; n.a. = not applicable. Cost components and LCOE figures
are rounded.

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Sources: IEA analysis; IRENA Renewable Costing Alliance; (IRENA, 2022).

Table B.4c ⊳Technology costs in selected regions in the
Net Zero Emissions by 2050 Scenario
Capital costs(USD/kW)

2021

2030

Capacity factor
(%)

2050

2021

2030

Fuel, CO2 and O&M(USD/MWh)

2050

2021

2030

LCOE
(USD/MWh)

2050

2021

2030

2050

100

United States
Nuclear

5 000 4 800 4 500

90

90

85

30

30

30

100

100

Coal

2 100 2 100 2 100

30

n.a.

n.a.

85

155

220

165

n.a.

n.a.

Gas CCGT

1 000 1 000 1 000

50

25

n.a.

55

80

105

80

130

n.a.

Solar PV

1 090

430

21

22

23

10

10

10

50

30

25

Wind onshore

1 380 1 270 1 190

42

43

44

10

10

10

35

30

30

Wind offshore

4 040 2 200 1 500

42

46

49

35

20

15

120

60

40

Nuclear

6 600 5 100 4 500

80

80

70

35

35

35

140

115

115

Coal

2 000 2 000 2 000

25

n.a.

n.a.

135

185

250

230

n.a.

n.a.

Gas CCGT

1 000 1 000 1 000

25

15

n.a.

95

115

135

145

195

n.a.

340

14

14

14

10

10

10

50

35

25

Wind onshore

1 590 1 470 1 380

29

30

30

15

15

15

55

50

45

Wind offshore

3 040 1 800 1 240

51

56

59

15

10

5

60

35

25

2 800 2 800 2 500620

European Union

Solar PV

810

470

China

85

80

70

25

25

25

65

65

65

Coal

800

800

800

55

n.a.

n.a.

80

120

180

100

n.a.

n.a.

Gas CCGT

560

560

560

35

25

n.a.

90

110

130

105

130

n.a.

630

360

15

Nuclear

250

17

18

19

10

5

5

35

20

Wind onshore

1 160 1 060 1 000

26

27

28

15

10

10

45

40

35

Wind offshore

2 860 1 640 1 120

33

39

43

25

15

10

100

50

35

Nuclear

2 800 2 800 2 800

70

85

90

30

30

30

75

65

65

Coal

1 200 1 200 1 200

Solar PV

India

65

n.a.

n.a.

40

105

200

60

n.a.

n.a.

Gas CCGT

700

700

700

40

40

n.a.

55

80

110

75

100

n.a.

Solar PV

590

320

210

20

21

22

5

5

5

35

20

15

Wind onshore

930

840

790

26

28

30

10

10

10

45

35

35

2 780 1 560 1 080

33

37

39

25

15

10

120

65

45

Wind offshore

Notes: O&M = operation and maintenance; LCOE = levelised cost of electricity; kW = kilowatt; MWh =megawatt‐hour; CCGT = combined‐cycle gas turbine; n.a. = not applicable. Cost components and LCOE figures
are rounded.

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BAll costs are expressed in year‐2021 dollars.



Major contributors to the levelised cost of electricity (LCOE) include: overnight capitalcosts; capacity factor that describes the average output over the year relative to the
maximum rated capacity (typical values provided); cost of fuel inputs; plus operationand maintenance. Economic lifetime assumptions are 25 years for solar PV, and onshore
and offshore wind.

Weighted average cost of capital (WACC) reflects analysis for utility‐scale solar PV in theWorld Energy Outlook‐2020 (IEA, 2020), with a range of 3‐6%, and for offshore wind
analysis from the Offshore Wind Outlook 2019 (IEA, 2019), with a range of 4‐7%.
Onshore wind was assumed to have the same WACC as utility‐scale solar PV. A standard
WACC was assumed for nuclear power, coal‐ and gas‐fired power plants (7‐8% based on
the stage of economic development).



The value‐adjusted levelised cost of electricity (VALCOE) incorporates information on
both costs and the value provided to the system. Based on the LCOE, estimates ofenergy, capacity and flexibility value are incorporated to provide a more complete
metric of competitiveness for power generation technologies.

Fuel, CO2 and O&M costs reflect the average over the ten years following the indicateddate in the projections (and therefore vary by scenario in 2021).

Solar PV and wind costs do not include the cost of energy storage technologies, such asutility‐scale batteries.



The capital costs for nuclear power represent the “nth‐of‐a‐kind” costs for new reactor
designs, with substantial cost reductions from the first‐of‐a‐kind projects.

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

B.5

Other key technology costs

Table B.5 ⊳Capital costs for selected technologies by scenario
StatedPolicies

Announced
Pledges

Net Zero
Emissions by 2050

2021

2030

2050

2030

2050

2030

2050

640
n.a.

650
1 400

660
1 050

650
1 330

670
980

650
1 020

680
910

Hybrid cars

16 12214 68614 861

14 52814 71814 46014 638Battery electric cars

21 32215 77214 18515 265

13 61814 78313 251
230

Primary steel production (USD/tpa)
Conventional
Innovative
Vehicles (USD/vehicle)

Batteries and hydrogen
Hydrogen electrolysers (USD/kW)

1 505

575

445

390

265

315

Fuel cells (USD/kW)

100

60

40

50

35

45

30

Utility‐scale stationary batteries (USD/kWh)

285

185

135

185

135

180

135

Notes: kW = kilowatt; tpa = tonne per annum; kWh = kilowatt‐hour; n.a. = not applicable. All values are in
USD (2021).

All costs represent fully installed/delivered technologies, not solely the module cost,
unless otherwise noted. Installed/delivered costs include engineering, procurement andconstruction costs to install the module.

Industry costs reflect production costs in the iron and steel sub‐sector and differentiate
between conventional and innovative production routes. Conventional routes are blast
furnace‐basic oxygen furnace (BF‐BOF) and direct reduced iron‐electric arc furnace (DRI‐
EAF). The innovative routes are Hisarna with carbon capture, utilisation and storage(CCUS), DRI‐EAF with CCUS and hydrogen‐based DRI‐EAF. Costs for conventional primary
steel increase over time reflecting an increasing shift towards DRI‐EAF in new capacity,which is more capital intensive.

Vehicle costs reflect production costs, not retail prices, to better reflect the cost declines
in total cost of manufacturing, which move independently of final market prices forelectric vehicles to customers. Historical values in 2021 have been used for the global
average battery pack size. In hybrid cars, the future cost increase is driven by regional
fuel economy and emissions standards.

Electrolyser costs reflect a projected weighted average of installed electrolyser
technologies (excluding China, where the modelled costs are lower), including inverters.

Fuel cell costs are based on stack manufacturing costs only, not installed/delivered
costs. The costs provided are for automotive fuel cell stacks for light‐duty vehicles.



Utility‐scale stationary battery costs reflect the average installed costs of all battery
systems rated to provide maximum power output for a four‐hour period.

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Sources: IEA analysis; James et. al. (2018); Thompson, et al. (2018); Financial Times (2020); BNEF (2021); Coleet al. (2020); Tsiropoulos et al. (2018);

B

B.6

Policies

The policy actions assumed to be taken by governments are key variables in this World
Energy Outlook (WEO) and the main reason for the differences in outcomes across the
scenarios. An overview of the policies and measures that are considered in the various
scenarios is included in Tables B.6 ‐ B.10.

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The policies are additive: measures listed under the Announced Pledges Scenario (APS)
supplement those in the Stated Policies Scenario (STEPS). The tables begin with broad cross‐cutting policy frameworks, followed by more detailed policies by sector: power, industry,buildings and transport. The tables for the STEPS list only the new policies enacted,
implemented or revised since the publication of the WEO‐2021. Policies already consideredin previous editions of the WEO are not listed due to space constraints. However, we dorestate major long‐term policies to be clear which targets and goals are met in the STEPS andwhich are only met in the APS. Some regional policies have been included if they play asignificant role in shaping energy at a global scale, e.g. regional carbon markets, standards invery large provinces or states. The tables do not include all policies and measures; rather
they highlight the policies most prominent in shaping global energy demand today, while
being derived from an exhaustive examination of announcements and plans in countries
around the world. A more comprehensive list of energy‐related policies by country can beviewed on the IEA Policies and Management Database (PAMS), https://www.iea.org/policies.

Table B.6 ⊳Cross-cutting policy assumptions for selected
regions/countries by scenario

Region/country

Scenario

Assumptions

United States

STEPS Energy provisions in the Inflation Reduction Act (2022), Consolidated Appropriations
Act (2021) and Infrastructure Investment and Jobs Act (2021).
 Defence Production Act supporting domestic production of heat pumps,
solar equipment and batteries.
 US Methane Emissions Reduction Action Plan.

APS Updated NDC aiming to reduce GHG emissions by 50‐52% by 2030
(from 2005 levels) and national target to reach net zero GHG emissions by 2050.
 Commitment to reduce methane emissions from the oil and gas sector
by 40‐45% by 2025 and 2021 US Methane Emissions Reduction Action Plan.

CanadaSTEPS

 Energy and emissions reduction‐related provisions in the 2020 Healthy
Environment and a Healthy Economy Plan; extended Investing in Canada
Infrastructure Programme; and Emissions Reduction Fund.
 Hydrogen Strategy and Strategic Innovation Fund.

APS Commitment to reach net zero GHG emissions target by 2050.
 Commitment to reduce methane emissions from the oil and gas sector
by 40‐45% by 2025, and further by 75% by 2030 relative to 2012. Measures in the
Healthy Environment and Healthy Economy action plan.

Central andSouth America

STEPS Colombia: Energy provisions in the Ten Milestones in 2021 Plan; National Strategy for
Mitigation of Short‐Lived Climate Pollutants; and National Energy Plan to 2050.
 Chile: 2021 National Strategy for Green Hydrogen.

APS Brazil: Long‐term objective of reaching climate neutrality by 2050.
 Chile, Costa Rica and Colombia: Net zero emissions by 2050.
 Commitment to Global Methane pledge by eight countries in the region.
 Colombia: National Strategy for Mitigation of Short‐Lived Climate Pollutants.

European Union

STEPS Energy spending provisions in the European Green Deal and national recovery plans
within the EU Recovery and Resilience Facility.
 Spending provisions to stimulate long‐term investment in energy efficiency and clean
energy implemented as part of national policy responses to the energy crisis as ofAugust 2022.
 Horizon Europe research and innovation funding programme.

APS Full implementation of the decarbonisation targets in the Fit for 55 package.
 2050 Net Zero Emissions target by 2050 embedded in the 2021
European Climate Law.
 EU member state‐level targets for climate neutrality.
 Targets in the EU Hydrogen Strategy for a Climate Neutral Europe.
 Partial implementation of the targets laid out in the REPowerEU Plan, eliminating theimport of Russian gas supply to the European Union well before 2030.
 EU member states commitment to the Global Methane Pledge.

Other Europe

STEPS United Kingdom: Ten Point Plan; Build Back Greener plan; 2020 Energy
White Paper; and provisions of the 2021 North Sea Transition Deal.
 Norway: 2021 Green Conversion Package.
 United Kingdom: Full implementation of the target for net zero GHG emissions by
2050. Commitment to the Global Methane Pledge.
 Norway, Iceland and Switzerland: Climate neutrality targets.
 Norway: Climate Action Plan 2021‐2030.

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APS

B

Table B.6 ⊳Region/country
Australia and
New Zealand

Cross-cutting policy assumptions for selected
regions/countries by scenario (continued)
Scenario

Assumptions

STEPS

 Australia: Spending and policy measures from the 2020 Climate Solutions Package.
 New Zealand: Energy‐related measures from the Covid Response and Recovery Fund.

APS Australia: Full implementation of the 2022 Climate Change Bill emissions target,
including net zero emissions by 2050, and ‐43% by 2030 relative to 2005.
 New Zealand: Full implementation of the New Zealand Zero Carbon amendment to
the Climate Change Response Act setting a net zero emissions target for all GHG
except biogenic methane by 2050. Commitment to the Global Methane Pledge.

China

STEPS

 Made in China 2025 transition from heavy industry to higher
value‐added manufacturing.
 14th Five‐Year Plan:o Reduce CO2 intensity of economy by 18% from 2021 to 2025.
o Reduce energy intensity of economy by 13.5% from 2021 to 2025.
o 20% non‐fossil share of energy mix by 2025.
o 25% non‐fossil share of energy mix by 2030.
 NDC:o Aim to peak CO2 emissions before 2030.
o Lower CO2 emissions per unit of GDP by 60% from 2005 levels.

APS
India

STEPS

 Carbon neutrality target by 2060.
 Energy‐related elements of the Self‐Reliant India Scheme (Atmanirbhar Bharat).
 450 GW renewables capacity by 2030 and 50% of total installed capacity
to be non‐fossil fuel‐based energy sources by 2030.
 Enhanced enforcement of energy efficiency policy under the 2022
amendments to the Energy Conservation Act.
 National Hydrogen Mission.

APS Updated NDC to reduce national carbon intensity by 45% by 2030
from 2005 levels, increase in non‐fossil energy capacity to 500 GW by 2030,
and reduce carbon emissions by 1 Gt CO2 by 2030.
 Net zero emissions by 2070.

Southeast Asia

STEPS Indonesia: 23% share of renewable energy in primary energy supply by 2025
and 31% by 2050.
 Singapore: Green Plan 2030.

APS

 Indonesia: Net zero emissions by 2060 or before.
 Malaysia: Carbon neutrality target by 2050.
 Thailand: Net zero GHG emissions target by 2065.
 Viet Nam: Carbon neutrality target by 2050.

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 Indonesia, Malaysia, Philippines and Viet Nam: Commitment to the Global Methane
Pledge.

Table B.6 ⊳Cross-cutting policy assumptions for selected
regions/countries by scenario (continued)

Region/country

Scenario

Assumptions

Japan

STEPS

 Implementation of concrete policies (renewable energy, batteries, energy efficiency
and nuclear power) announced in the 6th Strategic Energy Plan under the Basic Act
on Energy Policy, aiming to realise the Plan’s 2030 energy outlook.

APS Full implementation of the 6th Strategic Energy Plan under the Basic
Act on Energy Policy, including carbon neutrality target for 2050 andother policy targets beyond 2030.

 Public spending on clean energy innovation ‐ 2021 national budget.

 Accelerated nuclear policies under discussion in the Green Transformation (GX)
Implementation Council.
 Commitment to the Global Methane Pledge.
Korea

STEPS

 New Energy Policy.
 Korean New Deal Clean Energy Spending.
 14th Long‐term Natural Gas Supply and Demand Plan (2021‐2034).
 Methane Reduction Plan 2018‐2030.

APS

 Carbon Neutrality and Green Growth Act for Climate Change committing
to CO2 neutrality by 2050.
 Commitment to reduce methane emissions from all sectors by 30%
below 2018 levels by 2030, with a 28.6% sectoral reduction target for energy.

AfricaAPS

 Net zero emissions targets by 2050 in Nigeria, South Africa, Rwanda and Ghana.
Nine other net zero emissions commitments from sub‐Saharan African countries.
 All universal access targets for electricity and clean cooking.

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Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario. NDC = Nationally Determined
Contributions (Paris Agreement); CCUS = carbon capture, utilisation and storage; GHG = greenhouse gases;
GW = gigawatt; Gt = gigatonnes.

BRegion/country

Electricity sector policies and measures as modelledby scenario for selected regions/countries

Scenario

Assumptions

UnitedStatesSTEPS Inflation Reduction Act grants and tax credits for renewables, nuclear power and CCUS.
 100% carbon‐free electricity or energy targets by 2050 in up to 21 states plus Puerto Ricoand Washington DC.
 30 GW offshore wind capacity by 2030.
 Updated renewable portfolio standard policies (Delaware, Illinois, Nebraska, North Carolina
and Oregon).

APS G7 commitment: Achieve predominantly decarbonised electricity sector by 2035.

CanadaSTEPS

 Reach nearly 90% non‐emitting renewables generation by 2030.
 Phase out conventional coal‐fired plants by 2030.

APS G7 commitment: Achieve predominantly decarbonised electricity sector by 2035.

European
Union

STEPS

 New coal phase out commitments in Slovenia, Estonia and Croatia.
 Updated National Energy and Climate Plans, notably offshore wind targets.

APS Higher targets for renewables (40% renewables share of gross final consumption by 2030)
within Fit for 55 package.
 G7 commitment: Achieve predominantly decarbonised electricity sector by 2035.

Other
EuropeAPS United Kingdom: Energy Security Strategy sets new ambitions for offshore wind, nuclear &hydrogen. G7 commitment: Achieve predominantly decarbonised electricity sector by 2035.

AfricaSTEPS Partial implementation of national electrification strategies.

APS South Africa: Increased renewables capacity and reduced coal‐fired capacity under 2019
Integrated Resource Plan.
 Full implementation of national electrification targets.

STEPS

 14th Five‐year Plan for Renewables targets for 3 300 TWh of renewables by 2025(of which 1 400 TWh should be solar and wind) and that over 50% of incremental
electricity consumption is met by renewables.

China

APS

 Overall coal use to decline in the 15th Five‐Year Plan period (2025‐2030).

India

APS

 Updated NDC ‐ 50% cumulative electric power installed capacity fromnon fossil fuel‐based energy resources by 2030.

Japan

STEPS

 Achieve electricity generation outlook by 2030 in the 6th Strategic Energy Plan.
 Restart nuclear power plants aligned with the 6th Strategic Energy Plan and the Green
Transformation (GX) policy initiative.

APS Accelerated nuclear expansion, including SMRs, under discussion in the Green
Transformation (GX) Implementation Council.
 Green Growth Strategy: 30‐45 GW of offshore wind capacity in 2040.
 6th Strategic Energy Plan, with additional policies to support renewables in power
generation to reach 2030 targets.
 G7 commitment: Achieve predominantly decarbonised electricity sectors by 2035.

Korea

STEPS

 Increase renewables in electricity generation to over 20% and nuclear power to over 30%,and decrease coal‐fired power by 2030 under the New Energy Policy Direction.

Southeast
Asia

APS

 Indonesia: Renewable energy accounts for half (21 GW) of total power capacity addition
under the National Electricity Supply Business Plan (RUPTL) 2019‐2028.
 Viet Nam: Power Development Plan 8 proposed 19‐20 GW of solar, 18‐19 GW of wind,
22 GW of natural gas and 37 GW of coal‐fired capacity by 2030.

Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario. ETS = emissions trading system;
TWh = terawatt‐hour; GW = gigawatt; SMR = small modular reactor.

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Table B.7 ⊳Table B.8 ⊳Industry sector policies and measures as modelledby scenario for selected regions/countries

Region/country

Scenario

Assumptions

All regions

APS UN Resolution to end plastic pollution with ban on single‐use plastics. Lowers plastics
demand.
 Net Zero Emissions Steel Initiative.
 Concrete Action for Climate.

United States

STEPS

 Inflation Reduction Act of 2022: Investments in clean manufacturing and tax credits
for CCUS.

APS Department of Energy Industrial Decarbonization Roadmap.
 First Movers Coalition demand and production targets per sub‐sector, notably 10% ofaluminium and steel produced by low‐emissions means by 2030.

CanadaSTEPS

 Clean industry packages and provisions to promote clean industry
within Building Canada's Clean Industrial Advantage.

Central andSouth America

STEPS

 Brazil: Energy efficiency guarantee fund.

European
Union

STEPS

 EU updates to the emissions trading system reflecting extensions for free allocationand 2.2% annual reductions of emissions allowances.
 EU: Innovation Fund support for renewable energy, energy‐intensive industries,
energy storage and CCUS.
 Sweden: Government credit guarantees for green investment.
 France: France 2030 ‐ EUR 5.6 billion for industry decarbonisation.

STEPS

 United Kingdom: Industrial Decarbonisation Challenge. Pilot funding forlow‐emissions industrial clusters, and Industrial Energy Transformation Fund fundingfor energy efficiency.

APS United Kingdom: Industrial Decarbonisation Strategy.

Australia and
New Zealand

STEPS Australia: National Hydrogen Strategy to develop clean hydrogen.

China

STEPS

 Made in China 2025 targets for industrial energy intensity.

Other Europe Reduce comprehensive energy consumption per tonne of steel by 2% by 2025.
 Emissions from steel sub‐sector peak before 2030.
India

APS

 Expansion of the emissions trading system coverage to industry.

STEPS Perform, Achieve, Trade (PAT) Scheme to trade energy saving credits.
 Make in India programme. Boost to industry sector by building 11 industrial
world‐class corridors.
 Union Budget 2021‐2022, i.e. the national budget, includes USD 26 billion to enhance
the manufacturing capabilities of 14 key sub‐sectors.

Japan

STEPS

 Green Innovation Fund provides funding for R&D for innovative technology.

APS Technology Roadmap for Transition Finance in the cement, pulp and papersub‐sectors.

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Note: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; CCUS = carbon capture, utilisationand storage; ETS = emissions trading system; R&D = research and development.

BTable B.9 ⊳Buildings sector policies and measures as modelledby scenario for selected regions/countries

Region/country

Scenario

Assumptions

United States

STEPS

 Inflation Reduction Act: Rebates for heat pumps and energy efficiency upgrades inresidential and commercial buildings.
 Updated minimum energy performance standards for central air conditioning andheat pumps.

CanadaAPS State and local implementation of energy smart building codes and zero energy
building codes.

STEPS Implementation of updated appliance efficiency standards.
 Large‐scale energy‐efficient retrofits as part of the Canada Infrastructure Bank
growth plan.
 Greener Homes Grant and interest‐free loans for deep home retrofits.

Central andSouth America

APS All new buildings meet zero carbon‐ready building standards by 2030.

STEPS

 Colombia: Support for efficient lighting, efficient refrigerators and substitution of
firewood use with LPG or electric cooking stoves.
 Argentina: Strengthened energy efficiency building codes and mandatory efficiency
labelling for new social housing.

European Union

STEPS EU Recovery and Resilience Facility flagship area (Renovate) for energy efficiency inbuildings.
 Country‐level incentives for renovation and appliance upgrades, new building codes,
and clean heating incentives and investment.
 Bans on installing certain fossil fuel‐fired boilers in new or existing buildings: Austria(2021); France (2022); Belgium (Flanders, 2022); Slovenia (2023); Germany (2026).

APS

 EU Energy Performance of Buildings Directive objective to achieve a highly energy‐
efficient and decarbonised building stock by 2050.
 Renovation Wave objective to double the rate of building energy retrofits by 2030.

Other Europe

STEPS United Kingdom: Low‐Carbon Heat Support and Heat Networks Investment Project;various retrofit incentive schemes for improving buildings efficiency as part of thePlan for Jobs.

APS

 United Kingdom: Future homes standard banning fossil fuel heating in new homeconstruction by 2025.
 United Kingdom: Ban on installing natural gas‐fired boilers inall existing buildings (2035).

AfricaSTEPS Southern African Development Community lighting standards.
 Minimum energy performance standards for major residential appliances andequipment, including in: Algeria, Benin, Egypt, Ghana, Kenya, Morocco, Nigeria,
Rwanda, South Africa, Tunisia.

Australia and
New Zealand

APS All targets for clean cooking met.

STEPS

 Australia: Funding for energy efficiency measures, including energy rating labels andstate funding for energy‐efficient retrofits. Energy efficiency standards for new
homes upgraded to seven stars in 2023.

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 New Zealand: Replace all remaining coal‐fired boilers in schools with electric or
renewable biomass alternatives by 2025.

Table B.9 ⊳Region/country

Scenario

China

STEPS

Buildings sector policies and measures as modelledby scenario for selected regions/countries (continued)
Assumptions
 Standard for maximum energy consumption per square metre in buildings.
 Green and High‐Efficiency Cooling Action Plan.
 Minimum performance standards and energy efficiency labelling for room air conditioners.

India

STEPS

 Energy Conservation and Sustainable Building Code as part of the Energy Conservation(Amendment) Bill, comprising norms or energy efficiency and conservation, minimum useof renewable energy and other green buildings requirements.
 Cooling Action Plan. Standards and labelling for light commercial air conditioners, freezers
and light bulbs.
 Energy efficiency labelling for residential buildings for renters and homeowners.

Japan

Korea

STEPS

 Revised retail labelling system.

APS New residential and services buildings meet the net zero energy home or net zero energy
building standard on average by 2030.

STEPS

 Rebate for purchase of appliances entitled to energy efficiency grade 1.
 Korean New Deal: Increased funding to improve the efficiency of schools, public housing,recreational and healthcare facilities.

Southeast
Asia

APS

 All new buildings meet zero carbon‐ready building standards by 2030.

STEPS

 Viet Nam: Minimum performance standards and labelling for appliances and lighting inresidential and commercial buildings.
 Singapore: Enhancements to minimum energy performance standards for light bulbs.
 Malaysia: Minimum energy performance standards and labelling for washing machines,
refrigerators and air conditioners.

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Note: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; LPG = liquefied petroleum gas.

B

Table B.10 ⊳Transport sector policies and measures as modelledby scenario for selected regions/countries

Region/country

Scenario

Assumptions

All regionsAPS

 LDVs: COP26 declaration by 39 governments on all sales of new cars and vans being
zero emissions globally by 2040, and by no later than 2035 in leading markets.1
 HDVs: Global MoU on Zero Emissions Medium‐ and Heavy‐duty Vehicles among
15 countries, targets 100% new truck and bus sales being zero emissions by 2040.2
 International Civil Aviation Organization Carbon Offsetting and Reduction Scheme forInternational Aviation to offset CO2 emissions above 2019 levels.
 International Maritime Organization initial GHG emission strategy to reduce
emissions from international shipping by at least 50% by 2050 compared to 2008.

United States

STEPS

 Inflation Reduction Act: Extension of federal tax credit for electric LDVs and charging
infrastructure to 2032, and tax credits for biofuels including sustainable aviation fuel.
 Fuel economy standards to improve 8% per year for passenger cars and light trucks
for model years 2024‐2025 and requirement of 10% for model year 2026 relative to2021 levels. More stringent standards for GHG emissions for model years 2023‐2026
which requires 5‐10% emissions reductions per year.
 In California, Advanced Clean Cars II regulation aims to achieve zero emissions
passenger cars and light truck sales by 2035, as well as Advanced Clean Trucks
regulation to achieve a zero emissions medium‐ and heavy‐duty truck fleet by 2045.

APS

 Announced executive order for a target of 50% of all new passenger cars andlight‐duty trucks to be zero emissions vehicles by 2030.
 Sustainable Aviation Fuel Grand Challenge to scale up the production of at least
3 billion gallons per year by 2030, and by 2050 sufficient sustainable aviation fuel tomeet 100% of domestic aviation demand.
 Washington State target to phase out all new sales and registrations of internal
combustion engine cars and vans from 2030.

CanadaSTEPS

 Provinces of Quebec and British Columbia aim to phase out all new sales andregistrations of internal combustion engine passenger vehicles by 2035.

APS

 Emissions Reduction Plan to achieve 100% zero emissions light‐duty vehicles sales
target by 2035.
 National aim to achieve 100% of medium‐ and heavy‐duty truck sales to be emissions
vehicles by 2040.

Central andSouth America

APS Colombia: All urban bus sales are to be zero emissions by 2035.
 Chile: All LDV and urban bus sales are to be zero emissions by 2035, as well as
long‐distance trucks and intercity buses by 2045.
 Costa Rica: Target of 100% of LDV sales to be zero emissions vehicles from 2050.

1

Full list of signatories: https://zevdeclaration.org/signatories‐list/

2

Full list of signatories: https://globaldrivetozero.org/mou‐nations/482

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 Ecuador: All public transport vehicles must be electric from 2025.

Table B.10 ⊳Region/country
European
Union

Transport sector policies and measures as modelledby scenario for selected regions/countries (continued)

Scenario
STEPS

Assumptions
 National recovery and resilience plans of EU member states support green mobility,
railways, electric vehicles and charging infrastructure.
 Renewable Energy Directive II to supply a minimum of 14% of the energy consumed inroad and rail transport by 2030 as renewable energy.

APS Fit for 55 package:o Average emissions of new cars to reduce emissions by 55% from 2030 and by 100%from 2035 relative to 2021 levels.
o Alternative Fuels Infrastructure Regulation to accelerate the vehicle recharging
infrastructure deployment.
o ReFuelEU Aviation sets a 63% blending mandate of sustainable aviation fuelsby 2050, with a sub‐obligation of synthetic fuels.
o FuelEU Maritime initiative targets the reduction of average GHG intensity of energy
used on‐board by ships up to 75% by 2050 relative to 2020 levels.
 Revision of the Clean Vehicles Directive including minimum requirements for aggregate
public procurement for zero emissions urban buses.

Other Europe

STEPS United Kingdom: Almost 11% ethanol blend mandate by 2032.
 Norway: National Transport Plan supporting railways and the maritime sector.

APS United Kingdom: Implementation of a ban in 2030 on sales of new internal combustion
engine cars and vans. Hybrid vehicles to be phased out from 2035. 100% zero emissions
new trucks and bus sales by 2040. Sustainable aviation fuel mandate of 10% by 2030.
 Norway: Sustainable aviation fuel target of 30% by 2030. All city buses to be zero
emissions by 2025. Target of 100% of new HDV sales to be zero emissions by 2030.

Australia and
New Zealand

APS New Zealand: Transition to 100% sales of zero emissions new cars and vans by 2035.
Targets zero emissions vehicles to make up 100% of urban bus sales by 2025 and 100%of stock by 2035.

Japan

STEPS

 National budget 2022 for subsidies supporting electric and FCEVs.
 Fuel economy standard of LDVs to improve fuel efficiency by 32% to 2030 relative to2016 levels.

Korea

APS

 Green Growth Strategy and the 6th Strategic Energy Plan aiming for sales of 100% zero
emissions vehicles (including hybrids) for passenger vehicles by 2035 and for lightcommercial vehicles by 2040.

STEPS

 Subsidy scheme to support electric vehicles.
 Investment in urban and mass transit.
 Partial implementation of target for zero emissions vehicles: one‐third of new passenger
car sales in 2030 are electric vehicle or FCEVs.

APS Target to increase the number of FCEVs to 200 000 by 2025 (Green New Deal).

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 Full implementation of target for zero emissions vehicles: by 2030, 50% of passenger car
sales to be hybrid or plug‐in hybrid vehicles and 33% to be battery electric and FCEVs.

B

Table B.10 ⊳Transport sector policies and measures as modelledby scenario for selected regions/countries (continued)

Region/country

Scenario

Assumptions

China

STEPS

 Meets and exceeds targets from the China Society of Automotive Engineers for newenergy vehicles to reach 20% of new vehicle sales in 2025.
 Corporate average fuel consumption target of 4.0 litres/100 km for 2025
and 3.2 litres/100 km for 2030.
 New Energy Automobile Industry Development Plan (2021‐2035).
 Extension of purchase tax exemption and subsidies for new energy vehicles.
 National railway investments.

India

APS

 China Society of Automotive Engineers target new energy vehicle car sales reachmore than half by 2035 including 1 million FCEVs.

STEPS Urban and public transit investments.
 Partial implementation of 20% bioethanol blending target for gasoline and5% biodiesel in 2030.

APS Extension of FAME Phase II programme to support the target of 500 000 electric
three‐wheelers and 1 million electric two‐wheelers.

STEPS Indonesia: Introduction of the B30 programme to increase biodiesel blends
to 30% with 40% mandate in 2023.

APS

 Indonesia: Government plans to phase out conventional two‐wheelers from 2025
and to have 2 million electric vehicles in passenger light‐duty vehicle stock by 2030.

 National railways target of net zero emissions by 2030.
Southeast Asia

 Thailand: Target for 100% zero emissions vehicle sales from 2035.
 Malaysia: 100% of cars by 2030 to be electrified, CNG, LPG or biofuel‐fuelled vehicles.
 Singapore: Targets to phase out passenger internal combustion engine
vehicles by 2040.
Other Asia

APS Pakistan: Targets for 30% of passenger light‐duty vehicle sales to be electric by 2030
and 90% of truck sales to be electric vehicles by 2040. 90% of urban bus sales to beelectric vehicles by 2040. 50% of electric two/three‐wheeler sales by 2030.

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Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario. LDV = light‐duty vehicle andincludes passenger cars and light commercial vehicles. HDV = heavy‐duty vehicle. MoU = memorandum of
understanding; GHG = greenhouse gases; km = kilometre; FCEVs = fuel cell electric vehicle; CNG = compressed
natural gas; LPG = liquefied petroleum gas.

Annex C
Definitions
This annex provides general information on terminology used throughout this report
including: units and general conversion factors; definitions of fuels, processes and sectors;
regional and country groupings; and abbreviations and acronyms.

Area

km2
Mha

square kilometre
million hectares

Batteries

Wh/kg

watt hours per kilogramme

Coal

Mtce

million tonnes of coal equivalent (equals 0.7 Mtoe)

Distancekm

kilometre

Emissions

ppm
t CO2
Gt CO2‐eq
kg CO2‐eq
g CO2/km
g CO2/kWhkg CO2/kWhparts per million (by volume)
tonnes of carbon dioxide
gigatonnes of carbon‐dioxide equivalent (using 100‐year
global warming potentials for different greenhouse gases)
kilogrammes of carbon‐dioxide equivalent
grammes of carbon dioxide per kilometre
grammes of carbon dioxide per kilowatt‐hourkilogrammes of carbon dioxide per kilowatt‐hour

Energy

EJ
PJ
TJ
GJ
MJ
boe
toe
ktoe
Mtoe
bcme
MBtu
kWh
MWh
GWh
TWh
Gcal

exajoule (1 joule x 1018)
petajoule (1 joule x 1015)
terajoule (1 joule x 1012)
gigajoule (1 joule x 109)
megajoule (1 joule x 106)barrel of oil equivalent
tonne of oil equivalent
thousand tonnes of oil equivalentmillion tonnes of oil equivalentbillion cubic metres of natural gas equivalentmillion British thermal units
kilowatt‐hour
megawatt‐hour
gigawatt‐hour
terawatt‐hourgigacalorie

Gas

bcm
tcm

billion cubic metres
trillion cubic metres

Mass

kg
t
kt
Mt
Gt

kilogrammetonne (1 tonne = 1 000 kg)
kilotonnes (1 tonne x 103)
million tonnes (1 tonne x 106)
gigatonnes (1 tonne x 109)

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Units

Monetary

USD million
USD billion
USD trillion
USD/t CO2

1 US dollar x 106
1 US dollar x 109
1 US dollar x 1012
US dollars per tonne of carbon dioxide

Oil

kb/d
mb/d
mboe/dthousand barrels per day
million barrels per day
million barrels of oil equivalent per day

Power

W
kW
MW
GW
TW

watt (1 joule per second)kilowatt (1 watt x 103)
megawatt (1 watt x 106)
gigawatt (1 watt x 109)
terawatt (1 watt x 1012)

General conversion factors for energy
Multiplier to convert to:Convert from:

EJ

Gcal

EJ

1

Gcal

4.1868 x 10‐9

Mtoe

Mtoe
8

‐2

4.1868 x 10

‐9

MBtu

bcme

GWh

2.388 x 10

23.88

9.478 x 10

27.78

2.778 x 105

1

10‐7

3.968

1.163 x 10‐7

1.163 x 10‐3

1.163

11 630

7

10

8

7

1

3.968 x 10
‐8

MBtu

1.0551 x 10

0.252

2.52 x 10

12.932 x 10

bcme

0.036

8.60 x 106

0.86

3.41 x 107

1GWh

3.6 x 10‐6860

8.6 x 10

‐5

3 412

‐8

2.931 x 10‐4
9 999

‐4

1 x 101

Note: There is no generally accepted definition of boe; typically the conversion factors used vary from 7.15 to
7.40 boe per toe. Natural gas is attributed a low heating value of 1 MJ per 44.1 kg. Conversions to and frombillion cubic metres of natural gas equivalent (bcme) are given as representative multipliers but may differ
from the average values obtained by converting natural gas volumes between IEA balances due to the use ofcountry‐specific energy densities. Lower heating values (LHV) are used throughout.

Currency conversions
Exchange rates(2021 annual average)

1 US dollar (USD)
equals:British Pound

0.73

Chinese Yuan Renminbi

6.45

Euro

0.84

Indian Rupee

73.92

Japanese Yen

109.75486

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Source: OECD National Accounts Statistics (database): purchasing power parities and exchange rates dataset(period‐average), https://doi.org/10.1787/data‐00004‐en, accessed September 2022.

Definitions
Advanced bioenergy: Sustainable fuels produced from non‐food crop feedstocks, which arecapable of delivering significant life cycle greenhouse gas emissions savings compared withfossil fuel alternatives, and which do not directly compete with food and feed crops for
agricultural land or cause adverse sustainability impacts. This definition differs from the oneused for “advanced biofuels” in US legislation, which is based on a minimum 50% life cycle
greenhouse gas reduction and, therefore, includes sugar cane ethanol.
Agriculture: Includes all energy used on farms, in forestry and for fishing.
Agriculture, forestry and other land use (AFOLU) emissions: Includes greenhouse gas
emissions from agriculture, forestry and other land use.
Ammonia (NH3): Is a compound of nitrogen and hydrogen. It can be used as a feedstock inthe chemical sector, as a fuel in direct combustion processes in fuel cells, and as a hydrogen
carrier. To be considered a low‐emissions fuel, ammonia must be produced from hydrogenin which the electricity used to produce the hydrogen is generated from low‐emissions
generation sources. Produced in such a way, ammonia is considered a low‐emissionshydrogen‐based liquid fuel.
Aviation: This transport mode includes both domestic and international flights and their useof aviation fuels. Domestic aviation covers flights that depart and land in the same country;
flights for military purposes are included. International aviation includes flights that land ina country other than the departure location.
Back‐up generation capacity: Households and businesses connected to a main power grid
may also have a source of back‐up power generation capacity that, in the event of disruption,
can provide electricity. Back‐up generators are typically fuelled with diesel or gasoline.
Capacity can be as little as a few kilowatts. Such capacity is distinct from mini‐grid and off‐
grid systems that are not connected to a main power grid.
Battery storage: Energy storage technology that uses reversible chemical reactions to absorb
and release electricity on demand.
Billion cubic metres of natural gas equivalent (bcme): An energy unit equal to the energy
content of one standard billion cubic metres of natural gas.
Biodiesel: Diesel‐equivalent fuel made from the transesterification (a chemical process thatconverts triglycerides in oils) of vegetable oils and animal fats.
Bioenergy: Energy content in solid, liquid and gaseous products derived from biomass
feedstocks and biogas. It includes solid bioenergy, liquid biofuels and biogases.

Biogases: Include both biogas and biomethane.

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Biogas: A mixture of methane, CO2 and small quantities of other gases produced byanaerobic digestion of organic matter in an oxygen‐free environment.

CBiogasoline: Includes all liquid biofuels (advanced and conventional) used to replacegasoline.
Biojet kerosene: Kerosene substitute produced from biomass. It includes conversion routes
such as hydroprocessed esters and fatty acids (HEFA) and biomass gasification with Fischer‐Tropsch. It excludes synthetic kerosene produced from biogenic carbon dioxide.
Biomethane: Biomethane is a near‐pure source of methane produced either by “upgrading”
biogas (a process that removes any carbon dioxide and other contaminants present in the
biogas) or through the gasification of solid biomass followed by methanation. It is also known
as renewable natural gas.
Buildings: The buildings sector includes energy used in residential and services buildings.
Services buildings include commercial and institutional buildings and other non‐specified
buildings. Building energy use includes space heating and cooling, water heating, lighting,appliances and cooking equipment.
Bunkers: Includes both international marine bunker fuels and international aviation bunker
fuels.
Capacity credit: Proportion of the capacity that can be reliably expected to generate
electricity during times of peak demand in the grid to which it is connected.
Carbon capture, utilisation and storage (CCUS): The process of capturing carbon dioxide
emissions from fuel combustion, industrial processes or directly from the atmosphere.
Captured CO2 emissions can be stored in underground geological formations, onshore or
offshore, or used as an input or feedstock in manufacturing.
Carbon dioxide (CO2): Is a gas consisting of one part carbon and two parts oxygen. It is an
important greenhouse (heat‐trapping) gas.
Chemical feedstock: Energy vectors used as raw materials to produce chemical products.
Examples are crude oil‐based ethane or naphtha to produce ethylene in steam crackers.

Clean cooking systems: Cooking solutions that release less harmful pollutants, are more
efficient and environmentally sustainable than traditional cooking options that make use ofsolid biomass (such as a three‐stone fire), coal or kerosene. This refers to improved cook
stoves, biogas/biodigester systems, electric stoves, liquefied petroleum gas, natural gas or
ethanol stoves.
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Clean energy: In power, clean energy includes: generation from renewable sources, nuclear
and fossil fuels fitted with CCUS; battery storage; and electricity grids. In efficiency, clean
energy includes energy efficiency in buildings, industry and transport, excluding aviation
bunkers and domestic navigation. In end‐use applications, clean energy includes: direct useof renewables; electric vehicles; electrification in buildings, industry and international marinetransport; CCUS in industry and direct air capture. In fuel supply, clean energy includes low‐emissions fuels.

Coal: Includes both primary coal, i.e. lignite, coking and steam coal, and derived fuels, e.g.
patent fuel, brown‐coal briquettes, coke‐oven coke, gas coke, gas works gas, coke‐oven gas,
blast furnace gas and oxygen steel furnace gas. Peat is also included.
Coalbed methane (CBM): Category of unconventional natural gas that refers to methanefound in coal seams.
Coal‐to‐gas (CTG): Process in which coal is first turned into syngas (a mixture of hydrogenand carbon monoxide) and then into synthetic methane.
Coal‐to‐liquids (CTL): Transformation of coal into liquid hydrocarbons. One route involves
coal gasification into syngas (a mixture of hydrogen and carbon monoxide), which isprocessed using Fischer‐Tropsch or methanol‐to‐gasoline synthesis. Another route, called
direct‐coal liquefaction, involves reacting coal directly with hydrogen.
Coking coal: Type of coal that can be used for steel making (as a chemical reductant and asource of heat), where it produces coke capable of supporting a blast furnace charge. Coalof this quality is commonly known as metallurgical coal.
Concentrating solar power (CSP): Thermal power generation technology that collects andconcentrates sunlight to produce high temperature heat to generate electricity.
Conventional liquid biofuels: Fuels produced from food crop feedstocks. Commonly referred
to as first generation biofuels and include sugar cane ethanol, starch‐based ethanol, fatty
acid methyl ester (FAME), straight vegetable oil (SVO) and hydrotreated vegetable oil (HVO)
produced from palm, rapeseed or soybean oil.
Critical minerals: A wide range of minerals and metals that are essential in clean energy
technologies and other modern technologies and have supply chains that are vulnerable todisruption. Although the exact definition and criteria differ among countries, critical minerals
for clean energy technologies typically include chromium, cobalt, copper, graphite, lithium,manganese, molybdenum, nickel, platinum group metals, zinc, rare earth elements and othercommodities, as listed in the Annex of the IEA special report on the Role of Critical Minerals
in Clean Energy Transitions available at: https://www.iea.org/reports/the‐role‐of‐critical‐
minerals‐in‐clean‐energy‐transitions.
Decomposition analysis: Statistical approach that decomposes an aggregate indicator toquantify the relative contribution of a set of pre‐defined factors leading to a change in theaggregate indicator. The World Energy Outlook uses an additive index decomposition of thetype Logarithmic Mean Divisia Index (LMDI).

Demand‐side response (DSR): Describes actions which can influence the load profile such as
shifting the load curve in time without affecting total electricity demand, or load shedding
such as interrupting demand for a short duration or adjusting the intensity of demand for acertain amount of time.
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Demand‐side integration (DSI): Consists of two types of measures: actions that influenceload shape such as energy efficiency and electrification; and actions that manage load suchas demand‐side response measures.

CDirect air capture (DAC): Technology to capture CO2 directly from the atmosphere using
liquid solvents or solid sorbents. It is generally coupled with permanent storage of the CO2 indeep geological formations or its use in the production of fuels, chemicals, building materials
or other products. When coupled with permanent geological CO2 storage, DAC is a carbon
removal technology.
Dispatchable generation: Refers to technologies whose power output can be readily
controlled, i.e. increased to maximum rated capacity or decreased to zero in order to match
supply with demand.
Electricity demand: Defined as total gross electricity generation less own use generation,plus net trade (imports less exports), less transmission and distribution losses.
Electricity generation: Defined as the total amount of electricity generated by power only or
combined heat and power plants including generation required for own use. This is also
referred to as gross generation.
End‐use sectors: Include industry, transport, buildings and other, i.e., agriculture and othernon‐energy use.
Energy‐intensive industries: Includes production and manufacturing in the branches of ironand steel, chemicals, non‐metallic minerals (including cement), non‐ferrous metals (includingaluminium), and paper, pulp and printing.
Energy‐related and industrial process CO2 emissions: Carbon dioxide emissions from fuelcombustion and from industrial processes. Note that this does not include fugitive emissions
from fuels, flaring or CO2 from transport and storage. Unless otherwise stated, CO2 emissions
in the World Energy Outlook refer to energy‐related and industrial process CO2 emissions.
Energy sector greenhouse gas (GHG) emissions: Energy‐related and industrial process CO2
emissions plus fugitive and vented methane (CH4) and nitrous dioxide (N2O) emissions fromthe energy and industry sectors.
Energy services: See useful energy.
Ethanol: Refers to bioethanol only. Ethanol is produced from fermenting any biomass highin carbohydrates. Currently, ethanol is made from starches and sugars, but second‐
generation technologies will allow it to be made from cellulose and hemicellulose, the fibrousmaterial that makes up the bulk of most plant matter.
Fischer‐Tropsch synthesis: Catalytic production process for the production of synthetic fuels,
e.g. diesel, kerosene or naphtha, typically from mixtures of carbon monoxide and hydrogen(syngas). The inputs to Fischer‐Tropsch synthesis can be from biomass, coal, natural gas, orhydrogen and CO2.

Gaseous fuels: Include natural gas, biogases, synthetic methane and hydrogen.

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Fossil fuels: Include coal, natural gas and oil.

Gases: See gaseous fuels.
Gas‐to‐liquids (GTL): A process that reacts methane with oxygen or steam to produce syngas(a mixture of hydrogen and carbon monoxide) followed by Fischer‐Tropsch synthesis. The
process is similar to that used in coal‐to‐liquids.
Geothermal: Geothermal energy is heat from the sub‐surface of the earth. Water and/or
steam carry the geothermal energy to the surface. Depending on its characteristics,
geothermal energy can be used for heating and cooling purposes or be harnessed togenerate clean electricity if the temperature is adequate.
Heat (end‐use): Can be obtained from the combustion of fossil or renewable fuels, direct
geothermal or solar heat systems, exothermic chemical processes and electricity (throughresistance heating or heat pumps which can extract it from ambient air and liquids). This
category refers to the wide range of end‐uses, including space and water heating, andcooking in buildings, desalination and process applications in industry. It does not include
cooling applications.
Heat (supply): Obtained from the combustion of fuels, nuclear reactors, geothermal
resources or the capture of sunlight. It may be used for heating or cooling, or converted intomechanical energy for transport or electricity generation. Commercial heat sold is reported
under total final consumption with the fuel inputs allocated under power generation.
Heavy‐duty vehicles (HDVs): Includes both medium‐freight trucks (3.5 to 15 tonnes) andheavy‐freight trucks (>15 tonnes)
Heavy industries: Iron and steel, chemicals and cement.
Hydrogen: Hydrogen is used in the energy system as an energy carrier, as an industrial raw
material, or is combined with other inputs to produce hydrogen‐based fuels. Unlessotherwise stated, hydrogen in this report refers to low‐emissions hydrogen.
Hydrogen‐based fuels: See low‐emissions hydrogen‐based fuels.
Hydropower: Energy content of the electricity produced in hydropower plants, assuming
100% efficiency. It excludes output from pumped storage and marine (tide and wave) plants.

Improved cook stoves: Intermediate and advanced improved biomass cook stoves (ISOtier > 1). It excludes basic improved stoves (ISO tier 0‐1).
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Industry: The sector includes fuel used within the manufacturing and construction industries.
Key industry branches include iron and steel, chemical and petrochemical, cement,
aluminium, and pulp and paper. Use by industries for the transformation of energy intoanother form or for the production of fuels is excluded and reported separately under otherenergy sector. There is an exception for fuel transformation in blast furnaces and coke ovens,which are reported within iron and steel. Consumption of fuels for the transport of goods isreported as part of the transport sector, while consumption by off‐road vehicles is reported
under industry.

CInternational aviation bunkers: Includes the deliveries of aviation fuels to aircraft forinternational aviation. Fuels used by airlines for their road vehicles are excluded. The
domestic/international split is determined on the basis of departure and landing locations
and not by the nationality of the airline. For many countries this incorrectly excludes fuels
used by domestically owned carriers for their international departures.
International marine bunkers: Includes the quantities delivered to ships of all flags that are
engaged in international navigation. The international navigation may take place at sea, on
inland lakes and waterways, and in coastal waters. Consumption by ships engaged indomestic navigation is excluded. The domestic/international split is determined on the basisof port of departure and port of arrival, and not by the flag or nationality of the ship.
Consumption by fishing vessels and by military forces is excluded and instead included in theresidential, services and agriculture category.
Investment: Investment is the capital expenditure in energy supply, infrastructure, end‐use
and efficiency. Fuel supply investment includes the production, transformation and transportof oil, gas, coal and low‐emissions fuels. Power sector investment includes new construction
and refurbishment of generation, electricity grids (transmission, distribution and public
electric vehicle chargers), and battery storage. Energy efficiency investment includes
efficiency improvements in buildings, industry and transport. Other end‐use investment
includes the purchase of equipment for the direct use of renewables, electric vehicles,
electrification in buildings, industry and international marine transport, equipment for theuse of low‐emissions fuels, and CCUS in industry and direct air capture. Data and projections
reflect spending over the lifetime of projects and are presented in real terms in year‐2021
US dollars converted at market exchange rates unless otherwise stated. Total investment
reported for a year reflects the amount spent in that year.
Levelised cost of electricity (LCOE): The LCOE combines into a single metric all the costelements directly associated with a given power technology, including construction,
financing, fuel, maintenance and costs associated with a carbon price. It does not include
network integration or other indirect costs. The LCOE provides a first indicator ofcompetitiveness. For a more complete indicator, see VALCOE.
Light‐duty vehicles (LDVs): Include passenger cars and light commercial vehicles (grossvehicle weight <3.5 tonnes).
Light industries: Includes non‐energy‐intensive industries: food and tobacco, machinery,mining and quarrying, transportation equipment, textile, wood harvesting and processing
and construction.

Liquid biofuels: Liquid fuels derived from biomass or waste feedstock, e.g. ethanol, biodiesel
and biojet fuels. They can be classified as conventional and advanced biofuels according to
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Lignite: A type of coal that is used in the power sector mostly in regions near lignite mines
due to its low energy content and typically high moisture levels, which generally makes long‐
distance transport uneconomic. Data on lignite in the World Energy Outlook include peat.

the combination of feedstock and technologies used to produce them and their respective
maturity. Unless otherwise stated, biofuels are expressed in energy‐equivalent volumes ofgasoline, diesel and kerosene.
Liquid fuels: Include oil, liquid biofuels (expressed in energy‐equivalent volumes of gasoline
and diesel), synthetic oil and ammonia.
Low‐emissions electricity: Includes renewable energy technologies, low‐emissionshydrogen‐based generation, low‐emissions hydrogen‐based fuel generation, nuclear power
and fossil fuel power plants equipped with carbon capture, utilisation and storage.
Low‐emissions fuels: Include modern bioenergy, low‐emissions hydrogen and low‐emissionshydrogen‐based fuels.
Low‐emissions gases: Includes biogas, biomethane, low‐emissions hydrogen and low‐emissions synthetic methane.
Low‐emissions hydrogen: Hydrogen that is produced from water using electricity generated
by renewables or nuclear, from fossil fuels with minimal associated methane emissions andprocessed in facilities equipped to avoid CO2 emissions, e.g. via CCUS with a high capturerate, or derived from bioenergy. In this report, total demand for low‐emissions hydrogen islarger than total final consumption of hydrogen because it additionally includes hydrogen
inputs to make low‐emissions hydrogen‐based fuels, biofuels production, power generation,
oil refining, and hydrogen produced and consumed onsite in industry.
Low‐emissions hydrogen‐based fuels: Include ammonia, methanol and other synthetichydrocarbons (gases and liquids) made from low‐emissions hydrogen. Any carbon inputs,
e.g. from CO2, are not from fossil fuels or process emissions.
Low‐emissions hydrogen‐based liquid fuels: A subset of low‐emissions hydrogen‐based
fuels that includes only ammonia, methanol and synthetic liquid hydrocarbons, such assynthetic kerosene.
Lower heating value: Heat liberated by the complete combustion of a unit of fuel when thewater produced is assumed to remain as a vapour and the heat is not recovered.
Marine energy: Represents the mechanical energy derived from tidal movement, wave
motion or ocean currents and exploited for electricity generation.
Middle distillates: Include jet fuel, diesel and heating oil.

Modern energy access: Includes household access to a minimum level of electricity (initiallyequivalent to 250 kilowatt‐hours (kWh) annual demand for a rural household and 500 kWh
for an urban household); household access to less harmful and more sustainable cooking andheating fuels, and improved/advanced stoves; access that enables productive economic
activity; and access for public services.
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Mini‐grids: Small electric grid systems, not connected to main electricity networks, linking a
number of households and/or other consumers.

CModern gaseous bioenergy: See biogases.
Modern liquid bioenergy: Includes biogasoline, biodiesel, biojet kerosene and other liquidbiofuels.
Modern renewables: Include all uses of renewable energy with the exception of traditionaluse of solid biomass.
Modern solid bioenergy: Includes all solid bioenergy products (see solid bioenergy
definition) except the traditional use of biomass. It also includes the use of solid bioenergy
in intermediate and advanced improved biomass cook stoves (ISO tier > 1), requiring fuel tobe cut in small pieces or often using processed biomass such as pellets.
Natural gas: Includes gas occurring in deposits, whether liquefied or gaseous, consisting
mainly of methane. It includes both non‐associated gas originating from fields producing
hydrocarbons only in gaseous form, and associated gas produced in association with crude
oil production as well as methane recovered from coal mines (colliery gas). Natural gas
liquids, manufactured gas (produced from municipal or industrial waste, or sewage) andquantities vented or flared are not included. Gas data in cubic metres are expressed on agross calorific value basis and are measured at 15 °C and at 760 mm Hg (Standard
Conditions). Gas data expressed in tonnes of oil equivalent, mainly for comparison reasons
with other fuels, are on a net calorific basis. The difference between the net and the grosscalorific value is the latent heat of vaporisation of the water vapour produced during
combustion of the fuel (for gas the net calorific value is 10% lower than the gross calorificvalue).
Natural gas liquids (NGLs): Liquid or liquefied hydrocarbons produced in the manufacture,
purification and stabilisation of natural gas. NGLs are portions of natural gas recovered asliquids in separators, field facilities or gas processing plants. NGLs include, but are not limited
to, ethane (when it is removed from the natural gas stream), propane, butane, pentane,
natural gasoline and condensates.
Network gases: Include natural gas, biomethane, synthetic methane and hydrogen blended
in a gas network.
Non‐energy use: The use of fuels as feedstocks for chemical products that are not used inenergy applications. Examples of resulting products are lubricants, paraffin waxes, asphalt,
bitumen, coal tars and timber preservative oils.
Non‐renewable waste: Non‐biogenic waste, such as plastics in municipal or industrial waste.

Off‐grid systems: Mini‐grids and stand‐alone systems for individual households or groups ofconsumers not connected to a main grid.

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Nuclear: Refers to the primary energy equivalent of the electricity produced by a nuclear
power plant, assuming an average conversion efficiency of 33%.

Offshore wind: Refers to electricity produced by wind turbines that are installed in open
water, usually in the ocean.
Oil: Includes both conventional and unconventional oil production. Petroleum products
include refinery gas, ethane, liquid petroleum gas, aviation gasoline, motor gasoline, jet
fuels, kerosene, gas/diesel oil, heavy fuel oil, naphtha, white spirits, lubricants, bitumen,paraffin, waxes and petroleum coke.
Other energy sector: Covers the use of energy by transformation industries and the energy
losses in converting primary energy into a form that can be used in the final consuming
sectors. It includes losses in low‐emissions hydrogen and hydrogen‐based fuels production,
bioenergy processing, gas works, petroleum refineries, coal and gas transformation andliquefaction. It also includes energy own use in coal mines, in oil and gas extraction and inelectricity and heat production. Transfers and statistical differences are also included in thiscategory. Fuel transformation in blast furnaces and coke ovens are not accounted for in theother energy sector category.
Other industry: A category of industry branches that includes construction, food processing,machinery, mining, textiles, transport equipment, wood processing and remaining industry.
Passenger car: A road motor vehicle, other than a moped or a motorcycle, intended totransport passengers. It includes vans designed and used primarily to transport passengers.
Excluded are light commercial vehicles, motor coaches, urban buses, and mini‐buses/mini‐coaches.
Peat: Peat is a combustible soft, porous or compressed, fossil sedimentary deposit of plantorigin with high water content (up to 90% in the raw state), easily cut, of light to dark brown
colour. Milled peat is included in this category. Peat used for non‐energy purposes is notincluded here.
Plastic collection rate: Proportion of plastics that is collected for recycling relative to thequantity of recyclable waste available.
Plastic waste: Refers to all post‐consumer plastic waste with a lifespan of more than one
year.
Power generation: Refers to fuel use in electricity generation plants, heat plants, andcombined heat and power plants. Both main activity producer plants and small plants that
produce fuel for their own use (auto‐producers) are included.

Productive uses: Energy used towards an economic purpose: agriculture, industry, services
and non‐energy use. Some energy demand from the transport sector, e.g. freight, could beconsidered as productive, but is treated separately.
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Process emissions: CO2 emissions produced from industrial processes which chemically or
physically transform materials. A notable example is cement production, in which CO2 isemitted when calcium carbonate is transformed into lime, which in turn is used to produce
clinker.

C

Rare earth elements (REEs): A group of seventeen chemical elements in the periodic table,
specifically the fifteen lanthanides plus scandium and yttrium. REEs are key components insome clean energy technologies, including wind turbines, electric vehicle motors andelectrolysers.
Renewables: Includes bioenergy, geothermal, hydropower, solar photovoltaics (PV),concentrating solar power (CSP), wind and marine (tide and wave) energy for electricity andheat generation.
Residential: Energy used by households including space heating and cooling, water heating,lighting, appliances, electronic devices and cooking.
Road transport: Includes all road vehicle types (passenger cars, two/three‐wheelers, lightcommercial vehicles, buses and medium and heavy freight trucks).
Self‐sufficiency: Corresponds to indigenous production divided by total primary energy
demand.
Services: Energy used in commercial facilities, e.g. offices, shops, hotels, restaurants, and ininstitutional buildings, e.g. schools, hospitals, public offices. Energy use in services includes
space heating and cooling, water heating, lighting, appliances, cooking and desalination.
Shale gas: Natural gas contained within a commonly occurring rock classified as shale. Shaleformations are characterised by low permeability, with more limited ability of gas to flow
through the rock than is the case within a conventional reservoir. Shale gas is generally
produced using hydraulic fracturing.
Shipping/navigation: This transport sub‐sector includes both domestic and internationalnavigation and their use of marine fuels. Domestic navigation covers the transport of goods
or people on inland waterways and for national sea voyages (starts and ends in the same
country without any intermediate foreign port). International navigation includes quantities
of fuels delivered to merchant ships (including passenger ships) of any nationality for
consumption during international voyages transporting goods or passengers.
Single‐use plastics (or disposable plastics): Plastic items used only one time before disposal.
Solar: Includes solar photovoltaics and concentrating solar power.
Solar home systems: Small‐scale photovoltaic and battery stand‐alone systems, i.e. withcapacity higher than 10 watt peak (Wp) supplying electricity for single households or small
businesses. They are most often used off‐grid, but also where grid supply is not reliable.
Access to electricity in the IEA definition considers solar home systems from 25 Wp in rural
areas and 50 Wp in urban areas. It excludes smaller solar lighting systems, e.g. solar lanternsof less than 11 Wp.

Solid bioenergy: Includes charcoal, fuelwood, dung, agricultural residues, wood waste andother solid biogenic wastes.
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Solar photovoltaics (PV): Electricity produced from solar photovoltaic cells.

Solid fuels: Include coal, modern solid bioenergy, traditional use of biomass and industrial
and municipal wastes.
Stand‐alone systems: Small‐scale autonomous electricity supply for households or small
businesses. They are generally used off‐grid, but also where grid supply is not reliable. Stand‐alone systems include solar home systems, small wind or hydro generators, diesel or gasoline
generators, etc. The difference compared with mini‐grids is in scale and that stand‐alone
systems do not have a distribution network serving multiple costumers.
Steam coal: A type of coal that is mainly used for heat production or steam‐raising in power
plants and, to a lesser extent, in industry. Typically, steam coal is not of sufficient quality forsteel making. Coal of this quality is also commonly known as thermal coal.
Synthetic methane: Methane from sources other than natural gas, including coal‐to‐gas andlow‐emissions synthetic methane.
Synthetic oil: Synthetic oil produced through Fischer‐Tropsch conversion or methanol
synthesis. It includes oil products from CTL and GTL, and low‐emissions liquid hydrogen‐based fuels.
Tight oil: Oil produced from shale or other very low permeability formations, generally using
hydraulic fracturing. This is also sometimes referred to as light tight oil. Tight oil includes tightcrude oil and condensate production except for the United States, which includes tight crude
oil only (US tight condensate volumes are included in natural gas liquids).
Total energy supply (TES): Represents domestic demand only and is broken down into
electricity and heat generation, other energy sector and total final consumption.
Total final consumption (TFC): Is the sum of consumption by the various end‐use sectors.
TFC is broken down into energy demand in the following sectors: industry (including
manufacturing, mining, chemicals production, blast furnaces and coke ovens), transport,
buildings (including residential and services) and other (including agriculture and other non‐energy use). It excludes international marine and aviation bunkers, except at world level
where it is included in the transport sector.

Traditional use of biomass: Refers to the use of solid biomass with basic technologies, suchas a three‐stone fire or basic improved cook stoves (ISO tier 0‐1), often with no or poorly
operating chimneys. Forms of biomass used include wood, wood waste, charcoal agriculturalresidues and other bio‐sourced fuels such as animal dung.

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Total final energy consumption (TFEC): Is a variable defined primarily for tracking progress
towards target 7.2 of the United Nations Sustainable Development Goals (SDG). It
incorporates total final consumption by end‐use sectors, but excludes non‐energy use. It
excludes international marine and aviation bunkers, except at world level. Typically this isused in the context of calculating the renewable energy share in total final energy
consumption (indicator SDG 7.2.1), where TFEC is the denominator.

CTransport: Fuels and electricity used in the transport of goods or people within the national
territory irrespective of the economic sector within which the activity occurs. This includes
fuel and electricity delivered to vehicles using public roads or for use in rail vehicles; fueldelivered to vessels for domestic navigation; fuel delivered to aircraft for domestic aviation;and energy consumed in the delivery of fuels through pipelines. Fuel delivered tointernational marine and aviation bunkers is presented only at the world level and is
excluded from the transport sector at a domestic level.
Trucks: Includes all size categories of commercial vehicles: light trucks (gross vehicle weightless than 3.5 tonnes); medium freight trucks (gross vehicle weight 3.5‐15 tonnes); and heavy
freight trucks (>15 tonnes).
Unabated fossil fuel use: Combustion of fossil fuels in facilities without CCUS.
Useful energy: Refers to the energy that is available to end‐users to satisfy their needs. Thisis also referred to as energy services demand. As result of transformation losses at the pointof use, the amount of useful energy is lower than the corresponding final energy demand formost technologies. Equipment using electricity often has higher conversion efficiency thanequipment using other fuels, meaning that for a unit of energy consumed, electricity canprovide more energy services.
Value‐adjusted levelised cost of electricity (VALCOE): Incorporates information on bothcosts and the value provided to the system. Based on the LCOE, estimates of energy, capacityand flexibility value are incorporated to provide a more complete metric of competitivenessfor power generation technologies.
Variable renewable energy (VRE): Refers to technologies whose maximum output at any
time depends on the availability of fluctuating renewable energy resources. VRE includes abroad array of technologies such as wind power, solar PV, run‐of‐river hydro, concentrating
solar power (where no thermal storage is included) and marine (tidal and wave).
Zero carbon‐ready buildings: A zero carbon‐ready building is highly energy efficient andeither uses renewable energy directly or an energy supply that can be fully decarbonised,such as electricity or district heat.

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Zero emissions vehicles (ZEVs): Vehicles that are capable of operating without tailpipe CO2
emissions (battery electric and fuel cell vehicles).

Regional and country groupings
Figure C.1 ⊳Main country groupings

Note: This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries
and to the name of any territory, city or area.

Advanced economies: OECD regional grouping and Bulgaria, Croatia, Cyprus1,2, Malta andRomania.
Africa: North Africa and sub‐Saharan Africa regional groupings.
Asia Pacific: Southeast Asia regional grouping and Australia, Bangladesh, Democratic
People’s Republic of Korea (North Korea), India, Japan, Korea, Mongolia, Nepal, New Zealand,
Pakistan, People’s Republic of China (China), Sri Lanka, Chinese Taipei, and other Asia Pacificcountries and territories.3
Caspian: Armenia, Azerbaijan, Georgia, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan andUzbekistan.
Central and South America: Argentina, Plurinational State of Bolivia (Bolivia), Brazil, Chile,
Colombia, Costa Rica, Cuba, Curaçao, Dominican Republic, Ecuador, El Salvador, Guatemala,Haiti, Honduras, Jamaica, Nicaragua, Panama, Paraguay, Peru, Suriname, Trinidad andTobago, Uruguay, Bolivarian Republic of Venezuela (Venezuela), and other Central and SouthAmerican countries and territories.4
China: Includes the (People's Republic of) China and Hong Kong, China.

Emerging market and developing economies: All other countries not included in theadvanced economies regional grouping.

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Developing Asia: Asia Pacific regional grouping excluding Australia, Japan, Korea and
New Zealand.

CEurasia: Caspian regional grouping and the Russian Federation (Russia).
Europe: European Union regional grouping and Albania, Belarus, Bosnia and Herzegovina,
North Macedonia, Gibraltar, Iceland, Israel5, Kosovo, Montenegro, Norway, Serbia,
Switzerland, Republic of Moldova, Türkiye, Ukraine and United Kingdom.
European Union: Austria, Belgium, Bulgaria, Croatia, Cyprus1,2, Czech Republic, Denmark,Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania,
Luxembourg, Malta, Netherlands, Poland, Portugal, Romania, Slovak Republic, Slovenia,
Spain and Sweden.
IEA (International Energy Agency): OECD regional grouping excluding Chile, Colombia, Costa
Rica, Iceland, Israel, Latvia and Slovenia.
Latin America: Central and South America regional grouping and Mexico.
Middle East: Bahrain, Islamic Republic of Iran (Iran), Iraq, Jordan, Kuwait, Lebanon, Oman,
Qatar, Saudi Arabia, Syrian Arab Republic (Syria), United Arab Emirates and Yemen.
Non‐OECD: All other countries not included in the OECD regional grouping.
Non‐OPEC: All other countries not included in the OPEC regional grouping.
North Africa: Algeria, Egypt, Libya, Morocco and Tunisia.
North America: Canada, Mexico and United States.
OECD (Organisation for Economic Co‐operation and Development): Australia, Austria,
Belgium, Canada, Chile, Czech Republic, Colombia, Costa Rica, Denmark, Estonia, Finland,
France, Germany, Greece, Hungary, Iceland, Ireland, Israel, Italy, Japan, Korea, Latvia,
Lithuania, Luxembourg, Mexico, Netherlands, New Zealand, Norway, Poland, Portugal,
Slovak Republic, Slovenia, Spain, Sweden, Switzerland, Türkiye, United Kingdom and UnitedStates.
OPEC (Organization of the Petroleum Exporting Countries): Algeria, Angola, Republic of theCongo (Congo), Equatorial Guinea, Gabon, the Islamic Republic of Iran (Iran), Iraq, Kuwait,
Libya, Nigeria, Saudi Arabia, United Arab Emirates and Bolivarian Republic of Venezuela(Venezuela).
Southeast Asia: Brunei Darussalam, Cambodia, Indonesia, Lao People’s Democratic Republic(Lao PDR), Malaysia, Myanmar, Philippines, Singapore, Thailand and Viet Nam. These
countries are all members of the Association of Southeast Asian Nations (ASEAN).

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Sub‐Saharan Africa: Angola, Benin, Botswana, Cameroon, Republic of the Congo (Congo),
Côte d’Ivoire, Democratic Republic of the Congo, Eritrea, Ethiopia, Gabon, Ghana, Kenya,
Mauritius, Mozambique, Namibia, Niger, Nigeria, Senegal, South Africa, South Sudan, Sudan,
United Republic of Tanzania (Tanzania), Togo, Zambia, Zimbabwe and other African countries
and territories.6

Country notes
1
Note by Republic of Türkiye: The information in this document with reference to “Cyprus” relates to thesouthern part of the island. There is no single authority representing both Turkish and Greek Cypriot people
on the island. Türkiye recognises the Turkish Republic of Northern Cyprus (TRNC). Until a lasting and equitable
solution is found within the context of the United Nations, Türkiye shall preserve its position concerning the“Cyprus issue”.
2

Note by all the European Union Member States of the OECD and the European Union: The Republic of Cyprus
is recognised by all members of the United Nations with the exception of Türkiye. The information in thisdocument relates to the area under the effective control of the Government of the Republic of Cyprus.
3

Individual data are not available and are estimated in aggregate for: Afghanistan, Bhutan, Cook Islands, Fiji,
French Polynesia, Kiribati, Macau (China), Maldives, New Caledonia, Palau, Papua New Guinea, Samoa,
Solomon Islands, Timor‐Leste and Tonga and Vanuatu.

4

Individual data are not available and are estimated in aggregate for: Anguilla, Antigua and Barbuda, Aruba,
Bahamas, Barbados, Belize, Bermuda, Bonaire, British Virgin Islands, Cayman Islands, Dominica, Falkland
Islands (Malvinas), French Guiana, Grenada, Guadeloupe, Guyana, Martinique, Montserrat, Saba, Saint
Eustatius, Saint Kitts and Nevis, Saint Lucia, Saint Pierre and Miquelon, Saint Vincent and Grenadines, Saint
Maarten, Turks and Caicos Islands.
5
The statistical data for Israel are supplied by and under the responsibility of the relevant Israeli authorities.
The use of such data by the OECD and/or the IEA is without prejudice to the status of the Golan Heights, East
Jerusalem and Israeli settlements in the West Bank under the terms of international law.
6

Individual data are not available and are estimated in aggregate for: Burkina Faso, Burundi, Cabo Verde,Central African Republic, Chad, Comoros, Djibouti, Kingdom of Eswatini, Gambia, Guinea, Guinea‐Bissau,
Lesotho, Liberia, Madagascar, Malawi, Mali, Mauritania, Réunion, Rwanda, Sao Tome and Principe, Seychelles,
Sierra Leone, Somalia and Uganda.

AC
AFOLU
APEC
APS
ASEAN
BECCS
BEV
CAAGR
CAFE
CBM
CCGT
CCUS
CDR
CEM
CH4
CHP
CNG
CO
CO2
CO2‐eqalternating current
agriculture, forestry and other land use
Asia‐Pacific Economic Cooperation
Announced Pledges Scenario
Association of Southeast Asian Nations
bioenergy equipped with CCUS
battery electric vehicles
compound average annual growth rate
corporate average fuel economy standards (United States)
coalbed methane
combined‐cycle gas turbine
carbon capture, utilisation and storage
carbon dioxide removal
Clean Energy Ministerial
methanecombined heat and power; the term co‐generation is sometimes usedcompressed natural gas
carbon monoxidecarbon dioxidecarbon‐dioxide equivalent

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Abbreviations and acronyms

C

502

Conference of Parties (UNFCCC)
concentrating solar power
coal‐to‐gas
coal‐to‐liquids
direct air capture
direct air capture and storage
direct current
distributed energy resources
direct reduced irondemand‐side integration
distribution system operator
demand‐side response
extra‐heavy oil and bitumen
emerging market and developing economies
enhanced oil recovery
Environmental Protection Agency (United States)
environmental, social and governanceEuropean Union
European Union Emissions Trading Systemelectric vehicle
Food and Agriculture Organization of the United Nations
fuel cell electric vehicle
foreign direct investment
Final investment decision
feed‐in tariff
free on board
Global Energy and Climate (model)
gross domestic productgreenhouse gases
gas‐to‐liquids
heavy‐duty vehiclehydrogenated esters and fatty acids
heavy fuel oilhigh voltage direct current
International Atomic Energy Agency
internal combustion engine
information and communication technologies
International Energy Agency
integrated gasification combined‐cycle
International Institute for Applied Systems Analysis
International Monetary FundInternational Maritime Organizationinternational oil company
Intergovernmental Panel on Climate ChangeInternational Energy Agency | World Energy Outlook 2022

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COP
CSP
CTG
CTL
DAC
DACS
DC
DER
DRI
DSI
DSO
DSR
EHOB
EMDE
EOR
EPA
ESG
EU
EU ETS
EV
FAO
FCEV
FDI
FID
FiT
FOB
GEC
GDP
GHG
GTL
HDV
HEFA
HFO
HVDC
IAEA
ICE
ICT
IEA
IGCC
IIASA
IMF
IMO
IOC
IPCC

levelised cost of electricity
light commercial vehicle
light‐duty vehicle
light‐emitting diodeliquefied natural gas
liquefied petroleum gas
land use, land‐use change and forestry
minimum energy performance standards
market exchange rate
Nationally Determined Contributions
Nuclear Energy Agency (an agency within the OECD)natural gas liquids
natural gas vehicle
national oil company
net present value
nitrogen oxides
nitrous dioxide
Net Zero Emissions by 2050 Scenario
Organisation for Economic Co‐operation and Development
Organization of the Petroleum Exporting Countries
plug‐in hybrid electric vehicles
passenger light‐duty vehicle
particulate matterfine particulate matter
power purchase agreement
purchasing power parity
photovoltaics
research and development
research, development and demonstration
Sustainable Development Goals (United Nations)
small and medium enterprises
steam methane reformation
sulphur dioxide
Stated Policies Scenariotransmission and distribution
thermal energy storage
total final consumption
total final energy consumption
total primary energy demandtransmission system operator
United Arab Emirates
United Nations
United Nations Development Programme
United Nations Environment Programme

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LCOE
LCV
LDV
LED
LNG
LPG
LULUCF
MEPS
MER
NDCs
NEA
NGLs
NGV
NOC
NPV
NOX
N2O
NZE
OECD
OPEC
PHEV
PLDV
PM
PM2.5
PPA
PPP
PV
R&D
RD&D
SDG
SME
SMR
SO2
STEPS
T&D
TES
TFC
TFEC
TPED
TSO
UAE
UN
UNDP
UNEP

C

504

United Nations Framework Convention on Climate Change
United States
United States Geological Survey
value‐adjusted levelised cost of electricity
variable renewable energy
weighted average cost of capital
World Energy Outlook
World Health Organization
zero emissions vehicle
zero carbon‐ready building

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UNFCCCUSUSGSVALCOE
VRE
WACC
WEO
WHO
ZEV
ZCRB

Annex D
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https://www.iea.org/reports/world‐energy‐employment
IEA (2021), Net Zero by 2050: A Roadmap for the Global Energy Sector,
https://www.iea.org/reports/net‐zero‐by‐2050
IEA (2020), Working from home can save energy and reduce emissions. But how much?,https://www.iea.org/commentaries/working‐from‐home‐can‐save‐energy‐and‐reduce‐
emissions‐but‐how‐much
IIASA (International Institute for Applied Systems Analysis) (2022), AR6 Scenarios Databasehosted by IIASA, https://data.ene.iiasa.ac.at/ar6
IPCC (Intergovernmental Panel on Climate Change) (2022a), Working Group III: Summaryfor Policy Makers,
https://www.ipcc.ch/report/ar6/wg3/downloads/report/IPCC_AR6_WGIII_SPM.pdf
IPCC (2022b), Climate Change 2022: Impacts, Adaption and Vulnerability,
https://www.ipcc.ch/report/ar6/wg2/
IPCC (2021), Climate Change 2021: The Physical Science Basis. Contribution of Working
Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change,
https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_FullReport.pdf
Mumbower, S. and J. Sobieralski (2022), Jet‐setting during COVID‐19: Environmental
implications of the pandemic induced private aviation boom, Transportation ResearchInterdisciplinary Perspectives, Vol. 13, https://doi.org/10.1016/j.trip.2022.100575

Ritchie, H. and M. Roser, (2017), Meat and Dairy Production,
https://ourworldindata.org/meat‐production

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Ritchie, H. and M. Roser (2020), Environmental Impacts of Food Production,
https://ourworldindata.org/environmental‐impacts‐of‐foodDWFP (World Food Programme) (2020), 5 facts about food waste and hunger,
https://www.wfp.org/stories/5‐facts‐about‐food‐waste‐and‐hunger
WHO (World Health Organization) (2022), Household Energy (database),https://www.who.int/data/gho/data/themes/air‐pollution/who‐household‐energy‐db(accessed 20 July 2022).

Chapter 4: Energy security in energy transitions
Eurometaux (2022), Europe’s non‐ferrous metals producers call for emergency EU action toprevent permanent deindustrialisation from spiralling electricity and gas prices,
https://eurometaux.eu/media/qnhn5k30/non‐ferrous‐metals‐ceo‐letter‐on‐energy‐crisis‐
06‐09‐2022.pdf
European Commission JRC (Joint Research Centre) (2017), Global flood depth‐damage
functions: Methodology and the database with guidelines (database),https://publications.jrc.ec.europa.eu/repository/handle/JRC105688 (accessed
10 June 2022).
European Commission (2022), European CO2 storage (database),https://setis.ec.europa.eu/european‐co2‐storage‐database_en (accessed 16 June 2022).
Global Solar Atlas (2022), Global Solar Atlas (database),https://globalsolaratlas.info (accessed 20 July 2022).
Grubert, E. and S. Hastings‐Simon (2022), Designing the mid‐transition: A review of
medium‐term challenges for coordinated decarbonization in the United States, WIREs
Climate Change, 13(3), e768. https://doi.org/10.1002/wcc.768
IEA (International Energy Agency) (2022a), 10‐Point Plan to Reduce the European Union’s
Reliance on Russian Natural Gas, https://www.iea.org/reports/a‐10‐point‐plan‐to‐reduce‐the‐european‐unions‐reliance‐on‐russian‐natural‐gas
IEA (2022b), The value of urgent action on energy efficiency,
https://www.iea.org/reports/the‐value‐of‐urgent‐action‐on‐energy‐efficiency
IEA (2022c), Accelerating energy efficiency: What governments can do now to deliver
energy savings, https://www.iea.org/commentaries/accelerating‐energy‐efficiency‐what‐
governments‐can‐do‐now‐to‐deliver‐energy‐savings

IEA (2022e), Empowering people to act: How awareness and behaviour campaigns canenable citizens to save energy during and beyond today’s energy crisis,
https://www.iea.org/commentaries/empowering‐people‐to‐act‐how‐awareness‐and‐behaviour‐campaigns‐can‐enable‐citizens‐to‐save‐energy‐during‐and‐beyond‐today‐s‐energy‐crisis
508

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IEA (2022d), A 10‐Point Plan to Cut Oil Use,
https://www.iea.org/reports/a‐10‐point‐plan‐to‐cut‐oil‐use

IEA (2022f), World Energy Investment 2022,
https://www.iea.org/reports/world‐energy‐investment‐2022
IEA (2022g), The Need for Net Zero Emissions Demonstration Projects,
https://www.iea.org/reports/the‐need‐for‐net‐zero‐demonstration‐projects
IEA (2021a), Financing clean energy transitions in emerging and developing economies,
https://www.iea.org/reports/financing‐clean‐energy‐transitions‐in‐emerging‐and‐developing‐economies
IEA (2021b), The cost of capital in clean energy transitions,
https://www.iea.org/articles/the‐cost‐of‐capital‐in‐clean‐energy‐transitions
IEA (2021c), Hydropower Special Market Report,
https://www.iea.org/reports/hydropower‐special‐market‐report
IEA (2021d), The Role of Low‐Carbon Fuels in the Clean Energy Transitions of the Power
Sector, https://www.iea.org/reports/the‐role‐of‐low‐carbon‐fuels‐in‐the‐clean‐energy‐transitions‐of‐the‐power‐sector
IEA (2021e), Enhancing Cyber Resilience in Electricity Systems,
https://www.iea.org/reports/enhancing‐cyber‐resilience‐in‐electricity‐systems
IPCC (Intergovernmental Panel on Climate Change) (2021), Climate Change 2021: The
Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of
the Intergovernmental Panel on Climate Change,
https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_FullReport.pdf
Jochem, P. (2020), Does free‐floating carsharing reduce private vehicle ownership? Thecase of SHARE NOW in European cities, Transportation Research Part A: Policy and Practice,141, pp. 373‐395, https://www.sciencedirect.com/science/article/pii/S0965856420307291
Jupiter Intelligence (2022), ClimateScore Global (database),https://jupiterintel.com/products/ (accessed 24 July 2022).
OECD (Organisation for Economic Co‐operation and Development) (2021), Trends in
Stakeholder Reporting: Mineral Supply Chains (database),https://mneguidelines.oecd.org/trendsinstakeholderreportingmineralsupplychains.htm(accessed 30 June 2022).

Ofgem (2022), Net Zero Britain: Developing an energy system fit for the future,https://www.ofgem.gov.uk/publications/net‐zero‐britain‐developing‐energy‐system‐fit‐
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OECD (2019), Interconnected Supply Chains: A comprehensive look at due diligencechallenges and opportunities sourcing cobalt and copper from the Democratic Republic of
the Congo, https://mneguidelines.oecd.org/interconnected‐supply‐chains‐a‐comprehensive‐look‐at‐due‐diligence‐challenges‐and‐opportunities‐sourcing‐cobalt‐and‐copper‐from‐the‐drc.htm

D

S&P Global (2022), S&P Global Market Intelligence Platform (database),https://www.spglobal.com/marketintelligence/en/ (accessed multiple times in April ‐ July2022).
Shaffer, B., M. Auffhammer and C. Samaras (2021), Make electric vehicles lighter tomaximize climate and safety benefits, Nature, Vol. 598, pp.254‐256,
https://doi.org/10.1038/d41586‐021‐02760‐8
US DOE (United States Department of Energy) (2018), The National Carbon Sequestration
Database (NATCARB) (database), https://doi.org/10.18141/1474110 (accessed
28 April 2022).
World Inequality Database (2022), World Inequality Database (database),https://wid.world/ (accessed 10 July 2022).

Chapter 5: Outlook for energy demand
Balabanyan, A. et al. (2021), African Utilities during COVID‐19: Challenges and impacts,
https://openknowledge.worldbank.org/handle/10986/36179
Copernicus Climate Change Service (2022), Surface air temperature for August 2022
(database), https://climate.copernicus.eu/surface‐air‐temperature‐august‐2022 (accessed
13 September 2022).
Ethiopian Statistics Service (2022), Country and Regional Level Consumer Price Indices,
https://www.statsethiopia.gov.et/wp‐content/uploads/2022/07/CPI_June_2022.pdf
EV Volumes (2022), EV Data Centre (database), https://www.ev‐volumes.com/datacenter/(accessed 6 September 2022).
Ghana Statistical Service (2022), Year‐on‐Year Inflation,
https://www.statsghana.gov.gh/cpigraph.php?graphindicators=MTI0MDM5Njc1Ny42OTU1/cpigraph/n1r7pr567p
GOGLA (Global Off‐Grid Lighting Association) (2022), Global Off‐Grid Solar Market Report,semi‐annual sales and impact data ‐ July‐December 2021,
https://www.gogla.org/global‐off‐grid‐solar‐market‐report
IEA (International Energy Agency) (2022a), Nuclear Power and Secure Energy Transitions,
https://www.iea.org/reports/nuclear‐power‐and‐secure‐energy‐transitions
IEA (2022b), A 10‐Point Plan to Reduce the European Union’s Reliance on Russian NaturalGas, https://www.iea.org/reports/a‐10‐point‐plan‐to‐reduce‐the‐european‐unions‐reliance‐on‐russian‐natural‐gas

510International Energy Agency | World Energy Outlook 2022

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IEA (2022c), A 10‐Point Plan to Cut Oil Use,
https://www.iea.org/reports/a‐10‐point‐plan‐to‐cut‐oil‐use

IEA (2022d), Playing My Part: How to save money, reduce reliance on Russian energy,
support Ukraine and help the planet, https://www.iea.org/reports/playing‐my‐part
IEA (2022e), Africa Energy Outlook 2022,
https://www.iea.org/reports/africa‐energy‐outlook‐2022
IEA (2022f), Global Energy Review: CO2 emissions in 2021,
https://www.iea.org/reports/global‐energy‐review‐2021
IEA (2022g), What would net zero by 2050 mean for the emissions footprints of younger
people versus their parents?, https://www.iea.org/commentaries/what‐would‐net‐zero‐by‐2050‐mean‐for‐the‐emissions‐footprints‐of‐younger‐people‐versus‐their‐parents
IEA (2022h), Clean Energy Transition in the Greater Horn of Africa,
https://www.iea.org/reports/clean‐energy‐transitions‐in‐the‐greater‐horn‐of‐africa
IEA (2022i), Cooling Tracking, https://www.iea.org/reports/space‐cooling
IEA (2022j), An Energy Sector Roadmap to Net Zero Emissions in Indonesia,
https://www.iea.org/reports/an‐energy‐sector‐roadmap‐to‐net‐zero‐emissions‐in‐indonesia
IEA (2021), Clean Energy Transition in the Sahel,
https://www.iea.org/reports/clean‐energy‐transitions‐in‐the‐sahel
IEA (2020a), Clean Energy Transition in North Africa,
https://www.iea.org/reports/clean‐energy‐transitions‐in‐north‐africa
IEA (2020b), Is cooling the future of heating?,
https://www.iea.org/commentaries/is‐cooling‐the‐future‐of‐heating
IPCC (Intergovernmental Panel on Climate Change) (2022), Climate Change 2022: Impacts,
Adaptation and Vulnerability, https://doi.org/10.1017/9781009325844
IPCC (2021), Climate Change 2021: The Physical Science Basis. Contribution of Working
Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change,
https://doi.org/10.1017/9781009157896
IPCC (2018), Global Warming of 1.5 °C, An IPCC Special Report on the Impacts of Global
Warming of 1.5 °C above pre‐industrial levels, https://doi.org/10.1017/9781009157940

NASA Goddard Institute for Space Studies (2022), 2021 Tied for 6th Warmest Year inContinued Trend, NASA Analysis Shows,
https://www.giss.nasa.gov/research/news/20220113/

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Grid Solar Market Trends Report 2022: State of the Sector,
https://www.gogla.org/events/sneak‐peek‐off‐grid‐solar‐market‐trends‐report‐2022‐state‐of‐the‐sector

DNet Zero Tracker (2022), Net Zero Tracker, (database), https://zerotracker.net/ (accessed
September 2022).
Rafaj, P., G. Kiesewetter and V. Krey (2021), Air quality and health implications of 1.5 °C ‐2 °C climate pathways under considerations of ageing population: a multi‐model scenario
analysis, Environmental Research Letters, Vol. 16, N. 4,
https://iopscience.iop.org/article/10.1088/1748‐9326/abdf0b
RMI (Rocky Mountain Institute) (2018), Closing the Circuit: Stimulating end‐use demand forrural electrification, https://rmi.org/wp‐content/uploads/2018/10/SEED‐Demand‐
Stimulation‐Report.pdf
SEforALL (Sustainable Energy for All) and CPI (Climate Policy Initiatives) (2021), Energizing
Finance 2021, https://www.seforall.org/system/files/2021‐10/EF‐2021‐UL‐SEforALL.pdf
World Bank (2022), The Global Health Cost of PM2.5 Air Pollution: A case for action beyond
2021, https://doi.org/10.1596/978‐1‐4648‐1816‐5
WHO (World Health Organization) (2022), Household air pollution data,
https://www.who.int/data/gho/data/themes/air‐pollution/household‐air‐pollution,(accessed 17 June 2022).
WHO (2021), WHO Global Air Quality Guidelines: particulate matter (PM2.5 and PM10),
ozone, nitrogen dioxide, sulphur dioxide and carbon monoxide,
https://www.who.int/publications/i/item/9789240034228

Chapter 6: Outlook for electricity
Elia, A. (2020), Wind turbine cost reduction: A detailed bottom‐up analysis of innovation
drivers, Energy Policy, https://doi.org/10.1016/j.enpol.2020.111912
Energie‐Control Austria, MEKH and VaasaETT (2022), Household Energy Price Index(database), https://www.energypriceindex.com/price‐data (accessed 4 August 2022).
European Commission (2022), Proposal for a council regulation on an emergency
intervention to address high energy prices, https://eur‐lex.europa.eu/legal‐
content/EN/TXT/PDF/?uri=CELEX:52022PC0473&from=EN
European Council (2022), G7 Leaders’ Communiqué,
https://www.consilium.europa.eu/en/press/press‐releases/2022/06/28/g7‐leaders‐
communique/
IEA (International Energy Agency) (2022a), Electricity Market Report ‐ July 2022: Update,https://www.iea.org/reports/electricity‐market‐report‐july‐2022

512International Energy Agency | World Energy Outlook 2022

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IEA (2022b), Achieving Net Zero Heavy Industry Sectors in G7 Members,
https://www.iea.org/reports/achieving‐net‐zero‐heavy‐industry‐sectors‐in‐g7‐members

IEA (2022c), Global Hydrogen Review 2022,
https://www.iea.org/reports/global‐hydrogen‐review‐2022
IEA (2022d), Nuclear Power and Secure Energy Transitions,
https://www.iea.org/reports/nuclear‐power‐and‐secure‐energy‐transitions
IEA (2022e), Africa Energy Outlook 2022,
https://www.iea.org/reports/africa‐energy‐outlook‐2022
IEA (2022f), Steering Electricity Markets Towards a Rapid Decarbonisation,
https://www.iea.org/reports/steering‐electricity‐markets‐towards‐a‐rapid‐decarbonisation
IEA (2022g), Southeast Asia Energy Outlook 2022,
https://www.iea.org/reports/southeast‐asia‐energy‐outlook‐2022
IEA (2022h), World Energy Investment 2022,
https://www.iea.org/reports/world‐energy‐investment‐2022
IEA (2022i), Solar PV Global Supply Chains,https://www.iea.org/reports/solar‐pv‐global‐supply‐chains
IEA (2021a), World Energy Outlook 2021,
https://www.iea.org/reports/world‐energy‐outlook‐2021
IEA (2021b), The Role of Critical Minerals in Clean Energy Transitions,
https://www.iea.org/reports/the‐role‐of‐critical‐minerals‐in‐clean‐energy‐transitions
IEA (2021c), Hydropower Special Market Report,
https://www.iea.org/reports/hydropower‐special‐market‐report
IEA (2021d), The Role of Low‐Carbon Fuels in the Clean Energy Transitions of the Power
Sector, https://www.iea.org/reports/the‐role‐of‐low‐carbon‐fuels‐in‐the‐clean‐energy‐transitions‐of‐the‐power‐sector
REN21 (2022), Renewables 2022 Global Status Report, https://www.ren21.net/wp‐
content/uploads/2019/05/GSR2022_Full_Report.pdf
Söderholm, P. (2020), Metal markets and recycling policies: Impacts and challenges,
Mineral Economics, pp. 257–272, https://doi.org/10.1007/s13563‐019‐00184‐5

Chapter 7: Outlook for liquid fuels
Carmen Ferrara, G. (2021), LCA of glass versus PET mineral water bottles: An Italian casestudy, Recycling, Vol. 6 (50), https://doi.org/10.3390/recycling6030050

IEA (2022b), World Energy Investment 2022,
https://www.iea.org/reports/world‐energy‐investment‐2022
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https://www.iea.org/reports/a‐10‐point‐plan‐to‐cut‐oil‐use

D

IEA (2021), Renewable Energy Market Update 2021,
https://www.iea.org/reports/renewable‐energy‐market‐update‐2021
Samuel Schlecht, F. (2020), Comparative life cycle assessment of Tetra Pak carton packages
and alternative packaging systems for beverages and liquid food on the European market,
IFEU ‐ Institut für Energie‐ und Umweltforschung [Institure for Energy and Environmental
Research],https://www.tetrapak.com/content/dam/tetrapak/publicweb/uk/en/sustainability/2020‐
lca‐tetra‐pak‐european‐market.pdf

Chapter 8: Outlook for gaseous fuels
ACER (Agency for the Cooperation of Energy Regulators) (2022), Estimated number anddiversity of supply sources 2021, https://aegis.acer.europa.eu/chest/dataitems/214/view
BEIS (Department for Business, Energy and Industrial Strategy) (2022), Atmospheric
implications of increased hydrogen,https://www.gov.uk/government/publications/atmospheric‐implications‐of‐increased‐hydrogen‐use
Capterio (2021), Why the EU should enact methane regulation for imported oil and gas,
https://flareintel.com/insights/why‐the‐eu‐should‐enact‐methane‐regulation‐for‐imported‐oil‐and‐gas
Cedigaz (2022), Natural gas trade flows (database), https://www.cedigaz.org/ (accessed
1 September 2022).
Davis, M. et al. (2022), North Africa can reduce Europe's dependence on Russian gas bytransporting wasted gas through existing infrastructure,https://ccsi.columbia.edu/sites/default/files/content/pics/publications/CCSI‐Capterio‐
Associated‐Gas‐North‐Africa‐Address‐Energy‐Crisis‐Mar‐2022.pdf
Eurostat (2022), EU Trade since 1999, http://appsso.eurostat.ec.europa.eu/
International Energy Agency (IEA) (2022a), The energy security case for tackling gas flaring
and methane leaks, https://www.iea.org/reports/the‐energy‐security‐case‐for‐tackling‐gas‐flaring‐and‐methane‐leaks
IEA (2022b), Global Hydrogen Review 2022,
https://www.iea.org/reports/global‐hydrogen‐review‐2022
IEA (2022c), Southeast Asia Energy Outlook,https://www.iea.org/reports/southeast‐asia‐energy‐outlook‐2022

Wolfram, P. et al. (2022), Using ammonia as a shipping fuel could disturb the nitrogen cycle,
Nature Energy, https://doi.org/10.1038/s41560‐022‐01124‐4
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Zhizhin, M. et al. (2021), Measuring Gas Flaring in Russia with Multispectral VIIRS Nightfire,
Remote Sensing, Vol. 13(16): 3078, https://doi.org/10.3390/rs13163078

Chapter 9: Outlook for solid fuels
IPCC (Intergovernmental Panel on Climate Change) (2021), Climate Change 2021: The
Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of
the Intergovernmental Panel on Climate Change,
https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_FullReport.pdf
Havlík P. et al. (2014), Climate change mitigation through livestock system transitions,
PNAS, pp. 3709‐3714, https://doi.org/10.1073/pnas.1308044111

Annex B: Design of the scenarios
BGR (Bundesanstalt für Geowissenschaften und Rohstoffe) (Germany) (2021), (Federal
Institute for Geosciences and Natural Resources), Energiestudie 2021: Daten und
Entwicklungen der deutschen und globalen Energieversorgung, [Energy Study 2021: Dataand developments in Germany and global energy supply],
https://www.bgr.bund.de/DE/Themen/Energie/Downloads/energiestudie_2021.html
BNEF (Bloomberg New Energy Finance) (2021), Energy Storage System Costs Survey,
https://about.bnef.com
BP (Beyond Petroleum) (2022), Statistical Review of World Energy,
https://www.bp.com/en/global/corporate/energy‐economics/statistical‐review‐of‐world‐energy.html
CEDIGAZ (2022), Country Indicators (databases), https://www.cedigaz.org/databases/(accessed 5 September 2022).
Cole, W., A. Will Frazier and C. Augustine (2021), Cost Projections for Utility Scale Battery
Storage: 2021 Update, https://www.nrel.gov/docs/fy21osti/79236.pdf
Financial Times (2020), Electric car costs to remain higher than traditional engines,
https://www.ft.com/content/a7e58ce7‐4fab‐424a‐b1fa‐f833ce948cb7
IEA (International Energy Agency) (2021), World Energy Outlook 2021,
https://www.iea.org/reports/world‐energy‐outlook‐2021
IEA (2019), Offshore Wind Outlook 2019,https://www.iea.org/reports/offshore‐wind‐outlook‐2019

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Costs in 2021,
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DJames, B. et al. (2018), Mass Production Cost Estimation of Direct H2 PEM Fuel Cell Systems
for Transportation Applications: 2018 Update,https://www.energy.gov/sites/default/files/2020/02/f71/fcto‐sa‐2018‐transportation‐fuel‐cell‐cost‐analysis‐2.pdf
OGJ (Oil and Gas Journal) (2022), Worldwide look at reserves and production,
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production/document/17299726/worldwide‐look‐at‐reserves‐and‐production
Thompson, S. et al. (2018), Direct hydrogen fuel cell electric vehicle cost analysis: Systemand high‐volume manufacturing description, validation, and outlook. Journal of Power
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Tsiropoulos, I., D. Tarvydas and N. Lebedeva (2018), Li‐ion batteries for mobility andstationary storage applications,
https://publications.jrc.ec.europa.eu/repository/handle/JRC113360
UN DESA (United Nations Department of Economic and Social Affairs) (2019), World
Population Prospects 2019, https://www.un.org/development/desa/publications/world‐
population‐prospects‐2019‐highlights.html
UN DESA (2018), World Urbanisation Prospects 2018, https://population.un.org/wup/
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Resource Assessment, https://www.eia.gov/analysis/studies/worldshalegas
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Assessment of 137 Shale Formations in 41 Countries Outside the United States,
https://www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf
USGS (United States Geological Survey) (2012a), An Estimate of Undiscovered Conventional
Oil andGgas Resources of the World, https://pubs.er.usgs.gov/publication/fs20123042
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World Bank (2022a), World Development Indicators,
https://data.worldbank.org/indicator/SP.POP.TOTL

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https://openknowledge.worldbank.org/handle/10986/37455

Annex E
Inputs to the Global Energy and Climate Model
General noteThis annex includes references of databases and publications used to provide input data to
the IEA Global Energy and Climate (GEC) Model. The IEA’s own databases of energy andeconomic statistics provide much of the data used in the GEC Model. These include IEA
statistics on energy supply, transformation, demand at detailed levels, carbon dioxide
emissions from fuel combustion and energy efficiency indicators that form the bedrock of
the World Energy Outlook and Energy Technology Perspectives modelling and analyses.
Supplemental data from a wide range of external sources are also used to complement IEA
data and provide additional detail. This list of databases and publications is comprehensive,
but not exhaustive.

IEA databases and publications
IEA (International Energy Agency) (2022), Coal Information,
https://www.iea.org/data‐and‐statistics/data‐product/coal‐information‐service
IEA (2022), Emissions Factors 2022,
https://www.iea.org/data‐and‐statistics/data‐product/emissions‐factors‐2022
IEA (2022), Energy Efficiency Indicators,
https://www.iea.org/data‐and‐statistics/data‐product/energy‐efficiency‐indicators
IEA (2022), Energy Prices,
https://www.iea.org/data‐and‐statistics/data‐product/energy‐prices
IEA (2022), Energy Technology RD&D Budgets, https://www.iea.org/data‐and‐statistics/data‐product/energy‐technology‐rd‐and‐d‐budget‐database‐2
IEA (2022), Global Energy Review 2022: CO2 emissions in 2021,
https://www.iea.org/reports/global‐energy‐review‐co2‐emissions‐in‐2021‐2
IEA (2022), Global Fuel Economy Initiative 2021 Data Explorer, https://www.iea.org/data‐
and‐statistics/data‐tools/global‐fuel‐economy‐initiative‐2021‐data‐explorer
IEA (2022), Greenhouse Gas Emissions from Energy, https://www.iea.org/data‐and‐statistics/data‐product/greenhouse‐gas‐emissions‐from‐energy
IEA (2022), Methane Tracker Database 2022,
https://www.iea.org/data‐and‐statistics/data‐product/methane‐tracker‐database‐2022

Annex E | Inputs to the Global Energy and Climate Model

517

IEA. CC BY 4.0.

IEA (2022), Monthly Electricity Statistics,
https://www.iea.org/data‐and‐statistics/data‐product/monthly‐electricity‐statistics

IEA (2022), Monthly Gas Data Service,https://www.iea.org/data‐and‐statistics/data‐product/monthly‐gas‐data‐service‐2
IEA (2022), Monthly Oil Data Service Complete, https://www.iea.org/data‐and‐statistics/data‐product/monthly‐oil‐data‐service‐mods‐complete
IEA (2022), Natural Gas Information,
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World Energy Outlook 2022
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