The Oil and Gas
Industry in Net
Zero Transitions

World Energy Outlook Special ReportINTERNATIONAL ENERGYAGENCYThe IEA examines thefull spectrumof energy issues
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Foreword
In the energy and climate worlds, everyone has an opinion about the role of the oil and gas
industry in the transition to net zero emissions. For some, the conclusion is unambiguous.
The oil and gas industry is an obstacle to change, so successful transitions require relegating
oil and gas companies to history. For others, the capabilities and capital the industry holds
can be instruments of change – potentially important ones.
Perspectives on this issue are complicated by the size and diversity of the industry itself.
There are many different companies engaged in oil and gas, from small independent firms tohuge national oil companies – from technology providers to market traders. And there aremany different stances across the industry on energy transitions, from outright opposition
through to grudging acceptance and, in some cases, active pursuit of new opportunities.
A productive discussion on this crucial topic requires a solid evidence base and dispassionate
analysis. This is what the International Energy Agency (IEA) provides in this new special
report. It is by no means our first such in-depth analysis of the sector: we have published arange of useful studies over the years that have highlighted the urgent need for change, mostnotably The Oil and Gas Industry in Energy Transitions, in January 2020. This new special
report brings together, updates and expands that analysis in ways that make this the mostcomprehensive and authoritative work on this topic to date.
Since 2020, important changes have taken place in the global energy sector as the world hascontended with the turmoil of the Covid-19 pandemic and the global energy crisis – and as
an increasing number of governments have raised their climate ambitions and launchedmajor policy initiatives to accelerate clean energy transitions. As a result, we have seen a
40% increase in clean energy investment – and impressive momentum in key technologies
such as solar PV, wind and electric vehicles. This means that for the first time, we see peaks
in demand for all of the fossil fuels before 2030, based on today’s policy settings. Thesesettings are not yet strong enough to deliver steep declines in demand on the other side of
the peaks. However, if governments deliver in full on their national energy and climate
pledges, and even more so if they manage to shift the world onto the narrow pathway tolimiting global warming to 1.5 °C, the consequences for the oil and gas industry will be
profound.

IEA. CC BY 4.0

This report shows that the industry can and must do much more to respond to the threat ofclimate change. Regardless of which pathway the world follows, climate impacts will become
more visible and severe over the coming years, increasing the pressure on all elements ofsociety to find solutions. The industry therefore faces a choice – a moment of truth – over its
engagement with clean energy transitions. So far, its engagement has been minimal: lessthan 1% of global clean energy investment comes from oil and gas companies. But there isno part of the industry that will be left unaffected by the transition to net zero. Every part ofthe industry needs to respond.

Foreword

3

The uncomfortable truth that the industry needs to come to terms with is that successful
clean energy transitions require much lower demand for oil and gas, which means scaling
back oil and gas operations over time – not expanding them. There is no way around this. So
while all oil and gas producers needs to reduce emissions from their own operations,
including methane leaks and flaring, our call to action is much wider.
To escape the narrowing walls of their businesses based on traditional fuels, producers needto embrace the clean energy economy. This report explores what these opportunities look
like, both for companies and for economies that rely heavily on oil and gas revenues. And
with all of the above in mind, the report spells out clearly what it really means for producers
to align with the Paris Agreement and with the 1.5 °C goal.
I would like to thank the excellent team of IEA colleagues who produced this extremely
important study with all the nuance and objectivity that the subject requires – under theleadership of my colleagues Tim Gould, Chief Energy Economist, and Christophe McGlade,Head of the Energy Supply Unit. It provides important input to the discussions at theupcoming COP28 climate change conference in Dubai – but more than that, I am convinced
this will be a reference work for many years to come.

IEA. CC BY 4.0

Dr Fatih Birol
Executive Director
International Energy Agency

4International Energy Agency | Special Report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).
Christophe McGlade, Head of the Energy Supply Unit, co-ordinated the work and was thelead author; he designed and directed the report together with Tim Gould, Chief Energy
Economist.
The other main authors were: Simon Bennett, Tomás De Oliveira Bredariol, Paul Grimal,
Jérôme Hilaire, Peter Zeniewski.
Other key contributors from across the IEA were: Nadim Abillama, Abdullah Al-Abri,
Ana Alcalde Báscones, Oskaras Alsauskas, Caleigh Andrews, Elisa Asmelash, Heymi Bahar,
Emile Belin-Bourgogne, Charlène Bisch, Eric Buisson, Vittoria Chen, France d'Agrain,
Davide D'Ambrosio, Tanguy De Bienassis, David Fischer, Alexandra Hegarty, Paul Hugues,
Marco Iarocci, Hyeji Kim, Tae-Yoon Kim, Yun Young Kim, Luca Lo Re, Apostolos
Petropoulos, Diana Perez-Sanchez, Ryszard Pospiech, Siddharth Singh, Jun Takashiro, andDaniel Wetzel.
Marina Dos Santos, Eleni Tsoukala and Reka Koczka provided essential support.
Justin French-Brooks carried editorial responsibility.
Valuable comments and feedback were provided by other senior management andnumerous other colleagues within the International Energy Agency. In particular Mary
Warlick, Toril Bosoni, Joel Couse, Laura Cozzi, Dan Dorner, Rebecca Gaghen, Timur Gül, Ilkka
Hannula, Dennis Hesseling, Brian Motherway, and Hiro Sakaguchi.

IEA. CC BY 4.0

Thanks go to the IEA Communications and Digital Office for their help to produce the report
and website materials, particularly to Jethro Mullen, Poeli Bojorquez, Curtis Brainard,
Jon Custer, Hortense De Roffignac, Astrid Dumond, Merve Erdil, Grace Gordon,
Julia Horowitz, Oliver Joy, Isabelle Nonain-Semelin, Julie Puech, Robert Stone, Sam Tarling,
Clara Vallois, Lucile Wall, Therese Walsh and Wonjik Yang. The IEA Office of the LegalCounsel, Office of Management and Administration and Energy Data Centre provided
assistance throughout the preparation of the report.

Acknowledgements

5

Peer reviewers

IEA. CC BY 4.0

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:Ali Aissaoui

Oxford Institute for Energy Studies

Atul Arya

S&P Global

Zubin Bamji

World Bank

Imene Ben Rejeb-Mzah

BNP Paribas

Chris Besson

Independent consultant

Jason Bordoff

Columbia University, United States

Siân Bradley

Beyond Oil and Gas Alliance (BOGA)

Mark Brownstein

Environmental Defense Fund

Nick Butler

King’s College London

Michael Cohen

BP

Russell Conklin

US Department of Energy

Helen Currie

ConocoPhillips

Jonathan Elkind

Columbia University

Ronan Hodge

Glasgow Financial Alliance for Net Zero

Jan-Hein Jesse

JOSCO Energy Finance and Strategy Consultancy

Robert Kleinberg

Columbia University, United States

Ken Koyama

Institute of Energy Economics, Japan

Jim Krane

Baker Institute for Public Policy

Glada Lahn

Chatham House

Thomas-Olivier Léautier

TotalEnergies

Giel Linthorst

ING

Yvette Manolas

Woodside Energy

Antonio Merino Garcia

RepsolJulie Mulkerin

ChevronIsabel Murray

Department of Natural Resources, Canada

Julien Perez

Oil and Gas Climate Initiative

Stephanie Pfeifer

Institutional Investors Group on Climate Change

Amit Puri

Standard Chartered Bank

April Ross

ExxonMobil

Adnan Shihab Eldin

Independent expert

Wim Thomas

Independent consultant

6International Energy Agency | Special Report

Noé Van Hulst

International Partnership for Hydrogen and Fuel Cells
in the Economy

David Victor

UC San Diego School of Global Policy and Strategy

Claire Wang

U.S. Department of StatePeter Wood

Shell

Fareed Yasseen

Climate Envoy of the Republic of Iraq

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:
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

IEA. CC BY 4.0

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

Acknowledgements

7

Table of Contents
Foreword ................................................................................................................................. 3
Acknowledgements ................................................................................................................. 5
Executive summary ............................................................................................................... 131

Oil and gas in net zero transitions

19

1.1 Introduction................................................................................................... 20
1.2 The oil and gas industry today....................................................................... 21
1.3 Demand ......................................................................................................... 26
1.3.1 Oil ...................................................................................................... 26
1.3.2 Natural gas......................................................................................... 29
1.4 Supply ............................................................................................................ 33
1.4.1 Prices ................................................................................................. 33
1.4.2 Oil supply ........................................................................................... 34
1.4.3 Natural gas supply ............................................................................. 37
1.5 Refining and trade ......................................................................................... 41
1.5.1 Refining .............................................................................................. 41
1.5.2 Oil trade ............................................................................................. 43
1.5.3 Natural gas trade ............................................................................... 45
1.6 Alternative supply pathways in the NZE Scenario ......................................... 47
1.7 Investment .................................................................................................... 59
1.7.1 Risks from overinvestment ................................................................ 60
1.7.2 Risks from underinvestment.............................................................. 63
2

Technology options for the oil and gas industry

65

2.1 Introduction................................................................................................... 66
2.2 Traditional oil and gas operations ................................................................. 66
2.2.1 Current emissions from oil and gas operations ................................. 66
2.2.2 Emission reductions to 2050 by scenario .......................................... 70
2.2.3 Cutting methane and flaring .............................................................. 72
2.2.4 Boosting efficiency and electrifying oil and gas facilities................... 77
2.2.5 Reducing emissions from refining and LNG facilities ......................... 79
2.3 New technology options................................................................................ 86

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2.3.1 Carbon capture, utilisation and storage ............................................ 90
2.3.2 Low-emissions hydrogen and hydrogen-based fuels......................... 95
Table of Contents

92.3.3 Bioenergy ........................................................................................... 99
2.3.4 Offshore wind .................................................................................. 102
2.3.5 Geothermal...................................................................................... 105
2.3.6 Plastics recycling .............................................................................. 107
2.3.7 Electric vehicle charging .................................................................. 110
3Strategic responses of companies

113

3.1 Introduction................................................................................................. 114
3.2 The rising pressures on oil and gas companies ........................................... 114
3.2.1 Financial pressures .......................................................................... 114
3.2.2 Social, legal and political pressure ................................................... 116
3.2.3 Employment .................................................................................... 118
3.3 Oil and gas company responses to date ...................................................... 121
3.3.1 Targets to reduce scope 1 and 2 emissions ..................................... 121
3.3.2 Targets to diversify into clean energy technologies ........................ 125
3.4 What could net zero energy companies look like in 2050? ......................... 128
3.4.1 A net zero “major” energy company ............................................... 130
3.4.2 A liquids-focused national oil company ........................................... 132
3.4.3 An independent focused on gases ................................................... 135
3.5 Assessing alignment with net zero transitions ............................................ 137
3.5.1 Emissions from own operations ...................................................... 137
3.5.2 Investment in clean energy ............................................................. 139
3.6 Framework to assess the alignment of company targets with the NZE
Scenario ....................................................................................................... 144
3.6.1 Framework overview ....................................................................... 146
3.6.2 Scope 1 and 2 emissions reductions ................................................ 148
3.6.3 Investment in new oil and gas projects ........................................... 149
3.6.4 Investment in clean energy ............................................................. 150
3.6.5 Qualitative qualifiers ....................................................................... 150
4Strategic responses of exporters and importers

153

4.1 Introduction................................................................................................. 154

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4.2 Established producers ................................................................................. 155
4.2.1 Starting points ................................................................................. 155
4.2.2 Pitfalls facing producer economies.................................................. 158
10International Energy Agency | Special Report4.2.3 Impacts of net zero transitions ........................................................ 164
4.3 New producers ............................................................................................ 166
4.3.1 Starting points ................................................................................. 166
4.3.2 Impacts of net zero transitions ........................................................ 167
4.4 Building resilient net zero energy strategies ............................................... 170
4.4.1 Reduce emissions from traditional supplies .................................... 171
4.4.2 Put domestic energy systems on a cleaner footing ......................... 176
4.4.3 Develop new low-emissions products and value chains ................. 179
4.5 Working together to ensure equitable and just net zero pathways............ 186
4.5.1 Why should exporters and importers work together? .................... 186
4.5.2 How can exporters and importers work together? ......................... 190

Annexes
Annex A. Definitions............................................................................................................ 197

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Annex B. References ........................................................................................................... 217

Table of Contents

11

Executive Summary
A moment of truth is coming for the oil and gas industry
Structural changes in the energy sector are now moving fast enough to deliver a peak in oil
and gas demand by the end of this decade under today’s policy settings. After the peak,demand is not currently set to decline quickly enough to align with the Paris Agreement andthe 1.5 °C goal. But if governments deliver in full on their national energy and climate
pledges, then oil and gas demand would be 45% below today's level by 2050 and thetemperature rise could be limited to 1.7 °C. If governments successfully pursue a 1.5 °C
trajectory, and emissions from the global energy sector reach net zero by mid-century, oiland gas use would fall by 75% to 2050.
This new IEA report explores what oil and gas companies can do to accelerate net zerotransitions and what this might mean for an industry which currently provides more thanhalf of global energy supply and employs nearly 12 million workers worldwide. Since 2018,the annual revenues generated by the oil and gas industry have averaged close to USD 3.5
trillion. Around half of this went to governments, while 40% went back into investment and
10% was returned to shareholders or used to pay down debt. The implications of net zerotransitions are far from uniform: the industry encompasses a wide range of players, fromsmall, specialised operators to huge national oil companies (NOCs). While attention often
focuses on the role of the majors, which are seven large, international players, they hold lessthan 13% of global oil and gas production and reserves. NOCs account for more than half ofglobal production and close to 60% of the world’s oil and gas reserves.
The industry’s engagement with clean energy transitions will be a key topic at COP28, but
this report provides a reference for a debate that will continue well beyond the UN climate
summit in Dubai.

Most oil and gas companies are watching energy transitions from the sidelines
Oil and gas producers account for only 1% of total clean energy investment globally. Morethan 60% of this comes from just four companies, out of thousands of producers of oil andgas around the world today. For the moment the oil and gas industry as a whole is a marginalforce in the world’s transition to a clean energy system.

The first-order task is to slash emissions from company operations

IEA. CC BY 4.0

While there is no single blueprint for change, there is one element that can and should bein all company transition strategies: reducing emissions from the industry’s own
operations. As things stand, less than half of current global oil and gas output is produced bycompanies that have targets to reduce these emissions. A far broader coalition – with much
more ambitious targets – is needed to achieve meaningful reductions across the oil and gas
industry. The production, transport and processing of oil and gas results in just under 15% of
global energy-related greenhouse gas emissions. This is a huge amount, equivalent to allenergy-related greenhouse gas emissions from the United States.

Executive Summary13

To align with a 1.5 °C scenario, these emissions need to be cut by more than 60% by 2030
from today’s levels and the emissions intensity of global oil and gas operations must nearzero by the early 2040s. These are appropriate benchmarks for industry-wide action onemissions, regardless of the future scenario. The emissions intensity of the worst performers
is currently five- to ten-times higher than the best. Methane accounts for half of the total
emissions from oil and gas operations. Tackling methane leaks is a top priority and can bedone very cost-effectively – but it is not the only priority.

Transitions will hurt the bottom line for companies focused on oil and gas
The volatility of fossil fuel prices means that revenues could fluctuate from year to year –but the bottom line is that oil and gas becomes a less profitable and a riskier business as
net zero transitions accelerate. Prices and output are generally lower and the risk of
stranded assets is higher, especially in the midstream sector that includes refineries andfacilities for liquefied natural gas. If expectations are that demand and prices follow a
scenario based on today’s policy settings, that would value today’s private oil and gas
companies at around USD 6 trillion. If all national energy and climate goals are reached, thisvalue is lower by 25%, and by 60% if the world gets on track to limit global warming to 1.5 °C.
Oil and gas projects currently produce slightly higher returns on investment, but those
returns are less stable. We estimate that the return on capital employed in the oil and gas
industry averaged around 6-9% between 2010 and 2022, whereas it was 6% for clean energy
projects. Oil and gas returns varied greatly over time compared with more consistent returns
for clean energy projects.

Oil and gas investment is needed in all scenarios, but the demand trajectory
in a 1.5 °C world leaves no room for new fields
Continued investment in oil and gas supply is needed in all scenarios, but the
USD 800 billion it currently invests each year is double what is required in 2030 to meet
declining demand in a 1.5 °C scenario. Investment in existing and some new fields isnecessary in a world that achieves national energy and climate pledges, although there is noneed in aggregate for new exploration. In a scenario that hits global net zero emissions by
2050, declines in demand are sufficiently steep that no new long lead-time conventional oil
and gas projects are required. Some existing production would even need to be shut in. In
2040, more than 7 million barrels per day of oil production is pushed out of operation before
the end of its technical lifetime in a 1.5 °C scenario.

IEA. CC BY 4.0

In net zero transitions, new project developments face major commercial risks and could
also lock in emissions that push the world over the 1.5 °C threshold. Producers need to
explain how any new resource developments are viable within a global pathway to net zero
emissions by 2050 and be transparent about how they plan to avoid pushing this goal out ofreach.

14

International Energy Agency | Special ReportNot all producers can be the last ones standing
Many producers say they will be the ones to keep producing throughout transitions andbeyond. They cannot all be right. Oil and gas production is vastly reduced in net zerotransitions but does not disappear. Even in a 1.5 °C scenario, some 24 million barrels per dayof oil is produced in 2050 (three-quarters is used in sectors where the oil is not combusted,
notably in petrochemicals), as well as some 920 billion cubic metres of natural gas, roughly
half of which is used for hydrogen production.
The distribution of future supply among producers will depend on the weight assigned tolowering costs, ensuring diversity of supply, reducing emissions, and fostering economic
development. Market forces naturally favour the lowest-cost production, but that leads to ahigh concentration in supply among today’s major resource holders, notably in the Middle
East. Prioritising the least emissions-intensive sources drives progress towards climate goals,
but this often favours low-cost producers, so supply still becomes more concentrated. It ismuch better for transitions if all producers take targeted action to reduce their emissions. If
production from low-income producers is favoured, these projects may not ultimately bevery profitable in a well-supplied market. And if countries prefer domestically produced oil
and gas as a way to buttress energy security, they reduce reliance on others but risk finding
themselves with relatively high-cost projects in a low-price world.

The oil and gas industry is well placed to scale up some crucial technologies
for net zero transitions…
Some 30% of the energy consumed in a net zero energy system in 2050 comes from lowemissions fuels and technologies that could benefit from the skills and resources of the oiland gas industry. These include hydrogen and hydrogen-based fuels; carbon capture,utilisation and storage (CCUS); offshore wind; liquid biofuels; biomethane; and geothermalenergy. Oil and gas companies are already partners in a large share of planned hydrogenprojects that use CCUS and electrolysis. The oil and gas industry is involved in 90% of CCUS
capacity in operation around the world. CCUS and direct air capture are important
technologies for achieving net zero emissions, especially to tackle or offset emissions in hardto-abate sectors. For the moment, only around 2% of offshore wind capacity in operation
was developed by oil and gas companies. Plans are expanding, however, and the technology
frontier for offshore wind – including floating turbines in deeper waters – moves this sector
closer to areas of oil and gas company strength. In addition, industry skills and infrastructure,including existing retail networks and refineries, give the industry advantages in areas likeelectric vehicle charging and plastic recycling.

IEA. CC BY 4.0…but this requires a step-change in the industry’s allocation of investment
Companies that have announced a target to diversify their activities into clean energy
account for just under one-fifth of current oil and gas production. The oil and gas industry
invested around USD 20 billion in clean energy in 2022, some 2.5% of its total capitalspending. In this report, we offer a new framework for assessing the strategies of oil and gas
companies and the extent to which they are making a meaningful contribution to transitions.
Executive Summary

15

For producers that choose to diversify and are looking to align with the aims of the Paris
Agreement, our bottom-up analysis of cash flows in a 1.5 °C scenario suggests that areasonable ambition is for 50% of capital expenditures to go towards clean energy projects
by 2030, on top of the investment needed to reduce scope 1 and 2 emissions.
Not all oil and gas companies have to diversify into clean energy, but the alternative is towind down traditional operations over time. Some companies may take the view that their
specialisation is in oil and natural gas and so decide that – rather than risking money on
unfamiliar business areas – others are better placed to allocate this capital. But aligning theirstrategies with net zero transitions would then require them to scale back oil and gas
activities while investing in scope 1 and 2 emissions reductions.

Two pitfalls for the discussion about the future of oil and gas
A productive debate about the oil and gas industry in transitions needs to avoid two
common misconceptions. The first is that transitions can only be led by changes in demand.
“When the energy world changes, so will we” is not an adequate response to the immense
challenges at hand. An imbalanced focus on reducing supply is equally unproductive, as itcomes with a heightened risk of price spikes and market volatility. In practice, no one
committed to change should wait for someone else to move first. Successful, orderlytransitions are collaborative ones, in which suppliers work with consumers and governments
to expand new markets for low-emissions products and services.
The second is excessive expectations and reliance on CCUS. Carbon capture, utilisation andstorage is an essential technology for achieving net zero emissions in certain sectors andcircumstances, but it is not a way to retain the status quo. If oil and natural gas consumption
were to evolve as projected under today’s policy settings, this would require aninconceivable 32 billion tonnes of carbon captured for utilisation or storage by 2050,
including 23 billion tonnes via direct air capture to limit the temperature rise to 1.5 °C. The
necessary carbon capture technologies would require 26 000 terawatt hours of electricity
generation to operate in 2050, which is more than global electricity demand in 2022. And it
would require over USD 3.5 trillion in annual investments all the way from today through to
mid-century, which is an amount equal to the entire industry’s annual average revenue inrecent years.

IEA. CC BY 4.0

Producer economies face major uncertainties, but their energy advantages
are not lost in transition
Economies that are heavily reliant on oil and gas revenues face some stark choices andpressures in energy transitions. These choices are not new, but the prospect of falling oil
and gas demand adds a timeline and a deadline to the process of economic diversification.
Transitions create powerful incentives to accelerate the pace of change while also draining asource of revenue that could finance it. Compared with the annual average between 2010
and 2022, per capita net income from oil and natural gas among producer economies is 60%
lower in 2030 in a 1.5 °C scenario. New producers entering the market face additional
challenges, as they may overestimate the bounty that might lie ahead and underestimate
16

International Energy Agency | Special Reportthe hazards. Many producers are also heavily exposed to risks from a changing climate, which
stand to further disrupt the security of energy supply.
The challenges are formidable, but there are workable net zero energy strategies available
to producer economies and national oil companies. Today’s producer economies retain
energy advantages even as the world moves away from fossil fuels. In most cases, today’s
major producers of low-cost hydrocarbons also have expertise and ample, under-utilised
renewable energy resources that could anchor positions in clean energy value chains andlow-emissions industries. Reducing emissions from traditional supplies, including end-use
emissions; putting domestic energy systems on a cleaner footing by phasing out inefficientsubsidies and boosting clean energy deployment; and developing low-emissions products
and services offer a way forward.

Will the oil and gas industry be part of the solution?
Our scenarios plot out how the transition could be achieved, but the baseline expectation
should be for a volatile and bumpy ride. Declining markets are difficult to plan for, and thepotential for disruption also comes from geopolitical tensions and increased incidences ofextreme weather. Governments need to be vigilant for risks to the affordability and securityof supply. The implications of any physical disruptions to supply are felt most strongly inemerging and developing economies in Asia, whose share of global crude oil imports rises
from 40% today to 60% in 2050 in a scenario that meets national energy and climate goals.
On the supply side, even as overall demand falls back, the Middle East plays an outsize rolein global markets as a low-cost producer of both oil and gas.

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Dialogue across all parts of oil and gas value chains remains essential to deliver an orderly
shift away from fossil fuels – and to ensure that today’s producers have a meaningful stakein the clean energy economy. The industry must change, but this dialogue also needs clear
signals from consumers on the direction and speed of travel to guide investment decisions,to assign value to oil and gas with lower emissions intensities, to develop markets for lowemissions fuels, and to collaborate on technology innovation. Energy transitions can happen
without the engagement of the oil and gas industry, but the journey to net zero will be morecostly and difficult to navigate if they are not on board.

Executive Summary

17

Chapter 1
Oil and gas in net zero transitions
S U M M A R Y• Around 97 mb/d of oil and 4 150 bcm of natural gas were consumed globally in 2022.

This resulted in just over 18 Gt CO2 emissions, around half of total energy-related CO2
emissions. Recent momentum in deploying clean energy technologies means that oil
and gas demand peak before 2030 in the Stated Policies Scenario (STEPS), but the
declines after these peaks are not steep enough to achieve the world’s climate goals.

• Net zero transitions require a huge acceleration in clean energy technology

deployment and faster reductions in oil and gas use. In the Announced Pledges
Scenario (APS), oil and gas demand decline by around 2% each year on average to 2050
(to 55 mb/d and 2 400 bcm) and in the Net Zero Emissions by 2050 (NZE) Scenario
they fall by more than 5% each year on average to 2050 (to 24 mb/d and 920 bcm).

• Attention on the oil and gas industry often focuses on the large international oil andgas companies (the “majors”), but they own less than 13% of global oil and gas
production and reserves. By comparison, national oil companies own more than halfof production and close to 60% of reserves.

• Major challenges lie ahead for midstream infrastructure in net zero transitions. The

refining sector reduces its output of traditional products like gasoline and diesel, andfocuses more on petrochemical feedstocks and products like asphalt and bitumen.
Global liquefied natural gas (LNG) trade sees strong near-term growth, but trade
peaks in the APS before 2035 and the utilisation of export terminals drops; in the
NZE Scenario, demand for LNG can be met in aggregate by plants already in operation.

• In the APS and NZE Scenario, investment in existing oil and gas assets continues, butwith very different outcomes for new project development. In the APS, new oil andgas projects are needed, although in aggregate there would be no need for further oil
and gas exploration. In the NZE Scenario, falling demand means that no new long leadtime conventional oil and gas projects are approved for development and, after 2030,
a number of projects are closed before they reach the end of their technical lifetime.

• Many producers have set out why they think their resources should be preferred fordevelopment in net zero transitions. Some say that they have the lowest production
costs or emission intensities; others claim that they are a better option for energy
security; and some indicate that new oil and gas developments are needed to improvewelfare. In the demand environment of the NZE Scenario, any new oil and gas
resource developments would need to be matched by production reductions
elsewhere to avoid oversupply and fossil fuel lock-in.

• Both over- and underinvestment in fossil fuels carry risks for secure and affordable

IEA. CC BY 4.0

transitions. Sequencing the decline in oil and gas investment and the increase in clean
energy investment is vital to avoid damaging price spikes or supply gluts. At present,risks appear to be weighted more towards overinvestment than the opposite.

Chapter 1 | Oil and gas in net zero transitions

19

1.1

Introduction

This report explores the outlook for oil and natural gas producers in net zero transitions. Oiland gas account for around half of today’s global energy supply, providing valuable energy
services to consumers around the world but also resulting in over 18 Gt CO2 emissions. Someof the services provided by oil and gas can be replaced with relative ease by clean energy
technologies, as witnessed by the rise of electric vehicles (EVs) and renewable sources ofpower generation. Others are more difficult to replace, such as seasonal balancing for powersystems in the case of gas, or long-distance air travel in the case of oil. The position of oil andgas in the energy mix will not be transformed overnight. But it has to change, and change
dramatically, if the world is to avoid severe damage from a changing climate. This analysis
examines the contours and implications of such a process. With the United Arab Emirates
hosting COP28, 2023 is a critical year for oil and gas companies and producer economies todevelop and justify strong and credible narratives about the role they intend to play.
The two main scenarios examined in this report are the Announced Pledges Scenario (APS)
and the Net Zero Emissions by 2050 (NZE) Scenario. These scenarios set out what transition
pathways aligned with regional or global net zero targets would mean for oil and gas
companies and producer economies. They both require a significant acceleration in the paceof change compared with today's trends, which are reflected in the Stated Policies Scenario(STEPS). The report includes metrics, based on our scenarios, that allow stakeholders to makeinformed decisions on whether producers are making genuine efforts to adapt businessmodels at the necessary pace and scale.

IEA. CC BY 4.0

This chapter discusses the outlook for oil and natural gas demand and supply in net zerotransitions. Chapter 2 sets out the technology options for the oil and gas industry, including
options to cut emissions from its own operations, and the clean energy technologies thatappear best suited to its existing skills and resources. Chapter 3 sets out some of the strategic
responses of oil and gas producers to date and explores what the industry would need to do
to align with net zero transitions. And Chapter 4 focuses on producer economies, examining
how they can adapt to a changing energy system and how producers and consumers canwork together to achieve fair, net zero aligned transition pathways.
The remainder of this chapter is structured as follows: Section 1.2 provides an overview ofthe structure of the oil and gas industry, highlighting the contribution of different types ofcompanies to supply and investment trends. Section 1.3 examines oil and gas demand in the
APS and NZE Scenario, including the main levers used to reduce demand, and where oil andgas use is most resilient. Section 1.4 describes the oil and gas price trajectories and how
production evolves by region in net zero transitions. Section 1.5 examines the implications
for oil refining and oil and gas trade. Section 1.6 explores alternative supply pathways that
could be possible with the same overall demand trajectory of the NZE Scenario, highlighting
potential upsides and downsides and how different supply-side dynamics might play out inpractice. Finally, Section 1.7 examines the implications for investment, including the risks
posed by overinvestment or underinvestment in oil and gas during net zero transitions.
20

International Energy Agency | Special Report1.2

The oil and gas industry today

There are thousands of companies around the world that produce oil and gas today. The
industry is characterised by a wide variety of corporate structures and governance models,
ranging from small businesses to some of the world’s largest industrial corporations. The top
fifty companies produce around 70% of total supply. For this report, we distinguish between
four main types of company:


Majors are large companies listed on stock markets in the United States and Europe.
They have historically focused on developing large, capital-intensive projects and their
upstream divisions represent most of their financial value and revenue. In this report,
this group comprises seven companies: BP, ConocoPhillips, Chevron, Eni, ExxonMobil,
Shell, and TotalEnergies.

Independents are smaller fully integrated companies or independent upstream
operators. They encompass a wide range of companies, such as Lukoil, Repsol, OMV andWoodside, as well as many North American companies – including shale gas and tightoil players – such as Apache, Hess, Marathon Oil, Pioneer Natural Resources and Oxy,and diversified international conglomerates with upstream activities, such as Mitsubishi
Corp.



National oil companies (NOCs) have been given mandates by their home governments
to exploit national resources and have a legally defined role in upstream development.
While some NOCs operate outside their home country and are also active downstream,
the bulk of their assets are based in their home country’s upstream operations. Most of
the largest NOCs are located in the Middle East, such as Saudi Aramco, National Iranian
Oil Company, Kuwait Petroleum Corporation, Abu Dhabi National Oil Company and
QatarEnergy. There are also NOCs in Eurasia, including in Russia, in Latin America andmany parts of Africa and Asia (see Chapter 3 for further details).

International national oil companies (INOCs) share similarities with NOCs in theirownership and governance, but have substantial upstream investments outside theirhome country. This is usually done in collaboration with host NOCs or privatecompanies. Some INOCs are also major players in the global gas markets. They include
Equinor, China National Petroleum Corporation, Gazprom, Petronas and India’s Oil andNatural Gas Corporation.

IEA. CC BY 4.0

In addition to these categories, other types of company play a key role in the oil and gas
industry. They include:Service companies that provide specialist engineering services for drilling, reservoir
management, construction of infrastructure, and environmental impact management(e.g. SLB and Baker Hughes).



Pure downstream companies that operate refinery and petrochemical sites(e.g. Marathon Petroleum, Phillips 66, Essar, Reliance and Valero).

Chapter 1 | Oil and gas in net zero transitions

21

1



Trading companies whose business models tend to rely on owning only those physicalassets that help optimise their position in the market (e.g. Vitol, Mercuria, Glencore andGunvor).



Midstream operators of pipeline systems (e.g. Enagas, Enbridge, TC Energy, Enterprise
Products Partners and Kinder Morgan).



Shipping companies operating tankers and LNG carriers (e.g. Maersk, Teekay, Euronav,
Frontline and Mitsui).

Storage companies that manage and lease tank capacity for crude and products(e.g. VTTI and OilTanking).

Retail companies that buy product directly from refiners or from traders in the local orinternational market (e.g. Couche-Tard, Kroger and Avia).

Attention on the oil and gas industry often focuses on the role of the majors, but they own
less than 13% of global oil and gas production and proved-plus-probable (2P) reserves(Figure 1.1). NOCs and INOCs account for more than half of global production and close to
60% of the world’s oil and gas reserves. Their share of capital investment in upstream oil andgas projects is slightly lower, at around 45% of the global total. This is partly because theytend to own resources with lower-than-average development costs and partly because theirassets tend to have slow decline rates, meaning lower levels of spending are required tomaintain production.
Figure 1.1 ⊳Ownership of oil and gas reserves, production and upstream
investment by company type, 2022
Natural gas

Oil

100%
80%
60%
40%
20%
Reserves
Majors

Production Investment
Independents

Reserves

Production Investment

INOCs

NOCs
IEA. CC BY 4.0.

IEA. CC BY 4.0

NOCs, including those with operations outside their home country, produce more than halfof the world’s oil and gas. The majors produce 13% of the total.
Note: INOCs = International national oil companies; NOCs = National oil companies.
Source: IEA analysis based on Rystad Energy.

22International Energy Agency | Special ReportPartnerships and joint ventures are prevalent across the oil and gas industry. Exploration andnew field development are risky and complex processes, and companies often split theownership of any discovery or development to spread the risk and reward and to encouragetechnical and operational collaboration. Joint ventures mean the financial engagement andinfluence of companies can spread further than the oil and gas assets that they directly
operate. For example, of the oil and gas produced in 2022, the majors owned 20 million
barrels of oil equivalent per day (mboe/d) and operated assets that produced 23 mboe/d;nearly three times as much oil and gas (60 mboe/d) was produced from assets in which theyown more than 5% of production (Figure 1.2).

mboe/dFigure 1.2 ⊳Oil and gas production in 2022 by ownership, operator, and fromassets in which companies have an equity stake greater than 5%100

Equity share > 5%
Operated

80

Owned

60
40
20

MajorsIndependents

INOCs

NOCs
IEA. CC BY 4.0.

Companies’ production includes oil and gas from both operated and non-operated assets,
but the influence of companies can extend well beyond this.
Note: Equity share > 5% = total production from all assets in which a company holds at least a 5% share of the
produced oil and gas.

IEA. CC BY 4.0

Mergers and acquisitions are common in the oil and gas industry, with more than
USD 200 billion worth of deals taking place annually on average between 2018 and 2022.
These are used by companies to expand oil and gas production, diversify into new markets,
acquire new technologies, benefit from economies of scale, and to increase clean energy
holdings. The oil and gas industry spent around USD 15 billion acquiring clean energy
ventures in 2022, around 10% of the total value of its mergers and acquisitions in that year.
A number of major deals have also taken place in 2023, including the purchase of US shale
independent Pioneer Resources by ExxonMobil for USD 60 billion and the purchase of Hess
Corporation for USD 53 billion by Chevron.

Chapter 1 | Oil and gas in net zero transitions

23

1

The global oil and gas industry generated close to USD 3.5 trillion in revenue on average eachyear between 2018 and 2022 (Figure 1.3). This includes revenue from crude oil and natural
gas production as well as the additional value created from processing, refining, transportingand marketing the final products to consumers. There is a high degree of year-on-year
variation in this figure, ranging from a low of USD 2 trillion in 2020, given the impacts of theCovid-19 pandemic, to a historic record high of USD 5 trillion in 2022 during the global
energy crisis.

Trillion USD (2022, MER)

Figure 1.3 ⊳Use of revenue by the oil and gas industry, 2018-2022

5

Other:
Returns to shareholders
and debt payments
Operating costs

4

Capital expenditure:3

Clean
Midstream

2

Upstream
Government take:1

NOC domestic income
Taxes
2018

2019

2020

2021

2022
IEA. CC BY 4.0.

The oil and gas industry has generated around USD 17 trillion of revenue since 2018. Half
was paid to governments and 40% was spent developing and operating oil and gas assets.
Note: NOC domestic income = National Oil Company income generated in their home country.

IEA. CC BY 4.0

Around 50% of the revenue produced by the oil and gas industry since 2018 went togovernments, either from royalties and taxes or from income generated by NOCs and INOCs
in their home countries. A further 40% was capital and operating expenditure, and theremaining 10% was returned to shareholders through dividends and share buybacks or used
to pay down debt.
Companies have responded to the prospect of net zero transitions with a range of strategies.
The most common approaches are to reweight overall production towards natural gas,demand for which is perceived to be more durable through net zero transitions, and to takesteps to reduce emissions from operations. Some companies have diversified their capital
expenditure more substantially, moving into clean energy technology areas such as offshorewind, carbon capture, utilisation and storage (CCUS), low-emissions fuels, and electricity. Oiland gas companies with the largest proportions spent around 15-25% of their total capitalbudgets on clean energy in 2022 through mergers and acquisitions, joint ventures and direct
investment. As a whole, the industry spent around USD 20 billion on clean energy,
24International Energy Agency | Special Reportrepresenting less than 3% of its total capital budget and around 1% of total clean energy
investment globally. For the moment, the oil and gas industry remains a marginal force indirectly building up a clean energy system (see Chapter 3).
Scenarios examined in this reportBox 1.1 ⊳Three scenarios provide a framework for the analysis in this report (Figure 1.4). These
scenarios have been fully updated to reflect the latest economic and energy data and aredescribed in detail in the World Energy Outlook 2023 (IEA, 2023a). Rates of economic
growth – 2.6% on average globally each year to 2050 – and population growth are thesame across the scenarios. We focus our analysis mainly on the APS and the NZE Scenario,
which achieve net zero transitions for the energy sector at different speeds.

40

Energy-related CO2 emissions and total energy supply by
scenario
CO₂ emissions
EJ

Gt CO₂

Figure 1.4 ⊳

800

30

600

20

400

10

200

2010

2020

2030

2040
STEPS

2050

2010
APS

Total energy supply

2020

2030

2040

2050

NZE
IEA. CC BY 4.0.

Our scenarios paint very different pictures for the future of emissions and energy.

IEA. CC BY 4.0

The Stated Policies Scenario (STEPS) looks at what governments are actually doing rather
than what they say they will achieve. It is an outlook based on a detailed sector-by-sector
review of energy and climate policies and measures currently in place or underdevelopment by governments. In this scenario, each of the fossil fuels has a peak indemand before 2030, but declines after these peaks are relatively muted. Annual CO2
emissions are 20% below 2022 levels in 2050 and these trends are consistent with atemperature rise of around 2.4 °C in 2100 (with a 50% probability).
The Announced Pledges Scenario (APS) assumes that governments meet all of theclimate‐related commitments they have announced in full and on time. Pledges made bycompanies, businesses and industry organisations are also taken into account.
Energy-related CO2 emissions soon peak and they are around 70% lower than 2022 levels
Chapter 1 | Oil and gas in net zero transitions25

1

in 2050. There are also major reductions in all other energy-related greenhouse gas(GHG) emissions, including methane from fossil fuel operations. This pathway isconsistent with a temperature rise of 1.7 °C in 2100 (with a 50% probability).
The Net Zero Emissions by 2050 (NZE) Scenario describes a pathway for the global energy
sector to reach net zero CO2 emissions by 2050 without offsets from land-use measures.
Advanced economies reach net zero emissions earlier than emerging market anddeveloping economies, and universal access to electricity and clean cooking is achievedby 2030. There are also efforts to cut down on methane and other GHG emissions. The
global average surface temperature rise peaks at just below 1.6 °C around 2040 and thengradually falls to 1.4 °C in 2100 (with a 50% probability).

1.3

Demand

1.3.1

Oil

Global oil demand increased by just over 1 mb/d on average each year between 2010 and2019. The Covid-19 pandemic caused a 9 mb/d drop in oil demand in 2020, the largest annual
drop in history, but demand has since rebounded and it stood at 96.5 mb/d in 2022. Oilprovides a large range of the energy service demands required by society, including, forexample, about 25 trillion passenger kilometres in cars, 30 trillion tonne kilometres fortrucks, 320 million tonnes of high-value chemicals, and many other outputs.
In the STEPS, oil demand reaches a maximum level of 102 mb/d in the late 2020s before
declining to 97 mb/d in 2050. There are large declines in oil use in cars, buildings and power
generation, although most of this is offset by growth in oil use in trucks, aviation andpetrochemicals.

IEA. CC BY 4.0

Net zero transitions require replacing existing uses of oil and gas and satisfying the growth inenergy service demands in a low-emissions way. In the APS, oil demand soon peaks anddeclines to 93 mb/d in 2030 and 55 mb/d in 2050. In the NZE Scenario, demand falls to77 mb/d in 2030 and 24 mb/d in 2050 (Figure 1.5).
Road transport. Almost half of global oil use is currently in road transport, but this is underincreasing pressure from the rise of electric vehicles (EVs). The EV market has been growing
exponentially in recent years, and nearly 20% of new cars being sold globally in 2023 areelectric. In the APS, the share of electric car sales rises to nearly 45% in 2030 and 80% in
2050, reflecting electrification ambitions announced by governments, including acommitment by more than 40 governments to accelerate the transition to zero-emission carsand vans, as well as a major scale-up in EV manufacturing hubs around the world thatencourages consumers to choose to buy a domestically manufactured EV over an internal
combustion engine (ICE) car. Electric and hydrogen heavy truck sales grow from 1% today tojust under 20% of total sales in 2030 and 60% in 2050.
26

International Energy Agency | Special ReportFigure 1.5 ⊳Historical

APS

STEPS

NZE

1

mb/d

120

Oil demand by scenario, 2000-2050

90
60
30

2000
2022 2022
Cars and vans Heavy trucks
Power
Feedstock

2050 2022
Aviation
Other industry

2050
2050 2022
Shipping
Buildings
Other
IEA. CC BY 4.0.

Road transport accounts for almost half of oil demand today and sees the largest changes
to 2050. Oil use for petrochemicals is much more robust despite increases in recycling.
Notes: Other includes buses, 2/3 wheelers, agriculture, other energy sector, and other non-energy use.

In the NZE Scenario, virtually no new ICE cars are sold from 2035, and all new trucks use
electricity or hydrogen from 2040 in advanced economies and China, and from 2045 in therest of emerging market and developing economies. To 2030, 20% of the overall reductionin oil demand comes from electrifying road transport (Figure 1.6). A further 5% of the
reduction comes from behavioural change measures in road transport, including throughimprovements to public transport coverage and quality, and encouraging walking andcycling, car sharing and carpooling. By 2050, 1.5 billion of the 1.6 billion cars on the road areelectric, and 140 million out of 180 million heavy-duty trucks and buses on the road areelectric.

IEA. CC BY 4.0

Aviation. Around 5 mb/d of oil was used in domestic and international aviation in 2022, a
substantial increase from levels in 2021, but still far below the levels seen before theCovid-19 pandemic. Low-emissions fuels – including liquid biofuels and low-emissionshydrogen-based liquids – comprise less than 0.01% of the fuel used in aviation today. In the
APS this share grows to 5% in 2030 and to over 35% in 2050, driven by government ambitionsin the United States, the European Union, the United Kingdom and Japan, alongside industry
initiatives. In the NZE Scenario, low-emissions fuels provide around three-quarters of fueluse in 2050. Behavioural changes – stemming from greater use of high-speed rail, fewer
business flights, and frequent flyer levies – avoid 0.6 mb/d of oil demand in aviation in 2050
in the NZE Scenario.

Chapter 1 | Oil and gas in net zero transitions

27

Shipping. Around 5 mb/d of oil is consumed by ships annually, with a very small share ofoverall fuel use from low-emissions fuels (0.2% as biodiesel). In the APS this share grows toover 50% in 2050, mainly as a result of efforts to achieve the target set by the International
Maritime Organization (IMO) to reduce emissions from maritime transport by at least half by
2050.1 In the NZE Scenario, increases are even larger and 85% of the fuel used by the world’s
shipping fleet in 2050 comprises low-emissions fuels, predominantly hydrogen andhydrogen-based fuels.

mb/dFigure 1.6 ⊳Reductions in oil demand in the APS and NZE Scenario

100

APS

NZE
Wind and solar
Electrification

80

Low-emissions fuels
Energy efficiency

60

Avoided demand40

Behavioural change
Other

20

2022

2030

2050

2022

2030

2050
IEA. CC BY 4.0.

The electrification of cars and trucks makes the largest contribution to reducing oil use, withefficiency improvements and low-emissions fuels also playing an important role.
Notes: Avoided demand = material efficiency, reductions in oil use in refineries from lower demand, and otherstructural and economic effects. Other = hydropower, geothermal, nuclear, district heating, and natural gas.

Petrochemical feedstocks. Around 14 mb/d of oil was used as a feedstock in 2022, mainly to
produce plastics. Demand for virgin plastics is set to grow rapidly, even though a number ofpolicies to ban or reduce single-use plastics, improve recycling rates and promote alternative
feedstocks have been announced. In the APS, these policies increase the global averagecollection rates for plastic waste from 16% today to 37% in 2050; despite this increase, oil
use as feedstock still increases by 0.6 mb/d to 2030 and then only declines slightly to 2050.
The use of alternative feedstocks, including bio-based feedstock, remains a niche industry
due to a considerable cost gap and competing demand with other sectors. In the
NZE Scenario, the global average plastics collection rate increases to 50% in 2050 and,combined with an increase in the use of alternative feedstocks, this means oil use as apetrochemical feedstock peaks in the mid-2030s and declines to around 13.5 mb/d in 2050.

IEA. CC BY 4.0

1 In July 2023 the IMO adopted a revised version of its GHG emissions strategy that looks to achieve net zero

emissions from international shipping by 2050. Enforcement mechanisms are yet to be decided and so this is
not included in the APS.

28

International Energy Agency | Special ReportEfficiency improvements also play a role in all end uses to reduce oil demand. In the
NZE Scenario, oil use in buildings is eliminated by electrification of heating and cooking
appliances, even as liquefied petroleum gas (LPG) is used as an intermediary solution toprovide full access to clean cooking; oil demand to produce power is replaced with solar andwind generation.
Oil demand and CO2 emissions from oil use in the NZE Scenario,
2050

25

Gt CO₂mb/dFigure 1.7 ⊳

20
15

1.0

Other
Energy sector own use

0.8

Cars and vans
Buildings

0.6

Shipping
10

0.4

5

0.2

TrucksAviation
Other non-energy use
Petrochemical feedstock

DemandCO₂ emissions
IEA. CC BY 4.0.

Three-quarters of the oil used in 2050 is in sectors where it is not combusted. Around
0.8 Gt CO2 is emitted from oil use in 2050, mainly from aviation and trucks.
Note: Other non-energy use includes products not used in energy applications such as paraffin waxes, asphalt
and bitumen.

Oil demand of 24 mb/d remains in 2050 in the NZE Scenario, one-quarter of the 2022 level.
Three-quarters of this is used in sectors where the oil is not combusted, including as apetrochemical feedstock, and in products such as paraffin waxes, asphalt and bitumen(Figure 1.7). The remainder is combusted and this results in around 0.8 Gt CO2 emissions in
2050. This is mainly in the remaining diesel trucks on the road and from aviation, which areeach responsible for around 200 Mt CO2 in 2050, as well as from shipping at 110 Mt CO2.
These residual emissions are offset from within the energy sector through the use of direct
air capture with CCUS (DACS) and bioenergy with CCUS (BECCS).

IEA. CC BY 4.0

1.3.2

Natural gas

Natural gas markets were upended by Russia’s invasion of Ukraine. The sharp reduction inpipeline supply to Europe tightened global gas markets, resulting in record high prices and adrop in global demand of around 1% in 2022. Europe registered a record 13% fall in natural
gas demand. Aggregate demand in emerging markets in Asia, the past engine of global gas
Chapter 1 | Oil and gas in net zero transitions

29

1

demand growth, fell for the first time ever, as the spikes in global prices shook confidence ingas as an affordable alternative to coal or oil. Prices have moderated in 2023 and are
expected to come under downward pressure in the second half of the 2020s as a large newwave of LNG export facilities starts operation. There is still significant scope for demand
growth this decade, notably in industry, despite the near‐term risks brought about by the
supply squeeze. Nonetheless, increasingly cost-competitive low-emissions options for power
generation and heating – alongside increased climate ambitions among many emerging
market and developing economies in Asia – raise major questions about the long-term
outlook for natural gas demand.
Figure 1.8 ⊳Historical

APS

STEPS

NZE

bcm

5 000

Natural gas demand by scenario, 2000-2050

4 000
3 000
2 000
1 000
2000
Power

2022 2022
Industry

Buildings

2050 2022

2050 2022

Low-emissions hydrogen

Transport

2050
Other
IEA. CC BY 4.0.

Gas demand declines steadily in the APS, with the largest reductions being in buildings andpower. In the NZE Scenario there is little to no room for gas to act as a transition fuel.

IEA. CC BY 4.0

Global natural gas demand in 2022 was around 4 150 bcm, 40% of which was consumed in
the power sector, and around 20% in each of buildings and industry. In the STEPS, natural
gas demand growth to 2030 is considerably lower than the 2.2% seen on average between
2010 and 2021. Demand peaks before 2030, after which moderate growth in some emerging
market and developing economies is offset by declines in advanced economies, resulting in
relatively stable demand globally between 2030 and 2050.
In the APS, global natural gas demand soon peaks and by 2030 is nearly 10% lower than in
2022 (Figure 1.8). A modest net increase in demand in emerging market and developing
economies between 2022 and 2030 is more than offset by reductions in advanced
economies, where gas is gradually replaced by renewables and offset by efficiency gains,notably in the buildings sector. In the NZE Scenario, natural gas falls rapidly in all sectors anddemand is 20% lower in 2030 than in 2022. There are several factors that contribute to a
reduction in natural gas demand over time:
30

International Energy Agency | Special ReportRenewables. Annual wind and solar capacity additions reach 500 gigawatts (GW) by 2030 in
the STEPS, 900 GW in the APS and 1 150 GW in the NZE Scenario. Each gigawatt of installed
renewable capacity can displace anywhere in the range of 200-800 million cubic metres (m3)of natural gas in the power sector. The installed capacity of gas-fired power plants falls lessquickly than overall generation because some capacity is either added or retained forflexibility purposes in both the APS and NZE Scenario. Leaving gas plants on the system isoften necessary to support a renewables-rich grid, especially to manage seasonal variations
in demand; this requires an appropriate market design to remunerate balancing services.

bcm

Figure 1.9 ⊳4 500

Reductions in natural gas demand in the APS and NZE Scenario
APS

NZE
Wind and solar
Electrification
Low-emissions fuels

3 000

Energy efficiency
Other

1 500

2022

2030

2050

2022

2030

2050
IEA. CC BY 4.0.

Wind and solar play essential roles in reducing natural gas demand in the power sector. A
wide range of other fuels and technologies are needed to reduce gas use in other sectors.
Note: Other = nuclear and other renewables.

IEA. CC BY 4.0

Bioenergy. Around 30 bcm of natural gas is replaced by the use of biomethane in 2050 in the
STEPS, compared with 75 bcm in the APS and 110 bcm in the NZE Scenario, primarily to serve
remaining energy service demands met by gaseous fuels in buildings. Biomethane is sourced
from organic wastes, residues and other feedstocks that do not compete with food or have
harmful effects on biodiversity. Large volumes of natural gas are also displaced by modern
solid bioenergy in industry, buildings and for power generation.
Electrification. Around 140 bcm of natural gas is displaced through end-use electrification by
2050 in the STEPS, 300 bcm in the APS and 600 bcm in the NZE Scenario (Figure 1.9). Of thetotal in the NZE Scenario, around 50% is displaced by the use of electric motors in place ofgas turbines in industrial facilities that require low-temperature heat, and another 40% is
displaced by heat pumps in households, commercial buildings and small-scale industry.
Electricity use for cooking and hot water – along with the use of modern bioenergy – enables
households to eliminate natural gas use by 2050 in the NZE Scenario. EVs also replace most
Chapter 1 | Oil and gas in net zero transitions

31

1

compressed natural gas vehicles on the road, reducing the need for around 60 bcm of natural
gas in the NZE Scenario in 2050.
Other efficiency measures. Improvements in the energy efficiency performance of buildings
helps to reduce gas use. Around 1.5% of buildings are currently being retrofitted to thehighest performance standards each year in advanced economies; this rises to nearly 2% by
2030 in the APS and 2.5% in the NZE Scenario. More efficient gas-fired power plants are
employed in both the APS and NZE Scenario, which also help to avoid some gas use.
There is 920 bcm of natural gas use remaining in 2050 in the NZE Scenario, around
one-quarter of the level today (Figure 1.10). Natural gas is completely phased out inbuildings, and its role in power generation is confined to dispatchable balancing; this requires
around 100 bcm per year, or 95% less than the total amount of gas used in the power sector
today. Around 60% of natural gas in 2050 is consumed in facilities equipped with CCUS. wA
further 180 bcm is used as a feedstock or for other non-combustion purposes. Overall,
average combustion emissions from natural gas fall from 1.8 kg CO2/m3 today to
0.3 kg CO2/m3 by 2050.

1 000

Gt CO₂bcm

Figure 1.10 ⊳ Remaining natural gas demand in 2050 in the NZE Scenario, 2050
0.5

800

0.4

600

0.3

400

0.2

200

0.1

Merchant hydrogen production
Power sector
Oil and gas extraction
Chemicals
Other non-energy use
Non-metallic minerals
Transport and other own use
Iron and steel
Remaining industry
Other

DemandCO₂ emissions
IEA. CC BY 4.0.

Around 920 bcm of natural gas demand remains in the NZE Scenario in 2050, 75% lower
than in 2022. The emissions intensity of this gas drops by 85%.

IEA. CC BY 4.0

Note: The use of natural gas to produce on-site hydrogen is included in chemicals and iron and steel.

32

International Energy Agency | Special Report

1.4

Supply1.4.1

PricesIn our scenarios, oil and natural gas prices act as intermediaries between supply and demand
to ensure that sources of supply meet changes in demand and hold the system in equilibrium.
This balancing act means prices in our scenarios follow a relatively smooth trajectory; we do
not attempt to anticipate the fluctuations or price cycles that characterise commodity
markets. In practice, the potential for oil and gas price volatility is ever present, especiallyconsidering the profound changes that are needed in today’s energy system to meet theworld’s climate goals.
In the APS, the policy focus on curbing oil and gas demand brings the prices at which themarket finds equilibrium down from the levels in 2022: the international oil price falls toaround USD 60/barrel in 2050 while gas prices in key importing regions remain in a bandaround USD 5-6 per million British thermal units (MBtu) (Table 1.1).
In the NZE Scenario, oil and gas prices quickly fall to the operating costs of the marginal
project required to meet falling demand, and in 2050 they are around USD 25/barrel for oiland USD 2-5/MBtu for natural gas. These prices cover the operating expenses to lift oil andgas out of the ground of the marginal producer, the capital expenditure and operating costsof the required emissions reduction technologies, and upstream taxes.
Table 1.1 ⊳Oil and natural gas prices by scenario
STEPS
2030 2050

APS
2030 2050

NZE scenario
2030 2050

Real terms (USD 2022)

2010

2022

IEA crude oil (USD/barrel)

103

98

85

83

74

60

42

25

Natural gas (USD/MBtu)
United States

5.8

5.1

4.0

4.3

3.2

2.2

2.4

2.0

European Union

9.9

32.3

6.9

7.1

6.5

5.4

4.3

4.1

China

8.8

13.7

8.4

7.7

7.8

6.3

5.9

5.3

Japan

14.6

15.9

9.4

7.8

8.3

6.3

5.5

5.3

IEA. CC BY 4.0

Other price trajectories are possible, even while maintaining the overall demand trajectories
in the APS and NZE Scenario. For example, moves on the part of producer economies withthe lowest production costs to gain market share even as demand declines would likely leadto lower prices, at least for an initial period (see Section 1.6). Lower prices could also occur
in the case of overinvestment in oil and gas supply. In this case, projects would face evenlarger commercial risks, producer economies would face further headwinds, and it would risk
pushing the 1.5 °C goal out of reach (see Section 1.7).
Higher price trajectories could occur if there are widespread efforts by large producers to
restrict production. For example, in the NZE Scenario, the oil market share of theOrganization of the Petroleum Exporting Countries (OPEC) rises from 36% in 2022 to 53% in
Chapter 1 | Oil and gas in net zero transitions

33

1

2050. Production cuts could lead to large prices increases, especially as demand in the APS
and NZE Scenario becomes increasingly concentrated in sectors with few alternatives(e.g. the aviation and petrochemical sectors). However, in the NZE Scenario, low prices anddemand mean around 7 mb/d worth of projects would need to close by 2040 before the endof their technical lifetimes. Any efforts to drive up prices by restricting supply would likely
mean this overhang stays on the market for longer, muting the overall magnitude of theprice rise.
Another possibility that could lead to higher and more volatile prices is if some large
producers struggle to withstand the strains placed on their fiscal balances from lower oil andgas income. This could have knock-on impacts for upstream operations and mean that oil
and gas supply falls faster than demand. Venezuela provides a cautionary tale for how quickly
oil production can fall if there are problems with resource management; production fell by
16% per year on average between 2015 and 2020, around three times faster than the
average decline in demand in the NZE Scenario.
Higher prices and increased price volatility could also result if investor pressure or
government policies lead to widespread shut-ins of existing production, or they prematurely
close off investment in oil and gas supply and companies cannot maintain capital spending
on existing assets. In general, however, impacts would be moderated by continued declines
in demand and by supply responses by other producers.

1.4.2

Oil supply

Conventional crude oil production peaked in the late 2000s just below 70 mb/d and iscurrently around 63 mb/d (65% of global oil production). If no new conventional crude
projects were to start operations and there were to be no capital expenditure on any current
sources of supply, we estimate that production would fall by around 8-9% every year (this is
known as the “natural” decline rate). In practice, companies do invest in their current sourcesof supply and this slows the annual decline rate to around 4-5% (this is known as the“observed” decline rate). Under this condition, existing sources of conventional crude oil
supply will decline to around 45 mb/d in 2030 and 20 mb/d in 2050 as existing fields matureand projects reach the end of their lives.
Offsetting some of this decline is production from new conventional crude oil projects thatwere recently approved for development. These projects come on line in the next few years
and add close to 10 mb/d of oil production in 2030 (including 2.5 mb/d from projects thathave been, or will be, approved in 2023). This means that production from existing andapproved conventional crude oil projects declines by around 2% on average to 2030 and,once production from these approved projects peaks and starts to decline, by close to 5%
each year on average from 2030 to 2050.

IEA. CC BY 4.0

Other sources of supply make a major contribution to the oil supply balance today, but
exhibit very different production dynamics from conventional crude oil fields:

34

International Energy Agency | Special Report

Natural gas liquids: 19 mb/d was produced in 2022 (20% of global oil production). These
play an important role in the economics of gas field development by providing an
additional revenue stream; their production is often governed by gas market dynamics.



Tight oil: just over 8 mb/d was produced in 2022, 95% of which was from theUnited States. Tight oil wells decline by around 60-70% within 12 months of first
production (compared with a decline of around 6% for a conventional oil well). Decline
rates at an aggregate level are therefore mostly driven by levels of investment andscheduled drilling.

Extra-heavy oil and bitumen (EHOB): just under 4 mb/d was produced in 2022, 95% of
which was from Canada. Like tight oil, resources are spread over a large geographicalarea and new wells need to be drilled, or mines extended, to maintain production. For
EHOB, the investment required for these wells is only a fraction of the initial upfront
investment for a project as a whole and so natural decline rates are generally assumed
to be low.

In the STEPS, although demand peaks before 2030, the annual average rate of decline
thereafter is less than 0.2% to 2050 and investment in all types of production is required toensure that there are no shortfalls in supply (Figure 1.11).

mb/dFigure 1.11 ⊳ Oil supply by scenario, 2010-2050
100

80
60
40

Investment in
new supply
Investment
in APSin existing
and approved
projects

Oil supply with no investment

20

2010

STEPS
Additional investment
in new supply in STEPS

2020

2030

2040

APS

NZE

2050
IEA. CC BY 4.0.

IEA. CC BY 4.0

New conventional oil projects are needed in the APS, but no new projects are approved fordevelopment in the NZE Scenario and higher-cost projects are also closed from the 2030s.

In the APS, oil demand falls by 0.5% each year on average to 2030 and by around 2.5% eachyear between 2030 and 2050. In aggregate, no further hydrocarbon exploration is needed tomeet these demand levels, although new conventional oil discoveries may in some cases be
produced at a lower cost than existing sources of production. New conventional crude oil

Chapter 1 | Oil and gas in net zero transitions

35

1

projects are developed and small-scale extensions of existing EHOB projects offset some of
the underlying declines, as does continued drilling for tight oil (Table 1.2).
Table 1.2 ⊳Global liquids and oil production by scenario (mb/d)World liquids supply
World oil supply
World processing gains
World oil production
Conventional crude oil
OnshoreOffshore
Tight oil
Natural gas liquids
EHOB
Other production
OPEC share
Liquid biofuels
Low-emissions hydrogen-based fuels

STEPS

APS

NZE

2010

2022

2030

2050

2030

2050

2030

2050

86.5
85.3
2.2
83.1
67.4
44.6
22.8
0.7
12.7
2.0
0.5
40%
1.2
0.0

99.2
97.1
2.3
94.8
62.8
41.3
21.6
8.3
19.0
3.7
0.9
36%
2.2
0.0

104.5
101.5
2.4
99.1
61.3
39.9
21.4
11.1
21.2
4.4
1.0
35%
3.0
0.0

102.1
97.4
2.9
94.5
58.2
38.4
19.8
10.2
19.4
5.5
1.2
43%
4.5
0.2

97.5
92.5
2.4
90.2
54.9
35.6
19.3
10.3
20.1
3.9
0.9
35%
4.8
0.2

65.4
54.8
1.6
53.1
29.8
18.5
11.4
6.9
13.6
2.5
0.3
45%
7.0
3.6

83.7
77.5
2.3
75.1
48.0
31.6
16.3
7.6
16.2
3.0
0.3
37%
5.6
0.7

35.7
24.3
0.7
23.5
15.8
10.5
5.3
1.8
4.4
1.5
0.0
53%
5.4
6.0

Note: OPEC = Organization of the Petroleum Exporting Countries. Liquid biofuels and low-emissions hydrogenbased liquid fuels are expressed in energy equivalent volumes of gasoline and diesel, reported in million
barrels of oil equivalent per day.

In the NZE Scenario, oil demand declines by around 2.5% on average to 2030. This pace of
decline is sufficiently strong that no new long lead time upstream conventional projects need
to be approved for development.2 There is some ongoing investment in tight oil and EHOB
production to avoid these declining very rapidly, but no new infrastructure is required for
either source and both see steady declines in output over time. In total, production falls
across all regions to 2030 (Figure 1.12). After 2030, demand falls by more than 5.5% eachyear on average. This rate of decline is sufficiently fast that a number of higher-cost fields
are closed before they reach the end of their technical lifetimes. In 2040, for example, morethan 7 mb/d of oil production is closed earlier than would be implied by observed declines.

IEA. CC BY 4.0

Investment in existing oilfields in the NZE Scenario ensures that supply does not fall fasterthan the decline in demand. For conventional oil, this is similar to the types of field extensions
carried out in the past that slow the natural decline rate to the observed decline rate. It
includes, for example, the use of infill drilling and improved management of reservoirs, aswell as some enhanced oil recovery. Investment is also needed to minimise the emissions
intensity of operations. The NZE Scenario sees a 50% reduction in the global average GHG
emissions intensity of oil and gas production between 2022 and 2030, and close to zero
emissions from oil and gas operations soon after 2040 (see Chapter 2).
2 A discussion on the lead time of projects is included in Chapter 7 of World Energy Outlook 2022 (IEA, 2022).

36

International Energy Agency | Special Report

mb/dFigure 1.12 ⊳ Oil production by region in the APS and NZE Scenario
35

2022-50

30

APS

25

NZE

20

2022

1

15
10
5

Middle North
East
AmericaEurasia

Asia
Pacific

AfricaC&S
America

EuropeIEA. CC BY 4.0.

Production declines to 2030 across all regions in net zero transitions, with supply
increasingly concentrated in large resource holders given their lower decline rates.
Note: C & S America = Central and South America.

1.4.3

Natural gas supply

Russia’s invasion of Ukraine and its subsequent cuts to pipeline gas supply created a scramble
among importers, notably in Europe, to secure alternative sources of supply. Upstream
spending on gas outside Russia increased by more than 15% in 2022 and more than 150 bcm
of new supply will come online by the late 2020s from projects approved for development
since the invasion – greater than the 100 bcm drop in Russian production in 2022. Although
the near-term balance remains tight, this wave of new supply project announcements– notably for LNG – has eased fears of a supply deficit in the years ahead. But it also raises
the risk of significant oversupply, especially if the world redoubles its commitment to a net
zero pathway.

IEA. CC BY 4.0

Production dynamics for natural gas are broadly similar to those for oil. Conventional
non-associated natural gas fields supply around 60% of current global gas demand andobserved decline rates are around 4-5% per year on average. Gas volumes that are produced
as a by-product of oil production (associated gas) make up around 10% of total global gas
production today, and their supply dynamics are closely tied to the pace of reduction in
oilfields. Unconventional gas – which comprises shale gas, tight gas and coal bed
methane – provides the remaining 30% of gas supply today. Shale and tight gas exhibit
similar properties to tight oil and would decline rapidly if drilling were to stop. Decline rates
for coal bed methane projects are more comparable to conventional gas.

Chapter 1 | Oil and gas in net zero transitions

37

Figure 1.13 ⊳ Natural gas supply by scenario, 2010-2050
bcm

4 500

Additional investment STEPS
in new supply in STEPS
3 000

1 500

Natural gas supply with nofurther investment

Investment
in existing
and approved
projects

Investment in APS
new supply
in APS
NZE

2010

2020

2030

2050

2040

IEA. CC BY 4.0.

In the NZE Scenario, no new long-lead time gas projects are required and some production
capacity is surplus to demand. In the APS, 1 200 bcm of new production is required in 2050.

In the STEPS, new sources of gas supply are essential to meet demand and offset declines inexisting sources of supply. Just over 400 bcm of new upstream supply comes online over theperiod to 2030. After 2030 demand remains broadly stable, but new projects are still needed
to ensure a smooth balance between supply and demand at a regional level and around
2 900 bcm of new supply is required by 2050 (Figure 1.13).
Table 1.3 ⊳Global production of gases and natural gas trade
2010

2022

STEPS
2030
2050

2030

APS
2050

NZE
2030 2050

Natural gas production (bcm) 3 274
Conventional gas
2 769
Unconventional gas
504

4 138
2 871
1 266

4 299
2 894
1 405

4 173
3 016
1 157

3 861
2 742
1 119

2 422
1 940
482

3 403
2 363
1 040

919
627
293

Natural gas net trade (bcm)
LNG
Pipeline

640
276
364

810
479
331

919
611
309

921
656
265

827
588
246

370
242
125

719
507
220

187
121
47

Low-emissions gases (bcme)

23

39

89

324

197

1 161

414

1 797

Low-emissions hydrogen
BiogasBiomethane

0
23
1

2
28
9

23
42
24

99
89
136

80
51
66

809
117
235

232
56
126

1 385
129
283

IEA. CC BY 4.0

Note: bcme = billion cubic metres of natural gas equivalent.

In the APS, demand declines by around 1% each year on average to 2030 and by around 2.5%
each year from 2030 to 2050 (Table 1.3). Meeting this level of demand requires around
1 200 bcm of supply from new projects in 2050, which in aggregate can be met without any
38

International Energy Agency | Special Reportfurther natural gas exploration. In the NZE Scenario, natural gas demand falls on average by
2.5% per year between 2022 and 2030. This could be met in aggregate without any new longlead time upstream conventional projects, but some projects that have already been
approved help ensure gas demand can be met at the country and regional level, taking into
account the availability of import and export infrastructure (Figure 1.14). Some investment
also continues in unconventional gas; for example, around 500 shale gas wells are drilled in
2030 in the United States (compared with around 2 500 wells that were drilled in 2022).
Extensive efforts are also made to stop flaring and methane emissions, which unlock morethan 100 bcm of additional annual supply globally in 2030.
Between 2030 and 2040, demand in the NZE Scenario declines by around 7.5% per year, a rate
faster than implied by aggregate declines in existing sources of production. Around 650 bcm ofproduction capacity would be surplus to demand requirements in 2040 at the global level andsome higher-cost projects would close before reaching the end of their technical lifetimes. After
2040, the surplus production falls to 400 bcm as demand reductions slow to around 5% on
average per year, a consequence of ramping up the use of natural gas for hydrogen production.
Figure 1.14 ⊳ Natural gas production by region in the APS and NZE Scenario
1 500

bcm

2022-50
APS

1 200

NZE

900

2022

600
300

North
AmericaEurasia

MiddleEast

Asia
Pacific

AfricaEuropeC&S
America
IEA. CC BY 4.0.

In the APS, the sharpest drops in production occur in North America and Eurasia, while theMiddle East remains resilient. Production declines in all regions under the NZE Scenario.

IEA. CC BY 4.0

Note: C & S America = Central and South America.

LNG trade declines more slowly than overall natural gas demand in NZE Scenario. This meansthat gas production on average falls slightly less quickly in LNG-exporting regions than in
LNG-importing regions. This is also a consequence of larger fields declining more slowly.
Among exporting regions, North America records the largest fall in natural gas production inabsolute terms in the NZE Scenario, whereas Eurasia falls the most in percentage terms.

Chapter 1 | Oil and gas in net zero transitions

39

1

Box 1.2 ⊳Demand- and supply-side policies in net zero transitions

There is sometimes a debate around whether demand or supply should take the lead if
the world is to successfully achieve net zero transitions. This distinction is unhelpful andrisks postponing – perhaps indefinitely – the changes that are needed. Focusing narrowly
on a “demand-led transition” implicitly leaves responsibility for change with consumers,
and legitimises a passive approach from suppliers. Meanwhile, the idea of a “supply led
transition” comes with a heightened risk of price spikes and volatility. In practice, no one
committed to change can wait for someone else to move first: successful net zerotransitions will depend on suppliers and consumers working together, with all parties
implementing supportive policies and regulations.
In the APS and NZE Scenario, this means that a wide range of different policies are
introduced to scale up both the demand and supply of clean energy and to reduce thedemand and supply of fossil fuels and emissions in an equitable manner (Figure 1.15).
Figure 1.15 ⊳ Examples of policies to scale up demand and supply of clean
energy and reduce the demand and supply of fossil fuels

IEA. CC BY 4.0.

Successful net zero transitions require policies on the supply and demand of fossil fuels
and clean energy, with suppliers working together with consumers to reduce emissions

IEA. CC BY 4.0

Policies that boost the demand for clean energy include grants to encourage consumers
to purchase an EV, or deployment targets for heat pump installations. Policies to help
scale up new sources of clean energy supply include competitive auctions for solar PV
and wind, and providing concessionary finance for biofuel and low-emissions hydrogenproduction projects.
These actions need to be coordinated among governments, major consumers and large
energy suppliers to ensure the well-synchronised development of new clean energy value
40

International Energy Agency | Special Reportchains. For example, new low-emissions shipping fuels such as methanol or ammonia,
along with associated bunkering infrastructure, needs to be available to fuel a burgeoning
orderbook of vessels that are capable to run on these fuels.
Policies reducing fossil fuel demand play a role in creating additional room for clean
energy alternatives to expand. This includes, for example, policies to facilitate the early
retirement or repurposing of coal-fired power plants along the lines of the Just Energy
Transition Partnerships with South Africa, Indonesia and Viet Nam. These need to include
adequate provision for the social impacts on affected workers and communities. In
addition, in the NZE Scenario, sales of coal and oil boilers come to an end from 2025, andno new ICE cars are sold after 2035.
Fossil fuel supply-focused policies help to ensure more secure and equitable energy
transitions. This includes policies to reduce the emissions intensity of oil and gas supply,and help exporters achieve economic diversification and better manage the sharp
reductions in fiscal income from oil and gas sales (Chapter 4). In addition, policy makers
need to work with industry to plan for the safe and responsible decommissioning of wells
or pipelines when they are no longer needed, otherwise this could lead to major
additional costs and environmental impacts. In the APS and NZE Scenario, there are no
explicit policies restricting resource extraction or centralised efforts to impose
production quotas as the drops in oil and gas demand are assumed to be incorporated
fully into the resource development plans of companies and countries.

IEA. CC BY 4.0

Efforts to reduce fossil fuel use and scale up clean energy need to be carefully designed,
anticipating possible feedback effects and interdependencies to avoid creating new
vulnerabilities. The unplanned, chaotic or premature retirement of some existing fossil
fuel infrastructure could have negative consequences for the reliability of the overallsystem; for example, if gas-fired power plants are rendered uneconomic even while they
continue to provide valuable electricity system services. Bans on ICE vehicles or fossil fuelboilers would only be effective if clean energy alternatives are available. Policy makers
would also need to consider the extent to which existing fossil fuel infrastructure, suchas gas pipelines or storage sites, could be repurposed to transport low-emissions gases.

1.5

Refining and trade

1.5.1

Refining

The refining industry has enjoyed favourable profits in recent years as the post-pandemic
recovery in demand coincided with the first net reduction in capacity in 30 years. However,today’s high margins may not provide a good indication of the industry’s future as it faces
multiple challenges from net zero transitions. In all scenarios, the unbroken pace of demand
growth seen over the past decades changes direction. Oil demand reaches a peak in the
2020s and enters structural decline. This shift in demand trajectory creates a growing
Chapter 1 | Oil and gas in net zero transitions

41

1

mismatch between refining capacity and oil product demand, putting pressure on refineries
that are older and less competitive. The growing production of biofuels and the supply fromnatural gas liquids further exacerbate this pressure as they reduce the scope for refineries toserve liquid demand.
These challenges are compounded by changing patterns of product demand. Transport fuelssuch as gasoline, diesel and kerosene have been the main driver of demand growth over the
past few decades. However, they account for the bulk of demand reductions in the coming
decades. The decline in gasoline demand is particularly notable, with its share of oil productdemand falling from 25% today to around 15% by 2050 in the STEPS and APS, and to nearlyzero in the NZE Scenario. Demand for diesel and kerosene fares slightly better, maintaining
their share of total demand in the STEPS and APS. But they experience a significant decline
in the NZE Scenario as the long-distance transport and aviation sectors decarbonise. Demandfor petrochemical feedstock (ethane, LPG and naphtha) by comparison remains relatively
resilient. In the NZE Scenario their share of total product demand reaches over 50% by 2050,
up from 22% today, necessitating strategic adjustments by the refining industry to align with
future market demands (Figure 1.16). One example of the strategic response by refiners todate is to integrate refineries with petrochemicals to secure long-term competitiveness (seeSection 4.4.4).

mb/dFigure 1.16 ⊳ Oil product demand in the APS and NZE Scenario
100

OthersDiesel and kerosene

80

Gasoline
Ethane, LPG and naphtha

60
40
20

2022

2030 2050
APS

2030 2050
NZE
IEA. CC BY 4.0.

Reductions in oil demand are accompanied by a major shift inproduct demand towards petrochemical feedstock.

IEA. CC BY 4.0

Note: LPG = liquefied petroleum gas.

After the recent short-lived reduction in capacity, the industry is on track to add a host of
new refineries despite a notable slowdown in demand growth. Over 6 mb/d of crudedistillation capacity is slated to come online in the coming years, mostly in developing
42

International Energy Agency | Special Reporteconomies in Asia and the Middle East (IEA, 2023b). This wave of capacity expansions is
expected to be the last surge of new additions, with limited capacity growth projected after
2030 across all scenarios.
Table 1.4 ⊳Global refining capacity and runs by scenario (mb/d)
STEPS

APS

NZE

2022

2030

2050

2030

2050

2030

2050

Refining capacity

102.7

105.2

105.8

99.4

62.9

87.5

29.2

Atlantic Basin

54.2

53.2

51.8

50.4

28.3

44.0

13.2

East of Suez

48.5

52.0

54.0

49.0

34.6

43.5

16.0

Refinery runs

80.7

83.9

81.6

75.5

44.1

64.3

20.6

Atlantic Basin

42.5

40.5

37.4

36.5

18.3

30.8

8.6

East of Suez

38.2

43.4

44.1

39.0

25.8

33.5

12.0

In the STEPS, global refining activity peaks around 2030 and remains at today’s levels throughto 2050. In the APS, global refinery runs halve over the period to 2050. Refining activities inthe East of Suez region surpass those in the Atlantic Basic well before 2030 given that they
benefit from relatively resilient domestic demand or competitive feedstock (Table 1.4). Some
refiners, especially those in the Atlantic Basin, have begun adapting to a new market
environment by converting their facilities into biorefineries, expanding into low-emissions
businesses such as EV component production, hydrogen production and plastics recycling,or considering closures. In the NZE Scenario, refinery runs reduce further to 20 mb/d by
2050, around a quarter of today’s level, mostly to produce petrochemical feedstock or othernon-energy products such as asphalt and bitumen.

1.5.2

Oil trade

IEA. CC BY 4.0

Global oil trade flows are increasingly concentrated on emerging market and developing
economies in Asia, which currently account for just over 40% of global crude oil imports. Dueto robust demand and limited domestic production, this region's share of global imports is
set to rise to around 60% in both the STEPS and APS by 2050. The Middle East maintains its
stronghold as the largest crude oil supplier, serving more than half of global import needs in
2050 in both the STEPS and APS. Although Russian crude oil is finding buyers in Asian markets
and elsewhere, Russia’s share of global crude oil exports continues to decline in all scenarios.
North and South America play an increasingly important role in meeting the world’s crude
oil requirements, compensating for the loss of Russian volumes, as the reductions in theregions’ refining activity outstrip the impacts of falling domestic production.
In the APS, the United States’ share of global crude oil exports grows from 6% now to 15% in
2050, underscoring the region’s emerging role as a swing player in global crude oil markets.
In the NZE Scenario, the Middle East is set to play an outsized role in serving global crude oilmarkets as a low-cost producer, with its share of total exports surpassing 60% by 2050
(Figure 1.17).
Chapter 1 | Oil and gas in net zero transitions

43

1

mb/d

Figure 1.17 ⊳ Crude oil imports by region and exporters’ shares by scenario
APS

50

NZE

100%

40

80%

30

60%

20

40%

10

20%
2022

Importing regions
Exporters'shares(right axis)

2030

2040
China

2050
India

2022
Other Asia

From Middle East

From Russia

2030

2040

European Union

2050
Rest of world

From North and South America
IEA. CC BY 4.0.

Crude oil import flows continue to focus on Asia; in the APS, the Middle East’s strong position
as the largest exporter is joined by the United States’ growing role as a swing supplier.

The majority of new refining facilities under development are located in today’s exporting
regions for refined products, namely China, India and the Middle East. This makes itchallenging to justify new refinery investments in importing regions such as Africa andCentral and South America as new facilities would face intense competition from incumbent
refiners overseas seeking export outlets. As both exporters and importers increase theirreliance on trade, there is an increase in product trade volumes in the short term in the APS
and the subsequent decline in trade is less steep than the pace of demand declines. Gross oil
product exports in 2050 in this scenario are broadly similar to today’s levels despite an over
45% reduction in overall oil demand.

IEA. CC BY 4.0

China's evolving policy of regulating crude oil and product trade has significant implications
for global oil trade flows, given its imminent position as the world’s largest refiner. To address
excess product outputs and curb emissions in the refining sector, the Chinese government
implemented quotas for both crude oil imports and oil product exports. In the first half of2022 the reduction in product export quotas had a notable effect on global middle distillate
supplies, leading to a surge in prices for these products. Conversely, an easing of crude oil
import and product export quotas in late 2022 contributed to a moderation of diesel prices.
These instances demonstrate the substantial impacts of China’s trade policy shifts on producttrade balances, as any changes in its trade regulations can cause significant fluctuations in
product supplies and prices worldwide, especially for middle distillates such as diesel andkerosene (IEA, 2023b).

44

International Energy Agency | Special Report1.5.3Natural gas trade

Around 20% of global natural gas production is traded over long distances, using either largescale pipelines (440 bcm in 2022) or by liquefying the gas and shipping it by sea (530 bcm in2022). Continued expansion of natural gas trade requires investment in this capital-intensive
export infrastructure, which also requires high rates of utilisation. Buyers and sellers havetherefore typically entered into long-term contracts with pre-agreed volumes that justify thehigh upfront costs of the projects.
Global natural gas trade in the STEPS increases by nearly 15% between 2022 and 2030 toreach 920 bcm. In the APS, growth slows to just 2%. In the NZE Scenario total trade contracts
slightly, by 10%. Long-distance pipeline trade declines in all scenarios, diminished bysignificantly lower requirements for long-term, fixed volumes of gas deliveries. Interregional
pipeline trade falls by nearly 10% in the STEPS, 25% in the APS and by 35% in the NZE Scenario
between 2022 and 2030, as pipeline gas exports to Europe are rapidly reduced and a much
lower level of pipeline-based trade takes place within North America.
Figure 1.18 ⊳ Existing and under-construction LNG liquefaction capacity andbcm

LNG trade by scenario

800
STEPS

Under construction
600

400
Existing LNG capacity

200

APS
NZE

2015

2020

2025

2030

2035

2040

2045

2050
IEA. CC BY 4.0.

In the NZE Scenario, LNG projects currently under construction are not necessary. In the
APS, trade peaks by 2030 and the capacity utilisation of plants would drop significantly.

IEA. CC BY 4.0

Notes: LNG trade reflects interregional trade between regions modelled in the Global Energy and Climate
Model. LNG capacity is derated to 85% of nameplate capacity.

LNG is, by comparison, relatively resilient, growing by nearly 30% in the STEPS, and by 25%
in the APS to 2030. It declines by around 5% in the NZE Scenario over the same period, evenas overall natural gas demand falls by 20%. In all scenarios, global gas trade continues topivot toward LNG, as the relatively large share of destination-flexible volumes provides a better

Chapter 1 | Oil and gas in net zero transitions

45

1

match with the variable speed of transitions away from gas in different regions and sectors.
Portfolio players continue to act as important intermediaries between supply and demand.
After 2030, LNG trade grows moderately in the STEPS, falls by 4% per year in the APS and by
7% per year in the NZE Scenario (Figure 1.18). By 2050, demand for LNG in the APS is nearly
300 bcm lower than today and is 400 bcm lower in the NZE Scenario. This story of near-term
resilience but longer-term decline raises the question of whether investors are likely torecoup their invested capital, and what impact a possible surplus of LNG supply would haveon benchmark gas prices.
The world currently has around 650 bcm of annual nameplate liquefaction capacity, with afurther 250 bcm under construction. In the APS, since LNG demand no longer grows after
2030, the average capacity utilisation of LNG export terminals falls from around 90%
between 2018 and 2022 to 80% by 2030. In the NZE Scenario, the sharp decrease in natural
gas demand globally means that the majority of projects currently under construction are nolonger necessary. If they do go ahead, aggregate capacity utilisation would fall to 65% in 2030
and several plants that are unable to compete in a supply glut would likely end up closing or
being repurposed as a facility able to trade hydrogen-based fuels such as ammonia ormethanol.
Figure 1.19 ⊳ Delivered cost of existing and under-construction LNG supply
USD/MBtu

compared with gas prices in the NZE Scenario, 2030

10

Exporter
United States

8

Australia
Other

6

Qatar
Africa4

Weighted average
import price
European Union

2

China
0

100

200

300

400

500

600

700

800 bcm
IEA. CC BY 4.0.

IEA. CC BY 4.0

LNG exporters face intense competition for rapidly diminishing demand; most projects
under construction fail to recoup their invested capital under NZE Scenario import prices.

This outcome depends largely on whether projects are able to recover their costs in the low
gas price environments of the APS and NZE Scenario. On average, the delivered cost of LNG
is around USD 4.50/MBtu (Figure 1.19). The most cost-competitive sources of supply are
projects that have paid off their initial invested capital and benefit from low-cost feedgas and46

International Energy Agency | Special Reportlow operating costs, such as the Qatari LNG trains that started up in the early 2000s. Around
40% of existing projects have yet to recover fully their invested capital, having been online
for less than the typical 10-year period over which debt is recovered in project finance forlarge-scale LNG terminals. For projects under construction, average delivered costs are
estimated to be around USD 8/MBtu, and there is a risk that this may increase due tomounting cost inflation amid a crowded queue of projects.
In the NZE Scenario a glut of LNG and pipeline capacity forms in the mid-2020s, and weighted
average import prices in China and the European Union fall to levels last seen at the heightof the Covid-19 pandemic in 2020. This puts strains on the profitability of both existing andrecently commissioned LNG projects. While shut-in risks would only appear if prices fall
below feedgas and variable operating costs, there would be a degree of risk that projectsponsors write off the value of the assets. This would, to a large extent, depend on
contractual terms: suppliers selling LNG cargoes on a long-term take-or-pay basis could passmuch of the volume and price risk to offtakers. Given the low oil prices in the NZE Scenario,
oil indexation would offer little protection to sellers unless a floor price were set (such as
through an S-curve formula). For suppliers without firm offtake contracts, LNG cargoes would
have to be sold on the spot market at short-run marginal costs in order to avoid shutting in.
We estimate that the sponsors of around 70% of LNG export projects currently underconstruction would struggle to recover their invested capital in the NZE Scenario. In the APS
gas prices are higher, but there are still some 80 bcm of projects – or 40% of what is currently
under construction – that would not fully recover their invested capital.

1.6

Alternative supply pathways in the NZE Scenario

The rapid deployment of clean energy technologies and energy efficiency is at the core of
the net zero transitions set out in the APS and NZE Scenario. In the NZE Scenario it is thesurge in clean energy investment that leads to the overarching supply, price and investment
trends and removes the need for any new long lead time conventional oil and gas projects.
The energy system transformation in the NZE Scenario is not the only possible pathway toreach the goal of net zero emissions by 2050. Similarly, the supply-side dynamics in the
NZE Scenario are not the only way to meet a world with rapidly falling oil and gas demand.

IEA. CC BY 4.0

Some producers have also argued that higher levels of oil and gas demand and supply thanseen in the NZE Scenario could be consistent with achieving net zero emissions by 2050. This
would be by deploying much greater levels of CCUS and negative emission technologies suchas DACS and BECCS. This possibility is explored in Chapter 2.
A number of producers have set out reasons why their resources should be preferred in a
declining oil and gas market. Four arguments are most prevalent, revolving around the needto prioritise: (i) resources in low-income countries that could be used to help boost economic
development, (ii) resources with lower emission intensities, (iii) low-cost resources, and (iv)

Chapter 1 | Oil and gas in net zero transitions

47

1

energy security, with a view to limiting oil and gas imports (this may also express itself in apreference for imports from geopolitical allies).
In this section, we explore the implications, benefits and trade-offs of boosting production
in countries with a preference for the above factors (Box 1.3). Oil and gas demand levels are
assumed to remain the same as in the NZE Scenario, and so the increases in production arematched in aggregate by decreases elsewhere. This may lead to large changes in projectedoil and gas prices as well as changes in supplier concentration, emissions levels and income
for producer economies.
Box 1.3 ⊳Description of NZE Scenario supply-side sensitivity cases

The four cases described below illustrate different ways to think through oil and gas
supply in net zero transitions. They are framed here as sensitivities on the NZE Scenario,
but the choices and trade-offs that they reveal are of broad relevance.
In the low-income preference case, it is assumed that countries with gross domestic
product (GDP) per capita today below USD 10 000 develop their oil and gas resources inline with projections in the STEPS (Figure 1.20). To ensure that this additional production
does not mean supply exceeds demand in the NZE Scenario, producers with the highest
levels of GDP/capita today are assumed to cut back on production.
In the emissions preference case, production in the 40 countries with the current highest
emissions intensities are assumed to decline at their natural decline rates. The lower levelof production in these countries relative to the NZE Scenario is matched in aggregate byincreases in production above levels in the NZE Scenario by countries with the lowest
current emissions intensities. To examine the emissions implications of these changes in
the geography of production it is assumed in this case that countries do not undertake
any targeted efforts to reduce the emissions intensity of oil and gas operations (unlike in
the NZE Scenario, which sees major efforts to reduce these).
In the cost preference case, resource holders with lower costs expand production above
levels in the NZE Scenario. This leads to much lower prices than in the NZE Scenario,
compelling higher-cost sources of production around the world to close earlier thanwould otherwise be the case.

IEA. CC BY 4.0

In the security preference case, today’s oil and gas importers look to reduce their importdependency to the extent possible by boosting domestic production. This reduces thelevel of oil and gas imports required globally, resulting in lower prices and lower
production by high-cost exporters.
In many cases, although a number of countries see an increase in production above levelsin the NZE Scenario, the overall declining market for oil and gas demand means that thismanifests as a slower decline rate rather than an increase in production in absoluteterms.

48

International Energy Agency | Special ReportFigure 1.20 ⊳ Oil and gas production and GDP per capita in selectedThousand USD (2022, PPP) per capita

countries, 2022

Qatar

100

1

United States
Saudi Arabia
Russia10
Tanzania

1

Cameroon

Nigeria
Venezuela
AngolaMozambique
0.01

0.1
Low-income countries

10 mboe/d1
OthersIEA. CC BY 4.0.

Multiple low-income countries today could develop additional oil and gas resources.
These follow a higher production pathway in the low-income preference case.
Note: mboe/d = million barrels of oil equivalent per day.

Low-income preference caseIn the low-income preference case, production grows faster than in the NZE Scenario in a
number of countries in Africa, especially Nigeria, Angola and Mozambique, as well as
low-income countries in Asia Pacific, Eurasia, Latin America and the Middle East. In total,
these countries produce around 5.5 mb/d and 360 bcm in 2050 (compared with around
1 mb/d and 50 bcm in the NZE Scenario in 2050) (Figure 1.21).
To avoid any oversupply of oil and gas, a number of high-income countries see lower
production than in the NZE Scenario, including in the Middle East, Europe and North America(Figure 1.22). Production is assumed to fall at a maximum of the natural decline rates(around 8-9%) in these countries, although decline rates in these countries in this case tend
to be much lower than this.3

IEA. CC BY 4.0

Achieving the shift in production from high-income to low-income countries would likely bevery challenging to realise in practice. One possibility would be for high-income countries
explicitly to choose to ramp down production faster than in the NZE Scenario and provide
support for the development of new projects in low-income countries through technical or
financial support; but in reality there would be large risks of an oversupplied market.

3 The decreases in production in higher-income countries relative to the NZE Scenario are generally small

compared with their overall levels of production, meaning differences in decline rates are also small.

Chapter 1 | Oil and gas in net zero transitions

49

Figure 1.21 ⊳ Oil and natural gas supply from low-income countries in the
Oil

12

bcm

mb/d

NZE Scenario and the low-income preference case

9

300

6

200

3

100

2010

2020

2030

2040

Historical

2050

Natural gas

400

2010

NZE Scenario

2020

2030

2040

2050

Low-income preference
IEA. CC BY 4.0.

The low-income case sees much higher production in low-income countries, with natural
gas production growing substantially to 2050.
Note: Low-income countries include those with GDP per capita today below USD 10 000 (PPP).

Figure 1.22 ⊳ Increases and decreases in production relative to the
0.9

Oil

0.6
0.3

bcm

mb/d

NZE Scenario in the low-income preference case, 2040

Venezuela
Nigeria60
40

AngolaNigeria

20

0

0

-0.3

-20

Norway
UAE
-0.6
Qatar
Africa Asia PacificNatural gas
Mozambique
India

NorwayUAE
Qatar
Middle East North America-40

Eurasia

EuropeC & S America
IEA. CC BY 4.0.

IEA. CC BY 4.0

The increases in production in low-income countries relative to the NZE Scenario are mainly
balanced by reductions in countries in the Middle East, North America and Europe.
Notes: C & S America = Central and South America; UAE = United Arab Emirates. Shows only the 10 countries
with the largest production increases and decreases.

50

International Energy Agency | Special ReportIn the low-income preference case, low-income countries spend around USD 1 800 billion
more on oil and gas through to 2050 than the levels seen in the NZE Scenario (including both
capital and operating costs). There is some less spending in existing projects in high-income
countries than in the NZE Scenario but the overall cost of supplying oil and gas in this case isaround USD 1 400 billion (23%) higher than in the NZE Scenario.
The low-income producers generate significantly more revenue from oil and gas sales thanin the NZE Scenario. However, if oil and gas prices evolve as in the NZE Scenario, theadditional capital and operating costs in low-income countries (USD 1 800 billion to 2050)
would be greater than the additional revenue generated (USD 1 600 billion to 2050). Thishighlights a key risk for these countries. They could benefit from the broader economic
activity linked to developing oil and gas resources and could use the produced energy toboost access to energy domestically. But, if the world is successful at scaling up clean energy
in line with the NZE Scenario, low-income countries that develop their resources for export
may struggle to generate any substantial returns or fiscal income from oil and gas sales.
Box 1.4 ⊳Prospects for natural gas developments in Africa

The current position of natural gas in Africa’s energy mix varies widely across thecontinent. In North Africa, natural gas meets around half of the region’s energy needs
and domestic demand has run ahead of exports since 2010. In sub-Saharan Africa theshare of natural gas in the energy mix is a mere 5%, and its use domestically has grownin parallel with large-scale export projects.
The top three producers in Africa – Algeria, Egypt and Nigeria – currently produce around
80% of the continent’s natural gas. Around 7 000 bcm of natural gas resources have been
discovered over the past decade across the continent and a number of countries arelooking to substantially expand gas production. Around one-quarter of the gas discoveredin the past decade in Africa has already been approved for development, including large
developments in Mozambique, Mauritania and Egypt (Figure 1.23). If these projects are
all completed on time, we estimate that they would provide around 70 bcm of gas per
year by 2030.

IEA. CC BY 4.0

The combustion of the gas from projects already approved would result in around 10 Gt
of cumulative CO2 emissions over the next 30 years. This is equivalent to aroundfour months of emissions from the energy sector today. Africa’s share of cumulative
energy‐related CO2 emissions from 1890 to today is around 3%. If the cumulativeemissions from burning this gas over the entire lifetime were added to Africa’s current
contribution, it would raise Africa’s share to just under 3.5%.
These approved gas projects could provide a boost to economic activity, especially if they
enable the expansion of local industry, generate well-paid local jobs or provide
government income through royalties and taxes. In general, the export prices seen in the
STEPS and APS would be high enough to cover production costs, but in the NZE Scenario
much lower prices globally would mean that many of the projects would never recover
Chapter 1 | Oil and gas in net zero transitions

51

1

their upfront costs and government income would likely be very low. Any gas projects
developed could help to provide access to electricity and (via LPG) to clean cooking,where this remains to be achieved, but this would not provide much support to project
economics given the low prices that low-income consumers could afford to pay. In all
scenarios, project delays and cost overruns would severely challenge the commercialityof projects, especially those that have not yet been approved.
Figure 1.23 ⊳ Africa’s natural gas supply balance and status of resource
Supply balance

150

bcm

bcm

discoveries made since 2010

6 000

100

4 000

50

2 000

2000

2005

2010

North Africa:
Sub-Saharan:

2015

2022

Domestic
Domestic

Exports
Exports

Discoveries

North Africa

Sub-SaharanAfricaApproved
Not yet approved

IEA. CC BY 4.0.

Developing sub-Saharan Africa’s large resource discoveries would add little to its
historical emissions burden; however, they fail to turn a profit in the NZE Scenario.

Emissions preference case

IEA. CC BY 4.0

The emissions intensity of oil and gas operations in the worst-performing producers is five to
ten times higher than the best performers (see Chapter 2). In the emissions preference case,production in countries with the lowest emissions intensity today is given preference overproduction in countries with the highest emissions intensity. In this case, countries with thehighest emissions intensity produce around 3 mb/d and 140 bcm less oil and gas in 2040 thanin the NZE Scenario, with some of the largest reductions seen in Russia, Turkmenistan,
Kazakhstan and China (Figure 1.24). There is a commensurate increase in production incountries with the lowest emissions intensities, notably in Norway, Saudi Arabia and Qatar.
Looking at the period to 2030, the additional projects developed in the countries with thelowest emissions intensities means there is around USD 600 billion more spending on oil andgas above the levels in the NZE Scenario. This results in a 200 Mt CO2-eq reduction inemissions from oil and gas operations in 2030. This is an important reduction in emissions
from oil and gas operations, but it is far smaller and much more costly than the reductions inemissions from oil and gas operations that occur in the NZE Scenario.
52

International Energy Agency | Special ReportFigure 1.24 ⊳ Increases and decreases in production relative to the
Oil

0.5

NorwaySaudi Arabia

bcm

mb/d

NZE Scenario in the emissions preference case, 2040
30

Kuwait0

NorwayQatar
Saudi Arabia

0

Iran

- 0.5

- 1.0

1

Natural gas- 30

Kazakhstan
RussiaAfricaAsia PacificEurasia

Europe- 60
Middle East

Argentina
China
Turkmenistan

North America

C & S America
IEA. CC BY 4.0.

Shifting production from the highest to the lowest emitters cuts GHG emissions, but
reductions would be lower and more costly than the reductions in the NZE Scenario.
Notes: C & S America = Central and South America. Shows only the 10 countries with the largest production
increases and decreases.

In the NZE Scenario, all producers undertake extensive efforts to reduce the emissions
intensity of their operations; this requires around USD 600 billion of spending to 2030. This
investment cuts annual GHG emissions from oil and gas operations by 2 200 Mt CO2-eq in
2030. The unit cost of reducing emissions from oil and gas operations through dedicatedmitigation measures is therefore around ten times lower than the cost of reducing emissions
by developing new projects in lower-emission countries.
The changes in production in the emissions preference case could be achieved by countries
introducing restrictions or fees based on the emissions intensity of oil and gas that is
imported or consumed. In practice, these policy measures would also be likely to encourage
producers with high emissions intensity to undertake targeted efforts to improve theiroperations. Indeed, these results show that this would be a much more cost-effective way to
reduce emissions from oil and gas operations than developing new projects with low emissions
intensity and trusting that these will displace higher emissions intensity sources of production.

IEA. CC BY 4.0

Cost preference caseIn the NZE Scenario, the strategies adopted by resource‐rich governments and their NOCs
play a key role in determining the overall level of oil and gas prices. Large oil and gas resource
holders are assumed not to develop new fields even though there might be an economic
case for them to do so. For example, the oil price of around USD 40/barrel in 2030 in the
NZE Scenario would be more than sufficient to cover the capital and operating costs of new
field developments in a number of the low-cost producers.
Chapter 1 | Oil and gas in net zero transitions

53

In the cost preference case, it is assumed that low-cost producers expand their productionlevels well above the levels in the NZE Scenario. Since oil and gas prices are assumed to be
set by the operating costs of the marginal project, this pulls down oil and gas prices, forcing
producers whose operating costs are higher than the oil price to shut down production to
avoid making a loss (Figure 1.25).
Figure 1.25 ⊳ Costs of oil production in the NZE Scenario and cost preference
USD per barrel

case, 2030

40
30
20
Costs in cost preference case

10

0

10
Operating cost
Flaring reduction

20

30

40

Electrification
Residual CO₂ emissions

50

60
Methane abatement

70
mb/d

IEA. CC BY 4.0.

Almost 90% of oil can be produced for less than USD 10/barrel in the NZE Scenario. In thecost preference case, prices drop, and high-cost producers are pushed out of the market.
Note: Government taxes from production are not shown.

Low-cost producers – including Saudi Arabia, Qatar and Iraq – expand production above
levels in the NZE Scenario and this means that the oil price falls to around USD 10/barrel in
2030. Prices remain at low levels and high-cost producers, including Canada, Australia andChina, shut in around 5 mb/d of oil and 160 bcm of gas production in 2040 (Figure 1.26).

IEA. CC BY 4.0

Around USD 500 billion is invested in new projects in low-cost producers to 2050. These havemuch lower operating costs than projects closed in high-cost producers, resulting in around
USD 1 000 billion lower operating costs through to 2050 in the cost preference case than in
the NZE Scenario. Total capital and operating costs over the period to 2050 are therefore
around USD 500 billion lower than in the NZE Scenario.
A key risk for the low-cost countries looking to boost production is that it would result inmuch lower overall income from oil and gas sales. This risk is ever-present in oil markets
today, but it would be significantly heightened against the backdrop of falling oil and gas
demand. For example, in the cost preference case, countries in the Middle East produce
more than 20 mb/d of oil in 2040, 30% more than in the NZE Scenario. But the lower oil pricemeans they receive 60% less income from oil sales than in the NZE Scenario in 2040.
54

International Energy Agency | Special ReportFigure 1.26 ⊳ Increases and decreases in production relative to the
Oil

1.5

Saudi Arabia
Iraq

0.5
-0.5
-1.5
-2.5
Africa

Qatar

bcm

mb/d

NZE Scenario in the cost preference case, 2040

101Natural gas
Saudi Arabia
Iran

Qatar

-10

Algeria
China-30

CanadaAsia Pacific30

Eurasia

Europe-50
Middle East

Malaysia
Argentina
Australia

North America

C & S America
IEA. CC BY 4.0.

Low-cost producers could significantly boost supply, resulting in a further concentration of
supply and very low prices. Such low prices would be very hard to maintain in practice.
Notes: C & S America = Central and South America. Shows only the 10 countries with the largest production
increases and decreases.

Many producer economies would likely struggle to withstand such a large impact on theirfiscal balances. Avoiding this would rely on very rapid and successful implementation of
economic reforms. Without much more diversified economies and sources of tax revenue,
revenue from hydrocarbons in such a low-price world would not be sufficient to financeessential areas such as education, healthcare and public sector employment. These socialpressures could also mean much more limited funding being available for continued
investment in the upstream. This would lead to price volatility and turbulence and makes it
unlikely in practice that prices could be maintained at very low levels for a prolonged period.

Security preference case

IEA. CC BY 4.0

In the security preference case, importers are assumed to lower or eliminate taxes on
domestic oil and gas operations – and in some cases subsidise operations – to boost
production to levels seen in the STEPS. In 2030, importers produce close to 3 mb/d and150 bcm more oil and gas than in the NZE Scenario, with some of the largest relative
increases seen in China, India and Egypt. Globally, this means that net oil imports fall toaround 32 mb/d in 2030 (8 mb/d less than in 2022) and gas imports to around 570 bcm(240 bcm less than in 2022). By 2040, importers produce 4 mb/d and 200 bcm more oil andgas than in the NZE Scenario (Figure 1.27).

Chapter 1 | Oil and gas in net zero transitions

55

Figure 1.27 ⊳ Increases and decreases in production relative to the
Oil

1.5

bcm

mb/d

NZE Scenario in the security preference case, 2040

China

India

0.5

India

30

Egypt

Mexico00-1.0Africa

China

60

1.0

-0.5

Natural gas

90

Russia-30

Saudi Arabia
CanadaAsia PacificEurasia

Europe

Qatar
United States
Russia-60
Middle East

North America

C & S America
IEA. CC BY 4.0.

Efforts by importers to boost oil and gas production forces export-oriented producers to shutin production and could cause a fragmentation of international markets.
Notes: C & S America = Central and South America. Shows only the 10 countries with the largest production
increases and decreases.

The smaller opportunity for exports causes international oil and gas prices to fall and a numberof export-oriented producers are forced to reduce production.4 In 2040, a 4 mb/d reduction in
production by exporters would mean the oil price for exporters would fall to around
USD 20/barrel in 2040. OPEC’s share of the oil market in this case is 39% in 2040 and 41% in
2050, much lower than the levels seen in the NZE Scenario (44% in 2040 and 51% in 2050).

IEA. CC BY 4.0

This case would see a major fragmentation of international oil and gas markets. Importers
choose to forego cheap oil and gas available on the market to protect their domestic oil andgas industry. The overall cost for oil and gas supply is also much higher than in the
NZE Scenario. To 2050, cumulative capital and operating costs for oil and gas supply is around
USD 1 500 billion higher than in the NZE Scenario (a 25% increase). This case also includes
some potential policy inconsistencies, with importers looking to protect – or even subsidise– domestic oil and gas companies even as they rapidly scale up clean energy investment andmove away from fossil fuel use.

4 High-cost exporters are assumed only to reduce production designated for export so that they can always

meet their own consumption with domestic production to avoid becoming net importers.

56

International Energy Agency | Special Report

Conclusions
The cases examined here highlight that different supply pathways are possible in a net zero
emissions world (Figure 1.28). In general they achieve their starting aims, but they also see
major potential downsides for producers, markets and net zero transitions.
Figure 1.28 ⊳ Differences in oil and gas production from the NZE Scenario in
the sensitivity cases, 2040

Natural gas

Oil
Energy security
Low-income
EmissionsCost-6
AfricaAsia Pacific-30Europe3

6- 300 - 150
0
150
300
mb/d
bcm
Eurasia Middle East North America C & S America Other
IEA. CC BY 4.0.

Changes in preferences can reshape oil and natural gas production across regions, but
increases in one part of the world must be matched by faster declines elsewhere.

IEA. CC BY 4.0

Note: C & S America = Central and South America.


In the low-income preference case, oil and gas production in low-income countries isaround 4.5 mb/d and 300 bcm higher in 2050 than in the NZE Scenario. But in thecontext of oil and gas prices in the NZE Scenario, many of these new projects would failto generate a reasonable return and could become stranded assets.

In the emissions preference case, emissions from oil and gas operations are reduced
globally by around 200 Mt CO2-eq in 2030. But this reduction is much smaller and more
expensive than the reduction in emissions in the NZE Scenario, in which producers
undertake targeted action to reduce their emissions intensity and emissions are cut by
2 200 Mt CO2-eq in 2030.

In the cost preference case, the total cost of supplying oil and gas to 2050 is 7% lower
than in the NZE Scenario. But this case sees a further concentration of production– already visible in the NZE Scenario – among a small number of countries, and so maylead to heightened security of supply concerns. This case also sees lower commodity
prices than in NZE Scenario and some producer economies would likely struggle towithstand the impacts on their fiscal balances.

Chapter 1 | Oil and gas in net zero transitions

57

1

In the security preference case, most countries successfully cut their reliance on
imports, and global oil and gas imports in 2030 are around 20% lower than today(compared with a 13% drop in the NZE Scenario to 2030). But achieving this would leadto a major fragmentation of international oil and gas markets, and means the cost of
supplying oil and gas is around 25% greater than in the NZE Scenario to 2050.



A key assumption in the sensitivity cases is that overall demand levels do not change, withincreases in production above the levels in the NZE Scenario by some countries matched by
an identical level of reductions by others. Commodity prices could be the intermediary toallow for this, with new developments in one part of the world leading to lower prices andreductions in production in other parts of the world. Avoiding an increase in demand,
however, may require policies to be further tightened above what already occurs in the
NZE Scenario and there is a risk that this would not happen. Some of the cases examined
would also imply a breakdown in international oil and gas markets as they are today, and it
is not clear if prices would send a clear enough signal to avoid overproduction.
Figure 1.29 ⊳ Selected security, cost and revenue indicators in the
NZE Scenario and supply-side sensitivity cases

Billion USD (2022)

60%
55%
50%

Annual average oil and gas
Cumulative revenue ininvestment to 2050
low income countries to 2050
300
4Trillion USD (2022)

OPEC share in 2050

250
200
150

45%
NZE

Low-income

3
2
1

Emissions

Cost

Security
IEA. CC BY 4.0.

IEA. CC BY 4.0

The cases examined involve trade-offs between security, cost and oil and gas revenue in
low-income countries. The NZE Scenario aims to chart a middle ground between these.

A world with rapidly declining oil and gas demand will inevitably involve trade-offs andcompromises for producers and consumers between cost, security, emissions and equity
concerns. In the NZE Scenario, the supply-side dynamics are based on the assumption that
there is no development of new long lead time upstream conventional projects and thatprices rapidly fall to the operating costs of the marginal project. While there is no single
answer, this assumption means the NZE Scenario charts a middle ground between a numberof the various trade-offs that exist (Figure 1.29).
58

International Energy Agency | Special Report

The above analysis focuses on the NZE Scenario, but many of the considerations also apply
in the context of the APS. For example, in the APS, investment to reduce the emissions
intensity of existing operations is still a more effective way to reduce GHG emissions thandeveloping new fields. New conventional crude oil and gas developments are required in the
APS, but with falling oil and gas demand there could still be intense competition for market
share. Increases in production in one part of the world would likely require reductions
elsewhere to avoid making the later stages of the transition even more challenging.
All producers can make arguments as to why their resources should be developed overothers. In net zero transitions new project developments are, however, likely to face majorcommercial risks. Producers looking to undertake new resource developments need to
explain how their plans are viable within a global pathway to net zero emissions by 2050 andbe transparent about how they plan to avoid pushing this goal out of reach.

1.7

Investment

Total energy investment in 2023 is estimated to be USD 2.8 trillion. Of this, around
USD 1.8 trillion will be invested in clean energy, and USD 1 trillion in oil, gas, and coal(including extraction, refining, transmission and distribution, and power plants that use thesefuels). Both the APS and NZE Scenario see a major increase in clean energy investment, rising
to USD 3.1 trillion in 2030 in the APS and to USD 4.2 trillion in the NZE Scenario (Figure 1.30).
This boost in clean energy investment is the principal driver behind the drop in fossil fuel usethat can be achieved while ensuring there is no shortfall in meeting energy service demands.

Trillion USD (2022, MER)

Figure 1.30 ⊳ Investment in clean energy and fossil fuels by scenario
Clean energy

5Fossil fuels

Power

Supply4

End use3

Energy efficiency
Coal

2

Oil
1

Natural gas
2023e

STEPS APS NZE
2030

2023e

STEPS APS NZE
2030
IEA. CC BY 4.0.

IEA. CC BY 4.0

In the NZE Scenario annual fossil fuel investment drops by USD 500 billion to 2030 whileclean energy investment increases by more than USD 2 trillion.
Note: 2023e = estimated values for 2023.

Chapter 1 | Oil and gas in net zero transitions

59

1

In the APS, investment is needed in both new and existing oil and gas projects: oil and gas
investment in 2030 is around USD 650 billion, around 20% less than the expected level in
2023 (Figure 1.31). In the NZE Scenario, investment shifts entirely to maintaining production
at existing fields, and to reducing the emissions intensity of oil and gas operations.
Investment in oil and gas supply falls to USD 400 billion in 2030, half of the level in 2023. In
both the APS and the NZE Scenario, the increase in clean energy investment is assumed tobe synchronised with the scaling back of investment in fossil fuels. In reality, mismatches ininvestment levels are likely, and both over- and underinvestment in oil and gas could haveimportant consequences for net zero transitions.

Billion USD (2022, MER)

Figure 1.31 ⊳ Investment in new and existing fields by scenario
400

APS

NZE

2030 2050

2030 2050

APS

NZE

2030 2050

2030 2050

300
200
100

2023e

Exisiting fields:
New fields:

Oil
Oil

2023e

Natural gas
Natural gas
IEA. CC BY 4.0.

Investment in oil and natural gas supply declines from current levels in both the APS andNZE Scenario. Capital spending in the NZE Scenario is focused entirely on existing fields.

1.7.1

Risks from overinvestment

IEA. CC BY 4.0

Overinvestment could occur if the oil and gas industry invests for long-term growth indemand that does not materialise. This risk has always been a feature of oil and gas markets,
but net zero transitions – and the prospect of long-term structural declines in oil and gas
demand – would present a new and pervasive set of risks and uncertainties. In such a situation,
oil and gas prices would fall and new projects would face major commercial risks and may failto recover their upfront costs. Existing projects could be at risk if oil and gas prices remain below
operating costs for a prolonged period. Moreover, it could lead to difficulties for producer
economies in which oil and gas sales make up a significant share of exports and fiscal revenues.
Overinvestment in supply also risks locking in emissions that could push the world over the
1.5 °C threshold. This could be avoided by governments adopting resilient policies thatprevent a drop in prices feeding through into a rebound in oil and gas demand. But in practice60

International Energy Agency | Special Reportthis may be difficult to stop. Additional emissions from new projects would therefore need
to be compensated by even more robust emission reductions in the latter years of our
projections to achieve net zero emissions by 2050.

Assessing the risks of stranded assets
A reduction in oil and gas production and prices could lead to widespread losses for the oiland gas industry and to stranded assets. There are multiple strands to this debate and it istherefore useful to distinguish between different impacts and losses that could be incurredby the oil and gas industry. In particular, it is helpful to distinguish between:
Stranded volumes: existing fossil fuel reserves that are left unexploited as a result ofclimate policies.

Stranded capital: capital investment in fossil fuel infrastructure that is not recovered
over the operating lifetime of the asset because of reduced demand or reduced prices
resulting from climate policies.

Stranded value: a reduction in future revenue generated by an asset or asset owner, asassessed at a given point in time, caused by reduced demand or reduced prices resulting
from climate policies.

The world currently has around 1.8 trillion barrels of oil and 220 trillion m3 of natural gas 2P
reserves. With reasonable assumptions on possible deployment rates of CCUS and negativeemission technologies such as DACS and BECCS, a large proportion of these reserves cannot
be combusted if the temperature rise is to be limited to well below 2 °C or 1.5 °C. For
example, in the NZE Scenario around 30% of today’s oil and natural gas reserves areproduced by 2050. However, this does not necessarily mean that large volumes of reserves
will be “stranded”. In the STEPS, around half of oil and gas reserves are produced to 2050. In
other words, a large amount of existing oil and gas reserves will not be used even undermuch higher temperature outcomes. There is undoubtedly a large difference in fossil fueluse between the scenarios, but the assessment of risks to the industry is better focused oninvestment and value losses rather than reserves.

IEA. CC BY 4.0

In the NZE Scenario, despite the sharp reductions in demand, the risk of stranded capital isrelatively low as it is mitigated by production decline rates that are consistent with no further
investment in new projects. Some fields are closed before the end of their technical lifetimes,
but most of these projects will have recovered their upfront capital by the time shut-in risks
appear. In the upstream sector, stranded capital risks therefore exist primarily in the form of
the sunk costs incurred in exploring for resources that are not ultimately developed in the
NZE Scenario; we estimate that this amounts to around USD 400 billion in total.
Stranded capital risks are also present for large-scale infrastructure projects in the midstream
part of the oil and gas value chain. These assets typically require a high rate of utilisation overtheir lifetime to recover their invested capital. In the NZE Scenario, none of the LNG export
projects under construction today are required. If all projects under construction were to be
developed, the drop in LNG demand in the NZE Scenario would mean the global average
Chapter 1 | Oil and gas in net zero transitions

61

1

utilisation rate of LNG plants would fall from around 80% of nameplate capacity today to
below 60% in 2030. In practice, these assets may still be able to avoid incurring stranded
capital if their commercial structure is based on fixed cost recovery and long-term offtakeagreements, but this would merely shift the losses onto a different entity. The risk of
stranded capital would increase significantly if there were delays or “stop-go” policies related
to emission reductions, or a misreading of market signals on the part of the industry.

Trillion USD (2022, MER)

Figure 1.32 ⊳ Net present value of upstream oil and gas production
14

NOCs and host governments

Private companies

12
10
8
6
4
2
STEPS

APS

NZE

STEPS

APS

NZE
IEA. CC BY 4.0.

The value of the oil and gas industry diminishes sharply with increased climate ambition.
Notes: Values shown for NOCs and host governments are the sum of pre-tax discounted net income; forprivate companies it is the post-tax discounted net income. Uses a discount rate of 10%.

IEA. CC BY 4.0

The more relevant metric for the financial sector and the oil and gas industry is likely to be
estimates of potential stranded value. If the expectations of the financial sector are thatdemand and prices will evolve in a similar way to the STEPS, private oil and gas companies
would have a total value today of just under USD 6 trillion (Figure 1.32). This value is cut byaround one-quarter in the APS and by 60% in the NZE Scenario. The net present value of
NOCs today is much higher than private companies, given their larger share of global
production from lower cost resources. Their value drops by a similar rate in the APS and NZE
Scenarios, but this equates to a much larger reduction in absolute terms. NOC income
generated for host countries is critical to the fiscal balances of many economies, and the dropin value is liable to negatively impact sovereign credit ratings unless efforts are made todiversify economies away from hydrocarbons (see Chapter 4).
For companies, stranded value could materialise as large-scale write-offs, damaging their
creditworthiness and raising the cost of both equity and debt. With lower asset andcorporate valuations, higher risks would be attached to companies that produce or transport
oil and gas, putting pressure on companies to diversify their business model and limiting the62

International Energy Agency | Special Reportscope for dividends and buybacks that have historically attracted investors to the sector.
Stricter lending criteria and restricted access to capital could also weigh on the ability of oil
and gas companies to raise debt, even for activities that might contribute to lower emissions.

1.7.2

Risks from underinvestment

If supply were to transition faster than demand, with a drop in fossil fuel investment
preceding a surge in clean energy technology deployment, this would lead to much higher
and more volatile prices, even if the world is moving towards net zero emissions. For
example, if the oil and gas industry invests for the NZE Scenario or APS, but demand
continues to grow for some time (as in the STEPS), there would soon be a major shortfall in
supply. This would lead to major issues over the security of supply, especially if only certain
parts of the oil and gas industry or geographies choose to cut back on production in advanceof wider efforts to cut demand.
The higher price that would result from underinvestment could reduce demand, but the
impact on emissions is less clear-cut. For example, the record high natural gas prices in theEuropean Union in 2022 resulted in a 3% increase in power sector emissions because ofincreases in the use of coal. High oil and gas prices are also highly regressive and cause
financial difficulties for more vulnerable households and those with limited access toessential energy products. High oil and gas prices can therefore have significant impacts on
economic growth and the competitiveness of particularly energy-intensive industries, andthey should not be viewed as a viable or desirable substitute for climate policies.

Billion USD (2022, MER)

Figure 1.33 ⊳ Historical investment in oil and gas and needs in 2030
Historical

1 000

2030

800
Natural
gas

600
400

Oil
200

2015

2017

2019

2021

2023

STEPS

APS

NZE
IEA. CC BY 4.0.

IEA. CC BY 4.0

Recent investment levels are much higher than required in the APS and NZE Scenario in
2030; the risks now appear weighted more towards overinvestment than underinvestment.

Chapter 1 | Oil and gas in net zero transitions

63

1

IEA. CC BY 4.0

Previous editions of the World Energy Outlook warned of a risk of underinvestment in a
STEPS-like trajectory for demand, with a gap between the amounts being invested in oil andgas and the future requirements of this scenario. The situation has evolved and this is nolonger the case (Figure 1.33). Oil and gas investment has risen in recent years and thebenchmark level of investment needed in 2030 has come down, meaning that the level ofinvestment in oil and gas expected in 2023 is now broadly equivalent to the level needed in
the STEPS. The fears espoused by some large resource holders and certain oil and gas
companies that the world is underinvesting in oil and gas supply are no longer based on thelatest technology and market trends. Indeed, the amount of investment expected in 2023 issignificantly higher than what is needed in the APS and almost double NZE Scenario levels in
2030. This implies that the oil and gas industry does not expect there to be any significant
near-term reduction in demand and, when it comes to the overall adequacy of current
spending trends, the risks are currently weighted more towards overinvestment in oil andgas than the opposite.

64

International Energy Agency | Special ReportChapter 2
Technology options for the oil and gas industry
S U M M A R Y• The production, transport and processing of oil and gas resulted in 5.1 billion tonnes(Gt) CO2-eq in 2022, just under 15% of total energy-related GHG emissions andequivalent to all energy-related GHG emissions from the United States. The emissions
intensity of the worst-emitting producers is currently five to ten times higher than thebest performers. In the NZE Scenario, these emissions are cut by more than 60% by
2030 and the emissions intensity of global oil and gas operations is near zero by theearly 2040s, with many individual producers achieving this considerably earlier.

• Methane emissions account for nearly half of the sector’s current scope 1 and 2
emissions. Tackling methane is the most important measure to reduce theseemissions. Other key levers include: eliminating all non-emergency flaring, electrifying
upstream facilities with low-emissions electricity, equipping oil and gas processes withcarbon capture utilisation and storage (CCUS), and expanding the use of
low-emissions hydrogen in refineries. The 60% cut in scope 1 and 2 emissions by 2030
in the NZE Scenario requires around USD 600 billion of spending to 2030.

• The oil and gas industry is investing in many clean energy technologies and a numberof options have a close affinity to its existing skills and resources. These technologies
address 30% of final energy consumption in the NZE Scenario in 2050 and include:• CCUS: the oil and gas industry is involved in 90% of CCUS capacity in operation. CCUS

and direct air capture are key technologies to achieve net zero emissions, especially insome difficult-to-decarbonise sectors, but they are not a way to retain the status quo.

• Low-emissions hydrogen and hydrogen-based fuels: oil and gas companies are
partners in a large share of planned hydrogen projects that use CCUS and electrolysis.
In the NZE Scenario, low-emissions hydrogen use rises by a factor of 110 to 2030.

• Bioenergy: more than half of total clean energy spending by the industry in 2022 wasin bioenergy as a number of companies took major stakes in bioenergy producers.

• Offshore wind: around 2% of offshore wind capacity currently in operation wasdeveloped by oil and gas companies. Plans are expanding, including for floating
turbines that are needed to tap the large wind potential in deep water.

• Geothermal: this sector shares many similarities with upstream operations, especiallyfor a number of new and emerging technologies. The industry is currently only
involved in a fraction of projects, but there are significant growth opportunities.

• Plastics recycling: a large number of planned chemical plastic recycling projects

involve oil and gas companies. The industry can play a key role in reducing the highemissions intensity of chemical recycling today.

IEA. CC BY 4.0• EV charging: the oil and gas industry is responsible for 15% of global investment inpublic EV chargers currently. The number of EV chargers increases five to sixfold by2030 to support the growth of electric light-duty vehicles in the APS and NZE Scenario.

Chapter 2 | Technology options for the oil and gas industry

65

2.1

Introduction

There is much the oil and gas industry can do to accelerate net zero transitions. An essential
first step is to reduce the emissions that occur during oil and gas operations. The process of
extracting oil and gas from the ground, processing it and transporting it to consumers resultsin considerable emissions. These emissions must be cut to near zero to achieve global climate
targets. A major reduction in methane emissions to the atmosphere by 2030 is the single
most important and cost-effective way for the oil and gas industry to bring down its
emissions.1
Net zero transitions ultimately require low-emissions electricity, liquids and gases to satisfy
the world’s demand for energy services without the associated emissions. This requires all
stakeholders – governments, businesses, investors and citizens – to take immediate andrapid action. The oil and gas industry can support and accelerate this process in multiple
ways. The skills and resources developed and honed by the industry during oil and gas
extraction, processing and transport have potential crossovers with many of the key clean
energy technologies needed to deliver net zero transitions. They include areas whereemission reductions are likely to be most challenging.
The industry also has an enormous degree of agency in how net zero transitions evolve.
Governments have to take the lead, but by advocating for supportive policies and conditions,and demonstrating ambition in line with net zero transitions, the oil and gas industry canhelp create a transition in which its core skills and expertise still have a place.
This chapter initially looks at current emissions levels from traditional oil and gas operations
around the world, the technologies and measures needed to cut these emissions, and theirdeployment in the Announced Pledges Scenario (APS) and Net Zero Emissions by 2050 (NZE)
Scenario. It then examines the oil and gas industry’s engagement with clean energy
technologies to date and looks at its potential to help scale up a selection of clean
technologies that should have a large degree of overlap with its existing skills and expertise.

2.2

Traditional oil and gas operations

2.2.1

Current emissions from oil and gas operations

The production, transport and processing of oil and gas resulted in 5.1 billion tonnes(Gt) CO2-eq in 2022 (Figure 2.1). These scope 1 and 2 emissions from oil and gas activities are
responsible for just under 15% of total energy-related greenhouse gas (GHG) emissions.2
1 Two reports, Emissions from Oil and Gas Operations in Net Zero Transitions (IEA, 2023a) and Financing

IEA. CC BY 4.0

Reductions in Oil and Gas Methane Emissions (IEA, 2023b), were published in 2023 to inform discussion onthese topics ahead of the COP28 Climate Change Conference in Dubai.

2 In this report, “scope 1” emissions are taken as emissions that come directly from the oil and gas industry
itself. “Scope 2” emissions arise from the generation of energy that is purchased by the oil and gas industry.
“Scope 3” emissions for the oil and gas industry occur mainly during the combustion of the fuels by end users.

66

International Energy Agency | Special ReportFigure 2.1 ⊳Breakdown of GHG emissions from oil and gas supply, 2022

Oil
3.4 Gt CO2-eq

Energy2%3%Natural gas
1.7 Gt CO2-eq
2%

Upstream methane
Refining

14%8%

Flaring

14%

8%

Crude transport

2

16%

Product transport
Downstream methane
34%

33%

Vented CO₂

22%

LNG
Pipeline

44%

IEA. CC BY 4.0.

Methane emissions account for nearly half of all GHG emissions fromoil and gas operations.
Notes: One tonne of methane is taken to be equivalent to 30 tonnes of CO2 based on a 100-year global
warming potential (IPCC, 2021). LNG = liquefied natural gas.

These emissions come from a variety of sources along oil and gas supply chains. Extracting
oil and gas from the subsurface requires large amounts of energy to power drilling rigs,
pumps and other process equipment and to provide heat. Most oil is refined prior to use andthis requires large quantities of energy, especially to produce the hydrogen that is used to
upgrade and treat the crude oil (Figure 2.2). Natural gas also undergoes processing toseparate natural gas liquids and remove impurities such as CO2, hydrogen sulphide andsulphur dioxide. Crude oil, oil products and natural gas are transported, often over long
distances, by both pipeline and by ship, and these processes are also an important source of
GHG emissions.

IEA. CC BY 4.0

There are multiple potential sources of fugitive and vented methane emissions along oil andgas supply chains. We estimate that upstream oil operations resulted in 45 million tonnes(Mt) of methane emissions in 2022, upstream natural gas operations around 25 Mt andnatural gas transport just over 10 Mt. This is equivalent to 2.4 Gt CO2-eq in total. Methane
emissions account for around two-thirds of total scope 1 and 2 emissions for natural gas.
Scope 1 and 2 CO2 emissions from oil and gas supply chains totalled 2.7 Gt CO2 in 2022. Of this,the energy required for oil and gas extraction and processing resulted in 0.7 Gt CO2. Refining,
including natural gas liquids (NGL) fractionation and bitumen upgrading, resulted in around
1.2 Gt CO2, and oil and gas transport resulted in a further 0.4 Gt CO2. Gas flaring, predominantly
at oil production facilities, resulted in 0.3 Gt CO2 emissions and we estimate 0.1 Gt of
naturally occurring CO2 was vented to the atmosphere during gas operations (Figure 2.3).
Chapter 2 | Technology options for the oil and gas industry

67

kg CO2-eq per boe

Figure 2.2 ⊳Spectrum of scope 1 and 2 emissions for oil, 2022

250

200
150
100
50

0

10

Upstream energy

20
Flaring

30

40

Methane50

60

Crude transport

70
Refining

90
mboe/dProduct transport
80

IEA. CC BY 4.0.

Oil operations were responsible for 3.4 Gt CO2-eq emissions in 2022,
nearly 10% of all energy-related GHG emissions.
Notes: kg CO2-eq per boe = kilogramme of carbon dioxide equivalent per barrel of oil equivalent;
mboe/d = million barrels of oil equivalent per day.

kg CO2-eq per boe

Figure 2.3 ⊳Spectrum of scope 1 and 2 emissions for gas, 2022

150

100

50

0
Upstream energy

1 000Vented CO₂

2 000
Pipe

LNG

3 000
Upstream methane

4 000
bcm
Downstream methane
IEA. CC BY 4.0.

Natural gas operations were responsible for 1.7 Gt CO2-eq emissions in 2022,
close to 5% of all energy-related GHG emissions.

IEA. CC BY 4.0

Note: bcm = billion cubic metres.

68

International Energy Agency | Special ReportPutting these figures together, around 105 kg CO2-eq is emitted on average for each barrelof oil equivalent (boe) produced; this is 20% of the full life cycle emissions intensity of oil
when combusted. Extraction, processing and refining account for 50 kg CO2-eq/boe,
methane emissions and flaring add nearly 50 kg CO2-eq/boe and transport operations add
5 kg CO2-eq/boe. For natural gas, scope 1 and 2 emissions are just over 65 kg CO2-eq/boe
produced, 15% of the full life cycle emissions of natural gas that is combusted.

Oil

100
200
kg CO₂-eq/boe
Extraction, processing and refining

Natural gas

Turkmenistan
Uzbekistan
Nigeria
Indonesia
China
Argentina
Malaysia
Australia
Algeria
Iran
RussiaIndia
United States
Canada
UAE
Oman
Egypt
Saudi Arabia
Qatar
NorwayTransport

Global average: 65

Venezuela
Libya
Iran
Algeria
Nigeria
China
MexicoKazakhstan
Iraq
Oman
RussiaQatar
AngolaCanadaUnited States
Brazil
UAE
KuwaitSaudi Arabia
NorwayCountrywide average emissions intensity of the largest oil andgas producers, 2022

Global average: 105

Figure 2.4 ⊳100
200
kg CO₂-eq/boe
Methane, venting and flaring
IEA. CC BY 4.0.

Among the world’s largest oil and gas producers, the emissions intensity of theworst performers is five to ten times higher than that of the better ones.

IEA. CC BY 4.0

Notes: Emissions from transport depend on the mode and distance travelled and are larger for countries thatexport a larger share of their production as LNG. Reflects estimates for 2022, which may differ from levels for2023 given the recent introduction of measures and policies by a number of countries and companies.
Sources: IEA estimates using: for energy for extraction and processing, a detailed field-by-field dataset createdby the Rocky Mountain Institute (RMI, 2023) using the Oil Production Greenhouse Gas Emissions Estimator(Brandt et al., 2022); for refining, process-level information from the Petroleum Refinery Life Cycle Inventory
Model (PRELIM) (Bergerson, 2022); for flaring, data from the World Bank (2023); for methane estimates, theGlobal Methane Tracker (IEA, 2023c); for transport, crude oil, oil product, LNG and pipeline trade, data fromIEA (2023d) and assumed distances and emissions intensities. See IEA (2023a) for further information.

Chapter 2 | Technology options for the oil and gas industry

69

2

There is a strikingly broad range of emissions for different types of oil and gas supply. The
emissions intensity of the worst-performing countries is five to ten times higher than thebest-performing ones (Figure 2.4). For oil, emissions intensity tends to be lower in places
where the oil is easy to extract (e.g. Saudi Arabia) or where refining and consumption takeplace close to the point of extraction (e.g. United States). Intensity is also typically lower inlocations that have low methane emissions (e.g. Norway) or produce light oil or NGLs, which
can be processed by simple refineries or bypass the refining sector entirely. Natural gas also
has a wide range of methane emissions intensity associated with production from different
regions. The high energy intensity of transport means that countries tend to have a higher
overall emissions intensity if they export a large share of their production as liquefied naturalgas (LNG) or by long-distance pipeline (LNG liquefaction results in around 5 kg CO2-eq/boe
globally on average).

2.2.2

Emission reductions to 2050 by scenario

In the APS, the global average scope 1 and 2 emissions intensity of oil and gas production
falls by around one-third between 2022 and 2030, and by 55% by 2050.

kg CO₂-eq/boe

Figure 2.5 ⊳100

Global average scope 1 and 2 emissions intensity of oil and gas
production by scenario and reduction measure to 2050

APS

NZE

80
60
40
20
2040
2022
2030
2050
2022
2030
Electrification and efficiency
Methane
Flaring
Hydrogen

2040
CCUS

2050
Transport
IEA. CC BY 4.0.

Emissions intensities fall by more than 50% by 2030 in the NZE Scenario, mainly from cuts inmethane. Flaring reduction, electrification, hydrogen use and CCUS also play key roles.

IEA. CC BY 4.0

Notes: CCUS = carbon capture, utilisation and storage applied to hydrogen production at refineries or to supply
refineries; also includes CCUS deployed in upstream facilities to abate co-produced CO2 emissions. Hydrogenis the use of low-emissions electrolysis hydrogen to replace hydrogen from unabated fossil fuels.

In the NZE Scenario, a concerted effort by all oil and gas companies worldwide to cut downon emissions means the global average emissions intensity of oil and gas production falls by
more than 50% between 2022 and 2030. This is broadly equivalent to all of the world’s oil
and gas companies performing close to the emissions intensity of the best operators today.
70

International Energy Agency | Special Report

The emissions intensity of upstream oil operations falls by around two-thirds to 2030 and it
falls by around one-third for refining. For natural gas, the upstream emissions intensity falls
by around 60% by 2030, with a near 55% reduction in the emissions intensity of gas transport.
Five key levers are used to drive these reductions in emissions intensity: tackling methane
emissions, eliminating non-emergency flaring, electrifying upstream facilities with
low-emissions electricity, equipping oil and gas processes with CCUS, and expanding the useof low-emissions electrolysis hydrogen in refineries. Cutting methane emissions is the single
most important measure that contributes to the overall fall in emissions from oil and gas
operations to 2030, followed by electrification and efficiency, and eliminating flaring(Figure 2.5). Scaling up CCUS and expanding the use of low-emissions hydrogen have a larger
impact in the NZE Scenario, as does the use of low-emissions fuels in ships transporting oil
and gas.
After 2030, total emissions from oil and gas operations fall to 0.4 Gt CO2-eq in 2040 and to
0.1 Gt CO2-eq in 2050 (Figure 2.6). By 2050, oil supply results in less than 10 kg CO2-eq/boe,with refineries responsible for around three-quarters of this; the emissions intensity ofnatural gas is less than 5 kg CO2-eq/boe.
Scope 1 and 2 oil and gas emissions in the APS and NZE Scenario

NZE
Upstream

APS
Downstream

2050

2040

2030

2050

2030

2022

2050

0.5

2040

1

2030

1.0

2050

2

2040

1.5

2030

3

APS

Natural gas

2.0

2040

Oil

4

2022

Gt CO₂-eq

Figure 2.6 ⊳NZE
IEA. CC BY 4.0.

IEA. CC BY 4.0

Emissions from oil and gas operations fall by more than 60% by 2030 and by 98% by 2050 in
the NZE Scenario. There are also large reductions in scope 1 and 2 emissions in the APS.

Around USD 600 billion of cumulative spending is required in the NZE Scenario to 2030 toachieve the greater than 50% reduction in the emissions intensity of oil and gas operations.
Electrification requires around USD 260 billion, CCUS another USD 110 billion, andlow-emissions hydrogen projects would demand nearly USD 80 billion. Methane and flaring
abatement, which together provide 70% of the reduction to 2030, each requires less than
Chapter 2 | Technology options for the oil and gas industry

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USD 80 billion of spending to 2030. Electrification and reducing methane and flaring can leadto additional income streams by avoiding the use or waste of gas, meaning they can quickly
recoup the upfront spending required. By 2030, these three measures could provide morethan 200 bcm of additional natural gas. Despite low gas prices in the NZE Scenario, these gas
sales would be worth around USD 30 billion on average each year.

2.2.3

Cutting methane and flaring

MethaneOil and gas operations were responsible for around 80 Mt of methane emissions in 2022 (afurther 40 Mt were released from coal operations) (Figure 2.7). 3 Methane constitutes nearly
half of total scope 1 and 2 emissions from the oil and gas sector, although there are
significant variations between different regions. Reducing methane emissions is the single
most important measure that companies can take to reduce their scope 1 and 2 emissions
intensity.
Figure 2.7 ⊳Methane emissions from fossil fuels, 2022
Upstream

Coal

Steam coal
Coking coalLigniteConventional

Oil

Unconventional
Other
Downstream

Natural gas

End-use
10

20

30

40

50 Mt
IEA. CC BY 4.0.

Upstream operations are responsible for 85% of methane emissions from oil and gas supply;
downstream emissions are mostly from natural gas transport and distribution.
Notes: Other includes emissions from gas transport facilities, refining and emissions at the point of end use.

Oil and gas sector methane emissions could be reduced globally by 75% by implementing
well-known measures such as leak detection and repair programmes and upgrading leaky
equipment. Stopping all non-emergency flaring and venting is the single most impactfulmeasure; that alone would cut methane emissions from oil and gas operations by nearly 20%.

IEA. CC BY 4.0

3 Information on policies and measures to reduce coal mine methane is available in the Global Methane

Tracker (IEA, 2023c) and Driving Down Coal Mine Methane Emissions: A regulatory roadmap and toolkit(IEA, 2023e).

72

International Energy Agency | Special ReportMethane abatement in the oil and gas industry is one of the cheapest options to reduce GHG
emissions anywhere in the economy. This is both because methane is a very potent GHG andbecause the gas that is captured can often be sold to offset the cost of the abatement
measure. We estimate that around 40% of methane emissions globally from oil and gas
operations could be avoided at no net cost (Figure 2.8).4 Even if there was no value to thecaptured gas, almost all available abatement measures would be cost-effective in thepresence of an emissions price of about USD 20/tonne CO2-eq. Methane abatement
nonetheless faces a number of challenges, including information gaps, missing infrastructureand economic barriers (IEA, 2021a). Government policy and regulation are critical toremoving or mitigating obstacles that prevent companies from getting started and goingfurther.
Figure 2.8 ⊳Oil and gas methane abatement cost curve at average
2017-2021 prices

USD/t CO2-eq

20
10
0

-10
-20

10
Oil upstream

20
Oil downstream

30

40
Gas upstream50
Gas downstream

60
Mt
IEA. CC BY 4.0.

Just over 60 Mt – more than 75% of current oil and gas sector methane emissions – can be
avoided with existing technologies. Around 40% of emissions could be cut at no net cost.

IEA. CC BY 4.0

Preventing and quickly addressing very large leaks is a key opportunity to rapidly reduce
methane emissions. The Methane Alert and Response System is one example of aprogramme that uses satellites to detect very large leaks and provide timely alerts tooperators and regulators (UNEP, 2023). The Oil and Gas Climate Initiative is also operating asatellite-monitoring pilot programme at sites in Iraq, Kazakhstan, Algeria and Egypt and plans
to expand the initiative to other countries (OGCI, 2023). Continuous monitoring systems arealso being deployed at a number of facilities to tackle fugitive sources and improve emissions
quantification.
4 Based on average natural gas prices from 2017 to 2021 and an 8% rate of return over the lifetime of themeasure.

Chapter 2 | Technology options for the oil and gas industry73

2

In the APS, methane emissions from oil and gas operations fall to around 45 Mt in 2030 and
20 Mt in 2050. Around half of the methane emissions from oil and gas operations currently
occur in countries that have pledged to act on methane, and some of the largest
emitters – including Russia, Iran, Turkmenistan and China – have not committed to absolute
methane reductions before 2030. In the APS, countries with pledges on methane – including
participants in the Global Methane Pledge, endorsers of the Global Methane Pledge Energy
Pathway, and countries with specific methane pledges (e.g. Qatar) – are assumed to act on
oil and gas methane. Companies with commitments on methane emissions also help tackle
some emissions in countries without pledges, including at non-operated assets and throughjoint ventures (IEA, 2023f).
In the NZE Scenario methane emissions from oil and gas operations fall by more than 75% to2030. Around 30% of this reduction stems from the drop in oil and gas demand over thisperiod. The other 70% occurs because of targeted efforts to cut methane from oil and gas
operations. In other words, even in the NZE Scenario, the reduction in oil and gas demand
must be complemented by additional, targeted abatement action on methane to ensure
emissions fall at a fast enough pace. Without explicit efforts to tackle methane emissions
from fossil fuel supply, global energy-related CO2 emissions would need to reach net zero byaround 2045 – five years earlier than in the NZE Scenario – with important implications forequitable pathways.
In the NZE Scenario, currently available methane abatement technologies are deployed at all
oil and gas production, processing and transport facilities by 2030. This means that all oil andgas companies would have an emissions intensity similar to the world’s best operators today.
Reductions in oil and gas methane emissions to 2030 account for more than 10% of the total
reductions in energy-related GHG emissions in the NZE Scenario over this period. Technology
improvements after 2030 help to nearly eliminate all non-emergency methane emissions by
2040 and continuous monitoring systems ensure large leaks are prevented and minor ones
quickly addressed. The global average methane intensity of natural gas supply falls fromaround 1.4% in 2022, to 0.5% in 2030 and 0.1% in 2050; for oil the methane emissions
intensity falls from 1.3% in 2022, to 0.3% in 2030 and 0.05% in 2050.5

IEA. CC BY 4.0

Around USD 75 billion of spending is required to 2030 to deploy all methane abatement
measures in the oil and gas sector. This is less than 2% of the net income received by the oiland gas industry in 2022. Most measures should be financed by the industry itself, but about
USD 15-20 billion may be challenging to mobilise without concessional financing or othermeans of support. This includes measures to cut emissions in low- and middle-income

5 The natural gas methane intensity is calculated here as total methane emissions from natural gas supply(37 Mt in 2022) divided by global marketed natural gas production (144 exajoules [EJ] in 2022), assuming
methane has an energy density of 55 megajoules per kilogramme. The oil methane intensity is methane
emissions from oil supply (45 Mt in 2022) divided by oil production (189 EJ in 2022). These intensities differ
from those reported by some companies and industry organisations, e.g. OGCI (2022), which are upstream oil
and gas methane emissions divided by natural gas production in volume terms (equivalent to a global averageof about 2.5% today using our estimates).

74

International Energy Agency | Special Reportcountries, at facilities owned and operated by national oil companies and smaller
independent companies, and for measures that do not generate a meaningful return overtheir lifetime (IEA, 2023b). This is an appropriate area for focused international action.

Flaring
Around 140 bcm of natural gas was flared in 2022, resulting in nearly 0.5 Gt CO2‑eq of GHG
emissions. This includes both CO2 from the combustion of the gas and NGL contained within
the gas stream, plus methane emissions. There should be minimal methane emissions froma flare if it is designed, maintained and operated correctly, but this is not always the case andsometimes flares are totally extinguished, resulting in direct venting to the atmosphere ofgas that should be combusted. We estimate that only around 92% of the gas volumes
directed into flares around the world are properly combusted (IEA, 2023c).
CO2 combustion emissions from flaring and flaring intensity in the
APS and NZE Scenario, 2010-2030

300

6

200

4

m³/bblMt CO₂

Figure 2.9 ⊳World
EuropeAsia Pacific
C & S America
North America

1002Middle East
Eurasia
Africa

2015

2020

2022

2025 2030
APS

2025 2030
NZE

Intensity(right axis)
IEA. CC BY 4.0.

Flared volumes fall by more than 60% by 2030 in the APS and by about 95%
in the NZE Scenario as all non-emergency flaring is eliminated globally.
Notes: C & S America = Central and South America; m3/bbl = cubic metres per barrel.

IEA. CC BY 4.0

The Zero Routine Flaring by 2030 Initiative, launched by the World Bank and theUnited Nations in 2015, commits governments and companies to end routine flaring no later
than 2030. There has been some progress since its launch – the amount of gas flared per
barrel of oil produced fell by close to 10% in 2022 from 2021 – but the total gas flared globallyis still very high.
Nearly 95% of the GHG emissions from flaring are abatable with existing technologies. There
are many options to use the natural gas that is currently flared, including bringing it toconsumers via a new or existing gas network, reinjecting it to support reservoir pressure, andChapter 2 | Technology options for the oil and gas industry

75

2

converting it to LNG, compressed natural gas (CNG), methanol, fertilisers or power with
CCUS. Flares can now be monitored every day on a near real-time basis, helping companies
to identify bottlenecks and opportunities in operated and non-operated assets. Mobilemini-LNG production equipment can reduce the need for flaring and venting during well
testing and other short-term operations. Automated controls can ensure flares operate at
optimal levels, reducing the amount of methane that escapes from the combustion process.
With the exception of gas injection, gas that is saved can often be resold, depending on local
gas markets or the ability to export, significantly lowering the net cost of abatement.
In the APS, flared volumes fall by around 20% to 2025 and by more than 60% to 2030
(Figure 2.9). This is mostly due to flaring reduction projects in countries committed to theZero Routine Flaring by 2030 Initiative. Action from countries with pledges to curb methane
emissions (e.g. Global Methane Pledge) also play a significant role, as incomplete combustionin flares is a leading cause of methane emissions and related mitigation efforts also help
reduce flaring volumes. In 2030 flaring remains at high levels in some major producers, suchas Russia, and only partial reductions are achieved from levels in 2022 in regions where
governments have not pledged to act, but key industry players have (e.g. Algeria).
Figure 2.10 ⊳ Emission reduction potential and average cost of flaring
200

80

150

60

100

40

50

20

0

0

- 50

-20

- 100

Major
pipelines

LNG

Emissions reduction

CNG

Power

Other
pipelines

Injection

USD per t CO₂-eq

Mt CO₂-eq

reduction measures in the NZE Scenario, 2022

-40

Cost with gas revenue (right axis)
IEA. CC BY 4.0.

Around two-thirds of emissions from flares could be avoided at no net cost because the valueof the captured gas in the NZE Scenario is sufficient to cover the cost of abatement.

IEA. CC BY 4.0

Notes: Abatement measures selected according to flare size and distance from existing infrastructure(Omara, et al., 2023). Gas income is based on prices to 2030 in the NZE Scenario. Power projects include CCUS.
Major pipelines carry more than 280 000 m3 of gas per day.
Sources: IEA analysis based on data provided by EDF (2022), the World Bank Global Gas Flaring Reduction
Partnership (World Bank, 2023), the Methane Guiding Principle’s Cost Model (MGP, 2022), and Capterio(Charles & Davis, 2021).

76

International Energy Agency | Special ReportIn the NZE Scenario, all non-emergency flaring is eliminated globally by 2030, resulting in anear-95% reduction in flared volumes by 2030. Around USD 70 billion of upfront spending isrequired up to 2030 to achieve these reductions, but in many cases the value of the captured
gas is sufficient to cover the cost of the abatement measure. The most cost-effective solution
is to bring the gas to market via new pipeline connections to gas transmission or distribution
grids, or to CNG or LNG terminals, and this is where most of the capital expenditure isdirected. Close to 90% of emission reduction measures would be cost-effective to deploy inthe presence of an emissions price of USD 15/t CO2-eq and almost all measures would costless than USD 60/t CO2-eq to deploy (Figure 2.10). In aggregate, even with the low gas prices
seen in the NZE Scenario, the value of the captured gas that could be sold is greater than theamount of spending required to 2030.
Despite the cost-effectiveness of many flaring abatement options, reduction projects canface a number of challenges, including information gaps, institutional barriers andopportunity costs. Policy and enforced regulation play a critical role in reducing flaring;
Norway put in place a ban in 1971 and has successfully managed to keep very low levels of
flaring despite ongoing production, while Brazil and the United Kingdom impose a cap on
flaring and require operators to shut down production if they breach flaring limits.

2.2.4

Boosting efficiency and electrifying oil and gas facilities

The energy required for upstream oil and gas operations in 2022 resulted in more than
700 Mt CO2 emissions. Around 10% of this total is associated with Canadian oil sands
production, which requires significant quantities of natural gas. In more conventional
upstream operations, energy is mainly required to power electrical equipment, and theelectricity is often produced using small-scale on-site natural gas or diesel generators. Using
more efficient equipment – such as swapping an open-cycle gas turbine for combined-cycle– would save around 30% of the energy required. But full electrification would lead to evengreater efficiency improvements.
The energy for upstream facilities could be provided by electricity from a centralised grid or
generated in a decentralised renewable energy system. Operators face several choices when
implementing an electrification programme, including:

Selecting the appropriate technology and design (whether to use direct or alternating
current cables, or choosing the right mix of wind, solar and battery capacity).



Assessing total costs in the context of the capital required to build sufficient renewablecapacity or grid connections, as well as the price of the electricity and natural gas andthe value of avoided CO2.

IEA. CC BY 4.0

It is also important to ensure a continuous, reliable source of energy to maintain operations
and ensure safety; several solutions are available to do so, including the use of batteries,
hybrid systems or the retention of existing assets for back-up power.

Chapter 2 | Technology options for the oil and gas industry

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We have carried out detailed geospatial analysis to estimate the potential for and costs ofelectrifying upstream facilities through both of these methods: centralised grid connectionsvs decentralised renewable systems. We estimate that more than half of global oil and gas
production today lies within 10 km of an electricity grid and three-quarters takes place in anarea with good wind or solar resources. Some of the lowest-cost options are production sites
close to electricity infrastructure in countries with relatively low electricity prices or inrenewables-rich areas with plenty of available land (as in the Middle East and North Africa).
Grid connections are a viable solution in onshore oil and gas fields that lie relatively close tobuilt-up areas; this is the preferred option in North America and Eurasia. Offshore sites are
generally more costly to electrify as many platforms are far from the coast, are located indeep waters and operate in harsh environments (Figure 2.11).
Figure 2.11 ⊳ Cost of electrifying oil and gas production sites
USD/t CO₂

100
80
60
40
20
0
-20

0

Dedicated renewables:100
Onshore200
Offshore

300
Grid:

Onshore400
Mt CO₂
Offshore
IEA. CC BY 4.0.

CO2 emissions from upstream operations could be cut by more than 400 Mt CO2 – reducing
total upstream CO2 emissions by 60% – by electrifying upstream facilities.

IEA. CC BY 4.0

Note: Based on regional natural gas prices to 2030 in the NZE Scenario (USD 2-6 per million British thermal
units [MBtu]).

Most electrification options would incur a net cost to operators, even when accounting for
efficiency gains and the sale of the additional oil and gas not required. Policy or regulatory
incentives are therefore necessary to stimulate the required upfront investment. This could
take the form of a CO2 price – which provided the spur for development in Norway – or mightcome in the form of tax breaks or exemptions on a portion of electricity tariffs. Costs could
be kept down if operators collaborated to build shared clean electricity infrastructure thatwould feed wider areas of production, an example being recent efforts by companies
operating in the North Sea. Project economics could also be improved by crediting avoided
CO2 or selling surplus renewable electricity back to the grid.

78

International Energy Agency | Special ReportIn the APS, around 150 Mt CO2 is avoided through electrification in 2030 and 200 Mt CO2 in
2050. In the NZE Scenario around 320 Mt CO2 emissions are avoided in 2030 (Figure 2.12).
This requires nearly 800 terawatt hours (TWh) of electricity, of which around 60% is supplied
through dedicated renewable installations and the remainder from grid connections. By
2040, essentially all oil and gas sites that are still in operation are electrified. On average thecost of electrifying fields in this scenario adds USD 0.35/boe of production.
Figure 2.12 ⊳ CO2 emissions avoided by electrifying upstream oil and gas
Mt CO₂operations in the NZE Scenario, 2030

80

Dedicated
renewables:
Offshore60

Onshore40
Grid:Offshore

20

OnshoreNorth Middle
America East

Asia
Pacific

Eurasia

C&S
America

AfricaEuropeIEA. CC BY 4.0.

Most of the near-term opportunities for electrification
come from the construction of dedicated renewable sites.
Note: C & S America = Central and South America.

2.2.5

Reducing emissions from refining and LNG facilities

Refineries

IEA. CC BY 4.0

Oil refineries caused 1.1 Gt CO2 emissions in 2022, of which 800 Mt CO2 was from energy use
on-site and 350 Mt CO2 was from the production of electricity and hydrogen purchased from
off-site sources. Emissions arise from processes including catalytic cracking and petroleum
coke processing, as well as hydrogen, heat and electricity production. A very small amountof methane emissions also occur during refining (around 0.2% of total GHG emissions fromthe oil supply chain and 0.5% of GHG emissions from refining operations). The two key
mechanisms to cut emissions from refineries are the use of low-emissions hydrogen and
CCUS.
The production of hydrogen is one of the major sources of emissions from refineries. Globallyaround 42 Mt of hydrogen is used to refine and upgrade oil – nearly half of global hydrogen
demand today – resulting in around 380 Mt CO2 annually. Some 20% of the hydrogen
Chapter 2 | Technology options for the oil and gas industry

79

2

consumed in refineries comes from external suppliers. Refineries are well-suited for the
deployment of low-emissions hydrogen because they can accommodate a new source ofhydrogen without the need for new end-user equipment. 6 Refineries can be “anchor”
sources of demand for scaling up low-emissions hydrogen supply, reducing the risks forsecond-mover applications in the vicinity that face the complexity of synchronising
investment in low-emissions hydrogen supply with investment in hydrogen demand
technologies.
Some of the largest projects in operation or under construction globally to produce hydrogenfrom electrolysis are being developed by oil and gas companies or will supply hydrogen to arefinery. This includes a 260 megawatt (MW) electrolyser to produce hydrogen for a refinery
in China and a 200 MW electrolyser to replace hydrogen from a natural gas reformer in the
Netherlands. Oil and gas companies are involved in more than 300 electrolysis projects
already in operation or in development, with an average capacity of just under 1 gigawatts(GW). In addition to the advantages related to their relative ease of integrating low-emissionshydrogen, refineries are often in locations that are well-suited to deploying renewableelectricity, reducing the need for new infrastructure.

Mt of hydrogen

Figure 2.13 ⊳ Hydrogen use by refineries in the APS and NZE Scenario
APS

50

NZE

Low-emissions:
Natural gas with CCUS
Coal with CCUS

40

Electrolysis

30

Unabated:Natural gas

20

Coal

10

By-product:Oil2010 2022

2030 2040 2050

2030 2040 2050
IEA. CC BY 4.0.

Low-emissions hydrogen is deployed at scale in refineries by 2030,
and replaces hydrogen from unabated coal and natural gas by 2050.

IEA. CC BY 4.0

Notes: CCUS = carbon capture, utilisation and storage. Data includes both hydrogen produced on-site atrefineries and that procured from external facilities. By-product hydrogen is produced from other refinery
processes, such as catalytic reforming or petrochemical facilities.

6 Low-emissions hydrogen includes hydrogen produced from water using electricity generated by renewables,
nuclear, bioenergy, or fossil fuels equipped with CCUS with a high capture rate (IEA, 2023g). Demand for
low-emissions hydrogen includes its use to produce hydrogen-based fuels.

80

International Energy Agency | Special ReportIn the APS, total refinery demand for hydrogen is broadly flat to 2030, but an increasing
amount comes from low-emissions sources (Figure 2.13). Including hydrogen purchasedfrom off-site sources, around 3 Mt of low-emissions electrolysis hydrogen is used inrefineries in 2030, a value that increases moderately to 2050. This requires around 40 GW ofelectrolyser capacity and around 130 TWh of low-emissions electricity. Refinery hydrogenuse declines after 2030 as refinery activity diminishes, and this means the share of
low-emissions electrolysis hydrogen in total hydrogen use climbs from very low levels today
to 7% in 2030 and more than 20% in 2050.
In the NZE Scenario, around 4 Mt of low-emissions electrolysis hydrogen is used in refineriesin 2030. This volume remains stable to 2050 despite the sharp overall decline in hydrogenused in refineries; the share of low-emissions electrolysis hydrogen in overall use climbs from
10% in 2030 to nearly 40% in 2050 (most of the remaining hydrogen used in 2050 comes asa by-product from other refinery processes).
The cost of avoiding one tonne of CO2 through the use of low-emissions electrolysis hydrogen
ranges widely depending on the relative prices of fossil fuels and costs of renewable andnuclear electricity. Costs are lowest in regions where imported natural gas prices are
relatively high and renewable electricity costs relatively low, which include India and parts of
Latin America. In these regions, the use of low-emissions electrolytic hydrogen in 2030 would
add around USD 1.4/bbl to the cost of refining a barrel of oil. In Europe and North America,
the costs are less favourable, but would still only add around USD 3/bbl to the cost.
The use of CCUS can also help reduce emissions from refineries. Hydrogen production units
create a relatively pure stream of CO2 that is often vented; this accounts for 60% of the total
CO2 emitted by a steam methane reformer and it is relatively straightforward to capture it.
Coal- and natural gas-based hydrogen units can be designed for 95% CO2 capture or higher
to meet expectations for lower emissions intensity of hydrogen supply. CCUS can also reduce
emissions from catalytic crackers, heat plants and power generation at refinery sites.

IEA. CC BY 4.0

Equipping hydrogen production with CCUS costs USD 25-45/t of CO2 avoided (for coal) or
USD 50-90/t of CO2 avoided (for natural gas). This would add just USD 0.6-1/bbl to the costof refining, with costs around twice as high for other onsite CO2 sources where the size ofthe individual CO2 streams are smaller (IEAGHG, 2017). Many refineries are located close towhere extracted oil and gas are brought onshore and so are near geology that is potentiallywell-suited to underground CO2 storage, lowering the costs of CCUS for refineries comparedwith other types of facility. It is estimated that some two-thirds of existing refineries arelocated within 50 km of potential storage for CO2 (IEA, 2022a).
Learnings from the financing, construction and operation of CCUS for refineries cancontribute to cost reductions for CCUS in other sectors, such as cement production. The
involvement of oil and gas companies can also help develop new geological CO2 storage
resources to underpin future deployment elsewhere in the economy. The integration of
bioenergy represents another opportunity for refiners to make an active contribution to net
zero transitions by helping to scale up the cost-effective production of liquid biofuels (seeChapter 2 | Technology options for the oil and gas industry

812Section 2.3.3). Some companies are also looking to deepen integration with petrochemical
operations, which could offer operational synergies and enhance feedstock flexibility whileproviding a hedge against a possible peak in demand for road transport fuels.
In the APS, CO2 captured from refinery-related installations grows from around 8 Mt CO2 in
2022 to more than 120 Mt CO2 in 2030 (Figure 2.14). Most is captured on-site at refineries
from hydrogen production. Volumes captured rise further to 2040 and then remain aroundthat level given the downward trend in refinery throughput. In total, the use of CCUS andelectrolysis hydrogen – alongside other emission reduction measures taken by refiners,
including the use of electricity and bioenergy for heat – means the scope 1 and 2 emissions
intensity of refining falls from around 35 kg CO2/boe processed in 2022 to 28 kg CO2/boe in
2030 and just under 20 kg CO2/boe in 2050.

Mt CO₂

Figure 2.14 ⊳ CCUS use by refineries and trends in the APS and NZE scenario
APS

250

NZE

50%

Captured frompurchased hydrogen

200

40%

Captured on-site

150

30%

Share of total CO₂
captured (right axis)

100

20%

50

10%

2022

2030 2040 2050

2030 2040 2050
IEA. CC BY 4.0.

Refineries play a leading role in the deployment of CCUS this decade, helping to launch a
global CCUS industry in other sectors, which come to dominate total CO2 captured by 2050.

In the NZE Scenario, trends in the use of CCUS in refineries to 2030 are similar to the APS.
After 2030 the sharp reduction in refining activity means that the increase in CO2 captured
from refineries also starts to decline. In total, the use of CCUS, low-emissions hydrogen andother emission reduction measures means that the scope 1 and 2 emissions intensity ofrefining falls to around 23 kg CO2/boe in 2030 and just over 7 kg CO2/boe in 2050.

IEA. CC BY 4.0

LNG
Liquefying natural gas is an energy-intensive process that emits anywhere in range of
50-150 kg CO2-eq per boe from extraction of the raw feedgas to delivery to end consumers.
Around 40% of this comes from cooling the gas down to -162 °C, a process that is usually
powered by consuming a portion of the gas flowing to the (often remote) facility. The amountof gas used in this way varies markedly between facilities, but averages around 10% globally.
82

International Energy Agency | Special Report

The total emissions associated with the LNG value chain – liquefaction, shipping andregasification – are estimated to be around 130 Mt CO2-eq. Emissions from the upstream
feedgas add a further 120 Mt CO2-eq (Figure 2.15). Upstream methane is in some cases
difficult to directly attribute to individual liquefaction facilities, but on average it accounts
for around one-third of the overall LNG supply emissions. Another key variable is the CO2
content of the natural gas feeding the LNG terminal. The typical range is from 5% to 15% CO2
on a molar basis. Producing LNG requires the removal of this CO2 to avoid hydrate andfreezing issues during liquefaction. This CO2 is often vented to the atmosphere; we estimate
around 20 Mt CO2 is vented, primarily in the pretreatment phase.

kg CO2-eq per boe

Figure 2.15 ⊳ Spectrum of emissions intensity of LNG supply, 2022
150

Downstream
methaneUpstreammethane100

LNG
Vented CO₂

50

Upstream
energy
0

100

200

300

400

500

bcm
IEA. CC BY 4.0.

The global LNG supply chain emits around 300 MtCO2-eq. The most energy-intensive part ofthe process is gas liquefaction, requiring around 10% of the feedgas for export terminals.

IEA. CC BY 4.0

A handful of projects globally have made dedicated investments to reduce emissions
associated with the LNG value chain, and efforts have also been made to measure theemissions associated with LNG cargoes. The 21 bcm Gorgon LNG facility in Australia and7 bcm Hammerfest LNG in Norway employ CCUS in the gas processing and pretreatment
stages. In the case of Gorgon, the project was designed to capture and inject around 4 Mt CO2
per year, but issues around the presence of sand in the facility have resulted in lower
injection rates. Although there are no projects in operation today that use CCUS to reduce
emissions from liquefaction, Qatar has announced a plan to fit CO2 capture on ten of itsliquefaction trains, with the aim of capturing around 4 Mt CO2 per year. Costs would vary by
project scale and experience, but would likely average around USD 60/t CO2 avoided, which
would translate into an increase of around USD 0.25/MBtu in the cost of the liquefaction
process (around a 20% increase in costs) (IEAGHG, 2019).
Another way to lower emissions from LNG is to electrify the liquefaction process. Traditional
natural gas liquefaction processes use gas turbines or internal combustion engines to drive
the liquefaction refrigeration cycle. Electrification involves replacing these with electric
Chapter 2 | Technology options for the oil and gas industry

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motors, and these can be powered either by low-emissions electricity from the grid or
dedicated renewable installations backed by batteries or thermal back-up power. A handfulof projects have been pursued in this space, such as Freeport LNG in the United States, LNG
Canada, Hammerfest LNG in Norway and Curtis Island in Australia, albeit with mixed levelsof implementation success to date.
Through a detailed geospatial assessment of proximity to nearby electricity infrastructureand solar and wind potential, we estimate that 60% of the world’s LNG export terminals in
operation in 2030 in the NZE Scenario can be electrified, at a total cost of around
USD 20 billion. This would avoid around 70 Mt CO2 and would add around USD 0.60/MBtu tothe delivered cost of the LNG. Another option proposed to align LNG plants with net zerotransitions is to convert them to be hydrogen-ready (Box 2.1).
Box 2.1 ⊳Can LNG infrastructure be hydrogen-ready?

The energy crisis precipitated by Russian cuts to gas deliveries to Europe incentivised
investment in non-Russian supplies, new trade infrastructure – notably for LNG – andalternatives to natural gas. But with the future of natural gas unclear in regions withstrong climate policies, such as Europe, companies have been searching for other ways
to future-proof natural gas infrastructure, including making the assets ready for atransition to hydrogen at a later date.
In the NZE Scenario, LNG trade in 2030 is around 1 EJ lower than in 2022, while trade inhydrogen and hydrogen-based fuels increases to 2 EJ (90 bcm equivalent [bcme])(Figure 2.16). To understand whether investments can bridge from one fuel to anotherand thus retain economic value into the 2030s, analysts have set to work on what
“hydrogen-ready” – an as-yet undefined term – could mean for LNG in practice.
The liquefaction technology used for LNG is not reusable for hydrogen. If hydrogen were
to be transported in liquid form, it would have to be cooled to -253 °C, around 100 °C
colder than for natural gas. The cooling systems, storage facilities and tankers could
potentially be augmented from the outset to be compatible with these lower
temperatures – with special thermal insulation to minimise high boil-off rates duringstorage – but even with this additional investment, which would be considerable, thepumps and valves are likely to need replacing before transitioning to hydrogen.

IEA. CC BY 4.0

The energy that can be exported through hydrogen liquefaction is lower than for naturalgas. Hydrogen liquefaction requires 20-30% of the input energy, compared with around
10% for LNG. In addition, liquefied hydrogen has a lower energy density, meaning thatthe same sized storage facilities and ships can each hold less energy. Converting LNG
facilities to hydrogen facilities could benefit from the port infrastructure, brownfield siteand connections to energy networks, but there are likely to be few synergies between
some of the most capital-intensive equipment. There also may not be a perfect overlap

84International Energy Agency | Special Reportbetween the location of LNG liquefaction terminals and the availability of low-cost
renewable electricity to produce low-emissions electrolytic hydrogen.
Figure 2.16 ⊳ Key indicators for hydrogen, selected hydrogen-based fuelsand LNG trade in the NZE Scenario

Number of tankers

Trade(bcme)

600

900

30

400

600

20

200

300

10

1990 2010 2022 2030 2050

2022 2030 2050

Liquid hydrogen

Ammonia2

Terminal investment(Billion USD [2022, MER])

2022 2030 2050
LNG
IEA. CC BY 4.0.

The lower energy density of hydrogen means more ships are
required to ship the same energy content carried in LNG vessels.
Note: bcme = billion cubic metres equivalent.

If hydrogen were converted to ammonia for transport, more of the existing LNG
infrastructure might be reusable. Ammonia has an energy density closer to that of LNG
and an ammonia-ready LNG import terminal is estimated to be just 7-12% more
expensive than a conventional LNG import terminal, well within the range of historical
average cost overruns (IEA, 2022b). Another option is to the spread cost by constructing
shared LNG and ammonia terminals, and this has been proposed, for example inGermany. Whether operators will find a business case for converting the ammonia backto hydrogen at the import site remains subject to tests of the technology in coming years.

IEA. CC BY 4.0

A third possibility is to convert the hydrogen to synthetic methane or construct pipelines
to gather large volumes of biomethane, both of which can then use the existing LNG
infrastructure without modification. A source of carbon is needed, which could add
considerable cost: in the NZE Scenario, low-emissions synthetic fuels are exclusively
made with carbon recovered from CO2 captured from bioenergy or the air.
In all cases, the environmental benefits will hinge on avoiding any escape of methane
into the atmosphere along the value chain.
Chapter 2 | Technology options for the oil and gas industry

85

Repurposing gas pipelines
Existing gas pipeline infrastructure can potentially be repurposed or reused to fast-track the
deployment of CO2 or hydrogen infrastructure, reducing lead times and the amount and costof new infrastructure that would need to be built. Repurposing can lower a project’s overall
environmental footprint by reducing material demand, and it can help infrastructure owners
maximise the economic lifetime of their assets while reducing or deferring decommissioning
costs.
Hydrogen blends of up to 20% by volume (6% in energy terms) can be achieved with minimal
modifications to gas pipelines, depending on their material composition. Fully converting gas
pipelines to transport hydrogen is a more complex process; to operate a repurposed pipelineat its full design capacity, volumetric flows of hydrogen would need to be three times higher
due to the lower volumetric density of hydrogen compared to natural gas. This would require
more powerful and costly compressors. But it may nonetheless be cost-competitive against
building new, dedicated hydrogen infrastructure, cutting investment costs by 50-80%
relative to building new lines (IEA, 2023h).
Gas pipelines may also be used to carry CO2, with existing and under-development projects
in the United Kingdom, the Netherlands and the United States. Screening pipelines for theirstrength and pressure rating, alongside other integrity tests, would be essential to establish
their potential for safely transporting CO2.

2.3

New technology options

IEA. CC BY 4.0

The oil and gas industry has invested in a broad range of clean energy technologies in recent
years (Figure 2.17). Capital flows towards them have, to date, been small relative to overall
capital expenditure by the industry, but have been motivated as a hedge against possible
future declines in oil and gas demand, as an opportunity to grow new business areas in theemerging energy economy, and to comply with policies and regulations that limit theemissions intensity of energy supplied to the market.
A number of clean energy technologies have a close affinity with existing skills and resourcesin the oil and gas industry. They include technologies that can make use of the industry’s
know-how in handling liquids and gases, large financial resources, extensive research anddevelopment expertise, technical and operational knowledge (especially of subsurface anddrilling and offshore infrastructure), and proficiency in executing and managing multi-billion
dollar projects. Many of the technologies can also take advantage of existing transmission
and distribution infrastructure for oil and gas. Options include CCUS, low-emissions hydrogenand hydrogen-based fuels, offshore wind, geothermal, bioenergy, plastics recycling andelectric vehicle (EV) charging. These technologies can play a central role in helping to tackle
emissions from some of the hardest-to-abate sectors and they provide or address nearly 30%
of total final energy consumption in the NZE Scenario in 2050 (Figure 2.18). These
technologies also provide a large investment opportunity, reaching USD 350 billion in 2030
in the APS and more than USD 500 billion in the NZE Scenario (Figure 2.19).
86

International Energy Agency | Special ReportFigure 2.17 ⊳ Average annual investment in clean energy technologies,
2019-2022

118

100%

252

51

0.4

1

8

Billion USD (2022, MER)
Other
companies

80%

2

Oil and gas
companies

60%
40%
20%

Onshore
wind

Solar
PV

Offshore Hydrogen
wind

CCUS

Bioenergy
IEA. CC BY 4.0.

Oil and gas companies provide a notable share of total investment in certain clean energy
technologies – especially CCUS and bioenergy – but overall spending levels are still low.

Figure 2.18 ⊳ Final energy consumption met using one or more of the new
EJtechnology options in the NZE Scenario, 2022-2050

500

Other energy consumption
Geothermal
Biomethane
Liquid biofuels
CCUS
Offshore wind
Hydrogen and H₂-based fuels

400
300
200
100

2022

2030

2050
IEA. CC BY 4.0.

IEA. CC BY 4.0

Companies engaged in clean energy technology areas that draw upon oil and gas
industry strengths could provide or address 30% of all energy consumed in 2050.
Notes: H2 = low-emissions hydrogen. Where the final energy product is supplied via more than one technology
options – such as offshore wind electricity that feeds electrolysis for hydrogen or CCUS-equipped hydrogenproduction – it is allocated equally between the categories. Excludes EV charging.

Chapter 2 | Technology options for the oil and gas industry

87

Figure 2.19 ⊳ Annual investment in technologies that share synergies with theskills and expertise of the oil and gas industry

Offshore wind
Hydrogen

2022

Bioenergy

2030

CCUS
EV charging

APS

Plastic recycling
Geothermal

NZE

100

200

300

400

500 Billion USD (2022)
IEA. CC BY 4.0.

There is a USD 350-500 billion annual investment opportunity in clean energy technologies
in 2030 that are suited to the skills and expertise of the oil and gas industry.

None of these technologies are a perfect fit for all companies and they can demonstrate
important differences from traditional oil and gas operations. One area that is often cited is
the returns on capital invested (Box 2.2). Some National Oil Companies may not have amandate to move beyond traditional operations. Other factors inside oil and gas companies
may also hinder the development of clean energy activities, including limited managerial
bandwidth to operate both legacy businesses and new activities. If oil and gas companies
choose not to be involved in the deployment of these technologies, this does not mean thatthey will not be successfully deployed, but it may take much longer for them to reach thelevel of maturity where they can be supplied cost-competitively.
The remainder of this section looks in detail at each of these technologies, including the role ofthe oil and gas sector to date, what happens to the technology in the APS and NZE Scenario,
and how it matches or differs from the skills and expertise of the oil and gas industry.

IEA. CC BY 4.0

Box 2.2 ⊳Returns on capital for traditional oil and gas and clean energy

A key consideration for any oil and gas company looking to develop new business areas
is in the anticipated returns, especially compared with returns from traditional
operations. Returns depend on factors such as geographical location and sales market,
and vary between different types of companies (e.g. the majors and independents), but
we estimate that the return on capital employed (ROCE) in the oil and gas industry
averaged 6-9% between 2010 and 2022. Integrated companies tend to appear towards
the upper end of this range and refiners towards the lower end (Figure 2.20).

88

International Energy Agency | Special Report

The average ROCE masks a high degree of variability for individual years. For example, ina high-price year (e.g. 2022), integrated and upstream pure players made as much as
20-25%, and in a lower-price year (e.g. 2016) they saw returns fall close to zero or below.
Pipeline operators tend to see a more stable ROCE due to the regulatory environment inwhich they typically operate.
Most of the clean energy technology investments have delivered returns of around 6%
since 2010. Some exhibit a similar volatility and sensitivity to fuel prices – very high insome years and very low or negative in others – and can reach double-digit ROCE in
certain years. However, other technologies – such as offshore wind and geothermal – seeless annual variation in the ROCE, with stable returns due to long-term contracts andgreater revenue certainty.
Renewables projects with fixed offtakers tend to have lower volatility in returns than oil
and gas projects and they also generally have a lower risk profile. Shareholders in oil andgas companies that are accustomed to high – and volatile – returns may therefore
struggle with the different profile of clean energy technologies.
Figure 2.20 ⊳ Return on capital employed for selected oil and gas andclean energy businesses, 2010-2022

Oil and natural gas

Return in low-priceenvironment

Integrated
Pipelines

Average return

Upstream
Refining

Distribution

Clean fuels
Biofuels

Return in high-priceenvironment

BiogasClean power
Geothermal
Offshore wind
-5%

0%

5%

10%

15%

20%

25%
IEA. CC BY 4.0.

Investment opportunities in clean energy can yield average returns that are
similar to those of the oil and gas industry and, for clean power, are much less volatile.
Notes: Return on capital employed is a measure of the efficiency with which capital (assets minus current
liabilities) is employed. “High-price environment” is data for 2022 (oil price above USD 95/bbl andimported natural gas prices above USD 15/Mbtu); “low-price environment” is data for 2016 (oil pricebelow USD 50/bbl and imported natural gas prices around USD 6/Mbtu). For clean power technologies,
the “high price environment” is data for 2014 and "low price environment" for 2020.

IEA. CC BY 4.0

Source: IEA analysis of a sample 800 companies from 2010 to 2022 based on data from S&P Global (2023).

Chapter 2 | Technology options for the oil and gas industry

892

2.3.1

Carbon capture, utilisation and storage

CCUS is an essential technology for achieving net zero emissions. It prevents emissions insituations where non-fossil alternatives are particularly costly, such as cement manufacture
and petrochemicals, and allows for CO2 removals and it delivers just under 10% of the
cumulative CO2 emissions savings from 2022 to 2050 in the NZE Scenario. Deploying CCUS at
the necessary pace and scale will be contingent upon action by governments, regulators andother stakeholders to ensure sufficient value is attached to avoiding and removing CO2
emissions and delivering low-emissions products. The oil and gas industry can also play a
critical role in assuring the future success of all types of CCUS due to its uniquely relevant
expertise, project management skills and geological assets.
The oil and gas industry has been at the heart of CCUS development globally to date. It is aninvestor or project partner in more than 90% of CCUS capacity in operation around the world
and more than 40% of CCUS investment since 2010 has been in projects directly related to oiland gas value chains. Around 45 Mt CO2 per year is currently captured via CCUS in 11 countries
and injected deep below the earth’s surface. Around three-quarters of this CO2 is injected forenhanced oil recovery (EOR), which is commonly operated without the level of monitoringthat is normally associated with CCUS to confirm that the CO2 has been permanently stored.
Of the total, around 30 Mt per year is captured from natural gas processing, mostly in the
United States, Brazil, Australia, the Middle East and China, while refinery and upgrader
facilities in Canada and the United States capture around 3 Mt CO2 per year.
Following several recent investment decisions, annual spending on CCUS projects reached a
new high of more than USD 3 billion in 2022. The oil and gas industry is heavily involved inthese new projects, including nearly 60% of all announced CCUS “full-chain” project capacity
involving CO2 capture and over 90% of that for independent CO2 transport and storage
infrastructure (Figure 2.21). However, just 5% of these projects (representing just over
10 Mt CO2 per year of capture and 20 Mt CO2 per year of storage) have taken a final
investment decision (FID) so far. There have also been a number of major recent mergers
and acquisitions, including Occidental Petroleum’s purchase in August 2023 of direct air
capture (DAC) company Carbon Engineering and ExxonMobil’s acquisition in July 2023 of
Denbury, owner of 2 000 km of US CO2 pipeline capacity and CO2-EOR operator since the1990s. In the NZE Scenario, the vast majority of proposed projects would not use the CO2 forEOR but would instead use dedicated CO2 storage resources.

IEA. CC BY 4.0

CCUS has many crossovers with the existing skills and expertise of the oil and gas industry.
The full CCUS supply chain requires the development of geological CO2 storage resources,
operating above-ground CO2 handling facilities, monitoring gases in the subsurface, andexecuting complex engineering projects of the type that are almost exclusively carried out
by oil and gas companies.
Once established, CO2 transport and storage assets can provide their owners with significant
revenue and this can contribute to oil and gas company portfolio diversification. Since 2015,
however, investment by the oil and gas sector in CCUS has represented just 8% of its clean
90

International Energy Agency | Special Reportenergy capital investment and 0.1% of its upstream oil and gas investment (IEA, 2023i). In
some areas of CCUS, such as its integration into cement and steel production, technologicalrisk can still present a barrier to investment. However, major oil and gas companies havepublicly stated that the technological risks of CCUS for their own operations are minimal andthat economic risks related to CO2 storage are manageable.
Figure 2.21 ⊳ Share of operational and announced CCUS projects to 2030 thathas oil and gas company involvement

Oil and gas
companies

CO₂ capture
and full-chain
projects

Other companies

CO₂ transportand storage
only projects
20%

40%
60%
80%
100%
Share of capacity (in tonnes of CO₂ per year)
IEA. CC BY 4.0.

Oil and gas firms are partners in CCUS projects representing around 70% of existing andplanned capacity, with more involvement in transport and storage than capture projects.
Notes: Oil and gas companies include specialist service providers and natural gas network operators.
“Involvement” includes project partners and key known suppliers. Includes only CCUS projects targeting
operation by 2030, and excludes projects developing CO2 transport assets to minimise double-counting.

IEA. CC BY 4.0

Apart from CO2 capture for EOR, the business case for CCUS to reduce CO2 emissions depends
largely on government policies. 7 To date, incentives have generally been insufficient forinvestors to take on projects that are typically large and involve multiple partners building
major new pieces of connected infrastructure. There are, however, also signs of a growing
constituency of industrial customers that are willing to pay a premium for products made at
CCUS-equipped facilities, including low-emissions ammonia, to meet their environmental
performance commitments.

7 CCUS includes processes that convert captured CO into consumer products such as chemicals and fuels. To
2
reduce fossil fuel use in non-durable materials, industrial firms could explore CO2 utilisation as a source ofcarbon. In the NZE Scenario, CO2 utilisation is mainly the use of DAC and biogenic CO2 in aviation and marine
fuel, which do not require additional CO2 removals to compensate for residual emissions from captured fossil(or limestone-derived) CO2.

Chapter 2 | Technology options for the oil and gas industry

91

2

Table 2.1 ⊳Policy measures that incentivise CCUS investment
Sector in which theexample has triggered
private investment

Who pays?

Norwegian offshore CO2
tax (1991)

Natural gas processing

Natural gas buyers

Western Australia
Ministerial Statement 800(2009)Natural gas processing

LNG buyers

Brazilian licence for Santos
Basin oil and gas (2014)

Natural gas processing

Oil buyers

California Low Carbon FuelStandard CCS Protocol(2018)

None to date

Fuel buyers

US 45Q tax credit (2008,2018, 2022)

Bioethanol

Taxpayers

Danish CCUS Funds (2021)

Biomass cogeneration

Taxpayers

Dutch SDE++ system(2020)

None to dateTaxpayers

US 45V Hydrogen
Production Tax Credit(2022)

None to dateTaxpayers

UK Dispatchable Power
Agreement, Industrial
CCUS and Low Carbon
Hydrogen contracts(proposed)

None to dateTaxpayers or
ratepayers

EU Net Zero Industry Act(proposed)

None to date

Fuel buyers

Policy type

ExamplesPenalties forpollutingProhibition ofpollution oremissions intensity
standard

Payments for CO2
capture or storage
Payments for lowemissions production

CO2 storage capacity
mandatesThree types of climate policy have successfully triggered CCUS investments, and two others
may soon be tested (Table 2.1). Other projects have mostly proceeded with government
grants for one-off installations, with public spending justified as being in the “public good”
and to compensate for the higher risk of demonstration projects. Achieving the deployment
rates in the APS and NZE Scenario will require more policies of these types to be developed
quickly, complemented by effective regulations, administrative capacity, workforce training
and contractual arrangements between businesses in the value chain.

IEA. CC BY 4.0

Prospects for CCUS are best when the CO2 is already in a highly concentrated stream andlocated close to large CO2 storage developments. The land requirements for CCUS are smaller
than for many low-emissions technologies, particularly where CO2 pipeline distances areminimised. In both the APS and the NZE Scenario, the oil and gas industry increasingly uses
CCUS to avoid the 125 Mt CO2 that it routinely captures and vents after purifying extractedhydrocarbons (see Section 2.2).

92

International Energy Agency | Special ReportGt CO₂

Figure 2.22 ⊳ CO2 capture in the APS and NZE Scenario by source
APS

6

NZE

Direct air capture
Fuel production

2

Hydrogen

4

Power
Industry

2

2022

2030

2050

2030

2050
IEA. CC BY 4.0.

To reach net zero emissions globally, industrial processes become the largest source of
captured CO2 after 2030, followed by power generation and hydrogen production.

In the APS, CO2 capture grows from around 45 Mt CO2 in 2022 to 440 Mt CO2 in 2030
(Figure 2.22). The use of CO2 capture in fuel supply chains – natural gas processing, oil
refining and liquid biofuels – remains the largest source through to 2030 and this ensuresthat the emissions intensity of oil and gas supplies remains compatible with climate goals
during the transition. However, the share of CCUS related to fuel supply declines from 85%
today to half of the total by 2030. Early action and deployment of large-scale CCUS
infrastructure in fuel supply to 2030 is needed so that CCUS is a viable option in other sectors
where it is a necessary abatement option after 2030. Building on the investment up to 2030,
CO2 capture rises to more than 3.5 Gt CO2 globally in 2050.

IEA. CC BY 4.0

In the NZE Scenario, CO2 capture grows to 1 Gt CO2 in 2030. Around one-quarter of this isrelated to CO2 capture in fuel supply, partly due to a large increase in CCUS for merchanthydrogen production, just under 10% of which is purchased by refineries. Achieving this levelof CCUS deployment requires around USD 500 billion of investment through to 2030. This
investment continues to provide emission reductions after 2030 across multiple sectors, but
the nature of the CCUS business is likely to shift. Oil and gas companies operating integrated
CO2 value chains that abate emissions from refineries or hydrogen production in 2030 may
give way to dedicated CO2 transport and storage operators licensed to manage the captured
CO2 from a wider range of sectors and from the atmosphere. By 2050, 6 Gt CO2 is captured,
more than half of which is DAC and from heavy industry, substantially less than in many other
1.5 °C scenarios assessed by the Intergovernmental Panel on Climate Change (Box 2.3).
For the oil and gas industry, engagement with CCUS needs to go beyond thinking of it as ameans of securing a “social licence to operate”, whereby CCUS is used mainly as an option
Chapter 2 | Technology options for the oil and gas industry

93to reduce or compensate scope 1 and 2 CO2 emissions. Such an approach is unlikely tosupport the steady scale-up of investment in successive projects. Rather, the sizeablebalance sheets of many oil and gas companies give them a competitive advantage to invest
in CCUS across the energy economy. Forward-looking companies could lead the way by
advocating policies to help support their efforts to increase capital expenditure in this area.
CCUS offers a very different business proposition than traditional oil and gas operations,which could pose problems for companies seeking to incubate a CCUS division within a larger
oil and gas business. The revenue from operating CO2 transport and storage infrastructure,possibly for a fixed tariff, is likely to be lower and subject to a risk profile more often
associated with pension and infrastructure funds than oil and gas commodities.
Policies that underpin widespread CCUS uptake tend to overlap with policies that reduce oiland gas demand. Even so, as CCUS scales up it will compete for a time with oil and gas
projects for skills, goods and services, and this could drive cost inflation if not well-managed.
To temper cost upswings and risks that CO2 storage developers are outbid, governments canwork to increase the supply of skilled personnel and manage the transformation of depletedhydrocarbon reservoirs into CO2 storage sites (IEA, 2015). Resolving these various tensions
may prove central to scaling up CCUS.
Box 2.3 ⊳Direct air capture and CO2 removals in the NZE Scenario

CCUS can remove CO2 from the atmosphere when storage is paired with direct air capture(DAC) or CO2 capture from bioenergy (bioenergy with carbon capture and storage[BECCS]). The NZE Scenario sees around 1.7 Gt CO2 removals in 2050, of which one-thirdis achieved through DAC. This level of deployment is lower than in other comparable
1.5 °C scenarios, which are in the range of 3.5-16 Gt CO2 in 2050 (IEA, 2021b).

IEA. CC BY 4.0

For countries with low-cost energy and adequate CO2 storage resources, DAC represents
a major potential export opportunity. Countries deploying DAC could expect to receive apayment for any removals beyond those needed to meet their own long-term climate
goals. In the NZE Scenario, this market could be worth USD 60-150 billion per year if
certificates were to trade at USD 100-250 per t CO2.
CO2 removal via DAC is not an unlimited resource, and the level of DAC in the
NZE Scenario is likely to be close to the upper bound of what is practicable by 2050. It isconstrained by factors including accessible annual CO2 storage capacity, the available
space for the energy inputs (which tend to be renewables), competition for DAC CO2 fromsynthetic fuel production, and the price that buyers are willing to pay (IEA, 2022c). Theenergy requirements and costs of DAC are also substantial and there are good reasons tosafeguard its use to compensate for the hardest-to-abate emissions. The NZE Scenario
requires around USD 70 billion average annual investment in DAC to 2050 and around
500 TWh of annual electricity generation in 2050 (equivalent to Canada's electricity
demand in 2022).

94

International Energy Agency | Special ReportSome producers have argued that levels of oil and gas demand much higher than thoseseen in the NZE Scenario could be consistent with achieving net zero emissions by 2050
by deploying much greater levels of CCUS and DAC. The difficulties in doing this should
not be underestimated.
If oil and natural gas consumption were to evolve as in the STEPS (i.e. with 97 mb/d oil
and 4 200 bcm gas consumption in 2050), this would require 32 Gt CO2 of CCUS by 2050,
including 23 Gt CO2 of DAC, to achieve net zero emissions in 2050 and limit thetemperature rise to 1.5 °C. 8 The carbon capture technologies would require around
26 000 TWh of electricity to operate, more than global electricity demand in 2022.
Deploying this level of CCUS and DAC would require USD 3.7 trillion of annual average
investment through to 2050 (including the cost of the low-emissions power needed by
the DAC facilities), even assuming major cost reductions in CCUS and DAC from current
levels. The STEPS requires around USD 3.2 trillion average annual investment in fossil fuelsupply and clean energy through to 2050, and so annual investment required to limit thetemperature rise to 1.5 °C in this way would be USD 6.9 trillion. This is 50% greater thanannual average energy-sector investment in the NZE Scenario.
DAC is untested at this scale of deployment and relying on it to limit the temperature rise
to 1.5 °C would be extremely risky. The NZE Scenario is not the only pathway to net zero
emissions by 2050, but reducing emissions by phasing down fossil fuel use remains themost technically feasible, cost‐effective and socially acceptable way to achieve this goal.

2.3.2

Low-emissions hydrogen and hydrogen-based fuels

The oil and gas industry is already a major producer and consumer of hydrogen. Around
43 Mt of hydrogen is currently used to refine and upgrade oil per year, nearly half of globalhydrogen demand. Low-emissions hydrogen is one of the main pathways for cutting fossil
fuel use in heavy industry. Low-emissions hydrogen-based fuels (also known as synthetic
fuels) are critical to decarbonising long-distance transport and are an important part of the
future of liquid fuels in net zero transitions. Scaling up the production of low-emissionshydrogen and hydrogen-based fuels will require the skills, equipment and resources that giveoil and gas suppliers, including producer economies, a competitive advantage.

IEA. CC BY 4.0.

Investment in low-emissions hydrogen supply projects has been growing exponentially inrecent years. This includes production via electrolysis using renewable or nuclear electricity,and from fossil fuels with CCUS. In 2022, spending on electrolyser installations was nearly
USD 0.6 billion, double the level in 2021. The world’s largest electrolyser project in January
2021 was 25 MW; this was dwarfed by a 150 MW facility in late 2021, and then a 260 MW
plant in 2023, both in China. It stands to be overtaken again in 2026 by a 2 GW electrolyser
8 This level of DAC is required both to offset continued oil and gas use in 2050 and to draw down CO emissions
2

released prior to 2050 as the CO2 removal technology ramps up.

Chapter 2 | Technology options for the oil and gas industry

95

2

being built in Saudi Arabia. Meanwhile, investors took FID for two projects to make hydrogenfrom natural gas equipped with high rates of CCUS in 2022, with the aim for them to be
operational by 2025. These facilities, in the United States and Canada, have planned
capacities equivalent to 0.8 GW and 0.6 GW of electrolysis running 90% of the time, andshould capture 90% and 95% of their CO2.
Figure 2.23 ⊳ Share of low-emissions hydrogen project pipeline to 2030 thathas oil and gas company involvement, by anticipated output

Oil and gas
companies
CCUS
Other
companies

Electrolysis

5

10

15

20
25
30
Mt hydrogen per year
IEA. CC BY 4.0.

Oil and gas firms are partners in one-third of low-emissions hydrogen production involving
CCUS and around 20% of electrolysis operational and planned projects.
Notes: Oil and gas companies include specialist service providers and natural gas network operators. Output
estimates based on announced targets or assumed capacity factors.

IEA. CC BY 4.0

Oil or gas companies are partners in one-third of the estimated low-emissions hydrogen
output from operational or planned projects applying CCUS, and they are partners in 20% of
projects based on electrolysis (Figure 2.23). One rationale for the involvement of thesecompanies in the wider hydrogen sector is to transition their fuel supply businesses fromfossil fuels to clean fuels. This could be particularly attractive for producer economies seeking
to diversify revenue and reduce reliance on a shrinking market for fossil fuel exports. A visionof continuity is emerging among 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 (IEA, 2023j).
The capabilities required for large-scale, capital-intensive hydrogen and hydrogen-based fueldevelopments play to the strengths of oil and gas companies. Developing hydrogen
infrastructure involves specialist engineering, complex project management and the highest
safety standards. In addition, large-scale production of hydrogen is fundamental to the
manufacture of low-emissions hydrogen-based fuels, such as synthetic kerosene, that
96

International Energy Agency | Special Reportrequire the same infrastructure and management as those for crude oil. Not only do oil andgas companies have these skills, but they also have extensive experience with handlingindustrial volumes of CO2 and hydrogen, which, like methane, must be tightly controlled to
avoid leaks.
Investment in hydrogen supply is driven by government policy, and major public funding
initiatives have been launched in recent years. Policy interest in hydrogen has increased
considerably since the pandemic and the energy crisis, with greater ambitions to promote
domestic energy supply chains. Total annual spending has grown to USD 1.1 billion per year,
including USD 0.5 billion on CCUS and USD 0.6 billion on electrolysis projects (Figure 2.24).
While much of the funding has been directed to individual supply projects, there areexamples of support to other parts of the value chain, such as hydrogen pipelines, storageand electrolyser manufacturing, as well as more generic fiscal and regulatory support.

Billion USD (2022, MER)

Figure 2.24 ⊳ Investment in electrolysis projects for hydrogen, 2015-2022
0.8

Other

Latin America

0.6

United States
Europe

0.4

China
0.2

2015

2016

2017

2018

2019

2020

2021

2022
IEA. CC BY 4.0.

Spending on electrolysis projects is growing fast, but USD 500 billion of cumulative
investment in low-emissions hydrogen supply is needed to 2030 in the NZE Scenario.

IEA. CC BY 4.0

In the APS, climate policies act to increase low-emissions hydrogen demand. Demand for
low-emissions hydrogen grows from less than 1 Mt to 24 Mt in 2030 and it passes today’s
total hydrogen demand from fossil fuels (95 Mt) just before 2040 (Figure 2.25).
In the NZE Scenario, the demand for low-emissions hydrogen rises to 70 Mt in 2030 and
415 Mt in the 2050. In 2030, half of the demand for low-emissions hydrogen is for transport
fuels – whether for use in refining, upgrading biofuels, fuel cell vehicles or conversion tohydrogen-based fuels. In 2050 the two main sources of demand – industry and low-emissionshydrogen-based fuel production – represent similar volumes of hydrogen, with transportdemand for low-emissions hydrogen at a slightly lower level. As an example of how
important hydrogen-based fuels become to the continued use of oil and gas infrastructure,
Chapter 2 | Technology options for the oil and gas industry

97

2

synthetic kerosene represents over one-third of all energy used for aviation in 2050 in the
NZE Scenario. To meet this demand, low-emissions hydrogen production ramps up in all
regions according to resource availability, falling capital costs and the costs of transportinghydrogen-based products, such as ammonia, to demand centres. As a result, Australia, theMiddle East and North Africa become leading hydrogen producers at levels well above theirdomestic demand, providing them with the opportunity to move downstream intohydrogen-based products including ammonia or even iron or steel.
Figure 2.25 ⊳ Demand for low-emissions hydrogen by sector in the APS and
Mt of hydrogen

NZE Scenario

APS

500

NZE

Other
Refining

400

Power
300

Fuel production

200

Transport
Industry

100

2022

2030 2040 2050

2030 2040 2050
IEA. CC BY 4.0.

Annual demand for low-emissions hydrogen is 415 Mt by 2050 in the NZE Scenario, requiring
a rapid scale-up from today’s levels, mostly to supply industry and non-road transport fuel.
Note: Other includes agriculture and buildings.

IEA. CC BY 4.0

A number of challenges remain to achieving this scale-up in hydrogen production and use.
They include creating demand for low-emissions hydrogen in industries that currently
depend on hydrogen from fossil fuels, agreeing on international standards for emission
intensities and safety considerations, developing an investment case for the early
development of large-scale infrastructure (such as pipelines, ports, dedicated renewableelectricity and underground storage), and price discovery and assessment.
Recent commercial decisions confirm expectations that oil and gas companies can play acentral role in overcoming these challenges. Shell and Sinopec were the first companies tostart construction of 200 MW electrolyser installations, in large part because their refineries
provide a reliable offtake of low-emissions hydrogen without significant new infrastructure
and their existing steam methane reformers can be used as back-up to manage variability of
the new supply. As fuel suppliers, they are well-placed to diversify these projects into vehicle
refuelling and low-emissions fuels manufacturing (such as ammonia or synthetic oil products)
98International Energy Agency | Special Reportas those sources of hydrogen demand materialise. Coupled with their expertise in CCUS for
low-emissions hydrogen production from fossil fuels, this combination gives oil and gas
companies an almost unique ability to manage risks during the earliest phases of scale-up.
First-mover advantages could then pay off handsomely if hydrogen and hydrogen-based
fuels become commodities that are widely used and traded.

2.3.3

Bioenergy

Bioenergy – in solid, liquid and gaseous forms – is already a major source of energy today
and is an essential component of net zero transitions. Liquid transport biofuels, biogas andbiomethane9 offer a major opportunity for the oil and gas industry to use existing oil and gas
processing, transmission and distribution infrastructure while delivering a zero-emission
source of energy.

Liquid biofuels
The oil and gas industry is already a player in the production of liquid biofuels. It owns oroperates approximately one-third of biojet fuel capacity globally and two-thirds ofrenewable diesel production capacity (Figure 2.26). Liquid biofuels can often make use ofunits and facilities at traditional refineries. The co-processing of biofuels by blending small
amounts of bio-based feedstock into existing conversion units is already a widely adopted
practice that can be achieved without the need for infrastructure upgrades. Hydrotreating
units, normally used to eliminate sulphur and other impurities in the final production stagesof petroleum products, can also be converted to produce renewable diesel and biojet fuel.
Refineries can also be converted to produce 100% biofuels. This would require new upfront
investment to modify and adapt existing assets, but it would allow refiners to leverageavailable assets such as utilities, storage and transport infrastructure, along with theassociated human capital. The overall cost of conversion is generally much lower than that
required to build such infrastructure from scratch. However, full conversion to bioenergy
would require sourcing sustainable feedstocks at sufficient scale; these are not necessarily
available in dense quantities close to today’s existing infrastructure.
Other liquid biofuel feedstocks and production routes require new facilities andinfrastructure, but could still make use of the existing skills and expertise of some parts of
the oil and gas industry. For example, the gasification of solid biomass requires
preprocessing, gasification, syngas purification and the synthesis itself, as well ashydroprocessing of intermediate liquids into final products. In the APS, total liquid biofuel
production increases from 2 mboe/d today to 5 mboe/d in 2030 and 7 mboe/d in 2050
(Figure 2.27). Investment in biodiesel, renewable diesel and biojet fuel capacity rises fromvery low levels today to around USD 20 billion in 2030.

IEA. CC BY 4.0

9 Biogas is a mixture of methane, CO and small quantities of other gases produced by anaerobic digestion of
2

organic matter in an oxygen‐free environment. Biomethane (also known as renewable natural gas) is anear-pure source of methane produced either by removing the CO2 from biogas or through the gasification ofsolid biomass followed by methanation.

Chapter 2 | Technology options for the oil and gas industry

99

2

Figure 2.26 ⊳ Oil and gas sector capacity for liquid biofuel production, 2022
3 200

100%

kboe/d

20

300

Other
companies

80%

Oil and gas
companies

60%
40%
20%

Ethanol and biodiesel

Renewable diesel

Bio jetfuel
IEA. CC BY 4.0.

Oil and gas companies have a strong presence in emerging parts of the liquid biofuelsvalue chain that can be processed in existing refineries following modification.
Note: kboe/d = thousand barrels of oil equivalent per day.

Figure 2.27 ⊳ Modern liquid and gaseous bioenergy use by scenario

100

APS
NZE
Conventional

2030
2050

2

2030
2050

200

2022

4

2030
2050

300

2030
2050

6

2030
2050

400

2022

8

STEPS
Advanced

Gases (bcme)

500

2030
2050

Liquids (mboe/d)

10

STEPS
APS
Biomethane

NZE
BiogasIEA. CC BY 4.0.

IEA. CC BY 4.0

Oil and gas companies are well-positioned to satisfy growing investment needs for highvalue-added bioenergy supply, such as biojet fuel, renewable diesel and biomethane.

In the NZE Scenario, the production of liquid biofuels rises to 6 mboe/d in 2030, requiring asixfold increase in investment by 2030 from today’s levels. Production then remains
6 mboe/d to 2050 and investment levels decline. The high penetration of electric cars andtrucks leads to a reduction in biofuel consumption in road transport after 2030, and more of100International Energy Agency | Special Reportthe limited supply of sustainable bioenergy available is used in the form of solid bioenergy inpower generation and industrial applications.
Scaling up advanced biofuels will be critical to ensure minimal impacts on land use and foodprices while expanding biofuel production.10 In the APS, the share of advanced biofuels in
total biofuel production rises from about 10% today to nearly 60% in 2050. In the
NZE Scenario around 80% of liquid biofuels are produced from advanced feedstocks in 2050.
However, given the limited availability of the advanced feedstocks in use today, newtechnologies and waste streams will need to be commercialised to satisfy growing demand.
The oil and gas industry, with its access to capital, value chain synergies and establishedpresence in the sector, can play a key role in unlocking the necessary investment in liquidbiofuels. If the industry were to maintain its current share of investment in the liquid biofuel
market in the APS through to 2030, it would need to invest around USD 40 billion over the
next seven years.

Biomethane
Biomethane is another part of the bioenergy value chain that has attracted attention fromoil and gas companies, who are seeking to develop the fuel as an alternative to natural gas
or as a transport fuel. This has proven a particularly attractive proposition in Europe following
Russia’s invasion of Ukraine; the European Commission in its Fit for 55 and RePowerEU plans
has set a target for a biomethane production level of 35 bcm by 2030, from around 3 bcm
currently. California’s low-carbon fuel standards have also provided a spur for thedevelopment of biomethane as a transport fuel in the United States.
The biogas and biomethane industry is currently dominated by relatively small players, suchas independent producers, farming co-operatives, waste management firms andmunicipalities. A handful of larger players have recently been acquired by oil and gas
companies to gain a foothold in the emerging industry. BP bought US-based Archaea Energy
in late 2022 for USD 4 billion, Shell acquired Denmark-based Nature Energy for USD 2 billion,
and TotalEnergies has made a series of smaller acquisitions, such as the purchase of Fonroche
Biogaz in France and Poland-based biogas producer PGB.

IEA. CC BY 4.0

The global potential for biogas and biomethane remains largely untapped. A detailed
geospatial analysis of the sustainable agricultural wastes and residue feedstocks reveals apotential of just under 1 000 bcme (Figure 2.28). Around 30% of this potential lies within
20 kilometres of major gas pipeline infrastructure, providing a good match with possible
large-scale production and injection into gas grids. Around 40% of the potential is otherwise
near a road network, an indicator for the potential for feedstocks to be collected and brought
to centralised biodigesters, to produce biogas for local heat and power requirements orotherwise upgraded to biomethane for use in transport.
10 Advanced biofuels are produced from non‐food crop feedstocks, which can deliver significant life cycle GHG
emission savings compared with fossil fuel alternatives and do not directly compete with food and feed crops
for agricultural land or cause adverse sustainability impacts.

Chapter 2 | Technology options for the oil and gas industry

1012

Figure 2.28 ⊳ Assessed annual biomethane potential from agricultural wastes
and residues, and location of natural gas transmission pipelines

Million m3 per 100 km2< 0.5

0.5 - 1.0

1.0 - 1.5

1.5 - 2.0

2.0 - 2.5

2.5 - 3.0

> 3.0

IEA. CC BY 4.0.

Around 300 bcm of biomethane could be produced from agricultural wastes and injected
into nearby gas grids. Oil and gas companies have recently invested in this area.
Sources: IEA analysis based on FAO (2023) and Global Energy Monitor (2022).

Oil and gas companies could improve the biomethane value chain by helping it to achieve
scale, through standardising contracts, equipment and logistical operations, and integrating
biomethane into existing gas markets and infrastructure. Some companies participate in thevalue chain mainly as offtakers or traders of certified sustainable biomethane, enabling bothdemand and supply aggregation to support larger economies of scale. This is crucial in net
zero transitions, where biomethane rapidly grows in the years ahead, from 10 bcme in 2022
to 70 bcme in the APS in 2030 and 130 bcme in the NZE Scenario.

2.3.4

Offshore wind

IEA. CC BY 4.0

Offshore wind provides around 1% of global electricity generation, but has huge untapped
potential. The world’s offshore wind potential is 17 times the scale of global electricity
demand in 2022 (Figure 2.29). In most markets, offshore wind alone could generate enoughelectricity to meet total electricity demand in aggregate (IEA, 2019).
The involvement of the oil and gas industry in the offshore wind market is still in its relative
infancy; around 2% of offshore wind capacity in operation today was developed by oil andgas companies. However, plans are expanding. In 2022, TotalEnergies announced a projectpipeline of 6 GW of offshore wind, which would take its total to 11 GW; Shell also has around
9 GW in the pipeline and Equinor has ambitions to install 12-16 GW by 2030 (IEA, 2023i). If
realised, these capacity additions would rival those of pure-play developers such as Ørsted
over the same period. In 2023, in the world’s largest offshore wind auction, BP and
TotalEnergies bid USD 13 billion for the right to build wind farms in the North and Baltic seas.
102

International Energy Agency | Special ReportFigure 2.29 ⊳ Offshore wind potential and 2022 electricity demand in selected
regions and countries

United States

2

European UnionJapan
United Kingdom
China
India
10
Shallow water near shore
Deep water far from shore

20

30

Shallow water far from shore
Electricity demand (2022)

50
40
Thousand TWh
Deep water near shore
IEA. CC BY 4.0.

Offshore wind has untapped potential that is almost 17 times global
electricity demand in 2022 and exceeds current electricity demand in most countries.
Notes: Shallow water = 10-60 m. Deep water = 60-2 000 m. Near shore = < 60 km. Far from shore = 60-300 km.

The offshore wind industry is currently facing challenges in several markets as project costs
rise due to supply chain disruptions, elevated financing rates and extended permitting times.
These pressures are particularly acute in the United States, where companies including Shell,
BP and Ørsted have halted several large offshore wind projects in recent months, calling on
policy makers to address these challenges and help the industry to regain confidence.

IEA. CC BY 4.0

A number of possible synergies exist between the skills and resources of the oil and gas
industry and those needed for offshore wind developments. They include the ability to
manage large-scale projects in challenging offshore environments, the efficient utilisation ofvessels during installation and operation, and the maintenance of offshore infrastructure.
Offshore wind farms are capital-intensive: projects in 2022 cost around USD 3 million
per MW installed capacity and have an average total cost of around USD 1 billion. There arealso some major differences between offshore wind developments and the skills of theindustry. For example, offshore wind farms require deploying a large number of smaller
structures quickly and connecting these with a large amount of equipment and cables, while
offshore oil and gas operations tend to involve planning and constructing a much smaller
number of more centralised and complex structures.
As offshore wind farms are likely to involve increasingly more complex structures in deeper
water that are further from shore, offshore oil and gas platforms could be repurposed or
reutilised as operation and maintenance facilities. The use of drones and remotely operated
vehicles – already common practice in many offshore oil and gas facilities – for wind blade
and subsea inspections and repair would also reduce the necessity for workers stationed at
Chapter 2 | Technology options for the oil and gas industry

103

offshore platforms. The manufacture of substations, which are required for all new offshore
wind farms larger than 100 MW, and the cables connecting one turbine to another could also
draw on the expertise of the oil and gas supply chain.
Floating offshore wind power technologies are needed to tap additional potential in deep
water and the offshore oil and gas industry is emerging as a key player in this sector. The
experience of the oil and gas sector is especially beneficial to the design and construction of
floating facilities and their associated anchors and moorings. The first floating wind farm in
the world is operated by Equinor and Masdar, and three of the seven new floating wind farms
recently opened in Europe are owned or partially owned by oil and gas companies. Most
floating wind projects are still relatively small, but the involvement of oil and gas companies
could allow for larger projects, helping the sector as a whole to expand faster and to further
reduce costs. The levelised cost of offshore wind electricity indicates that the technology ison track to be competitive with most fossil fuels before 2030, trailing only solar PV andonshore wind.
In the APS, almost 1 800 GW of offshore wind capacity is installed globally by 2050, providing
10% of electricity generation globally. This requires almost USD 4 trillion of cumulative
investment to 2050 (Figure 2.30). Around half of this has significant potential synergies withthe offshore oil and gas industry, including the construction and installation of foundations,and associated logistics. There are also synergies in operation and maintenance costs andthis implies a USD 2.6 trillion opportunity for the oil and gas industry over the next 30 years.
Figure 2.30 ⊳ Cumulative investment in offshore wind and spending withsynergies with oil and gas activities in the APS and NZE Scenario

Trillion USD (2022, MER)

Cumulative investment in offshore wind

Synergies with oil and gas activites

4
3
2
1

APS NZE
2022-30APS NZE
2022-50

Advanced economies

APS NZE
2022-30
China

Other EMDEAPS NZE
2022-50
World
IEA. CC BY 4.0.

IEA. CC BY 4.0

Cumulative investment in offshore wind to 2050 is close to USD 4 trillion in both the APS andNZE Scenario, and has a large crossover with oil and gas activities.
Notes: EMDE = emerging market and development economies.

104

International Energy Agency | Special ReportIn the NZE Scenario, nearly 2 200 GW of offshore wind capacity is installed by 2050. Emerging
market and developing economies account for around 60% of global offshore wind electricity
generation in 2050, with major growth in China, India and Viet Nam. Cumulative investment
to 2050 exceeds USD 4 trillion and there is around USD 3 trillion of capital and operating
spending to 2050 that would have significant synergies with the oil and gas industry.

2.3.5

Geothermal

Geothermal currently provides just under 1% of global energy supply. It is used for electricity
generation and to provide heat to residential and commercial buildings. Oil and gas
companies have long recognised the potential of geothermal energy as an opportunity todiversify their activities while leveraging their drilling expertise. However, pure-player
geothermal developers and state-owned enterprises own the vast majority of capacity, withoil and gas companies owning less than 5% of capacity worldwide (Figure 2.31).
Figure 2.31 ⊳ Global geothermal capacity by company type, 2022
By company ownership

By company type

Public 0%
Oil andPrivategascompanies 4%

Private 41%
Public 59%

Electricity utilities
96%

IEA. CC BY 4.0.

IEA. CC BY 4.0

Oil and gas companies own less than 5% of installed geothermal capacity globally.

Geothermal and upstream oil and gas developments share many similarities. Most existing
geothermal developments have tapped into shallow heat resources that are relatively easy
to access, but there is significant potential for using high-temperature geothermal energy
from deeper sources in many parts of the world (sometimes known as “enhanced
geothermal systems”). Techniques developed by the oil and gas industry, including a deep
understanding of the subsurface, drilling and completing wells, predicting fluid flows andmanaging large-scale projects, can help to tap into these deep geothermal resources. The
potential for technology spillovers is considerable given the wide range of transferrable
disciplines, including resource characterisation, exploration, drilling, operations,maintenance, and risk management. It is highly likely that the costs of geothermal could be
Chapter 2 | Technology options for the oil and gas industry

105

2

lowered and performance improved if it could make use of the technologies and knowledgeof the oil and gas sector (Schulz & Livescu, 2023).
In the APS, geothermal demand doubles to 2030 and increases by a factor of five to 2050. By
2050, there is 100 GW of geothermal power capacity globally, up from 15 GW today, and thisrequires around USD 250 billion of investment through to 2050. The best prospects for
growth are in the United States, Southeast Asia and Africa, given their untapped potential
and growing electricity demand. Electricity generation costs from geothermal are in generalhigher than onshore wind and solar PV, but it can play an important role in balancing windand solar PV generation. In the NZE Scenario, geothermal power capacity grows to 130 GW
by 2050, requiring around USD 280 billion of cumulative investment through to 2050; total
geothermal supply in 2050 is around seven times higher than in 2022 (Figure 2.32).
There are differences between oil and gas and geothermal operations that may mean theindustry plays only a marginal role in its future growth. They include differences between thevolumes of fluids produced and temperature variations in geothermal and hydrocarbon
reservoirs, and contrasts in the supply chains for electricity (including engagement withdifferent customers). The returns on investment are also likely to be very different. While oiland gas industry support could help drive geothermal project cost reductions and boost
economies of scale, a much more proactive approach, matched with increased investment
levels, would be required.

8

Average annual power capacity additions

EJ

GW

Figure 2.32 ⊳ Geothermal deployment in the APS and NZE Scenario
40

6

30

4

20

2

10

2014-22 2023-30 2031-40 2041-50
APS

NZE

NZE scenario geothermal supply

2022
Power

2030

2040

2050

Buildings

Other
IEA. CC BY 4.0.

IEA. CC BY 4.0

Geothermal energy supply increases by a factor of seven to 2050 in the
NZE Scenario, mainly from increases in the power sector.

106

International Energy Agency | Special Report2.3.6

Plastics recycling

The demand for plastics has grown rapidly in recent years and around 12 mb/d of oil wasused to produce plastics in 2022. Plastics are very useful, but significant levels of emissions
are associated with their production – direct emissions of around 250 Mt CO2 were emitted
in 2022 just to produce high-value chemicals, the main precursor to plastics – and they result
in large amounts of waste. Momentum is growing behind policies and initiatives that aim to
reduce plastic use and increase recycling rates. More than 60 countries have restricted orbanned the production and use of single-use plastics, and the European Union announced aplastic packaging recycling rate target of 50% in 2025 and 55% in 2030. At present plastics
recycling is mainly performed using mechanical methods. These are generally low cost andlow emissions, but they cannot be used to process the mixed, complex and contaminatedplastic waste that makes up around 20-50% of collected material today(Vanderreydt et al., 2021). Mechanical recycling also leads to degradation of quality that
often prevents the use of secondary plastic in high-grade applications like food packaging.
Table 2.2 ⊳Oil and gas
company

Oil and gas companies’ involvement in selected
commercial-scale chemical recycling projects
Recycling technology
developer

Location

Capacity
Start-up(kt waste/yr)

Agreement

Pyrolysis
TotalEnergies

Honeywell, Sacyr

Andalusia (ES)

30

2023

Offtake agreement

Plastic Energy

Grandpuits (FR)

15

2024

Joint venture

JV Plastic Energy andFreepoint Eco-systems

Texas (US)

33

2024

Offtake agreement

Plastic Energy

Seville (ES)

33

2025

Offtake agreement

ExxonMobil

Texas (US)

35

2022

Investment

Plastic Energy

Gravenchon (FR)

25

2024

BP

Clean Planet Energy

Teesside (UK)

20

tbd

Offtake agreement

Shell

Nexus

Georgia (US)

15*

tbd

Offtake agreement

Pryme

Rotterdam (NL)
tbd (NL)

60
350

tbd
2024

Strategic partnershipand offtake agreement

Freepoint Eco-Systems

Ohio (US)
Gulf Coast (US)

90
192

2024
tbd

Exclusive offtakeagreement

SK

Plastic Energy

Ulsan (KR)

66

2025

Strategic partnership

Sabic**

Plastic Energy

Geleen (NL)

20

tbd

Joint venture

EnerkemTarragona (ES)

400

2025

Joint venture

Loop Industries

Ulsan (KR)

70*

2025

Joint venture

ExxonMobil

Gasification
RepsolSolvolysis

IEA. CC BY 4.0

SK* Recycled product; ** 70% owned by Saudi Aramco.
Notes: kt = thousand tonnes; tbd = to be decided. ES = Spain; FR = France; KR = Korea; NL = Netherlands;
UK = United Kingdom; US = United States.

Chapter 2 | Technology options for the oil and gas industry

1072

Alternative methods, such as chemical recycling, could help address some of these issues.
For example, solvolysis uses solvents to decompose waste into compounds that can be
re-used to make recycled plastic that has a quality similar to virgin plastics; pyrolysis andgasification use high-temperature processes to break down difficult-to-recycle plastics into
fuels and feedstocks for industrial processes, including making plastics. These present a
potential new business opportunity for the oil and gas sector, especially companies withpetrochemicals production facilities that could be integrated with new pyrolysis orgasification units. Existing facilities can be used for downstream treating of the products andthe workforce is familiar with similar types of processes and such large-scale,
capital-intensive projects.
A number of chemical recycling plants are starting operation and there is a strong pipelineof future projects, many of which involve oil and gas companies (Table 2.2). Companies havealso announced specific targets for recycled content in their plastic production. For example,
TotalEnergies has a target to increase recycled and renewable content in their plastics to 30%
by 2030, Shell is aiming to have 30% recycled-content packaging material by 2030, andExxonMobil has an ambition to have 0.5 Mt of advanced recycling capacity by year-end 2026.
In the APS, the share of recycled plastic production in the global total increases from 8%
today to 25% in 2050. This helps to curb some of the increase in the use of oil for primary
plastics production, but oil use for this application still rises to 2050 (Figure 2.33).
Figure 2.33 ⊳ Primary plastic production and recycling in the APS and NZE
Scenario, 2022-2050
2030

Mt

700

2050
Recycling

600

Primary
production

500
400
300
200
100
2022

APS

NZE

APS

NZE
IEA. CC BY 4.0.

IEA. CC BY 4.0

The share of recycling in total plastics production increases alongside wider efforts to
reduce waste and oil imports, avoiding 5 mb/d of oil use in 2050 in the NZE Scenario.

108

International Energy Agency | Special ReportIn the NZE Scenario, trends are similar to the APS to 2030, but the plastics collection rate
rises faster thereafter and oil use declines faster after its peak; by 2050 oil use for plastic
production is only marginally above that in 2022. In 2050, recycled plastics accounts foraround 35% of total plastics production. Along with the introduction of bio-based andalternative feedstocks, and the trend towards more durable materials, this avoids around
5 mb/d of oil use for primary plastic production in 2050 compared to a baseline whererecycling remains at current levels. In the NZE Scenario, plastic waste is not converted intotransport fuels, as the carbon in the plastic is still of fossil origin.
There are large differences in the emissions associated with different plastics production andrecycling routes. Currently, producing a tonne of primary plastic results in around2-6 t CO2-eq emissions, depending on the type of plastic and the region, including the direct
and indirect emissions from production and conversion (OECD, 2022;
Vanderreydt et al., 2021). Mechanical recycling tends to be 75-90% less emissions-intensive
than primary production, with the emissions intensity of the electricity used a key factor.
Reductions in emissions from oil extraction and processing, and during the plastics
manufacturing processes, mean that by 2050 one tonne of primary plastic produced in the
NZE Scenario results in less than 0.1 t CO2-eq throughout the value chain.
Increasing mechanical recycling rates helps reduce CO2 emissions from plastics use in the
NZE Scenario, especially over the next 10-20 years. In the longer term, however, the impetus
for further increases in the plastics recycling rate stems more from policies and regulations
aiming to cut down on waste generation and oil imports rather than to reduce CO2 emissions.

IEA. CC BY 4.0

Treating mixed and difficult-to-recycle plastics will be necessary to reach high recycling rates,
and chemical recycling is set to play a role in both the APS and NZE Scenario. However,extensive efforts are needed to reduce GHG emissions and local air pollutant emissions fromthese processes. At present, lifecycle emissions per tonne of plastic produced from solvolysis
are around 1.6 t CO2-eq (Vollmer et al., 2020), varying according to the type of plastic, andfrom pyrolysis are around 3 t CO2-eq (Möck et al., 2022). The knowledge and expertise of theoil and gas industry could be critical in helping to reduce these emissions. One option is toconvert the gaseous by-products into chemicals that can be used to make durable products,
rather than using them as fuel for the process. For pyrolysis, this could be achieved bytransforming by-product methane into methanol and electrifying the process heat demand.
For gasification, low-emissions hydrogen could be used to convert the by-products fromplastic waste into chemicals such as methanol. Chemical recycling processes could also beequipped with CCUS to reduce emissions, although there are currently no announced
projects to do this. These innovations would need to target an emissions intensity of
production comparable with that of primary production in the NZE Scenario in 2050.

Chapter 2 | Technology options for the oil and gas industry

1092

2.3.7

Electric vehicle charging

Sales of electric vehicles (EVs) have been growing exponentially in recent years and 29 million
EVs – including 27 million electric cars – were on the road in 2022.11 Sales are expected tocontinue to grow rapidly, but this will depend on affordable and accessible public charging
together with options for home and workplace charging.
More than 2.7 million EV chargers are publicly accessible globally; two-thirds of these are in
China and 20% in Europe. A number of governments have set out support for public charging
infrastructure, notably in the proposed Alternative Fuels Infrastructure Regulation in theEuropean Union, the National Electric Vehicle Infrastructure Formula Program in the
United States, targets from the China National Development Reform Commission, and India’s
financing scheme under the Faster Adoption and Manufacturing of Electric Vehicles (FAME)
scheme II (IEA, 2023k).
Figure 2.34 ⊳ Projections for electric light-duty vehicle chargers in the APS andMillion chargers

NZE Scenario, 2022-2050

APS

30

NZE
Public fast
chargers
Public slow
chargers

20

10

2022

2030

2050

2030

2050
IEA. CC BY 4.0.

EV chargers increase five to sixfold to support the growth of electric light-duty vehicles by
the end of this decade, with around 30 million chargers required globally by 2050.

IEA. CC BY 4.0

A number of oil and gas companies have taken an active role in the deployment of EV
chargers, through investment in charging stations at their retail stations as well as acquiring
charger manufacturers, network operators and service providers. Oil and gas companies
currently operate around 350 000 charging points and this number is expected to double by2025 under announced corporate strategies. Oil and gas companies, together with utilities,
11 Figures do not include electric two/three-wheelers, of which there were more than 50 million on the roadin 2022.

110

International Energy Agency | Special Reporthave their strongest presence in EV charging in Europe; pure-players and equipment
manufacturers dominate the market in the United States and China. We estimate that over
13 million publicly accessible EV chargers are required to serve electricity demand for electriccars and vans on the road in the APS in 2030, and up to 17 million in the NZE Scenario(Figure 2.34). This requires around USD 100-120 billion of investment to 2030.
EV charging presents a business opportunity for oil and gas companies, especially those withexisting retail networks. Historically, these have been the least profitable part of the oil andgas supply chain, but installing EV chargers could help diversify revenue streams and support
sustainability efforts while keeping the physical stations and convenience stores in place andproviding a boost to companies’ brands. By retrofitting existing filling stations with fast
charging equipment (usually 50-350 kilowatts), oil and gas companies can attract EV owners
and commercial fleet operators with en-route charging demand and create significant
revenue streams. These companies can also tap into synergies with renewable generation andstorage options, as an increasing number of EV stations are coupling charging infrastructurewith rooftop solar PV and battery storage options to optimise the balancing of the load.
Electric trucks in long-distance operations will increasingly rely on highway charging and seek
bulk purchase contracts with EV charging operators. Public filling stations on highways canoffer a charging hub if equipped with fast and ultra-fast charging, allowing electric trucks toperform operations that are currently carried out by diesel trucks with little to no additional
dwell time in comparison. However, commercialisation of chargers with high charging power(around 1 MW) will incur significant costs in both installation and grid upgrades and require
co-ordination with utilities to locate and plan appropriate transmission and distribution lines.

IEA. CC BY 4.0

EV charging is attractive to oil and gas companies who are seeking to position themselves asa broader energy service provider with low-carbon energy assets, while offering them an
effective means to diversify their businesses geographically in regions where EV uptake isalready strong. The transition to an energy service provider is challenging, however, as thebusiness models used to provide consumers with electricity as compared with fuels can differ
markedly.

Chapter 2 | Technology options for the oil and gas industry

111

2

Chapter 3
Strategic responses of companies
S U M M A R Y• An increasing number of oil and gas companies are facing financial, social and politicalpressure to clarify the roles they intend to play in net zero transitions. The industry
landscape is diverse and no single option will make sense for all, but many oil and gas
companies have already made announcements on how they plan to respond.

• The oil and gas industry currently employs nearly 12 million workers globally. This falls
by 10% in the APS and 20% in the NZE Scenario to 2030. Governments and companies
will need to work together closely to maximise opportunities for reskilling workers.

• The ratio of investment in fossil fuels to clean energy rises from 1:1.8 globally in 2023
to 1:5 in 2030 in the APS and to more than 1:10 in 2030 in the NZE Scenario. These
ratios can provide a guide for financial actors looking to assess the alignment of theirportfolios with the outcomes of net zero transitions.

• A key strategic challenge for oil and gas companies is aligning existing skills and capitalwith the new requirements of energy transitions. We have developed a newframework to examine the possible contribution of oil and gas companies to net zeroenergy transitions that allows for a more granular discussion of the targets thesecompanies are setting. The framework covers the following:• Scope 1 and 2 emissions: in the NZE Scenario there is a 60% reduction in scope 1 and2 emissions from oil and gas operations to 2030. A number of companies have alreadyundertaken efforts to cut these emissions and this reduction is broadly consistent
with all companies achieving the emissions intensity of current best practices by 2030.

• New oil and gas projects: the NZE Scenario does not require new exploration or thedevelopment of new long lead time upstream conventional oil and gas projects. No
companies have to date made specific pledges on this.

• Investment in clean energy: Clean energy investment by the oil and gas industry
represented 2.5% of its total capital spending in 2022. In the NZE Scenario, projectedoil and gas revenues would allow the industry to invest around 50% of its capitalbudget in 2030 in clean energy. Achieving this level of investment would require
governments, companies, shareholders and financial actors to work closely together.

• It is not axiomatic that oil and gas companies should invest in clean energy. If they donot, they would need to achieve very low emissions intensities and stop investment
in new long lead time upstream projects if they are to claim that they are making ameaningful contribution to achieving net zero emissions by 2050.

• The NZE Scenario trends on scope 1 and 2 emissions and oil and gas industry

IEA. CC BY 4.0

investment in clean energy provide important guidance for oil and gas companies
looking to play their part in net zero transitions, even if the energy transition does not
accelerate at the pace seen in that scenario.

Chapter 3 | Strategic responses of companies

113

3.1

Introduction

Oil and gas companies have a wide range of possible responses to the challenges posed by
net zero transitions. It will be for companies and their state and private owners to decide on
the best way forward based on their own assessment of their capabilities and theopportunities and risks that exist, and the energy and climate policies in place in the locations
where they operate. Some companies may decide, for example, that their core competencies
are in oil and gas and that they will focus on supplying them as cleanly and cheaply as possible
even while they phase down production to be consistent with net zero transitions. Other
companies may choose to reposition themselves as “energy companies” and look to develop
the fuels and technologies needed in the new energy economy.
The debate around the role of the oil and gas industry in net zero transitions has often been
framed in binary terms. A company is either fully aligned or fully out of alignment. This
chapter looks to move beyond this dichotomy by exploring the different options available tooil and gas companies and degrees to which these are aligned with net zero transitions. This
includes a new framework to help key stakeholders, both inside and outside the industry,engage in a more informed, granular and transparent discussion on the statements, targets,and actions of oil and gas companies.

IEA. CC BY 4.0

This chapter is structured as follows. Section 3.2 sets out the pressures facing oil and gas
companies from the challenges posed by climate change and how they could evolve in the
future. It examines the demands of investors and financial markets, social and politicalpressures, and the future prospects for oil and gas workers. Section 3.3 examines oil and gas
companies’ responses to date to the challenge of reaching net zero. It analyses the targets
announced by companies both to cut down on emissions from oil and gas operations and todiversify their activities away from oil and gas. Section 3.4 explores what current oil and gas
companies could look like in 2050 if they align their portfolios with trends in the
NZE Scenario. Section 3.5 addresses what changes by oil and gas companies would beconsistent with net zero transitions. Finally, Section 3.6 describes the IEA’s new framework,
which can be used to understand the alignment of oil and gas company targets with theoutcomes of the NZE Scenario.

3.2

The rising pressures on oil and gas companies

3.2.1

Financial pressures

As efforts to tackle climate change have moved up the agenda, a growing number of financial
actors have been reviewing their engagement with oil and gas companies. The most direct
impact has been on publicly traded oil and gas companies as equity and debt have comeunder increased scrutiny due to shareholder activism and stricter lending policies by
European and US banks (Figure 3.1). This group of companies makes up around one-third of
the total equity value of the oil and gas industry. Privately owned and government-owned

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International Energy Agency | Special Reportcompanies can also be affected due to stricter lending conditions, and banks are increasingly
including conditions on lending to oil and gas companies based on environmental policies.
Figure 3.1 ⊳Oil and gas company equity value by company type, andshareholders of listed and private oil and gas companies

Oil and gas equity book value

Shareholders of listed and private companies

State-owned
ListedPrivate10%

Investors
Banks
Others

5%

34%

56%

10%

85%

IEA. CC BY 4.0.

Just over half of the oil and gas equity market cannot be directly accessed by institutional
investors given the major role played by state-owned companies.
Note: Equity book value = difference between total assets and total liabilities.
Source: IEA analysis based on 2 000 oil and gas companies representing more than 70% of production using
data from S&P Global (2023).

Rising concerns over climate change have developed into a wider movement among banks
and investors to understand the alignment of their portfolios with environmental, social andgovernance (ESG) principles. ESG is a broad concept encompassing a wide range of actors
and activities, but a core tenet of the “environmental” pillar is to evaluate the activities andinvestment plans of individual companies against sustainability goals. ESG investing has
grown rapidly in recent years, reaching USD 2.5 trillion of assets under management in 2022
(IEA, 2023a). This has elicited a response from the oil and gas industry and financial actors
with oil and gas holdings, stemming from concerns over reputational damage, impacts onshare performance, increased borrowing costs and a reduction in financing options.

IEA. CC BY 4.0

At present many ESG reporting frameworks suffer from a lack of transparency, consistency
and standardisation. Governments and regulatory bodies are responding by introducing
regulations and reporting requirements to enhance transparency and disclosure of
ESG-related information. Examples include the EU taxonomy for sustainable activities, and
the Green Bond Principles and Common Ground Taxonomy released in China. A growing
number of central banks are also conducting climate stress tests; banks in at least
18 jurisdictions are, or soon will be, subject to requirements to implement such testing.

Chapter 3 | Strategic responses of companies

115

3

The two main avenues open to investors, banks and development finance institutions looking
to influence oil and gas companies are divestment and active engagement.


Divestment is a decision to sell ownership of equity or bonds in oil and gas companies.
A number of prominent campaigns in recent years have generated public pressure on
oil and gas companies and raised awareness of their contribution to climate change. The
value of assets under management committed to some form of fossil fuel divestment
increased from just over USD 50 billion across 180 institutions in 2014 to nearly
USD 40 trillion across 1 500 institutions in 2021 (Lipman, 2021). A key risk withdivestment is that it transfers ownership to institutions that are less focused on ESG orthat do not have as stringent climate goals; this can limit, or even negate, the intended
purpose of divestment.



Active engagement involves retaining ownership or influence in oil and gas companies
and pushing them to achieve sustainability-related goals. Nearly 500 shareholder
resolutions related to environmental and climate issues were filed in the United Statesin 2021 and 600 were filed in 2022 (ISS, 2023). A number of investor coalitions have also
emerged in recent years that aim to collectively engage with companies and push forthese goals, including the Net Zero Asset Owner Alliance, Climate Action 100+, and thePrinciples for Responsible Investing. The key risks with active engagement are that thetarget companies do not undertake real efforts to reform or that they diversify into
areas where they have fewer commercial advantages.

National oil companies (NOCs) currently rely on debt for around 35% of their total
investment and they have also responded to these financial pressures. Most NOCs generateenough income from their upstream assets to cover capital requirements, but their strategic
and financial autonomy is dictated by their host governments, and debt financing is often
used when they need to finance a rapid increase in production, expand overseas or grownew business areas.
Development finance institutions (DFIs) have in the past helped finance oil and gas projects
in a number of emerging market and developing economies, although their share of total oil
and gas investment was less than 0.2% in 2022. Many DFIs have restricted financing for fossil
fuels. For example, the World Bank Group stopped investing in upstream oil and gas in 2019,
and the European Investment Bank has indicated that it will no longer consider new financing
for unabated fossil fuel projects from 2021. Other DFIs have restricted financing for coal andoil, but make allowances for natural gas (Ferragamo & Auth, 2021).

IEA. CC BY 4.0

3.2.2

Social, legal and political pressure

The oil and gas industry requires a social licence to be able to build and operate facilities in theareas that it is active. In the past, concerns about projects traditionally focused on local impacts,
including the potential for air pollution and water use and contamination. But the threats posedby climate change – and the industry’s contribution to climate change – have widened andheightened the pressures the industry faces. These have been manifested in a number of ways,
including through local protests and direct action, legal action and political pressure.
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International Energy Agency | Special ReportLocal protests and direct action. The oil and gas industry is facing increased opposition to
new oil and gas infrastructure projects in some parts of the world. These can delay or lead tothe cancellation of licensing and development of some projects. The East African Crude Oil
Pipeline (EACOP) project, for example, has faced opposition due to concerns about climate
and biodiversity impacts, and protests and blockades have delayed its development. In somecountries, citizens have also been taking direct action through protests and campaigns toraise awareness of climate issues and to oppose new oil and gas licensing rounds and project
developments.
Legal action. Civil society organisations, often supported by institutional investors, havebrought legal action against oil and gas companies over their climate strategies. More than
2 300 climate-related legal cases have been raised around the world to date and around 30%
of cases brought in 2022 targeted fossil fuel exploration, production and transport(Setzer & Higham, 2023). Many of these cases focus on the majors and their tradeassociations to discourage them from continuing high-emissions activities, to force them tointegrate climate considerations into strategic decisions, or to seek financial compensationfrom climate change-related damages (Wentz, et al., 2023).
Oil and gas companies have also filed lawsuits against climate policies. These have included
challenges against pauses on new oil and gas leasing on public lands and in offshore waters
in the United States, fuel economy standards, greenhouse gas (GHG) reporting
requirements, and against the revocation of permits for large-scale infrastructure projects(Sabin Center for Climate Change Law, 2023).

IEA. CC BY 4.0

Political pressure. Few governments to date have explicitly stated a wish to stop all oil andgas activities in their jurisdictions: those that have include Denmark, Costa Rica, Ecuador,
Spain and France (Higham & Koehl, 2021). However, government policies, regulations andguidance related to climate change are affecting the operations and business decisions of oil
and gas companies, including national oil companies (NOCs). For example, India’s Oil andNatural Gas Corporation (ONGC) is required to diversify its investment portfolio to include
renewable energy alongside its plans for oil and gas expansion. As part of its most recent
nationally determined contribution (NDC), the United Arab Emirates indicates that the Abu
Dhabi National Oil Company (ADNOC) will become a net zero emissions company by 2050.
Iraq aims to leverage international support to reduce its greenhouse gas emissions by 15%
by 2030, including by reducing methane emissions from its oil and gas activities. Qatar’s NDC
lists measures to diversify the economy away from hydrocarbons and commits its NOC tozero routine flaring by 2030 and to reduce methane emissions across the natural gas value
chain.
A number of intergovernmental and civil society organisations exist that seek to stop future
oil and gas licensing or developments. Examples include the Beyond Oil and Gas Alliance,
which is an international alliance of governments and other stakeholders looking to facilitate
the managed phase-out of oil and gas production, and the Fossil Fuel Non-Proliferation
Treaty Initiative, which is a network of civil society organisations looking to stop the
expansion of fossil fuel use and wind down existing production.
Chapter 3 | Strategic responses of companies

1173

3.2.3

Employment

The oil and gas industry employs nearly 12 million workers globally (Figure 3.2). Around 60%
are employed in upstream segments, developing projects and maintaining production atexisting fields, while the remainder work in transport, refining and utilities. Workers areclearly essential to oil and gas activity, but fears over long-term job prospects means someparts of the industry have recently been struggling to retain and hire workers.
Figure 3.2 ⊳Employment in oil and gas supply, 2022
Natural gas

Oil
Upstream

18%

17%

14%

Midstream
LNG

7.6 million
employees
65%

Distribution
utilities

14%

4.1 million
employees

57%

15%

Refining

IEA. CC BY 4.0.

The largest share of workers are engaged in upstream activities, while in gas supply around
15% of employment is linked to each of distribution utilities, LNG and midstream work.
Notes: LNG = liquefied natural gas. Does not include employment at retail refuelling stations, as many of thesejobs are connected to service and retail and are not linked exclusively to oil and gas.

The plunge in oil demand and prices in 2020 spurred massive layoffs in the oil and gas
industry, with around a million jobs lost worldwide that year. Employment in oil has
recovered more slowly than gas from these pandemic-induced job losses, partly because of
the strong growth in LNG trade in 2022 following Russia’s invasion of Ukraine. Around
60 liquefaction and regasification terminals are currently under construction or coming
online worldwide, translating into nearly 150 000 LNG-related jobs in construction alone.

IEA. CC BY 4.0

NOCs and international national oil companies (INOCs) represent a much greater share of oil
and gas employment than the majors, and they were less likely to lay off workers due to the
Covid-19 pandemic (Figure 3.3). State-owned oil and gas companies may be seen by hostgovernments as a means to provide secure employment for their citizens, and NOCs tend tohave greater employee headcounts and lower productivity than INOCs, which rely moreheavily on outsourcing to contractors and oilfield services companies.
NOCs generally have more employees than the majors and are often in less diversified
economies, but they may also have a greater capacity to weather declining demand by
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International Energy Agency | Special Reportreassigning employees elsewhere in the public sector. In any case, oil and gas employment
does not disappear, even in the APS and NZE Scenario. In 2030 there are around 10.5 million
oil and gas workers in the APS and over 9 million workers in the NZE Scenario. Jobs in the gas
supply sector tend to be more robust, with the number of workers declining more slowly
over this period in both the APS and NZE Scenario (Figure 3.4).

boe/employee/day

Figure 3.3 ⊳Oil and gas production to employee ratio versus size ofworkforce in selected NOCs and INOCs, 2015-2021 average

3100
Equinor75
Ecopetrol
Petronas
Petrobras
ONGC
PDVSA
25
YPF Pertamina Pemex
50

Gazprom
Rosneft

Naftogaz
0100

SinoPec
200

300

PetroChina

400
500
600
700
800
Thousand employees (2015-2021 average)
IEA. CC BY 4.0.

Nationally owned oil and gas companies generally have an inverse relationship between
workforce size and labour productivity.
Notes: boe= barrel of oil equivalent. Figure excludes Saudi Aramco, which produces more than180 boe/employee per day.

IEA. CC BY 4.0

Net zero transitions result in large shifts in employment between and within different partsof the energy sector. But the number of job losses in oil and gas employment is smaller than
the number of clean energy jobs created in both the APS and NZE Scenario. Moreover, manyoil and gas workers possess skills that are in high demand in other parts of the energy sector;
for example, petroleum and gas engineering skills are highly applicable to the geothermal
industry and chemical engineers in refineries can help with the scale-up of hydrogen andhydrogen-based fuels (see Chapter 2).
The mobility and skills of oil and gas workers, especially highly skilled employees such asengineers, have already made them a highly sought-after group across other energy sectors,
as well as in non-energy industries such as technology. As a result, even with recent wavesof layoffs at the majors, many parts of the oil and gas industry are struggling to retain
experienced employees and find suitably skilled new workers. Concerns including career
security, instability associated with the boom and bust nature of oil and gas, and the energy
transition have made some new workforce entrants hesitant to commit to a career in oil and
Chapter 3 | Strategic responses of companies

119gas companies, especially in advanced economies such as Europe and the United States.
Those same factors have led an increasing number of oil and gas workers to express interest
in moving out of the industry, with as many as 85% considering switching to another sector
such as renewables or technology (Airswift, 2023). But possibly the most important cause of
the skills shortage is the retirement of the oil and gas workforce, which is shrinking theavailability of workers with relevant skills.
Employment in oil and gas supply by region and scenario, 2022
and 2030

Million employees

Figure 3.4 ⊳82022

APS 2030

NZE 2030
World
North America
C & S America
EuropeAfricaAsia PacificMiddle East
Eurasia

6
4
2

Oil

Naturalgas

OilNaturalgas

OilNaturalgas
IEA. CC BY 4.0.

Employment in oil and gas supply decreases by the end of the decadein the APS and NZE Scenario, but the gas workforce shows greater stability.
Note: C & S America = Central and South America.

IEA. CC BY 4.0

Oil and gas companies have recently been increasing wages as they struggle to hire new staff
and retain existing employees. Companies are also testing new recruitment and internal
career paths to respond to professional expectations and the need for flexibility in future
market developments.
The jobs created by the energy transition will not necessarily require the same skills, pay as
much, or be in the same geographies as the jobs lost. Although energy jobs worldwide are,on average, better paid than the median national wages, workers in oil and gas tend to earnmore than workers in less-established clean energy industries (Figure 3.5). In the
United States, for example, the median hourly wage of oil and gas workers is around 75%
greater than the economy-wide average, while the median for wind and solar workers isaround 50% larger than the average. This can be attributed to a combination of factors,
including the significant skill requirements for oil and gas work, high rents from oil and gas
production, greater compensation for occupational hazards, instability and relocation, andthe industry’s well-established union representation.
120

International Energy Agency | Special ReportThousand USD

Figure 3.5 ⊳Average annual salary of permanent energy workers, by industry
and region, 2023

120

Oil and natural gas

100

Renewables

3

Petrochemicals

80
60
40
20
Asia

AfricaNorth
America

EuropeMiddleEast
IEA. CC BY 4.0.

On average, the renewables sector offers lower salaries than the oil and gas sector,
a potential barrier to workers shifting between industries.
Note: Average annual salary of permanent workers based on six years’ experience.
Sources: Airswift (2023).

3.3

Oil and gas company responses to date

A number of large oil and gas companies have made announcements on how they plan torespond to the increasing pressures they are facing. These vary widely in their nature, scope
and ambition, and some previously announced goals were weakened following the 2022
energy crisis. The responses of companies can be broadly grouped into two main areas: plansto reduce scope 1 and 2 emissions from traditional oil and gas operations; and strategic
moves to diversify and invest in areas outside their core businesses.1

3.3.1

Targets to reduce scope 1 and 2 emissions

IEA. CC BY 4.0

Our detailed analysis of 40 large oil and gas companies indicates that just under half ofcurrent global oil and gas output is produced by companies that have announced a target to
reduce their scope 1 and 2 emissions. These targets have been expressed in many different
ways. The majority are specified as a reduction in absolute emissions from operations rather
than a reduction in the emissions intensity of operations (Figure 3.6). Around 40% of these1 Scope 1 emissions come directly from oil and gas operations; Scope 2 emissions arise from the generation ofpurchased energy. See Section 2.2 for further details on definitions.

Chapter 3 | Strategic responses of companies

121companies have announced a target only for 2050; the other 60% have announced an interim
target (for a date between 2025 and 2035) alongside a target for 2050.
Figure 3.6 ⊳Coverage and characteristics of company scope 1 and 2
emissions targets

Absolute and intensity targets

Absolute or absolute and intensity

Interim and long-term targets

Interim and long-termLong-term only

Target coverage

All operations

Target applies to

Operated assets

Absolute reduction 2021-30<20%

Use of emissions offsets

Upstream
Owned

20-30% 30-40%

Use offsets
20%

Intensity

40%

40-60% >60%

Not specified
60%

80%

100%
IEA. CC BY 4.0.

Around half of the oil and gas produced today comes from companies withscope 1 and 2 targets, but these vary widely in their ambition and scope.
Note: Depicts share of oil and gas produced by companies with targets. For the absolute reduction 2021-30,
reduction targets expressed as an emissions intensity reduction are converted to absolute reductions
assuming stated production plans or production changes in line with history. Linear interpolation used toderive 2030 values when not given.
Sources: IEA analysis based on annual reports of 40 oil and gas companies representing more than 60% of
global production; all other companies are assumed not to have a target.

Most companies indicate that their reduction targets cover only the emissions from directly
operated assets and exclude emissions from assets in which they hold an equity stake (seeChapter 1). This approach reflects legal and contractual requirements to manage GHG
impacts and most sustainability reporting frameworks do not require companies to reportemissions from non-operated assets. This means a major source of emissions could be
excluded from their targets. Some companies have therefore announced aims to use theirinfluence to achieve reductions at non-operated assets.

IEA. CC BY 4.0

Combining the above factors, we estimate that around half of the targets aim to reduce
absolute emissions by less than 20% by 2030. Only 5% of the oil and gas produced bycompanies with targets – i.e. less than 2% of global oil and gas production – is covered by atarget to reduce emissions by 60% or more to 2030 (the overall level of reduction in the
NZE Scenario [Section 3.5.1]).
One critical issue for scope 1 and 2 emissions reduction targets – however they are specified – isthe level of accuracy with which emissions are measured and how they are reported. One
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International Energy Agency | Special Reportparticular area of concern is methane emissions. Based on all publicly available methane
emissions measurement studies, we estimate that oil and gas operations were responsible foraround 80 Mt of methane emissions in 2022 (IEA, 2023b). This is much higher than implied by
the emissions from company reporting. For example, a recent industry report – covering morethan 20% of global oil and gas supply – indicated that around 0.5 tonnes of methane acrossthe supply chain were emitted per tonne of oil equivalent of oil and gas production (IOGP,
2023). If these companies were to be fully representative of the industry globally, then global
oil and gas methane emissions would be around 4 Mt, 95% lower than our estimate.
A number of companies have set out how they intend to cut emissions from their operations,
including the investment that will be required. This includes investing in energy saving
measures and materials, decarbonising electricity, and equipping facilities with carbon
capture, utilisation and storage (CCUS). Three quarters of the companies in our sample
indicate their intent to use emissions offsets to achieve their targets (Box 3.1).
Mergers and acquisitions have important implications for the way some oil and gas
companies could look to achieve their scope 1 and 2 emissions reduction targets. For
example, a company may decide to sell a high-emissions intensity asset rather thanundertake direct efforts to improve its environmental performance. This takes on an
additional dimension if the acquiring company has less stringent environmental conditions
and chooses to operate it in a more emissions-intensive way. The transfer of the asset may
help one company achieve its own emissions reduction targets, but it could lead to an overall
increase in emissions globally. It is estimated that asset transfers from companies withenvironmental commitments to those without increased from 15% of the overall value ofmergers and acquisitions in 2018 to 30% of the total value of deals in 2021 (EDF, 2023a).
Governments have a key role to play in preventing these perverse outcomes. Setting
country-wide goals on emissions intensity or emissions reduction requirements would limit
the risk of asset transfers leading to an increase in emissions. But companies themselves canalso undertake efforts to avoid asset disposals leading to increased emissions. Examples ofpossible actions include: assessing the emissions targets of acquirers as part of the due
diligence process before making a deal; making it clear how much of their company-wide
emissions reductions are due to transfers as compared to direct emissions reduction efforts;
and working with buyers to strengthen their emissions reduction targets and plans for asset
decommissioning (EDF, 2023b).

IEA. CC BY 4.0

Box 3.1 ⊳Using carbon credits to meet emissions targets

Three quarters of the oil and gas companies with scope 1 and 2 emissions reduction
targets have stated that they will use carbon credits to help them achieve their targets.
The remainder have not specified how they will achieve their targets, but few have totallyruled out the use of carbon credits. Carbon credits can play a role in net zero transitions,but it is important to distinguish between projects that avoid, reduce or remove
emissions:

Chapter 3 | Strategic responses of companies

123

3



Avoidance credits are generated by projects that avoid emissions from an activity
that would have otherwise caused emissions, e.g. avoiding deforestation or avoiding
the extraction of fossil fuel reserves. These are highly dependent on the credibilityof the counterfactual (in which the emissions would have occurred) and face thepossibility that the emissions take place anyway.



Reduction credits are generated by projects that directly reduce GHG emissions
from existing activities, e.g. energy efficiency improvements, methane abatement or
use of CCUS. There are likely to be few reduction credits generated in rapid net zeroglobal energy transitions as there is limited scope to demonstrate additionality.



Removal credits are generated through CO2 removal technologies or nature-based
solutions. The NZE Scenario sees 1.6 gigatonnes (Gt) of emission removals throughdirect air capture with CCUS (DACS) and bioenergy with CCUS (BECCS) in 2050 andno removal offsets from outside the energy sector.

The supply of high-quality carbon credits is struggling to keep pace with current demand.
A number of questions have been raised around the integrity of many existing schemes,
including addressing their long-term permanence, additionality, and the methods used
to issue credits (Kreibich & Hermwille, 2021). In some cases, projects generating credits
have also had negative impacts on local communities (Robinson, et al., 2016).

Mt CO₂

Figure 3.7 ⊳
2 000

1 500

Residual emissions and CO2 removal in the NZE Scenario,
2050
Residual emissions

Other
Power

1 000

CO₂ removal

Buildings
Oil and gas

DACSTransport
BECCS

500
Industry

IEA. CC BY 4.0.

In the NZE Scenario, the oil and gas sector accounts for around 5% of total removals
via DACS and BECCS in 2050 to offset its remaining emissions.

IEA. CC BY 4.0

Notes: DACS = direct air capture with CCUS; BECCS = bioenergy with CCUS.

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International Energy Agency | Special ReportIn the NZE Scenario, there is a 98% reduction in oil and gas sector scope 1 and 2 emissions
to 2050 that is achieved without using any carbon credits. In 2050 remaining scope 1
and 2 emissions from oil and gas supply amount to 75 Mt CO2, most of which is fromrefining. These emissions are offset through the use of DACS and BECCS and account foraround 5% of total CO2 removals in 2050 (Figure 3.7).
If oil and gas companies purchase removal carbon credits, this could help accelerate thedevelopment of negative emissions technologies more broadly. But the availability ofquality credits is likely to be limited, and would only be consistent with the NZE Scenario
once all efforts to realise real emissions reductions have been made. Given its existingskills and expertise, the industry could also look to develop negative emissions
technologies itself and sell credits to generate an additional source of income.

3.3.2

Targets to diversify into clean energy technologies

Just under 20% of current oil and gas production comes from companies that haveannounced a target to diversify their activities into clean energy (Figure 3.8). A number ofcompanies, including TotalEnergies, Equinor and BP, have pledged to invest a share of theircapital budget in electricity and renewables, or low-emissions and zero-emissions options.
Companies have also set specific capacity or spending targets for the deployment oftechnologies including CCUS, renewable power, bioenergy, low-emissions hydrogen andelectric vehicle (EV) charging stations. In addition, eight companies have announced targets
to reduce their scope 3 emissions. While there have been increasing calls on the industry to
set such targets, they can have a number of potential drawbacks (Box 3.2).
Figure 3.8 ⊳Share of global oil and gas production from companies withdiversification targets

At least one
diversification measure
CCUS
Renewable powerLow-emissions fuels
Capex on clean energy
EV charging
5%

10%

15%

20%

IEA. CC BY 4.0

IEA. CC BY 4.0.

Companies producing around 20% of oil and gas today have a target to diversify into
clean energy; CCUS and renewables are the most frequently cited technology choices.
Sources: IEA analysis based on public reports of 40 companies providing 60% of global oil and gas production.

Chapter 3 | Strategic responses of companies

1253Box 3.2 ⊳The trouble with scope 3 targets

Different “scopes” of emissions are used to help companies distinguish between thevarious ways that their business activities can result in emissions. Scope 3 includes
emissions caused before the company’s activities (e.g. during the manufacture of theequipment it uses) and after (e.g. from the processing and use of sold products). For theoil and gas industry, the largest source of scope 3 emissions is the combustion of oil andgas by end-use consumers; this accounts for 80% of the life cycle emissions of oil and 85%of the life cycle emissions of natural gas. Eight oil and gas companies – including BP,
Chevron, ENI, Equinor, Oxy, Repsol, Shell, and TotalEnergies – have announced scope 3
emissions reduction targets, and there have been calls for all companies to set targets
for reducing scope 3 emissions.
An oil and gas company can cut its scope 3 emissions in a number of ways, including:ensuring the oil and gas it produces, processes or transports is used with CCUS; ensuring
it is used in a non-combustion activity (e.g. converted into plastic); or reducing theamount of oil and gas sold. If the company sets a target to reduce scope 3 emissions
intensity, another option is to increase the proportion of lower-emissions energy sold.

IEA. CC BY 4.0

Scope 3 emissions reduction targets can be a useful signal of a company’s plans and how
it intends to achieve these, but they could also lead to some perverse incentives that
limits the real emissions reductions achieved. Targets relating to oil and gas production
or on clean energy deployment are likely to be easier to operationalise, more transparent
and align better with the overall needs of net zero transitions (Section 3.5). Somepotential issues with scope 3 targets are:

There is no clear designation of who should take the lead on reducing scope 3
emissions. Initiatives such as the Science-Based Target Initiative and Net Zero
Banking Alliance have taken a variety of views: the producers can take responsibility,or the user of the product, or all actors along the value chain. Oil and gas companies
can influence, anticipate and deliver on customer needs, but they are in general
unable to dictate how end-use customers use their products.



Scope 3 emissions are reported multiple times by different entities along the value
chain. Oil produced by one company, refined by another, transported by a third, andsold to end-use consumers by a fourth would result in scope 3 emissions being
reported for all four of the companies. Targets to cut down on scope 3 emissions
may encourage companies to change the ownership of and responsibility for
products to reduce emissions on paper, but without any real emissions reductions.



A number of scope 3 emissions targets stipulated to date are combined reductionsin scope 1, 2 and 3 emissions. Scope 1 and 2 commitments need to be ambitious andunambiguous to align with net zero transitions; combined scope 1, 2 and 3 targets
risks diluting the importance of reducing a company’s own emissions.

126

International Energy Agency | Special Report

The oil and gas industry invested around USD 20 billion in clean energy technologies in 2022
through direct investment, mergers and acquisitions and joint ventures, and corporate
venture capital (IEA, 2023a). This included investment in a wide range of technologies suchas solar PV, onshore and offshore wind, geothermal power, biofuel or biogas production,hydrogen, EV charging, and CCUS.2 Bioenergy accounted for more than half of the industry’s
clean energy spending in 2022 as a number of companies took major stakes in several
bioenergy producers, with significant acquisitions by BP, Shell and Chevron (Figure 3.9).

Billion USD (2022, MER)

Figure 3.9 ⊳Investment by the oil and gas industry in clean energy
technologies, 2015-2022

20

Other
Energy storage

15

CCUS
Bioenergy

10Wind
Solar PV

5

2015

2016

2017

2018

2019

2020

2021

2022
IEA. CC BY 4.0.

Clean energy investment by oil and gas companies doubled in 2022 to around
USD 20 billion, with companies taking major stakes in several bioenergy producers.
Note: Other include electrolysis and CCUS hydrogen as well as geothermal, small hydro and hybrid projects.
Sources: IEA analysis based on annual reports, Clean Energy Pipeline (2023), Rystad Energy (2023) and
IJ Global (2023).

IEA. CC BY 4.0

Clean energy investment by the oil and gas industry as a whole represented 2.7% of its total
capital spending in 2022 and 1.2% of total investment in clean energy (Figure 3.10). Morethan 60% of this came from four companies: Equinor, TotalEnergies, Shell and BP, whichspent each around 15-25% of their total budgets on clean energy. A number of companies
spent much smaller shares (e.g. CNPC, Qatar Energy and ConocoPhillips), others indicate thatthey invest in clean energy but have not stated the amounts involved (e.g. ADNOC), andmany have not provided any guidance on their levels of clean energy spending.

2 The clean energy investment amounts reported here do not include investment in nature-based solutions,scope 1 and 2 emissions reduction measures, or other business activities, such as investment in retail sites.

Chapter 3 | Strategic responses of companies

127

3Figure 3.10 ⊳ Clean energy investment by the oil and gas industry as a shareof its total investment and of global clean energy investment

3%

Share of investment by the industry

Share of global clean energy investment

2%

1%

2015

2020

2022 2015

2020

2022
IEA. CC BY 4.0.

Clean energy investment by oil and gas companies has accelerated since 2019. In 2022 it
represented 2.7% of total capital expenditure and 1.2% of global clean energy investment.
Sources: IEA analysis based on annual reports, Clean Energy Pipeline (2023), Rystad Energy (2023) and
IJ Global (2023).

3.4

What could net zero energy companies look like in
2050?

IEA. CC BY 4.0

The industry landscape is diverse and no single option will make sense for all, but oil and gas
companies looking to align their portfolios with net zero transitions need to change. Thissection provides illustrative examples of how today’s oil and gas companies would look ifthey chose to scale up clean energy activities and evolve their portfolios in line with trends
in the NZE Scenario. An alternative approach – not examined here, but also fully aligned with
the NZE Scenario – would be simply to wind down oil and gas operations in line with theoverarching declines in oil and gas demand (see Section 3.5).
There are a number of major challenges that a company would face in practice when looking
to achieve a major shift in its energy portfolio. In particular, inertia in shifting the corporate
culture could significantly slow down or even prevent the wholesale reorientation ofactivities. For example, oil and gas activities have typically been associated with a high levelof risk and reward and accompanied by a high degree of volatility in returns. Clean energy
technologies in contrast often have more tightly controlled or regulated returns and so, while
they may have a similar overall level of return on capital invested as oil and gas, they do notdisplay such large year-on-year fluctuations and thus have fewer opportunities for windfall
profits (see Box 2.2 in Chapter 2).
128

International Energy Agency | Special ReportSome companies might therefore choose to restructure and spin off fossil fuel activities or
new clean energy businesses, similar to the approach of several European electricity utilities
in the 2010s. Alternatively, companies could look to scale up their clean energy portfolio by
acquiring successful clean energy companies in the future. This wait-and-see approach also
carries significant risks. The acquisition target may not be prepared to be a junior partner, it
tends to be hard to merge large firms with very different cultures, and competition for any
available firms is likely to be fierce.
Companies could also look to learn quickly about new technology areas through corporate
venture capital (CVC) investment (Box 3.3). This may be especially useful in areas where thecompany has limited existing experience and would face difficulties launching its own new
product line, and where there is the risk that new businesses would struggle for sufficientattention and tolerance within the corporate parent. CVC investment is typically used as a
low-cost means of supporting start-ups that could become future acquisition targets,allowing them to operate initially outside the cultural constraints of the parent company.
Whichever strategy is used to transform in line with net zero transitions, profitability remains
a crucial consideration and pursuing diversification strategies involves multiple risks.
Companies could unwittingly acquire clean energy firms at inflated prices, choose
underperforming technologies, invest in oversaturated markets, misread policy signals, orventure too far from their core areas of expertise so that they lose commercial advantages.
In this section, we provide illustrative energy portfolios in 2050 of different types of oil andgas company if they were to provide the same amount of energy, or support the same levelsof energy service demands, in 2050 as they do today but in a manner consistent with the
NZE Scenario.
Box 3.3 ⊳Clean energy corporate venture capital spending by the oil andgas industry

IEA. CC BY 4.0

Oil and gas companies’ CVC investments in clean energy start-ups hit a record level in
2022 at USD 1.2 billion (Figure 3.11). The fivefold growth of CVC investment by the oiland gas sector since 2018 indicates a strategic evolution in their approach to technology.
As well as financial support, oil and gas companies can provide valuable access to testing
facilities, customers and commercial networks. In 2021 and 2022, CVC growth was driven
by hydrogen, CCUS and renewable energy technologies. The majority of this equity
investment was in growth-stage start-ups that are bringing a tested product to market,
with the biggest deals relating to CCUS, solar PV and synthetic fuels. Only 17% of the total
was for riskier early-stage start-ups, where the deals were concentrated in energy
storage, geothermal and hydrogen. Overall, the data indicate some opportunities fordiversification, given that 60% of the funding went to US-based start-ups and only low
shares went to innovators in areas such as bioenergy, wind and CO2 storage, where oiland gas expertise will be critical for success.

Chapter 3 | Strategic responses of companies

1293Figure 3.11 ⊳ Corporate venture capital investment by oil and gas
Million USD (2022)

companies in energy start-ups by technology area

1 250

Other
Fossil fuels

1 000

CCUS
Nuclear

750

Other renewables
Bioenergy

500

Hydrogen, fuel cells
and synthetic fuels

250

Energy storage,
batteries and mobility
2015 2016 2017 2018 2019 2020 2021 2022
IEA. CC BY 4.0.

The oil and natural gas industry has grown its CVC activity fivefold since 2018,with most investment in battery, EV, hydrogen and renewable start-ups.
Note: Includes early-stage and growth-stage investments, according to definitions used in IEA (2023a).
Source: IEA analysis based on Cleantech Group (2023).

3.4.1

A net zero “major” energy company

IEA. CC BY 4.0

The seven oil and gas majors currently each produce on average 1.5 million barrels per day(mb/d) of oil and 65 billion cubic metres (bcm) of natural gas per year. One possible option
to transition to be a net zero major energy company would be to continue to produce
1.5 mb/d of oil and 65 bcm of natural gas every year but to rapidly expand the use of CCUS
and carbon removal to avoid the associated emissions. This would involve developing around
60 Mt CO2 of CCUS capacity and around 200 Mt CO2 of carbon removal capacity. This would
require around USD 25 billion investment every year to 2050, which would be in addition to
the USD 10 billion likely needed on average each year to maintain its oil and gas productionlevels. Mobilising this level of capital would be an immense challenge as it three-and-a-halftimes the annual average capital expenditure of the majors over the past five years(USD 10 billion). This approach is therefore likely an option only in theory for a major totransition to be a net zero energy company.
An alternative approach would be to grow a broader portfolio of low-emissions fuels andproducts in line with the trends of the NZE Scenario. The oil and gas produced by a major
today provides the energy for around 250 billion vehicle kilometres, 8 Mt of primarychemicals, and thermal comfort, light and heat for 20 million homes, among many otherservice demands. If these same service demands were to be provided without any emissions,what might a net zero major energy company look like?
130

International Energy Agency | Special ReportIn 2050 in the NZE Scenario, oil and natural gas are still used in sectors where the fuels are
not combusted – as in petrochemicals – and in facilities equipped with CCUS. The company
would therefore still produce around 350 thousand barrels of oil per day (kb/d) and 6 bcm
of natural gas in 2050. This would need to be accompanied by extensive efforts to cut scope
1 and 2 emissions.
A large portion of the company’s energy portfolio in 2050 would consist of renewables(Figure 3.12). Over 300 gigawatts (GW) of renewables would be needed to replace some ofthe energy services currently met by oil and natural gas. Half of this capacity would beneeded to provide electricity for EVs to support a similar level of passenger vehicle
kilometres, a further 30% to support the rollout of electrolytic hydrogen production, and theremainder to produce power for other electrified energy service demands, such as
household heat pumps to provide thermal comfort and industrial-scale electric motors toprovide a range of manufactured products.
Figure 3.12 ⊳ Example of major’s energy production portfolio in 2050 aligned

CCUShydrogenOil and gas
combusted

Electrolytichydrogenwith changes in the NZE Scenario

Gas with
CCUS

CO₂ removal
IEA. CC BY 4.0.

A large oil and gas company would need to make significant efforts to diversify its energy
supply to provide the same energy services in the NZE Scenario in 2050 as today
Notes: Blocks are sized by the contribution of each energy source and technology to meeting the energy
service demands currently met by 1.5 mb/d of oil and 65 bcm of natural gas.

IEA. CC BY 4.0

The company would produce around 12 billion cubic metres equivalent (bcm-eq) of
low-emissions hydrogen produced from electrolysis or from natural gas with CCUS, as well
as around 85 kboe/d of biofuels. It would capture and store 8 Mt CO2 from oil and gas use
and remove a further 12 Mt CO2 from the atmosphere to offset residual emissions fromremaining combustion of oil and natural gas.

Chapter 3 | Strategic responses of companies

1313

On average, we estimate that it would cost just over USD 20 billion per year to 2050 for thecompany to undertake this full transformation of its energy portfolio, around twice theaverage annual capital expenditure of an oil and gas major in recent years. By 2050, less than
10% of capital investment would be to sustain existing oil and gas operations, and theremainder would be allocated to clean energy.

3.4.2

A liquids-focused national oil company

Companies could also choose to focus on their core strengths, rather than diversify into new
business areas. For example, a company might decide to retain a focus on liquids production,
processing and transport, leveraging its existing assets while building up new capabilities to
produce low-emissions fuels such as liquid bioenergy and low-emissions hydrogen-based
fuels (Figure 3.13). Here we examine what a company portfolio could look like if it continues
to provide a similar level of liquids to the market as it does today.
This route may be attractive for some vertically integrated NOCs with a strong presence
across the upstream, midstream and downstream parts of the oil value chain. The group of
NOCs and INOCs encompasses a wide variety of companies, but the 20 largest
liquids-focussed NOCs on average produce around 2 mb/d of crude oil and natural gas
liquids. Most process this in their own refineries and petrochemical plants. On averagearound 60% of refinery output by volume is gasoline and diesel, 15% is fuel oil and kerosene,
and a large part of the remainder is feedstock for use in the petrochemical sector.
In the NZE Scenario, 35.5 mboe/d of liquids are consumed in 2050, comprising 24 mb/d ofoil and 11.5 mboe/d of liquid biofuels and low-emissions hydrogen-based fuels. This level ofliquids demand in 2050 is two-thirds lower than in 2022 and so a company looking tocontinue deliver 2 mboe/d of liquid fuels through to 2050 would boost its overall share of
the market from about 2% in 2022 to 6% in 2050.3
Around 65% of liquids portfolio in 2050 of an NOC looking to evolve in this way would still
consist of oil products but the types of products produced would change dramatically.
Gasoline, diesel, and fuel oil would shrink to less than 15% of total output in 2050, and theshare of petrochemical feedstocks and other non-combusted oil products would increase toalmost 80% (including products that are supplied by fractionating natural gas liquids). This
would require investment to reconfigure refineries and to ensure scope 1 and 2 emissions
are minimised along the oil supply chain.

IEA. CC BY 4.0

The other 35% of the NOC liquids portfolio would consist of low-emissions liquid fuels. This
would include 170 kboe/d of advanced biofuels for road transport and 150 kboe/d of biojet
kerosene. It would also produce 200 kboe/d of ammonia for use in the power sector and inshipping and 180 kboe/d of low-emissions hydrogen-based kerosene for aviation. A

3 It would not be possible for all NOCs to increase their market share in this way as the space narrows

considerably in the NZE Scenario.

132

International Energy Agency | Special Reportsuccessful foray into this area would be contingent on the sourcing and processing of several
million tonnes of sustainable feedstocks and the construction of capacity that can produce
8 Mt each year of low-emissions hydrogen.
The large NOCs also possess infrastructure, such as depleted oil and gas fields, that is
amenable to being repurposed for CO2 or hydrogen storage. This could be used to help an
NOC offset residual emissions from its production portfolio. The NOC would own around
5 Mt CO2 of CCUS capacity for oil use in industry and a further 50 Mt of CO2 removal capacity(meaning close to 55 Mt CO2 of CCUS capacity in total).
We estimate that the NOC would need to invest about USD 15 billion on average each year
to 2050 to undertake this transformation of its energy portfolio. By 2050, around 20% of its
capital expenditure would be in oil supply, maintaining and transforming oil refineries, andreducing scope 1 and 2 emissions. The remainder would be invested in low-emissions fuels
and products (55%) and investment in carbon removal (25%). This overall level of investment
is around two-and-a-half times the USD 5.5 billion average annual capital investment in oil
production of the 20 largest NOCs in recent years, highlighting the challenges that would beface to maintain its production levels but grow its share of the liquids market. To maintainthe same level of net income as it generates today while covering the additional capital costsof developing low-emissions liquids, the NOC would need to receive around USD 200/boe forlow-emissions hydrogen-based fuels and liquid biofuels sold in 2050.
Figure 3.13 ⊳ Example of changes in a liquids-focused NOC aligning its energy
production portfolio with the NZE Scenario in 2050
2022

2050

Low-emissionshydrogenbased fuels

Biojet kerosene

EthaneCO₂ removal

IEA. CC BY 4.0.

IEA. CC BY 4.0

A liquids-focused NOC could retain some traditional assets to produce oil products for
petrochemicals and non-energy use, while diversifying into biofuels and synthetic fuels.
Notes: 2022 and 2050 blocks represent 2 mboe/d of liquids production.

Chapter 3 | Strategic responses of companies

133

3Box 3.4 ⊳The pivotal role of NOCs and INOCs in net zero transitions

The group of NOCs and INOCs encompasses a wide variety of companies with very
different roles, governance, sizes, operations, and contributions to their domestic
economies (Figure 3.14). Nonetheless, they are all critically important stakeholders intheir host countries and will also be critical to efforts to achieve net zero transitions, both
domestically and globally.
Figure 3.14 ⊳ NOC and INOC oil and gas production, oil as a share of total

NOC income as share of GDP

production, and net income as a share of GDP, 2022

60%

Turkmengas
KPC

Sonatrach

NOC (Libya)

40%
NIOC

ADNOC

20%
PetoroUzbekneftegaz

Gazprom

EquinorPetronas
PTTEP

20%
EuropeAsia Pacific

Saudi
AramcoQatarEnergy

20%

Socar

Basra Oil

NNPC Rosneft
PDVSA

KMG
Petrobras

YPF

Sinopec
Pemex
ONGC
CNPC
CNOOC
Pertamina
Ecopetrol

40%

60%

80%

100%

Oil share of total production
Middle East
AfricaEurasia
Latin America

Oil and gas production(mboe/d)

4

2
IEA. CC BY 4.0.

NOCs and INOCs are a diverse group, with different starting points and approaches totransitions. Many are pivotal to their host country’s economies.
Notes: ADNOC = Abu Dhabi National Oil Corporation; CNOOC = China National Offshore Oil Corporation;
CNPC = China National Petroleum Corporation; KMG = KazMunayGas; KPC = Kuwait Petroleum
Corporation; NIOC = National Iranian Oil Company; NNPC = Nigerian National Petroleum Corporation;
NOC (Libya) = National Oil Corporation (Libya); ONGC = Oil and Natural Gas Corporation (India); PDVSA =Petróleos de Venezuela, S.A; PTTEP = PTT Exploration and Production (Thailand).
IEA. CC BY 4.0

Source: IEA analysis based on Rystad Energy (2023).

134

International Energy Agency | Special Report

The profits made by NOCs and INOCs have helped governments to finance a great dealof public spending, while supporting public infrastructure investments and employment.
This could be threatened by the drops in oil and gas revenues that occur in net zerotransitions (see Chapter 4). To date, most of the large NOCs have responded to thechallenge of net zero transitions by emphasising their role as custodians of nationalhydrocarbon resources, with an enhanced focus on supplying the oil and gas with thelowest possible emissions intensity.
Very few NOCs have been charged by their host governments with leadership roles inrenewables or other non-core areas. The predominant model thus far is for hydrocarbonrich countries to create separate companies and public initiatives focussing on clean
energy, leaving the NOC to focus on oil and gas. But the possibility that NOCs may also
take on roles in relation to low-emissions technologies cannot be excluded, not least
because of the possible synergies with their oil and gas operations. Someforward-looking NOCs and INOCs as well as those with dwindling oil and gas reserves areindeed accelerating efforts that target models of resource development compatible withnet zero transitions. These cover a range of areas, including CCUS, hydrogen, biofuels,
strategies to find and develop non-combustion uses for hydrocarbons as well as
diversification into clean electrification, through investment in renewables, grids andelectric vehicles.

3.4.3

An independent focused on gases

A number of independent companies focus almost exclusively on producing natural gas:these “pure-play” gas-focused independents are prevalent in North America, and they
produce anywhere in the range of 5-60 bcm of natural gas, mostly from shale gas plays. Here
we look at how the portfolio of a company that currently produces 20 bcm of natural gas
might look in 2050 if it seeks to maintain this level of production of gaseous fuels to 2050.
In the NZE Scenario, natural gas demand falls by close to 80% between 2022 and 2050 while
overall demand for gases falls by 55% to 2050. An independent looking to maintain 20 bcm
of production would therefore need to diversify into biogases, hydrogen, synthetic methane
and, given infrastructure synergies, CO2 capture, transport and storage. This would roughly
double the share of the overall gases market by 2050.

IEA. CC BY 4.0

Around 60% of the 2050 production portfolio of the independent would be natural gas, 25%
would be biogases, and 15% would be electrolytic hydrogen. Of the 12 bcm natural gas thatit produces in 2050, around 40% would be used in the power and industry sectors where theCO2 emissions are captured, 25% would be used in processes where the gas is not combusted,and 15% would be combusted and offset through the use of carbon removal. The remaining
20% would be converted into low-emissions hydrogen through the use of CCUS (Figure 3.15).
Combined with the electrolytic hydrogen and biogases that it produces, this means thataround half of the energy delivered by the independent to end-use consumers would be
Chapter 3 | Strategic responses of companies

1353

low-emissions gases (some of this hydrogen may be further transformed into low-emissionshydrogen-based fuels). Most of the biogas produced would be upgraded to biomethane as adrop-in substitute for natural gas, for use in transport or injected into remaining gas
transmission and distribution infrastructure.
Figure 3.15 ⊳ Example of changes in a gas-focused independent aligning its
energy production portfolio with the NZE Scenario in 2050

Natural gas
non-energy use

Natural gas
Electrolytic non-energyhydrogenuse

Natural gas
with CCUS

CCUS
hydrogenNatural gas
combusted

CO₂ removal
EA. CC BY 4.0.

A gas pure player could orient its business model towards hydrogen, biogases and CCUS,
while maintaining a pivotal role for natural gas production.
Note: Blocks represent 20 bcm-eq gases production. Natural gas combusted with CCUS includes gas captured
in power and industry and the losses incurred in producing hydrogen with CCUS.

IEA. CC BY 4.0

There are opportunities for a gas-focused player to integrate value chains across the
spectrum of natural gas, hydrogen, synthetic methane and biogas production. For example,
CO2 captured from the process of producing hydrogen from natural gas or from theupgrading of biogas to biomethane could be used as an input into the production of synthetic
methane (although using fossil CO2 would require the capture of emissions from combusting
the synthetic methane at the point of use and, in the NZE Scenario, low-emissions synthetic
fuels are made with carbon recovered from CO2 captured from bioenergy or the air).
Although production costs are higher, synthetic methane or biomethane could employ thesame infrastructure used to transport natural gas, including LNG terminals, without
modification. There are also options to utilise natural gas infrastructure for hydrogentransport and storage (see section 2.2.5).
In the NZE Scenario, greater differentiation of gas according to its emissions intensity is likely
to be a feature of international gas trade. Already today regulatory efforts in the
United States and Europe are underway to enhance the measurement, reporting andverification of emissions associated with gas, particularly methane. An independent gas
producer with a 20 bcm supply portfolio is likely to need to invest around USD 50 million on
136

International Energy Agency | Special Reportaverage each year to reduce its scope 1 and 2 emissions. This would include efforts to reduce
methane emissions with enhanced leak detection and repair programmes, eliminating
flaring, and electrification of midstream operations, such as gas pipeline compression or LNG
liquefaction.
Overall trade of natural gas declines by around 80% between 2022 and 2050 in the NZE
Scenario but gas players could still benefit from having trading divisions that commoditise amore diverse portfolio of fuels and technologies besides natural gas, such as hydrogen,biogases, CO2, and carbon credits. In recent years trading houses and the trading divisions ofmajors and NOCs have accounted for a large share of total profits from oil and gas sales.
We estimate that the overall cost to transition to this low-emissions gas portfolio in 2050
would be around USD 3.5 billion per year. Around one-quarter of this would be for natural
gas production and to reduce the emissions intensity of supply, half would be to develop
low-emissions hydrogen, the associated CCUS capacity, and biogases, and the remaining
one-quarter to develop the carbon removal capacity needed to offset unabated natural gas(around 8 Mt CO2). This is a substantial increase from the USD 1.1 billion that an independent
gas player with a 20 bcm gas supply invests on average each year currently. We estimate thatto maintain the same level of net income as it generates today while covering the additional
capital costs of developing low-emissions gases, the independent gas producer would needto sell low-emissions hydrogen and biogases for an average price of USD 20/Mbtu in 2050.

3.5

Assessing alignment with net zero transitions

In this section we explore how oil and gas companies can play an active part in supportingnet zero transitions. Benchmarks based on the APS and NZE Scenario cannot capture all the
specifics of the wide range of oil and gas companies that exist. Nonetheless, they provide a
broad guide for the industry as a whole as well as for individual companies looking to playtheir part in achieving net zero transitions. Here, we focus on the targets that need to be set– and achieved – by 2030 given the importance of immediate action to keep net zero goals
within reach.

3.5.1

Emissions from own operations

IEA. CC BY 4.0

In the APS, the global average scope 1 and 2 emissions intensity of oil and gas supply falls byaround one-third between 2022 and 2030 and the absolute level of emissions falls by a similar
amount (see Chapter 2). In the NZE Scenario, the global average emissions intensity falls by
more than 50% to 2030 and total emissions fall by more than 60% in this period (Figure 3.16).
These figures provide an overarching guide to the reductions required of the oil and gas
sector as a whole to 2030. To build confidence in the actions being taken, a consistent andtransparent approach is also needed to monitor, report and verify emissions from oil and gas
activities. This should be based on robust measurements to improve the accuracy andavailability of emissions data. Companies can nonetheless do a lot even if they do not yet
Chapter 3 | Strategic responses of companies

137

3

have a firm understanding of the emissions from their operations. Actions to stop
non-emergency flaring, adopting a zero tolerance approach to methane emissions, andsetting targets for electrifying operations, among many others, would cut emissions even as
a company looks to improve measurement and reporting.
Figure 3.16 ⊳ Scope 1 and 2 emissions intensity of oil and gas operations in the
90

Emissions intensity
-30%
-50%

60

Gt CO₂-eq

kg CO₂-eq/boe

APS and NZE Scenario and total emissions in 2022 and 2030
64Total emissions

-35%
-60%

2

30

2022 2030
APS

2022 2030
NZE

2022 2030
APS

2022 2030
NZE
IEA. CC BY 4.0.

Emissions from oil and gas operations fall by around one-third in the APS
and by more than 60% in the NZE Scenario between 2022 and 2030.
Notes: Gt CO2-eq = gigatonnes of carbon dioxide equivalent; kg CO2-eq/boe = kilogrammes of carbon dioxide
equivalent per barrel of oil equivalent.

IEA. CC BY 4.0

A number of companies have already undertaken major efforts to cut emissions from theirown operations and have emissions intensities far below our estimate of global averages(Table 3.1). Examples of the best practices from facilities or operations that exist currently
for the largest sources of scope 1 and 2 emissions are:

Extraction and processing, for example Equinor’s operations in Norway. These
operations have reduced methane leaks to very low levels and avoid flaring in all but
emergency situations, and many operations have been electrified with low-emissions
power.



Refining, for example the Sturgeon Refinery in Canada. It captures CO2 from operations,
including hydrogen production, and sells the captured CO2 for enhanced oil recovery or
permanent storage, which reportedly reduces refining emissions by up to 70%. Shellannounced plans that it will build a 200 MW electrolyser in the Netherlands to producehydrogen using offshore wind, part of which will be used to replace high-emissionshydrogen in its refinery.

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International Energy Agency | Special Report

LNG liquefaction, for example Freeport LNG. Electrifying operations and using a zero
emissions source of electricity results in substantially lower overall emissions than using
natural gas; this is equivalent to the scope 1 emissions reported by Freeport LNG.

The best-performing companies can help reduce scope 1 and 2 emissions elsewhere byproviding technical, operational and financial assistance, particularly at non-operated assets.
Nonetheless, if companies already have a low level of emissions from the oil and gas theyown, it would be unreasonable to expect further large-scale reductions to achieve theindustry-wide reductions needed to meet the NZE Scenario.
There are large differences between the scope 1 and 2 emissions self-reported by companies
and the estimated level of emissions from publicly available measurement studies,particularly for methane emissions (see Section 3.3.1). Nonetheless, the reduction in total
scope 1 and 2 emissions in the NZE Scenario to 2030 is broadly equivalent to the reductions
that would be achieved if oil and gas producers around the world in 2030 were to perform
in line with the emissions intensity of the best operators today.
If companies already reliably and transparently measure and report emissions from the oiland gas they own or process, they could be deemed to align with net zero transitions if, forthe parts of the value chain they operate in, they achieve performance consistent withcurrent best practices by 2030.
Table 3.1 ⊳Average emissions intensity and best practices of projects
currently in operation or under construction
Current average(kg CO₂-eq/boe)

Best practice(kg CO₂-eq/boe)60

8Equinor operations in Norway (Equinor, 2022)

35

20

Most efficient medium conversion oil refinery(Jing, et al., 2020)

Upstream

438Equinor operations in Norway (Equinor, 2022)

LNG liquefaction

35

6

Scope 1 emissions of Freeport LNG (2022)

Example of best practice

Oil
Upstream
Refining
Natural gas

Notes: Upstream is emissions from extraction and processing. Processes included here cover nearly 90% of
our estimate of total scope 1 and 2 oil and gas emissions. Current average values are based on IEA estimates(see Chapter 2) and best practice values are based on reports by companies or in the scientific literature.
Emissions from pipeline gas transport and crude oil and oil product trade are currently a function mainly of
distances travelled and so are not included here.

IEA. CC BY 4.0.

3.5.2

Investment in clean energy

Large reductions in scope 1 and 2 emissions are a necessary condition for the oil and gas
industry to align itself with net zero transitions. But changes need to be broader than thisand some companies are making the case that they can play a constructive role in thenecessary scaling up of clean energy. A critical question is what level of investment or share
Chapter 3 | Strategic responses of companies

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3

of their overall capital budget would be reasonable to align with net zero scenarios. There
are no simple answers – it is impossible to capture the full diversity of options and nuances
for individual companies in long-term energy scenarios – but the overarching investment
trends of the APS and the NZE Scenario provide useful guidelines for a more informed,
data-led discussion.
In practice, oil and gas companies take strategic direction from governments andshareholders, who may be better placed than oil and gas company executives to efficiently
allocate capital towards clean energy by employing the proceeds of taxes, royalties anddividends toward clean energy initiatives. The degree of alignment of individual oil and gas
companies with the NZE Scenario is therefore likely to be dictated by the preferences ofthese actors.
Moreover, companies will make different investment decisions based on their portfolio ofassets, available resources, assessment of diversification opportunities, corporate culture
and business models. For example, the majors tend to focus on their future market value andare governed by the interests of shareholders, which in some cases may demand action to
mitigate climate risk to the business. Independent “pure-play” upstream companies typicallyexhibit a higher risk tolerance and seek higher returns from upstream investments. They may
prioritise the optimisation of their upstream portfolio by divesting non-core assets andreinvesting in projects that offer the most promising growth prospects. In contrast, NOCs
typically focus on the development of domestic oil and gas reserves, but may also invest in
regions that strengthen diplomatic ties or national industrial or development priorities.
Pressures or incentives to pursue low-emissions development pathways may be assessed inthis broader context.
We explore below a pathway for oil and gas companies that explicitly want to transform andbroaden their core competencies in line with the pace and scale of net zero transitions.

Economy-wide approach

IEA. CC BY 4.0

In net zero transitions, reductions in fossil fuel investment need to be sequenced carefully sothey do not run ahead of the necessary scale-up in clean energy technologies. In 2023 it isexpected that around USD 1 trillion will be spent on fossil fuels and USD 1.8 trillion on clean
energy technologies, meaning the ratio of investment in fossil fuels to clean energy iscurrently 1:1.8. By 2030 this increases to 1:5 in the APS and to 1:10 in the NZE Scenario. In
the NZE Scenario, 60% of clean energy investment is on clean energy supply (low-emissions
fuels and power) and 40% is on efficiency and clean end-use technologies (Figure 3.17).
These economy-wide ratios provide an important guide for financial actors looking to assess
their equity and lending portfolios against net zero targets. But they are not directly relevant
for oil and gas companies. This is because a large share of the clean energy investments in
net zero transitions will need to be undertaken by end users (such as household spending on
EVs and heat pumps, or energy-intensive industrial plants investing in retrofits or electricmotors). The oil and gas industry itself has little presence or influence over investment
140

International Energy Agency | Special Reportchoices in many of these areas and so it would be unreasonable to expect it to take a leadingrole in scaling up investment in these areas. These end-use investments could be excluded
from the ratio, but this would mean closing off some clean energy investment choices for oil
and gas companies, such as EV charging infrastructure or CCUS in industrial applications.
Comparing oil and gas investment just to clean energy supply (a ratio of 1:6 in 2030 in the
NZE Scenario and 1:3 in the APS Scenario) would suffer from similar limitations, and yield
only a partial picture of the necessary investments undertaken across the energy economy.

Trillion USD (2022, MER)

Figure 3.17 ⊳ Global energy investment spending in the APS and NZE Scenario
5

2023e

2030 APS

2030 NZE
10x

4

2

Other end-use
Efficiency

5x

3

Other

Low-emissions fuels
Grids

1.8x

Batteries
Nuclear1

Renewable power
Fossil Clean
fuels energy

Fossil Clean
fuels energy

Fossil Clean
fuels energy
IEA. CC BY 4.0.

The ratio of investment in fossil fuels to clean energy rises from 1:1.8 today to 1:5 in the APS
and to 1:10 in the NZE Scenario in 2030.
Note: 2023e = estimated values for 2023.

A more operational approach to assessing the compatibility of investment decisions by oil andgas companies with net zero transitions is to consider the industry’s future financial resources
and its ability to invest in clean energy, which can be determined as much by the strategic
preferences of oil and gas company management as the political priorities of governments andfinancial and non-financial imperatives governing shareholder action. The balance that is struck
invariably affects how much capital oil and gas companies would be able to allocate todiversification, taking into account expectations of future revenue and the continued need toinvest in oil and gas. Here we examine what this might look like in the NZE Scenario.

IEA. CC BY 4.0

How much capital is available for the oil and gas industry to invest in clean energy in
the NZE Scenario?
Between 2018 and 2022, the oil and gas industry earned, on average, close to USD 3.5 trillion
each year in revenue. Around 50% of this was paid to governments in the form of taxes androyalties or retained as part of NOC domestic income, and 10% of total revenue was paid to
Chapter 3 | Strategic responses of companies

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shareholders in the form of dividends or buybacks and to pay down debt. The remaining
revenue was used to cover capital and operating expenses, most of which were incurred in
exploration, development and production.
In 2022, total capital expenditure by the industry was USD 700 billion, of which USD 20 billion
went to clean energy (2.7% of the total). In the future, the level of capital that the industry
could direct towards clean energy will depend on the future spending requirements for oil
and gas and the extent to which governments and shareholders might be willing to accept
lower returns to enable oil and gas industry transitions. Currently, there does not appear to
be a large appetite among these stakeholders to forego these revenue streams.
In the NZE Scenario, around USD 1.6 trillion of gross oil and gas revenue is generated in 2030.
Capital expenditure on oil and gas (USD 350 billion) and operating expenditure(USD 220 billion) are required to maintain supply, fund near-field extensions to existing
fields, pay for equipment and infrastructure, transport and processing, and cover marketingand distribution costs. Reducing scope 1 and 2 emissions requires around USD 85 billion
annual spending in 2030. This leaves USD 900 billion revenue in 2030 (Figure 3.18).

Trillion USD (2022, MER)

Figure 3.18 ⊳ Distribution of oil and natural gas revenue in the NZE Scenario
NZE Scenario 2030

Use of revenue

6

Operating
costs

5
4
3

Capital Traditional

Scope 1 and 2

2
Net income
before taxes

1
20182019202020212022

CapitalOperating costs

Tax

NZE
2030

250

Dividends and debt

500
750
1 000
Billion USD (2022)
IEA. CC BY 4.0.

Oil and gas industry revenue is USD 1.6 trillion in 2030. All of the net income before taxes
could be spent on clean energy but this leaves no income for government or shareholders.

IEA. CC BY 4.0

Note: Traditional capital spending is investment in maintaining production and operations at existing
upstream and midstream oil and gas assets.

If shareholder payouts and government taxes as a percentage of total revenue remain at
historical levels, of the USD 900 billion the oil and gas industry would have no remaining
capital to spend on clean energy in 2030 in the NZE Scenario, given far lower prices anddemand for oil and gas. This would mean that the share of capital spending on clean energy
by the oil and gas industry would likely remain at a very low level.
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International Energy Agency | Special Report

Alternatively, if governments around the world were to lower tax takes to zero, andshareholders accepted no payouts from oil and gas sales, all the remaining USD 900 billion
income could be devoted to clean energy investment. This would mean that for every USD 1of capital expenditure on traditional oil and gas activities, almost USD 3 could be invested inclean energy. 4 In other words, nearly 75% of the capital spending by the oil and gas industry
in 2030 could be on clean energy but this would rely on no income from oil and gas sales
going to government or shareholders.
There is no single way to strike a balance between these two extremes and the situation is
likely to vary markedly between individual companies and jurisdictions. Governments andcompanies would need to work together if the industry is to generate the cash flow necessary
to sustain the investment required in oil and gas, while boosting new low-emissions activities
and providing sufficient revenues to governments and returns to shareholders.
Here is an illustration of how oil and gas revenue in 2030 could be used in the NZE Scenario:
if the government tax take from oil and gas revenue falls to 35% and shareholders accept
lower direct cash distributions of 5% of gross revenue, this would leave governments with
USD 600 billion and shareholders with USD 70 billion in 2030. After operating costs andinvestment to cut scope 1 and 2 emissions, this would leave around USD 600 billion revenue
from oil and gas sales. A steady ramp-up in clean energy spending would also provide
additional revenue, meaning the capital budget available to the oil and gas industry in 2030
would be closer to USD 700 billion. With USD 350 billion of capital investment in oil and gas
required in the NZE Scenario in 2030, around USD 350 billion would be left to invest in clean
energy. In other words, 50% of the oil and gas industry’s capital expenditure, outside scope
1 and 2 emissions reductions, would be on clean energy (Figure 3.19).
If the oil and gas industry were to follow this path, total capital expenditure in 2030 – around
USD 700 billion – would be comparable to its annual average capital expenditure between
2018 and 2022. Clean energy investment of USD 350 billion would mean that the oil and gas
industry contributes around 8% of all investment in clean energy in 2030 in the NZE Scenario,
up from just over 1% today.

IEA. CC BY 4.0

The analysis does not prejudice the choices individual companies may decide to make in net
zero transitions, nor preclude the option to wind down operations. Indeed, the sharp
reduction in the profitability of selling oil and gas in the NZE Scenario – which would be likely
to lead to increased risk premiums attached to continued investment in oil and gas – could
make it more challenging for the oil and gas industry to raise the capital necessary to diversify
into clean energy. In the NZE Scenario, if governments do not change oil and gas fiscal
regimes to give companies more space to invest in clean energy, it may be difficult for themto do so unilaterally. Strategies such as asset sales or accessing debt markets may free up
additional capital to invest in clean energy, but many oil and gas companies may also see

4 Investment in traditional oil and gas activities excludes operating costs and investment in scope 1 and 2
emission reductions.

Chapter 3 | Strategic responses of companies

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operational improvements and a focus on higher-return core assets as a better recipe forlong-term profitability than investing elsewhere in energy.
Figure 3.19 ⊳ Indicative clean energy and traditional fossil fuel investment by
the oil and gas industry in the NZE Scenario

2022

2030

3%

Clean energy
Traditional oil and gas
operations

IEA. CC BY 4.0.

In the NZE Scenario, it is possible for oil and gas companies to strike a balance between theinterests of government and shareholders by investing 50% of capital in clean energy.
Note: Excludes capital expenditure on reducing scope 1 and 2 emissions in 2030.

Achieving a clean energy investment share of 50% would require all
stakeholders – governments, companies, shareholders and financial actors – to work closely
together and agree on the way forward. Governments need to put in place clear policy
frameworks for net zero transitions that demonstrate the path ahead and allow companies
to plan for change. But leading companies and their owners also have a voice in the energy
and climate debate. They have the capacity to push for some of the certainty that they arelooking for: signalling their ambition by setting firm near-term targets in line with net zero
goals and taking steps towards achieving these is a vital step in the process.

3.6

Framework to assess the alignment of company
targets with the NZE Scenario

IEA. CC BY 4.0

Oil and gas companies face inevitable and wide-ranging changes if the world is to achieve its
climate targets. Some are responding, but the wide array of approaches has led to confusion
and ambiguity over how meaningful these actions really are. In this section, we present a
new framework for quantitatively and qualitatively assessing the alignment of company
actions and targets with climate goals.

144

International Energy Agency | Special ReportFigure 3.20 ⊳ An IEA framework for assessing alignment of company targets
with the outcomes of the NZE Scenario

3

IEA. CC BY 4.0.

IEA. CC BY 4.0

The new IEA framework allows for a more granular assessment of oil
and gas company targets and their alignment with net zero transitions.
Notes: “Scope 1 and 2 emissions” include emissions from operated and non-operated assets but excludes
reductions achieved through carbon credits purchases from outside the energy sector. “Best practice” metricassesses the alignment of 2030 targets for upstream and downstream activities with the lowest emissions
intensities achieved by an operator today. It is weighted according to the company’s level of emissions fromeach activity and is relevant only if a significant proportion of the emissions from the oil and gas it owns aremeasured. “Clean energy investment share” is total capital investment in clean energy technologies divided
by total capital investment, with both values excluding investment in scope 1 and 2 emissions reductions andcarbon credits generated from outside the energy sector.

Chapter 3 | Strategic responses of companies

145Given the wide range of possible ways to achieve net zero emissions globally, this framework
cannot cover every eventuality. It nonetheless aims to provide a more granular and data-led
discussion on whether oil and gas companies are “playing their part” in accelerating net zerotransitions. Fundamental to this is recognition that the diversity and complexity of theindustry means an approach based on companies being “fully aligned” or not with climate
targets is too simplistic.
The framework does not look to impose on companies any singular approach to net zerotransitions. Rather it draws on the trends and insights from the NZE Scenario to highlight theactions and targets that would align with the net zero pathway described in that scenario.
The key results from the NZE Scenario are the need to minimise the emissions intensity ofcore oil and gas operations, that no new long lead time conventional upstream projects areneeded, and the importance of scaling up clean energy investment.
This does not mean, however, that companies have to diversify into clean energy to bealigned with the NZE Scenario. For example, some companies may take the view that their
specialisation is in oil and natural gas and so decide that – rather than risking money on
unfamiliar business areas – others are better placed to allocate this capital to new activities.
Their “investment” in transitions would consist of returning cash to shareholders. Even
though they make no direct investment in clean energy, their activities would still be fullyaligned with the trends of the NZE Scenario if their scope 1 and 2 emissions are as low as
possible and they do not invest in new long-lead time upstream conventional projects.

3.6.1

Framework overview

The IEA’s new framework focuses on the targets that oil and gas companies have announced
for 2030, as action over the remainder of this decade will be critical to achieving net zero by
2050. Results and parameters are based on the trends of the NZE Scenario; while we live ina world where oil and gas demand is not falling at the pace seen in the NZE Scenario, thestructure and quantitative aspects of the framework remain relevant for assessing thecontributions of companies looking to say they are playing their part (Box 3.5).

IEA. CC BY 4.0

In this framework, companies that chose to align with net zero transitions are assessed on:
their 2030 target for scope 1 and 2 emissions reductions, whether or not they have plans todevelop new long lead time conventional oil and gas production, and their 2030 target forthe share of investment in clean energy, if they are looking to develop these types of projects(Figure 3.20). This is complemented by qualitative aspects including measurement andtransparency, the planned use of offsets, and a company’s plans for the stewardship of oil
and gas asset disposals.
An oil and gas company is fully aligned with the outcomes of the NZE Scenario only if it nolonger plans to invest in new oil and gas projects and if it has a target for its scope 1 and 2
emissions intensity to be aligned with current best practices by 2030 or for these emissions
to be cut by 60% by 2030.
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International Energy Agency | Special ReportHowever, if a company plans to continue to invest in new projects, it is assessed on its 2030
target to limit scope 1 and 2 emissions and 2030 target for the share of its capital budget
going towards clean energy technologies. A target for a share greater than 50% in 2030 would
allow the company to claim it is making a fair contribution to the scaling up clean energy
necessary to achieve net zero emissions by 2050. The following sections explain these
aspects in more detail.
Box 3.5 ⊳What should oil and gas companies do in a world not on track toachieve its climate goals?

Recent progress on clean energy technologies is keeping open the pathway towards
limiting the global temperature rise to 1.5 °C, but most technologies are not currently on
track with the NZE Scenario and much more needs to be done. A key question becomeswhat strategies the industry should adopt if oil and gas demand does not decline at thepace seen in the APS or NZE Scenario.
In the Stated Policies Scenario (STEPS), oil and gas demand reach a peak before 2030 but
investment in both new and existing fields is required. One option is simply to supply
these fuels for as long as they are in demand and returns on investment are sufficient.
But forward-looking companies seeking to make the case that they are playing an activerole in accelerating the energy transition would need to go much further than this.
Indeed, companies continuing with business-as-usual risk losing their “social licence” tooperate as the damage from climate change becomes ever more apparent.
Minimising emissions from core oil and gas operations should be a first-order priority for
all, in any scenario. Aiming to reduce scope 1 and 2 emissions intensity in line with the
reductions in the NZE Scenario would be beneficial whatever the broader transition
pathway.

IEA. CC BY 4.0

For investment in clean energy, investment strategies would need to find a middle
ground between scenario outcomes to hedge against the risk of either overinvestment
or underinvestment (as explored in Chapter 1). Importantly, if demand and prices evolveas in the STEPS, the after-tax capital resources available to the industry are higher, evenafter maintaining a similar level of dividends for shareholders to today (Figure 3.21).
Companies could choose to dedicate a larger share of their investment to clean energy,
and work with governments and consumers to ensure that markets and infrastructuredevelop quickly for low-emissions goods and services.
In 2030 in the NZE Scenario, the oil and gas industry invests around USD 350 billion in oil
and gas and, if taxes are reduced as a share of revenue from current levels andshareholders accept lower payouts, around USD 350 billion capital would be available toinvest in clean energy (i.e. a clean energy investment share of 50%). In 2030 in the STEPS,
oil and gas investment is higher at USD 700 billion and, if taxes and payouts toshareholders remain around historic levels, the capital available to invest in clean energy

Chapter 3 | Strategic responses of companies

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3

would be USD 500 billion (i.e. a share of 40%). In other words, for forward-looking
companies, looking to invest close to 50% of capital expenditure in 2030 in clean energy
would be plausible even in a scenario that does not align with global climate targets.
Figure 3.21 ⊳ Indicative distribution of annual oil and gas industry revenue
Trillion USD (2022, MER)

in the STEPS and NZE Scenario

4

Returns to shareholders anddebt payments
Capital - available for clean

3

Capital - oil and gas
2

Operating costs
Taxes

1

2018-22

STEPS

2030

NZE
IEA. CC BY 4.0.

In the STEPS, oil and gas companies have more resources to commit to clean energy
and investment in scope 1 and 2 emissions reductions.

3.6.2

Scope 1 and 2 emissions reductions

IEA. CC BY 4.0

Global scope 1 and 2 emissions fall from 5.1 Gt CO2-eq in 2022 to less than 2 Gt CO2-eq in
2030 in the NZE Scenario (Chapter 2). This 60% reduction is achieved mainly through a 50%
reduction in the global average emissions intensity of oil and gas operations. Forward-looking
companies are likely to need to move faster than this – and building a broader coalition ofcompanies willing to play their part is a crucial step forward – but the global average rate of
reduction sets a baseline for the overall changes that would be consistent with the
NZE Scenario. This reduction is achieved across the entire oil and gas supply chain and theoverall reduction includes emissions from both operated and non-operated assets. Targets
looking to achieve less than a 60% reduction by 2030 are placed along the horizontal axis of
the framework moving from right to left.
An additional 60% reduction in scope 1 and 2 emissions from 2022 levels could be challenging
for companies that have already undertaken major emissions reduction efforts in the past
(Section 3.5.1). In this case – which can only be demonstrated with reliable measurements
and transparent reporting of all emissions from the production, processing and transport ofoil and gas owned – a 2030 target to achieve the emissions intensity of the best practices
seen today could be used, as this would broadly align with the outcomes of the NZE Scenario.
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International Energy Agency | Special ReportIn our framework, 2030 targets to achieve best practices across the supply chain are set at
100% and the average values achieved by the industry today set at 0% (Table 3.1). For
companies involved in multiple parts of the oil and gas supply chain, a single number can bederived by taking the degree of alignment for each individual segment of the supply chain
and then weighting each by the share of the company’s overall emissions that come fromthat segment. For example, if a company has 2030 targets to achieve an emissions intensityof 10 kg CO2-eq/boe in upstream gas operations and 15 kg CO2-eq/boe in LNG liquefaction,
it would be 94% aligned on upstream and 61% on LNG. If three-quarters of its total emissions
come from upstream gas and one-quarter from LNG, its combined metric would be 86%.

3.6.3

Investment in new oil and gas projects

In the NZE Scenario, the overall trajectory of falling demand can be met without any approvalof new long lead time upstream conventional projects. Companies aligned with the resultsof the NZE Scenario would not invest in new exploration or approve new projects. One
possible caveat to this result is if a company were to choose to develop a new project and to
close another project of a similar size and production profile within its own portfolio. While
field abandonment and replacement has been common practice for the industry, thetrajectory of steeply declining demand in the NZE Scenario would impose a very different setof conditions than in the past, and no companies have to date proposed adopting thisapproach to alignment with the NZE Scenario.
Another important – but often overlooked – nuance to the result from the NZE Scenario on
new upstream oil and gas projects is that the IEA publishes a full update to all scenarios every
year. This means that the oil and gas projects incorporated in successive editions of the
NZE Scenario change in each update. For example, in the first version of the NZE Scenario
published in 2021, supply projections included projects that had already been approved orwere expected to be approved by the end of 2021. A similar approach was taken in the
updated NZE Scenario in the World Energy Outlook 2022, with the cut-off point at the end of2022; the latest update to the NZE Scenario as described in this report now includes projects
expected to be approved by the end of 2023.

IEA. CC BY 4.0

Updates to the NZE Scenario are essential to ensure that it is grounded in real-world
conditions, but this implies a moving target for the projects compatible with the goals of the
scenario. In this year’s edition of the NZE Scenario, oil and gas projects approved in 2023 areincluded and the pace of reduction in oil and gas demand in the 2030s and 2040s now meansthat some production will need to be closed before fields have reached the end of theirtechnical lifetime. For this reason, the framework specifies that no investment in any newlong lead time upstream oil and gas projects is required from today to align with theoutcomes of the NZE Scenario.

Chapter 3 | Strategic responses of companies

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3.6.4

Investment in clean energy

A decision to invest in new oil and gas fields does not rule out the possibility that companies
could look to play their part in scaling up clean energy deployment. As described in
Section 3.5.2, it is challenging to derive a single number for the share of clean energy
investment that would be consistent with the overall trends in the NZE Scenario. Investing
75% of the available capital in clean energy in 2030 is theoretically possible, but this would
imply that all governments and shareholders around the world accept no tax revenues ordirect returns from oil and gas sales. Conversely, if there is no change in government tax
takes or shareholder returns, there would be no capital left available after all necessary oil
and gas spending. We estimate that if governments, companies, shareholders and financial
actors work together, a 50% share by 2030 would be feasible.
This share is the total spending on all clean energy technologies by the company divided by
its total capital expenditure. Both figures exclude investment in scope 1 and 2 emissions
reductions, since efforts to reduce scope 1 and 2 emissions are included in the frameworkon the horizontal axis. Also excluded in the numerator is investment in emissions credits
generated from outside the energy sector, including nature-based solutions, since these are
not included within the scope of the NZE Scenario.

3.6.5

Qualitative qualifiers

In addition to these quantitative aspects, there are additional considerations that provide
insights into how companies are aiming to achieve their goals and the ease with which theirtargets can be assessed.
Measurement and transparency: Uncertainty about current scope 1 and 2 emissions levels
is high and reducing this through direct measurement is critical to measure progress against
targets. Transparency of disclosures is invaluable for policy makers, financial actors andcompanies to allow for comparability and build public confidence. This should include how
targets will be achieved, what elements are included within scope 1 and 2 emissions targets,
and what is considered within clean energy spending goals.

IEA. CC BY 4.0

Emission offsets: Offsets from outside the energy sector are not included in the NZE Scenario
and they are not included in the scope 1 and 2 emissions reductions or clean energy
investment in the framework. In the NZE Scenario, negative emissions are generated fromwithin the energy sector and some of these offset residual emissions from oil and gas
operations (Box 3.1). This occurs only after emissions reduction measures have been
deployed to the fullest extent possible, with the majority of residual emissions from oil andgas operations stemming from transport. Plans to use a high level of offsets to achieve scope
1 and 2 emissions reduction targets may indicate the company does not aim to actively
pursue the real emissions reductions that are necessary. Transparency about the magnitude
of offsets being used, how these offsets have been generated, and the nature of emissions
that these are offsetting, is therefore critical.

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International Energy Agency | Special ReportOil and gas asset disposals: Mergers and acquisitions are a natural part of the oil and gas
industry. Asset sales may help a company achieve its own emissions reduction targets, butthey could lead to an increase in overall emissions if sold to a company with lower
environmental targets. Governments must play a central role here to prevent these perverse
outcomes, but companies themselves can introduce stewardship policies to ensure that theiremissions reduction targets fully contribute to global net zero transitions.

IEA. CC BY 4.0

3

Chapter 3 | Strategic responses of companies

151Chapter 4
Strategic responses of exporters and importers
S U M M A R Y• Change is unavoidable for producer economies in net zero transitions. Transitions
increase the likelihood of boom and bust cycles for oil and gas producers and – withoil and gas markets entering terminal decline – the baseline expectation should be fora bumpy ride. Strategies will necessarily vary from country to country, but a common
element is that while net zero transitions will present immense challenges for
producer economies, their energy advantages do not disappear overnight.

• Ten established producer economies in the Middle East, Africa and Latin America,
currently produce more than 30 mb/d of oil and nearly 800 bcm of natural gas
annually. Per-capita income from oil and gas sales in the NZE Scenario in these
economies falls by 70% to 2030 and by 90% to 2050 compared with the average level
between 2010 and 2022. This could create a powerful incentive to accelerate the paceof reform while also draining a source of revenue that could finance it.

• A number of new potential producer economies – Guyana, Mozambique, Senegal andTanzania – have seen large oil and gas discoveries in recent years. Despite growing
domestic consumption, the prospects for new projects hinge mainly on exports, andtheir economics are very sensitive to the pace of global energy transitions. In the APS
and NZE Scenario, new large-scale oil and gas projects would face major commercial
risks and they may struggle to generate any real income. None of these countries have
universal access to energy today, but it is achieved in full by 2030 in the NZE Scenario;
this would require less than USD 2 billion annual investment to 2030.

• We explore elements of energy strategies for producer economies that, dependingon their context, could complement broader reforms to build macroeconomic
stability. These include: reducing the emissions intensity of oil and gas operations;securing additional value from traditional supplies by reducing flaring and methane
emissions and increasing non-combustion uses of oil and gas; phasing out inefficientfossil fuel subsidies; boosting clean energy deployment to reduce domestic oil and gas
use; stepping up low-emissions fuel production; and expanding into new clean energy
supply chains.

• Net zero transitions can only occur smoothly if producer and consumer countries

IEA. CC BY 4.0

provide clear signals on their direction of travel, work together in a mutually beneficial
manner, and implement coherent cross-border measures. We examine four routes
for effective international co-operation: sending the right market signals; working
together to unlock investment in low-emissions fuel trade; collaboration ontechnology; and bilateral and multilateral engagement. There are several examples ofcurrent policy efforts that promote action in these areas.

Chapter 4 | Strategic responses of exporters and importers

153

4.1

Introduction

Economies that are heavily reliant on oil and gas revenues face some stark choices in energy
transitions. These choices are not new: the benefits of a shift towards a more diversified
economic structure and sustainable energy mix have long been recognised, not least by the
producer economies themselves. But net zero transitions introduce an additional element ofurgency, as they add a timeline and a deadline. If governments around the world meet theirannounced pledges or mobilise to limit global warming to 1.5 °C, this will have profound
impacts on oil and gas income in the coming decades. It creates powerful incentives toaccelerate the pace of reform, while also draining a source of revenue that could finance it.
As we wrote in an earlier landmark report on this issue in 2018, “fundamental changes to thedevelopment model in resource-rich countries look unavoidable” (IEA, 2018). In this chapter,
we explore what this complex process might look like. We start by analysing the current
situation in different economies with large oil and gas resources, including establishedproducers and countries looking to step up their development. We consider the implicationsof net zero transitions for production prospects and revenues, as well as different
energy-related diversification options and strategies. Finally, we assess the ways thatinternational partners can support the diversification process, and the collaborative ways inwhich today’s oil and gas exporters and importers can work together to help net zerotransitions globally.
As in 2018, we conclude that the need for change is unavoidable and that the development
prospects for any country that fails to recognise this are bleak. At the same time, we urge a
considered approach: each country needs a well-designed strategy for what comes next
based on a clear-headed assessment of its strengths and weaknesses. These strategies will
necessarily vary from country to country, and many will require external technical andfinancial assistance. A common element, however, is that the energy advantages of today’s
producer economies do not disappear overnight. These countries are competitive providersof traditional fuels; many also have high potential to produce low-emissions fuels and power,
and to create new industries and employment opportunities on that basis.
The producer economies considered in this chapter are divided into two main groupings:
established producers and new producers.

IEA. CC BY 4.0

The first group of established producers comprises ten countries: Algeria, Angola, Iran, Iraq,
Nigeria, Oman, Qatar, Saudi Arabia, United Arab Emirates and Venezuela. These are notnecessarily the most vulnerable countries in energy transitions, but they represent a
cross-section of producers that are heavily dependent on hydrocarbon revenues and theyillustrate a range of starting points and circumstances. Russia is the main producer economy
not included in this analysis; many of the considerations discussed here also apply to Russia,
but the country’s role in international energy is in flux in light of its invasion of Ukraine.
The second grouping of new producers comprises four countries that have recently seen
substantial oil and gas discoveries and are looking to scale up production: Guyana,
Mozambique, Senegal and Tanzania.
154

International Energy Agency | Special Report4.2

Established producers

4.2.1

Starting points

The established producers examined in our analysis play a central role in oil and gas markets.
In 2022 these countries produced more than 30 million barrels per day (mb/d) of oil – morethan one-third of global oil production – and 800 billion cubic metres (bcm) of natural gas,
which is around 20% of global production (Figure 4.1). They are responsible for 45% of global
oil exports and 30% of global liquefied natural gas (LNG) exports.

Oil

40

900

20

600

10

300

Saudi Arabia

Russia
Iraq

UAE

China
Iran

Natural gas

1 200

30

UnitedStates4

Role of selected producer economies in global oil and gas
production, 2022
bcm

mb/d

Figure 4.1 ⊳Establishedproducers

UnitedStatesRussiaChina

Establishedproducers

Qatar

Algeria

AngolaOman

Venezuela

Nigeria

IEA. CC BY 4.0.

The established producers examined in this report produce more than one-third of global
oil production and around 20% of global natural gas production.
Note: mb/d = million barrels per day; bcm = billion cubic metres per year; UAE = United Arab Emirates.

IEA. CC BY 4.0

These countries are very diverse and over the years have managed their resources andeconomic policies in different ways. But they all depend on oil and gas sales for a substantial
part of their national budgets. We have assessed the starting points of the countries in thisgrouping across two dimensions of diversification: economic and energy. The economic
diversification indicator looks at the role of sectors other than oil and gas in the economy,
while the energy indicator assesses the role of non-hydrocarbon resources in the overall
energy mix. Our analysis highlights that most of these producers are only at the beginning of
their journeys, but also that substantial differences between them already exist (Figure 4.2).
The United Arab Emirates scores relatively well on both dimensions, having increased
substantially the share of non-oil and gas exports in recent years. The role of solar andnuclear power (the latter since 2020) is also increasing in the UAE power mix. Other
producers have made less progress than the United Arab Emirates on the economic front,
Chapter 4 | Strategic responses of exporters and importers155

although Algeria and Oman have seen a number of improvements. Some have moved further
with energy diversification, led by Oman and Qatar. The least diversified among our selected
producer economies are Iraq and Angola; these countries face the greatest challenges fromhigh dependence on oil and are most vulnerable to the effects of revenue volatility. The
strains facing these countries during transitions are exacerbated by their exposure to a rangeof climate-related risks (Box 4.1).
Figure 4.2 ⊳Selected producer economies by degree of economic andenergy diversification

Dominated by oil

Shifting to
low-emissions energy

Gas-based economy

Economic diversification

5
United Arab Emirates

4
3
Nigeria2
1

Saudi Arabia
Iraq

1

Oman

Iran
Qatar
Algeria

Angola2

3

4

5

Energy diversification
IEA. CC BY 4.0.

Each established producer economy has distinctive national circumstances and trackrecord; none of them are currently visibly shifting towards a low-carbon energy system.
Notes: Economic diversification score is the average of the share of non-oil and gas exports in total exports in
2021 (with a weighting of 70%) and the growth of non-oil and gas export revenue since 2010 (with a 30%
weighting). Energy diversification score is calculated as the weighted average of the share of oil, coal andtraditional use of biomass in 2021 and changes since 2010 (50% and 20%, respectively) and the share of
renewables and nuclear in 2021 (30%).
Source: IEA analysis based on export data from IMF (2023a).

Box 4.1 ⊳Climate vulnerabilities are hitting producer economies

Many of the world’s major oil and gas producers are also in parts of the world that arestrongly affected by a changing climate. Between 1980 and 2020 the global averagetemperature increased by close to 0.2 °C per decade, while temperatures in most of theestablished producers – particularly those in the Middle East and North Africa – increasedby more than double this. This has been accompanied by more frequent extreme
weather events, such as heatwaves and droughts.
The global average temperature today is around 1.2 °C higher than pre-industrial levels;in the States Policies Scenario (STEPS), this increases to around 1.9 °C in 2050 and to

156

International Energy Agency | Special Report2.4 °C in 2100 (Figure 4.3). This would translate into an even greater number of extreme
weather events. For example, in the Middle East, the number of hot days with amaximum temperature above 35 °C would increase from 121 on average each year
during 1995-2014, to 143 around 2050, and to 155 by 2100.1
Figure 4.3 ⊳Temperature changes in the Middle East and North Africa in
the Stated Policies Scenario, 2041-2060

4

IEA. CC BY 4.0.

Climate hazards such as extreme heat pose major dangers to people
and development, and need to be incorporated into transition planning.
Notes: Map presents the impacts of SSP2-4.5, which is broadly consistent with the temperature outcomesof the STEPS.
Sources: IEA analysis based on IPCC (2021).

In July 2022 temperatures in Baghdad reached almost 52 °C, the hottest day that Iraq has
ever recorded, and Iraq provides a telling example of the negative effects of climatechange on development. Climate change is exacerbating existing problems with water
scarcity and, without intervention, the gap between water supply and demand could rise
to more than 15% of total water demand by 2035 (World Bank, 2022). This would havewide-ranging impacts on crop yields and food prices, disproportionately affecting thepoorest and most vulnerable sections of the population. The agricultural sector employs
almost 10% of Iraq’s working population, and workers in other sectors such as
construction would also be affected by exposure to extreme heat.

1 Climate impacts here are based on results from the SSP2-4.5 scenario assessed by the Intergovernmental
Panel on Climate Change (IPCC) that is it is broadly consistent with the temperature outcomes of the STEPS.

Chapter 4 | Strategic responses of exporters and importers

157

Higher average temperatures also have wide-ranging negative consequences for theenergy sector, creating peaks in cooling demand that can be difficult to manage. Risingtemperatures worsen the operational performance of electricity grids and make it moredifficult to cool thermal power plants. They can also pose challenges to oil and gas
infrastructure through increased aridity and droughts. In Iraq, water injection is widelyused to increase recovery from the country’s large southern fields, and a lack of water
could stymie production.

4.2.2

Pitfalls facing producer economies

Three areas have traditionally been challenging for countries that derive large revenues fromoil and gas: revenue volatility; job creation and productivity; and energy pricing andefficiency.

Revenue volatility
Producer economies are heavily dependent on revenues from oil and gas exports to fueleconomic growth and to support public spending; their fiscal balances are therefore
vulnerable to changes in oil and gas prices. For example, the last ten years saw a period ofbounty in the early 2010s, a sharp drop in income mid-decade, the shock of the Covid-19
pandemic on commodity prices and production levels in 2020, followed by a sharp reboundin 2022 (Figure 4.4).

Billion USD (2022, MER)

Figure 4.4 ⊳Net oil and natural gas income in the ten established producer
economies, 2010-2022

1 250
1 000
750
500
250
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Algeria
Oman

AngolaQatar

Iran
Saudi Arabia

Iraq
UAE

Nigeria
Venezuela
IEA. CC BY 4.0.

The ten producer economies have seen huge swings in income from oil and gas sales.
Note: UAE = United Arab Emirates.

158

International Energy Agency | Special Report

The well-documented risk is that patterns of government spending – and reinvestment in oil
and gas projects – mirror these revenue cycles, such that an expansion in spending during
boom times is then followed by painful cutbacks when prices fall (Figure 4.5). This can havedestabilising effects on the economy and welfare, especially if the government employs alarge share of the workforce. Without mitigating actions, year-on-year swings in spending
force difficult decisions about which services or jobs to cut, making it hard for citizens toinvest and plan for better livelihoods.
Although challenging to implement in practice, there are tried and tested ways to mitigate
the impacts of oil price volatility on spending and growth. A key aim is to try to introduce
counter-cyclical fiscal policies, whereby governments trim spending and raise additional
revenues during the years in which commodity prices are high, to give them the option ofincreasing spending and reducing taxes to stimulate growth during leaner years. Thisobjective can also be helped by implementing multi-year spending plans, setting limits onannual spending increases, or specifying that (as Russia did in previous years) any excess
revenues above a specified oil price be diverted into a savings fund.

Billion USD (2022, PPP)

Figure 4.5 ⊳Public expenditure on wages and other services in selected
established producer economies, 2011-2021

800

Other
Wages

600

400

200

AngolaIranNigeria

Saudi Arabia

UAE

Venezuela
IEA. CC BY 4.0.

Dependence on oil revenue can increase the volatility of public spending, forcing difficult
year-on-year decisions on cutting jobs, cutting other services or using foreign reserves.
Notes: PPP = purchasing power parity; UAE = United Arab Emirates.
Source: IEA analysis based on World Bank (2023a).

The development of sovereign wealth funds can provide a buffer against oil price volatility.
Revenues from investments in diversified portfolios that include strategic assets, stocks andother securities have allowed some producer economies to support their welfare systems
and invest in ambitious diversification programmes. For example, Saudi Arabia’s
Chapter 4 | Strategic responses of exporters and importers

159

4

USD 620 billion Public Investment Fund underpins the country’s Vision 2030 plan, which aims
to limit the country’s reliance on oil and gas revenues (among other objectives). In the
United Arab Emirates, the USD 800 billion Abu Dhabi Investment Authority and investmentcompany Mubadala conduct strategic investments in a range of sectors, including energy,
through subsidiary companies such as Masdar.
Some producer economies used the increases in income in 2021 and 2022 to strengthen
domestic and overseas investments. For example, Oman, Qatar and Saudi Arabia areboosting efforts to diversify their economies, including investment in clean energy,
technology and healthcare, as a means to develop new domestic industries as well as
generate a return on investment. Others, including Algeria and Venezuela, have more limited
tools to manage the impacts of price volatility, including lower administrative capacity tocollect and redistribute fiscal income.
Another mechanism to protect against price volatility is to build up foreign reserves during
times of high commodity prices to lessen decreases in government spending during periodsof low oil and gas prices. A mixed picture emerges among the producer economies in 2021
and 2022: Algeria and Iraq increased reserves, while Angola and Nigeria saw a decrease as
they struggled to maintain production and faced increased calls on government expenditure
for food and fuel subsidies following Russia’s invasion of Ukraine. International sanctions onsome of the producer economies also mean they are unable to access and use foreign
currency reserves.

Job creation and productivity
The population of our established producer grouping has grown at a faster rate than the
global average since 1990. People under the age of 30 now account for more than half of thetotal population, compared with around one-third in advanced economies. A young working
population can be a spur to growth, but if countries are unable to create productive
opportunities at scale, it could also be a major source of strain. Demographic pressures arelower in producers such as Qatar and the United Arab Emirates – although both are heavily
dependent on expatriate labour – but are a huge issue in other countries, notably
Saudi Arabia, Iraq and Nigeria.
The temptation for governments, particularly when oil prices and revenues are high, is toabsorb these strains via an increase in public sector employment. It is difficult to estimate
the share of public sector employment in several of our established producer grouping due
to data scarcity and the size of the informal economy. Nevertheless, more than half of thecitizens in Saudi Arabia registered in the social security system are employed in the public
sector and wages represent around half of public expenditure. This stems mainly from thehigher pay and benefits offered by public sector jobs, which has limited the private sector’saccess to the talent needed to support its development (Hani & Lopesciolo, 2021). This has
led to major distortions in the labour market, with private sector job creation not keeping up
with increases in the availability of new workers. As a result, labour productivity in many
producer economies has not kept pace with that of their neighbours (Figure 4.6).
160

International Energy Agency | Special ReportIndex (1970 = 100)

Figure 4.6 ⊳Labour productivity in selected countries in the Middle East andNorth Africa

400

Oil importers:
Egypt

300

Tunisia
Morocco

200

100

1970

1980

1990

2000

2010

Oil exporters:
Iraq
Algeria
Oman
Saudi Arabia
United Arab Emirates
2020 Qatar
IEA. CC BY 4.0.

Oil and gas exporters have seen a relative drop in labour productivity, while non-exporting
countries in North Africa have seen an improvement.
Source: The Conference Board (2023).

Creating a dynamic private sector is a broad public policy challenge, but a vital one if
producer economies are to pursue a resilient, inclusive and diversified growth path. This iscentral to the reform plans of most producer economies. The United Arab Emirates has
successfully developed itself as a major financial, logistics and services hub, and has reduced
the share of fuel exports in total exports from 95% in 2000 to around 50% in 2022.
Saudi Arabia has made a number of advances in recent years and its Vision 2030 includes theambition for the private sector to account for 65% of gross domestic product (GDP) by theend of this decade, from close to 40% today.
Several producer economies have also leveraged their status as major producers to create
local supply chains. For example, since 2015 Saudi Aramco has been looking to source anincreasing share of its procurement domestically as part of the In-Kingdom Total Value Add
programme. As of 2022, 63% of Saudi Aramco’s spending was directed to domestic suppliers,
up from 35% in 2015, and it has a target to reach 75% by 2025.
Increasing the dynamism of the private sector in the broader economy will depend on efforts
to improve government effectiveness, regulatory oversight and the rule of law. Low scoresin these areas are not typically a major impediment to the development of the oil and gas
sectors – most producer economies have a higher level of economic output than countries
with comparable levels of governance – but they are crucial to cultivate a broader basis for
economic growth. Despite recent efforts to diversify revenue and strengthen the role of thedomestic private sector through governance reforms, significant challenges remain.

Chapter 4 | Strategic responses of exporters and importers

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4

Energy pricing and efficiency
The types of businesses that thrive in any given economy depend on many different factors,
and energy is a crucial one. Ample availability of competitively priced fuels and electricity is
an important consideration for many industrial sectors. However, if this advantage is derived
from policies that hold prices well below their market value, this can distort investment
incentives for businesses and households alike and lead to widespread inefficiencies. Someof the producer economies examined in this chapter are the most energy-intensive countries
in the world, and in some instances this indicator is heading in the wrong direction(Figure 4.7). Their average energy intensity – measured as energy demand per unit of
GDP – increased by nearly 10% between 2010 and 2021, a period when the global average
fell by more than 25%.

boe per capita

Figure 4.7 ⊳Total energy demand and GDP per capita in 2021

1 000

Other countries
Established producer
economies

100
10

0.11
0.010

Less than 7.5

7.5 to 15

15 to 35

Over 35

USD (2022, PPP) per capita
IEA. CC BY 4.0.

Producer economies tend to be the highest energy users among countries with similarlevels of GDP per capita.

High energy intensity in itself is not necessarily a warning sign; it could simply be a reflectionof comparative advantage. But in practice, subsidies also play a major contributing role, both
directly for fuels and also for electricity. In 2022 the ten established producer economies inour grouping accounted for around one-third of worldwide fossil fuel consumption subsidies.
The total value of these subsidies in 2022 in these economies was around USD 360 billion.
Iran’s fossil fuel subsidies are the largest in the world, with an estimated value of over
USD 125 billion (equivalent to 35% of the country’s GDP) (Figure 4.8).
Many producer economies have introduced periodic energy pricing reforms to reduce thelevel of subsidies. Despite these efforts, overall subsidy levels have followed closely the trend
for oil and gas prices, and indeed the increase in recent years has exceeded the movementin price levels (Figure 4.9).
162

International Energy Agency | Special ReportFossil fuel subsidies in established producer economies, 2022

Billion USD (2022, MER)

Figure 4.8 ⊳
125

100%

100

80%

75

60%

50

40%

25

20%
Iran

Saudi Algeria
ArabiaOil

Natural gas

UAE

Iraq

Electricity

Nigeria Venez- Qatar Angola Oman
uela
Average subsidisation rate (right axis)
IEA. CC BY 4.0.

Fossil fuel consumption subsidies are prevalent in many producer economies
and account for one-third of global fossil fuel subsidies.
Notes: UAE = United Arab Emirates. The average subsidisation rate is the combined ratio of subsidies for oil
and gas and electricity produced from fossil fuels to international reference prices.

Index (2010=100)

Figure 4.9 ⊳Evolution of oil and natural gas prices and fossil fuel subsidies inthe established producer economies

200
150
100
50

2010

2012

2014

Fossil fuel subsidies

2016

2018

2020

2022

Oil and natural gas price
IEA. CC BY 4.0.

Despite efforts by some producer economies to revise fossil fuel subsidies,
there has been no decoupling between prices and subsidy levels since 2010.
Note: Oil and gas price is the combination of international reference prices for oil and natural gas for the
producer economies weighted by domestic oil and gas consumption.

Chapter 4 | Strategic responses of exporters and importers163

4

In the exceptional circumstances of 2022, governments found multiple ways to avoid passing
on high and volatile prices to consumers. In some instances, these measures involved direct
allocations from national budgets; in other cases, subsidy estimates reflect income that wasforegone by producer economies in keeping domestic prices much lower than international
benchmarks.
As well as encouraging inefficient energy use, fossil fuel subsidies also tilt the scales against
the deployment of clean energy. Producer economies in the Middle East have some of thebest solar irradiation rates in the world and the potential to develop some of the lowest-costsolar projects. The United Arab Emirates and Saudi Arabia have seen solar photovoltaic (PV)prices below USD 15 per megawatt hour owing to high capacity factors, beneficial financing
and land costs, and large project size, which allow for the cost advantages of economies ofscale. New projects are under development, but as of 2022 only 8 gigawatts (GW) of solar
capacity was installed in the Middle East (for comparison, the Netherlands had around
20 GW) and solar provided only 1.5% of electricity generation in the region in 2022.

4.2.3

Impacts of net zero transitions

Net zero transitions will have profound implications for development models based onhydrocarbons. Our scenarios provide a sense of the magnitude of the changes for oil and gas
producers as demand falls back and prices ease. As major resource-holders, many of the
producer economies are also among the world’s least-cost suppliers and so retain strong
footholds in the markets – at least during the initial years of our projections. But the
trajectories mapped out in our scenarios may in some ways understate the difficulties thatlie ahead, in that the lines to 2050 are relatively smooth and, as such, provide a hint ofcertainty and predictability for the producers. No such assurances can be provided inpractice. Even as overall volumes contract, commodity markets are likely to continue to be
characterised by regular market imbalances. Transitions arguably increase the likelihood ofboom and bust cycles for oil and gas; the baseline expectation should be for a bumpy ride.
The projections nonetheless provide important orientation for the future. In the APS, oil
production by our grouping of established producer economies remains broadly flat to 2030
(at just over 30 mb/d) and falls to 23 mb/d in 2050; gas production rises to 900 bcm in 2030
but then peaks and falls back to 2022 levels in 2050 (800 bcm). Net income from oil and gas
is not materially different from the average levels seen during 2010-2022 until the latter partof the projection period (Table 4.1).
Rapid population growth means that there is a decline in income expressed on a per-capita
basis. This is particularly the case for Angola, which doubles its population by 2050, and for
Nigeria and Iraq, which both see a 70% increase in population to 2050. Across the establishedproducer economies as a whole, per-capita income in the APS by 2050 is 75% lower than the
average level during 2010-2022 (Figure 4.10).

164International Energy Agency | Special ReportTable 4.1 ⊳Average annual net income from oil and natural gas for
producer economies by scenario (billion USD [2022, MER])
STEPS

APS

NZE Scenario

2023-30 2031-50

2023-30 2031-50

2023-30 2031-50

2010-21

2022

Saudi Arabia

248

347

280

315

253

208

184

Qatar

83

195

88

125

80

82

52

27

Iraq

92

139

121

142

104

68

74

24

UAE

86

127

97

118

84

69

55

23

Algeria

44

97

32

13

31

11

21

9

Iran

62

62

41

44

35

14

25

8

Oman

30

78

31

24

28

13

16

3

Nigeria

54

46

20

18

19

7

11

3

Angola

34

31

16

13

15

7

9

2

Venezuela

25

10

12

17

9

7

4

1

Total

758

1133

738

829

657

485

450

189

89

Note: UAE = United Arab Emirates

Figure 4.10 ⊳ Net income from oil and gas in the established producer
1 500

Net income

USD (2022, MER) per capita

Billion USD (2022, MER)

economies in the APS and NZE Scenario

1 000

500

1990

2010

2030

Net income per capita

3 000

2 000

1 000

2050

1990

APS

NZE

2010

2030

2050
IEA. CC BY 4.0.

In the APS, net income is similar to historical levels but population growth means per-capita
income falls sharply. In the NZE Scenario, net income per capita is 60% lower by 2030.

In the NZE Scenario, much lower global demand and lower commodity prices mean that theestablished producer economies already see significantly lower oil and gas income over the
coming decade. Compared with the annual average between 2010 and 2022, net income
from oil and natural gas is around 60% lower in 2030 and per-capita net income in 2030 is
70% lower.
Chapter 4 | Strategic responses of exporters and importers

165

4

4.3

New producers

4.3.1

Starting points

The new producer economies examined here – Guyana, Mozambique, Senegal andTanzania – have all seen large oil and gas discoveries in recent years and have announced
major plans to develop them in the coming years. Guyana is furthest along this path. Oil was
discovered in the offshore Stabroek Block in 2015 – more than 10 billion barrels ofrecoverable oil resources have been discovered to date – and production started up at the
Liza project in 2019. Explorers continue to find new resources in its waters and production is
expected to rise substantially from current levels (275 thousand barrels per day [kb/d] in 2022).
Mozambique is an emerging gas producer, based on a number of huge offshore discoveries
in the early 2010s. The country produced 5 bcm of natural gas in 2022 and exported around
80% of its production. Supply is set to double in 2023 and then grow further as a number of
new LNG plants are being developed. The only existing facility is a floating one (Coral Sul),
which exported its first cargo in the second half of 2022. Tanzania, like Mozambique, hasseen a number of major offshore gas discoveries, but has to date been less successful indeveloping major new projects. Senegal currently has very little oil and gas production, but
the Greater Tortue Ahmeyim LNG project (shared with Mauritania) is soon expected to start
production, as is the Sangomar oil and gas field. These projects are set to move the country
from being a net oil and gas importer to an exporter.
Figure 4.11 ⊳ Electricity access and clean cooking access in new producer
economies, 2015 and 2021

Access to electricity

Access to clean cooking

GuyanaGuyanaSenegalSenegalMozambique

Mozambique

Tanzania

Tanzania
25%

50%

75%

100%

2015

2021

25%

50%

75%

100%

IEA. CC BY 4.0.

The new producers have made progress on improving access to electricity and clean
cooking, but on current trends they will not all achieve full access by 2030.

166

International Energy Agency | Special ReportA distinctive feature of these new producers is that while all have made progress in
expanding access to electricity and clean cooking in recent years, none have yet achieved
universal access. Indeed, less than half of people in Mozambique and Tanzania currently haveaccess to electricity and less than 10% have access to clean cooking options (Figure 4.11).
Developing new resources in countries with access deficits might seem like an obvious path
to follow, but it is not automatic that oil and gas developments provide energy to all. Some
well-established producers, notably Nigeria, still have large populations without access. And
many countries that have made great strides towards universal access in recent years, suchas Côte d’Ivoire, Kenya and Rwanda, have done so without large-scale domestic production.

4.3.2

Impacts of net zero transitions

Oil and gas discoveries may open up the promise of significant future income and resource
wealth. But there are significant uncertainties over how they deliver in practice. The
well-known “resource curse” describes the ways in which development based onhydrocarbon revenues can actually be detrimental to the economic outlook. They can also
lead to corruption and environmental hazards (van Hulst, 2023). Some risks were describedin the previous section: the volatility of revenues can be destabilising for public finances andprudent fiscal management; and resource-rich countries can face lower productivity andexcessive reliance on public sector employment, as well as inefficient and wasteful use ofenergy.
New producers face additional challenges as they are embarking on oil and gas production
at a time of heightened uncertainty over future demand. As such, they are prone to the riskof overestimating the bounty that might lie ahead, and underestimating the potential
hazards. In some cases, these hazards become visible even before the start of production, as
the promise of future revenues encourages higher borrowing and spending. After major
discoveries, the International Monetary Fund (IMF) found, on average, that growth has
underperformed the post- discovery forecasts (Cust & Mihalyi, 2017). For certain countries,
such discoveries have led to significant growth disappointments, even compared withpre-discovery trends. Mozambique’s large gas discoveries were made in 2009 at a time whenannual GDP growth was around 6%. By 2016, growth had fallen to 3% in large part as aconsequence of several huge state-backed “hidden loans”.
Declines in global oil and gas demand and lower prices in the APS and NZE Scenario
significantly reduce the scope for new oil and gas developments around the world, comparedwith the STEPS (Box 4.2). Some of the largest impacts are felt by the new producer
economies. Cumulative investment in oil and gas to 2050 in Guyana, Mozambique, Senegal
and Tanzania is 25% lower in the APS than in the STEPS, and is around 75% lower in the
NZE Scenario. In the APS, these countries generate USD 840 billion net income through to2050 (40% less than in the STEPS) and in the NZE Scenario they generate less than
USD 240 billion to 2050 (85% less than in the STEPS) (Figure 4.13).

Chapter 4 | Strategic responses of exporters and importers

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4

Box 4.2 ⊳What outlook for new producers under today’s policy settings?

Under today’s policy settings, as projected in the STEPS, oil and gas production rises
substantially in the four new producers examined. Oil production in Guyana rises mostsignificantly to 1.7 mb/d in 2030 (Figure 4.12). Annual natural gas production rises toaround 85 bcm in 2050 in Mozambique, 20 bcm in Tanzania and 15 bcm in Senegal.
Cumulative investment in oil and gas through to 2050 is USD 420 billion and the countries
generate nearly USD 1 400 billion in net income from oil and gas sales.

Oil

2.5

bcm

mb/d

Figure 4.12 ⊳ Oil and gas supply in new producer economies in the STEPS
2.0

120

1.5

90

1.0

60

0.5

30
2022

2030 2035 2040 2045 2050

GuyanaMozambique

Natural gas

150

2022
Tanzania

2030 2035 2040 2045 2050
Senegal
IEA. CC BY 4.0.

Today’s policy settings open substantial market opportunities for new producers of oil
and natural gas, but this is not accompanied by the provision of universal access.

There is no guarantee that the income generated by these new oil and gas developments
would be directed to achieving sustainable development goals, including universal
energy access. Indeed, on the basis of current policy settings, as in the STEPS, between
55-80% of people in Mozambique, Senegal, and Tanzania in 2030 would not have accessto clean cooking and nearly half of people in Mozambique and Tanzania would not haveaccess to electricity.
It is understandable why some of the new producer economies are looking to move ahead
with the exploration and approval of large supply projects. Africa’s oil demand continues togrow until the late 2040s in the APS, and its gas demand until the end of the 2030s, withindustrial gas demand continuing to rise through to mid-century. Only in the NZE Scenario
does the continent’s oil and gas use start to tail off before the end of this decade. However,if the world is successful in targeting and reaching net zero emissions by 2050, any new
projects would face major commercial risks. For example, if these countries were to invest innatural gas projects in line with the STEPS but gas prices evolve as in the NZE Scenario, then168

International Energy Agency | Special Reportspending of around USD 240 billion to 2050 (including both capital and operating
expenditure) would generate only USD 250 billion in revenue. The projects could even resultin losses as gas supply from these countries would be above the levels of the NZE Scenario,
potentially leading to even lower gas prices (see Chapter 1).
Figure 4.13 ⊳ Annual average investment and net income from oil and gas in
Billion USD (2022, MER)

new producer economies by scenario
Investment60

Net income

4

50
40
30
20
10
2022

2023-30
STEPS

2031-50
APS

2022

2023-30

NZE

2031-50
IEA. CC BY 4.0.

Rapid transitions severely impact the economic viability of new oil and gas investments.

In the case of energy access, the APS and the NZE Scenario both offer improved outcomescompared with STEPS. In the APS, nearly all of the populations of these new producer
economies have access to electricity by 2030, although 20% of people would still lack accessto clean cooking fuels by the same date. In the NZE Scenario, universal access to electricity
and clean cooking is achieved in full by 2030.
Oil and gas do not play much of a direct role in facilitating universal access to electricity in
the NZE Scenario in these countries. Across countries in sub-Saharan Africa, renewable
technologies provide the energy for 90% of connections to electricity, with solar PV alone
providing around two-thirds (Figure 4.14). For clean cooking, around 40% of the people who
gain access do so through liquefied petroleum gas (LPG), a further 35% with the use of
improved biomass cookstoves, 10% with electricity, and the remainder with solutions suchas biodigesters and bio-ethanol. In total, around 25 thousand barrels of oil equivalent per
day of oil and gas, mainly for cooking LPG, is used to provide access to energy in Senegal,
Mozambique and Tanzania in 2030. Achieving universal access to electricity and clean
cooking in these countries requires around USD 2 billion of investment per year to 2030;
international support would be vital to mobilise this investment.

Chapter 4 | Strategic responses of exporters and importers

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Figure 4.14 ⊳ Fuels used to achieve universal energy access in countries in
sub-Saharan Africa in the NZE Scenario, 2030

Access to electricity

5%
3%

5%

Access to clean cooking

6%

12%

17%
64%

Solar
Hydro
Wind
Oil
Natural gas
Modern solid bioenergy
Other bioenergy
Electricity
Other

12%

39%

37%

IEA. CC BY 4.0.

In the NZE Scenario 90% of the people gaining access to electricity do so with renewable
technologies. Solar PV alone powers around two-thirds of new connections.

4.4

Building resilient net zero energy strategies

The reform process for producer economies is much broader than energy; indeed, the whole
point of the process is to reduce the weight of energy in the economy, and to allow otherindustrial, manufacturing and service sectors to thrive. But a well-functioning energy sector
remains vital to the overall chances of success, and it is a mistake to think that the advantagesof today’s producer economies in the energy sector disappear as the world moves away fromfossil fuels. Utilising these opportunities and advantages is not simple and will require new
types of collaboration both within countries and internationally. But there are workable net
zero energy strategies available to today’s producer economies.
One crucial element of the broader context is macroeconomic stability and, as describedearlier, this is closely linked to the volatility of energy revenues. A strong anti-cyclical fiscal
policy is key to allowing producer economies to ride the unpredictable waves of commodity
price fluctuations. Recent analysis by the IMF of oil exporters in Africa showed that mostexporters were ill-prepared to cope with oil price changes: accumulated savings were slight,
with sovereign wealth funds in sub-Saharan Africa holding assets of just 1.8% of
GDP – compared with 72% in the Middle East and North Africa – forcing countries to take onhigher debts or draw down financial assets when oil prices fall (IMF, 2022). As a result, in thedecade to 2020 the region’s oil producers grew over 2 percentage points slower per year
than non-resource-intensive countries. The IMF recommended a much larger buffer – ofaround 5-10% of GDP – in order to manage revenue volatility and create the foundations for

170

International Energy Agency | Special Reportmore sustainable growth. This imperative only becomes more important as the world moves
through energy transitions.
Our energy-related guidance is complementary to these considerations of macroeconomic
stability, and falls into three main areas:
Reduce emissions from traditional supplies


Bring down the emissions intensity of oil and gas production.

Gain more value by cutting waste and stepping up non-combustion uses.

Put domestic energy systems on a cleaner footingPhase out inefficient fossil fuel subsidies.

Boost efficient clean energy deployment to reduce domestic oil and gas use.

4

Develop new low-emissions products and value chainsStep up production of low-emissions fuels.

Expand into new clean energy supply chains.

4.4.1

Reduce emissions from traditional supplies

Bring down the emissions intensity of oil and gas production
As described in detail in Chapter 2, there is huge scope to reduce emissions from traditional
oil and gas operations. Many producer economies are naturally well-positioned to produce
oil and gas with low emissions intensities, but in many cases greater effort is needed to bring
down energy use and emissions in different parts of the upstream and midstream.
Most of the producers that we examine in this chapter have large subsurface reservoirs withhigh levels of natural drive pressure. This means that the energy required to extract the oilfrom the ground is relatively small, especially compared with many mature oil provinces inother parts of the world. The producer economies should therefore have relatively low
emissions intensities for oil and gas production; indeed, according to our estimates,
Saudi Arabia and the United Arab Emirates have some of the lowest scope 1 and 2 intensities
anywhere in the world today. But others, including Algeria and Venezuela, have amongst thehighest (Figure 4.15).
For Venezuela, part of this is because its extra-heavy oil requires large quantities of heat andenergy to extract, but it is more a function of above-ground issues of methane and flaring.
Algeria, for example, flares around 40 times more natural gas than Saudi Arabia for every
barrel of oil it produces (see next section). For most of the producer economies, measurestargeting methane emissions would have the most immediate impacts to reduce theiremissions intensities. Norway provides an important benchmark for performance and bestpractices (Box 4.3).
Achieving a low emissions intensity is an important strategy for producer economies. It frees
up oil and gas for domestic use or export that is currently use to power operations or that is
Chapter 4 | Strategic responses of exporters and importers

171wasted through flaring and venting. Reducing scope 1 and 2 emissions from oil and gas
operations is also one of the cheapest options to reduce GHG emissions generally and sowould be an effective way for countries to achieve their own domestic emission reduction
targets.
In addition, a number of importing countries are also starting to differentiate the emissions
intensity of oil and gas imports, and they may look to penalise or restrict imports that havea high emissions intensity (see Section 4.5). This could shut off certain export markets unlessproducers can reliably demonstrate that they are achieving a low emissions intensity. The
need for new oil and gas developments differs according to the pace of the scale-up in clean
energy technologies, but producers that can demonstrate strong and effective action to
reduce emissions can credibly argue that their oil and gas resources should be preferred overhigher-emissions options.
Figure 4.15 ⊳ Emissions intensities of oil and gas production in selected
producer economies, 2022
Oil

Natural gas

Saudi Arabia
UAE
Angola
Qatar
Oman
Iraq
Nigeria
Algeria
Iran

Qatar
Saudi Arabia
UAE
Iran
Algeria
Nigeria50
100
kg CO₂-eq/boe

100
200
kg CO₂-eq/boe
Extraction, processing and refining

Transport

Methane, venting and flaring
IEA. CC BY 4.0.

A very wide spread in emissions intensities exists between
the best and worst performing producer economies.
Notes: kg CO2-eq/boe = kilogramme of carbon dioxide equivalent per barrel of oil equivalent. One tonne ofmethane is considered to be equivalent to 30 tonnes of CO2 based on the 100-year global warming potential(IPCC, 2021). Shows producer economies that produce more than 1 mb/d or 20 bcm of gas.

Producers could go one step further by using carbon removal technologies, such as direct air
capture or bioenergy with carbon capture and storage, to remove an amount of CO2 fromthe atmosphere similar to the full life cycle emissions of the oil and natural gas (including
emissions from combustion). Such emissions-neutral oil and natural gas could be highly
valued by consumers, but the process would require careful measurement, monitoring andverification to ensure that it truly avoids any increase in emissions to the atmosphere.

172

International Energy Agency | Special ReportBox 4.3 ⊳Norway’s efforts to minimise emissions intensities

Norway is a significant oil and gas producer, accounting for 2% of global oil production in
2022 and 3% of global gas production. It is the third-largest natural gas exporter andseventh-largest net oil exporter in the world. According to the latest IEA data, Norway
has the lowest emissions intensities of oil and gas production in the world.
The Norwegian government has made a concerted effort to decrease emissions from its
oil and gas industries. Under the Paris Agreement, Norway’s nationally determined
contribution (NDC) commits to reducing net emissions by at least 50% and towards 55%
by 2030 compared to 1990 levels and achieving carbon neutrality by 2050, which are
more ambitious targets than those of the European Union. These NDC commitments
were enshrined in law in 2017 when the country adopted the Climate Change Act.
Additionally, the act sets the target of becoming a low-emissions society by 2050,
equivalent to reducing greenhouse gas (GHG) emissions by around 90-95% from 1990
levels. The act includes steps for implementation, including a gradual increase in the
taxation of GHG emissions not already included in the emissions trading system (ETS).
Norway implemented a carbon tax covering the fossil fuels and petroleum sector in1991 – it was one of the first countries in the world to do so. The national CO2 tax iscurrently about NOK 766/t CO2-eq (USD 80/t CO2-eq) for emissions outside the EU ETS.
By 2030 the carbon tax is due to increase to NOK 2 000/t CO2-eq. Approximately 85% ofdomestic GHG emissions are either covered by the EU ETS or subject to a CO2 tax (or other
GHG taxes), or both. Norway was also one of the first countries to place a ban on routine
flaring, starting in 1971.
In 2016 the country’s parliament adopted legislation mandating that Norway would
become carbon-neutral by 2030 and set out policies to achieve this goal, including
domestic reductions, international co-operation on emissions reductions, andproject-based co-operation. As is the case for all major oil and gas producers,
commitments on national emissions have not been accompanied by measures or policies
to scale back domestic production.

Gain more value by cutting waste and stepping up non-combustion uses
Securing additional value from traditional supplies has multiple aspects and we zoom in here
on two of them. The first, reducing flaring, is a short-term imperative; the second, finding
additional non-combustion uses for hydrocarbons, plays out over the long term.
Substantial gas resources that are currently being produced do not make it to market
because they are flared. Almost 140 bcm of natural gas was flared in 2022, a slight reduction
year-on-year but still a vast waste of resources (World Bank, 2023b). Just fivecountries – Russia, Iraq, Iran, Algeria and Venezuela – that together produce just under onequarter of oil production globally are responsible for more than half of flared volumes. Most
flares operate on a continuous basis and many are located within 20 kilometres of existing
Chapter 4 | Strategic responses of exporters and importers

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4

gas pipelines. Reducing flaring can bring additional gas to market and generate additional
revenues, and so many of the abatement options pay for themselves. For example, installingshort pipelines is often an option to bring flared volumes to market and these can have apayback period of just a couple of years. Where putting new infrastructure in place is difficult,an increasing range of technologies are available to allow for local uses of gas as analternative to flaring.
Even though much more remains to be done, there are many positive examples of what canbe achieved under robust regulatory frameworks, and when governments and producers
work together. For example, Nigeria has made a multi-year effort that reduced its flaring
intensity by 55% between 2005 and 2015 (Box 4.4). Angola reduced flaring volumes byaround 60% between 2016 and 2021 following its endorsement of the World Bank’s Zero
Routine Flaring by 2030 initiative.
Regulations need to address flaring and methane emissions in tandem, to avoid theunintended outcome where a requirement to reduce flaring creates an incentive to vent gas
directly to the atmosphere instead. Colombia’s 2022 regulation, for example, sets out
requirements for methane mitigation and limits for gas flaring as well as methodologies toquantify flaring, venting and fugitive methane emissions (Colombia Ministry of Mines andEnergy, 2022).
Box 4.4 ⊳Nigeria’s efforts to cut flaring

The Nigerian government has introduced increasingly stringent legislation to reduce
flaring from oil and gas operations. Nigeria was the first African country to establish aroadmap to restrict flaring with the 1979 Associated Gas Re-injection Act. Since then, thecountry has developed various regulations and plans that have targeted flaring, including
the Nigeria Gas Master Plan and the Flare Gas (Prevention of Waste and Pollution)
Regulation. Emissions from flaring fell by 65% between 2005 and 2015, from around70 Mt CO2-eq to 25 Mt CO2-eq (Figure 4.16).
The flaring intensity in Nigeria has remained broadly constant since 2015 as the easiest
projects to implement have been harnessed and many facilities struggle with ageing
infrastructure. The country’s updated NDC to the Paris Agreement, from 2021, includes
reduction targets for gas flaring and venting, with quantifiable targets and detailed
regulatory plans on how to operationalise the intended reductions. The updated NDC
states the goal of ending routine flaring by 2030 and reducing fugitive methane emissions
from oil and gas operations by 60% by 2031.
To meet these goals, in 2022 the Nigerian government issued guidelines to prevent andcontrol the emission of GHGs from upstream oil and gas operations at new and existing
facilities. For flaring, the guidelines prohibit cold venting (a waiver for operational
exigencies is possible), require a combustion efficiency of at least 98% and set a series ofrepair requirements. Operators are also tasked with developing GHG management plansthat include an inventory of emissions sources, accounting methodologies, and plans and174

International Energy Agency | Special Reporttimelines to reach net zero emissions. Producers need to regularly monitor and reportflaring and venting volumes based on accurate and empirical measurements.

80

Emissions from flaring

m³/bblMt CO₂-eq

Figure 4.16 ⊳ Emissions from and intensity of flaring in Nigeria, 2005-2022
24

60

18

40

12

20

6

2005

Flaring intensity

4

2010

2015

2022

2005

2010

2015

2022
IEA. CC BY 4.0.

New policies and regulations have spurred a significant reduction in flaring
and in the flaring intensity of oil production in Nigeria.
Note: m3/bbl = cubic metres per barrel.
Source: IEA analysis based on World Bank (2023b).

In recent years many producer economies have been building a host of new refineries withthe aim of capturing more value from their hydrocarbon resources. The Middle Eastaccounted for a quarter of new refining capacity that came online between 2015 and 2022.
Some countries, such as Saudi Arabia and the United Arab Emirates, also made investmentsin overseas refineries, primarily in China and India. In 2022 Saudi Aramco acquired 30% of
the 210 kb/d Gdansk refinery in Poland. In 2023 it announced two deals to acquire stakes in
Chinese refineries, Rongsheng and ZPC, to secure outlets for its crude oil resources. For
example, investment in the ZPC refinery involved a long-term crude supply agreement for
480 kb/d.
More recently, companies in producer economies have put more emphasis on
petrochemicals as they expect oil demand for non-combustion uses to stay relatively robustin net zero transitions and their expansion projects to offer higher and more resilient
margins. Many recent refineries are being developed as integrated facilities, either
co-located with petrochemical facilities in the same industrial complex or more closely
integrated. These integrated facilities produce a substantially higher share of
petrochemical-related products and use less fuel than traditional refineries, and are better
suited to serve changing oil product demand patterns in the APS and NZE Scenario. China’s
Chapter 4 | Strategic responses of exporters and importers

175

Hengli Petrochemical refinery can produce over 40% petrochemical feedstock products
compared with around 10% in typical refineries. Some are maximising the reforming of
low-value naphtha to aromatics instead of gasoline.
Several new technologies are under development. High-severity fluid catalytic cracking (FCC)
can produce petrochemicals from a low-value refinery stream. An “FCC to steam cracking”
scheme could raise petrochemical yields to almost 70%. Saudi Arabia is pursuing a more
ambitious scheme to convert crude oil directly into chemicals. While the cost andperformance of this pathway are not yet fully proven, this “crude oil to chemical” technology
has potential to increase the petrochemical yield to up to 80% of total output.
This kind of strategic reorientation towards non-combustion uses of hydrocarbon resources
can help producer economies secure additional income streams against potentially declining
fossil fuel revenue, but will require strengthened efforts to manage capital costs and develop
the necessary skilled workforce.

4.4.2

Put domestic energy systems on a cleaner footing

Phase out inefficient fossil fuel subsidies
Pricing signals in many producer economies do not encourage clean or efficient choices by
consumers or investors. Changing this inevitably requires revisiting the difficult issue ofpricing reform and removal of fossil fuel subsidies. This is a socially and politically sensitive
issue, as the expectation of cheap fuels is deeply rooted in many producer economies andsubsidies are viewed as a means of sharing the benefits of the national resource endowmentwith populations. But it is nonetheless an essential reform if energy systems and economies
are to be put on a more sustainable footing.
Even without subsidies, many producer economies still have a comparative advantage inenergy, since their low oil and gas production costs and excellent renewable resources canprovide stable and low domestic prices, especially for natural gas and electricity.
There are many examples of successful – and unsuccessful – attempts at pricing reform.
Differing national circumstances mean that there is no single path to follow when reforming
inefficient fossil fuel subsidies. However, successful efforts in the past suggest the following
elements are essential ingredients:
Prepare the ground with a comprehensive vision of the aims and stages of the reform
process and a communication strategy that informs citizens of the need for reform andthat it is being implemented in a just manner.

Introduce reforms in stages to avoid too abrupt or there may be large price rises that
may be difficult for some parts of the population to absorb.

Ensure that pricing systems are transparent, well-monitored and enforced.



Implement parallel reforms to protect vulnerable groups. There is a strong case fortargeting conditional cash transfers at those who lack reliable access to clean cooking
fuels and electricity.

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International Energy Agency | Special ReportAnchor pricing reforms in a broader strategy that allows consumers to make moreenergy-efficient choices, e.g. by working with domestic producers and other suppliers
to raise standards for efficient appliances and equipment.

Pricing reforms are often pushed through quickly at times of stress – these are the sorts ofchanges that are most prone to reversal. Durable reforms are typically planned andimplemented over time, with inevitable adjustments for short-term circumstances but aspart of an integrated vision for the direction of change. Since most subsidies benefit
better-off segments of the population (who use more of the subsidised fuels), reforms arecompatible with wider efforts to promote energy access and tackle energy poverty, which
need to be much more targeted.
Box 4.5 ⊳Fossil fuel subsidy reform in Saudi Arabia

Historically, Saudi Arabia has extensively subsidised energy costs for domestic use, but it
has implemented a number of changes as part of its Vision 2030 development plan. By
and large, these have been relatively small and incremental steps, but the anticipatedgains from reforms have been clearly articulated: to improve the fiscal position,
incentivise sustainable patterns of consumption, promote a sound investment model forindustrial development, and allow for a more targeted approach to benefits. Between
2015 and 2018 gasoline prices tripled and electricity prices doubled. In 2018 thegovernment introduced a system of cash payments to Saudi citizens in lower- andmiddle-class households based on size and income, up to a certain threshold.
These efforts limited the subsidy for fossil fuel consumption, which in the Saudi case ismainly foregone revenue rather than an explicit payment from budgetary funds.
Nonetheless subsidies remain substantial, averaging around USD 50 billion per year overthe past five years (which included a large drop in 2020 followed by a substantial
increase, reflecting changes in international prices). While momentum for large-scalepricing reforms has slowed in recent years, the authorities raised the price of diesel,
which has been heavily subsidised, by 21% at the end of 2021 and by a further 19% at theend of 2022. Nonetheless, the diesel price remained around 80% lower than the global
average in 2022, and the average electricity price for residential consumers was around
70% lower.

From very low domestic levels in the past, the price of energy in the largest producers has
started to increase – Saudi Arabia is an example of gradual change (Box 4.5). Nigeria is now
undergoing a much more accelerated process of reform and it is having much more
substantial near-term impacts on consumption patterns and welfare. Pricing reforms in May
2023 tripled the price of petrol, nearly doubled some transport fares and significantly
increased food prices; this resulted in an immediate hike in the inflation rate, which reached
23% in June, the highest rate in 17 years. Nigeria’s average daily petrol consumption has
fallen by 28% since the subsidies were scrapped. In response, the government declared a
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4

state of emergency on food security and decided to reallocate the expenditure that was usedon subsidies to invest in the agricultural sector and to provide direct subsidies to farmers andlow-income families.

Boost efficiency and clean energy deployment to reduce domestic oil and gas use
Domestic oil and gas demand is set to increase significantly in many of the producer
economies in the coming years, driven by economic and population growth. In the
Middle East,2 for example, oil demand rises in the STEPS by more than 2 mb/d (a near 30%
increase) and gas demand by 265 bcm (a 45% increase) to 2050. Much of this demand could
be cost-effectively substituted with low-emissions sources, improving the overall efficiencyof the energy system, allowing countries to meet export demand with lower investment in
new supply, and reducing local air pollution as well as CO2 emissions.
Figure 4.17 ⊳ Potential reductions in domestic oil and gas demand in the
Oil

12

bcm

mb/d

Middle East by sector, 2010-2050

10

750

8

600

6

450

4

300

2

150

2010
Transport

2020
Power

2030

2040

Buildings

2050
Industry

Natural gas

900

2010
Other

2020
STEPS

2030

2040

2050

Resulting demand
IEA. CC BY 4.0.

Around 7 mb/d of oil and 650 bcm of gas consumed domestically in 2050 could be
avoided through efficiency efforts, electrification and other clean energy deployment.

The clearest opportunities to expand clean energy are in the power sector (Figure 4.17). Many
producer economies, most notably in the Middle East and North Africa, have solar resources
with some of the best potential in the world and these could provide the backbone for asignificant reduction in both oil and gas use in the power sector. Currently more than 70% of
the electricity generated in all the countries of the Middle East comes from natural gas and over
20% from oil. This is the highest share anywhere in the world; outside the Middle East, only

2 Figures in this section on the Middle East include all countries in the region, including some that are notproducer economies.

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International Energy Agency | Special Reportaround 2% of electricity is generated from oil. A concerted effort to deploy renewables could
displace around 1 mb/d of oil and 310 bcm of natural gas from the power sector by 2050.
Electricity use in buildings is the largest component of electricity consumption in the
Middle East. With the large anticipated increase in the use of air conditioners, demand forspace cooling alone could triple to 2050 (an increase of over 1 exajoule from 2022 levels).
Power demand for air conditioning is generally higher during the daytime when solar PV
generation is higher, reducing the risk of potential mismatches between power output andconsumption. Improvements to efficiency through stringent standards for new and existingbuildings, improvements in the efficiency performance of air conditioners, and theelectrification of heating systems could free close to 200 bcm of natural gas use.
The Middle East has around 45 million cars in its current vehicle fleet, the vast majority
relying on gasoline to fuel internal combustion engines (ICEs). Together with other roadvehicles, these account for the bulk of oil demand in the transport sector. The fleet of cars is
projected to increase and if this incremental demand for mobility is met with oil, as in the STEPS,
it would lead oil demand in the transport sector to rise by more than 50% to 2050. Greater
efficiency and electrification of transport could displace around 4 mb/d of oil in this sector.

4.4.3

Develop new low-emissions products and value chains

Step up production of low-emissions fuels
Clean electrification and efficiency are central pillars of rapid energy transitions, but theycannot carry the shift to a net zero emissions system on their own. In 2050 around 50% of
final energy consumption is met by electricity in the NZE Scenario, but the remainder is met
by a range of low-emissions fuels. While this is a very different landscape for fuel suppliers,
it nonetheless means that expertise in the large-scale production, processing and transportof fuels remains a crucial area of expertise and commercial opportunity.
Low-emissions fuels include various sources of biofuels, hydrogen and hydrogen-based fuels.
In addition, some fossil fuel use can be equipped with carbon capture, utilisation and storage(CCUS) to avoid CO2 emissions. Developing production facilities for hydrogen andhydrogen-based fuels and deploying CCUS are particularly interesting avenues for producer
economies (Box 4.6).
In Oman, for example, deploying low-emissions hydrogen in refining could cut annual
emissions by more than 3 Mt CO₂ (4% of current emission levels). This new industry can also
be a source of economic activity, inward investment and intellectual property exports.
Renewable energy generation, electrolysis, power grids, CCUS and the production ofammonia, synthetic fuels and low-carbon steel could all play such a role in developing
alternative sources of revenue; this is especially important in the APS and NZE Scenario
where there are large falls in income from oil and gas. Finally, low-emissions fuels allow
producers to leverage their existing strengths, resources and competencies in oil and gas forthe new global energy economy.
Chapter 4 | Strategic responses of exporters and importers

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4

Producer economies in Africa and the Middle East currently account for just under 5% of thelow-emissions hydrogen production capacity under construction or consideration around theworld, but this includes some of the largest individual projects. For example, the Helios Green
Fuels project in Saudi Arabia, a USD 8.5 billion project that was approved for development inearly 2023, will be able to provide around 0.2 Mt hydrogen per year and involves 4 GW ofsolar PV and wind power, 2 GW of electrolysis, and electricity storage. This is eight times
larger than today’s biggest operational project and 80 times larger than the biggest plant justtwo years ago.
In Oman, land leases were issued in June 2023 to three consortiums pursuing projects thatwill also have a capacity to produce around 0.5 Mt hydrogen per year; another project tobuild 5.5 GW of solar PV for a 350 MW electrolyser for ammonia production took final
investment decision in July 2023. In Angola, the integration of new renewable capacity andammonia manufacturing with around 300 MW of electrolysis is proposed for export from the
middle of the decade. Two-thirds of the planned capacity in producer economies is to
produce hydrogen or hydrogen-based fuels for export to overseas markets, and countries
have signed numerous agreements with potential importers. A number of producer
economies could produce some of the lowest-cost hydrogen available anywhere in theworld, but policy support will initially be essential to scale this up (Figure 4.18).
Figure 4.18 ⊳ Estimated production costs for low-emissions hydrogen from
USD per kg hydrogen

renewables via electrolysis in producer economies, 2030

6

10th - 90th
percentile

5

Mean

4
3
2
1
MiddleEast

Latin
America

AfricaRest ofworld

Producer economies

IEA. CC BY 4.0.

Some producer economies could produce low-emissions hydrogenat a much lower cost than global averages.
Note: Based on the costs of installing dedicated solar and wind electricity capacity in the lowest-cost
combinations for the purposes of hydrogen production per 40 square kilometre (km2) surface area.

Low-emissions fuels could create significant value for producer economies, but they are
unlikely to replace more than a small part of today’s fiscal and export revenues from fossil
180

International Energy Agency | Special Reportfuel activities (Figure 4.19). In the APS, hydrogen export revenues in the Middle East rise toaround USD 60 billion in 2050, a major increase from today, but less than the USD 390 billion
drop in income from oil and gas over this period. In the NZE Scenario, hydrogen export
revenues from the Middle East rise to around USD 90 billion in 2050. This is a similar
magnitude to oil and gas income at that time, but it is still much smaller than the
USD 690 billion drop in income from oil and gas sales to 2050.
Figure 4.19 ⊳ Income from low-emissions hydrogen and hydrogen-based fuelsBillion USD (2022, MER)

and oil and gas in the Middle East, APS and NZE Scenario
APS

800

NZE
Hydrogen:Ammonia

600

Hydrogen and otherH₂-based fuels
Fossil fuels:
Oil

400

Natural gas

200

2022

2030

2050

2030

2050
IEA. CC BY 4.0.

Exports of hydrogen and hydrogen-rich fuels are no substitute for the revenues from fossil
fuels, although they could provide a durable source of economic advantage.

The development of a hydrogen production industry can lay the foundation for otherindustrial developments. This includes the production of higher-value commodities such as
ammonia, steel, aviation fuel, methanol and other chemical products. It can also help
broader emissions reduction efforts, even if the hydrogen itself is destined for export. For
example, the output of a 4 GW renewable project would be larger than current total
electricity generation in each of Guyana, Senegal and Suriname.
If grid-connected, just a fraction of this renewable electricity could be a valuable resource
for managing the electricity network at key moments, and there are strong arguments for
expanding clean power generation for local communities alongside that for hydrogenproduction. Its scale would also generate experience with finance, regulation, installationand operation, which would reduce costs for subsequent installations to meet growing
domestic electricity demand from households and businesses or attract newenergy-intensive customers.

Chapter 4 | Strategic responses of exporters and importers

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4

Box 4.6 ⊳Oman’s low-emissions hydrogen plans

Oil and gas represent around 60% of Oman’s export income, but natural gas reserves are
declining towards a level that could only cover existing domestic demand in the medium
term and therefore not allow for export. It has announced a target to become net zeroby 2050 and to produce at least 1 Mt of renewable hydrogen a year by 2030, up to
3.75 Mt by 2040 and 8.5 Mt by 2050. Oman benefits from high-quality solar PV andonshore wind resources, and has existing fossil fuel infrastructure that can be directly
used or repurposed for low-emissions fuels. Oman also has large amounts of land that canbe used for large-scale project development; to date, around 1 500 km2 has been put aside
with the potential to produce around 1 Mt/yr of renewable hydrogen. Around 50 000 km2
has been identified as suitable for hydrogen production, enough for 25 Mt/yr (IEA, 2023).

PJ

Figure 4.20 ⊳ Oman’s LNG exports in 2021 and renewable hydrogen targets
1 000

Hydrogen targets
LNG exports

800
600
400
200

2021

2030

2040

2050
IEA. CC BY 4.0.

Oman has ambitious targets for renewable hydrogen and most is intended for export

Most of the hydrogen is intended for export – the 2040 hydrogen target would represent
80% of its LNG exports today in energy-equivalent terms – but developing a domestic
market can strengthen Oman’s position while international demand grows (Figure 4.20).
Oman’s refining sector, for example, uses around 0.35 Mt of fossil hydrogen and this
could be replaced by renewable hydrogen. Expanding renewables for hydrogen could
also accelerate cost reductions for other renewable projects in the country, assist
emission reductions in the country’s power system (natural gas accounts for over 95% of
the country’s electricity generation today) and bolster natural gas export revenues by
displacing domestic gas demand. Achieving Oman’s 2030 hydrogen and power sector
emissions reduction goals would require around USD 37 billion in investment. By then,exports and replacement of domestic natural gas use could generate an economic valueof more than USD 2 billion a year, which could rise to double-digit USD billion levels in
the long term.

182

International Energy Agency | Special ReportTo get projects moving will take a strongly collaborative mindset, both internationally andwithin countries. Low-emissions hydrogen and CCUS will not work easily, at least in the shortterm, unless the upstream, midstream and downstream explore greater integration andpartnership, together with government. When a CCUS project is planned by a particularcompany, the initial costs can be hard to finance. But when initiatives are considered as partof a broader approach, where the costs of infrastructure can be shared within an industrial
cluster, then the economic case can become much more attractive.

Expand into new clean energy supply chains
Alongside the ability to produce low-emissions energy, oil and gas producers also haveopportunities for diversification in clean energy supply chains, including in critical mineralssuch as copper and lithium. The rapid deployment of clean energy technologies as part ofnet zero transitions is set to turbocharge demand for a range of critical minerals. In the APS,
demand almost triples by 2030 and more than quadruples by 2050. In the NZE Scenario, aneven faster deployment of clean energy technologies implies a nearly fourfold increase indemand for critical minerals in 2030 from today’s level (Figure 4.21). Meeting these demands
requires a significant ramp-up in mining and refining activities.
Figure 4.21 ⊳ Mineral requirements for clean technologies in the APS andMt

NZE Scenario
By technology

40

By mineral

30
20
10
2022

2030 2050
APS

Solar PV
Other low emission
Electricity networks

2030 2050
NZE

Wind
EVs and storage
Hydrogen2022

2030 2050
APS

CopperLithium
Other2030 2050
NZE

NickelManganese

Graphite
CobaltIEA. CC BY 4.0.

Clean energy technology demand for critical minerals could
create new investment opportunities for the oil and gas sector.
Note: EVs = electric vehicles.

There are several similarities between oil and gas extraction and mineral extraction. Bothrequire large capital expenditure, geological and engineering expertise, and strong
capabilities to manage complex projects. An ability to work with governments in
Chapter 4 | Strategic responses of exporters and importers

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4

resource-holding nations and manage political risks are also common elements in bothbusinesses. The mining of critical minerals generally involves higher rates of return thanthose in traditional oil and gas operations. These make critical mineral developments one ofthe opportunities for fossil fuel producers to diversify their businesses.
A number of oil and gas companies are looking closely at opportunities around criticalmineral developments. Examples include the following:

Oil refining operations provide key inputs such as needle coke, which is used to produce
synthetic graphite for battery anodes. Phillips 66, a major refiner, established apartnership with Novonix to produce synthetic graphite anode materials using thespecialty coke Phillips 66 produces.



Oil and gas companies are making investments in lithium extraction and conversion
businesses. Galp Energia established a joint venture with Northvolt to build a lithiumhydroxide conversion plant. Some oil majors have ventured further into clean energy
manufacturing. TotalEnergies’ investments in battery manufacturing through Saft andthe Automotive Cell Company are key examples.



Oilfield service providers such as SLB and Halliburton are aiming to extend their chemical
know-how to critical minerals. Specialised engineering and technology companies thathave traditionally serviced the oil and gas sector such as Technip are starting to support
the development of critical mineral refining and conversion facilities.

Lithium brine extraction is an area that is gaining significant traction in the oil and gas
industry. Companies including Chevron, Equinor, ExxonMobil, Gazprom, Imperial, Oxy and
YPF, and service companies like Baker Hughes and SLB are securing a stake in this emerging
sector, investing or partnering with geothermal companies, mining juniors and chemical
start-ups (Table 4.2). Among various lithium production routes, direct lithium extraction(DLE) has become a key focus of oil and gas companies. DLE technologies extract lithium frombrine using filters, membranes or other equipment, removing the need for evaporation
ponds. Groundwater aquifers hold large volumes of water with considerable amounts ofdissolved mineral content, leading to large aggregate reserves. DLE technologies could help
unlock this potential with relatively short lead times. The process is closer to a chemicalbusiness than a traditional mining business and therefore attracts interest from oil and gas
companies with refining and chemical expertise. The possibility of extracting other metals,
such as bromine, or generating geothermal power has the potential to increase profitability
further, although challenges around scalability and water consumption need to be resolved.
Current areas of interest for oil majors are Canada (Leduc oil fields in Alberta), theUnited States (Arkansas and Texas), Germany and France (Rhine Valley), as well as Russia(Box 4.7).
There are well-known synergies between the core expertise of oil and gas producers andgeothermal-based lithium extraction. These involve knowledge and skills in geology and earth
exploration, drilling and well construction, reservoir engineering and subsurface pumping in
high-temperature and high-pressure environments. In July 2022 the US Department of Energy
184

International Energy Agency | Special Reportannounced a USD 165 million initiative to address technology and knowledge gaps in
geothermal energy, based on best practices used within the oil and gas industry.
Table 4.2 ⊳Oil and gas industry investment and partnerships in lithium andgeothermal activities

Oil majors

Region

Focus

Activities

ChevronUnited States

Geothermal• Investment in Baseload Capital to develop geothermal
projects in the United States (USD 24 million raised in
2022)

EquinorFranceGeothermal+ lithium• Investment in Lithium de France, junior miner(USD 55 million raised in 2023)

ExxonMobil

United States

Lithium• Announced project to exploit lithium in Arkansas

Imperial

CanadaLithium• Investment in E3 Lithium, junior miner, with projects
in Leduc oil fields

Gazprom

RussiaLithium• Partnering with Irkutsk Oil Company to exploit lithiumin Kovykta gas field

Oxy

United States

Geothermal+ lithium• Joint venture with All-American Lithium to extract
lithium from geothermal and brines

YPF

Argentina

Lithium• Partnering with Catamarca Minera y Energética toprospect for lithium in the Fiambala salt flats

Oilfield services Region

Focus

Activities

Baker Hughes

United States

Geothermal• Investment in Greenfire Energy

SLB

United States

Geothermal+ lithium• Investment in EnergySource Minerals• Partnering with technology provider Gradiant forsustainable lithium compound production

OthersRegion

Focus

Activities

Berkshire
Hathaway
EnergyUnited States

Geothermal+ lithium• Lithium and geothermal project in the Salton Sea,
California

Koch

United States

Geothermal+ lithium• Investment in lithium extraction processes• Investment in Standard Lithium (USD 100 million)• Investment in Compass Minerals’ Utah project,(USD 252 million)

Box 4.7 ⊳Identifying critical mineral opportunities in oil-rich countries

Certain oil-rich countries, such as Brazil, Canada, China, Russia and the United States,
have already identified significant critical mineral reserves. This creates the opportunity
to secure new revenue to compensate for the potential decline in fossil fuel demand inclimate-driven scenarios. For example, Latin America is already a major player in criticalminerals production, providing some 40% and 35% of global copper and lithium outputs
respectively. The region holds sizeable resources of bauxite, graphite, nickel and rareearth elements. With rising demand for these minerals, it is estimated that the region’s

Chapter 4 | Strategic responses of exporters and importers

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4

revenue from the production of these minerals could grow 1.5 times by 2030 in the APS
without a further increase in market share. However, this is not the case for many
producer economies in the Middle East and some African countries; resources in many
oil-producing countries remain underexplored, and better geological data will need to becollected to understand better the size of the opportunities. Exploration is often the firststep for countries wanting to develop their critical mineral potential. Some oil producers
are already embarking on this. Saudi Arabia launched a USD 207 million geologicalmapping project of the Arabian shield. Similarly, the African Finance Corporation (AFC)recently partnered with the Nigerian mining sovereign wealth fund to develop mining
projects in Nigeria, Africa’s largest oil producer. Three lithium refining projects are also
being developed in Saudi Arabia and the United Arab Emirates.
Infrastructure can play a key role in this transition. Several African oil producers, including
Angola, the Democratic Republic of the Congo (DRC) and Zambia, are reactivating therailway corridor to the port of Lobito, partnering with commodity traders to seize
economic opportunities related to their mineral resources. The world’s largest coppercobalt deposits are located in the DRC’s copperbelt, and Angola has a number of criticalmineral projects currently under development, including rare earth elements (Huambo
province), lithium (Namibe province) and phosphates (Cabinda province).
Developing new industrial-scale mining projects often comes with a risk of environmental
degradation and adverse impacts on local communities. Failing to consider these issues
may make it difficult to obtain – and maintain – a social licence to operate and imperilclean energy transitions. International co-operation to promote sustainable andresponsible development practices can help reduce these risks, including by encouraging
due diligence and strengthening data collection and reporting mechanisms.

4.5

Working together to ensure equitable and just net
zero pathways

4.5.1

Why should exporters and importers work together?

Net zero transitions can only occur smoothly if countries work together in a mutually
beneficial manner. This includes countries with different interests and positions in oil and gas
supply chains actively co-operating. As noted in a recent study, “nothing can replace thestrong domestic policy stance needed to tackle the risk of Dutch Disease and the Resource
Curse. But surely, the international community can do a lot more to support these domestic
efforts” (van Hulst, 2023). This would help accelerate efforts to achieve net zero andeconomic transitions and could reduce disruptions and geopolitical tensions. Common goals
for co-operation include:
Foster mutual understanding and reduce the risk of high and volatile prices. The sequencingof changes in fossil fuel demand and supply is a critical issue for orderly transitions, and186

International Energy Agency | Special Reportdialogue between importers and exporters can help to mitigate the risk of market disruption.
It is important for producers and exporters to understand how major consuming countries
view the outlook for demand and the dynamism of changes that could restrain it. If producers
are unable to manage the extreme strains that would be placed on their fiscal balances bylower prices in net zero transitions, this could also lead to turbulent and volatile markets.
Avoid a “race to the bottom” for oil and gas extraction. Governments around the world will
face difficult choices about how much income to retain from oil and gas companies’
dwindling revenues. While governments, especially those with higher cost resources, may
relax fiscal terms on extraction to protect local industries, this would reduce their income
and could be perceived as offering support to the oil and gas industry even as the world istransitioning away from fossil fuels. In the NZE Scenario it is assumed that countries do not
reduce government tax takes except where oil prices fall far below the marginal cost of
production. This helps to avoid a “race to the bottom” that would further reduce the income
governments in producer economies receive from oil and gas sales.
Pay attention to the allocation of rents from fossil fuel extraction and use. The reductionin oil and gas demand and prices through climate policies introduced by consumer countries
could reallocate the income generated from the extraction and use of fossil fuels fromproducer economies to consumer countries (Box 4.8). Different climate policies affect themagnitude of this swing in different ways and by working together producer and consumer
countries can address the undesirable impacts of a redistribution of income between andwithin countries. For example, it may be possible to levy CO2 pricing at the point of export
rather than via border adjustments in the importing region.
Minimise incentives to invest in ways that undermine net zero transitions. By providing
greater visibility on their demand-side policy goals, and stable regulatory regimes to deliver
them, consumer countries can help producer economies plan their oil and gas investment
strategies and fiscal regimes. Regular dialogue about demand and supply outlooks can also
assist. These approaches would reduce the risk of overinvestment in new oil and gas capacitythat could undermine overall efforts to reduce emissions and the risk that investment in new
oil and gas capacity cannot be recouped.
The prospect of lower future revenues from oil and gas in net zero transitions may also
incentivise producer economies to expand production in the near term, reducing prices andpotentially boosting near-term consumption (a tension known as the “green paradox”[Figure 4.22]) (Bauer, et al., 2018). In the NZE Scenario, consumer economies avoid this by
ensuring near-term policies are sufficiently strong to counteract any effect of lower prices on
demand. They could, for example, implement policies that swap combustion equipment forheaters and motors that are incompatible with fossil fuel, or prohibit ICE cars, which would
reduce demand even before the ban comes into force as carmakers ramp up EV production
and the ICE vehicle fleet shrinks.
Support producer economies to accelerate economic diversification. In addition todiversifying public revenue beyond the energy sector (Section 4.2.2), producer economies
Chapter 4 | Strategic responses of exporters and importers187

4

can be helped to develop new models of resource development, whether focused on CCUS,
trade in hydrogen, or non-combustion uses for hydrocarbons. Policy signals and investment
support from potential consumers of these resources will be fundamentally important. Given
the abundant renewable resources of many producer economies, producer economies could
also attract electricity-intensive industries looking to locate in areas that can best provide
low-cost emissions-free electricity. Similarly, existing subsurface data and expertise inproducer economies position them well to develop CO2 storage resources, potentiallymaking them attractive locations for new heavy industries and CO2 removals. Cross-border
support, including financial and technical assistance, can help with this, although thecollective global need for clean energy technology deployment needs to be balanced by thedesire of countries to promote domestic job creation and local commercial advantages andto ensure that clean energy supply chains are as resilient and low-cost as possible.
Figure 4.22 ⊳ How the anticipation of future climate policies can lead to thegreen paradox

IEA. CC BY 4.0.

Unless carefully designed, the announcement of future climate and energy policies
could encourage oil and gas producers to expand production in the near term.

Accelerate global clean energy transitions. Producer economies will be critical to thedevelopment of a number of clean energy technologies needed in net zero transitions. They
are well placed to support large-scale market expansion for CO2 capture equipment,
electrolysers, energy storage installations and other equipment that will propel them along
the learning curve. Some of these effects will accrue from economies of scale, and theimpacts of scaling up the capacity of installers, industrial relationships and efficient supply
chains could be even more significant. Producer economies are already leading the way onsome technologies: the size and ambition of their proposed hydrogen projects and theirpartnerships with international exports mean they are already near the global technologicalfrontier for hydrogen production from renewable electricity.
188

International Energy Agency | Special ReportBox 4.8 ⊳Tax revenues from the production and use of oil and gas

Governments around the world collect a large amount of income from the production
and use of oil and gas. Almost USD 2 trillion was collected annually through oil and gas
production taxes, production-sharing agreements, and domestic income generated by
NOCs between 2018 and 2022 (around half of gross revenues generated by the industry).
Over the same period, governments collected around USD 2.5 trillion annually throughenergy, excise and value-added taxes on oil and gas use (Figure 4.23). A further
USD 90 billion was collected globally through CO2 prices on oil and gas use.

4

Figure 4.23 ⊳ Annual average government revenue from oil and gas byBillion USD (2022, MER)

scenario

3 000

2018-22

2030
Upstream taxes
CO₂ taxes
Other energy taxes

2 000

1 000

Historical

STEPS

APS

NZE
IEA. CC BY 4.0.

Net zero transitions see a transfer in rents from producer to consumer economies astaxes from oil and gas extraction fall and CO2 taxes on oil and gas use rise.

In the APS and the NZE Scenario, reductions in oil and gas demand and prices, alongsidea slight drop in the government share of gross oil and gas revenue, results in a large dropin production taxes (they fall by around USD 1.2 trillion in the NZE Scenario to 2030). Tax
revenue from oil and natural gas use falls due to efficiency improvements, the rise inelectric mobility, and heating powered by renewable technologies. These reductions arealmost wholly offset by a rise in taxes generated by CO2 prices, which increase by USD 1
trillion in the NZE Scenario to 2030. Much of this represents a sizeable transfer of oil andgas rents from producer to consuming economies. However, the effect is partly mitigatedby policies such as renewable energy targets and bans on ICEs that limit the need for CO2
pricing to be the spur for the uptake of clean energy.
Aligning expectations on the demand and supply of low-emissions fuels would also be
mutually beneficial. There is considerable interest in investment in low-emissions fuels in
Chapter 4 | Strategic responses of exporters and importers

189

producer economies, but uncertainty persists about how quickly demand for the various
fuels will materialise in consumer countries. Close co-ordination between consumers andproducers is essential to the scale-up of a new international industry that requires new,extensive capital-intensive infrastructure.

4.5.2

How can exporters and importers work together?

Importing countries can work with export partners in several ways to build upon their sharedinterests. In a world where demand for energy services is increasing, resource-rich countries
will continue to seek value from their endowments, hydrocarbon or otherwise, andimporters will value secure, affordable energy supplies. The task ahead is to make thesequests compatible with net zero transitions and the gathering pace of change in global
energy. There are four main routes to promoting effective international co-operation in thisarea: ensuring the right market signals; co-operating to unlock investment in low-emissions
fuel trade; collaboration on technology; and bilateral and multilateral engagement. Several
examples exist of existing policy efforts looking to promote action in these areas (Table 4.3).
Table 4.3 ⊳PillarPillars of co-operation between importers and exporters forsecure and orderly energy transitions
Leading party Main elements

Ensure the right Oil andmarket signals natural gas
importers

ExamplesPlace economic value on oil
and gas with low emissions
intensity• EU regulation on methane emissions
reduction in the energy sector• Joint Declaration from Energy Importers
and Exporters on Reducing Greenhouse
Gas Emissions from Fossil Fuels

Align policies and regulations • EU 2035 ban on sales of ICE carson oil and gas use with stated • Canada Clean Fuel Regulations
climate targets• India 2022 ban on single-use plastics
Create demand for lowemissions fuels and products• EU proposed Carbon Border Adjustment
Mechanism• “First-mover coalitions” for lowemissions products• US Inflation Reduction Act tax credits

Co-operate to
unlockinvestment in
low-emissions
fuel trade

Importers and Sign memorandums ofexporters
understanding for
co-operation on studies andprojects• Agreements on hydrogen projects
between European countries, Japan andproducer economies

Importers facilitate or• H2Global “double auction” model tounderwrite multi-year offtake
bridge cost gaps between producers andcontracts
users and proposed international leg ofthe European Hydrogen Bank
Enable investment in• World Bank USD 350 million
infrastructure, including ports, commitment to Chile for hydrogenstorage and pipelines• US-UAE Partnership to Accelerate
Transition to Clean Energy

190International Energy Agency | Special ReportPillar

Leading party Main elements

Collaborate on Advanced
technology
economies,
research
institutes,
oil and gas
industryCo-fund pilot anddemonstration projects

Examples• Germany has announced financing for ahydrogen demonstration project inMorocco• Governments commit to purchasing
offsets from early projects in developing
countries, such as the proposed direct
air capture demonstration in Kenya• In Salah CCUS project in Algeria fundedby oil and gas companies

Support CO2 storage resource • World Bank Carbon Capture and Storage
exploration and development
Trust Fund for South Africa• Japan-Malaysia study on CO2 storage
Programmes that nurture
start-ups in producer
economies• Netherlands’ Invest International “Dutch
Desk Nigeria”

Joint R&D programmes thatenhance local technicalcapacities and skills• UK Ayrton Fund

• Innovation Norway support to start-ups
moving abroad• Mission Innovation calls for joint
projects• Asian Development Bank support for theIndonesia centre for excellence for
CCS/CCUSEnter bilateral Importers and Producer and consumer
and multilateral exporters
forums, including for cleandialogueenergy topics• Net-Zero Producers Forum• The LNG Producer and Consumer
Dialogues• Clean Energy Ministerial initiatives,
especially on CCUS and hydrogen

Work toward agreeinginternational standards• UN Oil & Gas Methane Partnership 2.0

Wider economictransformation• Saudi Japan Vision 2030

• IPHE work on emissions intensity
definitions for hydrogen

One area where producer and consumer economies can work together is on tackling
methane emissions. We estimate, for example, that the energy system in theEuropean Union results in around 11 Mt of methane emissions overseas during the
production and extraction of the oil and gas that it imports (Figure 4.24). If consumer
economies send support or signals to producer economies – which could take the form offinancial and technical assistance, financial penalties such as CO2 border taxes, or import
restrictions – producer economies would have a clear incentive to reduce these emissions.
For example, the recent provisional agreement on a new EU regulation on methane
emissions reduction in the energy sector requires that new import contracts for oil, gas andcoal entered into after 2027 follow EU methane management standards and sets maximum
methane intensity levels from 2030. It also establishes a methane transparency database,methane performance metrics, and a rapid alert mechanism for super-emitting events.
Chapter 4 | Strategic responses of exporters and importers

191

4

Figure 4.24 ⊳ Methane emissions of imported oil and gas in selected countries
and regions, 2022

China
European Union
United States
Korea
Japan
MexicoUnited Kingdom
Canada
2

4
Oil

8

6
Natural gas

Mt
IEA. CC BY 4.0.

Oil and gas importers can assist exporters in reducing the 25 million tonnes of methane
emitted per year from hydrocarbon extraction to meet demand from these eight regions.

A number of producer economies have announced plans to work with consuming countries
to scale up clean energy exports. For their plans to be realised, importers need to support
the investment case through co-operation on import demand and infrastructure. For
example, the value chain for large-scale trade in hydrogen-based fuels is complex andincludes hydrogen production, water supply, ammonia manufacture, energy storage, importand export terminals, pipelines, ships and either renewable electricity generation or CO2
storage.

IEA. CC BY 4.0

The first phases of such development could bear a close resemblance to the initial scale-upof the LNG market, with importers seeking access to new supplies sharing much of the risk
with the operators of export infrastructure. Japan was a frontrunner in the development of
the LNG market and it held a 75% share of global LNG trade through to the late 1980s due toits active development of contracting and co-investment (Figure 4.25). This enabled theglobalisation of the market on common principles. Japan’s share fell below 20% in 2022, bywhich time a much more liquid market had developed alongside the initial model oflong-term offtake contracts.
Ultimately, secure and orderly energy transitions will only unfold with countries working
together in a coalition that recognises their shared interests. For producer economies,
effective multi-year programmes and partnership could be designed with the close
involvement of international finance, including multilateral development banks. Increasing
the resilience of major producer economies, particularly as energy transitions gather pace, isa matter of great importance beyond the producers themselves. It is integral to ensuring
192

International Energy Agency | Special Reportsecure energy flows that provide producers with sufficient capital to finance the large-scalechanges required by their economies, while ensuring consumers have a stable supply ofenergy as they make the shift to a net zero emissions future.

bcm

Figure 4.25 ⊳ Global LNG imports by destination
600

Rest of world
Japan

500

4

400
300
200
100
1970

1980

1990

2000

2010

2022
IEA. CC BY 4.0.

Japan played an instrumental role in catalysing the global trade in LNG, before its share ofimports declined from 75% to 20% as the international market became established.

Chapter 4 | Strategic responses of exporters and importers

193

ANNEXES

Annex A
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.

Units
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)
kilotonne (1 tonne x 103)
million tonnes (1 tonne x 106)
gigatonne (1 tonne x 109)

Annex A | Definitions

197

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

Oilbarrelkb/dmb/dmboe/done barrel of crude oil
thousand 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

Convert from:

Multiplier to convert to:
EJ

Gcal

Mtoe

MBtu

EJ

1

2.388 x 108

23.88

9.478 x 10

Gcal

4.1868 x 10-9

1

10-7

Mtoe

4.1868 x 10

107

1

MBtu

1.0551 x 10-90.252

2.52 x 10-8

bcme

0.036

8.60 x 106

0.86

GWh

3.6 x 10-6860

8.6 x 10-5

-2

bcme

GWh

27.78

2.778 x 105

3.968

1.163 x 10-7

1.163 x 10-3

3.968 x 107

1.163

11 6301

2.932 x 10-8

2.931 x 10-4

3.41 x 107

1

9 999

3 412

1 x 10-4

18

Note: There is no generally accepted definition of barrel of oil equivalent (boe); typically the conversion factors
used vary from 7.15 to 7.40 boe per tonne of oil equivalent. Natural gas is attributed a low heating value of
1 MJ per 44.1 kg. Conversions to and from billion 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 of country-specific energy densities. Lower heating values (LHV) are usedthroughout.

Currency conversions
Exchange rates(2022 annual average)

1 US dollar (USD)
equals:British Pound

0.81

Chinese Yuan Renminbi

6.74

Euro

0.95

Indian Rupee

78.60

Japanese Yen

131.50Source: OECD Data (database): Exchange rates (indicator), https://data.oecd.org/conversion/exchangerates.htm, accessed October 2023.

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International Energy Agency | Special ReportDefinitions
Advanced bioenergy: Sustainable fuels produced from wastes, residues and non-food crop
feedstocks (excluding traditional uses of biomass), which are capable of delivering significant
life cycle greenhouse gas emissions savings compared with fossil fuel alternatives and ofminimising adverse sustainability impacts. Advanced bioenergy feedstocks either do notdirectly compete with food and feed crops for agricultural land or are only developed on landpreviously used to produced food crop feedstocks for biofuels.
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 offgrid 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.
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. Excludes
hydrogen produced from bioenergy, including via electricity from a biomass-fired plant, as
well as synthetic fuels made with CO2 feedstock from a biomass source.
Biogas: A mixture of methane, CO2 and small quantities of other gases produced byanaerobic digestion of organic matter in an oxygen-free environment.
Biogases: Include both biogas and biomethane.
Biogasoline: Includes all liquid biofuels (advanced and conventional) used to replacegasoline.
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Biojet kerosene: Kerosene substitute produced from biomass. It includes conversion routes
such as hydroprocessed esters and fatty acids (HEFA) and biomass gasification with FischerTropsch. 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): 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.
Clean energy: In power, clean energy includes: renewable energy sources, nuclear power,
fossil fuels fitted with CCUS, hydrogen and ammonia; 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 use of renewables; electric vehicles; electrification in buildings, industry andinternational marine transport; CCUS in industry and direct air capture. In fuel supply, clean
energy includes low-emissions fuels, direct air capture, and measures to reduce theemissions intensity of fossil fuel production.

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International Energy Agency | Special Report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-criticalminerals-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 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.

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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.
Direct air capture (DAC): A type of CCUS that captures CO2 directly from the atmosphereusing liquid solvents or solid sorbents. It is generally coupled with permanent storage of theCO2 in deep 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 acarbon removal technology, and it is known as direct air capture and storage (DACS).
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.
Electric arc furnace: Furnace that heats material by means of an electric arc. It is used for
scrap-based steel production but also for ferroalloys, aluminium, phosphorus or calcium
carbide.
Electric vehicles (EVs): Electric vehicles comprise of battery electric vehicles (BEV) and plugin hybrid vehicles.
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.
Electrolysis: Process of converting electric energy to chemical energy. Most relevant for theenergy sector is water electrolysis, which splits water molecules into hydrogen and oxygen
molecules. The resulting hydrogen is called electrolytic hydrogen.
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, industrial processes, and fugitive and flaring CO2 from fossil fuel extraction.
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.
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International Energy Agency | Special Report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 secondgeneration 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 process to produce 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, or hydrogen and CO2.
Fossil fuels: Include coal, natural gas and oil.
Gaseous fuels: Include natural gas, biogases, synthetic methane and hydrogen.
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, large-scaleheat pumps, geothermal or solar resources. It may be used for heating or cooling, orconverted into mechanical energy for transport or electricity generation. Commercial heatsold is reported under total final consumption with the fuel inputs allocated under power
generation.
Heavy-duty vehicles (HDVs): Include both medium freight trucks (gross weight 3.5 to
15 tonnes) and heavy freight trucks (gross weight >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.
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Hydropower: Refers to the electricity produced in hydropower projects, with the assumptionof 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).
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.
International aviation bunkers: Include the deliveries of aviation fuels to aircraft forinternational aviation. Fuel 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: Include 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-2022
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): LCOE combines into a single metric all the cost elements
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.
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International Energy Agency | Special ReportLight-duty vehicles (LDVs): Include passenger cars and light commercial vehicles (grossvehicle weight < 3.5 tonnes).
Light industries: Include non-energy-intensive industries: food and tobacco; machinery;mining and quarrying; transportation equipment; textiles; wood harvesting and processing;and construction.
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 make longdistance transport uneconomic. Data on lignite in the World Energy Outlook include peat.
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
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 output from renewable energy technologies, nuclear
power, fossil fuels fitted with CCUS, hydrogen and ammonia.
Low-emissions fuels: Include modern bioenergy, low-emissions hydrogen and low-emissionshydrogen-based fuels.
Low-emissions gases: Include biogas, biomethane, low-emissions hydrogen and lowemissions 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.
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Middle distillates: Include jet fuel, diesel and heating oil.
Mini-grids: Small electric grid systems, not connected to main electricity networks, linking a
number of households and/or other consumers.
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.
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 the
traditional use 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 exajoules are on a net calorific basis. The difference
between the net and the gross calorific 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 calorific value).
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.
Near zero emissions capable material production capacity: Capacity that will achieve
substantial emissions reductions from the start – but fall short of near zero emissions
material production initially (see following definition) – with plans to continue reducing
emissions over time such that they could later achieve near zero emissions production
without additional capital investment.
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International Energy Agency | Special ReportNear zero emissions material production: For steel and cement, production that achieves
the near zero GHG emissions intensity thresholds as defined in Achieving Net Zero Heavy
Industry Sectors in G7 Members (IEA, 2022). The thresholds depend on the scrap share ofmetallic input for steel and the clinker-to-cement ratio for cement. For other energyintensive commodities such as aluminium, fertilisers and plastics, production that achieves
reductions in emissions intensity equivalent to the considerations for near zero emissions
steel and cement.
Near zero emissions material production capacity: Capacity that when operational willachieve near zero emissions material production from the start.
Network gases: Include natural gas, biomethane, synthetic methane and hydrogen blended
in a gas network.
Non-energy-intensive industries: See other industry.
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.
Nuclear power: Refers to the electricity produced by a nuclear reactor, assuming an average
conversion efficiency of 33%.
Off-grid systems: Mini-grids and stand-alone systems for individual households or groups ofconsumers not connected to a main grid.
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.
It is sometimes referred to as non-energy-intensive industry.
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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/minicoaches.
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 electricity generation and heat production from all sources ofelectricity, including electricity-only power plants, heat plants, and combined heat andpower plants. Both main activity producer plants and small plants that produce fuel for theirown use (auto-producers) are included.
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.
Process heat: The use of thermal energy to produce, treat or alter manufactured goods.
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.
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: Include 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.
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International Energy Agency | Special ReportServices: A component of the buildings sector. It represents energy used in commercial
facilities, e.g. offices, shops, hotels, restaurants, and in institutional 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 mode 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 both solar photovoltaics and concentrating solar power.
Solar home systems (SHS): Small-scale photovoltaic and battery stand-alone systems, i.e.
with capacity higher than 10 watt peak (Wp) supplying electricity for single households orsmall 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.
Solar photovoltaics (PV): Electricity produced from solar photovoltaic cells including utilityscale and small-scale installations.
Solid bioenergy: Includes charcoal, fuelwood, dung, agricultural residues, wood waste andother solid biogenic wastes.
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. Standalone systems include solar home systems, small wind or hydro generators, diesel or gasoline
generators. 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.
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Synthetic oil: Synthetic oil produced through Fischer-Tropsch conversion or methanol
synthesis. It includes oil products from CTL and GTL, and non-ammonia low-emissions liquidhydrogen-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 nonenergy use). It excludes international marine and aviation bunkers, except at world level
where it is included in the transport sector.
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.
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.
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 weight< 3.5 tonnes); medium freight trucks (gross vehicle weight 3.5-15 tonnes); and heavy freighttrucks (gross vehicle weight > 15 tonnes).
Unabated fossil fuel use: Consumption 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 for
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International Energy Agency | Special Reportmost 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.
Zero emissions vehicles (ZEVs): Vehicles that are capable of operating without tailpipe CO2
emissions (battery electric and fuel cell vehicles).

Regional and country groupings
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, The People’s Republic of China (China), Sri Lanka, Chinese Taipei, and other Asia
Pacific countries and territories.3
Caspian: Armenia, Azerbaijan, Georgia, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan andUzbekistan.
Central and South America: Argentina, Plurinational State of Bolivia (Bolivia), Bolivarian
Republic of Venezuela (Venezuela), Brazil, Chile, Colombia, Costa Rica, Cuba, Curaçao,
Dominican Republic, Ecuador, El Salvador, Guatemala, Guyana, Haiti, Honduras, Jamaica,
Nicaragua, Panama, Paraguay, Peru, Suriname, Trinidad and Tobago, Uruguay and otherCentral and South American countries and territories.4
China: Includes (The People's Republic of) China and Hong Kong, China.
Developing Asia: Asia Pacific regional grouping excluding Australia, Japan, Korea and
New Zealand.
Emerging market and developing economies: All other countries not included in theadvanced economies regional grouping.
Annex A | Definitions

211

AFigure C.1 ⊳Main country groupings

Note: This map is without prejudice to the status of or sovereignty over any territory, to the delimitation ofinternational frontiers and boundaries and to the name of any territory, city or area.

Eurasia: Caspian regional grouping and the Russian Federation (Russia).
Europe: European Union regional grouping and Albania, Belarus, Bosnia and Herzegovina,
Gibraltar, Iceland, Israel5, Kosovo, Montenegro, North Macedonia, Norway, Republic ofMoldova, Serbia, Switzerland, 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 and the Caribbean (LAC): 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.

212

International Energy Agency | Special ReportOECD (Organisation for Economic Co-operation and Development): Australia, Austria,
Belgium, Canada, Chile, Colombia, Costa Rica, Czech Republic, 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, Bolivarian
Republic of Venezuela (Venezuela), Equatorial Guinea, Gabon, Iraq, Islamic Republic of Iran
(Iran), Kuwait, Libya, Nigeria, Republic of the Congo (Congo), Saudi Arabia and United ArabEmirates.
OPEC+: OPEC grouping plus Azerbaijan, Bahrain, Brunei Darussalam, Kazakhstan, Malaysia,
Mexico, Oman, Russian Federation (Russia), South Sudan and Sudan.
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).
Sub-Saharan Africa: Angola, Benin, Botswana, Cameroon, Côte d’Ivoire, Democratic Republicof the Congo, Equatorial Guinea, Eritrea, Ethiopia, Gabon, Ghana, Kenya, Kingdom ofEswatini, Madagascar, Mauritius, Mozambique, Namibia, Niger, Nigeria, Republic of theCongo (Congo), Rwanda, Senegal, South Africa, South Sudan, Sudan, United Republic of
Tanzania (Tanzania), Togo, Uganda, Zambia, Zimbabwe and other African countries andterritories.6

Country notes
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”.
1

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.

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, Tonga and Vanuatu.
3

4 Individual data are not available and are estimated in aggregate for: Anguilla, Antigua and Barbuda, Aruba,
Bahamas, Barbados, Belize, Bermuda, Bonaire, Sint Eustatius and Saba, British Virgin Islands, Cayman Islands,
Dominica, Falkland Islands (Malvinas), Grenada, Montserrat, Saint Kitts and Nevis, Saint Lucia, Saint Pierre andMiquelon, Saint Vincent and Grenadines, Saint Maarten (Dutch part), 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, Gambia, Guinea, Guinea-Bissau, Lesotho, Liberia, Malawi,
Mali, Mauritania, Sao Tome and Principe, Seychelles, Sierra Leone and Somalia.

Annex A | Definitions

213

AAbbreviations and acronyms
AC
AFOLU
APEC
APS
ASEAN
BECCS
BEV
CAAGR
CAFE
CBM
CCGT
CCUS
CDR
CEM
CH4
CHP
CNG
CO
CO2
CO2-eq
COP
CSP
CTG
CTL
DAC
DACS
DC
DER
DFI
DRI
DSI
DSO
DSR
EHOB
EMDE
EOR
EPA
ESG
ETS
EU
EU ETSEV
214

alternating 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
Conference of Parties (UNFCCC)
concentrating solar powercoal-to-gas
coal-to-liquids
direct air capture
direct air capture and storage
direct current
distributed energy resources
development finance institutions
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 governanceemissions trading system
European Union
European Union Emissions Trading Systemelectric vehicle
International Energy Agency | Special Report

FAO
FCEV
FDI
FID
FiT
FOB
GEC
GDP
GHG
GTL
H2
HDV
HEFA
HFO
HVDC
IAEA
ICE
ICT
IEA
IGCC
IIASA
IMF
IMO
IOC
IPCC
IPT
LCOE
LCV
LDV
LED
LNG
LPG
LULUCF
MEPS
MER
NDC
NEA
NGLs
NGV
NOC
NPV
NOX
N2O
NZE

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-liquidshydrogenheavy-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 Change
independent power transmission
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 Contribution
Nuclear Energy Agency (an agency within the OECD)natural gas liquids
natural gas vehicle
national oil company
net present value
nitrogen oxides
nitrous oxide
Net Zero Emissions by 2050 Scenario

Annex A | Definitions

A
215

OECD
OPEC
PHEV
PLDV
PM
PM2.5
PPA
PPP
PV
R&D
RD&D
SAF
SDG
SHS
SME
SO2
STEPS
T&D
TES
TFC
TFEC
TPA
TPED
TSO
UAE
UN
UNDP
UNEP
UNFCCCUSUSGSVALCOE
VRE
WACC
WEO
WHO
ZEV
ZCRB

216

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 aviation fuelSustainable Development Goals (United Nations)
solar home systems
small and medium enterprises
sulphur dioxide
Stated Policies Scenariotransmission and distribution
total energy supply
total final consumption
total final energy consumption
tonne per annum
total primary energy demandtransmission system operator
United Arab Emirates
United Nations
United Nations Development Programme
United Nations Environment Programme
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

International Energy Agency | Special ReportAnnex B
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222

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The Oil and Gas Industry in Net Zero Transitions
World Energy Outlook Special Report
The global oil and gas industry encompasses a large anddiverse range of players: from small, specialised operators
to huge national oil companies. These producers facepivotal choices about their role in the global energy systemamid a worsening climate crisis fuelled in large part by theircore products.
The Oil and Gas Industry in Net Zero Transitions analyses theimplications and opportunities for the industry that would
arise from stronger international efforts to reach energy andclimate targets.
It also examines how transitions increase the likelihood ofboom and bust cycles for oil and gas producer economies.
It highlights strategies for producer economies that could
complement broader reforms to build macroeconomic
stability and the role of international partners to support
this process.
The report sets out a fair and feasible way forward in which
oil and gas companies and producer economies take a real
stake in the clean energy economy while helping the world
avoid the most severe impacts of climate change.