Electricity Market Report 2023

Electricity Market

Report 2023

The IEA examines the full spectrum of energy

issues including oil, gas and coal supply and

demand, renewable energy technologies,

electricity markets, energy efficiency, access to

energy, demand side management and much

more. Through its work, the IEA advocates

policies that will enhance the reliability,

affordability and sustainability of energy in its 31

member countries, 11 association countries and

beyond.

This publication and any map included herein are

without prejudice to the status of or sovereignty

over any territory, to the delimitation of

international frontiers and boundaries and to the

name of any territory, city or area.

Source: IEA.

International Energy Agency

Website: www.iea.org

IEA member countries:

Australia

Austria

Belgium

Canada

Czech Republic

Denmark

Estonia

Finland

France

Germany

Greece

Hungary

Ireland

Italy

Japan

Korea

Lithuania

Luxembourg

Mexico

Netherlands

New Zealand

Norway

Poland

Portugal

Slovak Republic

INTERNATIONAL ENERGY AGENCY

Spain

Sweden

Switzerland

Republic of Türkiye

United Kingdom

United States

The European Commission

also participates in the work

of the IEA

IEA association countries:

Argentina

Brazil

China

Egypt

India

Indonesia

Morocco

Singapore

South Africa

Thailand

Ukraine

Electricity Market Report 2023

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Abstract

IEA. CC BY 4.0.

Abstract

Electricity is central to many parts of life in modern societies and will

become even more so as its role in transport and heating expands

through technologies such as electric vehicles and heat pumps.

Power generation is currently the largest source of carbon dioxide

(CO

) emissions globally, but it is also the sector that is leading the

transition to net zero emissions through the rapid ramping up of

renewables such as solar and wind. At the same time, the current

global energy crisis has placed electricity security and affordability

high on the political agenda in many countries.

The International Energy Agency’s Electricity Market Report 2023

offers a deep analysis of recent policies, trends and market

developments. It also provides forecasts through 2025 for electricity

demand, supply and CO

emissions – with a detailed study of the

evolving generation mix. This year’s report contains a

comprehensive analysis of developments in Europe, which faced a

variety of energy crises in 2022. The Asia Pacific region also

receives special focus, with its fast-growing electricity demand and

accelerating clean energy deployment.

The IEA’s Electricity Market Report has been published since 2020.

Its relevance goes beyond energy and climate issues, since

electricity supply impacts economies, regional development, the

budgets of businesses and households, and many other areas. It is

indispensable reading for anyone interested in the multifaceted

importance of energy in our economies and societies today.

Electricity Market Report 2023

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Table of contents

IEA. CC BY 4.0.

Table of contents

Executive summary ......................................................................................... 5

Global overview ............................................................................................. 11

Demand ........................................................................................................ 12

Supply .......................................................................................................... 20

Emissions ..................................................................................................... 31

Wholesale prices .......................................................................................... 34

Carbon pricing trends ................................................................................... 38

Regional perspectives................................................................................... 41

Asia Pacific ................................................................................................... 42

Americas ...................................................................................................... 63

Europe .......................................................................................................... 74

Eurasia ......................................................................................................... 93

Middle East .................................................................................................. 99

Africa .......................................................................................................... 108

General annex .............................................................................................. 118

Electricity Market Report 2023

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Executive summary

IEA. CC BY 4.0.

Executive summary

Electricity Market Report 2023

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Executive summary

IEA. CC BY 4.0.

Executive Summary

Global electricity demand growth slowed only slightly in 2022 despite energy crisis headwinds

World electricity demand remained resilient in 2022 amid the

global energy crisis triggered by Russia’s invasion of Ukraine.

Demand rose by almost 2% compared with the 2.4% average

growth rate seen over the period 2015-2019. The electrification of

the transport and heating sectors continued to accelerate globally,

with record numbers of electric vehicles and heat pumps sold in

2022 contributing to growth. Nevertheless, economies around the

world, in the midst of recovering from the impacts of Covid-19, were

battered by record-high energy prices. Soaring prices for energy

commodities, including natural gas and coal, sharply escalated

power generation costs and contributed to a rapid rise in inflation.

Economic slowdowns and high electricity prices stifled electricity

demand growth in most regions around the world.

Electricity consumption in the European Union recorded a

sharp 3.5% decline year-on-year (y-o-y) in 2022 as the region was

particularly hard hit by high energy prices, which led to significant

demand destruction among industrial consumers. Exceptionally mild

winter added further downward pressure on electricity consumption.

This was the EU’s second largest percentage decrease in electricity

demand since the global financial crisis in 2009 – with the largest

being the exceptional contraction due to the Covid-19 shock in

2020.

Electricity demand in India and the United States rose, while

Covid restrictions affected China’s growth. China’s zero-Covid

policy weighed heavily on its economic activity in 2022, and a

degree of uncertainty remains over the pace of its electricity

demand growth. We currently estimate it to be 2.6% in 2022,

substantially below its pre-pandemic average of over 5% in the

2015-2019 period. Further data expected in due course will provide

greater clarity on trends in China in 2022, which could also have

implications for the global picture. Electricity demand in India rose

by a strong 8.4% in 2022, due to a combination of its robust post-

pandemic economic recovery and exceptionally high summer

temperatures. The United States recorded a significant 2.6% y-o-y

demand increase in 2022, driven by economic activity and higher

residential use to meet both heating and cooling needs amid hotter

summer weather and a colder-than-normal winter.

Low-emissions sources are set to cover almost all the

growth in global electricity demand by 2025

Renewables and nuclear energy will dominate the growth of

global electricity supply over the next three years, together

meeting on average more than 90% of the additional demand.

China accounts for more than 45% of the growth in renewable

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IEA. CC BY 4.0.

Executive summary

generation in the period 2023-2025, followed by the EU with 15%.

The substantial growth of renewables will need to be accompanied

by accelerated investments in grids and flexibility for their

successful integration into the power systems. The increase in

nuclear output results from an expected recovery in French nuclear

generation as more plants complete their scheduled maintenance,

and from new plants starting operations, largely in Asia.

Global electricity generation from both natural gas and coal is

expected to remain broadly flat between 2022 and 2025. While

gas-fired generation in the European Union is forecast to decline,

significant growth in the Middle East will partly offset this decrease.

Similarly, drops in coal-fired generation in Europe and the Americas

will be matched by a rise in Asia Pacific. However, the trends in

fossil-fired generation remain subject to developments in the global

economy, weather events, fuel prices and government policies.

Developments in China, where more than half of the world’s coal-

fired generation occurs, will remain a key factor.

China’s share of global electricity consumption is forecast to

rise to one-third by 2025, compared with one-quarter in 2015.

Over the next three years, more than 70% of the growth in global

electricity demand is set to come from China, India and Southeast

Asia combined. Emerging and developing economies’ growth is

accompanied by a corresponding rise in demand for electricity. At

the same time, advanced economies are pushing for electrification

to decarbonise their transportation, heating and industrial sectors.

As a result, global electricity demand is expected to grow at a much

faster pace of 3% per year over the 2023-2025 period compared

with the 2022 growth rate. The total increase in global electricity

demand of about 2 500 terawatt-hours (TWh) out to 2025 is more

than double Japan's current annual electricity consumption.

Nevertheless, uncertainties exist regarding the growth of electricity

demand in China. While the country recently eased its stringent

Covid restrictions in early December 2022, the full extent of the

economic impacts remain unclear.

After reaching an all-time high in 2022, power

generation emissions are set to plateau through 2025

Global CO

emissions from electricity generation grew in 2022

at a rate similar to the 2016-2019 average. Their increase of 1.3%

in 2022 is a significant slowdown from the staggering 6% rise in

2021, which was driven by the rapid economic recovery from the

Covid shock. Nonetheless, electricity generation-related CO

emissions reached a record high in 2022.

The share of renewables in the global power generation mix is

forecast to rise from 29% in 2022 to 35% in 2025. As renewables

expand, the shares of coal- and gas-fired generation are set to fall.

As a result, emissions of global power generation will plateau to

2025 and its CO

intensity will further decline in the coming years.

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IEA. CC BY 4.0.

Executive summary

The European Union saw gas-fired generation increase

during a turbulent 2022

Due to historic drought conditions, hydropower generation in

Europe was particularly low in 2022. Italy saw a drop in

hydropower generation of more than 30% compared with its 2017-

2021 average, followed closely by Spain. Similarly, France recorded

a 20% decline in its hydro output compared with the previous five-

year average.

Nuclear generation in the European Union was 17% lower in

2022 than in 2021 due to closures and unavailabilities. Plant

closures in Germany and Belgium reduced the available nuclear

capacity in 2022. At the same time, France faced record-low nuclear

availability due to ongoing maintenance work and other challenges

in its nuclear fleet. The constrained nuclear output and low

hydropower supply in Europe – combined with reduced

dispatchable capacity due to previous retirements of thermal

generation plants – put additional pressure on remaining

dispatchable capacities to meet demand. As a result, although

variable renewable generation grew and record-high gas prices

supported fuel-switching from gas to coal, gas-fired generation grew

in 2022 by 2% in the European Union.

These factors have also

contributed to significant changes in the traditional import-export

structure of electricity in Europe: France became a net importer and

the United Kingdom a net exporter for the first time in decades.

In order to increase the security of electricity supply, reserve

capacities of conventional power generation have been

brought back in Europe for the 2022-2023 and 2023-2024

winters. Similarly, some plants that were previously set to be

decommissioned were also extended. Germany had the highest

share of such plants in Europe, having delayed the planned

shutdown of its three remaining nuclear reactors, as well as

delaying the closure or reactivating fossil-fired plants that make up

15% of its current fossil-fired generation capacity. An increased risk

of power outages was reported in some European countries during

several weeks of cold weather combined with lower-than-average

hydro and nuclear output. Security of supply was achieved through

successful short-term planning and management.

While the CO

intensity of global power generation

decreased in 2022, it increased in the European Union

After 2021, 2022 marks the highest percentage growth in CO

emissions of EU power generation since the oil crises of the

1970s, recording a 4.5% year-on-year growth. Excluding the 2021

post-pandemic rebound, the European Union also saw in 2022 the

highest absolute growth in power generation emissions since 2003.

This was mainly due to a rise in coal-fired generation of more than

6% in stark contrast to the almost 8% average annual rate of

decline in coal-fired generation over the pre-pandemic period of

2015-2019.

The setback in the European Union will be temporary, however,

as power generation emissions are expected to decrease on

average by about 10% annually through 2025. Both coal- and gas-

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Executive summary

fired generation are expected to see sharp falls, with coal declining

by 10% and gas by almost 12% annually on average over the

outlook period as renewables ramp up and nuclear generation

recovers.

Electricity prices remain high in many regions, with risks

of tight supply in Europe next winter

The increase in wholesale electricity prices was most

pronounced in Europe in 2022, where they were, on average,

more than twice as high as in 2021. The exceptionally mild winter so

far in 2022/23 in Europe has helped temper wholesale electricity

prices, but they remain high compared with recent years. Elevated

futures prices for winter 2023/24 reflect the uncertainties regarding

gas supply in Europe over the coming year.

In the European Union, a wide range of responses to the

energy crisis have been observed. In order to reduce reliance on

fossil fuels and to increase resilience to price shocks, the European

Commission published its REPowerEU plan in May 2022 to

accelerate clean energy deployment. At the same time, discussions

about electricity market design gained momentum due to soaring

wholesale prices, and the Commission launched a consultation on

market design reform. To dampen the effects of high electricity

prices on consumers, many countries introduced measures such as

the regulation of wholesale and retail prices; revenue caps on infra-

marginal technologies such as renewables, nuclear and coal-

plants; reductions of energy taxes and VAT; and direct subsidies.

While such market interventions can help mitigate the impacts of the

energy crisis, the potential creation of uncertainty in the investment

landscape needs to be minimised to ensure that responses to the

crisis do not come at the expense of much-needed investment.

Affordability will continue to be a challenge for emerging

and developing economies

Globally, higher electricity generation costs in 2022 were

driven by surging energy commodity prices. While the cost

increases were more moderate in countries with regulated tariffs

and long-term fuel supply agreements (oil-indexed LNG, long-term

contracts or fuel supply contracts), regions dependent on short-term

markets for fuel procurement were severely affected. In particular,

record-high LNG prices led to difficulties for South Asian countries

trying to procure gas for the power sector, which contributed to

blackouts and rationing of electricity in the region. If prices of energy

commodities remain elevated, fuel procurement will continue to be a

serious issue for emerging and developing economies.

Nuclear power is gathering pace in Asia, curbing the

intensity of power generation

The energy crisis has renewed interest in the role of nuclear

power in contributing to energy security and reducing the CO

intensity of power generation. In Europe and the United States,

discussions on the future role of nuclear in the energy mix have

resurfaced. At the same time, other parts of the world are already

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Executive summary

seeing an accelerated deployment of nuclear plants. As a result,

global nuclear power generation is set to grow on average by

almost 4% over 2023-2025, a significantly higher growth rate than

the 2% over 2015-2019. This means that in every year to 2025,

about 100 TWh of additional electricity is set to be produced by

nuclear power, the equivalent of about one-eighth of US nuclear

power generation today.

More than half of the growth in global nuclear generation to

2025 comes from just four countries: China, India, Japan and

Korea. Among these countries, while China leads in terms of

absolute growth from 2022 to 2025 (+58 TWh), India is set to have

the highest percentage growth (+81%), followed by Japan. This

results from the Japanese government’s push to ramp up nuclear

generation in order to reduce reliance on gas imports and

strengthen energy security. Outside Asia, the French nuclear fleet

provides more than one-third of the absolute growth in global

nuclear generation to 2025 as it gradually recovers.

Extreme weather events highlight the need for

increased security of supply and resilience

In a world where both the demand and supply of electricity are

becoming increasingly weather-dependent, electricity security

requires increased attention. Along with the high cost of electricity

generation, the world’s power systems also faced challenges from

extreme weather events in 2022. In addition to the drought in

Europe, there were heatwaves in India, where the hottest March in

over a century was recorded, resulting in the country’s highest ever

peak in power demand. Similarly, central and eastern China were

hit by heatwaves and drought, which caused demand for air

conditioning to surge amid reduced hydropower generation in

Sichuan. The United States saw severe winter storms in December,

triggering massive power outages. Mitigating the impacts of climate

change requires faster decarbonisation and accelerated deployment

of clean energy technologies. At the same time, as the clean energy

transition gathers pace, the impact of weather events on electricity

demand will intensify due to the increased electrification of heating,

while the share of weather-dependent renewables will continue to

grow in the generation mix. In such a world, increasing the flexibility

of the power systems while ensuring security of supply and

resilience will be crucial.

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Global overview

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IEA. CC BY 4.0.

Global overview

Demand

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IEA. CC BY 4.0.

Global overview

Global electricity demand growth eased in 2022, but is set to accelerate from 2023, led by Asia

The energy crisis sparked by the Russian Federation’s (hereafter

“Russia”) invasion of Ukraine has been characterised by record-high

commodity prices, weaker economic growth and high inflation.

Higher fuel prices increased the cost of electricity generation around

the world, putting downward pressure on consumption in many

regions. Despite the worsening crisis, global electricity demand

remained relatively resilient, growing by almost 2% in 2022.

By 2025, for the first time in history, Asia will account for half of the

world’s electricity consumption and one-third of global electricity will

be consumed in China. Over the outlook period, global electricity

demand is set to grow at an accelerated pace, by an annualised

3%, as electricity consumption increases in emerging markets and

developing economies (EMDEs), led by the People’s Republic of

China (hereafter “China”), India and Southeast Asia.

As the energy crisis abates, global electricity demand growth is set

to rise from 2.6% in 2023 to an average 3.2% in 2024-2025. This

stronger growth is well above the pre-pandemic rate of 2.4%

observed in the 2015-2019 period. Indeed, by 2025 demand will

increase by 2 500 TWh from 2022 levels, which means that over the

next three years the electricity consumption added each year is

roughly equivalent to that of the United Kingdom and Germany

combined. More than half of the increase will come from China. The

remaining growth will largely take place in India and Southeast Asia.

In China, electricity demand growth was subdued on weaker

economic activity in 2022, rising at an estimated 2.6%, and

significantly below its trend of 5.4% in 2015-2019. China is by far

the world’s largest electricity consumer at 31% of global demand in

2022. For 2023-2025 we expect an average annual growth of 5.2%.

In India, the robust post-pandemic recovery continued to support

strong electricity demand of over 8.4% in 2022, which was

substantially higher than the average annual growth rate of 5.3%

seen in the 2015-2019 period. The peak summer season also

arrived early in 2022, resulting in the hottest March in over a

century. Electricity demand from March to July was 12% higher than

the same period in 2021. For the 2023-2025 period, we expect

slightly slower growth, averaging 5.6% per year.

Electricity demand in the European Union (EU) fell 3.5% in 2022,

with spiking electricity prices, demand destruction in electricity-

intensive industries, energy saving measures and a mild winter all

contributing to the decline. We expect EU demand to grow by

around 1.4% on average in 2023-2025.

In the United States, electricity demand rose by 2.6% in 2022,

surpassing pre-Covid levels. But an expected economic slowdown

in 2023 is expected to lead to a decline of about 0.6%, before

returning to growth of 1.2% in 2024 and 1.3% in 2025.

In Africa, electricity demand rose by 1.5% in 2022, with growth

tempered by both lofty energy prices and high inflation rates. Our

2023-2025 outlook for the region shows much stronger growth of an

average 4.1%, led by a post-crisis economic recovery.

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Global overview

Out to 2025, more than 70% of the growth in global electricity demand is set to come from

China, India and Southeast Asia combined

Year-on-year relative global change in electricity demand,

2015-2025

IEA. CC BY 4.0.

Year-on-year change in electricity demand by region, 2019-2025

IEA. CC BY 4.0.

-1%

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Electricity demand growth

Historical demand

Updated forecast

Previous forecast (July 2022)

- 500

- 300

- 100

100

300

500

700

900

1 100

1 300

1 500

2019 2020 2021 2022 2023 2024 2025

TWh

China India Southeast Asia

United States European Union Others

Net change

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IEA. CC BY 4.0.

Global overview

By 2025, Asia will account for half of the world’s electricity consumption and one-third of global

electricity will be consumed in China

Evolution of global electricity demand by region (left) and regional shares (right), 1990-2025

IEA. CC BY 4.0.

5 000

10 000

15 000

20 000

25 000

30 000

35 000

1990 1995 2000 2005 2010 2015 2020 2025

TWh

China Other Asia Africa Rest of the world United States & OECD Europe

10%

25%

33%

13%

16%

18%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1990 2000 2015 2025

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IEA. CC BY 4.0.

Global overview

Global economic growth shows signs of resilience but continues to face challenges

The global economy continues to face myriad challenges in the

wake of Russia’s war in Ukraine and the rise in central bank rates

aimed at combating persistent inflation. The International Monetary

Fund’s (IMF) January 2023 World Economic Outlook

ovides

forecasts up to 2024 and shows global GDP growth of 6.2% in 2021

contracting to 3.4% in 2022 and easing to 2.9% in 2023. By 2024,

growth inches higher again, to 3.1%. The latest forecast represents

downward revisions of 0.2%, 0.7% and 0.3%, respectively,

compared with the

April 2022 forecast, w

hich underpinned our July

update. The January 2023 outlook, however, was slightly more

optimistic than the previous October 2022

forecast f

or the short

term, with global GDP growth for both 2022 and 2023 raised by

0.2 percent points. The October outlook, which provided projections

up to 2027, forecast a global GDP growth rate of 3.4% in 2025.

For the United States,

the IMF revised its latest GDP estimate to

2% for 2022 from 3.7% in April and its outlook to 1.4% from 2.3%

for 2023. Growth is forecast at a slower 1% in 2024. The contracting

trend reflects persistent and broadening inflation pressures and

higher interest rates that will continue to temper purchasing power.

2025 growth from the October outlook is 1.8%.

For the Euro area, GDP growth is estimated in the January outlook

at 3.5% for 2022 before plummeting to just 0.7% in 2023 and then

recovering to 1.6% in 2024. The latest forecast shows a sharp

downward revision from the April estimate of 2.3% for 2023. The

weaker outlook largely reflects the spillover effects from the war in

Ukraine and rate hikes from the European Central Bank, which are

partially offset by lower wholesale energy prices and support from

energy price controls. For 2025, a growth of 1.9% was forecast in

the October outlook.

Under pressure from its zero-Covid policy, China’s economy slowed

from the pre-pandemic average growth of 6.7% between 2015-2019

to 3% in 2022. However, the country’s sudden easing of its stringent

pandemic restrictions prompted an upward revision to 5.2% for

2023, up three percentage points from the October projections but

similar to its 5.1% estimate in April. Growth is forecast to slow to

4.5% in 2024. The October forecast estimated growth of 4.6% for

2025.

The GDP growth for India is estimated at 6.8% for 2022.The

outlook was revised downward in January to 6.1% from 6.9% for

2023, largely due to slow economic growth in its trading partner

countries. GDP growth for 2024 was unchanged at 6.8%. The 2025

forecast from the previous October outlook is 6.8%.

Sub-Saharan Africa’s GDP growth is estimated to ease from 4.7%

in 2021 to 3.8% in 2022, due to higher inflation and slower-than-

expected progress on poverty reduction. However, economic growth

will speed up from 3.8% in 2023 to above 4% in 2024 and 2025.

The IMF expects Latin America and the Caribbean’s GDP to grow

by 3.9% in 2022, 1.8% in 2023 and 2.1% in 2024. October forecast

for 2025 was 2.5%.

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IEA. CC BY 4.0.

Global overview

The war in Ukraine, energy crisis and persistent inflation suppress the economic outlook

Gross domestic product growth assumptions by country and region, 2022-2025

Notes: The bars represent annual changes in GDP relative to the previous year. The hollow lines show the previous April 2022 forecast. 2022-2024 values are from the January 2023

World Economic Outlook Update of International Monetary Fund (IMF). 2025 values are from IMF’s October 2022 outlook.

Sources: Based on International Monetary Fund (2023), World Economic Outlook October 2022 Database, World Economic Outlook Update January 2023

, 1 F

ebruary 2023.

-2%

-1%

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

2022

2023

2024

2025

United

States

Euro area United

Kingdom

Japan China India Brazil South Africa

World Advanced economies Emerging and developing economies

Real GDP, annual change

Updated forecast (IMF October 2022, January 2023) Previous forecast (IMF April 2022)

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Global overview

Industrial electricity demand plummeted to historic lows in multiple countries in 2022

In 2021, many countries started to gradually phase out Covid-19

public policy measures and return to more normal economic activity.

However, some economies (e.g. China) still imposed lockdowns in

2022, which had an impact on both residential and industrial

electricity consumption. Equally, persistently high electricity prices

continued to add downward pressure on consumption, particularly in

the residential and industrial sectors.

Comparing the first three quarters of the years, both the

United Kingdom and Spain experienced the lowest industrial

electricity consumption in over 20 years in 2022. Spain saw a

decrease of more than 10% compared to 2019, while the

United Kingdom posted a drop of almost 15% in 2022 versus 2019.

Spain’s electricity-intensive manufacturing activity was especially

hard hit by the rise in prices. The country’s industrial electricity

consumption posted a similar y-o-y decline in 2022 as it did in 2020

when severe Covid-related lockdowns led to substantial demand

destruction. Of the countries surveyed, the United Kingdom saw the

sharpest rise in average wholesale electricity prices. Spain followed

with the second highest level, despite the June 2022

implementation of the Iberian exception, a cap on wholesale gas

prices adopted to reduce the cost of electricity.

In the United Kingdom and Spain, as elsewhere, residents spent

more time at home during widespread Covid-19 lockdowns in 2021,

which led to higher residential electricity consumption that was well

above the subsequent 2022 levels when pandemic restrictions were

eased. Although formal Covid restrictions were lifted in the

United Kingdom in July 2021, many employees continued to

telework through the end of the year, which was less the case in

2022. In addition to the surge in prices amid the energy crisis, a

return to more normal work patterns and warmer temperatures

weighed heavily on UK residential consumption in 2022.

China’s

zero-Covid policy in 2022 boosted residential electricity

demand while growth in the industrial sector was tempered by

weaker economic activity. Residential power consumption has been

steadily increasing as the electrification of homes rapidly expands,

with a growing share of electricity used in cooling, heating, cooking

and appliances. The country’s house-bound population propelled

residential electricity demand up by a sharp 13.5% in 2022.

By contrast, China’s strict pandemic restrictions and lockdowns

disrupted the country’s economic activity. As a result, electricity

demand in the industrial sector was up a modest 1.7%. Coal supply

shortages also caused power restrictions and outages in industrial

hubs such as in Northeast China and the provinces of Guangdong

and Hunan, further contributing to the slowdown.

In the United States, residential electricity consumption saw a

similar y-o-y growth in 2022 as in the previous two years. Weaker

industrial electricity demand growth mainly reflected the slowdown

in the economy.

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Global overview

The United Kingdom and Spain saw a decline in industrial electricity consumption in 2022

Year-on-year change in sectoral electricity consumption in selected large economies, 2019-2022

Note: The analysis is based on data for the first three quarters of 2019-2022.

Sources: IEA analysis using data from the China Electricity Council (China) (2023), U.S. Energy Information Administration (United States) (2023), GOV.UK

(

United Kingdom) (2023),

Red Eléctrica (Spain) (2023), 31 January 2023.

-20%

-10%

10%

20%

2019

2020

2021

2022

2019

2020

2021

2022

2019

2020

2021

2022

2019

2020

2021

2022

United States United

Kingdom

China Spain

Residential

-20%

-10%

10%

20%

2019

2020

2021

2022

2019

2020

2021

2022

2019

2020

2021

2022

2019

2020

2021

2022

United States United

Kingdom

China Spain

Industrial

Electricity Market Report 2023

AGE | 20

IEA. CC BY 4.0.

Global overview

Supply

Electricity Market Report 2023

AGE | 21

IEA. CC BY 4.0.

Global overview

Low-carbon sources set to cover almost all the growth in global electricity demand by 2025

Power systems faced challenges in multiple regions in 2022 due to

extreme weather events. Heatwaves and droughts strained the

supply situation in both China and India. A historic drought in

Europe resulted in low hydropower output, putting increased

pressure on dispatchable capacities amid record-low nuclear

generation in France. In the United States, winter storms caused

widespread power outages. These extreme events reinforce the

urgent need to increase the flexibility of the power system and

enhance security of electricity supply to better cope with weather-

related contingencies.

In 2022, the surge in fossil fuel prices following Russia’s invasion of

Ukraine also compounded the supply situation, especially for gas.

The relatively higher increase in natural gas and LNG prices

prompted a wave of fuel switching in the world to coal for use in

power generation. Global coal-fired generation rose by 1.5% in

2022, with the largest absolute increases in the Asia Pacific region.

Coal-fired generation also rose significantly in the European Union

amid low hydro and nuclear output. However, 2022 is likely to be an

exception and global coal-fired generation is forecast to plateau in

2023-2025, as higher output in the Asia Pacific region is offset by

declines in Europe and the Americas.

Global gas-fired generation remained relatively unchanged in

2022 compared to 2021, as declines in China, India and other

regions were largely offset by a rise in gas-fired output in the

United States. We expect global gas-fired generation to stagnate to

2025 on average, after declining by 3% in 2023, then growing by

1.4% in 2024 and 2% in 2025. Substantial declines in the EU will

partly be offset by significant growth in the Middle East.

Low-carbon generation from renewables and nuclear had diverging

trends in 2022. Renewables saw a year-on-year rise of 5.7%,

making up almost 30% of the generation mix. A surge in renewable

generation in the Asia Pacific region accounted for more than half of

the increase, followed by Americas. By contrast, nuclear output fell

4.3%. This was due to maintenance outages at a large number of

French plants, decommissioning of units in Germany and Belgium,

and reduced Ukrainian output.

Our outlook for 2023 to 2025 shows that renewable power

generation is set to increase more than all other sources combined,

with an annualised growth of over 9%. Renewables will make up

over one-third of the global generation mix by 2025. This trend is

supported by government pledges to increase spending on

renewables as part of economic recovery plans such as the Inflation

Reduction Act in the United States. Nuclear output is expected to

grow by 3.6% per year on average, mainly due to the increase in

Asia Pacific, plus French generation returning to normal. As a result,

low-carbon generation sources – renewables and nuclear together –

are expected to meet on average more than 90% of the additional

electricity demand over the next three years, unless developments

in the global economy and weather events change the trends in

electricity demand and fossil-fired generation.

Electricity Market Report 2023

AGE | 22

IEA. CC BY 4.0.

Global overview

Renewables growth dampens fossil fuel-fired generation from 2023 to 2025

Year-on-year global change in electricity generation by source, 2019-2025

IEA. CC BY 4.0.

- 800

- 600

- 400

- 200

200

400

600

800

1 000

1 200

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

Coal Gas Nuclear Renewables

TWh

Coal Gas Nuclear Renewables Previous forecast (July 2022)

Electricity Market Report 2023

AGE | 23

IEA. CC BY 4.0.

Global overview

Hydropower generation exceptionally low in Europe in 2022 due to the historic drought

The year 2022 was characterised by heatwaves and droughts in

many regions, causing significant declines in hydropower output.

This has underscored the potential impacts of changing climate

patterns on power systems as low hydropower generation puts

additional strain on the remaining dispatchable conventional fleet

and increases the cost of electricity supply. Despite these

uncertainties, our current outlook sees global hydropower supply

grow in 2023 to 2025 on planned capacity expansions.

Europe saw its worst drought in 500 years

in 2022. Italy had a

record drop in hydropower output, posting its lowest hydropower

generation in the last two decades in the February-April 2022

period. Italy’s hydro use was down more than 30% compared to

2017-2021 averages, followed closely by Spain at 29% and France

at 20%. Norway had the

driest 12-month period in 26 years, wit

hydro reservoir levels in September declining to the lowest monthly

output in the last decade. Republic of Türkiye (hereafter “Türkiye”),

which saw its lowest hydro output in 2021 since 2014, had a strong

20% year-on-year rebound in 2022 but remained 5% below its

2017-2021 average.

In C

hina, drought conditions in Sichuan caused a significant drop in

hydropower output during August and September, depressing

annual growth to just below 1% in 2022. In India, despite a record

heatwave in 2022, hydropower generation increased more than

10% above its 2017-2021 average.

Percentage change in hydropower generation in 2022 compared

to the 2017-2021 average in selected countries and regions

IEA. CC BY 4.0.

Source: IEA (2023), Monthly Electricity Statistics, 31

January 2023.

Monthly hydropower generation in OECD Europe, 2017-2022

IEA. CC BY 4.0.

Source: IEA (2023), Monthly Electricity Statistics, 31

January 2023.

-40%

-20%

20%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

TWh

2017-2021 range 2022 2021

Electricity Market Report 2023

AGE | 24

IEA. CC BY 4.0.

Global overview

Significant potential to integrate more renewables in the world’s electricity generation fleet

Global installed capacity of renewables is estimated to have

increased at a faster year-on-year rate of almost 11% in 2022

compared to the average 9% growth seen in the 2017-2021 period.

Variable renewables – wind and solar PV – continued to see strong

growth in combined capacity, up nearly 18%. This corresponds to

about 300 GW in additional installed capacity of variable

renewables, which is greater than the current combined wind and

solar PV cumulative capacity in the United States (approximately

280 GW).

Despite continued growth in 2022, the share of variable renewable

capacity in the total generation fleet remains below 25% in the

world, whereas in Europe it is 35%. In countries with high variable

renewables penetration, variable wind and solar PV can make up

more than 60% of the total generation capacity (e.g. Denmark,

Germany). From a global perspective, there is enough potential for

further capacity expansions of variable renewables in many regions

of the world without facing major system integration bottlenecks.

As the share of variable renewables increases in the generation

fleet, their successful integration into the power system will

increasingly become more challenging. For the balancing of variable

generation, apart from expanding storage capacities and increasing

demand-side flexibility, having sufficient dispatchable capacity will

be crucial. In a decarbonised electricity sector, dispatchable

renewables such as hydro reservoir, geothermal and biomass

plants will be essential for complementing the variable renewables.

Evolution of dispatchable and variable generation capacities in

the world and in Europe, 2012-2022

IEA. CC BY 4.0.

Note: Dispatchable renewable capacity in the figure also includes run-of-river

hydropower plants.

Sources: IEA (2022), World Energy Outlook 2022; IEA (2022), Renewables 2022.

2 000

4 000

6 000

8 000

10 000

2012 2014 2016 2018

2020 2022

Dispatchable conventional Dispatchable renewable

Variable wind Variable solar

World

200

400

600

800

1 000

1 200

1 400

1 600

2012

2014 2016 2018 2020 2022

Europe

Electricity Market Report 2023

AGE | 25

IEA. CC BY 4.0.

Global overview

Affordability of energy remains a challenge for emerging and developing economies

The cost of electricity generation in 2022 increased in many parts of

the world, led by surging energy commodity prices. The rise in

generation costs has been more moderate in places with regulated

tariffs and long-term fuel supply agreements. However, regions

depending on short-term markets for fuel procurement were

severely affected by the steep rise in prices. In particular, record-

high LNG prices created financial hardships for South Asian

countries – most notably Bangladesh and Pakistan – trying to

procure gas for the electricity sector, and significantly contributed to

power outages and rationing.

In Bangladesh, natural gas plays a prominent role in electricity

supply, making up about 80% (2018-2022 average) of the

generation mix. At the same time, Bangladesh relies on LNG

imports to meet fuel demand for power generation and was

therefore hit hard by high LNG prices in 2022. LNG accounts for

approximately 20% of the total natural gas

onsumption of

Bangladesh. Because of a notable decrease in its foreign exchange

reserves, the government stopped buying LNG from the spot

market during the period of July-November 2022, which resulted in

fuel shortages for the power sector.

Following the LNG shortage, Bangladesh faced harsh power

sruptions due to load shedding, where forced supply interventions

were carried out to resolve the imbalance between electricity

demand and supply. During these outages, electricity supply to

areas with industrial production activities

ere given priority to

minimise the impact on the industrial sector. Nevertheless,

industries as well as households faced electricity scarcity and

outages.

Year-on-year monthly change in electricity peak demand and

load shedding, Bangladesh, January-October 2022 vs. 2021

Note: Average load shed is calculated as an average of day peak and evening peak

load shed.

Source: IEA analysis based on Ministry of Information and Broadcasting (Bangladesh)

(2023), Monthly Management Report, 10 January 2023.

250

500

750

1 000

10%

20%

30%

40%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct

MW/day

Relative change in peak demand

Absolute change in average monthly load shed (right axis)

Electricity Market Report 2023

AGE | 26

IEA. CC BY 4.0.

Global overview

Pakistan was also severely affected by the high prices of fossil

fuels due to its strong reliance on fossil fuel imports, as gas (20%)

and coal (30%) play a significant role in its power generation mix. In

2022, electricity production from imported LNG fell by approximately

13% compared to 2021. The reduced LNG imports were attributed

to the country's inability to afford the supplies at the sharply

elevated price levels.

Similarly, in the face of a tight coal market,

imports of high calorific-

value coal declined in 2022, leading to closures of coal-fired power

plants. By contrast, lignite-fired plants experienced a surge in output

during 2022, attributed to an increase in domestic lignite production

coupled with a

fourfold expansion in imports from Afghanistan,

payable in Pakistani rupees, in H1 2022.

Fuel

shortages for the power sector were further exacerbated by the

country’s severe flooding between July and September.

Consequently, a quarter of the total

operational power generation

capacity had to be shut down. This contributed to scarcity of

electricity supply and subsequent power outages.

In 2022, Pakistan’s liquid foreign exchange reserves reached their

lowest level since 2014, leading to the

prioritisation of energy

imports to the detriment of other imports. This caused the shutdown

of some industrial facilities due to a lack of imported raw materials.

For em

erging markets and developing economies, fuel procurement

will continue to be an important issue if energy commodity prices

remain high in the coming years. Increased integration of renewable

energy sources will not only serve to decarbonise the energy sector

but would also reduce reliance on fossil fuel imports and help shield

the economies from external fuel price shocks.

Quarterly evolution of liquid foreign exchange reserves and the

share of payments for oil and LNG imports in the payments for

total imports, Pakistan, 2019-2022

Note: Oil refers to petroleum products and crude oil.

Sources: IEA analysis based on State Bank of Pakistan (2023), Import Payments by

Commodities and Groups, Gold and Foreign Exchange Reserves of Pakistan,

10 January 2023.

10%

20%

30%

40%

20 000

40 000

60 000

80 000

2019 2020 2021 2022

Million USD

Total Liquid FX Reserves

Share of import payments for oil and LNG in total

import payments (right axis)

Electricity Market Report 2023

AGE | 27

IEA. CC BY 4.0.

Global overview

Stationary battery storage capacity additions are speeding up in emerging economies

As the share of variable renewable sources in electricity systems

further increase globally, battery systems are expected to play a

growing role by providing frequency control and operational

reserves as well as for wholesale arbitrage, while helping reduce

grid integration costs. The deployment of stationary battery systems

is speeding up

. In absolute magnitude, the United S

tates, Europe

and China are leading the latest annual capacity additions.

However, based on our 2022 estimates, emerging markets and

developing economies are on the way to catching up.

Compared with 2021, capacity additions in 2022 rose by over 80%

n the United States, almost 100% in China, roughly 35% in Europe,

90% in OECD Pacific (i.e. Japan, Korea, Australia and

New Zealand) and about sixfold in EMDEs, excluding China. In

2022, the largest fleet of cumulative battery systems installed

remains in the United States while China surpassed Europe in

cumulative capacity, reaching a total of 10 500 MW compared to

Europe's 9 400 MW.

The deployment rate in EMDEs gathered pace in 2022, with

capacity additions more than twice as high as the total cumulative

additions in 2015-2021. In China and the United States, over 45%

of the installed cumulative capacity was deployed in 2022. By

contrast, in EMDEs (excluding China), capacity additions in 2022

had a relatively much higher impact, accounting for almost 70% of

the total cumulative capacity in these regions.

Yearly stationary battery system additions by country and region,

2018-2022

Note: 2022 values are estimates.

Sources: IEA calculations based on Clean Horizon (2022), BNEF (2022), China Energy

Storage Alliance (2022).

1 000

2 000

3 000

4 000

5 000

6 000

7 000

2018

2019

2020

2021

2022E

2018

2019

2020

2021

2022E

2018

2019

2020

2021

2022E

2018

2019

2020

2021

2022E

2018

2019

2020

2021

2022E

2018

2019

2020

2021

2022E

United

States

China Europe OECD

Pacific

EMDEs

excl. China

Others

Yearly additions (MW)

Electricity Market Report 2023

AGE | 28

IEA. CC BY 4.0.

Global overview

The surge in coal and gas prices raised thermal generation costs to decade highs in 2022

Russia’s invasion of Ukraine put unprecedented pressure on

European and global energy markets. Natural gas and thermal coal

prices in Asian and European spot markets rose to all-time highs

throughout 2022, sharply increasing the cost of thermal generation

in those markets. In the United States, tight supply and demand

fundamentals drove both coal and natural gas prices to decade

highs. Thermal generation costs are expected to remain well above

historical averages out to 2025, further eroding their

competitiveness compared to low-emission alternatives.

In the European Union, estimated gas-based thermal generation

cost more than doubled in 2022 compared to the previous year, to

an average of USD 350/MWh. Coal-based thermal generation costs

almost doubled to an average of USD 190/MWh. This has been

primarily driven by the rapidly tightening gas and coal market

fundamentals. Russia more than halved its pipeline gas supplies to

the European Union in 2022 – a year-on-year drop of 80 bcm in

absolute terms. Consequently, European gas prices soared to

record highs. Gas prices on the Title Transfer Facility (TTF) in the

Netherlands, the region’s leading hub, averaged USD 37/MBtu

(EUR 123/MWh) in 2022 – more than five times their 2016-2021

average. The strong increase in gas prices provided upward

pressure on thermal coal prices through fuel-switching dynamics in

the power sector. Rotterdam thermal coal prices averaged at an all-

time high of USD 290/t (EUR 40/MWh) in 2022. Despite record-high

prices for coal and gas, gas- and coal-fired generation rose in the

European Union by about 2% and 6% y-o-y, respectively, as low

hydro and nuclear power output increased the call on thermal power

plants.

Monthly average prices of natural gas, thermal coal and emission

certificates, Europe, 2015-2022

Sources: Natural gas prices from TTF; coal prices are CIF ARA; emission certificate

prices are EUA prices from EU ETS.

The price of the emissions allowances (EUA) on the EU Emissions

Trading System (EU ETS) saw record highs, reaching almost

EUR 100/t CO

in August 2022. The surge in emission prices was

mainly driven by the increase in coal-fired generation, which then

resulted in stronger demand for the allowances. Later in 2022,

100

150

200

250

2015

2016

2017

2018

2019

2020

2021

2022

EUR/MWh and EUR/t CO

Natural gas (TTF) Emission certificates (EUA)

Thermal coal (ARA)

Electricity Market Report 2023

AGE | 29

IEA. CC BY 4.0.

Global overview

carbon prices fell, as lower gas prices reduced gas-to-coal

switching in power generation. Despite this, in 2022 EU ETS prices

at an average EUR 81/t CO

were 50% more expensive than in

2021. Even with the rising costs of CO

emissions in 2022 – which

weigh proportionally on coal power much more due to higher CO

emission factors – the generation cost of coal-fired power plants in

Europe remained substantially below that of gas-fired plants.

Forward curves as of late January 2023 indicate that, despite

declining, both natural gas and coal prices remain well above their

pre-2021 historical averages through to 2025, at USD 15-20/MBtu

and USD 130-170/t, respectively. By 2025 generation costs from

gas are expected to decline and approach coal-fired generation cost

levels.

In Asia, estimated gas-based thermal generation costs in Japan

and Korea rose by 65% in 2022, to an average of USD 135/MWh.

Coal-based thermal generation costs increased by more than 70%

to over USD 100/MWh. The steep drop in Russian piped gas

supply to the European Union was largely offset by LNG, driving

up competition between Asian and European buyers. This put

strong upward pressure on Asian spot LNG prices, which

averaged an all-time high of USD 30/MBtu in 2022. Oil-indexed

LNG prices displayed less volatility, averaging about

USD 15/MBtu. High spot LNG prices and flood-induced supply

outages in Australia also drove Newcastle coal prices to peak

levels, to an average of USD 360/t.

Forward curves as of late January 2023 indicate that spot LNG and

thermal coal prices are expected to remain elevated, putting

upwards pressure on thermal generation costs out to 2025. Despite

this, the thermal generation costs in Korea and Japan would be

roughly half that of Europe in 2025 according to the forward prices.

In the United States, the cost of gas supplied to power plants

increased substantially, by more than 50% y-o-y, driving up the cost

of gas-fired generation by a similar magnitude in 2022. This was

driven by a number of factors: supply constraints and low inventory

levels elevated thermal coal prices; the Central Appalachia

benchmark averaged USD 170/t – its highest level since 2010;

reduced availability of thermal coal increased the call on gas-fired

power plants; and higher gas burn in the power sector, together with

below-average gas storage levels and rising LNG exports, tightened

gas market fundamentals. As a result, Henry Hub prices rose by

more than 60% y-o-y, to an average of USD 6.50/MBtu in 2022.

Tight market conditions are expected to linger into the medium term

based on forward curves at the start of January 2023 that show

natural gas and coal prices remaining above their historical

averages, at USD 3-5/MBtu and USD 110-150/t, respectively, in

2023-2025. The generation cost gap between electricity generation

from coal and gas narrows based on the forward prices.

Electricity Market Report 2023

AGE | 30

IEA. CC BY 4.0.

Global overview

Large regional differences in thermal generation costs by 2025, with Europe about twice as high

as Asia

Generation costs of coal- and gas-fired power plants including emission costs, 2019-2025

Notes: Coal range reflects 33-45% efficiency; gas range reflects 43-55% efficiency. Due to the large geographic areas covered in each region, costs can differ between and within

countries and should therefore be interpreted as general trends. In the United States, natural gas prices increased significantly (exceeding USD 15/MBtu) in February 2021 due to

supply constraints. 2023-2025 costs for the regions are based on forward prices of fuels as of end of January 2023 and should not be interpreted as forecasts, rather as costs reflecting

the current market expectations. Fuel price assumptions for the model forecasts presented in this report are based on average forward prices.

Sources: United States: based on EIA (2023), STEO January 2023

. European Union: natural gas prices TTF; coal prices CIF ARA; emission costs EU ETS. Japan and Korea: natural

gas prices reflect estimated LNG import prices, including via oil-indexed LNG contracts and spot procurements; coal prices are Japan marker prices. Latest update: 31 January 2023.

100

200

300

400

500

600

2019

2020

2021

2022

2023

2024

2025

USD/MWhₑₗ

European Union

Gas Coal

100

200

300

400

500

600

2019

2020

2021

2022

2023

2024

2025

USD/MWhₑₗ

Japan and Korea

Gas Coal

100

200

300

400

500

600

2019

2020

2021

2022

2023

2024

2025

USD/MWhₑₗ

United States

Gas

Coal

Electricity Market Report 2023

AGE | 31

IEA. CC BY 4.0.

Global overview

Emissions

Electricity Market Report 2023

AGE | 32

IEA. CC BY 4.0.

Global overview

The world reached a new all-time high in power generation-related emissions in 2022

We estimate that the world reached a new all-time high of about

13.2 Gt CO

in power sector emissions in 2022, a year-on-year

increase of 1.3%. Record-level emissions in 2022 were mainly due

to growth in fossil-fired generation in Asia Pacific. Europe and

Eurasia also contributed to this increase. Similar to what was

highlighted in the IEA’s World Energy Outlook 2022

or the overall

energy sector, the rise in power sector emissions in 2022 was still

less than the y-o-y change in 2021 related to the post-pandemic

rebound.

After a projected decline i

n global electricity generation CO

emissions in 2023 due to lower gas- and oil-fired generation, we

forecast that emissions will plateau out to 2025. In the 2023-2025

period, lower emissions in regions such as Europe and the

Americas (each down roughly 70 Mt/yr on average) partly offset the

significant increases in Asia Pacific (up 100 Mt/yr on average),

mostly attributed to China and India. By 2025, the Asia Pacific

region will account for 67% of global power sector emissions (up

from 64% in 2022). Trends from other regions show mild growth or

remain flat.

In 2025, CO

intensity of global power generation would reach

417 g CO

/kWh, a decline of 3% on average each year to 2025.

The average annual rate of decline from 2023 to 2025 is markedly

steeper in Europe (-12%) and the United States (-4%).

Regional evolution of power system CO

intensity, 2019-2025

IEA. CC BY 4.0.

Note: The CO

intensity is calculated as total CO

emissions divided by total

generation.

100

200

300

400

500

600

700

800

g CO

₂

/kWh

China

United States

India European Union

Others World

Electricity Market Report 2023

AGE | 33

IEA. CC BY 4.0.

Global overview

Global emissions of power generation are expected to plateau from 2023 through 2025

Global emissions of power generation, 2015-2025

IEA. CC BY 4.0

Changes in global emissions of power generation, 2021-2025

IEA. CC BY 4.0.

2 000

4 000

6 000

8 000

10 000

12 000

14 000

2015 2017 2019 2021 2023 2025

Mt CO

China India

Other Asia Pacific

United States Other Americas EU

Other Europe Middle East

Africa

Eurasia

-202

-58

-166

-53

+161

+98

+40

+16

12 500

12 600

12 700

12 800

12 900

13 000

13 100

13 200

13 300

Mt CO

European Union Other Europe United States

Other Americas China India

Other Asia Pacific Rest of world

Electricity Market Report 2023

AGE | 34

IEA. CC BY 4.0.

Global overview

Wholesale prices

Electricity Market Report 2023

AGE | 35

IEA. CC BY 4.0.

Global overview

Electricity prices remain elevated in many regions, led by the high cost of energy commodities

The global energy crisis, with soaring prices of energy commodities

combined with the pandemic rebound and supply chain issues, has

resulted in substantially higher wholesale electricity prices in many

regions of the world in 2022 over year-ago levels.

In a large number of European countries, wholesale electricity

prices (i.e. day-ahead spot prices) in H2 2022 exceeded the

second-half average prices between 2019 and 2021, e.g. fourfold in

France. In H2 2022, the average wholesale price reached almost

EUR 330/MWh in Germany and surpassed EUR 320/MWh in

France, exacerbated by nuclear unavailabilities. By contrast, in

Spain, average prices were much lower for the same time period at

about EUR 130/MWh due to the Iberian price cap. The demand-

weighted average price for Germany, France, Spain and the United

Kingdom in H2 2022 was almost four times as high as the

H2 2019-2021 average.

The elevated futures prices in Europe for winter 2023/24 reflect the

continued uncertainties associated with gas supply for Europe.

Futures with delivery in Q4 2023 are EUR 227/MWh in France and

EUR 184/MWh in Germany while those for Q1 2024 are

EUR 258/MWh in France and EUR 186/MWh in Germany.

On the Nord Pool power exchange, average wholesale electricity

prices remained at unprecedented high levels in H2 2022,

exceeding EUR 150/MWh. Low hydro availability in the Nordics and

increased cross-zonal demand pushed prices up by almost 90%

year-on-year, yet they remained below European averages.

In the United States, the average wholesale price in H2 2022 stood

at about USD 91/MWh, more than twice the 2019-2021 second-half

average, and 65% higher than the price in H2 2021. This increase

was driven by exceptionally high gas prices.

Japanese wholesale prices in H2 2022 averaged almost

YEN 22 000/MWh (EUR 155/MWh), three times higher compared to

H2 2021 because of the tight supply situation. The increased prices

of fossil fuels also affected Japan because of its

low energy self-

sufficiency ratio. However, the majority of the imported LNG

volumes is contracted under oil-indexed long-term contracts which

alleviated some of the effects of soaring spot prices.

In 2022, Australian w

holesale prices averaged AUD 170/MWh

(Australian dollars; EUR 110/MWh), more than double the H2 2021

levels. This was due to surging electricity demand and gas prices

In India, despite increased coal stocks, higher electricity

consumption resulted in a 10% price rise in H2 2022 over the

H2 2021 level. The average wholesale price in H2 2022 was

INR 5 000/MWh (Indian rupees; EUR 55/MWh). Strong growth of

solar PV

helped to meet peak loads dr

iven by higher refrigeration

and space cooling.

Electricity Market Report 2023

AGE | 36

IEA. CC BY 4.0.

Global overview

Elevated futures prices in Europe reflect risks of tight supply in the winter of 2023/24

Indexed quarterly average wholesale prices for selected regions, 2019-2024

Notes: The European Index is calculated as the demand-weighted average of the prices for the European countries included in the analysis. For the Nordics region, the Nord Pool

system price is used for the historical prices and EEX Nordics futures are used for forward prices. The prices for Australia and the United States are calculated as the demand-

weighted average of the available prices of their regional markets. Continuous lines show historical data and dashed lines refer to forward prices. Price estimates for Q1 2023 and

beyond are based on the historical prices and the latest forward baseload electricity prices, except for the United States, where we use EIA (2023) values. The forward prices for Japan

are volume-weighted estimates of the latest JPX settlement prices, considering the baseload contracts (areas B1 and B3).

Sources: IEA analysis using data from RTE (France) and Red Eléctrica (Spain) – both accessed via the ENTSO-E Transparency Platform; Bundesnetzagentur (2023), SMARD.de;

Elexon (2023), Electricity data summary; AEMO (2023), Aggregated price and demand data; EIA (2023), Short-Term Energy Outlook January 2023; Nord Pool (2023), Market Data;

IEX (2023), Area Prices; EEX (2023), Power Futures; JPX (2023), Daily Data (Electricity Futures); ASX (2023), Electricity Futures © ASX Limited ABN 98 008 624 691 (ASX) 2020. All

rights reserved. This material is reproduced with the permission of ASX. This material should not be reproduced, stored in a retrieval system or transmitted in any form whether in

whole or in part without the prior written permission of ASX. Latest update: 31 January 2023.

250

500

750

1 000

1 250

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

Q1 Q2 Q3 Q4 Q1 Q2

Q4 Q1 Q2 Q3 Q4

2019 2020 2021 2022 2023 2024

Indexed electricity price (Q1 2019 = 100)

Germany France United Kingdom Spain United States

Japan Australia Nordics India European Index

Electricity Market Report 2023

IEA. CC BY 4.0.

Global overview

Electricity markets were impacted differently across the world – Europe being hit the hardest

Annual wholesale prices in selected countries, 2022 and 2017-2021 average

Notes: Avg refers to an average of the years from 2017 to 2021. The annual averages are calculated from the daily wholesale electricity prices.

Source: IEA analysis using data from RTE (France) and Red Eléctrica (Spain) – both accessed via the ENTSO-E Transparency Platform; Bundesnetzagentur (2023), SMARD.de

;

Elexon (2023), Electricity data summary; AEMO (2023), Aggregated price and demand data; EIA (2023), Short-Term Energy Outlook January 2023; Nord Pool (2023), Market Data;

IEX (2023), Area Prices. Latest update: 31 January 2023.

AGE | 37

100

200

300

400

avg 2022 avg 2022 avg 2022 avg 2022 avg 2022 avg 2022 avg 2022 avg 2022 avg 2022 avg 2022

Italy France Germany United

Kingdom

Spain Japan Norway Australia India United

States

USD/MWh

Electricity Market Report 2023

AGE | 38

IEA. CC BY 4.0.

Global overview

Carbon pricing trends

Electricity Market Report 2023

AGE | 39

IEA. CC BY 4.0.

Global overview

Status and trends of carbon pricing mechanisms in 2022

Carbon pricing is a key instrument to mitigate emissions, incentivise

investments in low-carbon technologies and reduce demand for

greenhouse gas (GHG)-intensive activities. Such policy instruments

usually take the form of a carbon tax, an Emission Trading System

(ETS) or a hybrid of the two. Due to the ongoing energy crisis, carbon

pricing policies have entered uncharted territory, and are facing new

challenges hindering their effectiveness. While the EU’s carbon price

influences the variable generation cost, and hence the merit-order of

the power plants, carbon pricing is currently unable to perform its

traditional role of incentivising a coal-to-gas switch in electricity

production given exceptionally high gas prices. Nevertheless, carbon

pricing still has a crucial role to play in maintaining a long-term

investment signal and making carbon-intensive fossil generation

such as coal-fired electricity an economically unattractive solution. In

addition, it can be a useful instrument to generate additional revenue

for governments to support faster clean energy transitions, and

mitigate social and competitiveness impacts.

As of April 2022, 68 carbon pricing initiatives

re in place

worldwide, covering over 23% of GHG emissions, with the majority in

the form of an ETS. Many of them saw carbon price increases

compared to 2021. The price of allowances in the EU ETS, the most

established ETS globally, rose from an average of USD 50/t CO

-eq

to more than USD 90/t CO

-eq for January to April 2022. Prices in

the UK ETS rose to more than USD 100/t CO

-eq, and doubled in the

New Zealand ETS (USD 50/t CO

-eq) and in state-level systems in

the United States. Allowance prices in Korea (USD 19/t CO

-eq) and

China’s national ETS (USD 9/t CO

-eq) increased only slightly.

Despite these increases, less than 10% of global emissions are

covered by a carbon price that is higher than USD 10/t CO

-eq. In

some jurisdictions in 2022, carbon pricing instruments have had

difficulty incentivising a fuel switch to lower-carbon sources due to

high natural gas prices. For example, EU coal-fired generation rose

by 6% in 2022.

Price evolution of selected carbon pricing instruments (as of

April 2022, annual average levels)

*The EU ETS operates in all EU countries, Iceland, Liechtenstein and Norway.

Notes: The year-on-year increase compares the 2021 full-year averages versus the

2022 January-April averages.

Sources: World Bank Carbon Pricing Dashboard, ICAP, and Ember.

20%

40%

60%

80%

100%

120%

China

EU ETS*

Korea

New Zealand

United Kingdom

California

Québec

South Africa

ETS Carbon

tax

Year-on-year increase in carbon

price (2021-2022)

Electricity Market Report 2023

AGE | 40

IEA. CC BY 4.0.

Global overview

Share of global GHG emissions covered by a carbon price, by

price level, 2012-2022

Source: World Bank (2022), Carbon Pricing Dashboard, 15 November 2022.

Increases in carbon prices and coverage have led to a new record

of revenues raised by these instruments, reaching

USD 140 bi

llion

in 2021, with ETS revenues more than doubling within a year

(USD 26 billion to USD 56 billion). Schemes differ in the use of their

revenues. California’s Cap-and-Trade, for example, returns the

majority of revenues to power companies and, ultimately, electricity

consumers, while another part is used for carbon mitigation

Least Developed Countries is a UN classification for “low-income countries confronting severe

structural impediments to sustainable development”.

programmes through its Greenhouse Gas Reduction Fund. This

notably includes programmes on renewable energy integration

towards low-income households.

China's national ETS, introduced in 2021 and covering the power

ector only, is the biggest carbon market, and accounts for about

9% of global GHG emissions. The introduction of partial auctioning

of allowances – instead of free allowance allocation – in the power

sector as well as expansion to industry are currently being

considered. Japan’s GX League

, composed of over 500 companies,

has started pilot trading in its voluntary carbon market, with official

trading starting in April 2023. This includes major participants in the

electricity, gas and heat and water sectors, such as TEPCO,

Kanden and Chuden. India also recently

adopted a carbon market

framework legislation, envisioning the construction of a national

carbon market.

Electricity projects are also being affected by rules decided in

oluntary carbon markets. Most notably, since 2020 the two biggest

carbon credits standards issuers, Gold Standard and Verra

, decided

to no longer register new renewable projects, except for those

located in Least Developed Countries

. This is because large-scale

renewable electricity projects are already cost-effective, not

requiring further support from carbon markets.

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2012 2014 2016 2018 2020 2022

Share of global GHG emissions

(%)

More than USD 50

USD 30 - 50

USD 10 - 30

Less than USD 10

No carbon price

Electricity Market Report 2023

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IEA. CC BY 4.0.

Regional perspectives

Electricity Market Report 2023

AGE | 42

Regional perspectives

IEA. CC BY 4.0.

Asia Pacific

Electricity Market Report 2023

AGE | 43

Regional perspectives

IEA. CC BY 4.0.

Asia Pacific’s major generation source remains coal, but low-carbon sources are catching on

Electricity demand grew by an estimated 3.3% in 2022 in the Asia

Pacific region, led by a strong rise in India (8.4%) that was partially

offset by subdued growth in China (2.6%) due to the slowdown in the

economy stemming from its zero-Covid policy. Demand in the two

countries represented about 70% of the region’s total electricity use

of 13 500 TWh, which accounts for approximately 50% of global

consumption. More than half of the increase in 2022 was met by

renewables, of this renewable output almost 60% was from China.

The majority (57%) of the region’s electricity was generated by coal

in 2022, with low-carbon sources, such as nuclear and renewables,

contributing to 32% of the mix. As a result of its strong reliance on

coal for power, Asia Pacific has the highest electricity generation CO

intensity of our analysed regions, at 590 g CO

/kWh in 2022,

compared to a global average of 460 g CO

/kWh.

Power systems in several countries came under severe pressure

during 2022, due to both sharply elevated global energy prices and

extreme weather events, highlighting the critical need for electricity

security. China experienced its longest heatwave in decades

worsening drought conditions that left the Yangtze river at record-low

water levels. South Asia was similarly affected, with heatwaves in

India starting exceptionally early in the spring and the worst recorded

in 122 years. These extreme weather events led to record-breaking

electricity demand for cooling, which was compounded by a fall in

hydropower generation and coal supply shortages. In Japan, the

government issued a

power shortage warning f

or the first time ever,

calling for reduced electricity consumption as very low temperatures

and a

7.4 magnitude earthquake i

n March 2022 put the power

system at risk of not being able to meet demand. Similar calls to

reduce power use amid tight supply were made in Thailand, a gas-

dependent country sensitive to high prices.

The convergence of weather events and record-br

eaking gas prices

led to higher coal use in electricity generation for the Asia Pacific

region in 2022 (+2.5% on 2021 levels), but going forward its share in

the mix will decline. Coal power is expected to fall to 52% in the

electricity mix in 2025, with the share of low-carbon sources rising to

38%, driven mainly by strong y-o-y growth of almost 12% annually in

renewable electricity generation, which will raise its share in the mix

from 26% in 2022 to 32% in 2025. The share of gas-fired generation

will decrease slightly from 10% in 2022 to reach 9% in 2025. Steady

growth in electricity consumption on average of 4.6% every year is

forecast in the next three years, with renewables meeting almost two-

thirds of that additional demand.

The higher share of renewables in the mix will help reduce the

average CO

intensity in the region to 535 g CO

/kWh in 2025.

However, CO

emissions from power generation will continue to rise

by an average 1.2% per year to 2025, as coal-fired generation,

despite having a diminishing share in the generation mix, remains the

main fuel in the region and grows on average 1.3% per year. In

2025, the CO

intensity of the Asia Pacific region remains the

highest globally.

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

Amid post-pandemic economic recovery, Asia Pacific demand sees sustained growth to 2025

Year-on-year relative change in electricity demand, Asia Pacific, 2019-2025

IEA. CC BY 4.0.

-10%

-8%

-6%

-4%

-2%

10%

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

Asia Pacific China India Japan Korea Australia Southeast Asia

Electricity demand growth

Historical demand Updated forecast Previous forecast (July 2022)

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

Carbon dioxide intensity falls as most of the additional demand is met by low-carbon electricity

Year-on-year change in electricity generation, Asia Pacific,

2019-2025

IEA. CC BY 4.0

Development of average CO

intensity, Asia Pacific, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 200

200

400

600

800

1 000

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

200

300

400

500

600

700

800

g CO₂/kWh

Asia Pacific China India

Japan Korea Australia

Southeast Asia

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

China

Electricity demand growth slowed in 2022 as the zero-

Covid policy weighed heavily on economic activity

Under pressure from the large-scale lockdowns affecting the

economy, electricity demand growth in China slowed to an

estimated 2.6% y-o-y in 2022 (significantly below pre-pandemic

rates). With industrial electricity consumption growth subdued, the

increase was mainly driven by residential sector demand.

China’s decision to ease severe pandemic restrictions on

7 December has paved the way for a recovery in its economy, and,

in tandem, a rebound in electricity growth from 2022 lows. Between

2023 and 2025, demand growth is forecast to grow by 5.2% per

year on average, led by continued electrification across the energy

sector, especially in buildings and transport. Nonetheless, our

forecast is slightly below the pre-pandemic trend of 5.4% in

2015-2019. Uncertainty remains around the pace of China’s

economic recovery, which could affect our forecast.

China’s historic heatwave hit the central and eastern regions of the

country from June to August 2022, which led to surging demand for

air conditioning. Sichuan province, which produces

30% of China’s

hydroelectricity, faced power outages during several weeks as its

generation fell by half due to drought conditions and unusually low

rainfall during what is normally Sichuan's rainy season.

Inflexible long-term contracts worsened the situation, with exports

continuing to eastern provinces, despite local shortages. China’s

power supply is likely to remain tight during winter 2022/23 as the

drought left Sichuan’s main reservoirs 77% lower at the end of

August 2022 than at the same time in 2021.

Renewables grow in parallel with coal as policy

prioritises electricity security

The reintroduction of an energy security narrative that followed the

2021 power crunch, as well as the “dual carbon” policy goals

(carbon peaking before 2030 and carbon neutrality before 2060),

imply that coal will possibly expand alongside renewable energy in

the short- to medium-term horizon.

Coal remains the backbone of the Chinese electrici

ty system,

representing over 62% of the power generation in 2022, even

though the share of renewables (30%) has increased. Hydropower

accounts for half of the renewable electricity generation, followed

by wind (29%) and solar PV (15%). While coal-fired supply

increased over the summer to make up for weak hydro output, its

average growth in 2022 compared to 2021 remained modest

(+1.5%), with renewables covering about 60% of the rise in

electricity demand.

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

The share of gas in the generation mix was under 3% and is set to

stagnate in the coming years, as limited domestic production and

high global prices reduce its competitiveness compared to coal in

the power system.

We expect low-carbon energy to account for 41% of electricity

generation by 2025, thus exceeding the objective set at 39% in

China’s 14

Five-Year Plan, owing to the fast development of wind

and solar PV. Capacity additions of both technologies reached new

records in 2022, and we expect their cumulative capacity to exceed

1250 GW by 2025

, up from over 630 GW in 2021.

Distributed solar in particular is developing rapidly in eastern and

central provinces following a national pilot programme

aunched in

2021 to promote solar rooftop PV at the county level. Construction

of utility-scale wind and solar PV power plants is underway in

northern and western desert areas, with a

new batch of projects

announced in 2022.

In parallel, new coal-

fired plants continue to be added to the grid

(11 GW in 2022) and more permits granted (15 GW i

n H1 2022).

Energy security concerns, the willingness to accompany variable

renewable sources

with dispatchable power sources and l

ocal

economic interests are behind these additions. However, they raise

the risk of future under-utilised assets, considering the lack of

profitability of existing coal-fired plants and their declining utilisation

rate.

High coal prices could reduce coal power companies’ operations of

heir assets and slow investments in new ones. Fuel prices were

exceptionally high in 2022, regularly exceeding the level at which

thermal power plants can breakeven. Despite government efforts to

set price caps on thermal coal and deregulate coal-fired power

tariffs following the autumn 2021 power crunch

, more t

han half of

state-owned coal power companies have recorded deficits.

Power market reforms accelerate to support the

transformation towards a modern energy system

China is increasingly relying on markets to support its “dual carbon”

goals and transition towards a modern energy system

. Power

market reforms are moving forward with the issuance in early 2022

of high-level guidance to establish a

unified national electricity

market system, requiring full implementation by 2030. However,

interprovincial and short-term trading remain limited, with 80% of

the electricity being traded within provincial mid- and long-term

markets through auctioning. The new reforms are expected to

harmonise trading rules and technical standards across China to

hasten the integration of existing provincial and regional markets.

China’s southern region took the lead in August 2022 with the

launch of the trial operation of a unified regional power market in the

five provinces covered by China Southern Power Grid. The

development of spot power markets is also progressing, with

trading

and market supervision rules released in November 2022 for

consultation.

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

Meanwhile, the regulator of the national carbon market is proposing

to tighten coal power plants’ emissions benchmarks f

or its second

compliance period running to the end of 2023 and covering

2021-2022 power sector emissions. This should strengthen the

system's stringency and help support carbon price signals, although

market liquidity could remain a challenge. The system's expansion

to industry sectors will only take place from 2023 at the earliest, and

uncertainties remain for the timeline on the development of carbon

derivatives and inclusion of non-compliance entities.

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

Most of the Chinese demand growth out to 2025 is met by renewables, followed by coal

Year-on-year change in electricity generation in China, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 200

- 100

100

200

300

400

500

600

700

800

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

India

Strong demand growth in 2022 led by record

heatwaves and economic recovery

Electricity demand in India grew strongly in 2022, by 8.4%, driven

by a combination of continued economic recovery after the

Covid-19 pandemic slowdown and peak summer temperatures. We

expect demand growth to continue at close to 5.6% on average per

year during 2023-2025.

India experienced extreme heatwaves in 2022. The hot season

arrived earlier than usual, resulting in the hottest March

in over a

century. Electricity demand from April to July was 14% higher than

the same period in 2021 and heatwaves led to a record peak power

demand of 211 GW on 10 June 2022.

The sharp growth in summer demand was primarily met by coal-

fired generation, which registered a significant year-on-year growth

of 21.3% in April-July 2022 from April-July 2021. Following from

this, India experienced coal supply shortages and the Ministry of

Power directed state generating companies and independent power

producers to meet a

10% blending requirem

ent, meaning that 10%

of their coal demand should be met by imported coal. This was

required to ensure adequate coal stocks before the onset of

monsoons. In August 2022, the

government withdrew these

blending requirements when adequate stock levels at power plants

were reached.

While retirement of coal power is lagging, measures are

being taken to accelerate renewable expansion

As of the end of 2022, India has an installed capacity of 410 GW, of

which 236 GW comes from fossil-fired power plants (coal, gas and

oil), 52 GW from hydro, 115 GW from renewable energy plants such

as solar PV and wind, and the rest from nuclear power plants. The

retirement of coal power plants has lagged over the years with

about 14 GW of

the capacity initially scheduled for closure over the

2017-2022 period still in operation and used for balancing purposes.

The government is t

aking actions to accelerate the deployment of

renewable energy capacity, in line with the target of 500 GW of

non-fossil capacity by 2030 announced in the updated Nationally

Determined Contributions. The government established a

plan for

the integration of this additional capacity within the transmission grid

that includes grid expansions and additional storage capacity.

Further, as per Central Electricity Authority (CEA), about 3 GW of

thermal power capacity planned for retirement by 2030, will

potentially be replaced with equivalent renewable energy capacity.

Measures to hasten renewable capacity additions are, first, to

ncrease renewable purchase obligations (to 2029-2030) with a

greater focus on wind, hydropower and energy storage to facilitate

round the clock power from renewable energy sources. Second, the

green open access electricity

ules (notified in June 2022 and

launched in November 2022) are expected to boost renewable

Electricity Market Report 2023

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Regional perspectives

IEA. CC BY 4.0.

energy procurement. Third, the Energy Conservation (Amendment)

Bill 2022 mandates the use of non-fossil sources for designated

industrial and commercial consumers, and establishes

carbon

markets. India also encourages the production of green

hydrogen/ammonia through waivers of inter-state transmission

charges for a period of 25 years under the green hydrogen policy.

Presently, coal dominates the Indian electricity mix (74%). We

expect nuclear output to rise by over 80% during the forecast

period, to 83 TWh, but to remain a small component at 4% of the

mix in 2025. Coal-fired generation rose by 7.7% in 2022, while gas-

fired output fell by 36% in 2022 due to higher imported gas prices.

While total coal-fired generation is set to rise to 2025, we expect its

share to fall to 69% in the generation mix in 2025, as the share of

renewables reaches 25%. Because of higher coal-fired generation,

total power generation CO

emissions rise by 8% from 2022 levels

by 2025, despite falling CO

intensity.

Several measures are underway to modernise the

power system

While short-term markets (trading of bilateral contracts of less than

a one-year period) still represent 14% of the total generation an

power exchanges cover 6% of that total generation, these markets

are expected to grow. Across all market segments, the volume

traded on the Indian Energy Exchange (IEX) rose by 38% year-on-

year in the fiscal year 2022 (April 2021 to March 2022). In addition

to IEX and Power Exchange India Ltd (PXIL), a third power

exchange,

Hindustan Power Exchange s

tarted operations in July

2022. During the 2022 summer supply shortages, demand on

power exchanges doubled, resulting in price hikes. To safeguard

the interest of consumers, the Central Electricity Regulatory

Commission (CERC)

announced a cap of INR 12/kWh on t

market clearing price. The price cap was initially proposed to last

until 30 September 2022, but

was l

ater extended to end-year to

allow for higher demand in the festive season and onset of winter.

India plays a major role in cross-

border trade and regional

connectivity in South Asia. Presently, India benefits from

hydropower imports from Bhutan, and imports from Nepal are

expected to increase

n the next 3-5 years, based on Nepal’s

5 000 MW surplus hydropower. Nepal, which started trading

hydropower on India’s power exchange in 2021, increased its

traded capacity to about 364 MW of hydropower in June 2022.

Investments for further development of new hydro projects (about

1 200 MW) have been agreed upon in a MoU in summer 2022.

The distribution sector, which reported an increase in aggregate

accumulated losses from INR 300 billion in FY 2019/2020 to

INR 500 billion

in FY 2020/2021, remains stressed. To address this,

the government launched the revamped distribution sector scheme

to provide financial assistance with the modernisation of

infrastructure, and the clean electricity authority provided guidelines

on a

resource adequacy planning framework.

Electricity Market Report 2023

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Regional perspectives

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Low-carbon power sources to provide bulk of India's additional supply from 2023 onward

Year-on-year change in electricity generation in India, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 200

- 150

- 100

- 50

100

150

200

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Japan

Electricity demand in Japan rose by 1% year-on-year in 2022 in

tandem with the economic recovery but growth will continue to be

curbed by Covid-19 measures and concerns about electricity

shortages.

The Japanese government issued a

power shortage warning in

March 2022 for the first time since their warning system was

enacted in 2012. They called on businesses and the public to cut

electricity use, emphasising that the combination of very cold

temperatures and a lack of generation capacity due to the

earthquake risked plunging the capital into blackouts. A similar alert

was issued

at the end of June 2022, triggering discussions on how

to secure stable electricity, especially with regards to the possibility

of restarting Japan’s nuclear plants. The government is mobilising a

number of measures to secure the minimum required power buffer

reserve of 3%.

The overall generation mix in Japan is still dominated by gas and

oal, which have a combined share of over 65%. However, the

renewable output is growing, with an estimated 4% y-o-y increase in

2022. In 2025, we expect renewable generation will reach 21%

above 2022 levels, partially offsetting declines in coal and gas-fired

generation.

A sharp 15% y-o-y reduction of nuclear generation was reported in

2022 due to the shutdown of some reactors that require periodic or

special inspection. After this decline, nuclear electricity output is set

to continuously increase out to 2025, driven by policies aimed at

reducing reliance on LNG and strengthening energy security in the

wake of the global energy crisis. In August 2022,

the Prime Minister

announced that the government would push for an accelerated

restart of the nuclear fleet, with the target of having 17 reactors

operational after mid-2023. While some uncertainty remains as

approvals need to be secured at the municipal level, this could

further boost nuclear generation.

Although electrification in the residential, commercial, and services

ectors has continued to increase, electricity demand is expected to

be flat from 2023 to 2025 due to energy conservation measures and

tight supply.

Korea

Korea saw strong electricity demand growth of about 3% in 2022,

led by the commercial, services and industrial sectors. We expect

continued growth of around 1-2% out to 2025.

Around 4 GW of renewable capacity was added in 2022, mainly

solar PV, in line with the trend in recent years. We expect this

development to continue in similar amounts over our forecast

horizon, supported by Korea’s renewables portfolio standard

and

the introduction of a direct power purchase agreement system in

September 2022.

Gas-

fired capacity will also increase out to 2025. Coal-fired capacity

is expected to rise until 2024, due to capacity already under

construction, and then will start to decline from 2025 onwards. New

nuclear capacity is also coming online, with the Shin-Hanul No.1

Electricity Market Report 2023

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Regional perspectives

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reactor (1.4 GW) having started operations in December 2022 and

reactor No. 2 expected to begin operating in late 2023. In July 2022,

the government announced plans t

o resume construction of the

Shin-Hanul No. 3 and No. 4 nuclear reactors.

Demand growth in 2022 was mainly met by renewable electricity

and nuc

lear generation. Renewables grew by around 26% y-o-y,

reaching 8% of the electricity generation mix. Nuclear rose by 15%

y-o-y, accounting for 29% of the mix, whereas coal fell to 33%.

Absolute generation from gas declined slightly, and its share fell by

around 2 percentage points to 29%. By 2025, we expect

renewables to grow to 12% of the mix and nuclear to reach 32%,

while the shares of gas (27%) and coal (29%) both decline.

emissions from Korean power generation fell slightly in 2022

due to a small decline in fossil fuel-fired generation. Average CO

intensity declined in 2022 due to higher renewable and nuclear

output, and we expect a continued decrease through 2025. We see

absolute emissions also entering a decline by 2025. From January

2022 onward Korea’s environmental dispatch system included a

price component reflecting greenhouse gas emissions, although at

present the impact on dispatch is limited and emissions reductions

are primarily driven by the increased availability of clean supply.

Korea released the working draft

of the 10

Basic Plan for

Electricity Supply and Demand (BPLE) in August 2022. This

included adjustments to the targeted electricity mix in 2030,

increasing the contribution of nuclear relative to the previously

released enhanced NDC plan. The 10

plan draft proposes

changes to the current wholesale market bidding system, which

would mean generation companies offer supply within a range of a

benchmark fuel cost and prices are set differentially by generation

company. Korea is also looking to introduce real-time electricity

markets for energy and ancillary services in addition to the existing

day-ahead market. Korea Power Exchange is planning

to begin a

pilot in Jeju in October 2023 to be extended to the mainland by the

end of 2025.

To manage the energy crisis, the government i

ntroduced a System

Marginal Price (SMP) upper limit system in the electricity market

from December 2022. The system limits electricity purchase prices

paid by Korea’s utility in charge of generation, transmission and

distribution, KEPCO, in the context of surging fuel costs. The price

cap, which will operate until November 2023, cannot be activated

for more than three consecutive months.

Australia

Australia’s economic activity posted a strong rebound in 2022, with

GDP growth above 3%. The recovery reflected the high levels of

Covid-19 vaccinations and a progressive relaxation of the measures

in place during 2021. Australia opened its borders to all vaccinated

people from February 2022.

Australia’s electricity consumption grew by around 3% in 2022, after

two years of relatively flat demand. We expect growth to continue

out to 2025 at slightly above 2% per year on average. Expanded

growth for large industrial customers

in Victoria and South Australia

contributes to the increase for 2022-2023.

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Continuing the trend of recent years, Australia’s capacity additions

in 2022 are dominated by more than 5 GW of new renewables,

including over 4 GW of solar PV. Growth in renewables is expected

to continue at a similar pace out to 2025, supported by auctions to

meet state-level targets and corporate purchasing.

Renewable

Energy Zones (REZ), or identified renewables-rich areas which are

targeted for coordinated infrastructure development, are expected

to enhance renewables deployment, and

different states declared

multiple zones in 2022 following the first zone announced in

November 2021. The retirement of the first unit of the coal-fired

Lidell Power Station (500 MW) took place in April 2022 as

anticipated and the remaining three units (1 500 MW) are on

schedule to retire in April 2023.

Battery capacity in Australia, which increased m

arkedly in 2021,

approximately doubled in 2022. This is driven both by the start of

operations of the many utility-scale projects

in the second half of the

year, and by growth in installation of residential battery systems.

2022 saw a continued decrease in generation from coal-fired plants,

which made up 49% of the mix relative to 53% in 2021. Demand

growth was met by increases in both renewable and gas-fired

generation. Over the forecast horizon, we see continued growth in

renewables output of around 12% annually as a result of ongoing

capacity growth. We expect gas-fired generation to remain stable to

2025. The power generation sector’s total CO

emissions, as well

as its average CO

intensity, will decrease as renewables output

increases and coal-fired generation declines.

Surging wholesale prices amid the energy crisis saw the Australian

Energy Market Operator suspend the National Electricity Market

from 15 June to 24 June 2022. The market suspension was

necessitated by sustained high prices that triggered the

Administered Price Cap, which was accompanied by reduced

generation volumes offered to the market and heightened risks to

security of supply.

Generation companies indicated t

hat offers were

lower because the price cap had affected the profitability of some

bids. The Australian Energy Market Commission has

subsequently

introduced a rule change to double the Administered Price Cap,

applicable from 1 December 2022 to 30 June 2025, and in

December 2022 also

intr

oduced a wholesale price cap for gas and

coal.

In July the government introduced the Climate Change Bill 2022,

legislating the country’s commitment to reduce GHG emissions 43%

from 2005 levels by 2030 and achieve carbon neutrality in 2050.

The bill

passed both houses in September 2022.

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Nuclear generation ramps up in Japan and Korea out to 2025; renewables expand in Australia

Year-on-year change in electricity generation in selected countries in Asia Pacific, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 60

- 40

- 20

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

Japan Korea Australia

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Southeast Asia

In 2022, we estimate electricity demand grew by 5.5% in Southeast

Asia. This trend is in line with the economic recovery

n the region

after countries reopened their borders to international tourism, a

significant ec

onomic driver in many Southeast Asian countries.

The region’s power generation is based mainly on coal (43% in

2022), gas (29%) and renewables (27%). While the share of

coal-fired generation in the mix is expected to decrease slightly in

the coming years, the absolute generation from coal is increasing

every year by 4% on average up to 2025 in the region, led by

capacity additions in Indonesia and Viet Nam. High global energy

prices and supply shortages have further contributed to the lifetime

extension of some coal-fired power plants in some countries, such

as in Thailand.

We estimate that electricity demand will continue rising by 4-6% per

year until 2025. Most of that additional demand will be met by fossil

fuels, with renewables meeting about a third of that demand growth.

The share of renewables in the generation mix will rise slightly to

below 28% in 2025. This leads to a decrease in the emission

intensity of the region’s generation mix by over 1% in 2025

compared to 2022, but at 585 g CO

/kWh it is set to remain among

the highest globally.

Several countries in the region have set carbon neutral or net zero

targets, and aim to accelerate renewable energy capacity

deployment. As such, the region is targeting the addition of 50 GW

of solar and wind capacity by 2030

, and over 250 GW by 2050.

Year-on-year change in electricity generation in Southeast Asia,

2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy

sources.

- 60

- 40

- 20

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

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Indonesia

In 2022, Indonesia’s share of coal in the electricity mix rose to 64%

of total power generation (from 61% in 2021), and provided the

majority of the electricity needed to meet the estimated 6.6% y-o-y

demand increase. Gas-fired output made up 15% of the Indonesian

mix in 2022, and renewables 20%, with hydropower, geothermal

and biofuels making up the largest share of the renewable mix.

In the coming years, electricity demand is expected to rise steadily

(ranging from 3% to 7% per year), in line with Indonesia’s projected

GDP growth of more than 5% per year in this decade, and

supported by government plans for electrifying mobility and cooking.

While the long-awaited Presidential Decree 112

on t

he acceleration

of renewable energy development for electricity generation was

published in September 2022, it is expected to come into effect only

gradually with the release of

Ministerial Regulations t

o implement

the Decree. We expect renewables to reach almost 22% of

electricity generation in 2025, falling slightly short of the target of

23% by 2025 established in the

2014 national energy plan.

While the generation expansion programme announced in 2015

continues to add coal-fired plants, with a total 13 GW in the

2021-2030 project pipeline for which tenders have been held

, the

Just Energy Transition Partnership will support an accelerated

phase-out of coal-fired output in the mid- to long-term. Indeed, one

of the measures of this partnership, launched in November 2022, is

the

freeze of the current planned pipeline of coal-fired plants. Other

targets in this framework to accelerate the decarbonisation of the

power sector include achieving peak power sector emissions by

2030 of no more than 290 Mt CO

, and reaching a share of 34% of

renewables in the generation mix by 2030.

Due to its coal-

heavy generation mix, Indonesia’s CO

intensity is

among the highest in the Southeast Asia region. CO

emissions

from the power sector in Indonesia rose by 6% in 2022, and are

estimated to further increase by about 4% per year up to 2025.

Viet Nam

The impact of high global commodity prices in Viet Nam is relatively

subdued due to a strong domestic market. Economic and electricity

demand growth are thus expected to remain high. We estimate

electricity consumption rose by 6% in 2022 and that it will grow by

about 6% per year on average in 2023-2025.

Alongside this high demand growth comes a challenge to provide

matching supply. The approval of Viet Nam’s main planning

document, the Power Development Plan 8, has been delayed to

incorporate recent developments such as the country’s recently

committed decarbonisation targets, changing global fuel prices, and

plant financing challenges. These include COP26 commitments to

net zero emissions by 2050 and the

phase out of coal power

generation by 2040. In the most recent draft (October 2022),

6.8 GW of coal-fired capacity was withdrawn from the planning

process, either due to investor withdrawal or proposals to shift from

coal to other fuels. Nonetheless, 3.8 GW of new coal-fired capacity

is still expected to be commissioned by 2030, in addition to the

Nghi

Son 2 (1.2 GW) and Song Hau 1 (1.2 GW) power plants that started

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Regional perspectives

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operations in 2022. About 32% to 44% of the annual increments

from 2023 to 2025 would therefore be met by coal power. Its share

in the generation mix will remain constant at 41% in 2022-2025.

The current draft development plan includes an additional

6 GW

LNG-based power generation by 2030 to help replace the planned

coal capacity that has been withdrawn. The ongoing build-up of the

first LNG terminals is therefore critical. The Hai Linh LNG terminal

(1.5 Mt/yr) is intended to supply a

1.2 GW power plant that is

already constructed but not yet operational. The Thi Vai LNG

terminal (1 Mt/yr) is expected to be finished by the end of 2023,

supplying 1.5 GW of power capacity. The Son My LNG terminal

(3.6 Mt/yr) designed to supply 2.3 GW of gas-fired capacity is

expected to begin commercial operations

only by 2026.

Issues on the policy measures to increase renewable capacity have

still not been resolved. The phase-out of feed-in-tariffs

has reduced

renewable capacity additions and extending these tariffs further is

still under discussion. Nonetheless, the growth is expected to

continue, such that about 40% of the demand increases in 2023-

2025 would be satisfied by renewables. In 2025, we expect

renewables to provide 46% of the total generation mix.

Moreover, a new pricing framework and r

ooftop PV regulations are

being considered in order to strike a balance between the

government’s fiscal capabilities and reducing the risk for investors.

The planned pilot projects for direct

power purchase agreements

with renewable developers have yet to take place. Such

mechanisms allow companies to procure clean electricity directly t

reach their corporate net zero goals and alleviate pressure on the

government’s renewable subsidy budgets.

Thailand

Thailand’s economic recovery continued in 2022, with an estimated

GDP growth of 3.2%. Peak demand in 2022 increased by 7%

32.3 GW, compared to 30.1 GW in 2021. We estimate overall y-o-y

growth in electricity consumption of almost 4% in 2022. Reported

data for the first eight months of 2022 show electricity consumption

rose by 4%, l

ed by the commercial (11%) and industrial (4%)

sectors, which represent 23% and 45%, respectively, of total

demand. The residential sector, which accounts for 28% of demand,

has stagnated in the same period.

Thailand, which dep

ended on gas for 61% of its power generation in

2022, was strongly impacted by the rise in global fuel prices, which

led the energy regulatory commission to increase the fuel tariff

–

component of the electricity price – for the last quarter of 2022 by

18%. Indeed, the country faced gas supply challenges due to a

combination of lower domestic production, import disruptions and

high prices. Thailand further decided to

extend the lifetime of some

of its coal-fired power plants and implemented plans to reduce

power consumption. To lower the burden of the high prices on

households, the government announced in September 2022 an

extension of the electricity bill subsidy f

or vulnerable consumers.

We expect electricity demand in Thailand to grow by 3-4% per year

until 2025. Gas will remain Thailand’s dominant generation source

in the coming years, with 1.3 GW of gas capacity commissioned in

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2022, and a new combined-cycle gas plant with four units of

660 MW each expected to be fully operational between 2023 and

2024, which will bring gas-fired output’s market share to 63% of the

mix in 2025. Per the goal to be

carbon neutral by 2050, Thailand

aims renewables to account for 50% of the electricity mix by this

target date. This will require an accelerated deployment of

renewables, as we expect their share in the generation mix to

decrease in the coming years, from 19% in 2022, to 17% in 2025.

With the new Power Development Plan (PDP) currently under

scussion, some targets such as the planned deployment of

16 hydro-floating solar hybrid projects

or a total of 2.7 GW of

capacity have already been announced. The government further

introduced a

feed-in tariff mechanism, starting in 2025-2026, which

regulates the sale of renewable electricity generated by small

(under 90 MW) and very small (under 10 MW) power producers.

Philippines

The Philippines’ economic rebound from the easing of lockdowns

underpinned an estimated GDP growth of 7% in 2022. It is expected

to dip slightly to 5% in 2023 due to high commodity prices, before

rising again to rates above 6% through 2025. We forecast annual

average demand growth of about 5.5% for the next three years.

Coal and renewables are expected to meet incremental demand

until the new gas-fired power plants start operation by 2024.

Coal made up 58% of the generation mix in 2022. About

1.6 GW

new coal-fired capacity is committed and projected to become

operational between 2023 and 2025, with an additional 720 MW

expected by 2027. These projects were all approved prior to the

moratorium on new coal-

fired power plants in 2020. Gas-fired units

are expected to meet a large part of future additional growth,

primarily driven by LNG imports given the

depletion of

the country’s

only domestic gas field. However, the LNG terminal build-up has

faced delays attributed to Russia’s war in Ukraine and t

he Covid-19

pandemic affecting the supply chain for materials. The delayed

5.2 Mt/yr import facility in Batangas is intended to supply an existing

1.2 GW gas power plant and another planned

850 MW gas power

plant expansion. Moreover, the constructed 650 MW Pagbilao gas

power plant set to start in 2022 is delayed due to financing issues of

the associated transmission substation. We expect the share of gas

generation in the mix to reach 19% by 2025, from 17% in 2022.

Despite ear

ly legislation to support renewables development in the

Philippines, growth has been limited so far. Renewables had a 22%

share of the generation mix in 2021, with solar PV and wind making

less than 3%. Additional policy changes were introduced in 2022

to further stimulate investment for renewables to help achieve the

country’s 2030 target of reaching a 35% share of renewables in the

energy mix. This includes

allowing 100% foreign ownership of

renewable assets which was limited to 40% before, and maintaining

priority dispatch for biomass and maintaining “must-dispatch” for

variable renewables after the expiry of the feed-in-tariff programme

on which the special dispatch condition depends. It also extended

priority dispatch privileges to

geothermal and dammed hydro. In

addition, the Green Energy Option Program started operation in

January 2022. The initiative allows consumers with a peak demand

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Regional perspectives

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of at least 100 kW and equipped with a 5-minute metering unit to

enter into direct procurement of renewables.

The Philippines’ electricity market continues to develop with the

ntegration of the island system of Mindanao at the end 2022 and

opening of the reserves market by 2023. Furthermore, the

Renewable Energy Market

(

REM), where renewable energy

certificates are traded, started operations in summer 2022.

Finally, electricity security and resilience continue to be key

oncerns for the country. The recent typhoon Noru impacted

thirteen 69-kV and four 230-kV transmission lines, resulting in

20 out of 51 public distribution areas to experience partial or total

power interruption. This year, the country also announced the

inclusion of nuclear energy i

n its long-term energy policy.

Singapore

Electricity demand in Singapore grew by 2% in 2022 as the impact

of the Covid-19 pandemic on the economy eased. We forecast an

increase of over 1% in 2023, due to higher demand in electricity-

intensive sectors (industry is the largest electricity consuming sector

in the country) and a growing EV adoption rate. Our outlook for

2024 and 2025 shows growth above 1% per year. According to the

Singapore Green Plan 2030, the country will double the target

number of EV charging points

from 28 000 t

o 60 000 by 2030 and

will phase out of all internal combustion engine vehicles by 2040. In

addition, the Minister of Transportation aims for

electrification of half

of the public buses and taxis by 2030.

Singapore relied on imported natural gas to generate around 95%

of its electricity in 2022, making domestic energy prices highly

vulnerable to volatile of global energy markets. In October 2022,

Singapore announced that they will maintain extraordinary

measures as a buffer, including standby fuel facilities

rom which

generation companies can draw fuel when their gas supplies are

disrupted. Authorities also required generation companies maintain

enough fuel in addition to the existing reserve requirements.

In the coming years Singapore plans on increasing electricity

mports to diversify its supply as their domestic output with existing

thermal power plants cannot meet rising demand. In line with that

plan, Singapore had its first renewable electricity imports i

n 2022.

The Lao PDR-Thailand- Malaysia- Singapore Power Integration

Project (LTMS-PI

P) enables trade up to 100 MW of hydropower

from Lao PDR to Singapore via Thailand and Malaysia utilising

existing infrastructure. This is the first multilateral cross-border

power trade including four countries of the Association of Southeast

Asian Nations (ASEAN). EMA also envisions importing

100 MW

equivalent of electricity from a solar farm in Pulau Bulan, Indonesia

through a new interconnector around 2024.

By 2025, while gas will remain the major source of electricity (95%

the mix), the share of renewables is expected to rise to 3.4%

(from almost 3% in 2022), which is driven by solar – there is a target

to reach 1.5 GW of solar PV by 2025 (from 0.4 GW in 2021).

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Coal- and gas-fired generation set to remain significant in meeting Southeast Asia’s demand

Year-on-year change in electricity generation in selected countries in Southeast Asia, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 20

- 10

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

Indonesia Viet Nam Thailand

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

- 6

- 4

- 2

2019

2021

2023

2025

2019

2021

2023

2025

Philippines

Singapore

TWh

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Americas

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Renewables meet most of additional demand in the Americas while coal-fired power declines

Electricity demand in the Americas region rose for the second year

in a row, up by 2.3% in 2022, though slightly below growth in 2021.

Regional demand declined in both 2019 and 2020. We expect

electricity consumption to stagnate in 2023 due to weaker economic

growth, before rebounding to 1.5% per year in 2024 and 2025.

The recovery is largely driven by the United States, which accounts

for two-thirds of overall regional electricity demand. US electricity

consumption rose by 2.6% in 2022, but demand is forecast to

decline by 0.6% in 2023 before increasing to an average of 1.2% in

2024 and 2025. Canada, the third largest consuming nation in the

Americas (behind the United States and Brazil), mirrors the US

trend, as demand rose by almost 2% in 2022 before declining 1% in

2023 and then recovering to growth of an average 2.5% in 2024 and

2025. We estimate that demand in Mexico rose by almost 4% in

2022, but expect growth to average 2.3% over the next three years.

In Central and South America, annual demand growth moderated to

an estimated 1% in 2022 from 4.4% in 2021. For 2023-2025, we

forecast electricity consumption to increase at an annual average

rate of 2%. Weaker growth in 2022 was largely due to a slowdown

in Brazil, the region’s second largest consumer. Brazilian demand

growth rose by a modest 0.3% in 2022, down from 6% in 2021. We

forecast an annual average increase of 2% for the country over the

2023-2025 period. In 2022, electricity demand in Argentina (0%),

Colombia (1%) and Chile (2%) saw modest increases while Peru

posted more robust growth (4%). Going forward, we expect growth

to accelerate in Colombia and Chile while the pace slows in Peru

and Argentina in 2023-2025.

An increase in coal-fired output due to fuel switching from

comparatively higher natural gas prices and lower hydro availability

in the region in 2021 proved to be short-lived. After growth of 13% in

2021, coal generation fell by 7% in 2022 and is forecast to decline

8% per year on average for the 2023-2025 period. Hydroelectric

output rebounded by an estimated 4% in 2022 as severe drought

conditions eased, particularly in Brazil and the United States. This

rise, as well as additions of wind and solar capacity, drove year-on-

year growth in renewables generation up 9% in 2022, from 2% in

2021. Renewables growth will then moderate to an average 5% per

year in the 2023-2025 period as hydroelectric generation levels out.

Renewables including hydro accounted for 36% of annual

generation in the region in 2022, the largest share of all sources,

followed by gas at 33%, coal at 15%, nuclear at 14% and oil at 2%.

By 2025 we expect renewables to account for over 40% of the

Americas electricity generation mix, with its share increasing almost

entirely at the expense of coal, which is expected to decline to a

share of 12% (from 15% in 2022).

This will drive emissions down, both in their overall level and

intensity. We estimate CO

intensity will fall to about 260 g CO

/kWh

in 2025, down from 300 g CO

/kWh in 2022 and 380 g CO

/kWh in

2015. Regional emissions are set to decline to 1.8 Gt CO

in 2025,

from 2.5 Gt CO

in 2015.

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Electricity demand growth will slow along with economic activity in 2023, but rebound in 2024

Year-on-year relative change in electricity demand, Americas, 2019-2025

IEA. CC BY 4.0.

-10%

-8%

-6%

-4%

-2%

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

Americas United States Canada Mexico Brazil

Electricity demand growth

Historical demand Updated forecast

Previous forecast (July 2022)

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Renewable generation ramps up, driving down emissions across the Americas

Year-on-year change in electricity generation, Americas,

2019-2025

IEA. CC BY 4.0.

Development of average CO

intensity, Americas, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 300

- 200

- 100

100

200

300

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

150

200

250

300

350

400

450

500

g CO₂/kWh

Americas United States Canada

Mexico Brazil

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United States

Electricity security remains at risk in many regions

Electricity security in the United States remains at risk during the

winter of 2022/23. Outages that occurred in Texas in February 2021

exposed the country’s vulnerabilities to extreme weather and

prolonged cold periods. The winter reliability assessment

eleased

in November 2022 by the North American Reliability Corporation

(NERC), reports that the US Southeast, Texas, the Midwest and

New England regions could see load shedding due to generation

and transmission outages, fuel supply shortages and natural gas

infrastructure unavailability. In December 2022, a strong winter

storm left over

1.5 million customers w

ithout power.

Electricity demand growth is set to slow in 2023;

policies boost low-carbon power in the coming years

Electricity use rose by 2.6% in 2022, surpassing pre-pandemic

levels, led by economic growth coupled with higher air conditioning

and heating use. However, demand is forecast to fall by 0.6% in

2023 due to an expected slowdown in economic activity, before

returning to annual growth of around 1.2% in 2024 and 2025.

Gas-fired generation grew by 8% in 2022, reversing a decline of 3%

in 2021, as gas prices moderated due to mild temperatures and the

loss of LNG export capacity at the Freeport facility. The overall

slowdown in electricity demand is expected to reduce gas-fired

generation by 3% in 2023. Coal-fired generation fell year-on-year by

7% in 2022, reversing a 15% rise in 2021, which was the first

annual increase since 2014. Out to 2025, falling natural gas prices

are expected to support an increase in coal-to-gas switching, with

growth in renewables reducing total fossil fuel-fired generation.

Coal-fired output is set to fall by an average 7% per year in the

2023-2025 forecast period.

Hydropower output rose by about 3% in 2022 as long-term drought

conditions eased in many hydro-producing regions, nevertheless

hydro output remained slightly below the 2017-2021 average by

4%. Wind and solar PV posted continued strong growth in 2022.

Wind generation rose by 14%, while solar output grew by 27%. By

2025, wind generation is expected to grow by 19% compared to

2022, and solar PV generation up by 56% over the same period.

This will be supported by the August 2022 passage of the

Inflation

Reduction Act, which included USD 30 billion in targeted grant and

loan programmes for clean electricity investments.

Nuclear output s

howed no significant change between 2021 and

2022, following two years of slight declines due to three reactors

retiring. We expect that the commissioning of Vogtle Units 3 and 4

in Q1 and Q4 2023, respectively, will raise nuclear output by 2% in

2023. Further, the California legislature passed a bill to

extend the

life of Diablo Canyon Units 1 and 2 from 2024 and 2025 to 2029

and 2030, respectively, which will boost mid-term generation.

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Coal-fired generation in the United States down in 2022, reversing a sharp increase in 2021

Year-on-year change in electricity generation in the United States, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources

- 300

- 200

- 100

100

200

300

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Canada

Electricity security also remains a concern in Canada. The NERC’s

November 2022 winter reliability assessment

ites Alberta and the

Maritimes as being at risk of insufficient electricity this winter due to

higher-than-average peak electricity demand growth combined with

the potential for high generator unavailability. The continued

economic recovery from the pandemic-induced slowdown, as well

as Canada’s position as a commodities exporter, has sheltered it

from high input costs, resulting in electricity demand growth of 2%

year-on-year in 2022. The expected economic slowdown in 2023

will lead to a decline in demand of 1%.

Total thermal generation is expected to remain steady over our

forecast period, but gas will increasingly replace coal in the

generation mix. This will result in an 18% share for gas and 2%

share for coal in 2025, compared to roughly equal shares of 10% in

2015. For nuclear output, the refurbishment programme at the

Darlington and Bruce

eactors will intensify in 2023, resulting in the

temporary shutdown of five out of ten units in the second half of the

year for refurbishment. This will decrease output of the overall fleet

by almost one-quarter over 2023-2025 compared to 2015-2019

averages.

The government’s F

all Economic Statement proposed a refundable

tax credit of 30% for clean energy investments of up to

CAD 6.7 billion over five years, including solar PV, wind, storage

and small modular nuclear reactors. We expect this policy to

contribute to strong growth in renewable generation, with wind and

solar PV growth forecast to rise by about 6% and 14% per year,

respectively, between 2023 and 2025.

Mexico

After the quick recovery in energy demand following the pandemic,

electricity demand grew by almost 4% y-o-y in 2022. After an

expected slowdown to less than 2% growth in 2023, the pace is set

to pick up continuously, reaching 3% by 2025, which equates to an

increase from about 300 TWh in 2022 to almost 330 TWh by 2025.

In 2022, the rise in demand was met by a mix of sources, mainly by

wind and solar PV, but also a small absolute increase in coal-fired

generation.

The Mexican government announced a more ambitious

GHG

reduction target at COP27, shifting from the original 22% to 35% by

2030 as part of a joint investment project with the United States.

The average CO

intensity of Mexican power generation, on the

other hand, has risen by 7% y-o-y in 2022 to reach 385 g CO

/kWh,

due to the increased share of fossil-fired generation. CO

intensity

growth is expected to decline out to 2025, to 370 g CO

/kWh, as

renewables and gas-fired output growth meets incremental

demand, while oil-fuelled generation remains flat on average.

In the coming years, growth in renewables such as solar PV and

ind from private sector companies is expected to slow. Auctions,

which resulted in much of the growth in renewable energy, were

halted in 2019. This follows a series of disconnections of private

sector renewable energy projects due to generation permit expiry,

permit cancellation or fines as a result of

deviations from their

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Regional perspectives

IEA. CC BY 4.0.

original arrangement. In January 2022 a plant in the northern state

of Nuevo Leon ceased operations after being fined USD 467 million

for selling surplus generation to third parties instead of to CFE.

Despite the slowdown of private sector activity in Mexico’s electricity

arket, the government has announced a number of clean energy

projects in collaboration with state governments. These include a

new 18 MW solar PV rooftop installation

on t

op of Mexico City’s

largest market, and most notably an ongoing development of the

solar PV plant in the northern state of Sonora, t

hat should add

420 MW by the end of February 2023 and reach a total of

1 000 MW by the end of the fourth phase in 2027.

In the coming years, CFE plans the addition of around 16 new

gas-fired power plants along with the repowering of ten of the

hydropower plants run by the state company.

Brazil

Despite the strong post-pandemic rebound, Brazil’s electricity

demand in 2022 increased only very slightly, by 0.3% year-on-year,

but is set to rise by around 2% per year in the 2023-2025 period.

Hydropower generation rebounded in 2022 with a y-o-y increase of

about 17% after the country’s most severe drought in 90 years

, and

led to a decrease in power system emission intensity from

135 gCO

/kWh in 2021 to 80 gCO

/kWh in 2022. The CO

intensity

is expected to continue decreasing towards 30 gCO

/kWh in 2025.

We expect hydropower’s share of generation to rise from 55% to

63% bet

ween 2021 and 2025, which will drive the emissions

reduction along with an increase in the share of wind and solar PV

generation, from 11% to 17% and 3% to 11%, respectively.

In the coming years, several proposed updates, which are part of

the country's power system modernisation programme, may alter

the rate at which renewables are deployed and how different actors

interact in the power system. On 1 November 2022, the regulator

ANEEL launched a consultation to

alter solar PV net-

metering

incentives, leading to a decrease in the number of incentives for

distributed generation (DG). The document also details new

financing schemes for new installations through a special energy

development account (CDE) from 2023. The CDE will be financed

by all captive consumers, reducing the burden in regions with high

penetration of renewables. Additionally, in 2023, the free market

reserve for renewables ends and from 2024 they will have to

participate in the wholesale market.

Brazil’s Law 14 300,

published in January 2022, sets a gradual

transition path for distributed generation; current contracts will be

grandfathered and a de facto net billing system will be introduced in

January 2023. After a transition period, new DG clients will only be

able to compensate for the energy component of their bills and they

will be obliged to pay all distribution components of the tariffs.

Additionally, 514/18

egulation will expand access to the liberalised

retail market for consumers with loads between 0.5-1 MW, and from

2024, high-voltage customers of any level of demand will have

access to the free market.

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Regional perspectives

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These new rules spurred the acceleration of decentralised solar PV

deployments in 2022, totalling 10.7 GW. However, as the gradual

opening of the energy market may offer customers an alternative to

investing in distributed PV generation in order to decrease their

electricity bills, it may slow the deployment of the distributed

generation, which is the regulator’s aim due to the impact of DG on

wider system operation.

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Regional perspectives

IEA. CC BY 4.0.

While gas dominates incremental supply in Canada and Mexico, renewables expand in Brazil

Year-on-year change in electricity generation in selected countries in the Americas, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 80

- 60

- 40

- 20

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

Canada Mexico Brazil

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Regional perspectives

IEA. CC BY 4.0.

Market trends in selected other countries in the Americas

In Chile, electricity demand grew by about 2% in 2022, following the

end of lockdowns in 2021. For 2023-2025, we expect an average

annual growth of 4% in electricity demand, supported by economic

growth and increased electrification (for example, in transport).

Given the country’s coal-power phase-out plan by 2040 at the

latest, coal-fired generation is forecast to decline by an average of

more than 7% per year in 2023-2025, due to some of these plants

being decommissioned in this period (about 1 GW

). Benefiting from

its large wind and solar power potential, the decline in coal-fired

power in the coming years is more than offset by growth in

renewables. We forecast total renewable output will reach over 65%

of the country’s electricity generation mix by 2025.

Addressing concerns over renewable curtailment related to

ransmission bottlenecks (for example, between northern and

central regions) and increasing flexibility requirements, the Chilean

government passed a law to support energy storage development

October 2022. Additionally, a new electricity tariff stabilisation fund

law was passed in July 2022 aimed at avoiding price hikes that

would put additional pressure on households’ expenses. This

stabilisation fund was first implemented in October 2019 in the wake

of public demonstrations and social unrest.

Electricity demand in Colombia f

ell below 1% in 2020 due to public

health measures to combat the pandemic, and then recovered by

1.6% in 2021. Supported by increased economic activity, electricity

consumption rose by about 1% in 2022. Despite being a significant

hydrocarbon producer, Colombia’s renewable capacity has helped

limit fossil fuel-powered electricity to under 25% in recent years.

Renewable output could surpass 80% of Colombia’s generation mix

by 2025.

To avoid further increases in end-user electricity prices, the

Colombian government

passed three resolutions in September

2022. These allow, for example, to renegotiate some supply

bilateral contracts among market agents, optimise the operation of

thermal power plants, and to decouple price increases from the

consumer and producer price indexes. Additionally, the government

presented an

offshore wind roadmap.

Costa Rica’s electricity system is already almost fully renewable

due to high hydropower availability. After falling by 3% in 2020 amid

Covid-19-related restrictions, electricity demand grew by 5% in

2021. In 2022, consumption rose again, by 3%. Costa Rica’s

transmission system is connected to Panama and Nicaragua, as it

is part of SIEPAC (the Central American interconnected system).

Electricity trade with neighbouring countries in recent years has

usually remained under 1 TWh (less than 10% of national demand).

In order to lower electricity prices, the government of Costa Rica

signed a decree in October 2022 that will allow the state-owned

electricity ICE to buy electricity from private generators

hat did not

already have a contract (and many of which were not selling

electricity in recent months).

Electricity Market Report 2023

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Regional perspectives

Europe

Electricity Market Report 2023

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Regional perspectives

Renewables will lead to a sharp decline in fossil fuel-fired generation from 2023 onward

Electricity consumption in the European Union rebounded to almost

5% in 2021, in line with the economic recovery, following a

substantial year-on-year decline of 4% in 2020. The return to growth

reversed in 2022 when Russia’s invasion of Ukraine triggered an

unprecedented energy crisis, with Europe at the epicentre. As a

result of demand destruction in electricity-intensive industries,

energy saving measures and unusually mild winter, EU electricity

consumption declined by 3.5% in 2022 – its largest percent

decrease since the Great Recession in 2009, excluding the

exceptional contraction due to Covid-19 in 2020. We forecast EU

electricity demand to rebound slightly from 2023 onwards, with an

average annual growth rate of 1.4%, on expectations of lower

energy prices and the push for electrification.

The energy crisis and its wide-reaching impacts has led to a

significant shift in policy priorities in the European Union. As a

response to the crisis, the European Commission published on

18 May 2022 its REPowerEU plan

o reduce the EU’s dependence

on Russian fossil fuels by hastening the clean energy transition.

This was followed in December by the adoption of a

Council

regulation that will set a temporary framework to accelerate the

deployment of renewables. Record-high electricity prices also

prompted discussions on electricity market design and the

Commission

launched a consultation in early 2023 on this subject.

Short-term measures on a national scale were implemented to ease

the tight market situation and provide relief to consumers, such as

the introduction of price caps, reduction of energy taxes and

regulation of retail tariffs, among various other initiatives. To reduce

power sector gas demand and increase the security of supply over

the 2022/23 winter, several countries have brought reserve

generation capacities back online, mainly consisting of coal-fired

plants. In Germany, the operation of the remaining three reactors

has been extended until April 2023. Belgium has decided to extend

the operation of Doel 4 and Tihange 3

by ten years, to 2035.

Coal-fired generation in the European Union increased again in

2022, rising over 6%. Despite high gas prices, gas-fired supply

actually grew by about 2%, largely to offset reduced nuclear power

and low hydro output. Over 2023-2025 we expect a sharp decline in

fossil fuel-fired generation, as strong growth in generation from

renewables of 34% from 2022 levels displaces fossil generation.

Significant increases in nuclear generation occurs only after 2023,

as French plants gradually conclude their maintenance schedules.

After the more than 11% y-o-y rise in 2021 due to the post-

pandemic rebound, the 4.5% growth in 2022 was the highest

percentage growth in power generation emissions in the European

Union since the oil crises of the 1970s. While the global CO

intensity of power generation fell in 2022, it increased in the EU by

7% due to the higher share of coal-fired output. With the expansion

of renewables and the decline in coal- and gas-fired supply, we

forecast a decline of 28% in the EU power sector’s CO

emissions

by 2025 from 2022 levels, and by 31% in CO

intensity.

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IEA. CC BY 4.0.

Regional perspectives

After significant decline in 2022, European electricity demand is set to recover

Year-on-year relative change in electricity demand, Europe, 2019-2025

IEA. CC BY 4.0.

-8%

-6%

-4%

-2%

10%

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

European

Union

Europe Germany France Italy Spain

United

Kingdom

Türkiye

Electricity demand growth

Historical demand Updated forecast Previous forecast (July 2022)

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Regional perspectives

Following two years of increases, CO

intensity starts to decline again from 2023 onward

Year-on-year change in electricity generation, European Union,

2019-2025

IEA. CC BY 4.0.

Development of average CO

intensity, Europe, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 250

- 200

- 150

- 100

- 50

100

150

200

250

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

150

200

250

300

350

400

450

500

g CO

₂/kWh

European Union Europe Germany

France Italy Spain

United Kingdom Türkiye

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IEA. CC BY 4.0.

Regional perspectives

The European Union faced a multi-crisis year in 2022 amid low nuclear and hydropower output

Year-on-year change in electricity generation by technology in the European Union, 2021-2022

IEA CC BY 4.0.

Note: Other includes oil, other renewable and other non-renewable energy sources. Generation numbers shown in this figure are net generation.

-64

-10

+38

+32

+26

+12

-84

-36

-82

- 200

- 180

- 160

- 140

- 120

- 100

- 80

- 60

- 40

- 20

Nuclear Hydro Other Solar Wind Coal Gas

Supply

difference

TWh

EU EU excl. France France

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Regional perspectives

Countries in Europe have resorted to coal to increase security of electricity supply

To enhance security of supply amid low nuclear availability and tight

gas markets, several countries in the European Union and the

United Kingdom have decided, or are discussing plans, to add

short-term conventional capacity to the market by bringing reserve

capacity back into the market or postponing closure dates, lifting

production caps and reviving idled power plants. Of the additional

capacity of about 24 GW now in place until the end of winter

2022/23, 19 GW is coal-fired, which comes on top of the existing

127 GW that would be in place without these measures. Germany

accounts for most of the additional coal-fired capacity, with almost

10 GW for the 2022/23 winter. In Netherlands, the

removal of the

35% production cap on coal-fired plants will add another 3.8 GW.

Under confirmed plans, overall coal-fired capacity will increase by

about 15% (19 GW) to 146 GW in the European Union and the

United Kingdom combined.

According to current government plans, coal-

fired power plant

capacity will fall again to about 141 GW during the 2023/24 winter

after the temporary return of capacity ends. As some of the revived

coal-fired generating capacity is idled again after winter 2022/23,

output of the French nuclear power plants are expected to start

increasing following maintenance in 2022. Nevertheless, depending

on developments in the ongoing energy crisis, further capacity

increases in European coal-fired generation is possible.

Breakdown of coal-fired capacity and capacity extensions in

selected European countries, 2022-2024

Note: The analysis is conducted with available data and information as of 30

November 2023.

Sources: IEA analysis based on ENTSOE (2022), Transparency Platform,

30 November 2022; Bruegel (2022), National energy policy responses to the energy

crisis, 30 November 2022.

127

146

141

120

125

130

135

140

145

150

Increase

Total

Decrease Increase Total

Winter

2022/23

without

capacity

additions

Winter 2022/23 Winter 2023/24

Coal-fired capacity (GW)

Other EU Denmark Finland

France Germany Netherlands

Spain Austria United Kingdom

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Regional perspectives

Soaring energy prices led to emergency interventions in Europe

The sharp escalation in electricity prices, starting in the second half

of 2021 and propelled higher by Russia’s invasion of Ukraine in

early 2022, compelled governments to implement measures aimed

at reducing energy prices and mitigating their impact on both

consumers and the wider economy. We explored some of these

measures in our Electricity Market Report – July 2022 Update

, such

as the EC toolbox, the introduction of exceptional taxation and the

establishment of market regulation schemes. Since then, national

governments and the European Union have introduced new

initiatives and continue with discussions on further measures to

address the crisis. These range from non-targeted support that

generally does not distinguish by the beneficent (e.g. wholesale

price regulation, VAT/energy tax reduction or retail price regulation)

to targeted programmes such as supporting vulnerable groups or

businesses.

Several initiatives are particularly noteworthy. One example is the

berian exception, which is a form of non-targeted support that caps

gas and coal prices for power generation in Spain and Portugal.

However, since differences in national measures might distort the

European single market, efforts have been made to coordinate the

implemented measures, such as the package with emergency plans

introduced on 30 September 2022 by European Council. This

emergency response entails introducing market revenue caps and

solidarity contributions.

The Iberian model and its consequences

In June 2022, the governments of Spain and Portugal were granted

an exemption by the European Commission

hat allowed them to

cap the price of gas and coal for electricity generators. The measure

started on

June 14 and will run until May 31 2023. It limits the

maximum price of gas and coal as an input to generation at

EUR 40/MWh during the first six months and then increases by

EUR 5/MWh per month before reaching EUR 70/MWh. Thus, this

measure reduces the price of electricity and limits windfall profits of

the inframarginal electricity producers. Under the measure, gas- and

coal-fired generators are paid the difference between the market

price of the fuels and the cap, financed through

congestion rents f

cross-border trade and an extra charge to consumers with contracts

based on regulated tariffs. The exemption was granted due to the

sufficient availability of gas in the region thanks to its ample LNG

regasification capacities, and also because the potential impact on

the EU internal power market would be limited by its marginal

interconnection with the rest of Europe .

The Iberian model has succeeded in lowering electricity prices in

pain but, at the same time, it has had various other consequences.

The price cap led to an increase in gas consumption

in Spain. At the

same time, lower Spanish wholesale prices as also led to increased

and relatively cheaper power exports to neighbouring countries,

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IEA. CC BY 4.0.

Regional perspectives

which benefited Portuguese

, Moroccan, and especially French

consumers. This caused distortions in the EU internal electricity

market, as well as in Iberian spot and futures markets. These

issues, while important, were limited in scope due to the low level of

interconnection between Spain and the rest of Europe.

Coordination package by the European Council

On 30 September 2022, the Council reached an agreement on a set

of emergency market interventions. Thanks to this agreement, a

Council Regulation on emergency interventions to address high

energy prices was published on 6 October. These measures, which

are deeper and broader than previous interventions at the European

level, are a new attempt of controlling the price surge, addressing

both the supply and demand sides.

These temporary measures on the electricity markets include a

nding demand reduction of 5% during selected peak hours and a

cap on market revenues for inframarginal technologies set at a

maximum of EUR 180/MWh. This revenue cap is applicable for the

period between 1 December 2022 and 30 June 2023. As the

measures are being implemented at the national level, it is too soon

to assess their effects, and key aspects of the implementation

remain to be clarified. Some countries (e.g. France, Belgium

the Netherlands) decided to set the market revenue cap below the

maximum level, for instance, and in the case of the Netherlands at

The benefit to Portugal is due to a bigger share of Portuguese consumers with fixed contracts

and so less contribution to compensating gas generators.

EUR 130/MWh. Particularly, the interaction between the revenue

cap for inframarginal generators and forward markets, where many

of these generators may have already sold their energy, will be key

for the success of the measure.

A temporary solidarity contribution (in place until June 2023) was

also introduced, which entails additional taxation of at least 33%

the excess profits received by companies active in the petroleum,

natural gas, coal and refinery sectors during 2022. The solidarity

measure aims at capturing windfall profits without modifying the

market price, and therefore without distorting the operation and

clearing of the markets. The implementation of the solidarity

contribution mechanism is not uniform across the EU member

states. Some EU member countries, such as the Czech Republic,

Greece and Italy, have set their rates much higher at 60%, 90% and

50%, respectively, than the reference rate of 33%. The Czech

government also extended the solidarity tax not only to energy

companies, but also

to some banks. S

imilarly, Spain imposed this

tax, which was originally targeted at energy companies, to some

domestic banks.

Disparity in magnitude of support across Europe

The vast majority of countries in the European Union introduced

some form of business support. However, the targeted direct

financial supports and retail price measures differ significantly

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Regional perspectives

among the member countries. As a result, the heterogeneity of the

implemented relief measures may lead to discrepancies in the

prices perceived by industrial consumers among European

countries, harming competition.

The German industry support scheme is a part of a EUR 200 billion

energy relief plan (called Economic Defence Shield), of which

EUR 25 billion will be dedicated to the industrial scheme.

Consequently,

electricity tariffs for industrial consumers will be

capped at EUR 130/MWh for 70% of their 2021 consumption (to

motivate electricity savings) whereas the cap for residential

consumers was set at EUR 400/MWh for 80% of the 2021

consumption. In Spain,

over EUR 500 million has been dedicated to

shielding large industrial consumers. Additionally, a plan was

introduced to decrease the transmission and distribution network

fees paid by electricity-intensive industries.

The total magnitude of the financial resources dedicated to shielding

hous

ehold and industrial consumers also differ widely among

European countries. For example, while the German energy support

scheme was above 7% of the German GDP

, the subsidies in

Sweden amount to less than 0.3% of its GDP.

Shielding residential consumers via support measures

In a large majority of countries in the European Union as well as

Norway and the United Kingdom, reductions in energy taxes or VAT

were introduced. Similarly, many countries strengthened financial

transfers to vulnerable consumers. Sixteen member states of the

European Union introduced retail price regulations. Some of the

introduced measures incentivise energy consumers to reduce their

consumption while others do not, which then act as consumption

subsidies. To illustrate, the Greek government implemented an

across-the-board

relief package w

hich subsidises consumption

based on the end-user. In this scheme, households can receive up

to EUR 436/MWh (industrial consumers can receive up to

EUR 398/MWh). In Norway, a subsidy scheme was

introduced to

cover exposed industrial consumers: those with more than 3% of

their costs spent on electricity will be compensated 25% of the

electricity rate if it exceeds a threshold of about EUR 68/MWh.

The implementation of support measures in Europe have helped

dam

pen the effects of the current crisis on residential electricity

prices. Based on VaasaETT's analysis of selected European capital

cities, the measures by governments have prevented on average a

14% price spike in new household electricity contracts in 2022,

considering estimates of mean annual prices with and without

measures.

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Regional perspectives

Support measures in Europe helped dampen the impact of high prices on consumers

Magnitude of support schemes to residential and industrial

consumers in the European Union, Norway and the United

Kingdom, September 2021- November 2022

Note: Data based on a percentage of GDP in the European Union, Norway and the

United Kingdom.

Source: Bruegel (2022), National fiscal policy responses to the energy crisis,

3 December 2022.

Representative household prices including and excluding support

schemes in the European Union, June 2021 to December 2022

Notes: The household price analysis focuses on general measures affecting typical

consumers and selected capital cities which have applied such measures during the

period analysed. Electricity demand-weighted wholesale price for the following EU

countries: Austria, Croatia, Czech Republic, France, Finland, Germany, Italy, Poland,

Romania, Slovak Republic, Slovenia, and Spain. Household prices consider new tariff

offers.

VaasaETT Ltd.

0% 2% 4% 6% 8%

Germany

Malta

Lithuania

Greece

Bulgaria

Italy

Netherlands

Croatia

Slovakia

United Kingdom

Romania

Czech Republic

Luxembourg

Portugal

Latvia

France

Austria

Poland

Denmark

Norway

Slovenia

Estonia

Belgium

Cyprus

Finland

Sweden

Support scheme (% of 2021 GDP)

100

200

300

400

500

600

EUR/MWh

Household price (excluding support schemes)

Household price (including support schemes)

Weighted-average wholesale price

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Regional perspectives

European electricity-intensive industries decrease their production

Exceptionally high prices are having a significant impact on some

industrial sectors with high electricity use, which has led to a

sharper drop in national electricity consumption. Among energy-

intensive industries (e.g. chemical, iron and steel, non-ferrous metal

production, paper mills, and others), aluminium production

eems to

be hit the hardest by steep electricity prices in Europe.

Permanent downsizing of European BASF’s c

apacities due to high

natural gas and electricity prices underscore concerns about

declining competitiveness of European production. Similarly, non-

ferrous metal producers have voiced their concerns over continuing

operations with the current energy prices. For example, in August

2022,

aluminium smelters in Slovakia hal

ted their production until

energy prices reach acceptable levels. The largest aluminium

producer in Germany, Trimet,

decreased production in multiple sites

due to the high energy prices, with the production capacity in Essex

halved in March 2022. Stainless steel production stopped in

fifteen

plants across the European continent. Thus, some metal producers

have requested to be shielded by political interventions. However,

metal producers are also hit by a decrease in demand caused by

slowing economic activity. Hence, the current crisis is affecting both

the demand and supply sides.

After the Russian invasion of Ukraine, not only were European

etal producers hit by soaring energy prices, but metal supply

chain issues also occurred due to the decline of Ukrainian metal

production. As a result of the tight supply and increasing production

costs for metals in Europe, China is turning into a

metal exporter

from being a metal importer. However, higher European reliance on

critical raw material imports also raises environmental concerns, for

instance in China, where aluminium production is

three times more

carbon-intensive than in Europe.

Year-on-year growth rate of primary aluminium production in

selected regions, 2022 and 2017-2021 average

Note: See the IAI website for the country groupings for the shown regions.

Source: IEA analysis based on International Aluminium Institute (IAI) (2022),

Primary

Aluminium Production, 1 December 2022.

-15%

-10%

-5%

10%

North America China Asia excl. China Western &

Central Europe

Average 2017-2021 2022

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Regional perspectives

Germany

Germany’s electricity demand declined by 4% in 2022 amid higher

prices, public calls to save energy

and a

n exceptionally mild winter.

Renewable power generation rose 9% from 2021, when it was

lower than average due to reduced wind speeds. The expansion of

renewable capacity also continued in 2022. In particular,

solar

power installation accelerated, driven by private investments in the

wake of high electricity prices.

Low water levels on the Rhine dur

ing the summer of 2022 disrupted

the transport of coal to plants located along the river, causing a

reduction in their output during the period. Despite this, and the

growth in renewable generation, coal-fired power generation in

Germany increased by more than 10%. for the second year in a row

in 2022, lifting the power sector’s coal use above 2019 levels.

Several factors contributed to this. The natural gas supply shortage

in Europe, resulting in high gas prices, made coal a comparatively

cheap source of electricity. At the same time, low availability of

nuclear power plants in France led to higher imports from Germany

in 2022. Nevertheless, coal fired-generation in Germany was still

much lower (-20%) than its average during the period 2015-2019.

Germany activated a gas replacement reserve f

rom fossil fuel

power plants that are not gas-fired on 13 July 2022. This includes

4.3 GW of hard coal and 1.6 GW of oil-fired plants until

31 March 2024, which were previously put in grid reserve. In

addition, about 1.9 GW of lignite-fired capacity – originally planned

to be decommissioned by 1 October 2022 – was brought back

from the security readiness reserve. These plants will remain

operational until 30 June 2023.

A further 2.2 G

W of hard coal-fired plants that was slated to be

decommissioned by 31 October 2022 according to the auctions

under the Act of Phasing Out Coal-fired Power Stations

and about

0.5 GW of hard coal capacity that would similarly be

decommissioned by 1 July 2023 have had deadlines extended until

31 March 2024. Additionally, 1.2 GW of lignite-fired capacity that

would have to be decommissioned by 31 December 2023 will also

be extended until 31 March 2024.

Germany’s remaining 4.1 G

W of nuclear capacity, initially set to be

shut down at the end of 2022, was put in emergency reserve

instead, allowing it to run during the winter until April 2023.

However, the plants will not be refuelled and therefore have a

reduced total output of an estimated 5 TWh for the duration of the

extension. In 2022, nuclear power provided about 6% of Germany’s

total electricity generation.

In 2023,

we expect coal-fired generation to increase another 4%, as

more of the reserve capacity will be operational while gas prices are

set to remain high. Renewables are set to grow strongly by 12%,

while gas-fired generation similarly records a sharp decline of 15%.

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Regional perspectives

Evolution of the German gas replacement reserve, 2022-2024

Source: IEA analysis based on data from BNetzA (2022), Power plant list

15 December 2022; ENTSO-E (2022), Transparency Platform, 15 December 2022.

In 2024-2025, we expect Germany to fully return to its coal phase-

out plan and, hence, coal-fired power generation to decline. By

then, renewable power generation is forecast to grow significantly,

driven by increased renewable

argets, reduced bureaucratic

hurdles and high energy prices. The government aims to install a

total of 38 GW of solar capacity, 19 GW of onshore wind and

3.5 GW of offshore wind capacity from 2023 to 2025. Acceleration

of the permitting procedures and grid build-out will be important

factors to achieve these targets. While our forecast shows Germany

will likely continue to be a net exporter of electricity also in 2023

after 2022, the likelihood increases significantly that it switches from

being a net exporter of electricity to a net importer from 2024

onward.

France

After posting a 5% recovery in electricity demand back to pre-

pandemic levels (475 TWh) in 2021, demand declined by 4.5% in

2022. This was principally driven by higher energy prices amid the

energy crisis in Europe and – despite lawmakers approving a 4%

annual price increase cap on electricity bills in 2022 – as well as by

the mild winter.

Total electricity generation fell by a sharper 15% (-83 TWh) in 2022,

where nuclear reactors produced almost a quarter less (-87 TWh)

than the year before, slightly offset by a 30% increase (+9.5 TWh)

in gas-fired power generation. France also became a net importer of

electricity for the first time in more than two decades, to cover about

4% (18 TWh) of its needs. Power generation from renewables

decreased by 4% in 2022, due to lower hydropower generation than

in 2021.

France’s supply imbalance stems from the nuclear fleet undergoing

continuous maintenance work since 2014, slowed further by safety

obligations in 2020-2021 and exacerbated by corrosion problems

that led to longer maintenance and unplanned shutdowns of 12

additional reactors (about 15 GW). This represents about 17% of

the peak load observed in 2021. In November 2022, out of the 56

total nuclear reactors, 26 were offline. Above average temperatures,

Hard coal Lignite Oil

3.9 GW of already

operational lignite

and hard coal

capacity have their

decommissioning

dates extended to

31 March 2024

Activating

plants

from the

reserve

started in

Aug 2022

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Regional perspectives

along with droughts and heat waves, further magnified the electricity

generation shortfall by creating cooling issues at nuclear reactors

and markedly lowering hydroelectricity output, with reserves

depleted in 2022 to below historical lows.

Several recent developments in France are set to improve its

demand-supply balance in the 2023-2025 period. The country is

aiming to reduce its primary energy consumption

10% by 2024

compared to 2019, with emergency measures announced during

the summer to both accelerate the development of renewable

sources of electricity and to enhance energy security. France’s first

commercial-scale offshore wind farm, with a capacity of 480 MW,

became fully operational in November 2022. Additionally, the coal-

fired power station Saint-Avold (0.5 GW) was temporarily restarted

in November 2022 to boost winter electricity supplies.

In 2023, despite the setbacks experienced by EDF in restarting all

its reactors in 2022, nuclear power is expected to reach a gross

output of 326 TWh (+11% y-o-y). Power generation from fossil-fired

sources is expected to decrease by more than 40%, down to

33 TWh. A 7% growth in French power generation is expected, with

a decline in imports. Start of operation of Flamanville 3 is expected

to be delayed to Q4 2024

On top of the 10% primary energy consumption decrease target by

2024, the French government’s longer-term objective is to be

carbon-neutral by 2040 with a

40% reduction in energy

consumption.

Italy

Italy’s electricity consumption fell by 2% year-on-year in 2022.

All-time high electricity prices weighed on industrial and commercial

activity, resulting in slower GDP growth which in turn slowed

electricity consumption. In addition, milder temperatures in Q4 2022

reduced space heating requirements in the residential and

commercial sectors. Energy efficiency improvements and slower

economic growth are set to weigh on electricity consumption going

forward. Italy’s electricity demand is set to fall at an average annual

rate of 1% in 2023-2025, and it is not expected to recover to 2022

levels throughout this period.

Dry weather led to a steep drop in Italy’s hydropower generation in

2022, down by 35% (-16 TWh) compared to 2021. Wind power

generation fell y-o-y by 3%. This was only partly compensated for

by higher solar PV generation, increasing by 11% (+3 TWh). Lower

renewables output contributed to higher thermal generation. Coal-

fired generation rose by 50% (+8 TWh), while gas-fired electricity

decreased by 2% (-2 TWh) compared to 2021.

We expect renewable output to rise by 20% (+20 TWh) by 2025

compared to 2021 levels. This will be primarily driven by strong

growth in solar PV. Lower electricity use, together with rapidly

expanding renewables, will reduce Italy’s reliance on thermal

power. Coal is set to be phased out by 2025, while gas-fired

generation is expected to fall at an average rate of 4.5% per year

between 2023 and 2025.

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Regional perspectives

Spain

Electricity demand in Spain increased by 3.5% in 2021, but was still

below 2019 pre-pandemic levels. However, electricity demand fell

by 2.6% to about 243 TWh in 2022, mainly due to demand

destruction related to high prices.

Despite this, power generation in 2022 increased by 6% (+16 TWh)

year-on-year, surpassing 285 TWh. Royal Decree-Law 10/2022,

also known as the "gas cap" or "Iberian exception", entered into

force on 15 June following its presentation to the European Council

on 26 March. In 2022, the Iberian exception has resulted in Spain

achieving lower wholesale prices at the expense of increasing

electricity exports, and boosting gas-fired generation by about 25%

(+18 TWh) above 2021 levels.

Coal-fired power generation rose by about 50% (+3 TWh), in 2022,

but still accounted for only 3% of electricity generation. Power

generation from solar PV increased by about 23% y-o-y (+5 TWh) in

2022. Solar PV reached an installed capacity of 20 GW, surpassing

hydro as the technology with the third-highest installed capacity. An

unusual event was seen this year, with a sharp drop in solar PV

electricity output in March due to the haze coming from the Sahara

Desert that affected the Iberian Peninsula. This led to a decrease of

14% (-0.2 TWh) compared to the same month of the previous year.

At the same time, record drought in Spain

dec

reased hydro

generation by more than 30% y-o-y in 2022. The aforementioned

cap on gas prices resulted in a further y-o-y decline in power

generation from CHP plants by 23% (-3 TWh), considering the

January-August 2022 period, since these facilities were not eligible

for the cap until an

announcement from the Spanish Government on

6 September.

Another series of measures, included in the recent More Energy

Security Plan, have been taken to better protect consumers,

including electricity-intensive industry, whose access charges have

been

reduced by 80%. Additionally, there has been a temporary

reduction of VAT for gas prices from 21% to 5% as well as the

creation of a new mechanism to manage demand in the event of

excess electricity consumption.

We expect electricity use to decrease by about half a percent during

2023,

before growth recovers to 1% annually in both 2024 and

2025. During that three-year period, we forecast total renewable

output to increase by over 15% annually, together with a moderate

rise in electricity imports. As a consequence of lower utilisation

rates for thermal generation plants due to higher renewable output

and lower gas-fired exports, CO

emissions will drop by close to

60% in 2025 compared to 2022 levels.

United Kingdom

After increasing by 1.7% in 2021, electricity consumption in the

United Kingdom declined by almost 5% in 2022, driven by energy

saving measures, high energy prices, sluggish economic growth,

and milder temperatures. 2022 saw a year-on-year decline of coal-

fired power (-20%), whereas gas rose 3% and nuclear increased by

2%. Renewable generation grew by 6%.

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Regional perspectives

Concerns for security of electricity supply over the winter led system

operator National Grid ESO to take a number of actions. In August it

secured emergency contracts

o keep coal-fired plants available

during the winter months. In early October 2022, they warned

consumers about

winter power outage risks i

n a worst-case

scenario. Later in the month, they announced financial incentives

for consumers to shift their electricity consumption.

In 2022, the United Kingdom also became a net electricity exporter

on an ann

ual basis for the first time on record, which accounts for

the positive net change in higher generation despite a decline in

domestic demand. Continental Europe increased purchases of

wholesale power from the United Kingdom to offset sharply lower

European nuclear and hydro power output in 2022 and also to take

advantage of cheaper UK wholesale electricity prices. UK prices

were relatively lower as comparatively lower gas prices than in

continental Europe due to excess regasification capacity fuelled

higher gas-fuelled generation, and combined with record-breaking

renewable electricity, supported exports. As a result, the United

Kingdom became a net electricity exporter in Q2 2022, which was

the first quarter with net exports in 12 years, with flows particularly

strong to France. Later in 2022, during September, the United

Kingdom sent exports to Norway, which was affected by low hydro

availability. By the end of 2022, the United Kingdom had a total net

export balance of about 5 TWh.

As of October 2022, Great Britain’s

interconnector capacity stands

at 8.4 GW (4 GW with France, 1.4 GW with Norway, 1 GW with

Belgium, 1 GW with the Netherlands, 500 MW with Ireland and

500 MW with Northern Ireland). However, the UK-France IFA1

interconnector (2 GW nominal capacity) suffered fire damage in

September 2021, which left it operating at partial capacity. After

repair works, the interconnector began to operate again at full

capacity by the end of January 2023.

Great Britain continues to strengthen its electricity interconnections,

ith capacity set to almost double by 2025

. Capacity is set to reach

almost 16 GW, with the commissioning of interconnectors both with

Germany and Denmark (1.4 GW each), and additional capacity with

France (2.8 GW), Ireland (0.5 GW) and Norway (1.4 GW).

For the 2023-2025 period, we forecast electricity consumption in the

nited Kingdom to grow by around half a percent per year on

average. We expect demand to decline in 2023 with a slight

recovery in 2024 and 2025. In these three years, electricity

generation from gas and nuclear energy is expected to decline. Due

to high gas prices, coal-fired generation is forecast to remain at just

above 5 TWh in 2022 and 2023 (less than 2% of the electricity mix),

then drop to almost zero by 2025. Finally, from 2023 to 2025,

renewable output is expected to grow by an average of more than

10%, led by wind and solar PV power additions, supported by the

Energy Security Strategy

In 2022, the United Kingdom launched a consultation for the Review

of Electricity Market Arrangements with the aim of ensuring the UK

power market is fit for purpose to support the national goal of a fully

decarbonised power supply by 2035.

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Regional perspectives

Republic of Türkiye

Türkiye’s electricity demand rose by 2% (+6 TWh) year-on-year in

2022. This was supported by strong GDP growth of 7.5% y-o-y in

the first half of 2022 and an estimated 5.5% for the full year. The

country’s electricity demand is expected to increase at an average

rate of close to 2.5% per year over the 2023-2025 period, supported

by expanding economic and industrial activity.

Following the drought of 2021, Türkiye’s hydropower output rose by

20% (+11 TWh) in 2022, recovering close to its 2020 levels. Wind

and solar generation expanded by 12% (+4 TWh) and 80%

(+1.2 TWh), respectively. As a consequence, the share of

renewables in total power generation rose to 42% compared to 35%

in 2021. Higher renewables-based generation weighed on thermal

power, although gas- and coal-based generation posted differing

results. The rapid increase in natural gas import prices led to gas-

to-coal switching dynamics in the power sector. While gas-fired

power generation fell by over 25% (-27 TWh) in 2022, coal-fired

output rose by 8% (+8 TWh) in 2022 compared to the previous

year. Improved hydro availability allowed Türkiye to export close to

2 TWh of electricity into neighbouring markets. By contrast, the

country imported about 2 TWh in 2021.

Türkiye announced at COP27 that it

increased its 2030 emissions

reduction target from 21% to 41%. We forecast that Türkiye’s power

generation will increase at an average rate of 2.5% per year over

the 2023-2025 period. Renewable generation is expected to

increase by almost 30% by 2025 compared to 2022, and will

account for almost half of the power generation mix. The first

reactor of the Akkuyu Nuclear Power Plant is expected to be

commissioned by the end of 2023 and gradually ramp up production

through 2024-2025. Fossil-based thermal generation is forecast at

15% below its 2022 levels by 2025. Over the 2023-2025 period,

coal- and gas-fired generation are expected to decline by an

average rate of 8% and 3% per year, respectively, reducing the

emission intensity of Türkiye’s power sector.

Ukraine

Since the invasion of Ukraine by Russia in February 2022,

electricity consumption has plummeted. It was cut by one-forth

within a week and by 40% two months later. Demand profiles

clearly highlight both the start of the war on 24 February and the

intensification of missile strikes on Ukraine since 10 October

, w

hich

led to massive destruction of infrastructure and power outages.

Between March and end October 2022, electricity consumption fell

by about 30% year-on-year.

The s

ecurity of Ukraine’s nuclear facilities almost immediately

became a serious issue after the invasion, in particular for the 6 GW

Zaporizhzhia nuclear power plant, whose grid connection was lost

on multiple occasions since the Russian army attack on 3

March.

The plant stopped injecting power into the Ukrainian power grid on

25 August 2022

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Regional perspectives

Another factor influencing the share of nuclear power in the

Ukrainian generation mix is the ability to export excess power to

European neighbours. Ukraine and Moldova were synchronised

with the continental European grid on 16 March. Trading with

European neighbours started on 30 June, with capacity gradually

rising in 100-150 MW increments. On 15 October, TSOs set the

export limit of Ukraine/Moldova to 400 MW and the import limit to

500 MW. The power exchange between Ukraine/Moldova and

continental Europe is beneficial for both parties; with increased

financial revenues for the former and help in balancing tight

electricity markets for the latter. While Ukraine was initially exporting

power in the face of a depressed demand, the situation changed

following the infrastructure damage on 10 October. Following that,

electricity exports were banned

Ukrainian authorities to ensure

local demand was met. Moldova swiftly received support from EU

neighbours (e.g. Romania and others) to fill the gap of the lost

electricity imports from Ukraine (which used to cover

30% of

Moldova’s electricity demand).

The outlook for future developments is highly uncertain. The end of

the war is not yet in sight and many factors may influence the post-

war recovery, including the state of the energy infrastructure. More

than half of

the Ukrainian energy infrastructure was destroyed at the

end of 2022.

Monthly electricity consumption in Ukraine and the evolution of

allowed trade capacity Ukraine/Moldova and continental Europe,

2021-2022

Notes: The maximum allowed exchange capacity does not include the already existing

export capacity to Poland of approximately 215 MW from the Ukrainian Dobrotvirska

power plant. Other changes in the allowed exchange capacities might have occurred

after 15 October 2022.

Sources: UKRENERGO

(consumption data available until 27 October 2022) and

ENTSO-E (export).



30/06

30/07

23/09

15/10

100

150

200

250

300

350

400

Jan Feb Mar Apr May Jun Jul Aug Sep Oct

TWh

2021 Electricity consumption

2022 Electricity consumption

Agreed trade capacity Ukraine/Moldova to

continental Europe in 2022 (right axis)

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Regional perspectives

Renewables lead generation growth in most large European countries until 2025

Year-on-year change in electricity generation in selected countries in Europe, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 100

- 80

- 60

- 40

- 20

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

Germany France Italy Spain United Kingdom Türkiye

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Regional perspectives

IEA. CC BY 4.0.

Eurasia

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Eurasia’s electricity demand growth slowed in 2022 amid the worsening economic outlook

Russia’s war in Ukraine has cast a long shadow over its domestic

macroeconomic outlook and could have negative spillover effects

on other countries in the region who share close economic or

political ties with Russia.

Eurasia’s electricity consumption increased by an estimated 1.5%

(+24 TWh) year-on-year in 2022 – a marked slowdown compared to

the record growth of 75 TWh in 2021. Over 70% of incremental

electricity demand was concentrated in the first half of the year.

Electricity consumption growth slowed to below 1% y-o-y in the

second half of the year amid the worsening economic performance.

Fossil-based thermal generation rose by over 3%, offsetting lower

hydropower output and meeting the incremental electricity demand.

The region’s electricity demand growth is expected to slow to an

average annual rate below 1% from 2023 to 2025.

Fossil-fired generation is set to continue to dominate Eurasia’s

electricity mix, at a share of around 65% over the 2023 to 2025

forecast period. While the deployment of renewables remains slow

at the current pace, the commissioning of new nuclear plants,

including in Belarus and Russia, is set to slightly reduce the CO

intensity of power generation over our forecast period.

Russia

Russia is by far the largest power consumer in Eurasia, with annual

consumption of over 1 000 TWh, and accounts for just over three-

quarters of the region’s electricity demand.

Russia’s electricity consumption grew by over 6% in 2021, or close

to 60 TWh – its highest increase in absolute terms since the demise

of the Former Soviet Union. This was largely supported by a strong

economic recovery (the country’s GDP grew by 4.7%) and adverse

weather conditions, i.e. a cold and long winter season. Power

generation rose by 6.3% (+69 TWh), largely supported by the

country’s significant thermal fleet. Gas-fired power generation

surged by over 10%.

Russian electricity consumption is estimated to have increased by

1.5% (+16 TWh) in 2022. Demand growth was almost entirely

concentrated in the first half of the year, when it rose by 2.2% y-o-y.

Depressed industrial and commercial activity moderated electricity

demand growth to 0.7% year-on-year in Q3 and Q4 2022.

In 2022, fossil-fired generation – including coal, natural gas and fuel

oil-fired power plants – rose by over 3% (+24 TWh) compared to

2021 levels and accounted for over 60% of total power supply. The

strong growth was primarily supported by lower hydro output, which

fell by 8% (-17 TWh) y-o-y.

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IEA. CC BY 4.0.

Russia’s power generation capacity increased by a marginal 0.5%

y-o-y through the first ten months of 2022. Gas-fired generation

capacity grew by close to 1 GW, more than compensating for a

reduction of 0.3 GW capacity in coal-fired power plants. Nuclear

and hydropower generation capacity remained stable, while solar

power capacity was up by close to 8% (+0.25 GW).

In Russia, lower industrial and commercial activity is expected to

weigh on electricity demand growth. The country’s generation mix is

set to remain broadly unchanged over the medium term, with fossil-

fired generation maintaining its share of over 60%. There are

currently two nuclear reactors under construction and expected to

come online before 2026, Kursk II-1 and Kursk II-2, with a combined

capacity of 2.5 GW. They are expected to be commissioned over

2023-2024 and will match the retirement of the first two old Kursk

units. Russia is also undertaking a large-scale modernisation

programme of its thermal fleet, with the target to refurbish over

20 GW between 2022 and 2026. According to initial estimates, this

could decrease the carbon footprint of Russia’s power system by

5%. In 2022, power generation companies requested to postpone

the modernisation of 26 thermal power plants (with a combined

capacity of close to 6 GW) by one year or a year and a half in some

cases. This is primarily due to the delayed delivery of gas turbines

due to Western sanctions imposed on Russia’s technology

procurement.

Kazakhstan

Kazakhstan is the second largest electricity consumer in Eurasia,

with annual demand of over 100 TWh. Electricity consumption rose

by 7% (+7 TWh) in 2021, driven by a recovery in industrial and

commercial activity. Higher demand was primarily met by fossil-fired

generation, which increased by 2% (+2 TWh) and compensated for

the decline in hydro output of 9% (-0.6 TWh).

Power generation fell by an estimated 1% (-1.1 TWh) in 2022 amid

slower economic growth. According to preliminary data, fossil-fired

generation declined by over2% (-2 TWh) y-o-y in 2022 .

Hydropower outputremained broadly flat compared to 2021. .

Kazakhstan’s electricity demand is forecast to increase by 1.7% per

year over the 2023-2025 forecast period, largely to be met by

expanding gas-fired power generation and renewable sources of

electricity supply. According to the country’s development plan for

the natural gas sector, published in July 2022, gas consumption in

the power sector is expected to rise 55% by 2025 from 2022 levels.

This would translate into an estimated 14 TWh of gas-based

electricity supply. While the growing share of renewable and gas-

based generation is set to reduce the power sector’s emissions

intensity, coal-fired generation will retain its dominant position,

accounting for more than half of the generation mix in 2025.

Other Eurasia

Similar to Russia and Kazakhstan, electricity consumption also

grew strongly (over 6% y-o-y) in other Eurasian countries in 2021,

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Regional perspectives

IEA. CC BY 4.0.

supported by recovery in economic and industrial activity after the

start of Covid-19 in 2020. Preliminary estimates indicate that

electricity demand growth in those markets slowed to around 4% in

2022.

In Uzbekistan, the region’s third largest electricity consumer,

electricity demand rose by 7% (+4.1 TWh) in 2021 and declined by

an estimated 1% in 2022. In the first eleven months of 2022,

Uzbekistan commissioned six thermal power plants with a

combined capacity of 1.4 GW and one solar power generation

complex with a capacity of 100 MW. According to the Ministry of

Energy, the new and more efficient power plants could save around

1.5 bcm of natural gas per year by replacing older units. Uzbekistan

continues to face electricity supply cuts due to natural gas supply

shortages for power plants. Natural gas output fell by 4% (-2 bcm)

y-o-y in 2022 due to ageing fields with rapidly deteriorating

production rates. As of mid-November 2022, Uzbekistan stopped

natural gas exports, with officials suggesting a supply-demand gap

of 20 mcm/d in the country.

In gas-rich Turkmenistan electricity generation rose by an

estimated 11% y-o-y in 2022, largely driven by the country’s

electricity exports, which increased by 30% compared to 2021.

These strong export gains were due to growing output from the

giant gas-fired power plant complex in the Mary province. For 2022,

Turkmenistan had planned exports of around 9 TWh of electricity

into neighbouring markets, including Afghanistan, Iran, Kyrgyzstan

and Uzbekistan. Turkmenistan started electricity exports to

Kyrgyzstan in August 2021, with deliveries rising to 1.7 TWh in the

first half of 2022. In October 2022, Turkmenistan and Uzbekistan

agreed to ramp up electricity supplies to 4 TWh/yr, which could

improve electricity supply security in Uzbekistan.

In Azerbaijan, electricity consumption grew by 7% (+1.5 TWh) in

2021, largely supported by the strong growth in fossil-fired

generation (up by 5%). Electricity demand grew by 4% y-o-y in

2022, supported by the economic growth. The country’s generation

mix continues to be dominated by gas-fired thermal generation.

Electricity demand in Eurasia (excluding Kazakhstan and Russia) is

expected to increase at an average growth rate of 2% per year over

the 2023-2025 forecast period. This will be largely supported by the

region’s rising population and economic expansion, although the

region’s macroeconomic outlook has worsened since Russia’s

invasion of Ukraine.

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IEA. CC BY 4.0.

Russia’s bleak economic outlook weighs on Eurasia’s electricity demand growth

Year-on-year relative change in electricity demand, Eurasia, 2019-2025

IEA. CC BY 4.0.

-2%

-1%

2019

2020

2021

2022

2023

2024

2025

Electricity demand growth

Historical demand Updated forecast Previous forecast (July 2022)

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IEA. CC BY 4.0.

Gas-fired power generation dominates incremental electricity supply in Eurasia

Year-on-year change in electricity generation, Eurasia,

2019-2025

IEA. CC BY 4.0.

Development of average CO

intensity, Eurasia, 2019-2025

IEA. CC BY 4.0.

Notes: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 60

- 40

- 20

100

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

150

200

250

300

350

400

450

g CO

₂/kWh

Eurasia

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Middle East

IEA. CC BY

4.0.

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IEA. CC BY 4.0.

Middle East electricity demand to grow 2% annually in 2023-2025 while CO

intensity declines

Electricity demand in the Middle East grew by about 4% in 2021

following a 1% decline in 2020 due to Covid-19 lockdowns.

Members of the Gulf Cooperation Council (GCC) – particularly

Saudi Arabia, Iraq, Oman, and the United Arab Emirates (hereafter

“UAE”) – saw the strongest absolute increases in electricity

consumption. However, lower-income countries in the region –

including Iraq, Lebanon and Iran – experienced periodic electricity

shortages throughout the year 2021.

We estimate that electricity consumption rose by 2.6% in 2022

across the region and expect growth to continue at a similar but

slightly reduced rate in the 2023-2025 forecast period. Electricity

demand in the Middle East is primarily driven by a growing

population, rising demand for cooling and water desalination, and

the continued expansion of energy-intensive industries. In the near

term, power demand will receive additional support from surging

GDP growth and higher public spending in the region’s leading oil

and gas exporters amid the current high energy price environment.

Multiple projects to enhance regional interconnections progressed

in 2022: a 150 MW line

to export power from Jordan to Iraq in 2023

started construction in 2021, a 3 GW interconnection between

Saudi Arabia and Egypt secured financing, and an agreement on a

1.8 G

W direct link between Iraq and the GCC grid (via Saudi

Arabia) was reported to have been finalised.

Gas remains the dominant fuel for electricity production across the

egion, and its share in total generation is on course to increase

from 72% in 2022 to 77% by 2025 as it captures market share from

both oil- and coal-fired generation. The share of oil in the generation

mix is set to drop from 21% to 14% between 2022 and 2025, led by

steep declines in Saudi Arabia, Iraq, Iran and Kuwait in particular.

Coal is projected to see its share diminish from 1% to just under

0.3% over the same period due to Israel’s decision to phase out

coal-fired generation by the end of 2025 and the recent conversion

of the new Hassyan power plant in the UAE from coal to gas.

Nuclear generation is expected to nearly double between 2022 and

2025, reaching 50 TWh (or 3.5% of total generation) by the end of

our forecast period, as the UAE’s Barakah nuclear plant ramps up

to full capacity. Renewable generation (led by solar PV) is set to

increase by 50% from 2022 levels and account for more than 5% of

total generation by 2025. The biggest increments are expected in

Saudi Arabia, Israel, Oman and the UAE, while the rollout of

renewables in the rest of the region remains slow or non-existent.

Annual power generation emissions increased only marginally (by

around 0.7%) in 2022 as higher gas-related emissions were largely

offset by lower emissions from oil- and coal-fired output. Total

power generation emissions are set to fall by 2% between 2022 and

2025 to around 710 Mt CO

. The biggest emission declines are

expected in the UAE (thanks to the rapid rise of renewables and the

ramp up of nuclear output), Israel (due to the phase-out of coal) and

Saudi Arabia (as a result of a steep drop in oil-fired generation).

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However, these declines are partly offset by growing emissions in

the rest of the region, mainly due to rising gas-fired generation.

The regional CO

intensity of power generation fell by nearly 2% in

2022, reaching about 540 g CO

/kWh. It is on course to drop by

another 7% in 2025 compared with 2022 levels, as the share of coal

and oil declines while the share of nuclear and renewables

increases in the region’s electricity mix.

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Electricity demand growth in the Middle East moderates in 2022-2025 following the 2021 spike

Year-on-year relative change in electricity demand, Middle East, 2019-2025

IEA. CC BY 4.0.

-2%

10%

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

Middle East Saudi Arabia United Arab Emirates

Electricity demand growth

Historical demand Updated forecast Previous forecast (July 2022)

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Gas-fired generation is set to continue to be the largest source of additional supply to 2025

Year-on-year change in electricity generation, Middle East,

2019-2025

IEA. CC BY 4.0.

Development of average CO

intensity, Middle East, 2019-2025

IEA. CC BY 4.0.

Notes: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 60

- 40

- 20

2019

2020

2021

2022

2023

2024

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

200

300

400

500

600

700

g CO

₂/kWh

Middle East Saudi Arabia United Arab Emirates

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Saudi Arabia

Saudi Arabia’s electricity consumption rose by 5.5% in 2021

(following a Covid-induced dip of 0.8% in 2020) with commercial

users and public sector entities registering the strongest recovery.

In the first half of 2022, power demand was up by 2.3% y-o-y, led

higher by commercial, government and industrial consumption as

well as water desalination. For 2022, we estimate electricity

demand increased by 2%. However, the average growth rate is

expected to slow to around 1% per year in the 2023-2025 forecast

period, as the demand boost from new grid connections is tempered

by earlier price reforms in 2018 (when tariffs for some residential

users were increased by as much as 260%). Moreover, a smart

meter rollout is proceeding rapidly, with more than 10 million

installed in 2020 and 2021 alone. This can potentially help increase

energy efficiency.

Saudi Arabia’s total generating capacity stood at 83 GW at the end

of 2021, which included 710 MW of renewable capacity. The Saudi

Electricity Company, the country’s state-owned power utility, plans

for the addition of another 2.1 GW of solar capacity and 7.2 GW of

combined-cycle gas turbine (CCGT) capacity by private operators

during the 2022-2025 period. We expect gas-fired generation to

increase by nearly 30% (+67 TWh) from 2021 to 2025, supported

by a string of high-profile gas developments (namely Hawiyah,

Tanajib, and the initial phase of the Jafurah unconventional gas

project), which are scheduled to begin operating between 2023 and

2025. At the same time, we project oil-fired output to decline by

35% (-57 TWh) and its share in total generation drops from 39% to

25% by 2025 as higher gas burn in new and existing thermal plants

reduce costly oil-fired power in the generation mix. Renewable

generation, though growing rapidly, is expected to account for less

than 3% (11 TWh) of Saudi Arabia’s total generation in 2025. The

most notable renewable projects in the pipeline include the Sudair

(1 500 MW), Jeddah (300 MW) and Rabigh (300 MW) solar

developments.

United Arab Emirates

In the UAE electricity consumption increased by 9% in 2021

following a slump of about 1% in 2020 due to Covid-related

restrictions. Growth has continued in 2022 as well. The Dubai

Electricity and Water Authority (DEWA), which serves about 35% of

UAE demand, reported a strong 5% year-on-year growth in the first

nine months of 2022. For the whole country, we estimate total

demand growth in 2022 was slightly below 3%. We anticipate total

electricity consumption to expand at a 2% annual average rate in

the 2023-2025 period on the back of strong economic growth

(averaging about 4% per year, according to the IMF).

Installed generation capacity across the UAE reached 35 GW in

2021, of which 31 GW was gas-fired, 2.6 GW solar and 1.4 GW

nuclear. Following the grid connection of 4.2 GW of nuclear,

3.6 GW of gas-fired and 4.8 GW of solar capacity during the 2022-

2025 period, the respective shares of gas, renewables and nuclear

in the generation mix are projected at 64%, 10% and 26% by 2025.

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Gas fuels most of the additional generation in Saudi Arabia, nuclear increments lead in the UAE

Year-on-year change in electricity generation in selected countries in the Middle East, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 30

- 20

- 10

2019

2020

2021

2022

2023

2024

2025

2019

2020

2021

2022

2023

2024

2025

Saudi Arabia United Arab Emirates

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

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Market trends in selected Middle Eastern countries

Kuwait’s installed generation capacity stood at just over 20 GW at

the end of 2021, of which 84% (17 GW) was simple steam or gas

turbine, 15% (3 GW) was CCGT and only about 0.3% (70 MW)

was renewable capacity. While the government has plans to add

9 GW of gas-fired and 5 GW of solar capacity by 2030, stalled

progress on these projects means they are unlikely to be added to

the generation mix before 2026. Electricity consumption is

expected to grow at an average annual rate of 2% between 2022

and 2025, driven by increasing demand for cooling and water

desalination.

Israel’s electricity consumption rose by 1% in 2021 (following

minimal growth in 2020) and is expected to grow by 3% per year

on average during the 2022-2025 period, driven by population

growth, rising water desalination requirements and the

electrification of energy end-uses. Gas-fired generation in 2025 is

projected to be 30% above 2021 levels (increasing 4 TWh/yr),

thanks to the ramp up of the Karish gas field in 2022-2024, whose

production is solely dedicated to the domestic market. Renewable

output in 2025 is set to reach 15% of the generation mix following

a 110% (+6 TWh) increase from 2021 levels, while coal-fired

power drops to close to zero by the end of 2025. This is in line with

the government’s plan to phase out all coal-fired power and

convert the remaining coal plants to natural gas by 2025.

Qatar’s electricity demand grew by about 5% in 2021 following a

small 1% decline in 2020. We expect demand to grow at an annual

average of 3% during the 2022-2025 period, driven by population

growth, rising demand for cooling and water desalination, and

expanding infrastructure. Incremental generation will mainly come

from gas (on top of Qatar’s 10.6 GW of existing gas-fired

capacity), but solar projects adding 1.7 GW of capacity between

2022 and 2025 are set to contribute 4% of the generation mix by

2025.

Oman’s electricity consumption posted a sharp 8% rebound in

2021 (after a 2% drop in 2020) and is projected to rise at an

annual average of 2.6% over the 2022-2025 period. The

government plans to add 1.9 GW of renewable capacity by 2026

(on top of the existing 550 MW of grid-connected capacity) to meet

growing demand and reduce dependence on gas-fired generation,

but only 1 GW of this is slated to come online by 2025. We

estimate that the share of gas in total generation will decline from

97% in 2021 to 87% in 2025, while the share of renewables is on

course to rise from below 2% in 2021 to around 11% by 2025.

Oman’s long-term plans target a renewable generation share of

39% by 2040. In an effort to increase system-wide efficiency and

support energy transition goals, the government of Oman

launched the first spot electricity market in the Middle East in

2022.

Jordan’s total electricity demand rose by about 2% in 2021 (after

remaining flat in 2020) and we expect it to grow at an annual

average of 2.6% in the 2022-2025 period. In 2021, 77% of total

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generation was fuelled by gas, 23% by renewables and under 1%

by oil. Of the country’s 6.2 GW of installed capacity, 3.7 GW (60%)

was thermal capacity (capable of burning oil or natural gas) and

2.5 GW (40%) was renewable. The government’s long-term plan

calls for a 50% renewable share in the generation mix by 2030; we

forecast a 26% renewable share to be achieved by 2025.

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Africa

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Africa’s electricity consumption growth is set to accelerate to 2025

Electricity demand in Africa increased by an estimated 5.7% in

2021, rebounding from a 3.3% decline in 2020 due to the Covid-19

pandemic impact on the economy. We estimate that electricity

demand in the region grew by 1.5% in 2022, down from our

previous forecast of 4%. Russia’s invasion of Ukraine triggered a

downward revision in economic growth prospects in Africa due to a

combination of record-level energy prices and high inflation rates,

which weighed heavily on our forecast for electricity demand across

the region. In addition, electricity consumption in South Africa was

revised lower – the continent’s largest electricity consumer –

because of production capacity constraints that turned out to be

worse than previously expected.

Natural gas-fired output, which accounted for an estimated 42% of

Africa’s electricity generation in 2022, remained stable in volume

compared to 2021. However, coal and nuclear (accounting for a

respective 27% and 1% share of Africa’s generation mix) both saw

their output decline in relation with supply shortages, while oil-fired

generation (5% of the mix) jumped by an estimated 24% year-on-

year. Supply from renewables (24% of the generation mix)

increased by 2% in 2022.

Electricity demand growth on the continent is expected to rebound

in 2023 to over 3%, thanks to an improvement in South African

production capacity as well as slightly enhanced macroeconomic

conditions, followed by an average 4.5% regional growth for 2024

and 2025.

The large majority of incremental generation to 2025 will come from

renewable sources, followed by natural gas. We expect electricity

delivered from renewable sources to increase by over 60 TWh in

2023-2025, to reach almost a 30% share of total generation by the

end of the forecast period (from 24% in 2021), replacing coal as the

second largest source of electricity in Africa.

Natural gas is expected to remain the largest source of electricity in

Africa through 2025, rising by around 30 TWh from 2022 to 2025, to

close to 400 TWh. However, despite this increase, gas sees its

share in the power generation mix decline slightly from 42% to 41%

over the same period as renewables expand. Coal-fired electricity

generation is expected to remain stable in output at around

240 TWh, declining in terms of share from 28% in 2021 to 24% in

2025.

The declining share of fossil-fuelled generation to 2025 results in

lower power generation CO

intensity in the region by the end of our

forecast period. We expect CO

intensity to decrease from about

540 g CO

/kWh in 2021 to around 500 g CO

/kWh in 2025. In the

same period, electricity generation CO

emissions would increase

slightly (+18 Mt CO

), reaching almost 490 Mt CO

, mainly due to

higher gas-fired generation than in 2021.

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South Africa deviates in its demand growth trend from other countries in Africa

Year-on-year relative change in electricity demand, Africa, 2019-2025

IEA. CC BY 4.0.

-10%

-8%

-6%

-4%

-2%

10%

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

Africa South Africa Egypt Algeria Morocco Nigeria Tunisia

Electricity demand growth

Historical demand Updated forecast Previous forecast (July 2022)

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Renewables lead the race in terms of generation increases, followed by natural gas

Year-on-year change in electricity generation, Africa, 2019-2025

IEA. CC BY 4.0.

Development of average CO

intensity, Africa, 2019-2025

IEA. CC BY 4.0.

Notes: Other non-renewables includes oil, waste and other non-renewable energy sources. The CO

intensity is calculated as total CO

emissions divided by total generation.

- 40

- 30

- 20

- 10

2019

2021

2023

2025

TWh

Coal Gas

Nuclear Other non-renewables

Renewables Net change

100

200

300

400

500

600

700

800

900

1 000

g CO₂

/kWh

Africa South Africa Egypt

Algeria Morocco Nigeria

Tunisia

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South Africa

Electricity consumption in South Africa fell by less than 4% y-o-y in

2022, due to declining availability of its ageing coal fleet and delays

in construction and commissioning of new generation projects. This

has resulted in unprecedented amounts of load shedding, with over

8 TWh (or 5% of forecasted annual demand) being reduced through

load shedding during 2022. This represents a fourfold increase in

unmet demand compared to 2021. In addition, load shedding was

implemented 205 days during 2022, approaching almost a threefold

increase on the 75 days in 2021.

At the end of August 2022, Eskom, the state-owned utility, released

their System Status and Outlook for 2022/23

, where its base case

scenario for the period September 2022 to August 2023 would see

a reduction in load shedding to only 24 days. However,

due to

ongoing issues with the commissioning of its new-build coal

generation, it has already seen 46 days of load shedding across

September and October 2022 alone. This aligns with the middle of

its most pessimistic scenarios, which forecasts between 203 and

326 days of load shedding over the September 2022 to August

2023 period, painting a potentially sombre picture for the South

African power sector in 2023, with new sources of generation

needed to lift the country out of this crisis. This is not aided by the

fact that one of the units of its only nuclear plant is also due to be

taken out of service f

or most of the first half of 2023, which will

result in an even tighter system. The outlook could be even more

dire after reports that Eskom had

spent its entire budget f

or the

financial year (April 2022-March 2023) for diesel used in its 3 GW of

gas peaking plants, and therefore this capacity will not be available

until the start of the next financial year in April 2023.

Volume and number of days of load shedding, South Africa,

2017-2022

Source: IEA analysis based on hourly data from Eskom (2023), Data Portal, 18

January 2023.

In July 2022, President Cyril Ramaphosa announced a 10-point

plan to address the ongoing power crisis in South Africa. Measures

included the removal of licensing requirements

or private energy

projects, although still retaining the requirement for registration with

the regulator. This builds upon the earlier relaxation of licensing

requirements, which raised the licence exemption threshold

from

1 MW to 100 MW in June 2021. In coming years this should

accelerate Eskom’s and the municipalities’ ability to procure clean

power directly. Already, the change in the licence exemption

120

150

180

210

240

270

2017 2018 2019 2020 2021 2022

days

GWh

Load shedding Days of load shedding (right-axis)

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threshold in 2021 led to a number of announcements from major

industrial consumers, including many large mining companies, to

power their own operations using a combination of renewable

technologies.

Another measure announced was the almost doubling of the

located capacity for procurement in the latest renewable energy

auction (i.e. Bid Window 6 of the REIPP Procurement Programme)

from 2 600 MW to 4 200 MW

. This sixth auction round was

concluded in December 2022, with South Africa selecting five solar

PV projects for a total capacity of 860 MW, significantly lower

capacity compared to the originally planned allocation. The auction

also saw no wind power project selected, due to a lack of grid

capacity for connection.

This is the second auction of this kind after a seven-year disruption

ollowing the refusal of Eskom to sign

pow

er purchase agreements

(PPAs) with the preferred bidders of the fourth bid window. While

the preferred bidders for Bid Window 5 have been announced, only

three of the bidders have signed a PPA as the others have

struggled to reach financial close due to delays in receiving

quotations on connection infrastructure from Eskom. An initial

deadline at the end of April 2022 was continuously delayed, then

extended until the end of October 2022 and

has been extended

beyond this date in November. There are also ongoing delays with

the Risk Management IPP Procurement Programme (RMIPPPP)

that aimed to procure 2 GW of firm capacity and was concluded in

2021, but which has been continuously delayed since.

It is expected that capacity from these auctions, along with the

oming online of the two coal megaprojects Kusile and Medupi and

improvements to performance of the existing coal fleet, will lead to

an increase in available capacity and a recovery of demand. Given

the uncertainty due to the tight supply situation, we estimate

South African demand and generation could recover to 2021 levels

in 2024-2025. While we expect coal to continue making up the

majority of the South African generation mix (82% in 2025), our

forecast sees the share of renewables increasing to 12% in 2025,

from 9% in 2022.

Egypt

Electricity consumption in Egypt increased by 8% in 2021 after a

2.7% decline in 2020. Growth slowed down in the first seven

months of 2022 to an estimated 3% y-o-y increase

, against the

backdrop of domestic economic pressures and the global energy

crisis. The continuous weakening of the Egyptian pound and

spiralling inflation (24.5% core inflation annualised rate in 2022)

since the beginning of the year puts the country’s economy under

pressure and resulted in a record USD 7.3 billion deficit in the

balance of payments in the first nine months of 2022. For the third

time since 2020, the Egyptian government decided in June to

postpone its planned increase i

n electricity tariffs until early 2023 in

order not to add new burdens on citizens. The country took

measures to reduce its natural gas consumption in power

generation (which provides up to 90% of total generation) in order to

maximise its LNG export volumes and generate revenue in foreign

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currencies. This included substantial switching back to oil-fired

generation, with fuel oil burn averaging above 100 kb/d in the first

nine months of 2022, its highest level in four years.

Demand-side measures were also adopted in order to reduce

electricity consumption. In August 2022, the government

implemented electricity rationing measures

argeting reductions in

lighting and air conditioning in administrative buildings, commercial

and leisure facilities, as well as for street lighting.

We estimate a 3%

y-o-y growth in electricity demand in Egypt for

2022, and an average annual 2.4% growth rate in 2023-2025 based

on the combination of an expected prolonged preference for gas

exports against domestic use and planned continuation of electricity

tariff rises as part of a government programme to lift subsidies by

2025.

Egypt has shifted its priority for new capacity from conventional

thermal to low-carbon sources of power generation over recent

years, after strong development of its gas-fired generation fleet in

the mid-2010s. The country currently has 3.1 GW of installed wind

and solar capacity on top of 2.8 GW of hydropower, and an

additional 2.8 GW of planned renewable capacity to be

commissioned by the end of 2023. Diversification and

decarbonisation of the generation mix also includes nuclear, with

the start of construction work for the 4.8 GW El Dabaa plant in

July 2022, which is scheduled for commissioning in 2026. Egypt

aims at using its rising electricity surplus to become a regional hub

for the east Mediterranean, with several transmission projects under

way, including a 3 GW interconnection with Saudi Arabia under

construction and scheduled for 2026, and plans to develop a 3 GW

interconnection with Europe via Greece.

Algeria

Algeria’s installed production capacity grew by 3.2 GW, or about

13%, between September 2021 and August 2022, according to the

government’s policy statement

to t

he parliament in September

2022. State-owned utility Sonelgaz indicated in September that a

new consumption peak record was reached in August 2022 at

16 822 MW. Algeria’s domestic electricity consumption increased by

an estimated 5% in 2021, after a 3% decline in 2020 and an

average 6% growth rate during 2015-2019. The country’s

continuous rise in electricity consumption is supported by

substantial subsidies. In spite of its growing deficit and a

quadrupling of its debt i

n two years, Sonelgaz’ confirmed in August

that tariffs would not be revised. This forecast expects Algeria’s

electricity demand to increase at an average rate of about 5% per

year in 2022-2025.

Algeria seeks to expand its electricity exports to nei

ghbouring

countries in North Africa and Southern Europe, thanks to planned

development of its renewable generation capacity over the next

decade. The country’s energy strategy has set a target of

developing 15 GW of renewable capacity by 2035. Renewable

development operator Shaems announced in July that

first

production of 50 MW from solar should be expected by end 2023

from the 1000 MW solar project currently underway. A potential

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project of a subsea interconnection with Italy was announced in July

and is currently being studied.

Morocco

Electricity consumption increased by 5.5% in 2021 in Morocco,

recovering from a 1.8% decline in 2020. This was supported by a

16% rebound from high-voltage customers, while residential

consumption increased by 2%. Domestic generation grew by 6.7%

year-on-year, principally driven by thermal generation from state-

owned ONEE (up 11.9%), while electricity supplied by independent

power producers (which account for about 60% of total domestic

generation) and from renewable sources both increased by close to

5%. According to statistics from the Ministry of Economy and

Finance, electricity demand rose by 4.8% y-o-y

n the first eight

months of 2022, down from 6.5% over the same period in 2021,

principally driven by medium- and low-voltage electricity customers

(up by 7% and 3.8% y-o-y, respectively) while demand from high-

voltage users rose 1.5%. Domestic production was up by 3% y-o-y in

the first eight months of 2022, with renewable generation growing by

8.6% and thermal from ONEE up by 22.6%. Output declined 3.2%

from independent producers. The balance of trade, which had shifted

to net electricity exports in 2021, returned to net imports, with a more

than doubling of imports while exports declined by 29%.

Morocco has experienced strong growth in renewables over the

pas

t several years. As of end 2021, renewable capacity accounted

for 3 950 MW, or 37% of the country’s

installed electricity

generation capacity – with 1 770 MW of hydro, 1 430 MW of wind,

and 750 MW of solar. The country aims to increase the share of

renewable capacity to 52% by 2030, 70% by 2040 and 80% by

2050, and to gradually expand its exports to Europe over the period.

The European Union signed in October 2022 a Green Partnership

on energy, climate and the environment with Morocco, the first of its

kind with a partner country, which will contribute to scale up

cooperation on energy transition and decarbonisation. We forecast

Morocco’s electricity demand to grow at an average annual rate of

2% between 2023 and 2025, similar to generation – with

renewables growing at an average 19% per year while thermal

declines by an annual average of 5% over the same period.

Tunisia

Tunisia’s final consumption of electricity increased by 9% y-o-y in

2021, driven by all types of consumers – the residential sector is the

largest and accounted for 38% of total electricity consumption,

followed by industry with 30%, commercial at 20%, and other

sectors for the remaining 12%. In 2022, total electricity demand

(including the sector’s own consumption and exports) increased by

10%. In comparison, electricity generation grew by 2% to 22 TWh,

principally from gas-fired generation which accounted for close to

94% of total generation. The remaining supply requirements were

met by 1 TWh of renewable electricity generation and by a strong

increase in electricity imports from Algeria (up by close to 1 TWh)

and reduced exports to Libya (down by close to 0.6 TWh). Statistics

from the Ministry of Industry, Energy and Mines indicate that

Tunisia’s reliance on electricity imports

urther increased in the first

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ten months of 2022 due to higher gas import prices, up by a sharp

150%, from 864 GWh to 2 169 GWh, a jump from less than 5% of

total supply to over 11%. This stems from a 2% decline in domestic

generation from gas-fired plants from independent power producers

(down 74% from 2 725 GWh to 706 GWh over January to October)

while generation from state-owned STEG (also primarily gas-driven)

increased by 12% to 16 024 GWh to bridge the gap. Electricity

consumption increased by 6% y-o-y in January through October,

driven by low- and medium-voltage customers (up by 9% and 6%,

respectively) while demand from high-voltage customers declined

7%.

We forecast an average 3% growth per year in Tunisia’s electricity

consumption in the 2023-2025 period, principally met by growing

domestic renewable generation. Generation from renewable

sources is expected to increase by 80% between 2022 and 2025

and reach around 2 TWh by the end of the period – or the

equivalent of close to 8% of Tunisia’s electricity consumption,

against less around 5% in 2022. Tunisia’s

energy strategy pl

an to

2030 targets a 30% share of renewables by the end of the decade.

Nigeria

Access to electricity in Nigeria is hampered by insufficient available

power generation and transmission capacity, and is further

constrained by grid collapses. According to industry data, Nigeria’s

power grid collapsed seven times

n January through to September

2022. This is higher than in 2020 and 2021, when there were four

grid collapses each year according to the

Nigerian Electricity

Regulatory Commission, but still shows some improvement

compared to the average rate of default observed since 2015, which

averaged 13 collapses per year (with a peak of 28 in 2016).

Earlier this year, President Buhari announced that electricity

ailability issues were mainly caused by low gas-fired generation

(which represents 73% of the electricity mix in 2022) resulting from

sabotage of gas pipelines. A report from Nigeria’s Association of

Power Generation Companies showed that the country’s average

available generation capacity fell to its

lowest level in seven years i

2022 (January to August) with 5 634 MW available, 20% below an

annual average of 7 078 MW over the reported period, and 28%

below the highest capacity – recorded in 2020 (7 792 MW).

New capacity is expected to be commissioned in early 2023, with

he start-up of the 700 MW Zungeru hydroelectric power plant

scheduled for the first quarter. President Buhari reaffirmed

October 2022 the country’s dedication to the Presidential Power

Initiative, an ambitious electricity development plan launched in

2019 with Siemens and with the support of the German

government, which would raise the country’s total available

generation capacity to 25 GW by 2025. The Senate passed a

constitutional amendment bill i

n July 2022 that would allow states to

own and develop electricity generation, transmission and

distribution capacity. This proposed removal of the federal state’s

monopoly on the electricity system would contribute to foster

investment in new capacity through public-private partnerships.

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Morocco set to see the highest relative growth in renewables in Africa, followed by South Africa

Year-on-year change in electricity generation in selected countries in Africa, 2019-2025

IEA. CC BY 4.0.

Note: Other non-renewables includes oil, waste and other non-renewable energy sources.

- 20

- 15

- 10

- 5

2019

2021

2023

2025

2019

2021

2023

2025

2019

2021

2023

2025

South Africa

Egypt

Algeria

TWh

Coal Gas Nuclear Other non-renewables Renewables Net change

- 4

- 2

2019

2021

2023

2025

2019

2021

2023

2025

Morocco Nigeria

TWh

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Summary table: Demand

Regional breakdown of electricity demand, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Africa 707 747 758 856 5.7% 1.5% 4.1%

Americas 6 037 6 200 6 342 6 535 2.7% 2.3% 1.0%

of which United States 4 109 4 211 4 320 4 402 2.5% 2.6% 0.6%

Asia Pacific 12 118 13 045 13 479 15 428 7.7% 3.3% 4.6%

of which China 7 471 8 188 8 400 9 790 9.6% 2.6% 5.2%

Eurasia 1 234 1 309 1 332 1 349 6.1% 1.8% 0.4%

Europe 3 648 3 817 3 675 3 846 4.6% -3.7% 1.5%

of which European Union 2 625 2 751 2 656 2 773 4.8% -3.5% 1.4%

Middle East 1 115 1 162 1 192 1 268 4.2% 2.6% 2.1%

World 24 860 26 281 26 779 29 281 5.7% 1.9% 3.0%

Notes: CAAGR = compounded average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. For the entire period

European Union data is for the current 27 member states. Data for 2021 are preliminary; 2022 data are estimated; 2023 to 2025 are forecasts. Differences in totals are due to

rounding.

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Summary table: Supply and emissions, world

Breakdown of electricity sector supply and emissions, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 2 676 2 803 2 684 2 986 4.8% -4.3% 3.6%

Coal 9 414 10 171 10 325 10 217 8.0% 1.5% -0.3%

Gas 6 330 6 489 6 500 6 522 2.5% 0.2% 0.1%

Other non-renewables 776 764 785 611 -1.5% 2.7% -8.0%

Total renewables 7 475 7 902 8 349 10 799 5.7% 5.7% 9.0%

Total generation 26 671 28 129 28 642 31 135 5.5% 1.8% 2.8%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 12 302 13 039 13 207 13 043 6.0% 1.3% -0.4%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Asia Pacific

Breakdown of electricity sector supply and emissions, Asia Pacific, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 653 723 750 908 10.8% 3.7% 6.6%

Coal 7 334 7 898 8 092 8 407 7.7% 2.5% 1.3%

Gas 1 502 1 508 1 438 1 495 0.4% -4.6% 1.3%

Other non-renewables 162 148 172 129 -8.2% 15.5% -9.0%

Total renewables 3 190 3 524 3 758 5 224 10.5% 6.6% 11.6%

Total generation 12 841 13 801 14 209 16 163 7.5% 3.0% 4.4%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 7 739 8 224 8 395 8 694 6.3% 2.1% 1.2%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Americas

Breakdown of electricity sector supply and emissions, Americas, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 954 941 924 941 -1.4% -1.8% 0.6%

Coal 973 1 098 1 027 808 12.9% -6.5% -7.7%

Gas 2 162 2 160 2 223 2 241 -0.1% 2.9% 0.3%

Other non-renewables 180 192 182 156 7.0% -5.6% -5.0%

Total renewables 2 213 2 255 2 461 2 847 1.9% 9.1% 5.0%

Total generation 6 482 6 646 6 816 6 993 2.5% 2.6% 0.9%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 1 927 2 062 2 008 1 789 7.0% -2.6% -3.8%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Europe

Breakdown of electricity sector supply and emissions, Europe, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 834 885 746 845 6.1% -15.7% 4.2%

Coal 584 653 681 513 11.7% 4.4% -9.0%

Gas 801 844 822 581 5.3% -2.6% -10.9%

Other non-renewables 87 87 86 69 0.4% -0.6% -7.4%

Total renewables 1 577 1 579 1 593 2 086 0.1% 0.9% 9.4%

Total generation 3 884 4 047 3 929 4 095 4.2% -2.9% 1.4%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 925 1 005 1 023 763 8.6% 1.8% -9.3%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Eurasia

Breakdown of electricity sector supply and emissions, Eurasia, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 219 224 225 229 2.6% 0.3% 0.6%

Coal 256 261 281 251 1.8% 7.8% -3.8%

Gas 604 659 679 714 9.1% 3.0% 1.7%

Other non-renewables 12 13 12 12 12.8% -6.5% -1.4%

Total renewables 277 294 277 289 6.2% -6.0% 1.4%

Total generation 1 368 1 452 1 474 1 495 6.1% 1.5% 0.5%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 530 560 592 599 5.6% 5.8% 0.4%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Middle East

Breakdown of electricity sector supply and emissions, Middle East, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 6 15 26 50 160.8% 70.2% 24.5%

Coal 20 18 13 4 -10.7% -27.4% -30.6%

Gas 917 955 973 1 094 4.1% 1.9% 4.0%

Other non-renewables 288 285 285 196 -1.3% 0.2% -11.8%

Total renewables 40 44 50 77 10.5% 14.7% 15.3%

Total generation 1 270 1 316 1 346 1 420 3.6% 2.3% 1.8%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 708 720 725 711 1.7% 0.7% -0.6%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Summary table: Supply and emissions, Africa

Breakdown of electricity sector supply and emissions, Africa, 2020-2025

TWh 2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Nuclear 10 14 12 13 41.9% -12.0% 2.3%

Coal 247 244 231 234 -1.1% -5.7% 0.5%

Gas 344 363 366 398 5.6% 0.8% 2.8%

Other non-renewables 48 38 48 49 -19.3% 23.9% 1.1%

Total renewables 178 206 209 275 16.0% 1.7% 9.5%

Total generation 826 866 866 970 4.8% 0.1% 3.8%

Mt CO

2020 2021 2022 2025

Growth rate

2020-2021

Growth rate

2021-2022

CAAGR

2023-2025

Total emissions 472 469 464 487 -0.6% -1.1% 1.6%

Notes: CAAGR = compound average annual growth rate. For the CAAGR 2023-2025 reported, end of 2022 data is taken as base year for the calculation. Data for 2021 are

preliminary; 2022 data are estimated; 2023-2025 are forecasts. Differences in totals are due to rounding. Unless otherwise specified, generation numbers refer to gross generation.

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Regional and country groupings

Africa – Algeria, Angola, Benin, Botswana, Cameroon, Congo,

Democratic Republic of the Congo, Côte d’Ivoire, Egypt, Equatorial

Guinea, Eritrea, Ethiopia, Gabon, Ghana, Kenya, Libya, Mauritius,

Morocco, Mozambique, Namibia, Niger, Nigeria, Senegal, South

Africa, South Sudan, Sudan, United Republic of Tanzania, Togo,

Tunisia, Zambia, Zimbabwe and other African countries and

territories.

Asia – Bangladesh, Brunei Darussalam, Cambodia, Chinese

Taipei, India, Indonesia, Japan, Korea, Democratic People’s

Republic of Korea, Lao People’s Democratic Republic, Malaysia,

Mongolia, Myanmar, Nepal, Pakistan, People’s Republic of China,

Philippines, Singapore, Sri Lanka, Thailand, Viet Nam and other

Asian countries, territories and economies.

Asia Pacific – Australia, Bangladesh, Brunei Darussalam,

Cambodia, Chinese Taipei, India, Indonesia, Japan, Korea,

Democratic People’s Republic of Korea, Lao People’s Democratic

Republic, Malaysia, Mongolia, Myanmar, Nepal, New Zealand,

Pakistan, People’s Republic of China,

Philippines, Singapore, Sri

Lanka, Thailand, Viet Nam and other Asian countries, territories and

economies.

Central and South America – Argentina, Bolivia, Brazil, Chile,

Colombia, Costa Rica, Cuba, Curaçao, Dominican Republic,

Ecuador, El Salvador, Guatemala, Haiti, Honduras, Jamaica,

Nicaragua, Panama, Paraguay, Peru, Suriname, Trinidad and

Tobago, Uruguay, Venezuela and other Latin American countries

and territories.

Eurasia – Armenia, Azerbaijan, Georgia, Kazakhstan, Kyrgyzstan,

Russian Federation, Tajikistan, Turkmenistan and Uzbekistan.

Europe – Albania, Austria, Belgium, Belarus, Bosnia and

Herzegovina, Bulgaria, Croatia, Cyprus,

6,7

Czech Republic,

Denmark, Estonia, Finland, France, Germany, Gibraltar, Greece,

Hungary, Iceland, Ireland, Italy, Kosovo

Latvia, Lithuania,

Luxembourg, Malta, Montenegro, Netherlands, North Macedonia,

Norway, Poland, Portugal, Republic of Moldova, Romania, Serbia,

Slovak Republic, Slovenia, Spain, Sweden, Switzerland, Republic of

Türkiye, Ukraine and United Kingdom.

European Union – Austria, Belgium, Bulgaria, Croatia, Cyprus,

6,7

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.

Middle East – Bahrain, Islamic Republic of Iran, Iraq, Israel

Jordan, Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, Syrian Arab

Republic, United Arab Emirates and Yemen.

Nordics – Denmark, Finland, Norway, Sweden

North Africa – Algeria, Egypt, Libya, Morocco and Tunisia.

North America – Canada, Mexico and United States.

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Southeast Asia – Brunei Darussalam, Cambodia, Indonesia, Lao,

People’s Democratic Republic, Malaysia, Myanmar, Philippines,

Singapore, Thailand and Viet Nam. These countries are all

members of the Association of Southeast Asian Nations (ASEAN).

Advanced economies – OECD member nations, plus Bulgaria,

Croatia, Cyprus, Malta and Romania.

Emerging markets and developing economies – All other

countries not included in the advanced economies regional

grouping.

Individual data are not available and are estimated in aggregate for: Burkina Faso, Burundi,

Cape Verde, Central African Republic, Chad, Comoros, Djibouti, Gambia, Guinea, Guinea-

Bissau, Lesotho, Liberia, Madagascar, Malawi, Mali, Mauritania, Reunion, Rwanda, Sao Tome

and Principe, Seychelles, Sierra Leone, Somalia, Eswatini and Uganda.

Including Hong Kong.

Individual data are not available and are estimated in aggregate for: Afghanistan, Bhutan,

Macau (China), Maldives and Timor-Leste.

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.

Individual data are not available and are estimated in aggregate for: Anguilla, Antigua and

Barbuda, Aruba, Bahamas, Barbados, Belize, Bermuda, British Virgin Islands, Cayman Islands,

Dominica, Falkland Islands (Malvinas), Grenada, Guyana, Montserrat, Saba, Saint Eustatius,

Saint Kitts and Nevis, Saint Lucia, Saint Pierre and Miquelon, Saint Vincent and the Grenadines,

Sint Maarten, and the Turks and Caicos Islands.

Note by Türkiye: The information in this document with reference to “Cyprus” relates to the

southern 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 United Nations,

Türkiye shall preserve its position concerning the “Cyprus issue”.

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 this document relates to the area under the effective control of the

Government of the Republic of Cyprus.

The designation is without prejudice to positions on status and is in line with the United Nations

Security Council Resolution 1244/99 and the Advisory Opinion of the International Court of

Justice on Kosovo’s declaration of Independence.

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.

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Abbreviations and acronyms

ASEAN Association of Southeast Asian Nations

CAAGR Compound average annual growth rate. Throughout

the report we refer to the CAAGR when talking about

average growth.

CCGT combined-cycle gas turbine

CFE Federal Electricity Commission (Mexico)

EC European Commission

EMDEs Emerging Markets and Developing Economies

ETS emissions trading system

EU European Union

EUA European Union Allowance (emissions)

EU ETS European Union Emissions Trading System

FY fiscal year

GCC Gulf Cooperation Council

GDP Gross Domestic Product

GHG greenhouse gas

IEA International Energy Agency

IEX Indian Energy Exchange

IMF International Monetary Fund

LNG liquefied natural gas

MoU memorandum of understanding

NDCs Nationally Determined Contributions

NERC North American Electric Reliability Corporation (US)

OECD Organisation for Economic Co-operation and

Development

PPA power purchase agreement

RE renewable energy

REIPPPP Renewable Energy Independent Power Producer

Procurement Programme (South Africa)

RES renewable energy sources

RMIPPPP Risk Mitigation Independent Power Producer

Procurement Programme (South Africa)

TSO transmission system operator

PV photovoltaic

TTF Title Transfer Facility (the Netherlands)

UAE United Arab Emirates

UK United Kingdom

US United States

UN United Nations

VAT value-added tax

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Units of measure

carbon dioxide

g CO

gramme of carbon dioxide

g CO

/kWh gramme of carbon dioxide per kilowatt hour

Gt CO

gigatonne of carbon dioxide

GW gigawatt

kWh kilowatt hour

MBtu million British thermal units

mcm/d million cubic metres per day

Mt CO

million tonnes of carbon dioxide

Mt/yr million tonnes per year

MW megawatt

MWh megawatt-hour

t CO

tonne of carbon dioxide

t CO

-eq tonne of carbon dioxide equivalent

TWh terawatt-hour

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Acknowledgements, contributors and credits

This publication has been prepared by the Gas, Coal and Power

Markets (GCP) Division of the International Energy Agency (IEA).

The report was led and coordinated by Eren Çam, Energy Analyst

for Electricity.

Javier Jorquera Copier led the modelling and coordinated earlier

stages of the production of the report. The main authors are (in

alphabetical order): Eren Çam, Julia Guyon, Zoe Hungerford, Javier

Jorquera Copier, and Martin Strand Husek. The report also

benefited from analysis, data and input from Carlos Fernández

Álvarez, Louis Chambeau, Jean-Baptiste Dubreuil, Keith Everhart,

David Fischer, Craig Hart, Tetsuro Hattori, Pablo Hevia-Koch, YuJin

Jeong, Luis Lopez, Akos Losz, Gergely Molnár, Gabriel Saive,

Enrique Gutiérrez Tavarez, Camille Paillard, and Jacques Warichet.

Arne Lilienkamp, Stefan Lorenczik, Javier Sesma Montolar, and

Jonas Zinke, former IEA colleagues, and Astha Guptha, IEA

consultant, also provided valuable analysis.

Keisuke Sadamori, director of the IEA Energy Markets and Security

(EMS) Directorate, and Carlos Fernández Álvarez, Acting Head of

GCP, provided expert guidance and advice.

Further IEA colleagues provided valuable input, comments and

feedback, in particular Nadim Abillama, Fengquan An, Yasmine

Arsalane, Heymi Bahar, Alessandro Blasi, Laura Cozzi, Davide

D’Ambrosio, Dan Dorner, Carole Etienne, Syrine El Abed, Pablo

González, Tim Gould, Haneul Kim, Jinpyung Kim, Rita Madeira,

Laura Marí Martínez, Rebecca McKimm, Jack Miller, Arnaud

Rouget, Diana Pérez Sánchez, Apostolos Petropoulos, Isaac

Portugal, Hiroyasu Sakaguchi, Brent Wanner, Biqing Yang.

Timely and comprehensive data from the Energy Data Centre were

fundamental to the report. Particularly, we thank to Aloys Nghiem,

Alessia Scoz, and Marta Silva. We also thank Einar Einarsson for

his assistance on setting up the peer review.

The authors would also like to thank Diane Munro for skilfully editing

the manuscript and the IEA Communication and Digital Office, in

particular Brainard Curtis, Astrid Dumond, Jad Mouawad, Jethro

Mullen, Isabelle Nonain-Semelin, Gregory Viscusi and Therese

Walsh.

Several international experts provided input and/or reviewed the

draft report. Their suggestions and comments were very valuable.

They include: A Balan (CEA), Rhea Caguete (IEMOP), Bram

Claeys (The Regulatory Assistance Project), Brent Dixon (Idaho

National Laboratory), Ganesh Doluweera (Canada Energy

Regulator), Gina Downes (Eskom), Carlos Finat (independent

consultant), Marco Foresti (ENTSO-E), Peter Fraser (independent

consultant), Rafaila Grigoriou (VaasaETT), Michael Grubb (UCL),

Renato Haddad (EPE), Edwin Haesen (ENTSO-E), Cristián Herrera

(ACERA), Sarah Keay-Bright (National Grid ESO), Donghoon Kim

(SK), Francisco Laverón (Iberdrola), Sanglim Lee (KEEI), Xiaomeng

Lei (CEC), Stefan Lorenczik (Frontier Economics), Tatiana Mitrova

(Columbia University), Enrique De Las Morenas Moneo (ENEL),

Emmanuel Neau (EDF R&D), Luiz Gustavo Silva de Oliveira (IEA

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consultant), Anne Radermecker (European Commission), Noor

Miza Razali (Tenaga Nasional Berhad), SC Saxena (POSOCO),

Abdullah Al Shereiqi (R&D, Oman), María Sicilia (Enagas),

Fereidoon Sioshansi (Menlo Energy Economics), Henrike Sommer

(Aurora Energy Research), Carlos Suazo (Ministry of Energy of

Chile/SPEC/ISCI), Arjon Valencia (IEMOP), Matthew Wittenstein

(United Nations ESCAP), Karen E. Young (Columbia University)

and Rina Bohle Zeller (Vestas).

The individuals and organisations that contributed to this report are

not responsible for any opinion or judgement it contains. Any error

or omission is the sole responsibility of the IEA.

For questions and comments, please contact GCP ([email protected]

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International Energy Agency (IEA)

This work reflects the views of the IEA Secretariat but does not

necessarily reflect those of the IEA’s individual member countries or

of any particular funder or collaborator. The work does not

constitute professional advice on any specific issue or situation. The

IEA makes no representation or warranty, express or implied, in

respect of the work’s contents (including its completeness or

accuracy) and shall not be responsible for any use of, or reliance

on, the work.

For further information, please contact: GCP ([email protected]).

Subject to the IEA’s Notice for CC-licenced

ontent, this work is

licenced under a Creative Commons Attribution 4.0 International

Licence.

This document and any map included herein are without prejudice

to the status of or sovereignty over any territory, to the delimitation

of international frontiers and boundaries and to the name of any

territory, city or area.

Unless otherwise indicated, all material presented in figures and

tables is derived from IEA data and analysis.

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