Gas Market
Report Q3-2021
including Gas 2021 - Analysis and forecast to 2024

INTERNATIONAL ENERGY AGENCY
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IEA member countries:
Australia
Austria
Belgium
CanadaCzech Republic
Denmark
Estonia
FinlandFranceGermany
GreeceHungary
Ireland
Italy
Japan
Korea
Luxembourg
MexicoNetherlands
New Zealand
NorwayPolandPortugal
Slovak Republic

Spain
SwedenSwitzerland
TurkeyUnited Kingdom
United States
IEA association countries:
BrazilChina
India
Indonesia
MoroccoSingapore
South Africa
ThailandAbstract

Gas Market Report Q2-2021

Abstract
Natural gas markets started off the year with a strong rebound,supported by a combination of recovering economic activity in mostmarkets along with a series of weather-related events – cold spells
in Q1 followed by colder or drier than average temperatures in Q2.
Rising demand in 2021 is expected to offset 2020’s decline andeven grow further with an anticipated 3.6% annual increase.
Demand growth is, however, not expected to maintain this pace inthe medium term, but rather to slow to an average 1.7% annual rate
for the 2022-2024 period, equally driven by economic activity andfuel switching from coal and oil. This slower growth may still be toohigh to match a net-zero emissions path, which requires higher
substitution rates and efficiency gains – especially in mature
markets, where most of the switching potential from coal and oil togas has already been realised.

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This new quarterly report offers a medium-term forecast andanalysis of global gas markets to 2024, as well as a review of recent
developments in major regional gas markets during the first half of2021.

Table of contents

Gas Market Report Q3-2021

Table of contents
Gas 2021: Analysis and forecast to 2024 ......................................................4
Overview and key findings ........................................................................ 5
Demand .......................................................................................................... 9
Supply ..........................................................................................................38
Tracking clean gas progress ........................................................................48
Trade ............................................................................................................61
Gas market update and short-term forecast ...............................................75

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Annex ..............................................................................................................99

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

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Gas 2021: Analysis and forecast to 2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

economic activity can explain almost two-thirds (270 bcm), while thesubstitution of coal (and oil to a lesser extent) explains the rest (160bcm). Strong natural gas demand growth in 2021 is mostly the
result of the global economic recovery from the Covid-19 crisis.

Overview and key findings
Global natural gas demand dropped by 1.9%, or 75 bcm, in 2020
because of an exceptionally mild winter in the northern hemisphereand the impact of the Covid-19 pandemic. We forecast global
demand to rebound by 3.6% in 2021. And unless major policychanges to curb global gas consumption are introduced, demand is
set to keep growing in the coming years, albeit at a slower pace, toreach nearly 4 300 bcm by 2024, a 7% rise from pre-Covid levels.

Growth in 2022-2024 is driven in equal proportions by economic
activity and fuel substitution.

Gas demand growth is set to slow despite coal-to-gas
switching, but more ambitious policies are needed toshift to a net zero path
Almost half of the increase in gas demand to 2024 is expected tocome from the Asia Pacific region, driven by China and India as well
as by emerging markets in South and Southeast Asia. The industrial
sector plays a pivotal role in medium-term gas demand growth,
accounting for about 40% of the total increase between 2020 and
2024 in our forecast. This includes the use of gas for industrial
processes and as a feedstock for chemicals and fertilisers.
Natural gas demand is set to grow by 350 bcm between 2020 and
2024. This would have been 80 bcm higher were it not for energy
efficiency improvements and measures to replace gas with otherfuels. Of the 430 bcm increase that can be considered as “grossgas demand additions” over the period, growth driven by higher

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In spite of this limited medium-term growth, our forecast for global
gas demand in 2024 is above what is called for in the IEA’s climatedriven scenarios, notably in the recent special report Net Zero by
2050: A Roadmap for the Global Energy Sector. To get on track forthe emissions pathway set out in the Roadmap, stronger policies
would need to be introduced within our forecast period to underpin
further fuel substitution and efficiency gains. This is especially thecase in more mature markets, where much of the potential forswitching from coal and oil to gas has already been tapped. Strong
and early policy actions and investment are required, with impacts
on gas demand that would commence during our forecast period
and intensify significantly over the course of the 2020s. Switchingfrom oil and coal to gas, particularly in emerging and developing
economies, can reduce emissions and improve air quality, andalready explains half of gas consumption growth in these markets inthe 2022-2024 period.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Projects already under development meet most supply
needs, and the focus on cleaner gas supply is growing

LNG markets tighten; new sources of flexibility reinforce
security of supply

Global gas production in 2024 is expected to be 6% higher than2019’s pre-Covid levels. This additional supply comes almost
exclusively from large conventional assets already underdevelopment, mainly in Russia and the Middle East. It is

Global LNG trade volumes in 2024 are expected to be 17% above
the pre-Covid levels seen in 2019, driven by continued demand
growth in Asia and in the absence of strong policy initiatives inmajor gas markets. At an annual average growth rate of 3.3%

supplemented by new investment in US shale gas production tokeep pace with expanding LNG export capacity. However, without
strong policy measures to curb longer-term gas demand growth,market volatility and concerns over security of supply may arise inthrough 2024, this is much slower than the double-digit increases
observed between 2016 and 2019. The wave of final investment
decisions on LNG projects taken before 2020 should therefore
prove sufficient to satisfy additional LNG demand in the coming
years. The global liquefaction utilisation rate is expected to return
progressively to its pre-2020 level by 2024. In the absence of major
project delays or unplanned outages, the risk of a structurally tightmarket appears limited before 2024 with the possible exception of

the last years of our forecast.
To reduce its emissions footprint and align with net-zero emissions
objectives, the gas industry needs to continue reducing the intensityof its greenhouse gas emissions along the value chain, support thedevelopment of low-carbon gases and develop carbon management
solutions to minimise emissions from combustion. Reducing
methane emissions is an efficient way – in terms of both time andcost – of narrowing the industry’s footprint. Analysis from the IEA
Methane Tracker shows as much as 40% of current methane
emissions could be avoided at no net cost. The transition to lowcarbon sources of gas supply – such as biomethane, hydrogen andsynthetic methane – requires the adjustment of regulations andinfrastructure to ensure their cost-competitive integration into futureenergy systems. This report reviews recent market and policy

short seasonal episodes.
increasingly interdependent global gas market, even if it is well
supplied. The growth of long-term contracts without a destination
clause for LNG exported from the United States is contributing toflexibility. US projects account for the large majority of additional
LNG supply capacity to be commissioned over the next three years.
Robust growth of the LNG carrier fleet is another contributor, withcurrent order books for deliveries in the next two to three years
representing a 25% increase in the vessel count. Undergroundstorage capacity, another pivotal source of flexibility, is set toincrease by 7% over the forecast period.

developments supporting such a transition to cleaner gases.

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Further flexibility would help ensure security of supply in anGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Main assumptions behind the forecast
2020 saw the worst economic downturn since World War II, with a
3.3% decline in global GDP. This forecast is based on theassumption of a strong economic rebound of up to 6% in 2021.
Global GDP growth is then expected to slow, increasing by 4.6% incancellations, bankruptcies and slower growth, especially inservices. Emerging markets, which account for the bulk of natural
gas demand growth, have been strongly affected by both the healthand economic crises, which have led to rising debt and fiscal

2022 and about 3% on average per year in the following years.

imbalances that could hamper medium-term growth.

The strong short-term recovery is underpinned by the assumption ofa prompt rollout of Covid-19 vaccination in mature economies, andcontinuous efforts to deploy vaccines and protect the mostvulnerable in emerging economies. Recovery packages, public
investment and fiscal relief policies have been the primary engine of
economic rebound. They are expected to remain the principal driverof growth in the short term as funds committed under stimulus
packages keep pouring into the economy.

Natural gas demand is also particularly sensitive to temperature.
After an exceptionally mild heating season in the northernhemisphere in 2020, 2021 saw more average – and even colder
than usual – temperatures. This forecast assumes average winterconditions for the forthcoming heating seasons, and the report uses
the average of futures prices during April 2021 as price indicators.
When futures price curves do not extend to the full forecast horizon,
we extend them to converge with medium-term fuel priceassumptions contained in the World Energy Outlook 2020 to

However, levels of uncertainty remain high for the course of the
global health recovery. The main short-term risk is the appearance
and spread of new Covid-19 variants, potentially more contagious
and more resistant to current vaccines. Although the repetition ofprovide an indication of assumed longer-term price evolution.

2020’s hard lockdowns looks less likely, further waves of infection
are possible. They would delay the global recovery and increase
disparities among economies in their individual growth paths.

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In spite of the unprecedented policy action to support the economy,
some longer-lasting impacts are likely due to investment delays andGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Economic activity and energy price assumptions
GDP growth assumptions, global and by region, 2019-2024

Gas price assumptions, 2019-2024
12

USD/MBtu

8%
6%
4%
2%
0%

8
6

-2%

4

-4%

2

-6%
-8%

10

2019
World
Asia PacificEurasia
Middle East

2020

2021

2022

2023

0

2024

AfricaCentral and South America
EuropeNorth America

2019

2020

2021

Oil indexation range
TTF

2022

2023

2024

Henry Hub
Asian spot LNG
IEA. All rights reserved.

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IEA. All rights reserved.

Sources: IMF (2021), World Economic Outlook; Oxford Economics (2021), Economic Forecasts (subscription required); CME (2021), Henry Hub Natural Gas
Futures Quotes; Dutch TTF Natural Gas Month Futures Settlements; EIA (2021), Henry Hub Natural Gas Spot Price; ICE (2021), JKM-Japan Korea Marker LNG
Future; ICIS (2021), ICIS LNG Edge (subscription required); Powernext (2021), Spot Market Data.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

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DemandGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas demand is expected to fully recover in 2021 from its drop in 2020, although the recovery
remains modest compared to the rebound after the 2008-2009 crisis
Global natural gas demand by region, 2008-2024

8%

FORECAST

4 000

6%

3 000

4%

2 000

2%

1 000

0%

0

-2%

2010

AfricaEurasia
North America

2012

2014

2016

Asia Pacific
EuropeY-o-y growth

2018

2020

2022

2024

Central and South America
Middle East
IEA. All rights reserved.

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IEA. All rights reserved.

2008

Y-o-y growth (%)

World gas demand (bcm)

5 000

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas demand bounces back at lower average growth rates, but still too high to be compatible
with net zero in the longer term
Natural gas demand is expected to reach close to 4 300 bcm by

From 2020 to 2024, the substitution of gas and efficiency gains
reduce natural gas demand by 80 bcm, mostly in power generation,

2024, adding 350 bcm or 9% compared to its 2020 low point.

moderating a gross demand increase of 430 bcm to a net increaseof 350 bcm. The return to economic growth – driven by theindustrial sector and led by Asia’s fast-growing markets – remains
the principal driver of rising gas consumption, accounting for almost

Short-term recovery plays a major role in the forecast period, withthe demand gains expected in 2021 accounting for about 40% of
the total increase. The global gas consumption growth rate stands
at 3.6% in 2021, then declines progressively over the following
years to 1.7% in 2024. Compared with 2019, natural gas increases
by only 275 bcm over the forecast period – or about 7%.

two-thirds of the gross demand increase to 2024. Fuel substitution
in favour of gas and at the expense of coal and oil, principally (butnot only) in the power generation sector, covers the remaining third.

The industrial sector, which provides the largest contribution to the2021 recovery in global gas demand, maintains a leading role in thefollowing years. The growing demand for natural gas, both forindustrial processes and as a feedstock, is expected to account fora dominant 40% share of the total increase in gas consumption overthe 2020-2024 period.

In spite of relatively modest demand growth in the coming years,
projected gas demand in 2024 is already about 2% above the 2025level of the World Energy Outlook 2020 Sustainable Development

The Asia Pacific region alone is responsible for almost half of totalgas demand growth, with a 47% share of the global increase. The
Middle East, the second-largest contributor to growth, stands far
behind at less than 20%. For most other regions, and especiallymature markets, the bulk of the increase comes in the initial years
as demand recovers from the 2020 downturn.

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Scenario. This scenario maps out a trajectory consistent with global
net-zero emissions by 2070. A faster decarbonisation path, as
described in the IEA Net Zero by 2050 report, would require evenslower growth.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Asia is the largest source of gas demand growth, driven largely by industry, but the recovery
from 2020’s downturn plays a predominant role
Breakdown of forecast growth in global natural gas demand, 2020-2024

2021

2022

2023

2024

By sector

Industry
Power generation
Residential and commercial
Energy sector
Transport

By region

Asia PacificMiddle East
North America
Eurasia
AfricaCentral and South America
EuropeIEA. All rights reserved.

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By yearGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

While the downturn in 2020 was less than expected, medium-term growth – following therebound – loses speed in this latest forecast update

4 300
4 200
4 100
4 000
3 900

360

1.7%

320

1.6%

280

1.5%

240

1.4%

200

1.3%

CAGR

4 400

bcm

3 800
3 700

2019

2020

Gas 2019 report

2021

2022

Gas 2020 report

2023

2024

Gas 2021 report

Gas
2019

Gas
2020

Net demand increase

Gas
2021

CAGR
IEA. All rights reserved.

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IEA. All rights reserved.

bcm

Evolution of global gas demand forecasts in the three latest issues of the IEA medium-term gas report, 2019-2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas demand from the industrial sector, which remained resilient in 2020, plays the lead role inmedium-term growth
The sectoral breakdown of the fall and rebound in gas demand in
2020-2021 is asymmetric; the crisis had a limited impact on
industrial uses of gas, which lead the recovery, whereas gas for
power generation was the most affected in 2020 and will see one of

weakened contribution to the 2021 rebound limits the role of thepower generation sector over the forecast period, with an average
1.4% annual growth rate for 2020 to 2024. Part of the increase ingas-fired generation (either from growing electricity demand or fromfuel switching) is offset by the addition of renewable capacity and –to a lesser extent – by higher efficiency of combined-cycle plant

the smallest increases in 2021.
The industrial sector is expected to be the main contributor to

replacing open turbines.

increasing gas demand to 2024, its consumption growing at an
average annual rate of 3.4%. It provides a two-pronged contribution
to growth: gas use as a fuel for industrial purposes on the one hand(principally driven by China, India and emerging Asian markets);and demand for natural gas as a feedstock for chemicals andfertilisers on the other hand (principally driven by gas producers and

The residential and commercial sectors, hit in 2020 by the
conjunction of a mild heating season and lockdown-induced
restrictions on commercial activity, bounced back in early 2021 oncolder-than-average winter temperatures. They should recover totheir 2019 levels. Such a rebound is expected to remain a one-off
event as growth potential remains limited outside a handful ofcountries – led by China, India and Iran – that continue developing
their city gas distribution networks. Gas demand for residential andcommercial uses is expected to grow at an average of 1.6%

exporters).
Gas use for power generation declined by about 35 bcm in 2020,
the equivalent of half of the total downturn in gas demand. The
impact of the crisis could, however, have been much worse without
the support of cheap gas prices that favoured coal-to-gas switching,principally in the United States (where gas-fired generation actually
grew in 2020) and to a lesser extent in Europe. Higher gas prices in
2021 have reversed this effect and hindered US gas-fired
generation versus coal – European gas competitiveness for power
generation being more protected by high carbon prices. Thisbetween 2020 and 2024.

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Increasing gas production and processing capacity sustains thegrowth of the energy sector’s own consumption, at an average 2%
rate, while gas as a transport fuel is expected to grow at a higher
rate of 4.8%, mainly driven by the growing use of LNG for trucks
and river transport in Asia.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

The industrial sector alone accounts for 40% of global growth in gas consumption over 20202024
Sectoral breakdown of global gas demand growth, 2019-2024

4 200
4 100
4 000
3 900
3 800

2019

Power generation

2020
Industry

2021

Residential and commercial

Transport

2024
Energy sector

IEA. All rights reserved.

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bcm

4 300

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Emerging regions and markets drive post-recovery growth in gas demand
In this forecast the Asia Pacific region is the main source of growthin demand for natural gas, with an average annual rate of 4.5% for
the 2020 to 2024 period. It contributes almost half of the global

0.7% annual growth rate. Canadian gas consumption follows astronger average growth rate of 2.4% over the 2020-2024 period,
principally supported by the abovementioned fuel switching in

consumption increase that follows the global recovery of 2021.
China, India and other fast-growing markets in emerging Asia
continue to drive the increase in gas demand, on a mix of economic
growth-related expansion and fuel substitution. China is the single
largest contributor to the growth in gas demand, accounting for
close to 30% of the total increase during the 2020-2024 period, led
by its industrial sector. In India industry keeps its leading role in gas
demand growth, supplemented by the residential and commercial
and transport sectors as the country rolls out its city gas distribution
networks. Power generation remains the major driver of gas
demand in emerging markets in South and Southeast Asia,
supported by growing electricity demand and the development of
new gas-fired generation capacity.

power generation. Gas demand in Mexico follows a moderate 1.3%
average rate, as growth in gas-fired generation slows and increases
in industry-related uses are partially offset by declining needs fromthe energy sector on lower domestic production.
Natural gas use in Europe remains broadly stable, with an
expected 0.4% average annual increase. Demand bounces back in
2021 with a 6% increase, driven by the combination of colder wintertemperatures, the return of industrial activity and limitedcompetitiveness loss in power generation thanks to high carbon
prices. The following years are marked by slight declines in gas
demand, as the potential gains from the retirement of nuclear, coaland lignite-fired capacity are offset by the expansion of renewables
in power generation and efficiency gains in other sectors.

North American gas demand is expected to grow at an average of

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Eurasia was the hardest-hit region in 2020, accounting for close to
40% of total gas demand loss. 2021 sees a return to pre-crisis
demand levels, principally due to the return of colder wintertemperatures that provided strong support for gas-fired heating andelectricity consumption. Growth flattens in the following years andreaches an average annual rate of 1.4% over the 2020 to 2024
period. The Russian Federation (“Russia”), which contributes about

1% per year during the 2020-2024 period. 2021 does not mark a fullrecovery to 2019 consumption levels as higher prices hamper US
gas-fired power generation to the benefit of coal. The power sector
slowly returns to growth over the forecast period, supported in
Canada by Alberta’s coal phase-out, to be completed in 2023. In the
United States gas demand stagnates after an initial industry-driven
rebound in the first years of the forecast, resulting in an average

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

three-quarters of the region’s gas demand, sets the trend with an
expected 1.5% growth rate. Demand is more mature in Ukraine withclose to zero growth, and turns negative in Belarus due to thecommissioning of the two units at Ostravets nuclear power plant.

end of the forecast period, with an average annual growth rate of
2.5% between 2020 and 2024. Demand prospects are morepositive in Argentina and Brazil thanks to the development ofdomestic gas production, whereas smaller markets where gas is
primarily used for power generation experience sluggish growth dueto the deployment of renewables, and Venezuela’s market is
expected to continue declining on shrinking domestic production
capacity.

Caspian and Central Asian economies provide slightly higher
growth rates than the region’s average, yet with limited additional
growth potential in already highly gas-intensive markets.
The Middle East is the second-largest contributor to demand

Natural gas consumption is expected to grow in Africa at an

growth over the forecast period, after the Asia Pacific region,
accounting for close to 20% of the total gas consumption increase.
The region, which avoided gas demand decline in 2020, is expected
to experience an average annual growth rate of 2.8% between 2020
and 2024. The bulk of additional demand comes from Iran andSaudi Arabia, and to a lesser extent from Iraq and Israel, while theUnited Arab Emirates makes a negative contribution due to thedevelopment of nuclear, coal and renewables in the country’s
electricity generation mix. Apart from this specific case, power
generation and water desalination remain the key drivers of gas
demand growth in the region, supported by demand from industry –especially for non-energy uses – and distribution customers (morespecifically for Iran).

average annual rate of 3.1% over the forecast period. While most of
the increase remains concentrated among the region’s three largest
markets of Egypt, Algeria and Nigeria, which together account forthree-quarters of total growth, smaller markets also experience
consumption increases. This is particularly the case for West Africa,
where the development of domestic resources in Mauritania andSenegal, and access to new LNG import capacity in Ghana, enable
the substitution of oil with gas in power generation. Gas-fired
capacity is also expected to start developing in South Africa fromlate 2022, with the planned commissioning of LNG-to-power
projects.

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Central and South America represents the most affected gas
market in 2020 in relative terms, with an estimated 9.9% y-o-ydecline in demand. The path to recovery is expected to be rather
slow as the region returns to its 2019 gas demand level only by theGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas consumption rebounds in 2021 with most regions recovering from 2020’s losses; Asia
Pacific drives growth from 2022 with an overwhelming 55% share of total demand increase
Change in global natural gas demand by region, 2019-2024

bcm

400
300
200
100
0

2019-242019-20

AfricaCentral and South America
EuropeNorth America

2020-212021-24

Asia PacificEurasia
Middle East
IEA. All rights reserved.

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- 100

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

After the 2021 recovery, global gas demand growth is equally driven by economic activity andfuel substitution for the rest of the forecast period
This forecast expects global gas consumption to increase by 9%
between 2020 and 2024 (adding 350 bcm), or 7% compared to2019 levels. This results from the contributions of several different
drivers, which play in favour of or against higher natural gas

and South America. Together these markets account for over twothirds of total economic activity-driven growth. North America is thelargest contributor among mature markets, principally thanks to theabundance of domestic gas resources to feed industrial demand.

demand.

The second contributor to demand increase is the substitution ofother fuels with gas, where additional natural gas does not add tototal energy consumption and emissions, but comes at the expenseof other, more CO2-emitting, fossil fuels. Replacement of coal andoil product volumes with natural gas results in an increase in gas

Growth in economic activity is the primary driver behind the global
increase in natural gas demand, accounting for almost two-thirds ofgross gas demand additions (or about 270 bcm). Due to the shapeof assumed GDP growth rates, economic activity plays a muchgreater role in the initial years of the forecast and especially in 2021
when it is assumed to drive most of the increase in gas demand.
Over the 2022 to 2024 period, the share of economic activity ingross gas demand growth falls to about 50%, on a par with fuelsubstitution.

demand of about 160 bcm over the forecast period.
Switching to natural gas arises from different types of incentive,
including: market-based pricing competitiveness (with or without acarbon pricing component); policy measures such as coal andnuclear phase-outs in Europe and industrial and residential boiler
conversion programmes in China; and physical supply

Higher economic activity in emerging markets is primarily driven bydebottlenecking solutions such as LNG-to-power value chains
under development in Southeast Asia, sub-Saharan Africa andCentral and South America.

industrial output, which in turn results in growing gas consumption
in the power generation and industrial sectors – both for industrial
processes and as a feedstock for chemicals and fertilisers. These
two sectors cover over 70% of economic activity-driven growth ingas demand to 2024 vs 2021. Unsurprisingly the vast majority ofsuch GDP-related consumption growth takes place in fast-growing
gas markets, especially in Asia but also in Africa, the Middle East

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The power generation sector provides the main contribution,accounting for half of total substitution with gas during the forecast
period. This stems from the combination of coal-reduction and/or

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

phase-out agendas, development of domestic natural gas capacity

substitution of gas, led by North America and Europe where the
combination of renewable capacity expansion and limited electricity
demand growth squeeze thermal generation. The deployment of
renewables (and nuclear) in other regions also contributes to a
reduction in the development of gas-fired generation, but this isand a desire to reduce oil import bills.
The large majority of gas demand gains from fuel substitution are in
Asia and the Middle East, with these two regions together
accounting for over two-thirds of the total increase. Fuel substitutionin Asia is led by China and targets coal in both the industrial andpartially offset by growing demand for electricity.

residential sectors. It is complemented by a mix of power sector
contributions from both mature and emerging markets, principally
aimed at coal but in some instances also targeting oil products. In
the Middle East, substitution gains are almost entirely driven by thepower generation sector and at the expense of oil. These comeprimarily from Saudi Arabia (although revised downwards due to
upstream project delays), and to a lesser extent from Israel andEfficiency has a more limited volumetric impact and is principallyfrom the power generation and energy sectors, which account for
80% of its total impact. Short- to medium-term changes in these
sectors are principally the replacement or retrofitting of turbines anddrilling and production engines, as well as operational efficiency
gains in gas production and processing. Other sectors, such asindustry or residential, show fewer short-term efficiency gains due totheir decentralised nature and longer life cycles, but provide an
additional contribution over the forecast period. About threequarters of the efficiency-related impact on gas demand growthoccurs in mature gas markets.

Iran.
Outside these two regions, gas demand growth from fuel switching
principally comes from power generation in North America – on a
combination of progressive recovery of US gas-fired generation andcoal phase-out in the Canadian province of Alberta – complemented
by Europe.

power generation, which accounts for over 95% of the impact.
Mature gas markets predominate, with a two-thirds share of global
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This primary increase is partially reduced by the joint impact of thesubstitution of gas with other energy sources and efficiency
factors, which taken together subtract the equivalent of 80 bcm ofgas demand. Switching away from gas occurs almost exclusively inGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Substitution of more CO2-emitting fossil fuels drives one-third of gas growth to 2024
Evolution of global gas demand by driver, 2020-2024

4 300
4 200
4 100
4 000

2019

3 900
3 800

2020

Economic
activity

Switch to gas

Switch fromgas

Efficiency

2024
IEA. All rights reserved.

PAGE | 21

IEA. All rights reserved.

bcm

4 400

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Power generation plays a central role in both sectoral demand increases and declines, while
there is a clear regional difference driving trends between mature and emerging markets
Main sectoral and regional component in each gas demand driver
Economic activity ()73%Industry andPower

Switch to gas ()Switch from gas ()

98%
Power

69%
Asia Pacificand Middle
East

50%
Power
generation

67%
Fast-growing
gas markets

Efficiency ()

80%
Power
generationand Energy

66%
Mature gas
markets

78%
Mature gas
markets

PAGE | 22

IEA. All rights reserved.

Note: “Fast-growing gas markets” include Africa, Asia Pacific excluding OECD countries (Australia, Japan, Korea and New Zealand), Central and South America,
and the Middle East. “Mature gas markets” include Asia Pacific OECD countries (Australia, Japan, Korea and New Zealand), Eurasia, Europe and North America.
IEA. All rights reserved.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas and energy transitions – at the crossroads on the way to 2050 net-zero emissions
The role played by natural gas in energy transitions is complex, withmultiple and diverging contributions: a versatile fuel of growth in
fast-growing markets, an enabler for reducing emissions when used
as a substitute for oil or coal, but also a major source of emissions
that needs to be reduced – especially in mature markets wheremuch of the growth and substitution potential has already beentapped.

reach 4 tcm by 2030, back to its 2019 level. The Net Zero by 2050
scenario requires a sharper decline to 3 700 bcm in 2030 –returning to the 2017 gas demand level.
The gas demand trajectory should therefore flatten to keep on track
towards global net-zero emissions by 2050. However, part of thisgas increase provides a positive contribution to lowering global
emissions through fuel substitution, while economic activity-driven
growth in gas demand results principally from the expansion of fastgrowing markets and improved access to energy. The remaining
drivers to slow demand growth would then be to further accelerate
fuel switching from gas and efficiency, especially in the moremature markets.

This diversity of factors is at play in our forecast to 2024. During thisperiod, annual gas demand grows by 350 bcm. Fuel switching fromgas and efficiency gains contribute to reduce annual demand by
80 bcm. Out of a total gross gas demand increase of 430 bcm,
higher economic activity accounts for almost two-thirds (270 bcm),
while fuel switching from coal and oil explain the rest (160 bcm).

Slower natural gas growth is needed to match a netzero path, with a higher substitution rate and efficiency
gains

The global increase in natural gas demand over the 2020 to 2024
period is rather modest, with a compound average annual growthrate of 2.2%. Yet this may still be too high to meet a net-zeroemissions target by 2050. This report forecasts a 9% increase inannual gas demand between 2020 and 2024 to reach close to
4 300 bcm. By comparison, the World Energy Outlook 2020
Sustainable Development Scenario, which maps out a trajectory
consistent with global net-zero emissions by 2070, sees natural gas
demand increase by only 4% between 2020 and 2025. In thisforecast, demand then declines by 4% in the following five years to

PAGE | 23

IEA. All rights reserved.

Achieving such a reduction in global gas demand over the medium
term is crucial to reaching net-zero emissions ambitions. But it
requires strong policy action, industry investment and consumers’
behavioural change for it to happen. Given the relatively long
lifetime of gas infrastructure and appliances, the impact of decisions– even those taken today – may not be visible within the time
horizon of this forecast.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

One driver available to reduce gas demand growth in the coming
years is to increase substitution. Any further acceleration in
renewable capacity additions to 2024 would contribute to reducing
the role of thermal generation, and therefore affect the amount ofterm equipment investment (such as improving the insulation of
furnace and oven walls and doors, or installing automatic controls to
optimise air-fuel ratios for burners), regular maintenance andoperating best practices (operate at close to full load capacity,

gas and coal consumed. This could, however, become more
complex where electrification simultaneously occurs for end usesthat have traditionally used gas, such as for cooking. Given a
maximum potential for renewable capacity additions, electrification
could result in additional electricity demand leading to an increase

reduce delays between cycles, recover heat from exhaust or fluegases to reduce primary generation) can lead to reductions innatural gas use of up to one-third.
In the case of residential heating, short-term efficiency gains can beobtained by replacing ageing individual appliances – for instance,
switching from an old conventional gas boiler to a condensing boiler
coupled with a heat pump water heater, which together can reduce
fuel consumption by up to 30%. Behavioural changes – such as
lowering the thermostat average temperature, or reducing it during
the night or before leaving – also contribute to reducing averagein thermal electricity generation.
Reducing gas consumption in the power generation sector can also
be achieved by improving power plant efficiency; the vast majorityof the world’s gas-fired generation fleet comprises open-cycle gas
or steam turbines with about half the efficiency of recent combined
cycles. Besides, over a quarter of the fleet of open-cycle turbines ismore than 30 years old. Accelerating their replacement withcombined-cycle gas plants (ideally hydrogen-ready to ensure future
fuel flexibility) could almost halve the individual gas consumption ofnatural gas consumption in a range of 7% to 12%.

each plant.
The other driver to lowering gas growth is to improve efficiency

PAGE | 24

IEA. All rights reserved.

beyond power generation. Taking into consideration the limited time
horizon of this forecast, visible improvements would come from a
mix of small-scale investment and operational behaviour changes
rather than large-scale changes that will require longer lead times.
In the industrial sector, for instance, the combined effects of short-Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Despite its moderate growth rate, global gas demand by 2024 would already be 2% above the2025 level in the Sustainable Development Scenario
Evolution of global gas demand compared to the WEO Sustainable Development Scenario and Net Zero by 2050 scenario

bcm

4 400
4 300
4 200
4 100
4 000
3 900
3 800
3 700
3 600
3 500

2015

2025

2020
Gas 2021

WEO Sustainable Development Scenario

2030
Net Zero by 2050 scenario
IEA. All rights reserved.

PAGE | 25

IEA. All rights reserved.

Sources: IEA (2020), World Energy Outlook 2020; (2021), Net Zero by 2050.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Focus on Asian gas demand: China
China’s economy rebounded quickly from the Covid-19-related
lockdowns in 2020, and the rapid expansion of gas demand is set tocontinue over the forecast period. Total consumption is projected toincrease at an average annual rate of nearly 7%, adding 95 bcm ofincremental demand between 2020 and 2024. China is the single
largest contributor to global gas demand growth, accounting for
close to 30% of the net increase by 2024.

generation capacity. China’s gas-fired fleet is set to expand by athird over the forecast period and reach 133 GW by 2024.
Residential and commercial users make up slightly less than 18%(17 bcm) of the demand growth in China, driven by new gridconnections and the ongoing conversion of small and inefficientcoal-fired boilers to cleaner fuels, including natural gas, to reduce
pollution in urban areas. The transport sector represents 14%(14 bcm) of the incremental demand between 2020 and 2024.
Nearly two-thirds of the growth within this segment comes from
LNG-fuelled trucks and buses, which are supported by local policies
and attractive payback times, followed by compressed natural gas(CNG) vehicles (20%), LNG-fuelled domestic shipping (12%) andtransport by pipeline (3%).

Nearly half of the aggregate growth is driven by fuel substitution.
About 70% of this comes from coal-to-gas conversions in industry
and the residential and commercial sector, and 30% from oil-to-gas
substitution in the transport sector. Overall, the net contribution offuel switching in China is almost twice as high as the global
average. This underlines the fact that government policies
incentivising a shift away from more polluting fuels remain an
important driver of gas demand in China over the medium term.
The industrial sector is the primary engine of growth, accounting for
43% (41 bcm) of China’s demand increase over the forecast period.
This is driven roughly in equal parts by growing industrial activity on
the back of a strong domestic (and global) economy and by thegovernment-mandated replacement of small coal-fired industrial
boilers to improve air quality. The power sector contributes a little
more than 18% (17 bcm) of the total consumption growth between
2020 and 2024, thanks mainly to continuing additions of gas-fired

lower transmission tariffs and the streamlined development of thedomestic gas grid. The new entity is expected to increase market
competition, stimulate new investment and reduce the cost of gas toend users over time. Although it is yet to be translated into specificpolicies, China’s recent pledge to reach net-zero emissions by 2060
is also set to encourage gas use (both as backup for renewables
and as a substitute for coal), at least in the medium term.
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IEA. All rights reserved.

The policy framework in China remains broadly supportive of
growing gas demand in the medium term. The official launch of
PipeChina in 2020, the country’s new national midstream operator,
marked a significant step towards improved third-party access,Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Focus on Asian gas demand: India
While India’s short-term outlook is clouded by a devastating second
wave of Covid-19 infections, which had the most disruptive effect inApril and May 2021, the prospects for continued growth in gas
demand remain strong in the medium term, aided equally byforecast period, as most of the country’s stranded gas-fired fleet is
uncompetitive without subsidies or an outright collapse ofinternational gas prices.
Natural gas enjoys considerable policy support in India, which
provides a strong basis for gas demand growth in the medium term.
The government has a stated ambition of building a gas-based
economy and increasing the share of natural gas in the primaryenergy mix from around 6% today to 15% by 2030. To support thisambition, in 2019 the Ministry of Petroleum and Natural Gas
announced a plan to invest USD 60 billion in natural gas
infrastructure. As part of the programme, India plans to complete
17 000 km of new gas transmission lines by 2024, expand the city
gas distribution network to cover 70% of India’s population, andincrease import capacity by nearly one half with the completion of
new LNG terminals, at least five of which are currently underconstruction. Government targets also include the addition of up to
1 000 LNG refuelling stations over time, and the next (11th) bid
round to further expand the gas distribution grid is expected to belaunched in the near future. Recent reforms to introduce a unified
tariff structure for domestic pipelines and plans to create an
independent gas transmission system operator could further

expanding infrastructure and a highly supportive policy
environment. India’s annual gas consumption is expected toincrease by 25 bcm in the 2020-2024 period, which translates into a
9% annual average growth rate. India is set to emerge as thesecond-largest driver of gas demand in Asia (after China) and thefifth-largest contributor globally (after China, Iran, Russia and theUnited States).
Almost two-thirds of India’s 2020-2024 demand expansion comesfrom fuel substitution, primarily from liquid fuels to gas. In theindustrial and energy sectors this means converting fertiliser plants
and refineries to natural gas. In the residential and commercial
sector, substitution is driven by the expansion of city gas distribution
networks to areas previously served by LPG or other fuels. In thetransport sector, CNG and to a lesser extent LNG displace oil
products as the refuelling infrastructure expands.
Nearly 40% of India’s net demand growth is expected to come fromindustrial users, while the remaining growth is roughly evenly split
between the residential, transport and energy sectors. Gas use forpower generation is projected to remain almost flat throughout the
PAGE | 27

IEA. All rights reserved.

support India’s gas demand growth in the years ahead.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Focus on Asian gas demand: Emerging Asia
Emerging Asia is expected to add 41 bcm of incremental gas
demand in the 2020-24 period, accounting for 25% of demand
growth in the Asia Pacific region and 12% worldwide. The collective
contribution of emerging Asia to global gas demand growth isthe energy sector, mainly driven by upstream activities and theoperation of LNG facilities across emerging Asia.
The region is increasingly dependent on LNG imports to bridge thewidening gap between declining indigenous production and growing
demand, and the medium-term outlook is highly dependent onfurther additions to the region’s gas infrastructure. There are someencouraging signs that the region’s infrastructure bottlenecks aregradually being addressed. Bangladesh completed thedebottlenecking of its regasification terminals in 2020, which now
enables the full utilisation of the country’s LNG import capacity. New
import terminals are scheduled to come online in Viet Nam(Hai Linh) and Indonesia (Jawa-1 FSRU) in 2021, and additional
regasification capacity is in advanced stages of development inThailand, Viet Nam and the Philippines. Indonesia and Thailand
also added LNG reload capability (and completed their first-ever reexports in early 2021), which could further enhance the flexibility of
LNG supply across the region. Remaining infrastructure bottlenecks(e.g. in Pakistan) and further delays in the development of planned

greater than of any single country except China. Unlike in China
and India, the bulk of the demand growth in emerging Asia is driven
by rising economic activity. Fuel substitution – from coal to gas inpower and oil to gas in industry – is only significant in Bangladesh
and Thailand in our assessment.
Nearly half (20 bcm) of the region’s demand expansion between
2020 and 2024 is projected to come from the power generation
sector, driven by the addition of about 18 GW of gas-fired
generation capacity. The industrial sector contributes another 31%(13 bcm) to emerging Asia’s growth, led by Indonesia, Malaysia,
Pakistan and Bangladesh. Given the lack of heating demand in theresidential and commercial sector (with the exception of Pakistan),its natural gas use is not expected to increase materially during theforecast period, only adding 7% (3 bcm) to the region’s net growth.
Gas demand in the transport sector is led by Pakistan, Bangladesh
and Thailand, the only countries with widespread adoption of CNG
vehicles, but the sector’s contribution of 4% (2 bcm) is relatively
modest due to the slow growth of CNG fleets across the region as awhole. The remaining 10% (4 bcm) of the net increase comes fromPAGE | 28

IEA. All rights reserved.

LNG-to-power projects, however, could still hamper the region’s gas
demand growth in the forecast period and beyond.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

China, India and emerging Asia account for almost half of the demand growth globally in 20202024, driven mainly by fuel substitution
Incremental gas demand growth by driver, 2020-2024
400

4 400

bcm
China

4 200

Economic activity
Switch to gas

200

India

Switch from gas

Emerging Asia

4 000

300

100

Efficiency

Rest of the world
0
3 800
- 100
3 600

2020

- 200

2024

China

India

Emerging Rest of
Asia the world
IEA. All rights reserved.

PAGE | 29

IEA. All rights reserved.

bcm

Incremental gas demand growth, 2020-2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Focus on Asian gas demand: Japan and Korea
Japan’s gas demand declined by 4.5% in 2020 due to the negative
impact of Covid-19. The declining trend is expected to continue
during the 2021-2024 period due to the lingering impact of Covid-19

Korea’s gas demand increased by 2% in 2020 thanks to the rapid
containment of the spread of Covid-19. This trend accelerates in
2021 with a 5% y-o-y increase, mainly driven by the economic

and the restart of nuclear power plants. Total consumption is set todecrease by 4% between 2020 and 2024.

recovery and continued coal-to-gas switching in power generation.
From 2022, however, the expansion of gas demand is expected toslow, with annual growth rates averaging less than 0.4% in theremainder of the forecast period. This is mainly due to lower gas
demand in the power sector following the addition of long-planned
nuclear (5.6 GW) and coal-fired (7.3 GW) generation capacity.
Some gas-to-coal substitution is expected to occur, despite the low
overall utilisation of coal-fired power units in the wake of thegovernment’s policy push to reduce air pollution. At the same time,city gas demand continues to increase at an annual average rate of

The decline is driven by the power generation sector, where nuclear
restarts and the increase in renewable generation reduce the needfor gas-fired generation. The trajectory of gas demand in Japan ishighly sensitive to power sector trends, particularly the timing andscale of nuclear reactor restarts, the rollout of renewables and thepace of improvements in generation efficiency. Other sectors are
expected to grow modestly, partially offsetting the decline in power
generation.

about 1%, led by the industrial and buildings sectors.

Japan’s commitment to reduce its GHG emissions by 46% by 2030
compared to 2013 levels will have repercussions for gas demand.
On the one hand, growing electrification of heating – combined with
nuclear restarts and the expansion of renewable generation – arelikely to reduce gas consumption. At the same time, further coal-togas switching in the power and industrial sectors could deliver quick

Korea’s gas demand trajectory remains highly uncertain throughout
the forecast period and will be greatly influenced by environmental
policies adopted to support the government’s 2050 net-zeroemissions target, which was announced in October 2020. As part ofthe plan, Korea pledged to replace coal-fired power generation with

reductions in GHG emissions, and thus support gas demand in themedium term.

PAGE | 30

IEA. All rights reserved.

renewable energy in the long term.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas demand in Japan and Korea take divergent paths in 2020-2024, led by different drivers

4
Economic activity

3
2

Switch to gas

1

Switch from gas

0-1

Efficiency-2

Net change 2020-2024

-3
-4
-5
-6

Japan

Korea
IEA. All rights reserved.

PAGE | 31

IEA. All rights reserved.

bcm

Incremental gas demand growth by driver, 2020-2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Oil to gas – the other fuel switching in power generation
Global electricity demand increased by about 26% between 2010
and 2019. This growth was primarily fuelled by the development of
renewables, which account for over half of additional electricity
generation over the past decade. Natural gas was the secondlargest contributor, accounting for close to 30% of the increase, thebalance being provided by coal. Oil-fired generation, whichamounted to close to 1 000 TWh in 2010, declined by 22% to 2019.

generation declined, this coincided in almost half of cases with anincrease in the share of gas-fired generation. The other half isprincipally correlated with a rise in renewable electricity’s market
share, with the balance of cases (about 15%) corresponding to anincrease in other fuels – mainly coal.

Substitution is driven by domestic gas monetisation andthe development of import projects

Although the amounts at stake are far less important than for coal –oil-fired generation accounts for less than 2% of global electricity

The main driver of switching is accessibility to alternative fuels,
either from domestic or imported sources. The largest consumers ofoil for power generation are almost all major oil and gas
producing and exporting countries. Some of these countries are
faced with strong electricity demand growth rates that have led to
an increase in oil burning in absolute terms, albeit that oil’s share insupply – its substitution nonetheless remains challenging. Indeed,oil-fired generation is concentrated in a limited number of national or
local markets where it plays a dominant role, principally either
because of its abundance as a fuel or because of the lack ofalternatives. This is especially the case in isolated markets such as
islands or remote regions where it is used to deliver electricity offgrid to industrial or residential customers. 1

the electricity generation mix has declined over the past ten years.
In Saudi Arabia, the world’s largest consumer of oil for power1
Oil-fired capacity can also be found in more interconnected markets as back-up generation,
generally used during demand peaks.

PAGE | 32

IEA. All rights reserved.

generation, the share of natural gas in power generation has
increased strongly, especially in the eastern and central regions of
the country (due to their proximity to gas production assets) where it
accounts for over 95% and 70% of total generation respectively.

In numerous emerging markets, the electricity system currently
relies heavily on low-efficiency plants burning diesel or fuel oil, asource of high energy import bills and local air pollution. A review ofthe past decade shows that in markets where the share of oil-fired

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Other regions currently rely almost exclusively on crude oil and oil
products. Aramco’s planned expansion of the country’s Gas Master
System would enable it to further develop gas-fired generation inenergy self-sufficiency and boosted the share of natural gas inpower generation. Gas-fired generation has more than doubled overthe past decade to account for close to 70% of the country’s
electricity mix in 2019, while oil-fired generation has halved. The
ramping-up of the Leviathan offshore gas field is expected to further

these regions.
In Iran, natural gas already dominates the power generation mix,
although oil products are still used despite an objective to phaseincrease the role of gas in power generation in the near future.
In Senegal, the development of the first phase of the Grand Tortue
Ahmeyim offshore project (jointly owned with Mauritania) will markthe start of gas-fired generation, as part of the project’s output isearmarked for domestic markets. First gas is expected by 2023 tothem out – this is due to natural gas supply constraints and theneed to ensure back-up for hydropower fluctuations. In Iraq, thedevelopment of gas-fired generation would meet three strategic
priorities: accommodating the country’s growing electricity demand,monetising currently flared associated gas production, and reducing
dependence on Iranian gas imports. The country aims to spend
USD 15 billion with private partners to develop domestic gas
production (notably monetising flared gas) in order to produce thefeed the 300 MW Cap des Biches CCGT project, which would
provide the equivalent of 25% of the country’s current generation. Itshould lead to a 40% drop in electricity production costs according
to state-owned utility Senelec. Oil products currently account forover 80% of the country’s electricity mix, which has some of thehighest electricity costs in West Africa.

equivalent of 12 GW of electricity.
Fast-track development of natural gas for power at the expense ofoil products is also a feature of the monetisation of recent gas
discoveries in less mature oil and gas producing countries. In
Egypt, the consumption of natural gas has jumped by almost 50%
over the past decade, with an acceleration since 2015 and theramping up of the Zohr offshore gas field. The power generation
sector accounts for over 60% of gas demand and close to 80% of
the country’s electricity is generated from gas – against about 15%
from oil. In Israel, the development of the Tamar offshore gas field

LNG-to-power projects enable fast-track electricity
access and oil-to-gas substitution in isolated systems

and start of production in 2013 enabled the country to increase its

PAGE | 33

IEA. All rights reserved.

The development of LNG-based flexible supply chains, with either
an onshore or floating regasification terminal, has fostered thetransition to gas-fired generation in several electricity systems.
While several LNG-to-power projects are now under development
or discussion in Asia to limit the role of coal in energy supply, theyfirst appeared in the context of oil-to-gas switching in small or

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

remote markets. Central America has a track record of developing

arrival of a floating regasification vessel in early 2021, allowing its
conversion to LNG ahead of the planned start-up of domestic

such integrated supply chains in various countries and territories
since the early 2000s – starting with Puerto Rico in 2000, followedby the Dominican Republic in 2003, Jamaica in 2016 with an initial

natural gas production in 2023.
In March 2021 South Africa’s Department of Energy listed eight
successful bidders for a total of 1 845 MW of power capacity as partof its Risk mitigation IPP Procurement Programme, designed toclose the country’s power supply gap and reduce its reliance ondiesel-fired turbines. Three of the selected projects are floating LNG
powerships totalling 1 220 MW, one is a hybrid solar and LNG
project of 197 MW, and the remaining three are solar and windprojects with a total of 428 MW. These projects still need to confirm
financial closing by end of July 2021 to go ahead, but they provide
an example of the strong complementarity of gas and renewables inthe drive to improve energy access and reduce emissions.

floating terminal and in 2019 with a second, and Panama in 2018.
Two new importers are set to join the group in 2021: Nicaragua andEl Salvador. In all these markets, the LNG infrastructure is coupledwith gas-fired combined cycles in order to displace oil products.
In South America several LNG projects have been developed tosupport power generation in remote markets, such as Chile’s
northern Mejillones terminal (initially floating in 2010 then replacedby an onshore terminal in 2014), or more recently Brazil’s Sergipe
LNG project, commissioned in 2020 together with 1 516 MW of gasfired combined cycle, the largest in South America. According to theWorld Bank’s analysis that supported its decision to finance theproject, the Sergipe LNG project is expected to avoid about
2.5 million tonnes of CO2 emissions a year by replacing diesel andfuel oil use.
LNG-to-power projects are also starting to take off in Africa. In West
Africa, Ghana’s Tema LNG floating regasification unit is expected

PAGE | 34

IEA. All rights reserved.

to receive its commissioning cargo in July 2021. Ghana’s National
Petroleum Company stated that gas from the LNG terminal willcontribute to improving electricity coverage and fuel the 1 500 MW
domestic gas-fired power generation fleet. In Senegal, a floating
power plant in operation since 2019 has been associated with theGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Natural gas has been the primary source of substitution for oil in power generation, which has
declined by 22% over the past decade
Oil substitution in power generation byreplacement fuel, 2010-2019

100%

50%

0%

0%

50%

100% 0%Share of gas in electricity mix
2010

50%

2019

100%
Gas

Note: Bubble size indicates oil-fired generation output per country.

Renewables

Other

IEA. All rights reserved.

PAGE | 35

IEA. All rights reserved.

Share of oil in electricity mix

Oil consumption for power generation and respective share of oil and gas in electricity
mix by country, 2010 vs 2019

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Transport sector gas demand set to grow rapidly from a low base…
Transport is the smallest but fastest-growing sector for natural gas
consumption, expanding at an annual average rate of 5% between
2020 and 2024. More than 60% of the growth comes from roadtransport, while the remainder is equally split between shipping andpipeline transport.

also eased rules for setting up LNG filling stations and introduced aplan to build 1 000 of them along the country’s main highway
corridors. However, the pace of the rollout beyond the 50 initial LNG
stations remains uncertain.
LNG use in marine transport has increased fivefold since 2016 andThe most widespread use of natural gas in the road transport
segment is in the form of CNG, with at least six countries having
fleets exceeding one million CNG-fuelled vehicles. CNG
consumption, which accounts for about 60% of the gas demandreached more than 2 bcm in 2020. LNG bunker fuel demand is set
to triple from 2020 levels to nearly 7 bcm by 2024. The International
Maritime Organization’s global sulphur cap, which phased out highsulphur fuel oil from the shipping sector in 2020, has accelerated

growth in road transport, is led by India and China. CNG uptake issupported by government policies and the expanding gas andrefuelling infrastructure in both counties. India’s programme toexpand CNG access is the most ambitious globally; it will add
another 4 500 CNG stations to its current network of 2 700 over the
next four years as part of the ongoing rollout of city gas
infrastructure. It is projected to more than double India’s CNG
demand between 2020 and 2024.

the adoption of LNG as a bunker fuel. As of January 2021, LNGfuelled ships made up about 8% of all vessels on order by one
estimate, and the fleet of LNG-propelled vessels (excluding LNG
carriers) is projected to expand by nearly 160% between 2020 and
2024. The inability of LNG to meet the IMO’s long-term GHG
reduction targets, however, casts doubt about the sustainability of
LNG demand growth in the shipping sector beyond our forecasthorizon.

LNG consumption in the road transport sector is dominated by
China, which had nearly 600 000 LNG-fuelled trucks and buses in
2020, the largest such fleet in the world. In the 2020-24 period,
China’s use of LNG in road transport is set to expand by more than
40%, driven by local incentives such as diesel bans and subsidies,and by lower fuel costs compared to diesel trucks. In 2020 India

LNG consumption for domestic shipping is expected to double
during the 2020-24 period, led primarily by China, and – to a lesser
extent – Europe.

pipeline gas flows, particularly in China, Russia and North America.
PAGE | 36

IEA. All rights reserved.

Natural gas use in the pipeline transport segment increases moremodestly at 8% (6 bcm) between 2020 and 2024, driven by growing

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021… driven by the road transport and shipping segments
200
180
160

Road transport (CNG)

140
Road transport (LNG)

120
100

Domestic shipping (LNG)

80
60

Marine shipping (LNG)

40
Pipeline transport and other

20
0

2019

2020

2021

2022

2023

2024
IEA. All rights reserved.

PAGE | 37

IEA. All rights reserved.

bcmTransport sector gas demand, 2019-2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

PAGE | 38

IEA. All rights reserved.

SupplyGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Most medium-term gas production growth comes from projects already under development
Global natural gas production dropped by an estimated 2.9% y-o-yor 120 bcm in 2020, a larger impact than in the aftermath of the2008 financial crisis (when gas supply declined by 100 bcm in2009). Demand recovery in 2021 and further growth in emerging
markets in the coming years are accompanied by gas supply
expansion, as output grows by 9% between 2020 and 2024 in thisforecast. It is worth mentioning, however, that this additional output
comes at a slower rate than before 2020 and is almost exclusively
from projects already under development.

the LNG Canada project. Mexico’s production continues to decline,
although at a more moderate pace than in previous years.
Eurasia has taken the brunt of 2020’s gas market adjustment, witha double impact on domestic and export sales that led to a close to
60 bcm decline in annual production compared to 2019 – about halfof the world’s total supply adjustment. The region’s natural gas
output is set to expand by 17% between 2020 and 2024, largely
driven by Russia, which accounts for over 85% of Eurasia’s growth.
Russia’s gas production is set to expand by 18%, mainly driven by
the ramp-up of new and recent export projects (the Power of Siberia
pipeline, the Yamal and Arctic LNG 2 plants) and the recovery ofexports to Europe. Azerbaijan is the second contributor to exportdriven production growth, with the ramping up of capacity to fill the

North American gas production showed some resilience in 2020,
with a modest 1.6% decline. This is particularly the case with US
gas production outlets, as export capacity ramp-up provided further
access to foreign markets, while lower prices triggered fuelsubstitution in the domestic market’s power generation mix. This
forecast expects North America’s gas production to account for
about a quarter of global supply growth to 2024, with a 7% increase
between 2020 and 2024. Modest US gas production growth is

TANAP and TAP pipelines to Europe. Turkmenistan leads thegrowth in Central Asia, while development potential appears more
limited for Kazakhstan, and even more so for Uzbekistan where gas
production is facing severe upstream issues that lead to an
expected end to gas exports by 2025 (it stopped exporting to
Russia in mid-2020).

principally driven by LNG export needs, and is delivered by dry
shale gas plays in general – and by the Appalachian Basin inparticular – with some support from the oil-driven Permian Basin as
light tight oil production recovers. Canadian production stagnates as
new domestic needs from Alberta’s coal phase-out are offset bylower pipeline exports to the United States, increasing slightly overthe end of the forecast period to prepare for the commissioning of

The Middle East is another major contributor to the medium-term

PAGE | 39

IEA. All rights reserved.

growth in global gas production, with a 9% increase between 2020
and 2024. This is related to the commissioning of a limited numberof large-scale projects currently under development, aimed both at

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

domestic and export markets. The North Field/South Pars giant
offshore field accounts for over half of the region’s development, tomeet Qatar’s scheduled expansion of LNG export capacity and
Iran’s growing domestic gas market needs respectively. This is

first phase of the Grand Tortue Ahmeyim complex developed
across the maritime border of Mauritania and Senegal. Productionin North Africa is generally stable, with some limited increase in
Egypt offsetting declines in most other neighbouring markets.

complemented by additional developments in Saudi Arabia andIsrael.

Gas production in Central and South America is expected to growby 10% over the forecast period, as output gradually returns to its
2019 level by 2024 after a notable decline in 2020. Most of the netincrease compared to 2019 comes from Brazil’s associated gas inpre-salt developments, which contributes to offsetting the net losses
from Venezuela and other legacy producers.

Gas production in the Asia Pacific region is set to increase by 7%
compared to 2020, to approach 700 bcm by 2024. Most of theregion’s growth is from China, which sees its domestic gas
production increase by 23% over the forecast period to above
230 bcm by 2024, thanks to continued policy support to develop gas
output. India is expected to grow and surpass its pre-2020 level of
output. Australia’s gas supply stabilises at around 150 bcm peryear, while more mature producers such as Indonesia and Malaysia

Europe’s natural gas production is expected to decline by 8%

Africa’s gas production grows by 10% between 2020 and 2024 inthis forecast to reach 265 bcm per year – a downward revisioncompared to our previous forecast. This is mainly due to thepostponement of the Mozambique LNG export project, which is notexpected to start operating before 2025 following the recent force

drop and heavy maintenance in 2021, other European domestic
production is expected to decline by almost a quarter. This is driven
by the combination of depleting fields in the North Sea, the closureof Groningen in the Netherlands and terminal output decline fromsmaller fields in the Netherlands and across Europe. Two outlierswith modest growth emerge outside Norway: Denmark, with therestart of the Tyra field, which boosts the country’s production tomajeure linked to security issues. The bulk of growth comes fromthe commissioning of other export-driven developments such as theclose to 3 bcm by 2024; and Romania, with some limited growthpotential.

decline slightly over the forecast period.

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IEA. All rights reserved.

between 2020 and 2024, to below 200 bcm per year by the end of
this period. While Norwegian output is recovering after the 2020

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Gas production grows modestly, rising 6% above 2019 levels by 2024, principally driven bymajor developments in Eurasia and the Middle East as well as new US shale wells
Global natural gas production by region, 2008-2024

FORECAST

4 000
3 000
2 000
1 000
0

2008

Africa2010
Asia Pacific

2012

2014

2016

Central and South America

Eurasia2018
Europe2020
Middle East

2022

2024

North America
IEA. All rights reserved.

PAGE | 41

IEA. All rights reserved.

World gas production (bcm)

5 000

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

US gas production is expected to resume growth, albeit at a slower pace
US natural gas production fell by about 15 bcm (or 1.6%) in 2020
from an all-time high of close to 970 bcm in 2019. Output dropped
from a record 86 bcm in December 2019 to 76 bcm in June 2020 on
a combination of lower domestic and export needs, before
rebounding to 82 bcm in December 2020. Gas production is
expected to grow further over the medium term, as prices recoverfrom their low 2020 levels and export capacity ramps up, albeit at a

In addition to delivering returns to investors, the US gas industry is
also expected to face tougher environmental performance targets.
As the new US administration puts climate considerations among its
top priorities, producers will have to accelerate planned activities
such as tackling flaring and methane leakage, and progressing
carbon capture and sequestration. US producing companies havestarted to focus more on environmental, social and corporate
governance issues, topics that remained more marginal in previous
years.

more modest rate than previously observed.
Pure-play shale gas producers have confirmed their financial
objectives for 2021, with investment kept flat and the objective ofdelivering returns to investors as market prices continue theirrecovery. This financial cautiousness is likely to contribute to lower
growth in the coming years. In the Appalachian Basin, the country’s
largest contributor to gas production, output was maintained
throughout 2020 and even grew by 3% y-o-y in spite of a 30%
decline in monthly drilling activity. Production kept growing thanks tothe start-up of previously drilled but uncompleted (DUC) wells,

This corporate context, together with almost flat domestic demand,
does not provide strong support for US gas production growth overthe medium term, which will instead be driven mainly by thecountry’s growing LNG export capacity. This forecast expects US
dry gas output to pass the 1 tcm mark and reach above 1 030 bcm
in 2024, or a 9% increase compared to 2020 (7% compared to2019). Dry shale gas plays are expected to provide most of theadditional volumes, led by the Appalachian Basin. This modest

providing a lower-cost alternative to new developments. Over the
past 18 months the Appalachian Basin’s DUC count has shown asteep decline of nearly 30%. The trend is less visible in the
Haynesville gas play, where drilling activity remained more stable

growth is also supported by developments in tight-oil production(dominated by the Permian Basin). Contributions from otherassociated shale basins stagnate, while dry gas output fromconventional assets continues its decline.

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IEA. All rights reserved.

throughout 2020.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

US dry gas production progresses slowly from 2022, driven by LNG exports’ feedgas needs
Dry gas production by main source in the United States, 2014-2024

12%

FORECAST

1000

10%

800

8%

600

6%

400

4%

200

2%
2014

2015

2016

2017

2018

2019

Other production
Permian Basin
Appalachian Basin

2020

2021

2022

2023

2024

0%

Other associated shale
Other dry shale
Share of production for LNG exports
IEA. All rights reserved.

PAGE | 43

IEA. All rights reserved.

0

Share of production for LNG exports

bcm

1200

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Export-oriented projects are set to drive Russia’s gas production…
Russia’s annual gas production is expected to expand by over 17%(or close to 120 bcm) between 2020 and 2024, to account for
approximately one-third of incremental global gas supply during theforecast period. This will be largely supported by demand recovery
in 2021 and the country’s growing exports (both pipeline and LNG),
together driving almost 80% of additional gas supply requirements
between 2020 and 2024.

growth and the continued ramp-up of exports through bothtraditional and new export channels.
The Yamal Peninsula is set to drive Gazprom’s production growththrough the forecast period, while the traditional production centres
in Western Siberia continue to deplete. Besides Bovanenkovo
reaching its 115 bcm/y nameplate capacity, the Kharasavey field is
expected to be commissioned by 2023 (although reaching its
nameplate capacity of 32 bcm/y beyond our forecast period).
Novatek’s Utrenneye field in the Gydan Peninsula will support theRussia’s gas production is set for a strong recovery in 2021.
Following a steep drop in 2020, gas output is expected to increaseby 12% (over 80 bcm) y-o-y to above 2019 levels as domestic
consumption returns to growth and exports climb to above pre-crisis
levels. The recovery in gas supply will be supported by Russia’s
large fields in Western Siberia, including Urengoyskoe,company’s Arctic LNG 2 export project, with its production expected
to reach approximately 20 bcm/y by 2024. Rosneft is set tocontinue its gas development programme in Western Siberia. This
includes the phased commissioning of the Rospan fields throughout
the forecast period and the project launch of the Kharampur field(expected to reach its nameplate capacity of 11 bcm/y by 2022/23).

Yamburgskoye and Zapolyarnoe, all of which produced well below
their nameplate capacities in 2020. In addition, the giant
Bovanenkovo field is expected to reach its nameplate capacity of
115 bcm/y in 2021/22. In Eastern Siberia, the continued ramp-up

In Eastern Siberia, the Chayandinskoe field is expected to reachits 25 bcm/y design capacity by 2024, whilst production capacityfrom the Kovyktinskoye field is set to reach 15 bcm/y. This resultsof supplies to China via the Power of Siberia pipeline is expected toincrease annual production from the Chayandinskoe field byapproximately 6 bcm in 2021.

in an incremental output of 30-32 bcm/y between 2021 and 2024 as
supplies to China via the Power of Siberia pipeline continue to ramp
up. The Amur gas processing plant is expected to reach its

Russia’s gas production is expected to increase by close to 2% peryear between 2021 and 2024, amidst moderate domestic demand

PAGE | 44

IEA. All rights reserved.

42 bcm/y design capacity by 2025.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021…expanding by close to one-fifth between 2020 and 2024bcm

Natural gas production growth in Russia by key fields, 2020-2024

850
800
750
700
650
600

2020

Bovanenkovo Chayandinskoye Kharasavey
and Kovytkinskoye

Utrenneye

Others2024

IEA. All rights reserved.

PAGE | 45

IEA. All rights reserved.

Source: IEA analysis based on various companies reports.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Middle Eastern natural gas production is set for rapid expansion…
The Middle East’s annual gas production is set to expand by 9% (or64 bcm) between 2020 and 2024, driven by the region’s strong
demand growth – particularly in Iran and Saudi Arabia – and partly

export capacity by over 40% (or 45 bcm/y). This is set to provide amajor boost to Qatar’s gas output, expanding the country’s
production to close to 230 bcm (or 30% above 2020 levels).

supported by the continued oil-to-gas switching in the power sector.
As such, the region is expected to contribute over 17% of the

Saudi Arabia’s annual production is set to increase by nearly 20%(18 bcm) in 2020-24, driven mainly by the 10 bcm/y expansion of
the Hawiyah gas processing plant and growing associated gas
output from existing fields. Recent capex cuts pushed the online
date of the Marjan increment programme and the 26 bcm/y Tanajib
gas processing plant to 2025. Production start-up at the Jafurah
shale development is expected in 2024, but unconventional gas
only contributes materially to supply growth beyond our forecasthorizon.

world’s additional gas supply during the forecast period.
The North Field/South Pars Gas Condensate field, shared
between Iran and Qatar, is expected to account for over half of theregion’s production growth between 2020 and 2024. This is partly
driven by the continued strong demand growth in Iran, expected to
expand by almost 15% by 2024. The ramp-up of South Pars
Phases 13, 14 and 22-24 will add close to 30 bcm/y of production
capacity over the forecast period. Drilling started in late 2020 at
South Pars Phase 11, which is expected to begin production by
March 2022 and add an estimated 20.5 bcm/y of production

Israel is projected to see a substantial 77% (12 bcm) production
increase between 2020 and 2024, as the Leviathan field ramps up
to full capacity, output from Tamar recovers after the removal of
takeaway capacity bottlenecks and the Karish development starts
production from 2022. About 60% of the incremental supply is
directed to the domestic market to meet growing demand anddisplace LNG imports. The remaining 40% is exported by pipeline tocapacity by the end of the forecast period.
Qatar’s gas output is expected to increase by 2% per year between
2020 and 2024, driven by growing domestic production amidst thecommissioning of new gas-fired power generation and desalination
facilities. This includes the commissioning of the 2.6 GW Facility E,with the first power and water from the plant due in June and July
2023 respectively. Beyond our forecast, the expected start-up of theNorth Field East project in Q4 2025 increases the country’s LNG

PAGE | 46

IEA. All rights reserved.

Egypt and Jordan to satisfy existing contractual commitments.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021…driven by strong domestic growth and rising exports

bcm

Natural gas production growth in key Middle Eastern gas markets, 2020-2024

90%

60

80%

50

70%
60%

40

50%

30

40%

20

30%
20%

10
0

10%
Qatar

Iran
Domestic market

Saudi Arabia
Exports

Israel0%Growth in % (2024 vs 2020)

IEA. All rights reserved.

PAGE | 47

IEA. All rights reserved.

Source: IEA analysis based on various companies and news reports.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

PAGE | 48

IEA. All rights reserved.

Tracking clean gas progress

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

The neighbour’s gas is always greener: Clean gas policies and market developments
announced the establishment of the Net-Zero Producers Forum todevelop zero-emission strategies, including methane abatement.
Also in April, the US Senate voted in favour of reinstating methane
emission regulations. Meanwhile, the industry is developing newcommercial proposals, such as carbon/GHG-offset LNG and isadvancing carbon management technologies associated with LNG

Natural gas alone accounted for more than one-fifth of global CO2
emissions in 2020. With the recovery of natural gas demand,carbon emissions from natural gas combustion are set to increaseby 3% in 2021, to reach an all-time high of 7.35 Gt. Moreover,natural gas operations were responsible for over 40 Mt of methane
emissions in 2020 – equating to over half of the total energy-related
CO2 emissions of the European Union. Given the immediate needproduction.

to reduce the climate impact of fossil fuels, the gas industry willneed to rapidly undertake several measures, including: (1) reduce
the GHG emission intensity of its various supply chains; (2) support
the integration and deployment of low-carbon gases; and (3)minimise emissions occurring from the combustion of natural gas
through carbon management solutions.

The production of low-carbon gases (including biomethane,hydrogen and synthetic methane) remains expensive and theirdeployment will take time; however, the industry, infrastructure andregulation should begin adapting now to enable their cost-efficient
integration into the gas system in the future. The European
Commission is set to publish its Hydrogen and clean gas package

Reducing methane emissions through the gas value chain would
be a time- and cost-efficient manner for the gas industry to act on
climate change. Around 40% of current methane emissions from oil
and gas operations could be avoided at no net cost. A number ofjurisdictions are considering the introduction of regulations to tackle
the gas industry’s GHG emissions and to incentivise their reduction.
The European Commission announced the EU Strategy to reduce
methane emissions in October 2020, to be followed by a set ofon the integration of low-carbon gases by the end of 2021. The
deployment of carbon management technologies (including
carbon capture and storage [CCS] and carbon capture, utilisationand storage [CCUS]) could significantly reduce the emissions fromthe end use of natural gas, in both the industrial and the power
sectors, including for the production of gas-based low-carbonhydrogen.

PAGE | 49

IEA. All rights reserved.

In this section we review recent gas market developments andpolicy initiatives supporting the reduction of GHG emissions along
the gas value chain and the deployment of low-carbon gases.

legislative proposals in 2021. In April 2021 the governments ofCanada, Norway, Qatar, Saudi Arabia and the United States

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Principal clean gas policies, industry initiatives and market developments, 2019-2021

Note: MRV = measurement, reporting and verification.
Sources: IEA analysis based on IEA (2021), Net Zero by 2050: A Roadmap for the Global Energy Sector; industry data, press releases and various news reports.
PAGE | 50

IEA. All rights reserved.

IEA. All rights reserved.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

In the spotlight: Reducing the emission intensity of LNG supply
GHG emissions associated with LNG have come under increased
scrutiny from governments and market participants in recent years.
Global LNG trade has more than tripled since the beginning of the
century, while GHG emissions from LNG supply and end use hadreached an estimated 1.25 Gt CO2-eq (~17% of emissions fromnatural gas) by 2020. 2 Expectations of tightening future regulations
and emission standards are set to drive investment in GHG
emissions reduction measures over the medium term. Meanwhile,

Ras Laffan with a capacity of 2.1 Mtpa. The North Field East LNG
project is set to be developed in association with a CCS facility,
integrated into the wider CCS scheme in Ras Laffan.
Qatar Petroleum’s sustainability strategy states that the company
aims to capture more than 7 Mtpa of CO2 emissions by 2030.
Russia’s Novatek is currently investigating the potential to develop
CCS-based solutions to reduce the carbon intensity of its operations
associated with LNG production. The company is targeting a final
investment decision (FID) by 2022. BP is considering thedevelopment of the Ubadari field in Indonesia in association with aemission intensity is emerging as a critical differentiator among LNG
projects, as lower emission profiles are seen as a natural hedge
against regulatory uncertainties.

CCS project to supply Tangguh LNG. Besides CCS, the emission
intensity of feedgas supply can be reduced through the mitigation of
methane leaks/venting and the electrification of compressor stations
along the transmission system.

Reducing emissions will require effort through the entire value
chain. The upstream segment (including production, gathering,processing and transmission to the liquefaction plant) typicallyaccounts for 10-25% of total (well-to-use) emissions. CCS/CCUSbased solutions can reduce the GHG emission intensity of
feedgas supply by capturing and storing reservoir CO2 during theprocessing of raw gas. Currently only Snøhvit LNG in Norway and
Gorgon LNG in Australia are using CCS in association with their
upstream operations. Qatar announced in October 2019 thecommissioning of a CO2 recovery and sequestration facility in

The liquefaction process itself accounts typically for 6-10% of
LNG’s overall emissions. Using electricity from renewable sources
can significantly reduce emissions associated with LNG plant
operations. LNG Canada will rely on hydropower for all of its
auxiliary power needs. Qatar Petroleum’s sustainability strategy
stipulates the addition of more than 4 GW of renewable (mainly
solar) power capacity to its portfolio by 2030, partly to supply

Assuming that life-cycle emissions of a conventional LNG cargo (~175 000 m3) translate intoaround 250 000 t CO2-eq.
PAGE | 51

IEA. All rights reserved.

2

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

the end-use combustion of regasified LNG, typically 60-80% ofelectric power to the North Field East LNG project. The use ofelectric drives instead of gas turbines to power the liquefaction

total emissions. Improving the efficiency of the power fleet and
CCS/CCUS-based solutions can reduce end-use emissions.

compressors can significantly improve the environmental
performance of the LNG plant, provided that electricity originatesfrom low-carbon sources. CCS-based solutions can be applied

Carbon/GHG-offset LNG continues to gain traction. Under thismechanism, stakeholders involved in LNG trading can agree to buy
carbon credits to offset GHG emissions from the LNG value

directly at the liquefaction plant level. NextDecade announced in
March 2021 that its yet-to-be-sanctioned Rio Grande LNG project

chain. Since July 2019 at least 15 carbon/GHG-offset LNG cargoes
have been delivered, of which 12 were to Asian buyers. The scopeof emissions typically covers all the segments of the value chain,including combustion (well-to-use), whilst a few cargoes have beendelivered with partial emission offsets. In more recent deals,
emissions have been expressed in CO2-eq, whilst others explicitly
indicated the inclusion of methane emissions.

in the United States would be equipped with a 5 Mtpa CCS unit,
enabling it to reduce its permitted carbon emissions by more than90%. Venture Global LNG plans to capture and sequester ~1 Mtpa
from its Calcasieu Pass and future LNG projects.
Shipping typically accounts for 5-10% of total emissions, largely
depending on the vessel’s propulsion system, boil-off rate, speed
and distance travelled. Better fuel efficiency and enhanced boil-off
management systems can reduce the emission intensity of LNG
shipping. The share of less-efficient carriers with steam turbine
propulsion systems dropped from over 50% of the fleet in 2015 to
38% in 2020, while the share of vessels with ME-GI and XFD
propulsion systems (50% higher fuel efficiency compared to steam
vessels) rose from 1% to 16% during the same period. Altogether
they account for over 85% of the order book.
Regasification represents only a fraction of total emissions,typically 1-3%. Enhanced boil-off recovery, low-carbon electricity
sourcing and mitigation of venting/methane leaks can further reduce

emissions data associated with each LNG cargo produced from its
US liquefaction facilities, starting from 2022. Tokyo Gas, together
with 14 other Japanese companies, announced in March 2021 theestablishment of a Carbon Neutral LNG Buyers Alliance to promoteemissions at the regas plant. The majority of emissions stem fromthe use of carbon-neutral LNG.

PAGE | 52

IEA. All rights reserved.

LNG carbon offset mechanisms would benefit from greatertransparency and a standardised MRV framework across theindustry. The European Commission is set to present legislative
proposals for a compulsory MRV framework for all energy-related
methane emissions in 2021. Singapore’s Pavilion recently awarded
two contracts with obligations to quantify GHG emissions
associated with each LNG cargo. Cheniere plans to provide GHG

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Reducing emissions will require effort along the entire LNG value chain
Indicative breakdown of life-cycle GHG emissions for US LNG shipped to Europe, showing carbon reduction options
CCS/CCUS to capture reservoir CO2
Venting/methane leak reduction
Electrification of compressor stations
Low-carbon electricity sourcing

Upstream*

CCS/CCUS at liquefaction plant
Replace gas turbines with electric drivers
Low-carbon electricity sourcing

Liquefaction

Enhanced boil-off gas recovery
Reduction of methane slips
Optimisation of shipping routes/trading

Shipping

Cold energy recovery
Enhanced boil-off gas recovery
Low-carbon electricity sourcing
Venting/methane leak reduction

Regasification

Improve efficiency of the power fleet
CCS/CCUS-based solutions at power plant level

Power plant
operations
0%

20%

40%

60%

80%

100%

IEA. All rights reserved.

PAGE | 53

IEA. All rights reserved.

* Upstream includes natural gas extraction, gathering and boosting, processing and domestic pipeline transport.
Note: GHGs are based on the common mass basis of CO2-eq using the global warming potential of each gas from the IPCC Fifth Assessment Report (AR5).
Source: IEA analysis based on National Energy Technology Laboratory (2019), Life Cycle Greenhouse Gas Perspective on Exporting Liquefied Natural Gas from theUnited States: 2019 update.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Keep counting: Carbon/GHG-offset LNG continues to gain traction

Notes: CER = Certified Emission Reduction; VCS = Verified Carbon Standard; VER = Verified Emission Reduction; CCB = Community and Biodiversity Standard.
Sources: IEA analysis based on companies’ press releases and various news reports
PAGE | 54

IEA. All rights reserved.

IEA. All rights reserved.

Gas Market Report Q3-2021

Gas 2021: Analysis and forecast to 2024

Biomethane continued to grow strongly in 2020…
In contrast with natural gas, biomethane production continued to
grow strongly in 2020. Preliminary data suggests that it expanded
by 18% last year to reach 4.7 bcm, a tenfold increase since 2010.
This has been largely driven by the European Union and the UnitedStates where biomethane production benefits from a wide range ofpolicies and subsidies.

account for ~17% of total gas supply in 2020. The share ofbiomethane reached a daily record of 40% in July 2020. In France,

The United States emerged as the world’s largest biomethane
producer in 2019 when it surpassed Germany. The country’s
biomethane output rose more than fivefold from 2010 to reach over

Biomethane production is expected to grow at an average rate of
18% per year through the forecast period to reach ~9 bcm by 2024.
This growth will be largely driven by Europe and North America,
where biomethane is supported through various subsidy schemes
and is benefiting from well-developed and interconnected gas grids.
France’s multiannual energy plan foresees biomethane grid
injection at 14-22 TWh by 2028, whilst Denmark’s transmission
system operator expects biomethane to cover over 60% of Danish
gas consumption by 2030. The relatively high production costs ofbiomethane remain a challenge over the medium term. The right
set of policies could provide additional upside potential forbiomethane injected into the distribution network rose by 82% toreach 0.15 bcm. In Germany, which accounts for 40% of Europe’s
output, biomethane production capacity rose by a moderate 5% in2020 according to data from Biogas Partner.

1 bcm in 2019. Over 80% of biomethane production units have grid
injection capability. According to the Coalition for Renewable
Natural Gas, transport accounted for over 80% of biomethane end
use in 2019. Over half of producing units were using landfill gas asa feedstock at the end of 2019. Preliminary data indicates thatbiomethane production capacity increased by 30% y-o-y in 2020,
driven by projects using agricultural waste as a feedstock.
In Europe, biomethane production rose more than tenfold from2010 to reach almost 2.5 bcm in 2019. It is estimated that close to80% of biomethane is injected into gas transmission and distribution
networks. Preliminary data suggests that biomethane grew strongly
in some of the key European markets in 2020. Biomethane injection
into Denmark’s transmission system rose by close to 50% y-o-y tobiomethane development, especially in the rapidly growing marketsof the Asia Pacific region. China and India announced ambitious

market, please refer to the IEA World Energy Outlook special
report, Outlook for Biogas and Biomethane.
PAGE | 55

IEA. All rights reserved.

targets recently, which could support global biomethane production
reaching 28 bcm by 2024. For an in-depth review of the biomethane

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021…and is expected to almost double by 2024
Biomethane production by region, 2010-2024

bcm

10

8

6

4

2

0

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
EuropeNorth America

Other regions

Sources: IEA analysis based on Argonne National Laboratory (2020), Database of Renewable Natural Gas (RNG) Projects: 2020 Update; Biogas Partner (2021),
Biogaspartner Einspeiseatlas Deutschland; Cedigaz (2021), Global Biomethane Database; Energinet (2021), Energi Data Service; GRDF (2021), Production
annuelle de biométhane par site d'injection.
PAGE | 56

IEA. All rights reserved.

IEA. All rights reserved.

Gas Market Report Q3-2021

Gas 2021: Analysis and forecast to 2024

Beyond biomethane: Hydrogen and synthetic methane make inroads on the gas grid
The existing natural gas infrastructure can facilitate the deploymentof low-carbon gases beyond biomethane, including low-carbonhydrogen and synthetic methane. Blending hydrogen in gas
networks can provide a transitional solution until dedicatedAustralia’s first pilot project was launched in May 2021. Canada andCalifornia are set to launch their first pilot projects later in 2021.
Based on projects that have reached FID or are under construction,hydrogen blending capacity could increase more than tenfold by2024, largely driven by Europe. Supporting policies and regulatory
mechanisms, including guarantees of origin, could further facilitate
the development of hydrogen trading and transport via pipeline.

hydrogen networks are developed, whilst in the longer term parts ofthe gas infrastructure can be converted to hydrogen, resulting insubstantial cost savings.

Gas-to-hydrogen pipeline conversions are expected to gradually

Due to its chemical properties, hydrogen can lead to theembrittlement of steel pipelines, i.e. the possibility of fissure inpipelines as a result of the reaction of H2 with the steel they aretake off in the medium term, mainly in Europe. Gasunie converted
the first gas pipeline fully to hydrogen in the Netherlands inNovember 2018 and several pilot projects are under considerationin Germany and France. Based on project submissions from
European gas network operators, ENTSOG assessed in its latest
Ten-Year Network Development Plan that some 500 km of gas

made from. Depending on the characteristics of the gastransmission system, hydrogen can be blended at rates between
2% and 10% by volume without requiring substantial retrofitting.
The hydrogen tolerance of polymer-based distribution networks istypically greater, allowing blending of hydrogen up to 20% by
volume. The grid injection capacity of low-carbon hydrogenprojects has more than quadrupled since 2013; however, volumes
remain limited (1-2% of low-carbon hydrogen production fed into thegrid). The estimated grid injection capacity of low-carbon hydrogenprojects reached 40 mcm in 2020, almost all of which is in Europe
and dominated by Germany. Several pilot blending projects havepipelines could be converted to hydrogen by 2024, although theseprojects have yet to be confirmed.
Synthetic methane (SNG) is struggling to take off. While SNG is

been undertaken in recent years, including in France (GRHYD),
Italy (in Contursi Terme) and the United Kingdom (HyDeploy).

stagnation in SNG production in the medium term.
PAGE | 57

IEA. All rights reserved.

perfectly interchangeable with natural gas, its production would
require the development of a separate CO2 value chain. Hydrogenbased SNG production capacity was less than 10 mcm in 2020 –almost all of which is in Europe and connected to gas grids. Only afew projects are currently under development, indicating potential

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Hydrogen blending capacity is set to increase tenfold, while syngas stagnates
Synthetic methane grid injection capacity

Hydrogen grid injection capacity

2020-2024

2020-2024

Source: analysis based on IEA Hydrogen Projects Database.
PAGE | 58

IEA. All rights reserved.

IEA. All rights reserved.

Gas Market Report Q3-2021

Gas 2021: Analysis and forecast to 2024

Fit for 55: Can the surge in European carbon prices create an alliance between natural gas,
CCS and low-carbon hydrogen?
The recent surge in European carbon prices is rapidly improving
the cost-competitive position of low-carbon hydrogen produced via
SMR+CCS. EU ETS prices rose from an average of EUR 12/t CO2eq during the last decade to over EUR 55/t CO2-eq in May 2021.
This has been partly driven by the agreement reached in December
2020 to raise the 2030 emission reduction target from 40% to 55%

Carbon management solutions, such as CCS/CCUS, cansignificantly reduce the emissions from conventional hydrogenproduction, including from steam methane reforming (SMR). Fossil
fuel-based hydrogen currently accounts for over 98% of globalhydrogen production, resulting in over 900 Mt CO2 emissions per
year globally, of which about 70-100 Mt are in the European Union.

and its anticipated impact on the EU ETS. The new target will be
underpinned by the “Fit for 55” legislative package to be

SMR+CCS accounts for the majority of global low-carbon hydrogenproduction, albeit on a tiny scale. The first commercial-scale SMR
facility equipped with CCS technology started operations in 2013 at
Air Product’s facilities in Port Arthur, Texas, with a carbon capture
capacity of 1 Mtpa. It has been followed by Shell’s Quest Projectin Canada (commissioned in 2015 with 1 Mtpa capacity) and theTomakomai CCS Demonstration Project in Japan (operating
between 2016 and 2019 and capturing ~0.3 Mt CO2). In Europe,
Shell’s Pernis refinery in the Rotterdam area captures carbon

presented in summer 2021. Consequently, the cost differential
between SMR and SMR+CCS decreased, which in turn, could
support additional investment in CCS in the medium term.
Several large-scale SMR+CCS/CCUS projects are currently underdevelopment in Europe. In Sweden, a pilot project at the hydrogengas plant of the Lysekil refinery started operations in May 2020. The
target is to scale up CCS capacity to 0.5 Mtpa by 2025. In the
Netherlands, the 2.5 Mtpa Porthos CCS project is expected to takeemissions from hydrogen production as part of the OPAC project,which reuses CO2 for enhanced crop growth. In 2015 Air Liquide
equipped its Port-Jérôme hydrogen production facility in France witha cryogenic CO2 purification system (~0.1 Mtpa). Progress on new
SMR+CCS project development has been meagre since 2016 due
to a combination of poor project economics and often challenging
regulatory environments.

FID in 2022 and start operations in 2024. Porthos would receive
CO2 from various sources, including from hydrogen production. In
the United Kingdom several projects are undergoing feasibility
studies, potentially adding 20 Mtpa of CCS capacity either entirely

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IEA. All rights reserved.

or partly associated with hydrogen production.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

The cost spread between conventional and low-carbon gas-based hydrogen is tightening€/kgH2

Production costs of hydrogen via SMR vs SMR+CCS in the European Union, 2010-2021
2.5

2

1.5

1

0.5

SMR+CCS

Apr-21

Nov-20Jun-20Jan-20Aug-19Mar-19Oct-18May-18Dec-17

Jul-17

Feb-17

Sep-16

Apr-16

Nov-15Jun-15Jan-15Aug-14Mar-14Oct-13May-13

Dec-12

Jul-12

Feb-12

Sep-11

Apr-11

Nov-10Jun-10Jan-100

SMR

Notes: Capex: SMR without CCUS = EUR 910/kW H2; SMR with CCUS = EUR 1 580-2 100/kW H2; gas price = TTF; carbon price: EU ETS.
Source: Bloomberg (2021), TTF and EUA prices.
PAGE | 60

IEA. All rights reserved.

IEA. All rights reserved.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

PAGE | 61

IEA. All rights reserved.

Trade

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

LNG remains the main driver of global gas trade after 2021, though growth is slower than
beforeGlobal gas trade – including both LNG and long-distance pipeline –is expected to expand more quickly than demand growth over the2021 and by the rising import requirements of Europe and China
through the rest of the forecast period. Following a steep drop of
10% in 2020, European pipeline imports are set to recover toforecast period, principally driven by LNG expansion.

close to their 2019 levels in 2021, and increase at an average
growth rate of 2% between 2021 and 2024, largely driven by theregion’s rapidly declining domestic production. This will be met by a

Global LNG trade is expected to expand by 16% between 2020
and 2024, driven by continued growth in Asia. The annual average
growth rate of 3.8% over the forecast period is a far cry from the
double-digit rates observed between 2016 and 2019, but represents
a recovery from 2020’s low rate of 1.4%. Investment in newliquefaction projects stalled in 2020 due to the Covid-19 pandemic,
but the growth in gas demand is also slower compared to pre-Covid
levels. In the 2021-2024 period incremental LNG demand growth
only marginally exceeds liquefaction capacity additions, which limits
the risk of a structurally tight LNG market in the next three years.
China, India and emerging Asian markets account for most of the
future growth in LNG imports. Europe remains the main importing
market after Asia, keeping its role as the balancing market for LNG.
On the supply side, North America accounts for more than 70% of
the growth as the primary engine of export development.

combination of higher Norwegian deliveries, the ramp-up of
Azerbaijani flows via the TAP pipeline to 10 bcm/y and higher
Russian pipeline exports.
Similarly, China’s pipeline imports are expected to expand by
more than two-thirds between 2020 and 2024. This growth will belargely dominated by the ramp-up of Russian export flows via thePower of Siberia pipeline, which are set to reach 30 bcm/y by theend of our forecast. In North America, US net imports from Canada
are expected to oscillate in the range of 50-55 bcm/y during theforecast period, and play a critical role in meeting seasonal demandswings. Additional pipeline capacity between the United States and
Mexico will allow US exports to Mexico to expand by close to 10%
between 2020 and 2024.

Long-distance pipeline trade 3 is expected to expand by over
one-fifth between 2020 and 2024, driven by a strong recovery in
For the purpose of this analysis, long-distance pipeline trade includes Europe’s pipeline imports(including deliveries from Norway), North American net pipeline trade and China’s pipeline imports.
PAGE | 62

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3

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Global LNG trade is expected to reach 561 bcm by 2024, anincrease of 16% compared to 2020.

and the Middle East (driven by Kuwait) also register small increases
throughout the forecast period.

LNG import growth is predominantly driven by the Asia Pacificregion, where demand for LNG is set to rise by 26% (89 bcm)
between 2020 and 2024. The region’s share of global LNG imports
is projected to increase from 71% in 2020 to 77% in 2024. Chinaalone is expected to account for nearly 30% of global LNG demand
growth in the 2020-2024 period, and is on track to become theworld’s largest importer of LNG on a yearly basis in 2021 or 2022.
India is responsible for more than 20% of the net increase globally;
import growth is expected to re-accelerate from 2022 as the postCovid gas demand recovery coincides with a slowdown in
production growth. Emerging Asian countries are projected to
double their LNG imports between 2020 and 2024, driven by strong
demand growth and the decline of domestic production. Japan’s
LNG imports are expected to gradually decrease, while Korea’s
LNG demand continues to expand over the forecast period.

LNG export growth is led by North America, which is projected toboost production by 86% (55 bcm) between 2020 and 2024. Thisstrong growth is driven by already sanctioned liquefaction projects,
albeit some of these will not start production (or reach full capacity)
within the forecast period. Russia is the second-biggest source of
LNG supply growth, with a 38% increase between 2020 and 2024.
Export growth from Africa is limited due to the delay of theMozambique LNG project. Output from the Middle East remains
stable through to 2024, as Qatar's expansion project is notexpected to ramp up before 2025. Exports from Asia Pacific andSouth America are on course for a slight decline between 2020 and
2024.
The utilisation of available liquefaction capacity is expected togradually recover from the low point of 88% in 2020, but remains
slightly below the 2019 level of 93% at the end of the forecast
period. Therefore, the risk of persistent supply shortfalls and astructurally tight LNG market remains limited throughout theforecast period. However, periods of temporary tightness may occur– and lead to dramatic price swings – as was illustrated by theNortheast Asian energy crisis in January 2021, when a combinationof surging demand, supply constraints and a lack of storage pushedspot LNG prices to record-high levels for a brief period.

European LNG imports reached record levels in 2019 and 2020,
and are expected to decrease and oscillate around 90 bcm in the2021-2024 period as the region continues to play the role of swing
consumer to balance the market. Europe’s share of total LNG
imports is expected to decrease from 23% in 2020 to 16% in 2024.
LNG imports into Africa (led by Ghana, Senegal and South Africa)

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IEA. All rights reserved.

LNG import growth is dominated by Asia; LNG supply growth is led by North America and Russia

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Global LNG trade reaches more than 560 bcm by 2024
World LNG imports and exports by region, 2015-2024
bcm

600

ActualIMPORTS

Forecast

400

AfricaAsia Pacific200

Central and South America
Eurasia0

Europe-200

Middle East
North America-400
EXPORTS
-600

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024
IEA. All rights reserved.

PAGE | 64

IEA. All rights reserved.

Source: IEA analysis based on ICIS (2021), ICIS LNG Edge.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

LNG trade growth only marginally exceeds capacity expansions, leading to a slow increase inutilisation rates

75%

200

70%

100

65%

0

60%

Liquefaction capacity

LNG exports

2024

300

2023

80%

2022

400

2021

85%

2020

500

2019

90%

2018

600

2017

95%

2016

700

2015

bcm

Global LNG trade and liquefaction utilisation rate, 2015-2024

Utilisation rate (%)

PAGE | 65

IEA. All rights reserved.

Note: Liquefaction capacity and utilisation rate are based on assessed available capacity – adjusted to take into account the assumption that several liquefaction
plants will remain offline or run below their nameplate capacity because of technical issues, lack of feed gas, weather-related issues or security risks.
Source: IEA analysis based on ICIS (2021), ICIS LNG Edge.
IEA. All rights reserved.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

LNG investment: Tentative post-Covid recovery underway
True to the cyclical nature of the LNG business, the pace of FIDs on
new LNG capacity have fluctuated wildly in recent years. In 2019
developers approved nearly 100 bcm of new capacity (worth
USD 65 billion), an all-time high far exceeding any previous records.
This was followed by a near collapse of activity in 2020, with only
one project (the 4 bcm Energía Costa Azul plant in Mexico) taking
FID as the Covid-19 crisis brought new investments to a standstill.
2021 has seen a sharp rebound of sanctioned capacity, but so far
this has been solely driven by Qatar’s 45 bcm expansion project,
the largest FID in the history of LNG. Notwithstanding the wide
fluctuations in project approvals in recent years, the spending profile
associated with already sanctioned projects is expected to recoversteadily from a low point of USD 14 billion in 2020 to USD 30 billion
in 2024. Annual spend on liquefaction projects is expected toscale seen in 2018-2019. The appetite for additional uncommitted
LNG among portfolio players could be limited by the overhang ofsuch volumes from the previous cycle, which will be compounded

average USD 24 billion in the 2020-2024 period, 13% lower than in
the preceding five years.
The previous wave of LNG FIDs in 2018-2019 was led by the major
portfolio players, which participated as offtakers, equity partners ordevelopers in all of the liquefaction projects sanctioned in that
period. Confidence in long-term market growth – combined with thewidespread use of the equity-lifting structure – enabled projects to

Nonetheless, market developments in H1 2021 indicate that there
may well be room for further investments in 2021 and beyond. In
the month of May 2021 alone, North American pre-FID projects
secured two binding long-term sales purchase agreements with
offtakers, more than in 2020 as a whole. Qatar Petroleum
announced that it is planning to approve the second 22 bcm phaseof its expansion project by early 2022, and that the company isreach FID without having to secure end-use demand for equity LNG
volumes in advance. This trend is unlikely to be repeated on theevaluating additional capacity increases beyond the six-train
development envisaged by 2027.

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IEA. All rights reserved.

by the expiry of nearly 200 bcm of long-term LNG contracts
between 2021 and 2025. Capex cuts and write-downs on LNGrelated assets – combined with greater uncertainty about future
LNG demand and investor pressure to limit fossil fuel investment –could present further headwinds to another investment wave led byinternational oil companies in the foreseeable future. Independent
developer-led projects (especially in North America) also sufferedsetbacks, saw their FID target dates pushed back and in somecases were outright cancelled in the past 18 months as buyer
appetite for new long-term LNG contracts dried up during the
pandemic.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Investment in new LNG liquefaction capacity, 2010-2024

100

40

USD (2019) billion

FIDs for new LNG liquefaction capacity, 2010-2021

80
60

30

20
40

North America

2024

2023

2022

2021

2020

2019

2018

2017

2016

2015

2014

Middle East2013

Europe2011

2010

5-year average
IEA. All rights reserved.

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IEA. All rights reserved.

2020

2019

2018

2017

Eurasia

2021

Asia Pacific

2016

2015

2014

2013

2012

2011

Africa

2012

10

20

2010

bcm

LNG investment: 2018-2019 wave and 2021 recovery drives sustained capex growth to 2024

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

LNG shipping: Robust order book mitigates risk of capacity shortfall in the medium term
The LNG shipping market has been characterised by substantial
volatility and periods of seasonal tightness in recent years. Daily
spot LNG vessel charter rates have spiked above USD 100 000 ineach of the last three northern hemisphere winters, and hit an alltime high of well above USD 200 000 during the unexpected cold
spell in northeast Asia in January 2021 – amid physical shortages ofavailable shipping capacity. Expectations of growing shipping
demand are supported by the lengthening of shipping routes on the
ramp-up of export capacity from the United States and Russia, as
well as by the latest wave of LNG FIDs in 2018-2019, with the bulk

(21 vessels in total) are Arc7 class carriers dedicated to serve theArctic LNG 2 project in Russia.
In addition to the substantial capacity already on order, Qatar
Petroleum announced in 2020 that it had booked slots for nearly
120 newbuild vessels at Chinese and Korean shipyards. These
units – if converted into firm orders – are only expected to enter themarket after 2024, however, as the vessels are primarily intended toserve Qatar’s recently approved 45 bcm expansion project and theGolden Pass LNG project on the US Gulf Coast, which is being
jointly developed by ExxonMobil and Qatar Petroleum. Both plantsof sanctioned capacity entering the market in the 2021-2024 period.

are scheduled to ramp up production from 2025.

These fundamental drivers have incentivised fleet operators tomaintain a robust order book for LNG vessels. At the end of 2020
as many as 150 LNG vessels were on order, which represents aquarter of the active carrier fleet (excluding FSRUs). Of these,nearly 60 ships are scheduled for delivery in 2021, adding close to
10 million m3 of capacity, an 11% y-o-y increase. The market entryof the remaining 15 million m3 of capacity on order is spread acrossthe period between 2022 and 2025. The vast majority (98%) of theorder book is so-called Neopanamax vessels ranging between
170 000 m3 and 180 000 m3 in size, which can navigate the new
locks on the Panama Canal. One of the largest contingents of ships

Global LNG shipping demand is expected to rise by 38% in the2020-2024 period. Despite this strong increase, we estimate thatthe 31% expansion in shipping capacity is sufficient to maintain fleet
utilisation at around 90% through to 2024, if no retirements occur. If
Qatar’s anticipated large-scale shipbuilding programme is fully
executed, the risk of capacity shortfalls could be limited evenbeyond the end of our forecast horizon. Such long-term visibility is
unusual in the LNG shipping market, where the investment cycle is

PAGE | 68

IEA. All rights reserved.

relatively short, approximately two to three years. However, as
projects in Russia and Qatar in particular take a more strategic
approach to vessel procurement, the visibility horizon can hence be
expected to lengthen in the years ahead.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

LNG shipping: Capacity growth helps keep the market in balance through to 2024
Evolution of LNG shipping capacity, 2019-2024

800

100%

700
80%

600

120

100

80

500

60%

400

60
40%

300

40

200

20%

100
0

million m3

174 000 m3 vessel eq.

LNG shipping capacity, demand and fleet utilisation, 2019-2024

2019

2020

Shipping capacity

2021

2022

Shipping demand

2023

2024

Fleet utilisation %

20

0

2019

2020

2021

On order

2022

2023

2024

In operation
IEA. All rights reserved.

PAGE | 69

IEA. All rights reserved.

Sources: IEA analysis based on GIIGNL (2021), Annual Report; ICIS (2021), ICIS LNG Edge.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Pipeline trade is set to expand by over one-fifth by 2024
domestic production. Norwegian deliveries to the rest of thecontinent are set to recover to above their 2019 levels and hover
between 110 bcm/y and 115 bcm/y for the rest of the forecast
period. The Baltic Pipe is expected to be commissioned by October
2022 and will provide Norway with the option to supply 10 bcm/y ofnatural gas to Denmark and Poland, with Poland’s PGNIG having
already booked over 8 bcm/y capacity. Azeri pipeline flows
through the TAP pipeline – commissioned in January 2021 – areexpected to ramp up to their 10 bcm/y nameplate capacity in thenext two years, providing additional supply diversity to the Italianand Southeast European gas markets. North African exports toFollowing a record drop in 2020, long-distance pipeline trade 4 is
expected to expand by over one-fifth (or 100 bcm) during theforecast period, meeting close to 30% of incremental demand
between 2020 and 2024. This is driven by a strong recovery in 2021
and supported through the rest of the forecast by the rising importrequirements of Europe and China.
Europe’s net pipeline imports declined by over 10% in 2020, owing
to the steep drop in pipeline flows from Russia, North Africa andIran. Norway’s pipeline deliveries remained resilient, while Azeri
exports increased by over 20% y-o-y. Pipeline flows are expected torecover to over their 2019 levels in 2021, driven by a strong
increase in Russian and North African imports (up by 18% and130% y-o-y respectively in H1 2021) and the initial ramp-up of Azeri
flows to Italy and Southeast Europe through the TAP pipeline.
Approximately 3 bcm of natural gas has been exported via TAP in
H1 2021 and flows are set to exceed 5 bcm in 2021 as a whole.
Norwegian deliveries are expected to remain close to levels seen

Italy and the Iberian gas markets are expected to average close to
30 bcm/y during the forecast period. In May 2021 Algeria’s
Sonatrach commissioned a “loop” between its GME and Medgaz
pipeline systems. The loop could potentially increase direct export
flows to Spain via the Medgaz pipeline, once the capacity of thelatter is expanded from its current 8 bcm/y. Russia’s net pipeline
exports are expected to reach 200 bcm/y by the end of the forecast

2020 due to a heavy maintenance schedule on the Norwegiancontinental shelf and pipeline system during Q2-Q3 2021.
Europe’s pipeline imports are expected to expand by 6% between
2021 and 2024, primarily driven by the region’s rapidly declining
4 For the purpose of this analysis, long-distance pipeline trade includes Europe’s pipeline imports(including deliveries from Norway), North American net pipeline trade and China’s pipeline imports.
PAGE | 70

IEA. All rights reserved.

period, supplied through a combination of traditional export routes
and the commissioning of new pipeline infrastructure. This includes
midstream capacity being built-up in Southeast Europe to enable ahigher offtake from TurkStream’s second string. The newGas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

from Central Asia are expected to hover between 40 bcm/y and 45
bcm/y during the forecast period, as higher export flows from
Turkmenistan are likely to be offset by declining deliveries fromUzbekistan – the country aims to cease exports by 2025.

interconnector between Serbia and Hungary (with a capacity of
6 bcm/y) is expected to be commissioned by Q4 2021.
China’s pipeline imports fell by 5% y-o-y in 2020, as the initialramp-up of flows via the Power of Siberia pipeline from Russia(4.1 bcm) was not sufficient to offset plummeting gas deliveries fromCentral Asia (dropping by 13% y-o-y). China’s pipeline imports areNorth American net pipeline trade remained flat y-o-y in 2020, as
declining net imports from Canada to the United States (down by

expected to recover to close to their 2019 levels in 2021. This will
be largely driven by the continued ramp-up of flows via the Power ofSiberia, reaching 4 bcm in the first five months of 2021 and set tototal 10 bcm in the year as a whole. Pipeline deliveries fromCentral Asia are expected to recover only marginally in 2021 and toremain below their 2019 levels, due to lower supplies from
Kazakhstan and Uzbekistan.

7%) were compensated by higher pipeline deliveries from theUnited States to Mexico (up by 7% y-o-y). Net imports from
Canada are expected to recover to above their 2019 levels in 2021,
increasing by close to 20% y-o-y in H1 2021. This was partly

Flows via the Power of Siberia are expected to triple between 2021
and 2024, reaching 30 bcm at the end of our forecast. This will beenabled by the ramp-up of production from the Chayandinskoye
field and the Kovyktinskoye field (to be commissioned in late 2022)
and the start-up of the Amur gas processing complex. In China the
middle section of the China-Russia East pipeline started
commercial operations in December 2020, allowing Russian gas
flows to reach the Beijing-Tianjin-Hebei region. Construction works
started on the final, southern section of the pipeline in the summerof 2020. The section is expected to be commissioned in 2025,
channelling gas down to Shanghai and enabling the Power ofSiberia to reach its 38 bcm/y supply capacity. Pipeline deliveries

was enabled by the expansion of cross-border capacity and the
expansion of Mexico’s pipeline system. Recent capacity additions
include completion of the Samalayuca-Sásabe pipeline(4.8 bcm/y), which started commercial operations in January 2021.
The Tula-Villa de Reyes pipeline (10 bcm/y) is set to becommissioned later this year, allowing for a further increase in US
pipeline exports to Mexico. US exports to Mexico are expected toincrease by close to 10% between 2020 and 2024.
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IEA. All rights reserved.

supported by the cold spell in February 2021, when Canada’s
pipeline deliveries played a key role in meeting the spike in US gas
demand. Canadian net exports are expected to oscillate at 5055 bcm/y during the forecast period and play a key role in meeting
seasonal demand swings. US pipeline exports to Mexico rose by
45% between 2016 and 2020 and grew strongly in H1 2021, up by
15% y-o-y (despite a temporary decline during the February cold
spell). The sharp increase in US-Mexico gas trade in recent years

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

The growing import requirements of Europe and China are set to drive pipeline trade growthLong-distance pipeline trade growth 2020-2024

Long-distance pipeline trade, 2014-2024

IEA. All rights reserved.

PAGE | 72

IEA. All rights reserved.

Sources: IEA analysis based on CEDIGAZ (2021), Trade – Annual Flows; China Customs Office (2021), Customs Statistics; EIA (2021), Natural Gas Data,
Imports/Exports; ENTSOG (2021), Transparency Platform; Eurostat (2021), Imports of Natural Gas by Partner Country – Monthly Data.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021

Global underground gas storage capacity is expected to expand by 9% in the next five years…
Underground gas storage (UGS) in porous reservoirs (such as
depleted fields and aquifers) plays a critical role in meeting
seasonal demand swings, whilst fast-cycling salt caverns are well-(salt cavern) and Silviri storage facilities from 0.6 bcm to 5.4 bcm
and from 2.8 bcm to 4.6 bcm respectively. In Italy, the Cornegliano
storage site is expected to ramp up its working capacity from thesuited to meeting short-term demand fluctuations. Global UGS
capacity is set to expand by 9% from 420 bcm in 2020 to over455 bcm by 2026, largely driven by China, Europe and Eurasia. Salt
caverns are expected to account for one-third of total capacity
additions over the forecast period. Project delays and regulatory

current 0.2 bcm to over 1 bcm in the forecast period.
In Russia, Gazprom continues to expand the country’s gas storage
capacity, with the target to increase the daily withdrawal capacityfrom 0.84 bcm in 2020/21 to 1 bcm. This includes theredevelopment and expansion of existing storage facilities, theconstruction of fast-cycling salt caverns and the build-up of new
UGS facilities in regions with high natural gas demand. Based on
projects currently under development and/or construction, Russia’s
gas storage capacity is expected to increase to close to 80 bcm
through the medium term. In Belarus, the Mozyrskoe salt cavern’s

uncertainties present a risk to the current storage outlook.
China is expected to add 17 bcm of UGS capacity in 2021-2026,
accounting for nearly half of the increase globally. At the end of
2020, China’s working gas capacity was estimated at between
14 bcm and 16 bcm by various sources, close to or exceeding the2020 target of 14.8 bcm under the 13th five-year plan, but less than
5% of total consumption, well below the level in mature markets.
The government has stepped up support for new storage capacity
since 2018, but progress has been slow due to the long lead time of
USG projects. Expansion is set to accelerate in the next five years,
led by CNPC and Sinopec. PipeChina, which assumed control overthree UGS facilities at its inception in 2020, is also expected to playa more active role in UGS development in the next five years.

capacity is set to expand from the current 0.3 bcm to 0.65 bcm by
2023.
Storage additions are expected to be limited in other regions. In the
Middle East, Iran is set to increase the combined working capacityof its Sarajeh and Shourijeh storage sites from 3.25 bcm to 6.5 bcm
by 2023. In the United States, Sempra has asked the Federal

Europe’s UGS capacity is set to increase over the forecast period.
This is largely driven by Turkey, with the expansion of the Tuz Gölü

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IEA. All rights reserved.

Energy Regulatory Commission for permission to build a new salt
dome facility with a working storage capacity of 0.55 bcm, expected
to start up in Q1 2024.

Gas 2021: Analysis and forecast to 2024

Gas Market Report Q3-2021…with China accounting for almost half of incremental storage capacity

bcm

Expected UGS capacity additions in key gas markets, 2020-2026

480

420

360

300

2020

China

EuropeEurasia

Other regions

2026
IEA. All rights reserved.

PAGE | 74

IEA. All rights reserved.

Source: IEA analysis based on various companies and news reports.

Gas market update and short-term forecast

Gas Market Report Q3-2021

PAGE | 75

IEA. All rights reserved.

Gas market update and short-term forecast

Gas market update and short-term forecast

Gas Market Report Q3-2021

Gas demand growth in 2021 is expected to offset 2020 losses globally, although some mature
markets are not fully recovering
Change in gas demand by region, 2019-2021

World
Eurasia
North America
2020

EuropePower generation

Central and South America

Industry

AfricaResidential and commercial
Energy sector

Middle East

Transport

Asia Pacific

Net growth 2019-2021
- 60

- 40

- 20

0

20

40

60

80

100

120

140
bcm

IEA. All rights reserved.

PAGE | 76

IEA. All rights reserved.

- 80

Gas market update and short-term forecast

Gas Market Report Q3-2021

North American gas consumption almost recovered during Q2 2021 after a mixed winter,although 2021 gains are still not likely to offset 2020 losses
Natural gas demand in the United States declined by an estimatedon a combination of recovering economic activity and lower gas
prices after the end of the heating season.

0.2% y-o-y during the first half of 2021. Support from cold
temperatures drove heating demand up in the first two months ofthe year, but these gains were offset by lower gas-fired electricity
generation (down 3.8% y-o-y over the first six months) due to higher
fuel prices than in 2020. At the end of the first quarter of 2021 gas

Canada’s natural gas demand slightly increased by 1% y-o-y in thefirst quarter of 2021, principally supported by wholesaleconsumption for power generation and in industry (up 2%), while
retail customers’ demand stagnated. Canadian pipeline exportsrose strongly in the first half of 2021, increasing by close to 20% yo-y. This was primarily a response to US production constraints inburn for power generation lost close to 9% compared to 2020, as
colder weather kept prices at higher levels. Gas-fired generation
resumed growth over the second quarter as fuel competitiveness
improved. Rising temperatures by the end of June supported
electricity demand, with price spikes in California and Texas. Higher
demand combined with higher capacity outages put a strain on
system operators who issued early summer conservation alerts.

February.
Mexico’s apparent natural gas consumption followed a y-o-yincrease during the four first months of 2021, as the growth inimports more than compensated for the decline in domestic
production. The commissioning of new pipelines has eased accessto the Mexican market for producers in the US Permian Basin, withvolumes ramping up and resulting in a 15% y-o-y increase in US

Lower than usual temperatures raised consumption for heatingneeds in the residential and commercial sector, which was up to 5%
higher y-o-y at the end of the first quarter. It then declined over theshoulder months, yet remained above 2020 levels with a 1.6% y-o-yincrease for the first six months.

pipeline exports for the first half of 2021.

Industrial customers provided the strongest source of support for
natural gas demand, with a 2.4% y-o-y increase during the first halfof the year. Much of this growth occurred during the second quarter,of gas.
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IEA. All rights reserved.

This forecast does not assume North American gas demand to fully
recover from its 2020 2.2% annual drop over this year. The
expected 1% annual growth for 2021 in the region is principally the
result of the lower market share of gas in the US power mix, as
higher prices favour a rebound in coal consumption at the expense

Gas market update and short-term forecast

Gas Market Report Q3-2021

Lower use for power generation is a drag on US natural gas demand, after a temperature-driven
increase in residential consumption during the first quarter

120

2%

110

1%

100

0%

90

-1%

80

-2%

70

-3%

60

-4%

50

-5%
Jan

Feb

2020

Mar

Apr

2021

May

Jun

Y-o-y change (%)

Temperature-adjusted

3%

Total consumption

130

3%
2%
1%
0%
-1%
-2%
-3%
-4%
-5%

Residential andcommercial

4%

Industry

140

Power generation

Gas consumption by sector in the United States,
2021 relative to 2020

Y-o-y change

Bcf/dWeekly natural gas consumption in the United States, 2020-2021

IEA. All rights reserved.

PAGE | 78

IEA. All rights reserved.

Note: Bcf/d = billion cubic feet per day.
Sources: IEA analysis based on EIA (2021), Natural Gas Consumption; Natural Gas Weekly Update.

Gas market update and short-term forecast

Gas Market Report Q3-2021

Severe droughts drive gas for power demand in Brazil and other South American markets,
while Argentina’s lower industry needs hamper gas demand recovery
Natural gas consumption in Brazil increased 12% y-o-y during theArgentina’s gas demand fell by an estimated 10% y-o-y in the firstquarter, in spite of rising needs from the power generation sector,

first quarter, mainly due to a jump in gas-fired power generation.
Severe droughts – the worst recorded in almost a century – greatly
impacted hydroelectricity generation, which drove gas use for power
generation up 24% y-o-y. Gas use in industry provided further
support with a 7% y-o-y increase, while the commercial andas industrial demand remains low compared to last year. Floating
regasification capacity has risen ahead of the austral winter toensure additional supply and offset the decline in Bolivian pipeline
imports. The Escobar terminal reopened in February after a federal
judge decision lifted a suspension order enacted in October ontechnical risk concerns, and a second vessel started operations intransport sectors dropped by 19% and 5% y-o-y respectively on theimpact of Covid-19 containment measures.

Bahia Blanca in early June to cover the following three months.

Exceptionally low rainfall levels are likely to have a prolonged
impact on the country’s power mix, as it entered the dry season withhydro reservoirs at a weighted average of 45%, lower than the fiveyear average of 53% according to the Electricity Sector Monitoring
Committee. Rising domestic gas production provides some support,with a 4.5% m-o-m increase in April (or 6% y-o-y), but is not
sufficient to meet increasing needs. LNG imports more thandoubled over the first quarter compared to 2020 to supplement
declining pipeline imports from Bolivia. The Ministry of Mines andEnergy is seeking to expand energy supply, but has not at the timeof writing yet considered it necessary to arrange emergency energy

Apparent gas consumption rose in Central America and the
Caribbean as LNG imports jumped over 55% y-o-y in the first fivemonths of the year, prompted by higher needs in the Dominican
Republic and Puerto Rico.
According to preliminary data, Venezuela’s gas consumption
declined by 17% y-o-y in the first quarter of 2021.
This forecast expects a 5% increase in gas demand in Central andSouth America for 2021, insufficient to offset the close to 10% fall in
consumption observed in 2020.

contracting.
Chile is also affected by lower hydro levels, which prompted a 40%

PAGE | 79

IEA. All rights reserved.

y-o-y increase in LNG imports over the first five months of the year.

Gas market update and short-term forecast

Gas Market Report Q3-2021

South American gas demand rises in March from a low February level, supported by power
generation needs in Brazil, Argentina and neighbouring markets
Monthly natural gas demand and production, Central and South America, 2020-2021

16

bcm

14
12
10
8
6
4
2
0

J

F

M

A

M

J

J

A

S

O

2020
Argentina
Colombia
Other

N

D

J

F

M

2021

BrazilChile
Production

Venezuela
PeruTrinidad and Tobago
Bolivia
IEA. All rights reserved.

PAGE | 80

IEA. All rights reserved.

Sources: IEA analysis based on ANP (2021), Boletim Mensal da Produção de Petróleo e Gás Natural; ICIS (2021), ICIS LNG Edge; IEA (2021), Monthly Gas Data
Service; JODI (2021), Gas Database; MME (2021), Boletim Mensal de Acompanhamento da Industria de Gás Natural.

Gas market update and short-term forecast

Gas Market Report Q3-2021

Cold spring temperatures and economic recovery boosted European gas consumption…
European gas consumption rose by an estimated 25% in Q2 2021 –its largest y-o-y quarterly increase since at least 1985. This
exceptionally strong recovery has been driven by the combination ofan extended heating season due to lower than averagetemperatures, higher gas burn in the power sector and economic
activity recovering to close to pre-Covid-19 levels.

competitiveness of gas-fired power generation vis-à-vis coal- andlignite-based generation, despite carbon prices reaching new highs
to oscillate in the range of EUR 50-55/t CO2-eq. Nevertheless, gasfired power generation continued to increase in May (up by 20%)and remained close to last year’s levels in June. Turkey alone
accounted for over half of additional gas burn in the power sector in
Q2, as lower hydro availability together with economic recovery
supported gas-fired power generation (increasing by more than
threefold y-o-y).

First estimates suggest that distribution network-related gas
demand increased by close to 35% y-o-y and accounted alone forover half of total growth in gas consumption. According to theGas consumption in industry increased strongly across key
markets compared to Q2 2020 – when most European countries
imposed lockdowns and other restrictive measures, weighing on
economic activity. First estimates indicate that industrial gas
consumption increased by 20% y-o-y in Italy and 8% in France in
Q2 and was up by over 25% y-o-y in Spain in April and May.

measurements of the De Bilt meteorological station in the
Netherlands, April 2021 was the coldest April month since 1986,
whilst heating degree days in May 2021 averaged at their highest
since 2010 for that month of the year. This translated into higher
space heating requirements for households, whilst the gradual
recovery in commercial/service sector activity provided additional
support to distribution network-related gas demand.

As a result of the strong, largely weather-driven demand growth inQ2, the forecast for European gas demand in 2021 is revised up to

Colder spring temperatures together with improving macroeconomic conditions also led to higher electricity consumption (upby 10% y-o-y). This higher electricity demand led to higher thermal
generation needs, including gas-fired power plants, which
increased their output by over 25% y-o-y. Most of the growth in gas
to meet power demand has been concentrated in April (up by 65%
y-o-y). The sharp increase in gas prices gradually reduced the cost-

PAGE | 81

IEA. All rights reserved.

6%, with most of the demand growth concentrated in H1 2021.
Additional demand is largely driven by the industrial sector, whilehigh gas prices are expected to weigh on gas demand for power
generation. For further details, please refer to our Electricity Market
Report.

Gas market update and short-term forecast

Gas Market Report Q3-2021…rising by over 20% year-on-year in Q2 2021
25

25%

20

20%

15

15%

10

10%

5

5%

0

0%

-5

-5%

- 10

-10%

- 15

-15%

- 20

-20%

Q1 2020

Q2 2020

Distribution network

Q3 2020

Q4 2020

Power generation

IndustryQ1 2021

Q2 2021Year-on-year change (%)

Year-on-year change (bcm)

Estimated change in quarterly European gas consumption by sector (Q1 2019-Q2 2021)

Y-o-y change (%)
IEA. All rights reserved.

PAGE | 82

IEA. All rights reserved.

Sources: Enagas (2021), Natural Gas Demand; ENTSOG (2021), Transparency Platform; Gaspool (2021), Consumption Data; NCG (2021), Consumption Data;
EPIAS (2021), Transparency Platform.

Gas market update and short-term forecast

Gas Market Report Q3-2021

Asia’s gas demand recovery remains uneven; 2021 growth is expected to be 6%
Asia’s gas demand recovery gained further momentum in Q1 2021,
initially driven by an unseasonably cold winter across northeast Asia
in January, and then by a sharp rebound in economic activity,

expanding gas infrastructure. The industrial sector remains the main
driver, accounting for 42% of the net increase, followed by power
generation, residential and commercial users and the transport

especially in China. Preliminary data for April and May 2021
indicate that the China-led recovery of Asian gas demand continued
into Q2. In 2021 total gas consumption in Asia is set to increase by
6%. China alone accounts for two-thirds of the net demand growthin 2021. A group of emerging Asian economies together contribute
another 25%, while India’s share of the net demand increase ismore modest – at around 6% – following a downward revision to ourforecast in light of the country’s second wave of Covid-19. Declines
in Japan are expected to be fully offset by increases in the rest of
Asia.

sector, which are responsible for 25%, 16% and 10% of the total
growth respectively.
India’s gas consumption contracted by 5% y-o-y in the first quarterof 2021 as high spot LNG prices in the aftermath of the northeast
Asian winter energy crisis tempered demand, especially in therefining and petrochemical sectors, where some operators
reportedly switched from imported LNG to liquid fuels. India’s
second wave of Covid-19 infections in April and May likely had anegative effect on gas demand in Q2 2021 as well. Preliminary data
indicate that total consumption declined by 6% m-o-m in April(despite a spectacular 34% y-o-y rise, which is due to the low basein April 2020, when India’s first Covid-19-induced demand drop was
the steepest). LNG imports were down by 12% m-o-m in April 2021
according to provisional shipping data. The city gas segment
registered the sharpest decline, dropping by 11% m-o-m in April, as
lockdown measures hit CNG demand and small industries
particularly hard. In 2021 India’s gas consumption is expected toincrease by 4.5%, but the economic fallout from the ongoing second

China’s gas consumption grew at double-digit y-o-y rates in each of
the first five months of 2021, and recorded a 17% y-o-y increase in
the January to May period. This remarkable expansion was
supported by cold winter weather in January as well as by a robust
post-pandemic recovery throughout the first five months. Gas use in
the power generation sector was further boosted in May as hot earlysummer weather in southern China led to surging electricity
demand at a time when nuclear, hydro and coal availability was
limited. In 2021 total gas demand is projected to increase by 10%,driven by a strong economic recovery, coal-to-gas conversions and
PAGE | 83

IEA. All rights reserved.

wave and high LNG prices present downside risks to our forecast.

Gas market update and short-term forecast

Gas Market Report Q3-2021

Japan's gas consumption increased by 9% y-o-y in the first four

the impact of the new units will be offset by lower utilisation of thecoal fleet due to the ongoing restrictions on plant operations. Our
forecast includes the addition of a new 1.4 GW nuclear unit
(Shinhanul 1) in the second half of 2021. Any delays in thecommissioning of the plant represent further upside potential for gas

months of 2021. The seasonal jump was driven by the residential
and power generation sectors, where gas demand rose sharply
during a cold blast in January. Power sector gas demand wasfurther boosted by low nuclear availability, especially during the firstquarter. Gas demand in the industrial sector also remained strong,
despite Japan’s second and third states of emergency, whichspanned most of the January to April period. In 2021 gas

demand in the remainder of the year.
Emerging Asia’s gas demand recovery remained muted in early2021 as price-sensitive markets, such as Pakistan and Bangladesh,curtailed consumption in the face of record-high spot LNG prices inJanuary. However, there are tentative signs of recovering demandin the remainder of Q1 and in Q2, with LNG imports into the region
up by 13% y-o-y in the first five months of 2021 and y-o-y gas
consumption growth in Thailand moving into positive territory fromFebruary. In 2021 total consumption is expected to increase by 5%,
fuelled by an ongoing economic recovery and strong power demand
growth. New waves of Covid-19 infections across the region,
however, could present downside risks to our forecast.

consumption is expected to decrease by 2% as nuclear restarts andgrowing solar generation limit gas burn in the power generation
sector for the remainder of the year.
Korea’s total gas consumption increased by 11% y-o-y in the first
four months of 2021, driven by strong growth in both the power
generation and city gas sectors, especially during the weatherdriven demand spike in January. Preliminary shipping data indicatesthat LNG demand remained strong and expanded by 7% y-o-y in
the first five months of 2021. In 2021 as a whole, Korea’s gas
demand is expected to increase by 5% y-o-y, fuelled by sustained

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IEA. All rights reserved.

high demand in the power and city gas segments. This comes
despite the addition of 3 GW of new coal-fired capacity in 2021, asGas market update and short-term forecast

Gas Market Report Q2-2021

Asia’s demand recovery is led by China for now; others are likely to catch up in 2021
Monthly gas demand in selected Asian countries

Gas demand in selected Asian countries, 2020 and 2021

30%
20%
10%
0%

12%
China

% change y-o-y% change y-o-y

40%

India

Indonesia

10%
2020

2021

8%
6%
4%
2%

Japan

-10%

0%
Korea

-20%
-30%
-40%

-2%
Philippines

-4%
-6%

Thailand

PAGE | 85

IEA. All rights reserved.

Sources: IEA analysis based on ICIS (2021), ICIS LNG Edge; CQPGX (2021), Nanbin Observation; IEA (2021), Monthly Gas Data Service; JODI (2021), Gas World
Database; PPAC (2021), Gas Consumption.

Gas market update and short-term forecast

Gas Market Report Q2-2021

US gas output stabilises in Q2 after a volatile first quarter; shale industry shows signs offurther consolidation and developing environmental certification
US dry gas production recovered in March from its low point in
February, returning to 81 bcm – comparable to January. The
second quarter saw a stable level of production, around 80 bcm permonth, slightly below March’s level, but about 3% above average(USD 8.5 billion), and Southwestern expanding its gas portfolio withthe acquisition of Haynesville producer Indigo Natural Resources(USD 2.7 billion).
Shale gas players are also increasingly seeking to certify theirproduction in the second quarter of 2020.

production as responsibly sourced. EQT, the United States’ largest
shale producer, announced in April a test programme covering over
200 Pennsylvania well pads. About 4 Bcf/d (110 mcm/d) of
production is to be certified according to its environmental, socialand governance performance (including quantification of methane
emissions). This follows similar statements made earlier this year byshale producer Chesapeake Energy, as well as LNG export project
owners Cheniere Energy and Next Decade.

Drilling activity continues its increase since the beginning of theyear, with close to 100 active gas rigs as of the end of June, some
19% above the early January number and 25% higher than a year
ago. About half of the gas drilling activity is in the Haynesville play,whereas most of the remaining half takes place in the Northeast
Marcellus and Utica plays in the Appalachian Basin. This recovery
is, however, expected to remain modest, as shale gas producers
have confirmed strict financial discipline for 2021 to deliver shortterm returns.
This second quarter also showed additional merger and acquisition
activity as the shale industry consolidates. With an estimated
USD 30 billion in shale M&A activity as of mid-June, 2021 is set tosurpass the previous year’s USD 41 billion total. Several of the mostrecent deals involved gas-driven players, such as EQT’s acquisitionof Alta Resources’ Marcellus gas assets (USD 2.9 billion),
Appalachian-centred Cabot Oil & Gas merging with Cimarex Energy

US dry gas production is expected to stabilise in 2021, with shalegas (both dry and associated with light tight oil) providing limited
growth to compensate for a slight decline in conventional gas
production.
PAGE | 86

IEA. All rights reserved.

In the oil-driven Permian Basin, the commissioning of the Permian
Highway natural gas pipeline in January increased takeaway
capacity by 2.1 Bcf/d (59 mcm/d). It is contributing to reducing gas
flaring and supporting exports to Mexico, which increased by 15%
y-o-y in the first half of 2021.

Gas market update and short-term forecast

Gas Market Report Q2-2021

US gas production keeps recovering from its February drop, standing 2% below 2020’s level
over the first half of 2021
Gas production by type in the United States, 2019-2021

bcm

100
90

Pipeline imports (net)8070

Total US dry gas

60

Other production

50

Other associated shale

40

Permian Basin

30

Other dry shale

20
10
0

Appalachian Basin
J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J
2019

2020

2021
IEA. All rights reserved.

PAGE | 87

IEA. All rights reserved.

Sources: IEA analysis based on EIA (2021), Natural Gas Data; Natural Gas Weekly Update.

Gas market update and short-term forecast

Gas Market Report Q2-2021

US dry gas production is expected to stabilise in 2021, as growth from pure shale gas plays
offsets declines from other sourcesbcm

Dry gas production by main source in the United States, 2019-2021
200

400

500
400

300

300
100

200
200
100

100
0

2019
Dry shale
Other production

2020

2021
Associated shale

0

2019
2020
2021
Appalachian Basin
Other gas-driven basins

0

2019
2020
2021
Permian Basin
Other oil-driven basins
IEA. All rights reserved.

PAGE | 88

IEA. All rights reserved.

Sources: IEA analysis based on EIA (2021), Natural Gas Data; Natural Gas Weekly Update.

Gas market update and short-term forecast

Gas Market Report Q2-2021

Eurasian gas production grew by close to 10% in the first five months of 2021…
Natural gas production in Eurasia grew by an estimated 10% y-o-yin H1 2021, supported by a combination of higher extra-regional
exports, recovery in domestic demand and higher injection needs

Central Asian pipeline exports to China remained flat, increasing

into storage following a cold and long heating season.

to offset lower export flows from Kazakhstan, down by 29%. In
Azerbaijan, natural gas production increased by close to 8% y-o-yby a mere 0.4% y-o-y in the first five months of 2021. Higher
pipeline deliveries from Turkmenistan (up by 8%) were not sufficient

In Russia, natural gas production grew by 11% y-o-y in the first fivein the first five months of the year. This has been driven by strong
export growth, up by over 40% y-o-y. Deliveries via the TAP

months of 2021, with recovery accelerating in April and May whengas output increased by 18% (almost 20 bcm) y-o-y. This has been
partly supported by higher deliveries to the domestic market, as

pipeline continued to ramp up and reached 2.5 bcm in the first fivemonths of the year. In Ukraine, gas production fell by close to 7% in

the combination of a colder winter and spring temperatures,
recovery in economic and commercial activity and higher gas burnin the power sector supported Russian gas demand. Russia’s vast
storage sites closed the heating season at an historical low of
12 bcm, meaning that storage injections would need to average

the first five months of 2020. .
Eurasian gas production is expected to increase by over 10% y-o-yin 2021, supported by recovery in domestic demand, higher
injection needs and strong export growth. This will be partly enabledby the ramp-up of flows through new export channels. Gas

over 330 mcm/d through the gas summer to reach the country’s
72.6 bcm fill target by the start of the heating season. Higher
injection needs are set to provide further support to gas output
through the summer. Net pipeline exports to Europe rose by closedeliveries via the Power of Siberia to China are set to reach 10 bcm
in 2021, whilst exports via TAP are expected to total 5-5.5 bcm. The
commissioning of YAMAL Train 4 in June could increase Russia’s
LNG exports by ~0.6 bcm in H2 2021. The first string of Nord
Stream 2 was completed in June 2021. Combined pipeline exports
from Russia to Europe and Central Asia to China are expected toincrease by close to 15% y-o-y.

to 20% y-o-y in the H1 2021, largely supported by higher deliveries
to Turkey (more than doubling in January-May compared to lastyear). Pipeline deliveries to China via the Power of Siberia pipeline
totalled over 4 bcm in the first five months of 2021. LNG exports

PAGE | 89

IEA. All rights reserved.

declined marginally by less than 0.5% in the first five months of2021, largely due to lower output from Sakhalin-II.

Gas market update and short-term forecast

Gas Market Report Q2-2021… supported by a strong recovery in extra-regional exports
6

26%

4
13%
2
0

0%

Year-on-year change (%)

Year-on-year change (bcm)

Estimated change in monthly Eurasian gas exports (January 2020-May 2021)

-2
-13%
-4
-6

-26%

Russian pipeline exports to Europe

Central Asian pipeline exports to China

Russian LNG exports

Azeri pipeline exports to Europe

Russian pipeline exports to China

Year-on-year change (%)

Sources: ENTSOG (2021), Transparency Platform; Eurostat (2021), Imports of Natural Gas by Partner Country – Monthly Data; General Administration of Customsof People’s Republic of China (2021), Customs Statistics; ICIS (2021), ICIS LNG Edge.
PAGE | 90

IEA. All rights reserved.

IEA. All rights reserved.

Gas market update and short-term forecast

Gas Market Report Q2-2021

LNG inflows into Europe remained subdued in Q2 2021…
production continued to decline, down by over 10% in the first four

The combination of strong demand recovery, together with fallingdomestic production and higher LNG spot prices, created additional
market space both for new and traditional pipeline suppliers tomonths of 2021 – largely due to lower output in the Netherlands andthe United Kingdom, together accounting for approximately 75% ofEurope in Q2 2021.

the drop.

European LNG imports dipped by 40% y-o-y through the 2020/21

North African pipeline exports recovered strongly in Q1 (up byheating season (October to March) and remained below last year’slevels in Q2, down by 6% y-o-y. The spread between Asian LNG
spot and European hub prices averaged over USD 1/MBtu in thesecond quarter (more than double compared to last year), sufficientfor LNG flows to favour the Asia Pacific region instead of theEurope market. The drop in LNG imports has been largely driven bynorthwest Europe (down by 4% y-o-y) and Turkey (plummeting byover 60%), whilst LNG inflow into southwest European markets rose
by 5% (mainly due to higher imports into Portugal). The UnitedStates has been the largest source of supply, increasing its exportsby over 30% y-o-y and accounting for almost 30% of Europe’s total
LNG imports. In contrast, Qatari flows dropped by almost one-third,70%) and more than doubled compared to last year in Q2, largely
driven by higher Algerian gas deliveries to Italy and Spain, whilst
pipeline flows from Libya dropped by over 40%. Oil-indexed
Algerian prices remained at a significant discount compared toEuropean hub prices (~30% lower compared to TTF in the first fourmonths of 2021). Net pipeline exports from Russia continued
their recovery during Q2 and increased by 18% y-o-y. This has
been partly supported by the strong recovery in export flows toTurkey, more than doubling compared to last year in January-May
2021. Azeri flows to the European Union via the TAP pipeline
started in January 2021 and totalled over 3 bcm in H1 2021.

Despite the strong demand growth and prices climbing to multi-year
highs, Norwegian pipeline deliveries to the rest of Europe
increased by a mere 1% y-o-y in H1, being limited by a combinationof planned maintenance works and unplanned outages on key
Norwegian gas infrastructure. Non-Norwegian domestic

PAGE | 91

IEA. All rights reserved.

Low European storage levels (23% below their five-year average)
are expected to create additional market space both for LNG andpipeline suppliers during the summer season. Pipeline imports are
expected to increase by close to 20% y-o-y in 2021, with LNG
inflows settling below last year’s levels. Europe’s future
infrastructure set-up is a major uncertainty factor in this forecast.

being increasingly redirected to the Asia Pacific market.

Gas market update and short-term forecast

Gas Market Report Q2-2021… leaving additional market space for pipeline suppliers

25

25%

20

20%

15

15%

10

10%

5

5%

0

0%

-5

-5%

- 10

-10%

- 15

-15%

- 20

-20%

Q1 2020

Q2 2020
RussiaQ3 2020
NorwayQ4 2020
LNG

Others

Q1 2021

Q2 2021Year-on-year change (%)

Year-on-year change (bcm)

Estimated change in monthly European gas imports and deliveries from Norway, Q1 2019-Q2 2021

Y-o-y change

Sources: IEA analysis based on ENTSOG (2021), Transparency Platform; Eurostat (2021), Energy Statistics; Gas Transmission System Operator of Ukraine (2021),
Transparency Platform; GIE (2021), ICIS LNG Edge; JODI (2021), Gas World Database; Norwegian Petroleum Directorate (2021), Monthly Production Figures.

PAGE | 92

IEA. All rights reserved.

IEA. All rights reserved.

Gas market update and short-term forecast

Gas Market Report Q2-2021

Global LNG trade is expected to increase by a modest 4% in 2021
In the first half of 2021 global LNG trade expanded by nearly 5%
y-o-y. The Asia Pacific region remained the primary engine ofimport growth, registering 12% y-o-y expansion in the January to

LNG intake was offset by increased storage withdrawals andpipeline gas imports into Europe. The Middle East recorded a minor
y-o-y increase, while North American imports dropped by almost

June 2021 period. China saw the largest absolute expansion, with
LNG inflows increasing by 28% y-o-y in the first six months. Thiswas fuelled by cold winter weather, a strong economic recovery,
subdued pipeline gas imports from Central Asia and a hot start tothe summer in south China in May. Japan and Korea sustained
healthy LNG import growth, driven by a cold blast in January, thesubsequent replenishment of LNG stocks and growth in gas-fired
generation. The majority of emerging Asian importers – led by
Pakistan and Bangladesh – experienced a sharp increase in LNG
arrivals thanks to rising gas demand in the power sector.
Meanwhile, India’s LNG imports dropped by 3% y-o-y, as recordhigh spot prices in January and a devastating second wave of
Covid-19 in April and May dampened LNG demand.

50% y-o-y as US pipeline gas continued to displace LNG in Mexico.
North America has dominated LNG export growth so far this year,with US LNG output expanding by more than a third y-o-y in the firstsix months of 2021. This remarkable growth comes despite a sharp
29% m-o-m drop in February 2021 during the Texas electricity
crisis, and is largely the result of a 50% increase in US liquefaction
capacity since the beginning of 2020. Africa’s LNG exports rose by
9% y-o-y, driven by a sharp rebound in LNG exports from Egypt,which was further boosted by the reopening of the Damietta plant in
February 2021. LNG output in the Middle East rose by 2% y-o-y as
Qatar produced in excess of nameplate capacity in the first half of2021. LNG exports from Eurasia (i.e. Russia) were up by 5% y-o-y.
Exports from the Asia Pacific region remained flat, while output in
Europe and Central and South America saw steep declines due tothe ongoing outage at the Hammerfest LNG terminal in Norway andreduced feed gas availability at the Atlantic LNG plant in Trinidad
and Tobago, respectively.

Central and South America registered strong gains, boosting LNG
imports by more than 75% y-o-y in the first six months of 2021.
Brazil accounted for the bulk of the growth, where LNG-fired power
plants were dispatched to compensate for low hydro generation
amid an unusually dry southern hemisphere winter. European LNG
imports dropped by nearly 20% y-o-y in the first half of 2021 asAtlantic Basin cargoes were redirected to Asia. The reduction in

In 2021 global LNG trade is expected to increase by 4%, with

PAGE | 93

IEA. All rights reserved.

import growth driven entirely by the Asia Pacific region and export
growth fuelled mainly by North America.

Gas market update and short-term forecast

Gas Market Report Q2-2021

Asia Pacific leads LNG import growth and North America leads LNG export growth so far in
2021

Y-o-y growth (bcm)

Y-o-y growth (bcm)

LNG imports and exports by market and region, January-June 2021 vs January-June 2020
12
10
8
6
4
2
0
-2
-4

AfricaAsia PacificCentral and South America

Eurasia

EuropeMiddle East

North America

IMPORTS

14
12
10
8
6
4
2
0
-2
-4

EXPORTS

Notes: Based on preliminary shipping data. LNG trade is net of reloads. Reference period is 1 January to 25 June.
Source: IEA analysis based on ICIS (2021), ICIS LNG Edge.
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IEA. All rights reserved.

Gas market update and short-term forecast

Gas Market Report Q2-2021

Spot gas prices and charter rates recorded strong gains in Q2 2021…
Tighter market fundamentals supported spot gas prices rising tomulti-year highs in Q2 2021 across all major gas-consuming
regions.
In the United States, Henry Hub prices increased by over 70% y-oy in Q2, to an average of USD 2.9/MBtu – their highest Q2 average

highest level since 2014.

since 2017. This has been largely supported by the surge in LNG
exports (up by 30% y-o-y), which increased overall system demand,
whilst gas production remained close to last year’s levels. Forward
curves as at the end of June indicate that Henry Hub prices are

Oil-indexed LNG prices gained an estimated 10% y-o-y in Q2, andare expected to average 70% higher compared to last year in H2
2021. The strong gains in spot prices have been accompanied bywidening regional price spreads compared to last year. The priceexpected to average USD 3.5/MBtu through the second half of2021, translating into an annual average of USD 3.4/MBtu – its
highest since 2014. In Europe, cold spring temperatures during
April and May, together with lower LNG inflows, supported a strong
increase in TTF prices, rising by fivefold in Q2 y-o-y to an averageof USD 8.7/MBtu –its highest Q2 average since 2013. Forward
curves as at the end of June suggest that gas prices will remain well
above their five-year averages during the second half of 2021, at
USD 11/MBtu. Overall TTF prices are expected to average USD
9.5/MBtu in 2021 – their highest level since 2013. In Asia, LNG
spot prices more than quadrupled y-o-y in Q2 to reach an average

differential between Asian spot LNG and Henry Hub, and TTF andHenry Hub, averaged close USD 7/MBtu and USD 6/MBtu
respectively in Q2 (from close to zero last year). Price spreads
between Asian spot LNG and TTF averaged USD 1/MBtu in Q2,
supporting higher LNG flows towards the Asia Pacific region.
Forward curves suggest that spreads between Asian spot LNG andHenry Hub, and between TTF and Henry Hub, will average
USD 9.5/MBtu and USD 7.8/MBtu respectively in H2 2021. Strong
growth in LNG trade in Q2 led to an increase in tonne-mile demand,
providing upward pressure on charter rates in both the Atlantic andPacific basins. They are averaging respectively 70% and 50%
higher in Q2 compared to last year. Forward curves indicate that
Atlantic and Pacific charter rates are set to average 50% and 40%
above last year’s levels in H2 2021, respectively.

of USD 9.8/MBtu – their highest Q2 average since 2014. Strong
buying interest from China, India and Korea, together with a
combination of planned and unplanned outages in liquefaction
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IEA. All rights reserved.

plants, provided upward support to LNG spot prices. Forward
curves at the end of June indicate that Asian spot prices are set toaverage close to USD 13/MBtu through the second half of the year,
resulting in an overall annual average of over USD 11/MBtu – theGas market update and short-term forecast

Gas Market Report Q2-2021… filtering through the forward curve for the rest of the year
Main spot and forward natural gas prices,Atlantic and Pacific spot and forward charter rates,

January 2020-December 2021

January 2020-December 2021
USD 000/day

USD/MBtu

14
12
10
8

210
180
150

90

4

60

2

30

0

0

Jan-20Feb-20Mar-20
Apr-20May-20Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21
Jul-21
Aug-21
Sep-21
Oct-21
Nov-21
Dec-21

6

TTF

Henry HubJan-20Feb-20Mar-20
Apr-20May-20Jun-20Jul-20Aug-20
Sep-20
Oct-20Nov-20Dec-20Jan-21
Feb-21
Mar-21
Apr-21
May-21
Jun-21
Jul-21
Aug-21
Sep-21
Oct-21
Nov-21
Dec-21120

Atlantic

Asian spot LNG

Pacific
IEA. All rights reserved.

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IEA. All rights reserved.

Sources: Gas prices: IEA analysis based on CME (2021), Henry Hub Natural Gas Futures Quotes; Dutch TTF Natural Gas Month Futures Settlements;
CME Group (2021), LNG Japan/Korea Marker (Platts) Futures Settlements; EIA (2021), Henry Hub Natural Gas Spot Price; ICIS (2021), ICIS LNG Edge; Powernext(2021), Spot Market Data. Charter rates: IEA analysis based on ICIS (2021), ICIS LNG Edge; Spark Commodities (2021), LNG Freight Dashboard.

Gas market update and short-term forecast

Gas Market Report Q2-2021

Tight summer-winter spreads weighed on storage injection in Europe and the US in Q2...
Underground gas storage sites both in Europe and North America
closed the first half of the injection season with inventory levels
below their five-year average. Tighter than expected supplydemand fundamentals during Q2 led to more pronounced uplift inspot prices compared to winter contracts. This, in turn, translated
into tighter seasonal price spreads, reducing the incentive forstorage injections.

last year, whilst working gas inventories stood 42% below lastyear’s levels at the end of June according to data published by Gas
Infrastructure Europe. In Russia, where working gas inventories
dropped to a record low of 12 bcm at the end of the heating season,storage injections would need to average over 330 mcm/d to reachthe 72.6 bcm fill target by the start of the heating season.
In the United States, seasonal price spreads between 2021/22

In Europe, unseasonably cold temperatures in early spring
extended the withdrawal season from the end of March until thesecond half of April. The strong demand increase throughout April
and May firmed up spot prices, rising more strongly than 2021/22
winter contracts. Consequently, seasonal price spreads have fallenfrom over USD 2/MBtu in Q2 2020 to USD 0.25/MBtu in Q1 2021.
Tighter seasonal spreads have depressed net storage injections,falling by close to 40% y-o-y in the second quarter. This in turnresulted in working gas inventories standing 40% below last year’slevels and 23% below their five-year average at the end of June.
Net injections would need to increase to 460 mcm/d in Q3 (up by
60% compared to their five-year average) for European storage toreach 90% fill rates by the beginning of the next heating season. In
Ukraine, net injections have fallen by a factor of 30 compared to

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winter contracts and spot prices averaged at USD 0.28/MBtu in Q2,
down from USD 1.1/MBtu during the same period of last year. Thisnaturally weighed on net storage injections, which declined by 30%
y-o-y from 29 bcm in Q2 2020 to 20 bcm in Q2 2021. Consequently,
US gas inventory levels stood 17% below last year’s levels and 6%
below their five-year average levels by mid-June, despite starting
the injection season 1.3% below their five-year average. The
reclassification of ~1.4 bcm of working natural gas storage to basegas in Northern California contributed to this decline. In Canada,storage injections declined by 30% y-o-y during Q2, depressing
inventory levels to 6% below their five-year average by mid-June. In
Japan and Korea, LNG closing stocks stood 7% below their fiveyear average in April, as tighter supply-demand fundamentals
weighed on LNG restocking.

Gas market update and short-term forecast

Gas Market Report Q2-2021

European underground storage inventory

120

120

100

Japan and Korea LNG storage inventory
12
bcm

bcm

US underground storage inventory

100

10
8

60

60

6

40

40

4

20

20

2

0

0

0

2016-2020 range

2019/20

Five-year average

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

80

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

80

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

bcm

…leaving inventory levels below their five-year average by the middle of the injection season

2020/21IEA. All rights reserved.

PAGE | 98

IEA. All rights reserved.

Sources: IEA analysis based on EIA (2021), Weekly Working Gas In Underground Storage; GIE (2021), AGSI+ Database; IEA (2021), Monthly Gas Data Service.

AnnexTitle of the Report

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AnnexAnnexTitle of the Report

Summary tables (1/2)
2018

2019

2020

2021

2022

2023

2024

Africa

157

161

160

164

170

176

180

Asia Pacific

824

853

857

907

940

986

1 024

283

307

325

359

377

400

421

Central and South America

153

152

137

145

147

149

151

Eurasia

666

658

633

661

659

662

670

493

482

460

485

481

484

489

Europe

536

537

522

553

537

531

530

Middle East

544

543

547

559

577

591

610

North America

1 061

1 097

1 070

1 081

1 098

1 109

1 111

854

888

869

873

886

894

895

3 940

4 001

3 926

4 069

4 127

4 205

4 277

of which Chinaof which Russia

of which United States
World

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IEA. All rights reserved.

World natural gas demand by region and key country (bcm)AnnexTitle of the Report

Summary tables (2/2)
2018

2019

2020

2021

2022

2023

2024

Africa

244

248

240

247

249

253

265

Asia Pacific

627

654

648

669

677

683

694

160

174

189

200

210

221

232

Central and South America

167

167

152

160

163

166

168

Eurasia

932

941

884

982

977

1 002

1 033

726

738

692

774

764

785

814

Europe

246

227

211

203

203

199

195

Middle East

666

677

680

694

709

725

744

North America

1 062

1 166

1 145

1 150

1 179

1 211

1 229

868

968

953

959

987

1 019

1 034

3 944

4 080

3 960

4 105

4 158

4 239

4 328

of which Chinaof which Russia

of which United States
World

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World natural gas production by region and key country (bcm)AnnexTitle of the Report

Regional and country groupings
Africa – Algeria, Angola, Benin, Botswana, Cameroon, Congo, Democratic
Republic of Congo, Côte d’Ivoire, Egypt, Eritrea, Ethiopia,
Gabon, Ghana, Kenya, Libya, Morocco, Mozambique, Namibia,
Nigeria, Senegal, South Africa, Sudan, United Republic of
Tanzania, Togo, Tunisia, Zambia, Zimbabwe and other countries
and territories.1

Netherlands, Poland, Portugal, Romania, the Slovak Republic,
Slovenia, Spain and Sweden.
Middle East – Bahrain, the Islamic Republic of Iran, Iraq, Israel,8 Jordan,
Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, the Syrian Arab
Republic, the United Arab Emirates and Yemen.
North Africa – Algeria, Egypt, Libya, Morocco and Tunisia.

Asia Pacific – Australia, Bangladesh, Brunei Darussalam, Cambodia,
Chinese Taipei, India, Indonesia, Japan, Korea, the Democratic
People’s Republic of Korea, Malaysia, Mongolia, Myanmar,
Nepal, New Zealand, Pakistan, the People’s Republic of China,2
the Philippines, Singapore, Sri Lanka, Thailand, Viet Nam andother countries and territories.3

North America – Canada, Mexico and the United States.

Central and South America – Argentina, Bolivia, Brazil, Chile, Colombia,
Costa Rica, Cuba, the Dominican Republic, Ecuador, El
Salvador, Guatemala, Haiti, Honduras, Jamaica, Netherlands
Antilles, Nicaragua, Panama, Paraguay, Peru, Trinidad andTobago, Uruguay, Venezuela and other countries and territories.4

Europe – Albania, Austria, Belgium, Bosnia and Herzegovina, Bulgaria,
Croatia, Cyprus,5,6 Czech Republic, Denmark, Estonia, Finland,
the Former Yugoslav Republic of North Macedonia, France,
Germany, Gibraltar, Greece, Hungary, Iceland, Ireland, Italy,
Kosovo,7 Latvia, Lithuania, Luxembourg, Malta, Montenegro,
Netherlands, Norway, Poland, Portugal, Romania, Serbia, Slovak
Republic, Slovenia, Spain, Sweden, Switzerland, Turkey andUnited Kingdom.
European Union – Austria, Belgium, Bulgaria, Croatia, Cyprus,5,6 Czech
Republic, Denmark, Estonia, Finland, France, Germany, Greece,
Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta,

3 Individual data are not available and are estimated in aggregate for: Afghanistan, Bhutan, Cook
Islands, Fiji, French Polynesia, Kiribati, the Lao People’s Democratic Republic, Macau (China),
Maldives, New Caledonia, Palau, Papua New Guinea, Samoa, Solomon Islands, Timor-Leste,
Tonga and Vanuatu.

4 Individual data are not available and are estimated in aggregate for: Antigua and Barbuda, Aruba,
Bahamas, Barbados, Belize, Bermuda, British Virgin Islands, Cayman Islands, Dominica, Falkland
Islands (Malvinas), French Guyana, Grenada, Guadeloupe, Guyana, Martinique, Montserrat, St.
Kitts and Nevis, St Lucia, St. Vincent and the Grenadines, Suriname and Turks and Caicos Islands.
5 Note by Turkey: The information in this document with reference to “Cyprus” relates to thesouthern part of the Island. There is no single authority representing both Turkish and Greek Cypriot
people on the Island. Turkey recognises the Turkish Republic of Northern Cyprus (TRNC). Until alasting and equitable solution is found within the context of United Nations, Turkey shall preserve
its position concerning the “Cyprus issue”.
6 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 Turkey.
The information in this document relates to the area under the effective control of the Governmentof the Republic of Cyprus.
7 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 Justiceon Kosovo’s declaration of Independence.
8
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 ofinternational law.
PAGE | 102

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Eurasia – Armenia, Azerbaijan, Belarus, Georgia, Kazakhstan, Kyrgyzstan,
the Republic of Moldova, Russian Federation, Tajikistan,
Turkmenistan, Ukraine and Uzbekistan.

1 Individual data are not available and are estimated in aggregate for: Burkina Faso, Burundi, Cape
Verde, Central African Republic, Chad, Comoros, Djibouti, Equatorial Guinea, Gambia, Guinea,
Guinea-Bissau, Lesotho, Liberia, Madagascar, Malawi, Mali, Mauritania, Mauritius, Niger, Reunion,
Rwanda, Sao Tome and Principe, Seychelles, Sierra Leone, Somalia, Swaziland and Uganda.
2 Including Hong Kong.

AnnexTitle of the Report

NCG

NetConnect Germany

NDRC

National Development and Reform Commission (China)

ANPAgência Nacional do Petróleo, Gás Natural e Biocombustíveis
(Brazil)

PPAC

Petroleum Planning & Analysis Cell (India)

SENER

Secretaría de Energía (Mexico)

CAPEX

capital expenditure

TANAP

Trans-Anatolian Natural Gas Pipeline

CME

Chicago Mercantile Exchange (United States)

TAP

Trans-Adriatic Pipeline

CNG

compressed natural gas

TTF

Title Transfer Facility (the Netherlands)

CNY

Chinese yuan

USD

United States dollar

CQPGX

Chongqing Petroleum and Gas Exchange (China)

w-o-w

week-on-week

EIA

Energy Information Administration (United States)

y-o-y

year-on-year

ENTSOE

European Network of Transmission System Operators forElectricity

ENTSOG

European Network of Transmission System Operators for Gas

EPIAS

Enerji Piyasaları İşletme A.Ş (Turkey)

bcf

billion cubic feet

EPPO

Energy Policy and Planning Office (Thailand)

bcf/dbillion cubic feet per day

ERCOTElectric Reliability Council of Texas (United States)

bcm

billion cubic metres

FID

final investment decisionbcm/ybillion cubic metres per year

GDPgross domestic productmb/dmillion barrels per day

GECF

Gas Exporting Countries Forum

MBtu

million British thermal units

GIE

Gas Infrastructure Europe

mcm/d

million cubic metres per day

HH

Henry Hubtcm

trillion cubic metres

IEA

International Energy Agency

TWhterawatt hour

ICIS

Independent Chemical Information Services

JODI

Joint Oil Data Initiative

LNG

liquefied natural gas

NBP

National Balancing Point (United Kingdom)

Units of measure

PAGE | 103

IEA. All rights reserved.

Abbreviations and acronyms

AnnexTitle of the Report

Acknowledgements, contributors and credits
This publication has been prepared by the Gas, Coal and Power
Markets Division (GCP) of the International Energy Agency (IEA).
The analysis was led and co-ordinated by Jean-Baptiste Dubreuil,Senior Natural Gas Analyst. Tetsuro Hattori, Songho Jeon, Akos
Lósz, Gergely Molnár and Jean-Baptiste Dubreuil are the main
authors. Keisuke Sadamori, Director of the IEA Energy Markets andSecurity (EMS) Directorate, and Peter Fraser, Head of GCP,
provided expert guidance and advice.
Other IEA colleagues provided important contributions including
Paulina Becerra Zavala, Joel Couse, Carlos Fernández Alvarez,
Hiroyasu Sakaguchi, and Stefan Lorenczik. José Miguel Bermudez
Menendéz provided invaluable data/comments and guidance to thehydrogen-related parts of the report, while the CCS/CCUS-relatedparts have been greatly enriched by the contributions from Niels
Berghout and Adam Baylin-Stern.

and his team: Astrid Dumond, Tanya Dyhin, Merve Erdem, Jethro
Mullen, Grace Gordon, Rob Stone and Therese Walsh.
Justin French-Brooks edited the report.
The report was made possible by assistance from SK E&S andTokyo Gas.
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 (gcp@iea.org).

Timely and comprehensive data from the Energy Data Centre were
fundamental to the report. Special thanks go to Mathilde Daugy,
Louis Chambeau and Amani Al-Saidi for their support.

PAGE | 104

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The IEA Communication and Digital Office (CDO) provided
production and launch support. Particular thanks to Jad MouawadThis publication reflects the views of the IEA Secretariat but does notnecessarily reflect those of individual IEA member countries. The IEA
makes no representation or warranty, express or implied, in respect ofthe publication’s contents (including its completeness or accuracy)
and shall not be responsible for any use of, or reliance on, thepublication. Unless otherwise indicated, all material presented infigures and tables is derived from IEA data and analysis.

This publication and any map included herein are without prejudice tothe status of or sovereignty over any territory, to the delimitation ofinternational frontiers and boundaries and to the name of any
territory, city or area.

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International Energy Agency
Website: www.iea.org
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