The global energy system is governed by complex dynamics that play out over time across
regions and sectors of the economy. Projected increases in population and incomes drive
our expectation of rising energy demand through 2050. However, we expect the increased
energy demand to be moderated by reduced energy intensity: less energy will be required
for each unit of economic activity. In addition, we expect reduced carbon
intensity—largely driven by the wide-scale deployment of renewables for
electricity generation—which will help limit global CO2 emissions
associated with what will be record-high energy demand. Our International Energy
Outlook 2023 (IEO2023) explains our findings and showcases key regional and
sectoral variations. We use EIA's detailed World Energy Projection System to produce
IEO2023, giving our readers a unique view into future global energy systems.
The challenge we face as modelers is to deliver actionable insights about the future in a
world filled with uncertainty. To address that uncertainty, IEO2023 includes several
projections—which we refer to as cases—each with different input
assumptions. The cases we modeled focus on well-understood variables that can produce
significant changes in global supply and demand patterns: macroeconomic growth, costs
for zero-carbon generating technologies, and crude oil prices.
Although we model a number of cases, we do not try to comprehensively address all issues
that could drive significant change, like in a forecast. In IEO2023, we do not
incorporate deeply uncertain factors such as major new policy developments,
technological breakthroughs, and geopolitical events, all of which can dramatically
shift the course of energy system development. Instead, the cases included in IEO2023
build on recent trends and highlight the current trajectory of the global energy system.
Unmodeled surprises or breakthroughs that shift the trajectory of the global energy
system will almost certainly happen. As Yogi Berra quipped, “The future ain’t what it
used to be.” So, our modeled cases should not be interpreted as forecasts. Rather,
IEO2023 provides a useful benchmark for decision makers around the world as they
continue to shape our collective energy future.
In producing the IEO, we aim to be as transparent as possible. In addition to this
written report, detailed model results are
available on our website. Detailed
documentation of the World Energy Projection System is also available on our
website. In addition, the model source
code is available for review, and we are actively working to make the model’s
source code publicly available under an open source license. We are also working on
expanding the capabilities of our model so that we can examine a wider range of cases in
In closing, I’d like to thank our staff for their tremendous effort to produce this
year’s IEO. I feel privileged to help lead such a talented team of experts.
The International Energy Outlook 2023 (IEO2023) explores long-term energy trends
across the world through 2050. Since our last IEO two years ago, IEO2021, the global
energy system has evolved against a backdrop of new energy policies, the transition to
zero-carbon technologies, energy security concerns, and economic and population growth.
While IEO2023 includes several cases to capture important drivers of change, the modeled
cases represent a set of policy neutral baselines that place emphasis on the current
trajectory of the global energy system.
Increasing population and income offset the effects of declining energy and carbon
intensity on emissions.
Our projections highlight a key global insight—global energy-related CO2
emissions will increase through 2050 in all IEO2023 cases except our Low Economic Growth
case. Our projections indicate that resources, demand, and technology costs will drive
the shift from fossil to non-fossil energy sources, but current policies are not enough
to decrease global energy-sector emissions. This outcome is largely due to population
growth, regional economic shifts toward more manufacturing, and increased energy
consumption as living standards improve. Globally, we project increases in energy
consumption to outpace efficiency improvements.
Increasing population and income offset the effects of declining energy and carbon
intensity on emissions.
China remains the primary source of energy-related CO2 emissions through 2050
across all cases, although its share of total global CO2 emissions declines.
Further, across all cases we project India to displace the United States and our Other
Asia-Pacific modeling region1
to displace Western Europe as the second- and third-highest emitters of energy-related
CO2 emissions by 2050, respectively.
Three different rates of macroeconomic growth underlie our energy projections across all
modeled cases (Appendix A). Economic and population growth drive the increase in
emissions, and we expect global gross domestic product (GDP) to more than double by 2050
in all of our IEO2023 cases, except the Low Economic Growth case. We project the
Asia-Pacific region's GDP will grow faster than the global average, and a declining
population will slow GDP growth in China relative to recent history. Population growth
across our cases is concentrated in Africa, India, and Other Asia-Pacific, which
combined, contribute 94% of the expected 1.7 billion people added to the global
population by 2050 across all cases in our projections.
We project global industrial-sector energy consumption to grow between 9% and 62% and
transportation-sector energy consumption to grow between 8% and 41% from 2022 to 2050,
depending on the case. Increasing income and rapid population growth, particularly in
India, Africa, and Other Asia-Pacific, leads to continued growth in buildings'
energy consumption in our projection. For example, in India, we project energy
consumption in commercial and residential buildings to as much as triple in some cases
between 2022 and 2050.
The intensity of energy-related CO2 emissions (CO2 emissions per
unit of primary energy) decreases through 2050, despite overall emissions increases in
our projections. The decreasing emissions intensity reflects a transition toward
lower-carbon energy sources. These trends of decreasing emissions intensity could be
offset by shifts toward increased manufacturing in certain regions. For example, we
project that declines in energy intensity will be offset by sectoral shifts toward
manufacturing and that industrial energy consumption grows the fastest in India, Other
Asia-Pacific, Africa, and Other Americas. Across most of our cases, China is the region
with the largest level of industrial energy consumption decline, reflecting the
commercial service sector's growing share of China's economy and
manufacturing's shrinking share of total industrial activity.
The shift to renewables to meet growing electricity demand is driven by regional
resources, technology costs, and policy.
We project global electricity generation will increase by 30% to 76% in 2050 from 2022
(depending on the case) and will primarily be met by zero-carbon technologies across all
cases. For all cases, we project that 81% to 95% of the new electric-generating capacity
installed from 2022 to 2050 to meet new demand will be zero-carbon technologies. As a
result, by 2050, the combined share of coal, natural gas, and petroleum liquids decrease
to between 27% and 38% of the installed global generating capacity across our cases.
shift to renewables to meet growing electricity demand is driven by regional resources,
technology costs, and policy.
In Western Europe and China, zero-carbon technology capacity increases faster early in
the projection period because of policy, rapid demand growth, and energy security
considerations that favor locally available resources such as wind, solar, and battery
storage prompt more of these types of installations and planned builds.
We project electric vehicles (EVs) to account for between 29% and 54% of global new
vehicle sales by 2050; China and Western Europe account for between 58% and 77% of those
EV sales across all cases. Continued increases in EV adoption leads to a projected peak
in the global fleet of internal combustion engine light-duty vehicles (LDVs) between
2027 and 2033.
Energy security concerns hasten a transition from fossil fuels in some countries,
although they drive increased fossil fuel consumption in others.
Energy security concerns hasten a transition from fossil fuels in some countries,
although they drive increased fossil fuel consumption in others.
Natural gas and crude oil supply, consumption, and trade patterns evolve in our
projections to meet growing demand against the backdrop of Russia's full-scale
invasion of Ukraine, which we assume will continue to limit Russia's exports to
Western markets. The Middle East and North America are the primary regions to increase
natural gas production and exports to meet growing international demand, mainly in Asia
and Europe. Near- to mid-term (2023–2035) growth in crude oil production is met by
non-OPEC regions, particularly in North and South America. OPEC regains market share as
other regions reach peak production, generally between 2030 and 2040 in our projection.
We project reduced gasoline demand due to rising EV sales and rising demand for jet fuel
due to global economic growth, which will drive changes in refineries. Refineries are
currently configured to meet gasoline and distillate demand and cannot easily change the
petroleum ratio of products they produce. To address the shift in global products
demand, refineries need to adjust crude oil inputs, resulting in a transition from light
crude oil to medium crude oil in our projections.
Baseline projections, not forecasts
Many aspects of the global energy system over the next three decades are deeply
uncertain. Although the IEO2023 cases—which vary assumptions related to
macroeconomic growth, technology costs, and fuel prices—help to capture the range
in possible outcomes, many unmodeled issues remain that could drive significant change
across the global energy system.
Key among the unmodeled issues: our model does not assume future policy. We assume
current policies, as of March 2023, remain in place. Specifically, in IEO2023, policies
without enforcement mechanisms are discounted, and those with expiration dates expire as
indicated. For the United States, we only consider policies implemented by November 2022
because IEO2023 uses our Annual Energy Outlook 2023 to model the U.S. energy
system. Since November 2022, U.S. government agencies have implemented provisions
associated with the Inflation Reduction Act, although not all are finalized.
Therefore, our projections should not be interpreted as forecasts. Our projections
represent a set of policy-neutral baselines against which future policy action can be
evaluated. When interpreting our results, keep in mind the caveats associated with our
The International Energy Outlook 2023 (IEO2023) explores long-term energy trends
across the world. IEO2023 analyzes long-term world energy markets in 16 regions through
2050. We developed IEO2023 using the World Energy Projection System (WEPS),2 an integrated economic
model that captures long-term relationships between energy supply, demand, and prices
across regional markets.
IEO2023 identifies three key findings:
Increasing population and income offset the effects of declining energy
and carbon intensity on emissions.
The shift to renewables to meet growing electricity demand is driven by
regional resources, technology costs, and policy.
Energy security concerns hasten a transition from fossil fuels in some
countries, although they drive increased fossil fuel consumption in
We explore the three key findings in separate sections of this report, each containing a
series of in-depth explanations that include region- and sector-specific insights across
modeled cases. IEO2023 includes a series of cases that reflect different assumptions
related to macroeconomic growth, technology costs, and fuel prices, although the future
remains significantly uncertain. Therefore, our cases should not be interpreted as
predictions. One important source of uncertainty is future policy implementation around
the world. Our IEO2023 cases are based on current laws and regulations as of March 2023.
In particular, U.S. projections in IEO2023 are the published projections in the
Annual Energy Outlook 2023 (AEO2023), which assumes U.S. laws and regulations
as of November 2022 remain unchanged. Our projections provide a range of outcomes in a
world of frozen policy that are intended to help inform decision makers as they plan for
IEO2023 cases do include some anticipated changes over time:
Expected regional economic and demographic trends based on the views of leading
Planned or known changes to infrastructure for new construction and announced
Assumed cost and performance improvements in established technologies based on
Sources of uncertainty
Energy market projections are inherently uncertain because many of the events that will
shape future energy markets—including developments in policy, technology,
demographics, and resources—are unknown. Many sources of uncertainty exist beyond
the ones we test explicitly, including new policies, unforeseen geopolitical events, and
rapid technological innovation. Innovation is particularly relevant for technologies in
the earliest stages of development.
Any future legislation would further affect technology trajectories and emissions
pathways. We reflect legislated and enacted energy sector policies that can be
reasonably quantified in WEPS. Policies with expiration dates expire rather than being
replaced or extended. Policies without enforcement mechanisms are evaluated and, in some
cases, assumed to be only partially met. More information on how we model climate
policies is available in our companion article, Climate Considerations in the International
Energy Outlook 2023.
Since we released the most recent IEO in late 2021, the world has changed. We have had
significant national and international short-term market volatility associated with
economic growth as the world reemerges from the COVID-19 pandemic and with the political
instability associated with Russia's full-scale invasion of Ukraine. Appendix B
discusses the assumptions we made around the invasion and how we represented it in our
An economic recovery starting around 2030.
Two nuclear power plants that are located in military conflict zones in Ukraine
resume full operation by 2034.
Western Europe and the United States suspend imports of crude oil and petroleum
liquids from Russia, beginning in 2023 and lasting through 2050.
The outage of Nordstream natural gas pipelines continues through 2050.
We continuously monitor such developments and consider how they may affect our long-term
IEO2023 explores key areas of uncertainty about how energy markets will develop through a
Reference case and the following six side cases, including two new side cases in this
IEO that focus on higher and lower zero-carbon technology costs:
High and Low Economic Growth cases
High and Low Oil Price cases
High and Low Zero-Carbon Technology Cost cases
As in AEO2023, our graphs emphasize the range of results, denoted by shaded areas, across
all modeled cases. We derive our key analytical insights by assessing the results across
cases and examining how overall trends may vary under the different assumptions.
In IEO2023, we used a new regional representation to group countries in the World Energy Projection System
(WEPS). The new regional groupings are based solely on geography. Figure 1 shows
a map of our new 16 regions and 4 superregions (that is, Americas, Europe and Eurasia,
Africa and Middle East, and Asia-Pacific). A table of the countries assigned to each
region is available in Appendix C.
Some components of uncertainty in the IEO are magnified by the global focus. For example,
both short-term and long-term projections of GDP are more uncertain in economies with
lower GDP per capita than in economies with a higher GDP per capita (Appendix A).
Similarly, although we assume implemented laws and regulations in the United States will
be enforced, policy norms vary around the world. The balance between energy security,
climate policies, and economic growth also vary in different regions of the world and
can be influenced by as-yet-unknown geopolitical events. Our IEO cases explore some
components of this uncertainty.
Increasing population and income offset the effects of declining energy and carbon intensity on emissions
The future trajectory of global energy consumption and emissions will be determined by
complex and interrelated dynamics that play out across regions, sectors, and time.
Global energy consumption increases 34% from 638 quadrillion British thermal units
(quads) in 2022 to 855 quads in 2050 in the Reference case and varies between 739 quads
and 999 quads by 2050 across the other cases.3 Corresponding energy-related CO2
emissions rise 15% from 35.7 billion metric tons in 2022 to 41.0 billion metric tons in
the Reference case, and they vary between 35.1 billion metric tons (a decrease from 2022
levels) and 47.9 billion metric tons by 2050 in the other cases.4
To better illustrate the basic dynamics that drive global primary energy consumption and
energy-related CO2 emissions, Figure 2 represents our model projections as a
series of four driving factors: population, average income (per capita GDP), energy
intensity (energy per dollar GDP), and carbon intensity (CO2 emissions per
unit of primary energy).
At a given point in time, the product of the first three factors yields total primary
energy consumption, and the product of all four factors yields total energy-related
CO2 emissions. Quantifying emissions this way is known as the Kaya
Identity,5 which provides a
useful conceptual framework for thinking about the high-level factors that drive changes
Growth in the first two components—population and GDP per capita—place upward
pressure on energy-related CO2 emissions, and projected decreases in the
third and fourth components—energy and carbon intensity—place downward
pressure (Figure 2).
The first four sections in this chapter provide additional insight at the global level.
We begin by analyzing the two factors of the Kaya identity that continue to drive global
emissions though 2050: population and GDP per capita. We round out our global overview
by discussing global energy consumption by fuel type, sector, and emissions worldwide.
Because regions and sectors vary significantly, the last five sections examine the
dynamics driving energy consumption. These sections focus on fuel and technology
pathways, which inform the energy- and carbon-intensity factors of the Kaya identity and
how the ongoing declines of these factors moderate emissions growth. These sections
highlight the value of our detailed World Energy Projection System (WEPS) model, which
explores the complex interconnections of macroeconomic drivers and technology evolution
over time, producing global total energy consumption and emissions (Figure 3).
GDP growth and population trends are major drivers of energy
IEO2023 assumes that, as incomes and population rise over time, energy consumption
increases as more people can afford to drive, use commercial services, demand goods, and
control building temperatures. Macroeconomic projections, specifically population and
GDP trends, are key drivers of the energy consumption and production results in WEPS.
Global population increases from 7.9 billion in 2022 to 9.6 billion in 2050, an average
growth rate of 0.7%, and does not vary across cases. The regions with the largest
population increases by 2050 are Africa (1 billion), the Other Asia-Pacific region (306
million), and India (249 million) across all cases. Falling populations in China, Japan,
Russia, and South Korea will weigh on GDP growth as the labor force shrinks.
Global GDP grows annually at an average rate of 2.6% in the Reference case, from
approximately $136 trillion to $275 trillion in real 2015 purchasing power parity (PPP)
adjusted U.S. dollars (USD), from 2022 to 2050. Global GDP in 2050 rises to a range of
$221 trillion (2015 PPP USD) in the Low Economic Growth case to $345 trillion (2015 PPP
USD) in the High Economic Growth case. Developing Asia, specifically India and our Other
Asia-Pacific region, contributes the most to global economic growth (Figure 4). We
project China to retain the highest GDP in 2050 despite slower growth relative to
GDP and population growth affect energy consumption in several ways. First, economic
activity is reallocated across sectors as GDP per capita increases. As household incomes
rise, wealthier consumers shift their consumption toward energy-intensive goods and
services. Because energy intensities vary from one sector to another, this reallocation
tends to raise total energy consumption.
Second, technology and energy efficiency improvements often accompany economic growth.
Improvements in energy efficiency reduce energy consumption per unit of output; we
discuss these energy and economic mechanisms across sectors in greater detail next.
The tension between changes in sector composition due to rising incomes and population as
well as energy efficiency determines the overall impact on total energy consumption.
Globally, we project that increases in energy consumption per person will outweigh the
pace of efficiency improvements.
Third, demographic trends affect economic activity and are important drivers of total
energy consumption. We project the labor force as a share of the population will
decrease in many regions, which tends to lower average productivity and GDP per capita
(Figure 5). These demographic factors vary by region and are reflected in our
macroeconomic projections for population and GDP growth. Our global population
assumptions do not vary across side cases.
Renewable energy grows the fastest as a share of primary
energy consumption across all cases due to current policy and cost drivers
Across all IEO2023 cases, energy consumption increases globally, driven by demographic
and macroeconomic trends. The
increased consumption coupled with current policy and energy security concerns drive
non-fossil fuel sources to gain a
larger share of the increasing primary energy consumption worldwide (Figure 6).
Renewable energy consumption,
particularly solar and wind, grows faster than any other energy source, and the
non-fossil fuel share of primary energy
grows from 21% in 2022 to a range of 29% to 34% in 2050 across the cases. The projected
rise in renewable energy
consumption is largely driven by its increased use for electric power generation..
Natural gas is the fastest-growing fossil fuel globally; consumption grows from 153 quads
in 2022 to a range of 170 quads to 241 quads by 2050 across cases, an 11% to 57%
increase. Growth in natural gas consumption is widely distributed regionally, but it is
most notable in India, the Other Asia-Pacific region, China, Africa, Russia, the Middle
East, and the Other Americas region. The projected rise in natural gas consumption is
most pronounced in the electric power sector, where it replaces retiring coal-fired
generation, and the industrial sector, where it primarily fuels expanding industrial
Starting from 166 quads in 2020, global coal consumption grows in some cases while it
decreases in others. From 2022 to 2050, the largest growth (19%) is in the High Economic
Growth case, and the largest decrease (13%) in coal consumption is in the Low Economic
Growth case. Coal consumption varies by region, increasing in Africa, India, and the
Other Asia-Pacific region and decreasing in China and the United States.
Global demand grows fastest in the industrial and residential
Across all cases, end-use consumption, not including electricity-related losses, grows
through 2050 across all sectors (Figure 7). The industrial sector grows by the greatest
amount across most cases—ranging from a relatively flat increase of 24 quads in
the Low Economic Growth case to as much as a 159-quad increase in the High Economic
Growth case over 2022 to 2050. The industrial sector has the widest range of consumption
across cases due to a broad range of industrial gross output assumptions across our
cases and a sensitivity to macroeconomic drivers.
Consumption grows at the fastest pace in the residential sector, averaging 1.0% to 1.6%
per year over the same period across all cases.
Global energy-related CO2 emissions increase
through 2050 in most cases, but carbon intensity declines in all cases
Global energy-related CO2 emissions in 2050 are higher than in 2022 in all
cases except the Low Economic Growth case. In the High Economic Growth case, emissions
rise from 35.7 billion metric tons in 2022 to up to 47.9 billion metric tons in 2050
(Figure 3). In the Low Economic Growth case, global energy-related CO2
emissions fall to 35.1 billion metric tons by 2050. Economic activity (the product of
population and GDP per capita), the fuel choices supporting that activity, and the
energy and carbon intensity of that activity drive the range of projections. The largest
differences in economic activity are between the High and Low Economic Growth cases, and
the largest differences in carbon intensity are between the High and Low Zero-Carbon
Technology Cost (ZTC) cases.
projections indicate that resources, demand, and technology costs will drive the shift
from fossil fuel to non-fossil fuel energy sources, but current policies alone will not
decrease global energy-sector emissions.
Changes to the fossil fuel consumption mix—which is heavily determined by relative
fuel prices—decrease global emissions intensity across all cases. Rapid growth of
renewable power sources in the electric power sector further decreases emissions
intensity, and the largest effects occur in the Low ZTC case. Within fossil fuels,
liquid fuels and natural gas gain a larger share of fossil fuel consumption, lowering
global emissions intensity because they emit less CO2 than coal when
combusted. Contrary to the global trend, regions with access to affordable coal, such as
the Other Asia-Pacific region, consume more coal as a share of total fossil fuel
consumption. Coal remains the number one source of energy-related CO2
emissions, followed by liquid fuels and natural gas (Figure 8).
On a regional level, China remains the top source of energy-related CO2
emissions, although its share of the global total declines. Meanwhile, the shares of
global emissions increase from India and the Other Asia-Pacific region, and these two
regions displace the United States and Western Europe to become the second- and
third-highest emitters of energy-related CO2 emissions, respectively.
CO2 emissions from coal combustion fall as a share of total energy-related
CO2 emissions from 47% in 2022 to a range of 37% to 41% in 2050 across all
cases. Declining coal emissions in China and the United States primarily drive the
global decline, with additional, smaller declines in Western Europe, Canada, and Japan.
Although China has the largest decline in emissions from coal, it remains the number one
source of emissions from coal, ranging from 44% to 46% of the global total in 2050
across cases (Figure 9).
Carbon emissions increase in the transportation sector due to
growing travel demand, regional variation in electrification, and slow turnover of the
Increasing demand for passenger and freight travel drives global transportation energy
consumption, which grows by 8% to 41% across cases between 2022 and 2050. Steady
population increases coupled with rising incomes, employment, and industrial output
increase travel demand.
Demand for passenger travel, as measured in passenger miles traveled, increases by
64%—108% across cases from 2022 to 2050 primarily due to growth in both population
and income. This increase corresponds to an increase in both the number of people
traveling and the miles traveled by each person. Global population growth is responsible
for about one-third of the projected increase in passenger travel demand between 2022
and 2050; in Africa, population growth is responsible for more than one-half of the
projected increase in passenger travel demand in the region between 2022 and 2050.
Global per capita travel demand is highly sensitive to changes in disposable income per
capita and employment. We project that the global average passenger miles traveled per
person will increase 51% between 2022 and 2050 in the Reference case, varying between
35% in the Low Economic Growth case and 71% in the High Economic Growth case. Much of
this growth is concentrated in India and the Other Asia-Pacific region, where disposable
income and employment grow significantly across all cases. Regions with slower income
growth—and with lower absolute income per capita, such as Africa and the Other
Americas region—continue to have growing travel demand, due to increases in
employment, but to a lesser degree. In regions where both income and employment grow
more slowly, such as Canada, South Korea, the United States, Western Europe, and Japan,
per-capita travel demand growth is lower (Figure 10).
Continued increases in electric vehicle adoption lead to a projected peak between 2027
and 2033 in the global fleet of internal combustion engine light-duty vehicles.
Travel demand for less efficient modes of transportation grows in regions as incomes
increase. Rising incomes in several regions enable travelers to shift from inexpensive
but more efficient modes (such as two- and three-wheelers, buses, and rail) to more
convenient but less efficient modes (such as light-duty vehicles [LDVs]), especially in
China, India, and the Other Asia-Pacific region. Aircraft travel, which is highly
sensitive to changes in income, is noticeably increasing across all regions. In regions
with slower income growth, such as Africa and the Other Americas region, use of two- and
three-wheelers persists and grows more than aircraft and LDV travel. This trend occurs
across our four superregions as growth from a 2025 baseline—which is when we
project travel to return to pre-pandemic levels (Figure 11). For example, we project LDV
travel demand in the Asia-Pacific superregion—which includes China and
India—to double, and we project two- and three-wheeler and rail travel demand to
increase by less than 50% across all cases. We see the opposite in the Africa and Middle
East superregion, where we project two- and three-wheeler travel demand to grow over
three times the 2025 level, and LDV travel demand to increase by less than 70% across
all cases. We also project travel demand to increase across all superregions, modes,
years, and cases, except for bus travel, which plateaus or starts to decline in all
superregions but Africa and the Middle East.
The aggregate increase in LDV travel leads the global on-road LDV fleet to grow from
about 1.4 billion vehicles in 2022 to more than 2.0 billion vehicles by 2048 in the
Reference case, with all but the Low Economic Growth case exceeding 2.0 billion vehicles
Efficiency improvements within each powertrain technology offset a significant portion of
the energy consumption from travel demand growth and the wider shift into less-efficient
modes of travel. Efficiency of the global LDV fleet increases by over 40% between 2022
and 2050 in all cases, reaching a global average of between 42 miles per gallon and 52
miles per gallon across cases. Average efficiency continues to increase due to
improvements within each individual powertrain type (for example, gasoline internal
combustion engine, gasoline hybrid, battery electric) as well as a sales shift from less
efficient to more efficient powertrains, primarily electric vehicles (EVs). We apply
implemented and enforceable fuel economy standards that vary regionally, but we do not
include government and industry aspirations and intentions in our projections. Stricter
standards—such as those in Canada, China, South Korea, Japan, Australia and New
Zealand, and parts of the European Union—drive efficiency improvements in
conventional internal combustion engine (ICE) vehicles through the mid-2030s. The
advanced technology required to achieve this efficiency also increases ICE vehicle
Electric vehicle sales grow due to current policy incentives,
efficiency standards, favorable electricity prices, and decreasing battery costs
Purchase incentives for EVs—such as those in Canada, China, several countries in
the European Union, Japan, South Korea, and the United States—increase EV sales in
the near term. In the longer term, declining battery prices lead to additional growth in
EV adoption even as current fuel economy standards level off.
EVs (which include battery electric and plug-in hybrid electric vehicles) account for 29%
to 54% of global new vehicle sales by 2050, reaching cumulative sales between 465
million and 832 million battery electric vehicles as well as between 218 million and 241
million plug-in hybrid electric vehicles over the projection period (2022 to 2050)
(Figure 12). China and Western Europe account for 58% to 77% of those EV sales because
of supportive policy and the size of their LDV market; the two regions account for
between 37% and 40% of all global LDV sales between 2022 and 2050.
Continued increases in EV adoption lead to a peak in the global fleet of ICE LDVs between
2027 and 2033 in all cases (Figure 12); in the High Economic Growth and Low Oil Price
cases the ICE fleet reverses the decline in 2043 and starts growing again. Slow turnover
of LDVs means more than 1.1 billion ICEs are still on the road by 2050 in all cases.
Technical Note 1: EV penetration
We determine the non-U.S. share of electric vehicle (EV) sales in our projection
using a multinomial logit function that includes comparative vehicle purchase price,
cost to drive, model availability, and fuel availability. Growing EV sales drive
growth in the number of EV models available and access to EV charging
infrastructure, which both support further increases in EV sales. In our projection,
the purchase price and cost to drive factors are affected by enacted and enforceable
regional purchase incentives and fuel economy standards, declining battery costs,
and electricity and gasoline prices. We do not include stated aspirations and
ambitions for EV market penetration rates that are not supported by enforceable laws
or regulations in our projections.
U.S. projections in IEO2023 are from our AEO2023. The National Energy Modeling System
(NEMS), which produces the projections in the AEO, has a detailed representation of
the U.S. light-duty vehicle market, policies, and technological development. AEO2023
results include the Inflation Reduction Act, specifically the Clean Vehicle Credit,
as well as the latest finalized Corporate Average Fuel Economy (CAFE) standards for
model years 2024–2026. Specific assumptions are discussed in AEO2023.
We include policies in many regions that provide incentives and rebates for consumers
that purchase or lease EVs. These incentives vary by country and regionally within
countries. For example, the iZEV program in Canada provides EV purchasers with
point-of-sale incentives ranging from CA $2,500 to CA $5,000, depending on the
powertrain type (battery electric or plug-in hybrid) and driving range of the
vehicle (more or less than 50 kilometers). Some Canadian provinces provide separate
incentive programs that offer additional rebates to EV purchasers. China, South
Korea, Japan, Australia and New Zealand, and parts of the European Union have
similar programs but with their own requirements and incentives.
Enforceable fuel economy standards are also modeled regionally in our projections.
Many of the regions listed above have enforced stricter fuel economy standards.
Stricter standards result in increased ICE vehicle efficiency but also result in
higher ICE vehicle purchase price, reducing the ICE vehicle sales share in favor of
EVs. Over time, these standards plateau, but their impact on adopting
efficiency-improving technologies is long term.
The combination of incentive policies and stricter fuel economy standards increases
EV sales, which produces a feedback loop through our learning algorithm that drives
down battery costs and results in greater EV adoption in the long term. We base
projected battery cost declines on the historical relationship between production
costs and cumulative production, modeled using a learning rate.
We can estimate whether EVs reach cost parity with ICE vehicles within our projection
window using several factors, including:
Enacted and enforceable regional purchase incentives
Enacted and enforceable fuel economy standards
Declining battery costs
Favorable electricity and gasoline prices modeled in our projection
Energy security and decarbonization policies in the buildings
and industrial sectors of Western Europe slow natural gas consumption growth,
accelerating the use of electricity
Current European Union policies aim to decrease carbon intensity and to limit imports of
fossil fuels from Russia, driving electrification and decarbonization in the industrial,
buildings, and district heat sectors. In the industrial sector, stricter efficiency
policies lead to declining energy intensity. Total industrial energy intensity across
all fuels in Western Europe decreases by 18% to 20% from 2022 to 2050 across all cases
In Western Europe, industrial, residential, and commercial energy consumption grows more
slowly than economic indicators of sector growth. For example, energy consumption in
homes in Western Europe grows more slowly than disposable incomes. Across the IEO2023
Reference case and Economic Growth cases, which are our bounding cases for both economic
output and energy use, the amount of energy consumed per dollar of output in the
commercial and industrial sectors declines faster for natural gas than for electricity.
Although this effect is most pronounced for the industrial sector, the intensity of
natural gas use in buildings (particularly residential buildings) declines more rapidly
than the intensity of electricity use in buildings (Figure 14). This difference is, in
part, due to policies prioritizing the use of electricity over other energy sources in
Buildings accounted for 47% of natural gas consumption in Western Europe and 61% of the
region's electricity consumption in 2022, a share we project to decline slightly
over time as electricity use for transportation increases through 2050. Buildings'
share of electricity use in Western Europe declines fastest in the IEO2023 High Economic
Growth case—down to 56% by 2050—as increasing incomes support faster
adoption of electric vehicles (EVs). With a greater number of EVs on the road, we
project that the transportation sector will have a larger share of the electricity used
in end-use sectors.
Despite faster growth in electricity use in the transportation sector, buildings continue
to make up over one-half of Western Europe's electricity consumption across all
cases, in part because European countries have enacted laws and incentives to slow
growth in natural gas consumption. However, stable natural gas prices contribute to the
slight decline to modest growth in natural gas consumption in all end-use sectors
combined over the projection period, ranging from a decline of 3% to an increase of 19%
from 2022 to 2050 across all cases.
Western Europe, electricity use in buildings grows as much as five times as quickly as
natural gas consumption through 2050 because of near-term policies enacted to reduce the
natural gas imported from Russia.
In Western Europe, electricity use in buildings grows three to five times as quickly as
natural gas consumption through 2050 across all cases because of near-term policies
enacted to reduce natural gas imported from Russia. In the winter of 2022, many Western
European countries implemented laws and incentives to reduce natural gas consumption in
homes, in commercial buildings, and in the industrial sector. In addition, countries
developed enhanced building energy codes and the made funds available to complete energy
retrofits, intended to support the EU's ability to meet energy efficiency targets
through 2030. Policymakers design these measures to shape long-term behavioral change,
to ensure that efficiency tempers expanding energy demand, and to prioritize
carbon-neutral energy sources. One example is government-sponsored subsidies for
installing energy efficient and non-fossil fuel equipment, such as an
incentive in France to offset the cost of heat pumps. Such programs provide
incentives to purchase electric technologies over natural gas equipment as consumers
replace or purchase new heating and cooling systems.
For centralized district heat plants—which provide space and water heating in
residential and commercial buildings and process heat and steam for the industrial
sector—we project that generation resources will increasingly shift to renewable
sources through 2030. Across all cases, biomass-fired heat displaces natural gas and
coal consumption for district heating as EU member countries conform with the district
heating provisions of the Renewable
Across all cases, in 2050, biomass accounts for 29% to 38% of heat generation that meets
industrial sector demand for heat and steam in Western Europe, excluding the share of
heat generated from combined-heat-and-power (CHP) or cogeneration sources, which
generate both electricity and useable heat. Accounting for fuel use by CHP sources, we
project renewable sources, including biomass, to account for 23% to 25% of heat
generated for all sectors in district energy networks in 2050 across cases.
As India's economy expands, building electrification
supports a rapidly expanding service sector; home energy use triples
Our projection for energy consumption in India exemplifies the relationship among energy
consumption, income, and service sector growth. Increases in disposable income and rapid
population growth lead to significant increases in residential energy use, which triples
over the projection period. Commercial energy consumption increases as the sector
expands to meet growing demand for services. This contributes to increases in
buildings' energy consumption overall, which almost triples by 2050 relative to
2022 across all IEO2023 cases (Figure 15). Electrification of the building stock
supports broader electricity use, which increases more than any other energy source in
the residential and commercial sectors.
In India, in the High Economic Growth case, electricity use in buildings grows nearly
five times 2022 levels by 2050 as total building energy consumption triples over the
same period. Even in the Low Economic Growth case, commercial energy consumption more
than doubles by 2050, led by business expansions and increases in warehousing and retail
sales, education, and other services. Across all cases, after 2035, commercial and
residential electricity use grows even faster as average electricity prices for all
consumers decline through 2050.
Population growth increases building energy consumption in India. On a per capita basis,
total delivered energy consumption more than doubles from 2022 to 2050 in the commercial
sector and increases by two to three times in Indian homes across our range of cases.
In India, electricity use in buildings in the residential sector grows faster than in
other sectors because of increased demand for air conditioning, electric appliances, and
other devices. Disposable income grows faster in India than anywhere else in the world,
increasing, on average, 3% to 5% annually. Compared with 2022, we project that even in
the Low Economic Growth case, with incomes growing more slowly than in our Reference
case, each person in India will use nearly three times as much residential electricity,
on average by 2050.
In the High Economic Growth case, by 2050, India's energy consumption across all
end-use sectors more than triples relative to 2022. Growth in the commercial sector
outpaces overall industrial growth from 2022 to 2050 (Figure 16).
India transitions to a service-oriented economy slightly faster in the High Economic
Growth case, reducing the overall energy intensity of the economy relative to the
Reference case. This outcome occurs not only because the economy grows faster than
energy consumption in the High Economic Growth case, but also because the commercial
sector is less energy intensive than the industrial sector. Economy wide, the energy
intensity of consumption in India declines to 2.61 thousand British thermal units (Btu)
per dollar of GDP (2015 PPP USD) in the High Economic Growth case, reaching the lowest
energy intensity in India in any IEO2023 case (Figure 17).
Declining energy intensity in the industrial sector results
from increasing efficiency in the manufacturing subsector, increased recycling in the
primary metals industries, and continued advances in energy-efficient technologies
Global energy consumption in the industrial sector—which includes both
manufacturing and non-manufacturing (construction, agriculture, and mining)
industries—varies widely across cases. As industrial gross output grows, energy
consumption increases between 9% and 63% by 2050, from 257 quadrillion British thermal
units (quads) in 2022. Growth in industrial energy consumption varies across regions,
with the fastest growth in India and three of our multi-country regions—Africa,
Other Asia-Pacific, and Other Americas (Figure 18). Much of the growth in these
regions' industrial sectors occurs in the manufacturing subsector, especially in
energy-intensive industries such as primary metals, chemicals, and non-metallic
minerals. China is the region with the largest decline in industrial sector energy
consumption, despite its overall increasing industrial gross output, partially because
of a shift in growth to less energy-intensive industries and realized energy efficiency
improvements in its primary metals industry.
Over time, as GDP per capita increases, economic activity is reallocated across sectors
in a systematic way. Generally, agriculture's share of gross output, value added,
and employment declines, and the service sector's share increases. Initially,
manufacturing's share of gross output, value added, and employment grows but
eventually peaks at intermediate stages of economic development. This process produces
changes in sector composition that are reflected in the energy intensity of each region.
Although growth in industrial energy consumption varies across regions, industrial
energy intensity declines globally through 2050, in part, because of increases in
Industrial energy intensity—measured as the ratio of industrial energy consumption
to output (dollar value of shipments)—declines globally from 2022 to 2050, in
part, because of increases in efficiency. Industrial energy intensity also varies by
region because of differences in the pace of energy efficiency advancements, specific
activities within each subsector, and the evolution of the sector composition. Changes
to industrial technologies and the composition across regions reflect our current
understanding of national and regional policies, supply chains, and commercially viable
technology. We don't include revolutionary technological breakthroughs or policies
that are not codified and enforceable.
India is the fastest-growing region in terms of GDP and GDP per capita across all cases.
The country's manufacturing subsector grows from $6.7 trillion (2015 PPP USD) in
2022 to a range of $20.9 trillion (2015 PPP USD) in the Low Economic Growth Case to
$34.7 trillion (2015 PPP USD) in the High Economic Growth Case. As a result, industrial
energy consumption in India increases from 18.6 quads in 2022 to a range from 40.2 quads
in the Low Economic Growth case to 64.1 quads in the High Economic Growth case in 2050
(Figure 19). Growth in the manufacturing sector outpaces other sectors and, as a result,
grows as a share of total industrial gross output in all the IEO cases. We project
India's manufacturing activity, a relatively energy-intensive subsector, to grow
from 60% of the country's total industrial gross output (as measured in 2015 PPP
USD) in 2022 to 71% of total industrial gross output in 2050 across all side cases.
Figure 19 shows India's industrial energy intensity and how changes in sector
composition and energy efficiency affect it. Technology and efficiency developments
reduce energy use, while changes in India's industrial sectoral composition drive
additional energy consumption. The net effect is a decline in industrial energy
intensity in India.
In contrast to India, China's industrial energy consumption declines in all cases
except the High Economic Growth case (Figure 20). Energy consumption decreases partly
because many of the industries in China increase energy efficiency by implementing more
recycling and technology advancements. Although we project energy-intensive
manufacturing declines as a share of China's industrial activity, this sectoral
shift only mildly contributes to the overall decline in industrial energy consumption.
Overall, manufacturing gross output—when measured in 2015 PPP USD—made up
49% of all gross output in China in 2022, but it decreases in our projection to 41% in
2050 in all IEO2023 side cases.
The different trajectories of industrial energy consumption in China and India are also
motivated by their primary metals industry, which is made up of steel—the top
energy consumer of the primary metals industry—and non-ferrous metals, such as
aluminum. In aggregate, the two countries' primary metals industries contributed
about 6% of total global emissions in 2022. In China, unlike India, we project that the
gross output of the iron and steel industry will decline over the long term, and the
country could significantly increase production of recycled steel, which is
significantly less energy intensive 6. We assume steel produced by the more
energy-intensive coal-based basic oxygen furnace process declines to 40% for all cases
by 2050, down from 88% in 2022. For the Reference case, this change will reduce steel
industry coal demand in 2050 by 71% relative to 2022. China's steel industry gross
output falls by 25% over the same period in the Reference case, with 2050 steel industry
gross output ranging from $0.9 trillion (2015 PPP USD) in the Low Economic Growth case
to $1.7 trillion (2015 PPP USD) in the High Economic Growth case (Figure 21).
Due to this change in steel production processes in China, coal consumption by its steel
industry ranges from 4.0 quads in the Low Economic Growth case to 7.8 quads in the High
Economic Growth case in 2050. This decline in metallurgical coal consumption decreases
domestic coal production by a range of 38% to 94% across cases. This decrease affects
coal imports, which vary from a 65% decrease to a 4% increase across cases compared with
2022. Coal production in China declines faster than coal imports because of higher costs
for mining and transporting domestically sourced coal, continuing the country's
need for imports from regions such as Australia and Russia.
Although India faces similar coal production challenges as China, the growing coal demand
in India increases domestic coal production through 2050 (Figure 22). The increasing
coal demand is driven by the increasing gross output and the industry's unique and
heavy reliance on coal to make iron ore using direct reduced iron (DRI). From 2022 to
2050, India's metallurgical coal production increases by 10% to 28%, and coal
imports increase by 120%—202% across cases. India receives imports from regions
such as Australia and Africa, and potentially Canada and the United States, as demand
for metallurgical coal rises.
In addition to the iron and steel industry, energy efficiency increases in the aluminum
industry (the largest component of the nonferrous metals industry) mostly as a result of
the switch from primary to secondary aluminum production. Secondary aluminum is made by
remelting recycled aluminum or scrap from production. Globally, we project the aluminum
industry will grow by approximately 76% from 2022 to 2050 in the Reference case, while
the aluminum industry's energy demand will rise by only 9% (Figure 23). The High
and Low Economic Growth cases project different futures for the aluminum industry. Gross
output reaches $7.3 trillion (2015 PPP USD), and energy demand reaches 10 quads in 2050
in the High Economic Growth case. Gross output reaches $4.5 trillion (2015 PPP USD), and
energy demand reaches 6.5 quads in 2050 in the Low Economic Growth case.
Production of secondary aluminum, which requires about 90% to 95% less energy than
primary aluminum, contributes to the decline of energy demand growth relative to the
industry's gross output.
The shift to renewables to meet growing electricity demand is driven by regional resources, technology costs, and policy
We project electricity generation worldwide will increase 30% to 76% in 2050 relative to
2022 across all cases (Figure 24). By 2050, zero-carbon generating
technologies—renewables and nuclear—supply electricity for 54% to 67% of the
total demand across cases. Across most years, the Low Zero-Carbon Technology Cost (ZTC)
case projects the most wind and solar generation across the globe. This case assumes a
more rapid capital cost decline than in the Reference case for a subset of zero-carbon
technologies, including storage (Appendix A). Other cases, such as the High Economic
Growth case, also show significant growth in renewable generation, suggesting that the
cost competitiveness of renewables is more prominent when serving higher incremental
demand. The rest of the demand is mainly met by coal and natural gas.
Coal-fired generation varies across cases in 2050, from declining 24% to increasing 10%
from 2022 levels. The upper bound for coal occurred in the High Economic Growth case,
where the economy is assumed to grow more rapidly compared with the Reference case and
more generation is needed from all generating resources. The lower bound for coal
generation occurred in the Low Economic Growth case until the mid-2040s and in the Low
ZTC case thereafter. In the Low Economic Growth case, where electricity demand is lower,
less coal generation is needed to meet demand. In the Low ZTC case, higher generation
from zero-carbon technology displaces coal generation.
By 2050, growth in global natural gas-fired generation ranges from 1% to 66% relative to
2022. The upper bound in natural gas-fired generation occurred in the High Oil Price
case in the early part of the projection period, but in the High Economic Growth case
over the later portion of the projection period. This range indicates the potential
effect of high economic growth and the regions' continual use of existing
facilities. Multiple cases determine the lower bound of natural gas, depending on the
projection period. Natural gas-fired generation is lowest in the Low ZTC case around
2050; in most of the 2030s and 2040s however, natural-gas fired generation is lowest in
the Low Economic Growth case.
New global electricity demand is primarily met by non-fossil fuel sources
By 2050, global coal-fired generation and liquid fuel-fired generation decrease in most
of the cases we modeled. Generation from zero-carbon technologies—primarily solar,
wind, hydroelectric, and nuclear—grows faster than electricity demand in some
cases, and accounts for 78% to 120% of the incremental global electricity demand from
2022 across cases, displacing existing fossil generation in some cases (Figure 25).
Additional natural gas largely meets the rest of the new electricity demand across
To meet increased global electricity demand, installed power capacity increases and, by
2050, reaches a total of about one-and-a-half to two times what it was in 2022 (Figure
26). In 2022, coal, natural gas, and liquid fuels combined made up more than one-half of
the world electricity generation capacity. Zero-carbon technologies (including storage)
make up 81% to 95% of the new global generating capacity installed across cases from
2022 to 2050. In each region, zero-carbon technologies make up most new electric
generating capacity installed except Russia and our "Eastern Europe and Eurasia" region.
So, by 2050, the combined share of coal, natural gas, and liquid fuels decreases to 27%
to 38% of the world's generating capacity across cases.
the zero-carbon technologies, solar photovoltaic capacity is projected to grow the most
Across cases, the 4,600 gigawatts (GW) to 9,200 GW of generating capacity installed by
2050 is predominantly solar, wind, and storage. Nuclear capacity is stable in most cases
except the Low ZTC case, where we eased noneconomic constraints (that is, geopolitical
considerations) to explore the economic effects on nuclear builds (Appendix A). In this
case, nuclear capacity increases by 194 GW in 2050 relative to the 2022 capacity of 400
Current policies, demand growth, and energy security considerations in each region
determine when zero-carbon technologies grow
In China, zero-carbon technology capacity increases faster early in the projection period
but slows closer to 2050 (Figure 27). Western Europe follows a similar trend of a rapid
capacity increase early on in all cases and then slower growth rates across most cases
toward the end of the projection period. Policy, energy security concerns, and rapid
demand growth early in the projection period drive near-term deployment of zero-carbon
technology capacity in these two regions. For China, we include 5% annual growth in
carbon price because most thermal power plants in the region are currently included in
emissions trading scheme (ETS). CO2
emissions limit is included in the electric power sector projection. Energy
security considerations favoring locally available resources—such as wind and
solar—further increase installations and planned builds for these technologies as
well as batteries in China and Western Europe early in the projection period. We project
China will install between 54% and 87% of its 2050 zero-carbon technology capacity
across all cases before 2030, and Western Europe will install between 63% and 95% of its
2050 zero-carbon technology capacity over the same period.
Several other regions, including India and Africa, show rapid growth in zero-carbon
technology after 2030. In India, this later growth is heavily influenced by assumptions
of economic growth, with the growth in these technologies in India across IEO2023 cases
bounded by the High and Low Economic growth cases in most years. In Africa, the upper
range of zero-carbon technology capacity occurs in the High Economic Growth or Low ZTC
case, depending on the projection period, while the lower range occurs in the Low
Economic Growth or High ZTC cases. Across all cases, we project India will install
between 79% and 84% of its zero-carbon technology capacity after 2030, and Africa will
install between 42% and 65% of its zero-carbon technology capacity after 2030. In
general, we expect a smaller range of zero-carbon technology capacity growth in more
developed countries and regions (for example, in Western Europe) because of the smaller
variations in growth rates assumed in our High and Low Economic Growth cases for
developed versus developing regions (Appendix A).
IEO2023 cases model policies that are enacted legislation and can be reasonably modeled.
Other unmodeled or future policies might affect the timing of zero-carbon technology
Regionally, battery storage installation correlates with high variable renewable
Electricity storage, particularly batteries, is used to store excess power produced by
variable generating sources—such as wind and solar—during off-peak hours and
to dispatch the stored energy during times when demand is higher. Battery storage grows
significantly in all cases. In 2022, battery storage capacity was 52 GW, less than 1% of
global power capacity. By 2050, we project that battery storage capacity will increase
to between 625 GW and 1,507 GW across cases, making up 4% to 9% of global power
Use of battery storage differs regionally. In India, the high share of battery storage
capacity coupled with low dispatchable capacity results in battery storage dispatch
meeting 24% of electricity demand by 2050 in the Reference case.
IREStore is a
complementary module to the International Electricity Market Module (IEMM). IREStore
enhances capacity expansion and utilization decisions for variable renewable and
electricity storage technologies using higher temporal resolution. IREStore divides
the year into 288 representative time slices instead of the 12 time slices per year
used in the IEMM.
We model two types of storage technologies in IEMM and IREStore:
Four-hour diurnal batteries connected to the grid
Six-hour pumped-storage hydropower
Although electricity storage can play several different roles on the grid, the
primary use represented in IREStore and IEMM is for energy arbitrage. That is, the
model will store energy when it is cheap, such as when solar energy would otherwise
be curtailed, and dispatch from storage technologies when energy is more expensive,
such as during periods of peak demand.
In general, our model results indicate that solar, more than wind or other resources,
tends to pair well with storage. Solar arbitrage opportunities are very regular and
predictable, making it relatively easy to size both the power and energy capacity of
a storage system for efficient use, compared with wind energy, which has more
irregular generation patterns.
Inside IREStore and IEMM, battery storage has 85% efficiency, meaning that 15% of the
energy is lost during the charging and discharging process. At maximum discharging
rates, it takes four hours for a battery to fully discharge itself. Pumped-storage
hydropower has 80% storage efficiency, meaning that 20% of the energy is lost during
charging (pumping water into its reservoir) and discharging (hydropower generation
using released water from its reservoir). When the water reservoir is completely
full, it can run for six hours before emptying. Either energy-storage type may run
longer at a reduced output level. For example, a four-hour battery could operate for
eight hours at half of the maximum rated output, or two such batteries could operate
at full output for eight hours.
Using the simplified 12 time-slice representation in IEMM, the model tends to
underestimate the opportunities for energy arbitrage when solar capacity is just
starting to grow and overestimate these opportunities at very high levels of solar
penetration. IREStore addresses this shortcoming by allowing energy arbitrage with a
much higher temporal resolution. Figure 28 shows how IREStore models electricity
generation and storage in India in 2050 across four seasons.
India's hourly load (demand) in each of the four seasons is similar, although
the amount of curtailed energy varies with the seasonal variation in solar output.
Curtailed energy is the lowest during the summer due to lower solar energy potential
during India's summer monsoon season. The model arbitrages the
otherwise-curtailed energy during midday hours to provide energy during hours when
more expensive fuels are the marginal dispatch resource. Most of the storage (>99%)
in the IREStore model for India is battery storage.
Fossil fuel-fired generation in the Africa and Middle East superregion and Europe and
Eurasia superregion remains stable throughout the projection period
Natural gas is an important part of the electricity generation mix in several regions of
the world in our projection through 2050. In 2022, natural gas constitutes 61% of the
electricity generation share in the Africa and Middle East superregion. By 2050, the
natural gas share in this superregion is still close to 60% in almost all cases; it
drops to 50% in the Low ZTC case (Figure 29). This result demonstrates the effect of
abundant low-cost natural gas in this superregion combined with continued reliance on
the existing natural gas generation infrastructure. Other regions, such as Russia and
Mexico, also continue to use a significant amount of natural gas for electricity
In the Europe and Eurasia superregion, zero-carbon technology increases by 1,200 billion
kilowatthours (BkWh) to 2,300 BkWh across all cases by 2050 to meet new demand. Across
all cases, the share of zero-carbon technology in the generation mix increases from 55%
in 2022 to between 63% and 65% by 2050. However, the combined generation from natural
gas, coal, and liquid fuels of 2,200 BkWh to 2,600 BkWh in 2050 remains stable in all
cases (except in the High Economic Growth case, which grows to 3,100 BkWh in 2050)
compared with 2,400 BkWh in 2022. Although not as natural gas-dominant as the Africa and
Middle East superregion, the Europe and Eurasia superregion continues to have a
relatively stable amount of fossil fuel-fired generation, which reflects the continued
reliance on the existing capacity mix, the relatively stable demand, and the abundance
of natural gas, particularly in Eurasia.
Variations in costs of zero-carbon technologies affect the energy mix and emissions most
in China and the Other Asia-Pacific region, where coal-fired generation is most
By 2050, we project worldwide electric-generating capacity for zero-carbon technologies
to increase two to three times relative to 2022. The conditions that foster zero-carbon
technology capacity installation, however, are not uniform throughout the regions or the
The assumptions underlying the ZTC cases and the Economic Growth cases particularly
affect zero-carbon technology and coal-fired generation within the Asia-Pacific
superregion, where electricity demand grows most rapidly and coal is cheap and abundant.
China and Other Asia-Pacific, two regions within the Asia-Pacific superregion, show
large variations in generation mix and emissions, particularly as it relates to reliance
In China, coal-fired generation made up 62% of the electricity generation mix in 2022 and
decreases by less than 10% throughout the projection period—from 5,200 BkWh in
2022 to between 4,800 BkWh and 5,100 BkWh in 2050—in all cases except in the Low
ZTC and Low Economic Growth cases (Figure 30). In the Low Economic Growth case,
coal-fired generation decreases almost 25% to 4,000 BkWh by 2050, but because of the
overall decrease in electricity generation due to a decrease in overall demand,
coal-fired generation still makes up 41% of the generation mix. In the Low ZTC case,
coal-fired generation decreases 27% to 3,800 BkWh, resulting in the lowest share of
coal-fired generation (31%) in 2050 among all cases. At the same time, zero-carbon
technology generation in China increases from 3,000 BkWh (35% generation share) to 7,700
BkWh (63% generation share) by 2050 in the Low ZTC case. Among the cases modeled, the
power generation in China is very sensitive to the cost of zero-carbon technologies, as
seen in the Low ZTC case. Impacts of other factors, such as additional policies or
potential market disruptions, are not modeled in these cases.
Coal-fired generation in the Other Asia-Pacific region made up 39% of the generation mix
in 2022, and we project it to increase from about 700 BkWh in 2022 to between 1,000 BkWh
and 2,100 BkWh in 2050 across all cases. In our Reference case, coal-fired generation
accounts for 47% of the Other Asia-Pacific region's total generation in 2050 and
ranges between 30% and 52% across all cases. By 2050, zero-carbon technology generation
in the region accounts for 37% of the generation mix in the Reference case and between
31% to 54% of the generation mix across the other cases. The parameters of the Low ZTC
case particularly affect the Other Asia-Pacific region because it is the only case that
increases zero-carbon technology generating capacity to over 820 GW (73% of all
capacity) and zero-carbon technology generation to over 1,800 BkWh (54% of net
generation). In all other cases, in 2050, zero-carbon technology generating capacity
does not exceed 570 GW and generation does not exceed 1,400 BkWh. The Low ZTC case is
the only IEO case where coal's share of the generation mix decreases to as low as
30% by the end of the projection period.
High coal-fired generation across cases reflects the low cost of coal as a commodity in
both China and the Other Asia-Pacific region. With lower zero-carbon technology costs,
renewables and nuclear generation become more cost competitive in China and the Other
Asia-Pacific region. The sensitivity of China's and the Other Asia-Pacific region's
capacity and generation mix to variation in zero-carbon technology cost and economic
growth illustrates the impact of cost, existing infrastructure, and demand growth.
Policy proposals in China and the Other Asia-Pacific region (where coal is prevalent)
could significantly affect the role of coal in the generation mix. The projected
variation in the electricity generation mix has a large effect on electric power sector
CO2 emissions in these regions and globally.
Total CO2 emissions from fossil fuel-fired generation in China and the Other
Asia-Pacific region totaled 6.2 billion
metric tons in 2022, accounting for 50% of the world’s total CO2 emissions
from fossil fuel-fired generation of 12.5
billion metric tons that year (Figure 31). In 2050, projected CO2 emissions
from fossil fuel-fired generation in China
and the Other Asia-Pacific region vary considerably across cases and range between
decreasing to 5.5 billion metric tons
in the Low ZTC case to increasing to 8.4 billion metric tons in the High Economic Growth
case. This range of outcomes
still results in the combined electric power sector CO2 emissions from China
and the Other Asia-Pacific region
increasing to between a 51% to 57% share of the world’s electric power sector emissions,
which we project will decrease
to 10.4 billion metric tons in the Low ZTC case or increase to 14.8 billion metric tons
in the High Economic Growth
Of the regions included in the Asia-Pacific superregion, China and the Other Asia-Pacific
region combined have the
largest coal-fired generation share. Collectively, the two regions contributed to 77% of
the Asia-Pacific superregion’s
coal-fired generation and 61% of the world’s coal-fired generation in 2022. The high
share of coal-fired generation in
China and the Other Asia-Pacific region and the sensitivity of that generation in those
two regions to the assumptions
made in the Low ZTC and High Economic Growth cases contribute to the large difference in
the Asia-Pacific superregion
and worldwide electric power sector CO2 emissions between the two cases.
Energy security concerns hasten a transition from fossil fuels in some countries, although they drive increased fossil fuel consumption in others
Energy trade is adapting to new realities as Western Europe continues to face challenges
in maintaining fossil fuel production as current geopolitical events disrupt traditional
trade patterns and as emerging economies continue to grow. Although zero-carbon
technologies continue to develop and deploy at scale, our modeled cases suggest major
crude oil and natural gas producers will continue producing to keep up with growing
demand from consumers such as China, India, Southeast Asia, and Africa under prevailing
The Middle East and North America are the primary regions to increase natural gas
production and exports to meet growing international demand, assuming Russia's
exports stay flat
Although Russia has 23% of world natural gas reserves, historical net exports peaked at
over 8 trillion cubic feet (Tcf) in 2019. Russia's net exports fell to about 6 Tcf
in 2022, and in our projection, remain there through 2050. This result assumes that
Russia's full-scale invasion of Ukraine will continue to drive Western markets away
from importing Russian natural gas. The model assumes that Russia will grow natural gas
production to meet future domestic consumption but will not increase its net exports.
The model also assumes Nord Stream 1 and 2 will not return to operation during the
projection period. In addition, low GDP growth and an outflow of foreign investors in
Russia throughout the projection period reduce investment in the country's
export-related infrastructure (Figure 4). Russia will require massive infrastructure
investment to reroute current natural gas production from Western to Eastern markets.
Further, Russia has historically relied on Western companies for liquefied natural gas
(LNG) technology. With the departure of these companies, Russia must develop this
technology domestically, which will take time and investment to bring it to commercial
scale.7 Because shifting
exports from Europe to Asia is limited by technology, trade agreements, and sanctions,
Russia's net exports fall across all cases.
Across all cases, the Middle East's natural gas exports grow throughout the
projection period as other regions' natural gas consumption—driven by
economic growth—outpaces their domestic production (Figure 32). Export growth
takes longer to occur in the High Oil Price case, remaining relatively flat until 2040,
due to high prices promoting more aggressive production growth in other regions of the
The Middle East holds almost 40% of the world's natural gas reserves8. Starting at 6 Tcf in 2022,
net exports reach between 15 Tcf and 26 Tcf by 2050 in most cases, but they increase to
37 Tcf by 2050 in the High Economic Growth case. Most of the growth occurs in the latter
half of the projection period, especially in the High Economic Growth case. (Figure 33).
In the near term, growth of Middle East natural gas exports is consistent with the
planned expansions in capacity expected in Qatar. In the latter part of the projection
period, the strong growth in global demand for natural gas will require new investment
and development of new resources from the significant remaining Middle East reserves.
Natural gas production will grow in all regions if domestic resources are available and
production is price competitive compared with imports. As a region runs out of
cost-efficient resources, it will import natural gas from regions that have access to
cheaper resources. As a result, we expect the Middle East will increase exports over the
projection period because other regions reach their domestic production limit although
their demand continues to grow.
Middle East LNG export volumes depend on assumed U.S. LNG capacity. IEO2023 relies on the
Reference case from the Annual Energy Outlook 2023 (AEO2023), in which almost
10 Tcf of U.S. LNG is exported in 2050. In a supplemental study to AEO2023, we found that U.S.
LNG exports reached nearly 18 Tcf if we assumed higher prices and faster LNG export
capacity additions. Such a scenario would affect the outlook for Middle East LNG export
Total global demand for natural gas differs significantly between the Reference case and
the High Economic Growth case. By 2050, global natural gas demand reaches 197 Tcf in the
Reference case and grows to about 240Tcf in the High Economic Growth case, almost a 22%
difference between cases. U.S. supply of natural gas increases 4% from the Reference
case to the High Economic Growth case in 2050. Given the lack of significant growth in
natural gas production from the United States and the limited growth from Russia, the
Middle East's role as a natural gas supplier increases significantly in the High
Economic Growth case.
As a result of the anticipated LNG export growth in the United States (as projected in
AEO2023), North America becomes the second-highest global natural gas exporter by 2050.
Because U.S. LNG exports are fixed to AEO2023 projections, U.S. growth is limited to the
early 2030s, and further global LNG demand across the projection period is supplied by
other regions. Although Canada increases natural gas production across all cases except
the Low Economic Growth case, it struggles to maintain a balance of net exports due to
rising domestic natural gas consumption in its electric power sector.
By 2050, U.S. natural gas net exports fall from almost 12 Tcf in the Reference case to 7
Tcf in the Low Oil Price case. Although global natural gas demand in the Low Oil Price
case is only marginally higher than in the Reference case, the Middle East increases net
exports from 21 Tcf in 2050 in the Reference case to 26 Tcf in the Low Oil Price case,
which offsets the decline in U.S. natural gas exports. Because the Middle East is a
lower-cost supplier than the United States, the region can supply a larger share of
global natural gas demand in a low-price environment.
Asia and Europe continue to import more natural gas
Across cases, the Asia-Pacific superregion—which includes China, India, Japan,
South Korea, and the Other Asia-Pacific region—will not be able to meet domestic
demand though domestic natural gas production. Due to the lack of natural gas reserves
and technically recoverable resources in this superregion, we project it is more
economical for these countries and regions to import natural gas, primarily as LNG
Most of this demand growth occurs in China, where natural gas consumption rises across
all sectors, particularly the electric power sector in later years. China's net
natural gas imports grow by almost 8 Tcf from 2022 to almost 14 Tcf in 2050 across most
cases, but its net natural gas imports reach 9 Tcf in the Low Economic Growth case and
29 Tcf in the High Economic Growth case by 2050. Although China has considerable shale
gas resources, it has been able to produce only a small fraction of these resources due
to difficult geography.9 We
assume that no technological breakthrough occurs to make these difficult-to-access
resources more cost effective, resulting in China's growing reliance on natural gas
imports throughout the projection period.
The Other Asia-Pacific region also drives the growth of natural gas import markets in
Asia. Due to growing domestic demand and declining production, the Other Asia-Pacific
region transitions from being a net exporter in 2022 to a net importer, with net imports
rising to over 3 Tcf of natural gas by 2050 across all cases except for the High Oil
India is also a significant source of natural gas import growth in the Asia-Pacific
superregion, increasing from 1.3 Tcf of net imports in 2022 to more than 4.0 Tcf in 2050
across all cases. India's natural gas demand grows significantly throughout the
projection period because of growth in the industrial sector. In the Reference case,
industrial natural gas consumption in India increases from 1.9 Tcf in 2022 to between
5.0 Tcf in the High Economic Growth case and almost 8.5 Tcf in the Low Economic Growth
case in 2050. Although India has significant natural gas reserves, most are offshore and
expensive to develop. We project India will continue to rely on imports to meet its
Both Japan and South Korea remain net natural gas importers, and total net import volumes
remain at or just below 2022 levels across all cases. Both countries have strong,
established demand markets, particularly in the industrial and electric power sectors.
They also have little domestic resources to draw from, resulting in limited to no
natural gas production throughout the projection period.
Outside of Asia, we project Western Europe will grow as an import market. Although slowed
by energy security considerations and decarbonization policies, Western European natural
gas demand across all sectors (including the electric power sector) increases about 12%
between 2022 and 2050 across all cases except for the Low and High Economic Growth
cases. In the High Economic Growth case, natural gas demand grows by 22%, and in the Low
Economic Growth case, it grows by less than 4%. We also expect steady natural gas
production declines due to depleted North Sea reserves and the closure of the Groningen
natural gas field in the Netherlands. The slow but increasing natural gas demand growth,
coupled with the region's decreasing natural gas production, increases Western
Europe's net natural gas imports by between 2.3 Tcf and 6.2 Tcf by 2050 across all
cases. Policy action is ongoing, and any updates or new policies in the future may
significantly affect Western Europe's LNG import projections.
OPEC, particularly in the Middle East, acts as a global swing producer
Global crude oil production expands to meet the increase in global demand across all
cases. The High and Low Oil Price cases explore the projected range of crude oil
production due to the uncertainty around world crude oil prices, a key model assumption.
Near- to mid-term production growth (2023–2035) is met by non-OPEC regions,
particularly in North and South America, across all cases except the Low Oil Price case.
Between 2022 and 2035, non-OPEC production rises from 49 million barrels per day (MMb/d)
to almost 55 MMb/d—Brazil and the Other Americas region produced over 6 MMb/d in
the Reference case. Canada oil sands production continues to grow through most of the
Near-term oil demand growth is met by non-OPEC regions, particularly North and South
America in most cases; OPEC regains its relative market share later in the projection
In the High Oil Price case, increased oil prices sustain the production of less
cost-efficient resources globally, and the share of global production from OPEC declines
in the short term. Total non-OPEC production reaches almost 62 MMb/d by 2030, led by
increases in U.S. production. Meanwhile, OPEC production continues to decrease through
2030 because OPEC uses its market power to maintain relatively high oil prices by
decreasing global supply. As other regions reach peak production, generally between 2030
and 2040, OPEC regains its share of the market in the High Oil Price case. Because OPEC
has relatively accessible resources and the ability to shift large volumes of production
to meet policy targets, our model assumes that OPEC plays the role of a global swing
producer. OPEC Middle East is given the most flexibility of all regions to significantly
raise and lower crude oil production from year to year. Non-OPEC regions will produce as
much domestic crude oil as economically possible and leave OPEC regions to contract or
expand production to meet global demand. In the Low Oil Price case, the OPEC regions
maintain stable production in the near term because many OPEC member countries have
cheaper access to resources that remain profitable at a lower price.
Technical Note 3: Refinery representation
The World Hydrocarbon Activity Module (WHAM) includes three major components:
Upstream natural gas and crude oil production
A logistics system to handle international trade of these commodities and
WHAM is a linear program that minimizes the cost of supplying every region in the
World Energy Projection System (WEPS) with the natural gas and liquid fuels demanded
by the other WEPS modules. Structurally, WHAM has three types of
regions—supply, refining, and demand—that are based on geography and
economic activity. Each country is assigned to a supply region, a refining region,
and a demand region..
WHAM receives petroleum product demand for every WHAM demand region and year, which
WHAM must meet with supply from its refineries. These refinery regions import crude
oil and natural gas from upstream supply regions. Oil refining is a complex process
that is bound by a molecular balance, and WHAM's representation includes many
intermediate and finished products.
Petroleum product supply within WEPS must meet demand each year because WHAM does not
model refined product storage. Modeling refineries comes with some trade-offs, given
their complexity. A more generalized approach that simplifies refineries to a few
key components and operations would reduce WHAM's run-time at the expense of
flexibility to perfectly balance supply and demand. Alternatively, a complex
representation that strictly models every refinery micro-decision would provide
greater flexibility to meet WEPS demand precisely and efficiently but add
significant run-time. To balance these trade-offs, WHAM represents oil refining
Countries are aggregated into refining regions based on geography. Countries with
large refining sectors—such as the United States—are represented as
single-country regions. Within a defined refining region, country-level refinery
capacity data are aggregated into a single representative regional
refinery—representing that region's total throughput. Each refining
region makes its own refining decisions by using WHAM's global logistics
representation to export products it makes that exceed domestic demand and to import
products required for the region. Because WHAM is formulated as a cost minimization
problem, production from the model's refining regions tends to consist of
products that are in high demand in close logistical proximity, representing the
most cost-efficient outcome.
WHAM allocates capacity utilization across a variety of refinery operation templates.
These templates are generated with the third-party Generalized Refining
Transportation Marketing Planning System (GRTMPS), which models a sample refinery
with varying crude oil slates and refinery configurations. These templates are
condensed into refinery yield options and passed into WHAM. Each refinery yield
contains information about a particular mode of refinery operations, including:
Crude oil consumption for all crude oil types
Natural gas and electric power consumption at refineries
Process unit capacity allocation
Each finished product's production
By allocating regional capacity across a variety of yields, refineries modeled in
WHAM shift global product production over time to meet a changing energy landscape.
You can find more information on WHAM and its refining model in our Component Design Report
and WHAM fact sheet
The changing fuel demand mix for petroleum products will drive a shift toward jet fuel
Refineries are currently configured primarily to meet gasoline and distillate demand and
cannot easily change the petroleum ratio of products they produce. In 2050, we project
that the transportation sector will account for at least 54% of total global liquid
fuels consumption across all cases, despite increased penetration of electric vehicles
(EVs) through the projection period. Therefore, this sector remains the main driver
behind refinery operations and the crude oil feedstocks needed to produce the volumes
and product shares of liquid fuels demanded. The High Economic Growth and Low Oil Price
cases are the only cases where motor gasoline demand rises significantly, starting at 47
quads in 2022 and increasing more than 12% by 2050. In the High Oil Price case, motor
gasoline demand is lowest, falling more than 17% by 2050 (Figure 34). Motor gasoline
demand rises about 2% by 2050 in the Reference case. Compared with gasoline demand, jet
fuel demand, rises consistently across all cases through 2050. In the High Economic
Growth case, jet fuel demand increases from 11 quadrillion British thermal units (quads)
in 2022 to 26 quads in 2050. Because we base projections on current policies, and
climate policy is rapidly changing, long-term refinery projections face significant
Subject to current policies and technology, we do not assume significant penetration of
sustainable aviation fuel in the projection period; therefore, refineries must adjust
production over time to meet a changing product slate where gasoline demand falls and
jet fuel continues to rise with global economic growth. This shift in focus results in a
transition from light crude oil to medium crude oil. Medium crude oil has a higher
concentration of distillates compared with lighter varieties (which have a higher
concentration of gasoline), allowing for refineries to adjust their jet fuel output via
a shift in crude oil consumption patterns. Technological breakthroughs for alternative
aviation fuel production could significantly affect the long-term preference of
refineries for each crude oil type.
Appendix A: Case descriptions
The Reference case models projections under assumptions that reflect current energy
trends and relationships, existing laws and regulations, and select economic and
The Reference case includes existing non-U.S. laws and regulations as of spring 2023, and
it reflects legislated energy sector policies that can be reasonably quantified in the
World Energy Projection System (WEPS). More information on our general approach to
modeling climate policies is available in our companion article, Climate Considerations in the International
Energy Outlook (IEO2023).
U.S. projections in IEO2023 reflect the published projections in the Annual Energy Outlook 2023 (AEO2023), which
assumes that U.S. laws and regulations, current as of November 2022, remain unchanged.
In the Reference case, we assume the world oil price in 2050 is $102 per barrel (2022
USD). Macroeconomic growth rate assumptions in our Reference case are listed by region
in Table 1.
Table 1. IEO2023 Reference case GDP growth rates by region
Reference case Average annual GDP
(purchasing power parity) percentage change, 2022–2050
Europe and Eurasia
Eastern Europe and Eurasia
Australia and New Zealand
Africa and Middle East
Data source: U.S. Energy Information
Administration, International Energy Outlook 2023 (IEO2023)
High and Low Economic Growth cases
The High Economic Growth and Low Economic Growth cases reflect the uncertainty in
projections of global economic growth. These cases show the effects of alternative
assumptions about economic growth that result in higher or lower growth relative to the
Reference case projection for different regions.
In the economic growth cases, we alter GDP growth rates of each region based on its GDP
per capita—measured in real 2015 purchasing power parity (PPP) adjusted U.S.
dollars (USD) per person. In IEO2023, we divide countries into two categories:
Low GDP per capita: less than or equal to $30,000 (2015 PPP USD) per person
High GDP per capita: greater than US $30,000 (2015 PPP USD) per person
In general, countries with lower GDP per capita exhibit more volatile business cycles and
vary more in long-term-trend growth rates. As a result, more uncertainty surrounds the
economic projections of low-income economies compared with high-income economies.
To reflect this uncertainty, the growth rate of countries classified as low GDP per
capita varies between approximately -1.0% in the Low Economic Growth case and +1.0% in
the High Economic Growth case, relative to the Reference case. The annual GDP growth
rate of countries classified as high GDP per capita varies less—between
approximately -0.5% in the Low Economic Growth case and +0.5% in the High Economic
Growth case, relative to the Reference case (Table 2).
Table 2. Macroeconomic growth rates in the IEO2023 Low Economic Growth, Reference, and
High Economic Growth cases, average annual GDP (measured in 2015 PPP USD) percentage
Table 2. Macroeconomic growth rates in the IEO2023 Low
Economic Growth, Reference, and High Economic Growth cases, average annual GDP (measured
in 2015 PPP USD) percentage change, 2022–2050
Low Economic Growth case
High Economic Growth case
Europe and Eurasia
Eastern Europe and Eurasia
Australia and New Zealand
Africa and Middle East
Data source: U.S. Energy Information
Administration, International Energy Outlook 2023 (IEO2023)
Note: PPP=purchasing power parity.
High and Low Oil Price cases
Different expectations about long-term future oil prices can significantly affect our
energy system projections. IEO2023 considers three cases (Reference, Low Oil Price, and
High Oil Price) to assess the impacts of alternative future paths of oil prices. We draw
the initial assumptions for the world crude oil price in IEO2023 from AEO2023, which
projects spot prices for North Sea Brent crude oil, an international standard for light,
sweet crude oil prices. In the Low Oil Price and High Oil Price cases, the high and low
prices of a wide range of potential price paths occur, illustrating uncertain and
potentially varied global demand for and supply of petroleum and other liquid fuels.
The Low Oil Price case assumes that all crude oil resources are extracted with more
cost-efficient methods due to technology or policy drivers, thereby lowering the price.
The High Oil Price case assumes the opposite, in which higher extraction costs and
policy result in higher prices for all crude oil resources. U.S. crude oil consumption
and production match the respective Low and High Oil Price and Reference cases in
AEO2023, where U.S. liquid fuels production and consumption respond only to changes in
Input prices to WEPS are listed in Table 3, and the full input price paths are in our
Table 3. IEO2023 Brent oil prices in selected years in the
High Oil Price, Reference, and Low Oil Price cases (2022 USD per barrel)
High Oil Price case
Low Oil Price case
Data source: U.S. Energy Information
Administration, International Energy Outlook 2023 (IEO2023)
High and Low Zero-Carbon Technology Cost cases
The share of electricity generation from renewable sources has been increasing
significantly in many parts of the world in recent years, due in part to rapid cost
declines. Capital costs of renewables over the past 20 years suggest significant
uncertainty and variability in the rate of decline. For example, between 2000 and 2010,
wind technology costs in the United States increased; in the following decade, they
decreased by a similar amount before increasing again in recent years. Although the
decline in solar technology cost has been more directionally consistent, the rate of
decline has varied significantly during this period. Uncertainty in nuclear technology
costs also plays a role in the future development of nuclear as a zero-carbon
The International Electricity Market Module (IEMM) in the WEPS assumes capital costs for
each technology in the Reference case decline annually through the projection period.
This decline is the result of experience-based cost reductions from factors such as
learning-by-doing and manufacturing scale, government-funded research and development
(R&D), and changes in the cost of commodities.
To address this uncertainty, we examine the impact of the capital cost assumptions that,
in turn, determine relative economic competitiveness among generating technologies. The
High Zero-Carbon Technology Cost case assumes no cost reduction from learning-by-doing
and holds capital costs constant at the 2022 level throughout the projection period for
zero-carbon electric-power generating technologies, which include solar, wind, battery
storage, and nuclear. The Low Zero-Carbon Technology Cost case assumes a more rapid
capital cost decline compared with the Reference case, achieving capital costs that are
40% lower by 2050 for these zero-carbon technologies. In the Reference case, potential
nuclear additions and retirements are largely constrained based on noneconomic
factors—geopolitical considerations such as nonproliferation agreements, energy
security, and government regulations, among others. For the Low Zero-Carbon Technology
Cost case, in addition to the lower costs described above, we eased these noneconomic
constraints to explore the economic effects on nuclear builds.
In February 2022, Russia's full-scale invasion of Ukraine introduced significant
geopolitical upheaval that had immediate and future impacts. Although some impacts have
already occurred, significant uncertainty surrounding long-term effects remains. In our
detailed energy system model (the World Energy Projection System [WEPS]), we make
assumptions about these events. In the section below, we discuss the assumptions that we
made for IEO2023, which are held constant across all cases. By making fixed parameter
assumptions rather than examining a range, our modeling assumptions understate the
uncertainty in the range of potential outcomes.
Russia's full-scale invasion of Ukraine has affected energy markets worldwide. For
example, Russia was a significant natural gas supplier to markets throughout the world,
particularly to Europe. In response to the invasion, some of Russia's trade
partners placed sanctions on Russia's exports, and other market participants have
changed their trade preferences. These changes will continue to have impacts, but their
duration and extent are uncertain. For IEO2023, we make consistent assumptions on the
length and extent of these impacts on energy markets. Regardless of when the conflict
ends, we assume the geopolitical ramifications, to the degree described below, will
persist through 2050, the IEO2023 projection period. Implicitly, this assumes the end of
the invasion will not reset relationships within energy markets.
This appendix is a comprehensive list of all relevant modeling assumptions specific to
each WEPS module, but it may not include all global responses to the invasion. Although
we did not vary these assumptions across cases, changing these assumptions would yield
different projections. For example, assuming a more restricted natural gas supply might
lead to higher natural gas prices and, consequently, lower natural gas consumption (or
vice versa)—underscoring the importance of our modeling assumptions.
The macroeconomic projections we used came from the Oxford Economics Global Economic
Model and Global Industry Model as of February 1, 2023. These projections include a
post-invasion recovery (around 2030) that captures impacts in Russia, Ukraine, and
Europe, as well as related effects on the rest of the world, including:
Changes in demand for goods and services in Europe and elsewhere
Changes in non-energy trade flows to reflect Oxford Economics economic data and
Legislated subsidies in various countries, including assumptions on availability of
subsidies into the future as reflected in Oxford Economics' economic data and
Legislated sanctions targeting Russia implemented in 2022 that remain in place as of
February 1, 2023, assuming sanctions remain in place without end dates and no new
sanctions are implemented
Russia's efforts to lessen the economic impact of sanctions and policies,
including concealing crude oil trade flows, using multiple trade partners to avoid
sanctions, and identifying new purchasers for its exports
We also assume Nord Stream will remain offline through 2050, as further discussed in the
oil and natural gas section, and the Zaporizhzhya nuclear plant will resume operations
beginning in 2030, as further discussed in the electricity section.
These bullets are broad categorizations of the analysis included inside the Oxford
Economics models and databases. Additional detail is available to subscribers of their
services or by requesting more information from us.
We made assumptions based on REPowerEU, which is a European Commission proposal to end
reliance on Russia's fossil fuels before 2030. Russia's full-scale invasion of
Ukraine has prompted the EU to move forward with more urgency on the existing energy and
climate policy goals in place. In May 2022, under the REPowerEU
plan, the European Commission proposed an increase to the binding EU energy
efficiency target from 9% to 13% by 2023 (relative to 2020). In July 2022, EU member
to reduce their natural gas consumption by 15% through March 2023.
We account for demand-side measures that EU countries implemented to curb natural gas
consumption and reduce natural gas imports from Russia. We modeled Western Europe's
attempts to curb demand for natural gas in homes and commercial buildings throughout the
winter of 2022 by applying higher sensitivity to price increases than in previous years.
We considered policies and public calls to reduce natural gas consumption in
buildings—such as new rules in Germany affecting energy consumption in public
buildings and similar
measures in France. We assume that non-price considerations will reduce
consumers' willingness to pay for natural gas. We also expect homeowners and
commercial building operators will generally be more sensitive to increases in the
natural gas price than they have been historically. As a result, growth in natural gas
demand slows in buildings, and we project electricity consumption to grow faster than
WEPS modules do not explicitly account for national- or sub-national subsidies for
purchasing energy or heat across the end-use sectors.
As with the buildings sector, we made assumptions based on REPowerEU in the industrial
sector. Energy-efficiency goals were part of Europe's
pre-invasion climate goals, and we assume the invasion of Ukraine will spur
structural shifts that will lower Europe's long-term natural gas demand. To model
this, we increased industrial natural gas demand elasticities for several European
industries that have the technical potential to increase energy efficiency with respect
to natural gas consumption. We adjusted food, paper, non-metallic minerals, and many
non-energy intensive industries that use boilers and low-temperature process heat, such
as other metal-based durables, motor vehicles, and industrial other, the catch-all for
The RePowerEU plan revises the target for the share of renewables used to generate heat
in centralized district energy plants to 45% of heat generation by 2030. Centralized
district energy plants distribute heat and steam to meet demand for space heating, water
heating, and process heat in the buildings and industrial sectors. Increasing the use of
renewables for heat generation in Western Europe displaces some natural gas and coal as
a heat generation source.
We made assumptions in the Eastern Europe and Eurasia modeling region (including Ukraine
and 10 other countries)11
regarding when and how quickly the two Ukrainian nuclear power plants located in
military conflict zones—Zaporizhzhya Nuclear Power Plant and South
Zaporizhzhya Nuclear Power Plant: ramp up from cold shutdown, beginning in 2030 to
100% by 2034
South Ukraine: generation remains at 70% of total plant capacity over
2022—2029 and increases to 100% by 2030
Crude oil and natural gas production and trade
We made assumptions specific to oil and natural gas production and trade for IEO2023,
Russia's crude oil and petroleum liquids exports directly to the United States
and Western Europe are suspended, beginning in 2023 and lasting through 2050
The Nord Stream natural gas pipelines remain offline through 2050
We assume zero net export growth of Russia's natural gas. EU sanctions prohibit
supplying Russia with the goods and technology suited for liquefying natural gas.
Without access to Western company technology and replacement equipment, Russia's
current liquefied natural gas (LNG) projects may struggle to be completed on time, and
future projects will face significant barriers. Our model does not currently model LNG
at the project level and does determine the expected completion of projects under
Coal production and trade
We made two sets of time period-specific assumptions for coal production and trade.
Across both periods, Ukraine no longer imports coal from Russia.
From 2023 to 2028:
We decreased trade between Japan and Russia. During this period, total trade of
steam and metallurgical coal will decrease to nearly zero, but Japan will continue
purchasing a small amount under previous contracts.
We decreased trade between Western Europe and Russia, not including Türkiye.
During this period, we assume that coal trade will occur between only Russia and
For 2029 and later:
Japan and Türkiye return to pre-invasion coal trade activity with Russia.
Western Europe, excluding Türkiye, seeks to reduce coal imports from Russia
relative to imports before the invasion. Within the model, we allow Western Europe,
excluding Türkiye, to import up to about two-thirds of pre-2022 imports.
Appendix C: New modeling regions
Regions have changed in IEO2023
For the International Energy Outlook 2023 (IEO2023), we are introducing new
regional groupings for countries in the World Energy Projection System
(WEPS). Previously, our publication regions were defined
primarily by Organisation for Economic Cooperation and Development (OECD) designation
and secondarily by geography. We based the new regional groupings solely on geography. A
map of our new 16 regions and a table of the countries assigned to each region are in
The previous regions were partially based on organizational membership
We have used OECD membership as a partial basis for WEPS publication regions since 2006,
when we determined that OECD membership was a reasonable proxy for economic development,
and economic development was a reasonable grouping for modeling regions. In IEO2021 we
used 16 regions based on geography and OECD membership, and we combined these regions
into two larger groupings: OECD and non-OECD.
Many WEPS modules use higher geographic resolution internally but aggregate to 16 regions
for communication with the greater WEPS system and for the IEO publication. You can find
more details on module regionality in the model documentation.
Dividing the world economically is complicated
In recent years, OECD and non-OECD are no longer simple proxies for economic development.
For example, China does not belong to the OECD but had the second-largest economy in the
world in 2022. Several countries—with smaller economies than China—have
joined the OECD in the past decade, such as Latvia (in 2016); Colombia (in 2020); and
most recently, Costa Rica (in 2021). Using the OECD designation led to geographically
noncontiguous regions, such as the WEPS region that combined Mexico and Chile.
In peer publications, many organizations use regions largely based on geographies in
their models, although they may use economic indicators for reporting.
The new regions are largely based on proximity
IEO2023 uses four superregions—larger regional groupings:
Europe and Eurasia
Africa and the Middle East
Within those superregions, the new IEO publication regionality breaks out certain
countries into independent regions. The United States, Canada, Brazil, Mexico, Russia,
China, India, Japan, and South Korea make up 9 of the 16 WEPS regions. The remaining
seven regions are aggregate regions with two or more component countries in each (Figure
35 and Table 4).
We plan to continue to evaluate and take comments on additional
publication regions, particularly in Africa and the Asia-Pacific.
Table 4. IEO2023 country-region assignments
IEO2023 WEPS region
Central African Republic
Saint Helena, Ascension and Tristan da Cunha
Sao Tome and Principe
Tanzania, United Republic of
Australia and New Zealand
Australia and New Zealand
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Moldova, Republic of
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Eastern Europe and Eurasia
Palestine, State of
Syrian Arab Republic
United Arab Emirates
Antigua and Barbuda
Saint Kitts and Nevis
Saint Pierre and Miquelon
Saint Vincent and the Grenadines
St. Kitts and Nevis
St. Vincent and the Grenadines
Trinidad and Tobago
Turks and Caicos Islands
Venezuela, Bolivarian Republic of
Virgin Islands, British
Virgin Islands, U.S.
Korea, Democratic People's Republic of
Micronesia, Federated States of
Northern Mariana Islands
Papua New Guinea
Taiwan, Province of China
Korea, Republic of
United States of America
Bosnia and Herzegovina
Macedonia, the former Yugoslav Republic of
Data source: U.S. Energy Information Administration,
International Energy Outlook 2023 (IEO2023) Note:
WEPS=World Energy Projection System
The Other Asia-Pacific region is an aggregation of 41 countries, including
Indonesia, Thailand, Vietnam, and Malaysia. Full regional definitions used in the
International Energy Outlook 2023 appear in Appendix C.
In 2023, we began changing our
accounting for renewable energy—the way we convert kilowatthours
generated from renewable energy to British thermal units—to change the basis
for our conversion from fossil fuel equivalency to captured energy. In IEO2023,
electricity generation from renewable sources (such as hydroelectric, wind, or
solar) is converted using our original fossil fuel equivalency approach. The
renewable generation is converted to British thermal units at a rate of 8,124
British thermal units per kilowatthour, which reflects the average projected
conversion efficiency of the U.S. fossil-fuel fired electric-generating fleet in the
Annual Energy Outlook 2021 over the projection period (2022–2050). We
will be reporting electricity generation from renewable sources using the captured
energy approach in future editions of the IEO.
When quantifying energy-related CO2 emissions, we only tally those generated when
the energy is used. This measure does not include emissions associated with
producing the energy—such as methane leaks for flaring.
Kaya, Y., 1990: Impact of Carbon Dioxide Emission Control on GNP Growth:
Interpretation of Proposed Scenarios. Paper presented to the IPCC Energy
and Industry Subgroup, Response Strategies Working Group, Paris.
Aguiar, Mark, and Gita Gopinath. “Emerging Market Business Cycles: The Cycle Is the
Trend.” Journal of Political Economy, vol. 115, no. 1, 2007, pp. 69–102.
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