Category: US Energy Information Administration

Source: US Energy Information Administration

In-brief analysis

June 23, 2026

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On April 28, 2026, the United Arab Emirates (UAE) announced that it was leaving OPEC, effective on May 1. OPEC was formed in 1960 by Iraq, Iran, Kuwait, Saudi Arabia, and Venezuela, with the stated objective to “coordinate and unify petroleum policies among Member Countries.” OPEC is best known for its effect on global crude oil prices.

The UAE joined OPEC as the emirate of Abu Dhabi in 1967 and as of 2025 held the third-largest crude oil production capacity in the group behind Saudi Arabia and Iraq. The UAE produced an average of 3.4 million b/d of crude oil and held an estimated 4.2 million b/d of effective production capacity in 2025. This was all before the onset of the conflict in Iran on February 28, 2026 and the effective closure of the Strait of Hormuz, which has lowered production levels in the region and significantly impacted oil markets.

OPEC (including the UAE) produced an estimated 28.0 million b/d of crude oil in 2025, 35% of total world crude oil production that year. Without the UAE’s contribution, the group’s share of world total crude oil production would have been 31% in 2025. The largest producer and most influential member of OPEC is Saudi Arabia, which was the world’s second-largest oil producer in 2025 (9.3 million b/d), after the United States, and held an estimated 11.6 million b/d of effective production capacity in 2025.

The larger OPEC+ group (also known as the Declaration of Cooperation) was formed in 2016 largely in response to dramatically falling oil prices driven by significant increases in U.S. shale oil output. OPEC+ meetings and coordinated production targets still influence global oil prices, and market participants closely follow them. Beginning in April 2023, several OPEC+ producers agreed to numerous rounds of voluntary cuts to crude oil production “aimed at supporting the stability of the oil market.” The UAE and Saudi Arabia made among the largest voluntary cuts to crude oil production as part of those agreements, at a time when the UAE’s production capacity increased.

Production from OPEC+ countries made up about 46% of global crude oil production in 2025; without the UAE, the OPEC+ portion would have been closer to 42%. More recent production agreements have exempted Iran, Venezuela, and Libya.

Since the closure of the Strait of Hormuz, the UAE and Saudi Arabia were the only regional OPEC countries able to reroute crude oil exports around the Strait of Hormuz. The UAE redirected oil exports via the Abu Dhabi Crude Oil Pipeline (ADCOP) to the port of Fujairah in the Gulf of Oman just outside of the Strait. The pipeline currently has a maximum capacity of 1.8 million b/d, and the UAE recently announced that it intends to double the pipeline’s capacity by 2027. Similarly, Saudi Arabia rerouted crude oil exports to the Red Sea via its 7 million-b/d East-West pipeline to the port of Yanbu on the Red Sea, with 5 million b/d of that capacity available for exports and the rest for domestic consumption.

Due to these investments, Saudi Arabia and the UAE have seen lower relative volumes of shut-in crude oil production compared with other Middle Eastern producers reliant on the Strait of Hormuz to reach global oil markets.

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While OPEC+ meetings continue to focus on setting crude oil production targets based on their assessments of global oil balances, the de facto closure of the Strait of Hormuz limited their ability to increase production levels.

Principal contributor: Sean Hill

Source: US Energy Information Administration

In-brief analysis

June 18, 2026

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The Permian region’s marketed natural gas production grew from 17.2 billion cubic feet per day (Bcf/d) in 2021 to 27.6 Bcf/d in 2025, a 60% increase, according to data from our latest Short Term Energy Outlook. Over the same period, crude oil production grew by 39%, going from 4.7 million barrels per day (b/d) to 6.6 million b/d. The higher growth in natural gas production is the result of increasing gas-oil ratios (GOR).

As more oil and natural gas are produced, pressure within the reservoir declines; natural gas is easier to produce at lower pressures and the GOR increases.

The GOR in the Permian region has steadily increased over the past five years. In 2025, the GOR averaged nearly 4,200 cubic feet of natural gas per barrel of oil (cf/b), a 16% increase from 2021. As the region matures, we expect the GOR to continue to increase. As the GOR rises, we estimate that the production growth rate of natural gas will continue to exceed the growth rate of crude oil in the Permian region.

In 2021, the Permian produced 17.3 Bcf/d of natural gas and 4.7 million b/d of crude oil, and the GOR averaged 3,628 cf/b. If the GOR had remained the same as in 2021, the Permian region would have produced only 23.8 Bcf/d of natural gas in 2025, 14% less than actual production that year. The extra 3.8 Bcf/d of gas in 2025 comes because of this higher GOR.

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Principal contributors: Naser Ameen, Troy Cook

Source: US Energy Information Administration

In-brief analysis

June 16, 2026

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In the first five months of 2026, utility-scale solar generation surpassed natural gas generation in CAISO. Solar electricity generation in the California Independent System Operator (CAISO) over the first five months of 2026 increased 21% compared with the same period in 2024, and natural gas generation decreased by 60%, data from our Hourly Electric Grid Monitor shows.

In CAISO, utility-scale solar generated more electricity than natural gas on a daily basis on 82% of days in the first five months of 2026, up from 21% in 2024 and 2025.

Both solar generating capacity and battery storage capacity have grown in CAISO over the past two years while natural gas generation capacity has remained flat, according to our Preliminary Monthly Electric Generator Inventory. From April 2024 to April 2026, utility-scale solar capacity increased 19% to 25 gigawatts (GW), and net battery storage capacity increased 79% to 16 GW. Natural gas capacity remained nearly unchanged at 29 GW. Total net capacity increased by 14% (11 GW) over this period.

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Battery storage, often co-located with solar, charges when solar generation exceeds grid needs in the middle of the day and contributes power to the grid during the evening and early morning when there is less sun. In the first five months of 2026, battery storage discharge tripled compared with the same period in 2024. Despite increasing generation from solar and batteries and a 7% increase in demand over this time period, there was a 19% decrease in net generation as electricity imports from nearby systems doubled in CAISO. The increase in imports was driven by relatively inexpensive electricity generation coming online and available for import. Hydroelectric power imports from the Pacific Northwest increased as the drought there subsided, and CAISO began importing from the new SunZia wind project in New Mexico starting April of this year. In addition, generator retirements in CAISO between May 2024 and May 2025 totaled 555 MW and included a 300 MW battery installation that caught fire in January of 2025.

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Principal contributors: Kimberly Peterson, Katherine Antonio, Lori Aniti

Source: US Energy Information Administration

In-brief analysis

June 12, 2026

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The SunZia Wind Project, the largest wind farm in the United States, began commercial operations this month. The wind farm, located in New Mexico, has a total net summer generating capacity of 3,650 megawatts (MW) and is composed of 916 wind turbines. SunZia’s capacity is more than three times larger than the next two largest wind farms, Alta Wind in Southern California (1,098 MW) and Great Prairie in northern Texas (1,027 MW). The SunZia Wind Project works with a high voltage transmission line to deliver the wind power generated to Arizona and California.

Pattern Energy started construction of the SunZia Wind Project in 2023, after almost two decades of permitting and planning. The wind farm spans three counties. The northern part of SunZia located in San Miguel and Lincoln counties has 242 turbines, while the southern part in Lincoln and Torrance counties has 674 turbines. By April 2026, some of the wind turbines were producing power and contributing to the grid during a testing phase.

Before the SunZia Wind Project came online, net summer wind generating capacity in New Mexico totaled 3,997 MW. The new capacity from SunZia will bring total wind capacity in New Mexico up to 7,647 MW. With this addition, wind accounts for 45% of the capacity mix in the state, followed by 19% from solar and 19% from natural gas capacity.

Most of the electricity generated at SunZia will be exported to Arizona and to Southern California. To be able to export the power generated by this project, Pattern Energy also built the SunZia Transmission Project—a 550-mile high voltage direct current transmission line that goes from the SunZia Wind Project site in central New Mexico to south-central Arizona. Of the SunZia transmission line’s 3,021 MW of power capacity, 2,131 MW will be delivered and consumed in Southern California via the Palo Verde Substation.

Generation from the SunZia Wind Project is reported by the California Independent System Operator (CAISO) in EIA’s Hourly Electric Grid Monitor. On May 15, 2026, CAISO reported 7,122 MW of hourly wind generation, which is 20% higher than the previous annual record of 5,922 MW in 2024.

Principal contributors: Tyler Hodge, Lindsay Aramayo

Source: US Energy Information Administration

In-brief analysis

June 10, 2026

Data source: Bloomberg L.P. and the U.S. Bureau of Labor Statistics
Note: RIN=renewable identification number; real prices are adjusted to May 2026 dollars.

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Compliance credits for biomass-based diesel and ethanol have doubled in value since the start of this year. The credits, known as renewable identification numbers (RINs), have increased in price, mostly because of higher U.S. biofuel blending targets. The combination of high RIN prices and rising motor gasoline and diesel fuel prices has created an especially favorable market for producing and blending biofuels.

RINs are credits generated when biofuels are produced or imported and are used to comply with the Renewable Fuel Standard (RFS) program. Under the RFS, the U.S. Environmental Protection Agency (EPA) sets annual renewable volume obligations (RVOs) for the minimum volume of biofuels that must enter the U.S. fuel supply. Obligated parties—petroleum refiners and motor gasoline and diesel importers—comply either by blending biofuels into petroleum-based fuels or by purchasing RIN credits.

As of June 4, biomass-based diesel (D4) RINs traded at $2.41 and ethanol (D6) RINs traded at $2.37, both close to their all-time highs set in 2021. Because one gallon (gal) generates 1.5 RINs for biodiesel and 1.6 RINs to 1.7 RINs for renewable diesel, these fuels currently generate more than $3.50/gal of credits. A gallon of fuel ethanol generates 1.0 credit.

RIN prices increased in 2026 primarily because of higher blending mandates. On March 27, the EPA announced the final RFS rule for 2026 and 2027, establishing significantly higher RVOs than in 2025. RIN prices increase with high RVOs to reflect the higher profit margins biofuel producers need as incentive to produce enough fuel to meet mandates.

Higher prices for petroleum products make fuel ethanol relatively more attractive to blend into gasoline. Relative to motor gasoline prices, the U.S. Gulf Coast fuel ethanol price, adjusted for energy equivalence, has been lower most days since mid-March. The higher RIN value that blenders using ethanol can then sell on the open market to companies that need to remain in compliance also incentivizes more blending into gasoline. The fuel ethanol discount to gasoline has been more than $2/gal in May and June when adding in the higher RIN value.

Data source: Bloomberg L.P.
Note: RIN=renewable identification number; the ethanol discount to gasoline is calculated as (2/3 * Gulf Coast spot gasoline price) – (U.S. Gulf Coast spot ethanol price – D6 RIN price). The gasoline price is multiplied by 2/3 to equate it to ethanol’s energy content.

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High RIN values have also supported production and blending margins for biodiesel and renewable diesel. The difference between soybean oil and heating oil prices, the Bean Oil-Heating Oil (BOHO) spread, reflects the profitability of blending biodiesel and renewable diesel without incentives. Typically, RIN prices move with the BOHO spread to maintain margins. However, when RIN values increase relative to the BOHO spread, as they have done in 2026, profit margins for producing biodiesel and renewable diesel generally improve. The rapid increase in RIN values relative to the BOHO spread in 2026 suggests that the new RVOs are a significant driver of increased RIN values and that biodiesel and renewable diesel production margins are much higher than in 2025.

Data source: Bloomberg L.P.
Note: RIN=renewable identification number; the Bean-Oil Heating-Oil (BOHO) spread is calculated using front-month futures prices of soybean oil and heating oil. The biomass-based diesel (D4) RIN value is based on the RIN value times 1.6. Changes in federal tax credits and state credit values are also among factors that affect biomass-based diesel margins.

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We forecast record-high production of fuel ethanol and renewable diesel in 2026 because of high blend mandates, high gasoline and diesel prices, and increasing production capacity at biofuel plants. Biodiesel production also increases, although we have it remaining below record highs because of lost production capacity. Fuel ethanol production increases by 2% in 2026, with the fuel ethanol share of motor gasoline consumption at 10.7%, compared with 10.5% in 2025. Renewable diesel production increases 24% and biodiesel production increases 41% in 2026, compared with 2025. We forecast production of all three fuels to increase further in 2027, when the RVO increases further.

Principal contributor: Jimmy Troderman

Source: US Energy Information Administration

In-brief analysis

June 8, 2026

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Weekly estimates suggest U.S. jet fuel production has increased to record highs in response to elevated jet fuel prices after the Strait of Hormuz closed on February 28. Higher crude oil prices and supply concerns, particularly in Europe and Asia, which previously imported much of their jet fuel supply from the Persian Gulf, have driven up jet fuel prices. Much of the increased U.S. jet fuel production is being exported, as domestic inventories remain above average.

U.S. jet fuel production has increased since February 28 when the four-week average production was 1.7 million barrels per day (b/d). In the week ending May 1, the four-week average estimate of U.S. jet fuel production surpassed 2.0 million b/d for the first time on record. The increased production reflects both above-average refinery runs and strategic shifts to increase jet fuel yields.

U.S. refiners have been maximizing jet fuel production to take advantage of high jet fuel prices and margins. From March through May, U.S. Gulf Coast Jet Fuel Spot prices averaged $3.91 per gallon (gal), about double the price at the start of the year and higher than the regional spot prices for both gasoline and diesel fuel. The jet fuel crack spread on the U.S. Gulf Coast, an indicator of the profitability of refining crude oil into jet fuel in the region, averaged $1.25/gal in the same period, up from $0.42/gal at the start of the year. Jet fuel prices at other major global trading hubs—such as Amsterdam, Rotterdam, Antwerp (ARA) and Singapore—also averaged about double their start-of-year prices from March to May and had higher jet fuel crack spreads.

Jet fuel prices in Europe and Asia traded at significant premiums to the U.S. Gulf Coast in March and April, attracting sources to replace imports from the Middle East. In response to the price increases abroad, weekly estimates based on transactional trade data from U.S. Customs and Border Protection indicate U.S. jet fuel exports reached record highs in April and May. Jet fuel prices in Europe and Asia are now closer to U.S. Gulf Coast prices, and prices are lower than their April peaks in all three regions as concerns of an imminent jet fuel shortage have eased.

Data source: Bloomberg L.P.

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Despite increased export demand, jet fuel inventories in the United States have remained above average. U.S. jet fuel inventories as of May 29 totaled 45 million barrels, 7% above the 2021–2025 average. Inventories in the U.S. West Coast, the U.S. region that relies most heavily on jet fuel imports, also remain above average. However, if the recent decline in imports to the West Coast continues, the region may need to increase draws from inventories.

Principal contributors: Jimmy Troderman, Kimberly Peterson

Source: US Energy Information Administration

The survey Form EIA-860 collects generator-level specific information about existing and planned generators and associated environmental equipment at electric power plants with 1 megawatt or greater of combined nameplate capacity. Summary level data can be found in the Electric Power Annual.

Starting with 2013 data, the EIA-860 began collecting construction cost data for new electric generators. Aggregated average construction cost information can be found on the Construction cost data for electric generators page.

Detailed data are compressed (zip) and contain the following files:

• LayoutYyyyy — Provides a directory of all (published) data elements collected on the Form EIA-860 together with the related description, specific file location(s), and, where appropriate, an explanation of codes.
• 1___UtilityYyyyy — Contains utility-level data for the plants and generators surveyed in the reporting year.
• 2___PlantYyyyy — Contains plant-level data for the generators surveyed in all available years.
• 3_1_GeneratorYyyyy — Contains generator-level data for the surveyed generators, split into three tabs.
• • The Operable tab includes those generators which are currently operating, out of service or on standby;
  • The Proposed tab includes those generators which are planned and not yet in operation; and
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
  • The retired tab only includes those retired generators which were reported in the most current data cycle. This is not a comprehensive list. Starting with March 2017 data, Preliminary Monthly Electric Generator Inventory includes a comprehensive list of generators which retired since 2002. The list can be found on the Retired tab of the data file.
• 3_2_WindYyyyy — Contains additional details for surveyed generators that use wind as an energy source, split into two tabs:
• • The Operable tab includes those generators which are currently operating, out of service or on standby; and
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_3_SolarYyyyy — Contains additional details for surveyed generators that use solar as an energy source, split into two tabs:
• • The Operable tab includes those generators which are currently operating, out of service or on standby;
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_4_Energy_StorageYyyyy — Contains additional details of surveyed generators for the energy storage technology, split into two tabs:
• • The Operable tab includes those generators which are currently operating, out of service or on standby;
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 3_5_MultiFuelYyyyy — Contains data on fuel-switching and the use of multiple fuels by surveyed generators, split into three tabs:
• • The Operable tab includes those generators which are currently operating, out of service or on standby; and
  • The Proposed tab includes those generators which are planned and not yet in operation; and
  • The Retired and Canceled tab includes those generators which were cancelled prior to completion and operation and retired generators at existing plants.
• 4___OwnerYyyyy — Contains owner and/or operator data for generators with shared ownership and generators that are wholly-owned by an entity other than the operator (generators not appearing in the file are wholly-owned by their operator).
• 6_1_EnviroAssocYyyyy — Contains boiler association data for the environmental equipment data collected on the Form EIA-860.
• • The Boiler Generator identifies which boilers are associated with each generator;
  • The Boiler Cooling tab shows which cooling systems are associated with each boiler;
  • The Boiler Particulate Matter tab shows which flue gas particulate (FGP) collectors are associated with each boiler;
  • The Boiler SO2 tab shows which flue gas desulfurization (FGD) systems are associated with each boiler
  • The Boiler NOx tab shows which nitrogen oxide control equipment is associated with each boiler;
  • The Boiler Mercury tab shows which mercury control equipment is associated with each boiler
  • The Boiler Stack Flue tab shows which stacks and flues are associated with each boiler; and
  • The Emissions Control Equipment tab shows the operational status, in-service date, and installation costs of all the environmental equipment.
• 6_2_EnviroEquipYyyyy — Contains environmental equipment data for the surveyed generators.
• • The Emission Standards & Strategies tab shows boiler data as collected on Schedule 6, Part B of the Form EIA-860;
  • The Boiler Info & Design Parameters tab shows boiler data as collected on Schedule 6, Part C;
  • The Cooling tab shows cooling system data as collected on Schedule 6, Part D;
  • The FGP tab shows FGP data as collected on Schedule 6, Part E;
  • The FGD tab shows FGD data as collected on Schedule 6, Part F; and
  • The StackFlue tab shows stack and flue data as collected on Schedule 6, Part G.
• Superseded Form EIA-860A (Utility) & B (Non-Utility) — Retired Annual Electric Generator Report
• Electric utility generator level data includes information for company, facility, unit type, prime mover, in-service date, energy source, heat content, nameplate capacity, summer and winter capability, etc.
• 860-A (Utility)
  Data are compressed into a zip file that expands into xls data files and a txt layout file:
• • PLANTYyy — plant-level data
  • UTILYyy — utility-level data
  • TYPE3Yyy & TYPE4Yyy — 2 generator files for 1990-1997
    or GeneratorOwnershipyyyy, ProposedGeneratorsyyyy, ExistingGeneratorsyyyy — 3 generator files for 1998-2000
  • LAYOUT — ASCII layout file
• 860-B (Non-Utility)
  Data are compressed into a zip file that expands into xls data files and a txt layout file:
• • qfdocket — qualifying data
  • xdocket — plant-level data
  • cogen — cogeneration data
  • nuppfac — non-utility power producer data
  • fuelquant — fuel quantities
  • genergy — 2 generator files
  • noxequip — nox removal data
  • LAYOUT — ASCII layout file

Source: US Energy Information Administration

U.S. ENERGY INFORMATION ADMINISTRATION
WASHINGTON DC 20585

FOR IMMEDIATE RELEASE
June 9, 2026

The U.S. Energy Information Administration published its June Short-Term Energy Outlook (STEO), reducing its expectation for global oil demand in 2026. High fuel prices, reduced fuel availability, and government initiatives are curbing oil consumption this year, particularly in Asia, resulting in the world consuming 1 million fewer barrels of oil each day on average than it did last year. The reduced demand could limit crude oil price increases resulting from near-term disruptions in the flow of oil out of the Middle East through the Strait of Hormuz.

“Any scenario involving full restoration of inventories, production, and trade flows to pre-conflict levels must account for the partial restructuring of the global oil market that has already occurred,” EIA Administrator Tristan Abbey said.

Key takeaways from the June STEO are below.

U.S. energy market indicators	2025	2026	2027
Brent crude oil spot price (dollars per barrel)	$69	$95	$79
Retail gasoline price (dollars per gallon)	$3.10	$3.90	$3.64
U.S. crude oil production (million barrels per day)	13.6	13.7	14.2
Natural gas price at Henry Hub (dollars per million British thermal units)	$3.53	$3.60	$3.46
U.S. liquefied natural gas gross exports (billion cubic feet per day)	15	17	19
Shares of U.S. electricity generation
Natural gas	40%	40%	40%
Coal	17%	16%	15%
Nuclear	18%	18%	18%
Conventional hydropower	6%	6%	6%
Wind	11%	11%	12%
Solar	7%	8%	9%
Other energy sources	1%	1%	1%
U.S. GDP (percentage change)	2.1%	2.0%	1.7%
U.S. CO2 emissions (billion metric tons)	4.9	4.8	4.8
Data source: U.S. Energy Information Administration, Short-Term Energy Outlook, June 2026 Note: Values in this table are rounded and may not match values in other tables in this report.

• Global oil markets. With the Strait of Hormuz remaining effectively closed in the near term, disruptions to global oil production and shipments continue. Middle Eastern oil producers have cut output by over 11 million barrels per day (b/d), leading to large global inventory draws that average 6.3 million b/d in 2Q26 and 7.6 million b/d in 3Q26. As a result, oil inventories in OECD countries are the lowest since 2003. Global oil demand in 2026 falls by 1.1 million b/d compared with last year but is expected to increase by 2.5 million b/d in 2027, as oil prices decline and oil production in the Middle East gradually rises.

• Crude oil price forecast. Crude oil spot prices dropped in May on reports of an agreement between the United States and Iran and falling oil demand. However, the Brent price averages $105 per barrel (b) in June and July, as oil shipments remain limited and oil production and inventories fall. We expect prices to average $79/b in 2027 when supply flows and oil production resume.

• U.S. petroleum trade. Disruptions to crude oil and refined product flows through the Strait of Hormuz have led to increased demand for U.S. supply, pushing U.S. crude oil and petroleum product net exports in April to a record 5.8 million b/d, with May net exports staying close to that level. The increase in exports has been most pronounced for diesel and jet fuel. Overall, we expect U.S. crude oil and petroleum product net exports to average 4.2 million b/d this year, up 1.4 million b/d from 2025.

• Natural gas prices. The Henry Hub spot price averaged $2.94 per million British thermal units (MMBtu) in May, up 17 cents/MMBtu from April, as warmer temperatures increased electric power sector demand. However, supply growth continues to outpace demand, lowering prices in our outlook from earlier forecasts. We forecast the Henry Hub price to average $3.34/MMBtu in 2H26, similar to the price in 2H25.

• Electricity generation. We expect above-average temperatures this summer to increase U.S. electricity generation by 3% compared with the summer of 2025. Increased solar (+19%) and wind (+10%) generation will meet demand, as coal (-2%) generation gradually decreases.

The full June 2026 Short-Term Energy Outlook is available on the EIA website.

The product described in this press release was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy. By law, EIA’s data, analysis, and forecasts are independent of approval by any other officer or employee of the U.S. government. The views in the product and this press release therefore should not be construed as representing those of the U.S. Department of Energy or other federal agencies.

EIA Program Contact: Tim Hess, STEO@eia.gov
EIA Press Contact: EIAMedia@eia.gov

Source: US Energy Information Administration

In-brief analysis

June 5, 2026

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From 2016 to 2024, China’s nuclear generation capacity increased 76% (24 GW), based on our International Energy Statistics (IES) data. According to the International Atomic Energy Agency’s Power Reactor Information System (PRIS), China added an additional 1.1 GW of nuclear power capacity in 2025 and 2.2 GW in 2026 (through May). China is continuing to build out its nuclear generating capacity and has 36 reactors under construction, accounting for more than 49% of total world nuclear construction, according to PRIS.

China’s nuclear fleet is concentrated near population centers in the eastern part of the country, along the Pacific Ocean coastline from the Liaoning province in the north to the Hainan province in the south. According to IAEA’s PRIS, China’s existing nuclear fleet mostly consists of pressurized water reactors.

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As of May 2026, China had 60 operational reactors with 58.7 GW of total capacity installed at 18 different sites. China has also implemented strategies to help rapidly expand its nuclear power plant fleet.

Nuclear projects in China use a standardized project management approach for design, licensing, and construction for multiple reactor technologies. Reactors are built in batches of 6 to 10 reactors to take advantage of economies of scale. China is also building up a nuclear supply chain with a focus on domestic manufacturing of the main plant components to decrease reliance on foreign nuclear vendors.

Additionally, China’s average build time for nuclear power plants is below the global average. According to the World Nuclear Industry Status Report, 2022 the average build time for a nuclear power plant in China between 2012 and 2021 was six years, compared with a global average construction time of about nine years. More recent reporting in 2024 similarly indicates that Chinese firms built reactors both inside and outside of China in five to seven years.

China started construction of six new reactors in 2025 and two new reactors, Xuwei-1 and Taipingling-4 in 2026 through May. China has also commissioned two new units so far in 2026: Sanao-1 and Taipingling-1. In total, China has 36 reactors under construction across 19 sites which will add about 38.9 GW of additional capacity.

Data source: U.S. Energy Information administration, World Bank, Global Energy Monitor, Global Nuclear Power Tracker, and International Atomic Energy Agency
Note: MW=megawatts

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China is building its first small modular reactor (SMR), the Linglong-1, a domestically designed 100 MWe pressurized water reactor that can be used for power generation, water desalination, and district heating. The project is intended to demonstrate commercial operation and is expected to start operation in the first half of 2026. The Linglong-1 uses the ACP100 SMR design, a modular design, allowing certain components to be built in a factory and installed onsite.

You can find more information about energy in China in EIA’s Country Analysis Brief on China.

Principal contributors: Slade Johnson, Jonathan Russo

Source: US Energy Information Administration

In-brief analysis

June 3, 2026

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Underground working natural gas storage capacity in the Lower 48 states increased slightly in 2025, according to our latest data, with growth concentrated in the South Central and Mountain regions. Underground natural gas storage provides a source of energy when demand increases, balancing U.S. energy needs. We calculate natural gas storage capacity in two ways: demonstrated peak capacity and working gas design capacity. Both increased in 2025.

Demonstrated peak capacity is the sum of the largest volume of working gas stored in each storage field during the previous five-year period, regardless of when the peaks occurred. Demonstrated peak capacity for the Lower 48 states rose 0.1%, or 6 billion cubic feet (Bcf), in 2025, increasing for the third year in a row. In the last three years, use of both existing storage facilities and new storage facilities has increased. Demonstrated peak capacity increased by 16 Bcf and 18 Bcf in the South Central and Mountain storage regions, respectively. Meanwhile, demonstrated peak capacity in the Midwest region decreased by 5 Bcf; the Pacific region by 8 Bcf; and the East region by 15 Bcf. Demonstrated peak capacity is typically less than working gas design capacity because it relates to actual usage rather than potential capacity based on the design of the facility.

Design capacity, sometimes referred to as nameplate capacity, is based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which federal or state regulators usually must certify. As of November 2025, the design capacity of underground natural gas storage facilities in the Lower 48 states rose by 26 Bcf to 4683 Bcf compared with the previous year. The South Central and Mountain regions reported the largest capacity additions in the Lower 48 states. Working gas design capacity increased 21 Bcf in the South Central region and 6 Bcf in the Mountain region. Working gas design capacity declined 2 Bcf in the East region primarily due to base gas adjustments in the region. Working gas design capacity in the Pacific and Midwest regions remained unchanged from the previous year.

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Principal contributor: Jose Villar