Category: US Energy Information Administration

Source: US Energy Information Administration

In-brief analysis

July 27, 2026

Data source: Omdia
Note: 1Q16=first quarter 2016; 2Q26=second quarter 2026

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In the second quarter of 2026 (2Q26), 24% of new light-duty vehicles sold in the United States were hybrid electric, battery electric, or plug-in hybrid electric vehicles, up from 22% in 2Q25. Between 2Q25 and 2Q26, hybrid electric vehicles continued to gain market share, reaching a record 16% of light-duty vehicle sales. The market shares of battery electric and plug-in hybrid electric vehicles decreased, according to estimates from Omdia. In 2Q26, battery electric vehicle sales were 6% of new light-duty vehicles sold, down from 7% in 2Q25; plug-in hybrid electric vehicle sales fell from 1.9% to 1.4% over the same period.

These different vehicle types affect the broader energy sector in different ways. Battery electric and plug-in hybrid electric vehicles can consume electricity from the grid, which affects electricity demand. By comparison, hybrid electric vehicles consume liquid fuels and do not connect to the grid. Hybrid vehicles were not eligible for any of the federal tax credits that expired in September 2025.

Data source: U.S. Energy Information Administration

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Two tax credits for purchasing or leasing new electric vehicles both expired on September 30, 2025: the New Clean Vehicle Credit and the Qualified Commercial Clean Vehicle Credit. Battery electric vehicles made up a record 12% of light-duty vehicle sales in September 2025, immediately before the credits expired. However, 2025 marked the first year where annual sales and market share of battery electric vehicles declined, a trend that has continued in 2026. Battery electric vehicle sales fell to 6% of new vehicle sales in the first six months of 2026, down from 7% over the same period last year.

Battery electric vehicles have historically been more popular in the U.S. luxury vehicle market, which accounted for 12% of the total U.S. light-duty vehicle sales in 2Q26. However, battery electric vehicle sales are also decreasing in this market segment. In 2Q26, battery electric vehicles accounted for 14% of luxury light-duty vehicle sales, down from 22% in 2Q25.

Data source: Omdia

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Because sales figures in any year are relatively small compared with the total number of vehicles on the road, electric vehicles’ share of the light-duty vehicle fleet is much less than the recent total 7% sales share in 2Q26. In 2024, the most recent year for which we have fleet-wide data available in our Monthly Energy Review, electric vehicles accounted for 2% of all registered light-duty vehicles in the United States.

Principal contributors: Matthew Skelton, Michael Dwyer

Source: US Energy Information Administration

In-brief analysis

July 24, 2026

North America liquefied natural gas export facilities (2016–2031)

Data source: U.S. Energy Information Administration, Liquefaction Capacity File, and trade press
Note: Bcf/d=billion cubic feet per day; LNG=liquefied natural gas; FLNG=floating liquefied natural gas. Sites that are listed as commissioning have introduced feedgas, system testing, and first LNG production and exports but have not started meeting long-term shipping obligations.

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Energia Costa Azul, the second liquefied natural gas (LNG) export facility in Mexico, shipped its initial cargo from Phase 1 of the terminal on July 8, according to the project developer. The completion of the project adds 0.4 billion cubic feet per day (Bcf/d) of nominal export capacity from a single train, tripling Mexico’s LNG export capacity. The facility is the first terminal in Mexico and the second in North America, following LNG Canada, to be located on the Pacific Coast, boosting North American export capacity there to 2.2 Bcf/d. The Pacific Coast location allows for shorter shipping routes to importers in Asia.

LNG exports from this project are subject to regulatory approvals by the U.S. Department of Energy (DOE) because the facility is supplied with natural gas sourced from the United States. DOE has authorized 0.50 Bcf/d of LNG exports from Energia Costa Azul Phase 1 to countries that have a Free Trade Agreement (FTA) with the United States and 0.44 Bcf/d of LNG exports to non-FTA countries.

Sempra has proposed a second phase of the project, which if constructed would add 1.6 Bcf/d of nominal export capacity from two large-scale trains.

Principal contributor: Jordan Young

Source: US Energy Information Administration

In-brief analysis

July 22, 2026

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For the week ending July 17, 2026, commercial crude oil inventories (excluding the Strategic Petroleum Reserve) increased 2.0 million barrels to 411.7 million barrels, 6% below the previous five-year (2021–2025) average. Gasoline inventories increased 0.8 million barrels, 7% below the five-year average. Distillate inventories increased 1.4 million barrels, 10% below the five-year average. Propane/propylene inventories increased 6.3 million barrels, 34% above the five-year average. Total commercial petroleum inventories increased by 11.6 million barrels for the week.

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U.S. refineries operated at 96.1% capacity utilization, processing 17.1 million barrels per day (b/d), down 58,000 b/d from the previous week. Gasoline output averaged 9.7 million b/d, and distillate production increased to 5.3 million b/d.

Crude oil imports increased 117,000 b/d to 5.8 million b/d, although the four-week average of 5.6 million b/d is 11% less than a year ago. Gasoline imports averaged 494,000 b/d; distillate imports averaged 173,000 b/d.

Over the past four weeks, total product demand averaged 20.4 million b/d, down 1% year over year. Gasoline demand increased 1% to 8.9 million b/d, while distillate demand increased 2% to 3.7 million b/d. Jet fuel demand increased 9% year over year. The increase demand for transportation fuels was offset by decreasing demand in residual fuel oil, propane, and other oils.

Principal contributors: EIA Staff

Source: US Energy Information Administration

This report highlights notable trends in energy-related carbon dioxide (CO₂) emissions in the United States in 2025, based on preliminary data. The U.S. Energy Information Administration (EIA) has published this report on an annual basis since 2010, and has published monthly historical data and forecasts on energy-related CO₂ emissions since August 2009.

U.S. energy-related CO₂ emissions increased by 2%, or about 115 million metric tons (MMmt), in 2025. Emissions increased across all economic sectors, with the largest increase (in tonnage) in the electric power sector as a result of both higher electricity demand and a larger share of electricity generated from coal, relative to 2024 (Table 1). Colder winter weather relative to 2024 also led to an increase in emissions from the residential and commercial sectors for space heating.

Emissions increases in the industrial and transportation sectors were small, with energy efficiency gains and switches to less carbon-intensive fuels curbing growth. The following sections of the report provide more detail and insights into emissions changes for each sector.

Table 1. Total U.S. energy-related carbon dioxide emissions by sector, 2021–2025
million metric tons of carbon dioxide

Sector	2021	2022	2023	2024	2025
Residential	325	340	313	304	331
Commercial	245	260	245	239	256
Industrial	977	964	964	955	960
Transportation	1,807	1,842	1,855	1,863	1,871
Electric power	1,553	1,539	1,422	1,427	1,485
Total	4,906	4,945	4,799	4,789	4,904
Data source: U.S. Energy Information Administration, Monthly Energy Review, May 2026, Tables 11.1–11.6 Note: Totals may not equal sum of components due to independent rounding.

Figure 1. U.S. energy-related CO₂ emissions by sector, 1990–2025

Figure data

Growth in electricity demand and coal’s share of electricity generation were the largest contributors to increases in CO₂ emissions

CO₂ emissions from the electric power sector rose by 4%, or 58 MMmt, in 2025, partly because of growth in overall electricity generation. Net generation in the electric power sector increased by 3%, or 12 terawatthours (TWh), in 2025, surpassing 2024’s record annual generation. Hot summer weather, which led to increased demand for space cooling and record summer peak electricity demand, and growth in electricity demand from data centers and manufacturing facilities both contributed to increased generation.

Changes in the electricity generation mix also influenced sectoral CO₂ emissions, with both net growth in fossil fuel-fired generation and relative growth in coal-fired generation, which emits more CO₂ per kilowatthour than natural gas when combusted. Specifically:

• Coal-fired electricity generation increased by 13% (85 TWh), raising coal-related CO₂ emissions by 78 MMmt
• Natural gas-fired electricity generation decreased by 4% (64 TWh), lowering natural gas-related CO₂ emissions by 23 MMmt
• Wind generation increased by 3% (12 TWh) and solar generation rose by 34% (75 TWh), curbing increased emissions from electricity generation

Electricity generation from other sources was essentially flat compared with 2024.

Figure 2. Share of U.S. electric power sector generation by fuel source, 1990–2025

Figure data

Colder winter weather led to higher residential and commercial natural gas use and CO₂ emissions

CO₂ emissions increased in 2025 from rising consumption of natural gas, propane, and distillate fuel oil—key fuels used in space heating–in both the residential and commercial sectors. Increases in CO₂ were primarily a result of colder winter weather relative to 2024. U.S. population-weighted heating degree days (HDDs), increased by 9% relative to last year, with a peak winter HDD reaching 12% higher than the 2024 winter season.

Figure 3. U.S. monthly average heating degree days, 2020–2025

Figure data

Direct energy use CO₂ emissions in the residential and commercial sectors increased by 9% (27 MMmt) and 7% (17 MMmt) relative to 2024, respectively.

Figure 4. U.S. residential sector direct carbon dioxide emissions by fuel source, 1990–2025

Figure data

Figure 5. U.S. commercial sector direct carbon dioxide emissions by fuel source, 1990–2025

Figure data

Total industrial CO₂ emissions remained mostly unchanged as decreases in coal-related emissions balanced increases from natural gas

CO₂ emissions from the U.S. industrial sector increased by less than 1% (5 MMmt) in 2025. Despite an increase in industrial output in 2025, emissions from the sector remained relatively unchanged because of changes in fuels used. Specifically, coal use in the industrial sector, for both power and manufacturing, continued to decrease through 2025. However, as coal use in industry has decreased, natural gas use has continued to increase and is expected to reach records in 2026 and 2027. As a result of these fuel changes, industrial coal-related emissions fell by 4% (3 MMmt) in 2025 while natural gas-related emissions rose by 1% (6 MMmt). The residual increase in total emissions was a result of modest increases in consumption of various petroleum products.

Figure 6. U.S. industrial sector direct carbon dioxide emissions by fuel source, 1990–2025

Figure data

Transportation sector CO₂ emissions remained flat as decreases from motor gasoline emissions offset increases from distillate fuel oil

U.S. transportation sector emissions remained effectively unchanged in 2025 as emissions changes in the two most-used fuels, motor gasoline and distillate fuel oil, offset each other. CO₂ emissions from motor gasoline fell by 1% (12 MMmt), but CO₂ emissions from distillate fuel oil increased by 3% (12 MMmt). Smaller emissions increases from other fuels, such as jet fuel as use has gradually returned to near pre-pandemic levels, did not meaningfully affect overall sectoral emissions changes. Total transportation sector emissions rose by less than 1% relative to 2024.

Decreases in motor gasoline CO₂ emissions were most closely associated with improvements in vehicle fuel economy, some of which can be attributed to changing trends in vehicle powertrains. Most of these fuel economy improvements can be attributed to continued efficiency improvements in conventional light-duty vehicles. To a lesser extent, increases in electric vehicles and hybrid electric vehicles in the U.S. light-duty fleet also contribute to fuel economy improvements. Emissions reductions from improvements in light-duty vehicle fuel economy outpaced emissions growth from steadily rising on-road vehicle travel, resulting in an overall reduction in motor gasoline emissions.

Increases in CO₂ emissions from distillate fuel oil, mostly from increased vehicle travel and on-road diesel consumption, offset emissions decreases from motor gasoline. Diesel is a more common fuel in larger heavy-freight vehicles, for which there are fewer electric and hybrid options. As a result, demand for freight movement grows faster than fuel economy improvements, leading to a net increase in distillate emissions.

Figure 7. U.S. transportation sector carbon dioxide emissions by fuel source, 1990–2025

Figure data

We based our analysis of U.S. energy-related CO₂ emissions in this report on data published in our Monthly Energy Review (MER). This initial analysis is based on preliminary 2025 data published in the May 2026 edition of the MER. These values are subject to change as final data are published from underlying sources, according to source data revision policies and publication schedules. Although these results are still preliminary, we expect only minor revisions to these estimates. If major revisions to 2025 CO₂ emissions estimates do occur, then this report will be revised accordingly. Supplemental analysis, figures from past reports, and a discussion of the methodology and terminology used in this report are available in the Appendix.

Emissions values and analysis presented in this report pertain only to U.S. CO₂ emissions associated with fossil-fuel combustion and non-combustion applications of energy products (for example, as industrial feedstocks). We do not include estimates of CO₂ emissions outside this scope or other greenhouse gas emissions burned or released in production, extraction, or distribution of energy products. Our approach may result in discrepancies between our emissions estimates and those of other organizations, including other U.S. government agencies.

In addition to historical estimates, we also offer short-term forecasts and long-term projections of U.S. energy-related CO₂ emissions in several other data products. You can find a short-term forecast of U.S. energy-related CO₂ emissions and key drivers in our monthly Short-Term Energy Outlook (STEO), which includes monthly forecasts by fuel source currently through the end of 2027 and the latest estimates of the effects of recent events on energy markets and energy-related CO₂ emissions. We publish long-term U.S. emissions projections in our Annual Energy Outlook, which provides annual projections of energy-related CO₂ emissions by fuel source, sector, and end use through 2050.

EIA has published this report on an annual basis since 2010. The STEO has included a forecast for energy-related CO₂ emissions since August 2009. The MER has also included historical data for energy-related CO₂ emissions on a monthly basis since August 2009.

Source: US Energy Information Administration

In-brief analysis

July 20, 2026

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On July 3, 2026, the New York Independent System Operator (NYISO) imported 52 gigawatthours (GWh) of electricity from Canada, the most traded between the two areas since January 2025. Some of the imported electricity flowed along the new Champlain Hudson Power Express (CHPE) transmission line between Québec, Canada, and New York City, which officially reached commercial operations in May after three years of construction.

A strong heat wave drove electricity demand in NYISO up during the first week of July with a maximum hourly load (peak load) of 31,097 megawatts (MW) on July 2 at 7:00 PM. The hourly peak load last summer (June through August) was 31,857 MW on June 24, 2025, at 7:00 PM (the all-time record load of 33,956 MW occurred in July 2013). Canadian imports fulfilled 9% of electricity demand in NYISO on July 3, with a daily average of 1,400 megawatts (MW) per hour coming from Hydro-Québec and 800 MW per hour from the Independent Electric System Operator in Ontario. The new CHPE transmission line connecting Hydro-Québec’s grid and the NYISO grid has a capacity of 1,250 MW, which was fully utilized on July 3.

According to the New York State Energy Research and Development Authority, CHPE is expected to meet up to 20% of New York City’s power demand. Although the transmission line supplied power to New York during the heat wave in July, an outage occurred in June, and the transmission line was taken offline again on July 4 for further repairs.

In recent years, both ISO-New England and NYISO have relied less on electricity imports from Canada as drought conditions have limited hydroelectric generation. However, both regional grids have built high voltage transmission lines connecting hydropower from Québec to their respective regions, which could reverse the trend if hydroelectric generation increases.

Principal contributors: Tyler Hodge, Kimberly Peterson

Source: US Energy Information Administration

In-brief analysis

July 16, 2026

Data source: Weekly Petroleum Status Report, and Thomson Reuters
Note: WTI=West Texas Intermediate

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Crude oil inventories held at storage facilities in Cushing, Oklahoma, fell below 20 million barrels during the week ending June 19 until the week ending July 10, according to our Weekly Petroleum Status Report.

Storage facilities for crude oil and petroleum products require a minimum volume of product in their tanks and pipe infrastructure to remain operational, which can vary between different storage facilities or tank systems. If storage levels fall below their minimum volume, pump suction can become ineffective and storage facilities cannot function. These minimum volumes are sometimes called tank bottoms.

Tank bottoms are a part of what distinguishes working storage capacity from shell capacity. Shell capacity, in general, refers to the total volume of material that might be held in a given storage facility by design. Working storage capacity, on the other hand, refers to the maximum safe fill volume of storage available, minus the tank bottom capacity. EIA is currently reviewing the results of a pilot study to better understand the minimum working inventory levels at select petroleum inventory facilities.

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In mid-June when storage at Cushing fell below 20 million barrels, the spot price differential between international benchmark Brent crude oil and U.S. benchmark West Texas Intermediate (WTI) priced at Cushing fell just below $0 dollars per barrel. The five-day rolling average differential became negative from June 18 to June 24, and again from July 2 through July 8. The negative differential occurred as the WTI-Cushing price increased above the Brent spot market price, putting the spread at its lowest point since January 2022. The relatively high WTI-Cushing price suggests that recent low inventory levels may be near tank bottom levels, contributing to extreme tightness for Cushing storage operators and the mid-Continent crude oil market.

Storage facilities must generally operate within their working storage capacity limitations, which prevents inventories of crude oil and other products from truly falling to zero under normal conditions. This means that not every barrel of crude oil or petroleum in inventories is necessarily accessible. In extreme cases, an inventory facility may be unable to provide a product even though it is not technically empty, because it is effectively at the bottom of its working storage capacity.

Principal contributor: Kevin Hack

Source: US Energy Information Administration

In-brief analysis

July 15, 2026

Data source: Bloomberg L.P.
Note: 2Q26=second quarter of 2026

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Petroleum markets in the second quarter of 2026 (2Q26) were characterized by continued disruptions to international crude oil and petroleum product flows through the Strait of Hormuz, contributing to higher and more volatile crude oil prices through most of the quarter. The disruptions also resulted in international buyers seeking alternative supply sources for petroleum products, driving up U.S. refinery margins, production, and exports.

Crude oil prices and inventories

The front-month futures price of Brent crude oil traded in a wide range in 2Q26, reaching a high of $118 per barrel (b) on April 29 and falling to a low of $72/b on June 26.

The price of Brent crude oil began the quarter above $100/b, as disruptions to international crude oil flows through the Strait of Hormuz reduced access to crude oil for much of the world and led many countries in the Middle East to shut in crude oil production. Uncertainty around reopening the Strait of Hormuz to shipping traffic contributed to highly volatile prices in April and May, with an average daily price swing of $4/b in the Brent crude oil price, compared with $1/b in the same months in 2025. From May 18 to June 17, negotiated ceasefires and growing market anticipation for the resumption of shipping traffic through the Strait of Hormuz led the Brent crude oil price to decline by an average of more than $1/b per day (d). On June 17, the United States and Iran signed a Memorandum of Understanding (MOU) that, among other things, sought to resume traffic through the Strait of Hormuz. Following the signing of the MOU and an increase in crude oil tanker movements through the strait, Brent crude oil prices generally declined in the remainder of the quarter. In the first two weeks of the third quarter, prices increased following renewed military strikes and uncertainty over the agreement.

Crude oil prices declined in the second half of the quarter despite large global crude oil inventory draws. In our July Short-Term Energy Outlook, we estimated 2Q26 average global crude oil inventory declines of 5.1 million b/d. Crude oil inventories also declined in the United States, where commercial stocks declined from above the seasonal five-year (2021–2025) average at the beginning of the quarter, to its lowest seasonal level since 2014 at the end of the quarter. Record crude oil exports and high refinery runs were key drivers behind U.S. inventory drawdowns.

Refinery margins

U.S. refineries ran at unseasonally high levels in 2Q26, processing the most crude oil for the quarter since 2019, when refining capacity was 4% higher. High refinery inputs reflected strong margins for transportation fuels. Motor gasoline, distillate, and jet fuel crack spreads—measures of the refinery margins for these fuels—were all elevated, with the quarterly average gasoline crack spread up 60% from the year-ago level, and the distillate and jet fuel crack spreads more than double their year-ago levels as a result of tight international supply.

Data source: Bloomberg L.P.
Note: The crack spreads reflect the New York Harbor spot prices for RBOB, ultra-low sulfur diesel, and jet fuel minus the Dated Brent Spot price.

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Petroleum product exports

U.S. distillate and jet fuel exports reached record highs in the second quarter as disruptions to supplies through the Strait of Hormuz also tightened global refined product markets. We estimate 2Q26 distillate exports averaged 1.56 million b/d, 30% higher than the five-year average, and jet fuel exports averaged 356,000 b/d, more than double the five-year average. Compared with 1Q26, U.S. distillate shipments increased to all major export markets, according to data from Vortexa. Jet fuel exports increased substantially to Europe, while remaining about the same to most other destinations.

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Higher global demand to replace lost jet fuel volumes led some refiners to shift their refinery yield to maximize jet fuel output for exports. Refiners can adjust product yields in response to changing market conditions by varying refinery processes and the types of crude oil they refine. In the United States, refineries typically optimize production for motor gasoline to meet domestic demand. In 2Q26, we estimate jet fuel production was 24% higher than the five-year average because of higher refinery runs and higher jet fuel yields. Distillate production was 5% higher and motor gasoline production was only 1% higher over the same period.

Principal contributors: Jimmy Troderman, Alexander de Keyserling

Source: US Energy Information Administration

In-brief analysis

July 14, 2026

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

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Global liquefied natural gas (LNG) trade volumes increased 5.4% to a record 56.3 billion cubic feet per day last year (Bcf/d), driven largely by U.S. LNG export capacity expanding to meet growing demand, according to a recent report from the International Group of Liquefied Natural Gas Importers (GIIGNL). Global LNG trade has slowed this year following the closure of the key export route for Qatar, the world’s second-largest LNG exporter.

LNG exports from the United States increased by 26% to 15.1 Bcf/d in 2025, a larger increase than from any other country, according to our Natural Gas Monthly. We forecast U.S. LNG exports will increase further, to 17.4 Bcf/d of LNG in 2026 and 18.6 Bcf/d in 2027 in our Short-Term Energy Outlook.

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

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U.S. exports amounted to 26% of the global total in 2025, up from 21% in 2024. The United States, Qatar, and Australia, the three largest LNG exporters globally, made up a combined 63% of global exports, up from 60% in 2024. Canada exported 0.3 Bcf/d of LNG in 2025 after LNG Canada began operations in June.

Qatar reported the second-largest increase in LNG exports, rising 3% to 10.6 Bcf/d in 2025. However, Qatari exports have fallen in 2026 due to the closure of the Strait of Hormuz since February 28, which has cut off approximately 20% of global LNG supplies. Until LNG flows through the strait return to historical norms, Asian buyers, who in 2025 imported over 80% of Qatari volumes, are competing on the global spot market with European buyers seeking to refill storage inventories, which are currently at a deficit to the five-year average.

Some exporters, including Malaysia, Australia, and Norway, reported decreases compared with 2024 due to facility maintenance. Russian LNG exports fell 8% (0.4 Bcf/d) in 2025, the largest volumetric decrease of any exporter, on the impact of EU sanctions stemming from the invasion of Ukraine.

European countries increased imports by 29% (3.8 Bcf/d) in 2025, leading all regions worldwide.

Data source: International Group of Liquefied Natural Gas Importers (GIIGNL)

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Europe’s seven largest importers added between 0.4 Bcf/d and 0.6 Bcf/d of LNG imports each. The expiration of the Ukraine-Russia gas transit agreement at the end of 2024 reduced pipeline gas supplies into Europe and increased LNG import requirements. Imports into Asian countries fell 4% compared with 2024 to 35.7 Bcf/d, largely driven by a 15% (1.5 Bcf/d) reduction in imports to China, which expanded its pipeline gas imports and local production to capture a greater share of its domestic natural gas market.

Elsewhere, Egypt increased imports to 1.2 Bcf/d in 2025 from 0.3 Bcf/d in 2024 as a domestic supply shortage led to an increase in LNG imports. Bahrain and Senegal imported their first LNG cargoes in 2025, each importing less than 0.1 Bcf/d. Outside of these three countries, LNG imports into the Middle East and Africa were essentially unchanged in 2025, while LNG imports in the Americas fell by 0.3 Bcf/d.

Principal contributor: Jordan Young

Source: US Energy Information Administration

In-brief analysis

July 9, 2026

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The United States remained the world’s largest crude oil producer in 2025, according to our International Energy Statistics database, extending a streak that began in 2018 when the United States overtook Russia to become the world’s leading producer.

Crude oil production in the United States, including lease condensate, averaged a record-high 13.6 million barrels per day (b/d) in 2025, breaking the previous U.S. and global production record of 13.2 million b/d set in 2024. U.S. crude oil production was about 40% higher on average in 2025 than that from the next two largest global crude oil producers, Russia and Saudi Arabia.

U.S. crude oil production has been buoyed by continued gains in drilling productivity and operational efficiency across key shale basins, which allow operators to extract more oil per well. The growth in output continued in 2025 despite lower oil prices; West Texas Intermediate (WTI) prices dropped from an average of $77/b in 2024 to $65/b in 2025 amid global oversupply. Production growth was particularly strong in the Permian Basin of Texas and New Mexico, which had a 4% increase in crude oil production, from 6.3 million b/d in 2024 to 6.6 million b/d in 2025. The Permian accounted for approximately 48% of U.S. production in 2025.

Shale oil and gas development in the United States became notable when in 2008 it reversed a multi-decade decline in U.S. crude oil production. U.S. crude oil production powered by shale development has turned the United States into not just the world’s largest producer, but the largest producer of crude oil ever.

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The difference between the United States and other major producers widened in 2025, with Russian output largely unchanged and Saudi Arabia recording modest growth as a result of OPEC+ unwinding voluntary production cuts. Crude oil production including lease condensate in Saudi Arabia increased from 9.2 million b/d in 2024 to 9.6 million b/d in 2025. Russia’s crude oil production averaged 9.9 million b/d in 2024 and remained largely unchanged in 2025 as a combination of voluntary production cuts and effects of the conflict with Ukraine limited crude oil output growth.

Looking ahead, we forecast U.S. crude oil production will remain near 13.7 million b/d in 2026, before increasing to 14.2 million b/d in 2027 based on our latest Short-Term Energy Outlook. Production growth comes amid rising prices as WTI prices increase by $22/b to $88/b in 2026. In addition to the WTI price increase, continued shale well productivity improvements will also drive growth.

Parallel to the growth in crude oil production, U.S. associated natural gas production has also surged, driven by activity in oil-dominant plays like the Permian. This abundance of associated gas has continued to support domestic natural gas-fired electricity generation and growing natural gas exports. In 2024, the most recent year data are available, the United States was the world’s largest natural gas producer. We will release 2025 natural gas production data in our International Energy Statistics database later this year.

Principal contributors: Naser Ameen, Troy Cook

Source: US Energy Information Administration

In-brief analysis

July 8, 2026

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U.S. petroleum exports reached a record in April as disruptions to international crude oil and refined product flows through the Strait of Hormuz increased global demand for U.S. exports. Exports increased to 13.6 million barrels per day (b/d) in April, 15% more than the previous record set in March.

Crude oil exports made up the largest share of total petroleum exports, averaging 5.6 million b/d in April, 21% more than the previous record set in December 2023. Propane made up the second-largest share, with exports exceeding the 2.0 million b/d mark for the first time in monthly data, and distillate fuel oil made up the third-largest share, increasing to 1.6 million b/d, the most since July 2017.

U.S. exports of finished petroleum products—which is mostly made up of distillate fuel oil, motor gasoline, jet fuel, and petroleum coke—were the highest since December 2024, despite relatively average exports of motor gasoline.

Exports for other products including jet fuel, unfinished oils, and naphtha reached record highs in March and remained high in April but slightly below their record levels.

Our more recent weekly estimates suggest crude oil, distillate fuel, jet fuel, and propane exports remained above five-year (2021–2025) seasonal highs in May and June.

Principal contributor: Jimmy Troderman