Five years after the COVID-19 national emergency was declared, gasoline demand, distillate demand, and jet fuel demand all remain less than pre-pandemic averages. Several factors are keeping demand, which we track as product supplied, below pre-pandemic levels. For example, increased fuel efficiency in the vehicle and aircraft fleets has offset increased travel, and demand for petroleum-based distillate fuel oil has been partially replaced by biomass-based distillate fuels.

U.S. jet fuel consumption growth has slowed in 2025, following a period of rapid consumption growth after 2020, as U.S. air travel recovered from the COVID-19 pandemic. We forecast the slowdown in jet fuel consumption growth will continue through 2026, falling below both the accelerated rate of the previous four years and the longer-term growth rate seen during the 2010s. Contributing factors include rising economic concerns weighing on flight demand and ongoing improvements in commercial aircraft fleet fuel economy.

We forecast natural gas consumption in the United States will increase 1% to set a record of 91.4 billion cubic feet per day (Bcf/d) in 2025. In our latest Short-Term Energy Outlook, we expect natural gas consumption to increase across all sectors except for electric power, which had been the source of most natural gas consumption growth in the previous decade.

Alaska has the highest per capita energy expenditures of any state at $12,100, according to our recently published State Energy Data System information for 2023. Wyoming and North Dakota spent the next most on energy at $10,100 and $9,300 per capita, respectively. All three states spent twice as much as the national average of $4,700. Florida had the lowest per capita energy expenditures at $3,700, followed by New York and Maryland at $3,800 each.

Developers added 12 gigawatts (GW) of new utility-scale solar electric generating capacity in the United States during the first half of 2025, and they plan to add another 21 GW in the second half of the year, according to our latest survey of electric generating capacity changes. If those plans are realized, solar would account for more than half of the 64 GW that developers plan to bring online this year. Battery storage, wind, and natural gas power plants account for virtually all of the remaining capacity additions for 2025.

In our latest Short-Term Energy Outlook, we forecast U.S. working natural gas inventories will reach 3,872 billion cubic feet (Bcf) by the end of October, or 2% more than the previous five-year average for that time of year. Natural gas inventories grew quickly in late April through early June, with seven consecutive weeks of net injections to inventories exceeding 100 Bcf each for the first time since 2014.

Even without accounting for electricity interruptions resulting from major events such as hurricanes, customers in Puerto Rico experienced on average 27 hours of power grid interruptions per year between 2021 and 2024. By comparison, electricity customers in the mainland United States generally experience about two hours of electricity interruptions per year without major events.

In 2024, the United States exported about 30% of its domestic primary energy production. This percentage has grown considerably in recent decades, according to data in our Monthly Energy Review. Nearly all of the exports were fossil fuels destined for other countries in North America, Europe, or Asia.

Five countries account for more than two-thirds of the world's total nuclear electricity generation capacity. The United States has the most capacity, followed by France, China, Russia, and South Korea, based on International Atomic Energy Agency (IAEA) data as of June 2025. Globally, 416 nuclear power reactors are operating in 31 countries, with a total installed net generating capacity of 376 gigawatts (GW).

From 2020 to 2024, crude oil and condensate exports from Russia averaged 5.0 million barrels per day (b/d). Exports from Russia in the first half of 2025 (1H25) were 4.3 million b/d (compared with 4.8 million b/d in 2024). Even as crude oil export volumes from Russia have remained relatively high, the destination of these exports has shifted, mainly due to sanctions related to Russia's full-scale invasion of Ukraine in February 2022.

Energy prices—along with other globally traded commodities, equities, and currencies—were more volatile in the second quarter of 2025 (2Q25) amid significant uncertainty from concerns over economic growth as well as geopolitical tensions in the Middle East. The geopolitical uncertainty has affected crude oil prices and refinery margins, and shifting government policies have affected biofuel compliance credit prices.

Electricity demand in the Lower 48 states exceeded previous peaks on two days in the last week of July.

In our recently published Annual Energy Outlook 2025 (AEO2025), we introduced our new Hydrogen Market Module (HMM), which allows us to model the market for hydrogen in the coming decades.

In our most recent Short-Term Energy Outlook (STEO), we forecast nationwide U.S. retail electricity sales to ultimate customers will grow at an annual rate of 2.2% in both 2025 and 2026, compared with average growth of 0.8% between 2020 and 2024. The forecast reflects rapid electricity demand growth in Texas and several mid-Atlantic states, where the grid is managed by the Electric Reliability Council of Texas (ERCOT) and the PJM Interconnection, respectively. We expect electricity demand in ERCOT to grow at an average rate of 11% in 2025 and 2026 while the PJM region grows by 4%.

The value of energy trade between the United States and Canada remained steady in 2024 at an estimated $151 billion compared with $154 billion in 2023, according to data from the U.S. Census Bureau. Energy trade value is the total value of energy imports and exports between two countries and is driven by commodity volumes and prices. Most of the U.S.-Canada trade value is U.S. energy imports from Canada—$124 billion in 2024—rather than from U.S. energy exports to Canada, which totaled $27 billion last year.

In our Annual Energy Outlook 2025 (AEO2025), we project regional differences in natural gas markets will encourage increased natural gas flows from the mid-Atlantic to the southern Gulf Coast in the coming decades. Across the cases we explored, we project production from the Appalachian Basin in the mid-Atlantic and Ohio region will increasingly meet growing demand on the Gulf Coast in the South Central region, driven largely by increasing liquefied natural gas (LNG) exports. The economics of increased production in the Appalachian Basin are more favorable by 2030, and our model shows natural gas transiting through the Eastern Midwest region on the way to the Gulf Coast.

Crude oil production from onshore federal lands has increased in recent years as a result of significant growth in drilling activity and operations. According to data collected by the U.S. Department of the Interior's Office of Natural Resources Revenue, onshore crude oil production from federal lands reached 1.7 million barrels per day (b/d) in 2024, a record high. Most of this growth was in New Mexico from crude oil produced from federal lands in the Permian Basin.

The average historical volatility of the daily Henry Hub front-month futures price, a key benchmark for U.S. natural gas, trended downward through the first half of the year, with quarterly volatility falling from a recent high of 81% in the fourth quarter of 2024 to 69% by mid-2025. This decline marks a return to more typical seasonal patterns and reflects greater market stability as storage inventories return to levels close to the prior five-year average. Since 2022, natural gas markets have experienced a series of extremes, including both unusually high and low inventory levels, which contributed to elevated price volatility. Recent quarters, by contrast, have seen more seasonally consistent price movements, suggesting that natural gas market dynamics have steadied amid record storage injections and more balanced inventories.

We expect U.S. coal-fired power plants will remain relatively well-stocked through the end of next year in our latest Short-Term Energy Outlook. We estimate power plants in the United States had 124 million short tons of coal on-site at the end of June for them to consume that coal at a rate of about 1.3 million short tons per day, meaning they had about 93 days' worth of fuel on-site. This metric, also called days of burn, is calculated by dividing coal inventories held at power plants by a seasonal consumption rate. We forecast days of burn will range between about 90 and 120 days between now through the end of 2026, or about a month's worth of coal more than power plants had on-site between 2019 and 2022.

The United States exported more crude oil to Nigeria than it received from Nigeria for the first time in February and March 2025. During this period, refinery maintenance on the U.S. East Coast drove down U.S. demand for crude oil imports, including imports from Nigeria, and the relatively new Dangote refinery in Nigeria drove up Nigeria's demand for inputs, including crude oil it imported from the United States. This marks the first time that the United States was a net crude oil exporter to Nigeria, and structural changes to crude oil trade between the countries suggest this dynamic could occur more frequently.