New data from the U.S. Energy Information Administration (EIA) shows output rose by about 3 per cent, or 350,000 b/d, compared to 2024. The increase came despite a 5 per cent drop in active rigs and fewer wells drilled, highlighting a structural shift in how U.S. producers are growing supply.

The gains reinforce the United States’ position as the world’s largest oil producer and contribute to expectations of a global supply surplus. Reuters has reported that rising U.S. output is a key factor behind forecasts of an oversupplied global market, with production expected to average roughly 13.6 million b/d in 2025.

Efficiency offsets lower prices

The 2025 production increase came as benchmark West Texas Intermediate (WTI) crude prices fell to about $65 per barrel, down from $77 in 2024. Normally, lower prices would dampen output, but U.S. producers continued to extract more oil from fewer wells.

New wells added 2.9 million b/d of production in 2025, while existing wells accounted for 8.3 million b/d. Industry analysts have increasingly pointed to productivity gains — including longer laterals, improved fracking techniques, and better data analytics — as the main driver of growth.

Bloomberg has similarly reported that U.S. shale producers are pumping more oil per dollar invested, allowing output to rise even as capital spending and rig counts decline.

This decoupling of production from drilling activity marks a significant evolution in the shale sector, where companies have shifted focus from rapid expansion to capital discipline and efficiency.

Permian dominates growth

As in previous years, the Permian Basin remained the engine of U.S. production growth. Output in the region rose by 280,000 b/d in 2025 to reach 6.6 million b/d — nearly half of total U.S. supply.

Low breakeven costs continue to underpin Permian growth. According to the Dallas Fed Energy Survey, operators in the Midland and Delaware basins reported breakeven prices of roughly $61–$62 per barrel in 2025, below the annual average oil price. That cost advantage has allowed producers to sustain output even in a weaker price environment.

By contrast, other major shale regions showed limited growth. Production in the Eagle Ford rose modestly to 1.2 million b/d, while the Bakken saw a slight decline to a similar level.

Together, the Permian, Eagle Ford, and Bakken account for nearly two-thirds of total U.S. crude production.

Offshore projects add supply

Production in the Gulf of America also contributed to overall growth, rising by 111,000 b/d to average 1.9 million b/d in 2025.

Five new offshore projects — Whale, Ballymore, Dover, Shenandoah, and Leon-Castile — came online during the year. Unlike shale operations, offshore developments are less sensitive to short-term price fluctuations due to their long lead times and high upfront capital costs.

This steady pipeline of offshore projects is helping to diversify U.S. supply growth beyond shale basins.

Global implications

The global outlook for oil markets has shifted rapidly in recent weeks. The war in Iran and severe disruptions to shipping through the Strait of Hormuz — which typically carries about one-fifth of global oil — have tightened supply and driven prices sharply higher. With tanker traffic collapsing and infrastructure under attack, the market is moving away from fears of oversupply toward a more constrained and volatile environment.

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Production increased by 5.3 Bcf/d compared with 2024, according to the EIA’s latest Natural Gas Monthly. Three regions — Appalachia, Permian and Haynesville — accounted for 67 per cent of total U.S. marketed gas production and 81 per cent of the growth last year.

Higher natural gas prices helped support drilling activity. The Henry Hub benchmark price rose about 60 per cent in 2025 to US$3.52 per million British thermal units (MMBtu), improving the economics of production across multiple basins.

The Appalachian Basin in the northeastern United States remained the country’s largest natural gas producing region, accounting for 36.6 Bcf/d, or roughly 31 per cent of total U.S. marketed production.

Production growth there has slowed in recent years because of limited pipeline capacity to move gas to markets. However, additional capacity began coming online in 2024 when the Mountain Valley Pipeline was authorized to start operating. Combined with higher gas prices, that helped push Appalachian production up by 1.1 Bcf/d in 2025, compared with only modest growth in 2024.

The Permian Basin in Texas and New Mexico continued to play a major role in U.S. gas growth. Production in the region rose 11 per cent, or 2.7 Bcf/d, reaching an average of 27.7 Bcf/d in 2025.

Much of the natural gas produced in the Permian is associated gas, meaning it is generated as a by-product of oil production. Even though benchmark West Texas Intermediate crude prices declined from US$77 per barrel in 2024 to about US$65 in 2025, prices remained high enough to support oil-directed drilling.

Industry surveys suggest the basin remains economically viable at those levels, with breakeven prices estimated around US$61 per barrel in the Midland Basin and US$62 in the Delaware Basin.

Another factor contributing to higher gas production in the Permian is the region’s rising gas-to-oil ratio, meaning wells are producing more natural gas relative to oil over time.

The Haynesville shale, which spans Louisiana and Texas, also contributed to production growth. Output there averaged 14.9 Bcf/d in 2025, about four per cent higher than in 2024.

Haynesville wells are typically much deeper — between 10,500 and 13,500 feet — than wells in the Appalachian Basin, which generally range from 4,000 to 8,500 feet. The greater depth increases drilling costs, but the basin’s location provides an important advantage.

Haynesville sits close to liquefied natural gas export terminals and large industrial natural gas consumers along the U.S. Gulf Coast, making it an attractive supply source for both domestic and export markets.

The EIA expects U.S. natural gas production to continue growing in the coming years as additional infrastructure and export demand support drilling activity. Expansion of LNG export capacity along the Gulf Coast is expected to play a key role in shaping future natural gas markets.

The United States has been the world’s largest producer of natural gas for more than a decade, largely because of the expansion of shale gas production since the mid-2000s.

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According to the U.S. Energy Information Administration (EIA), the first large-scale commercial enhanced geothermal system (EGS) power plant in the United States is currently under construction and scheduled to begin operating in June 2026.

Geothermal power plants generate electricity by tapping underground heat from reservoirs of hot water or steam. These resources typically occur in geologically active regions near tectonic plate boundaries or volcanic areas, which is why most conventional geothermal generation in the United States is located in western states such as California and Nevada.

The United States currently has about 2.7 gigawatts (GW) of geothermal generating capacity, accounting for roughly 0.2 per cent of total U.S. summer electricity capacity, according to the EIA.

Enhanced geothermal systems aim to expand that potential by creating artificial reservoirs deep underground where naturally occurring geothermal resources do not exist.

Unlike conventional geothermal plants that rely on naturally permeable rock formations, EGS uses advanced drilling techniques—including horizontal drilling and hydraulic fracturing—similar to technologies developed for oil and natural gas production. These techniques allow engineers to create underground reservoirs where water can circulate through hot rock, producing steam that drives electricity-generating turbines.

Because EGS can theoretically be deployed in many more locations, it could significantly expand geothermal energy production.

The U.S. Geological Survey estimates that 135 GW of potential geothermal electricity generation could be available from EGS in the Great Basin region alone. Other studies suggest that up to 150 GW of cost-effective geothermal capacity could eventually be developed across the United States, depending on technological progress and electricity market conditions.

A 2023 study by the National Laboratory of the Rockies estimated that 90 GW of EGS capacity could be economically built in the United States by 2050.

Several projects are already moving forward. Fervo Energy’s Cape Generating Station in Utah will be the first large-scale commercial EGS power plant in the country. The facility is expected to have 28 megawatts (MW) of net summer generating capacity, with a maximum capacity of 53 MW.

Two additional EGS units of the same size are expected to begin operating at the site in early 2027, and the company has signed power purchase agreements with Southern California Edison for up to 320 MW of electricity as it expands the project.

Other developers are also testing advanced geothermal technologies. Rodatherm Energy Corp. is piloting a closed-loop geothermal system designed for hot sedimentary rock formations common in the western United States and along the Gulf Coast.

Large electricity users are beginning to support geothermal development as well. Technology company Meta recently signed an agreement with geothermal developer SAGE to supply up to 150 MW of geothermal electricity to help power its data centre operations.

Despite the promise of EGS, several challenges remain. Geothermal projects require expensive deep drilling and careful management of underground reservoirs. Developers must also mitigate the risk of induced seismicity, or small human-caused earthquakes that can occur during reservoir creation.

Governments and industry groups are investing in research to reduce those risks and lower drilling costs. One major research initiative is the Utah Frontier Observatory for Research in Geothermal Energy (FORGE), a U.S. Department of Energy field laboratory where scientists and engineers are testing techniques for creating and managing enhanced geothermal reservoirs.

Canada is also playing a role in advancing next-generation geothermal technology.

Calgary-based Eavor Technologies is developing a closed-loop geothermal system that circulates fluid through underground wells without requiring naturally occurring reservoirs or hydraulic fracturing. The technology creates a sealed underground heat exchanger designed to deliver constant geothermal energy.

The company recently completed a major project in Geretsried, Germany, where it is building what it describes as the world’s first commercial-scale closed-loop geothermal power plant. The facility is expected to produce both electricity and district heating using Eavor’s advanced geothermal system.

Advances such as enhanced geothermal systems and closed-loop technologies could significantly expand the role of geothermal energy in global electricity markets.

Because geothermal plants produce continuous electricity and are not dependent on weather conditions like wind or solar power, some analysts say advanced geothermal technologies could become an important source of reliable, carbon-free power as countries expand clean energy systems.

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The United States exported an average of 4.0 million barrels per day (b/d) of crude oil in 2025, a 3 per cent drop from 2024, marking the first annual decline since 2021. The decrease came primarily from reduced shipments to Europe and to the Asia–Oceania region, historically the largest markets for U.S. crude.

Despite the drop in exports, overall U.S. net crude imports also declined, falling from 2.5 million b/d in 2024 to 2.2 million b/d in 2025, because imports fell by an even greater amount.

The export slowdown is notable given that U.S. crude production rose 3 per cent in 2025 to a record 13.6 million b/d. Instead of flowing to overseas buyers, more of that production went into domestic stockpiles—including the Strategic Petroleum Reserve (SPR)—and to U.S. refineries.

Since the early 2010s, U.S. crude exports have expanded dramatically. Driven by the shale boom, new pipeline and port infrastructure, and strong global demand for light, low-sulphur crude, exports have surged since Washington lifted its decades-old crude export ban in 2015. By comparison, exports in 2025 were about 85 times higher than in 2011.

Europe remained the largest destination for U.S. crude oil, although exports to the region fell 7 per cent in 2025.

European demand for American crude surged after Russia’s invasion of Ukraine in 2022 disrupted global oil flows and forced European refiners to replace Russian supplies. In 2023 the region overtook Asia as the largest market for U.S. crude.

But in 2025, according to the EIA, some U.S. volumes were displaced as OPEC producers increased output, allowing European refiners to diversify supply sources.

The United Kingdom saw the largest decline among European buyers, with imports of U.S. crude falling more than 100,000 b/d, or roughly 35 per cent, year over year.

Even with the decrease, exports to Europe remain higher than they were before the Ukraine war reshaped global oil trade patterns.

Exports also dropped sharply to the Asia and Oceania region, particularly to Singapore and China. U.S. shipments to Singapore fell 75 per cent, while exports to China plunged 89 per cent compared with 2024.

China had been the second-largest destination for U.S. crude in 2023, but purchases have fallen sharply over the past two years as Chinese refiners turned increasingly to Middle Eastern and Russian supplies that often trade at discounted prices.

Some Asian buyers, however, increased imports. India boosted purchases of U.S. crude by about 90,000 b/d, while Japan increased imports by roughly 80,000 b/d.

In Europe, the Netherlands imported about 80,000 b/d more U.S. crude in 2025 than the previous year, partly reflecting the country’s role as a major refining and trading hub.

Another notable new buyer is Nigeria. U.S. exports to the country rose from about 40,000 b/d in 2024 to around 110,000 b/d in 2025.

The increase coincides with the launch of the massive 650,000 b/d Dangote refinery, which began processing crude in early 2024 and reached its designed capacity in February 2026. As the refinery ramped up operations, Nigeria increasingly turned to imported crude, including supplies from the United States.

The decline in U.S. exports appears largely driven by market dynamics rather than geopolitical conflict, analysts say. Higher OPEC production, shifting refinery demand, and domestic stock builds in the United States played a larger role than any single geopolitical event.

While tensions in the Middle East—including the Iran conflict—have added volatility to global oil markets, major news outlets such as Reuters and Bloomberg report that the primary structural shifts in crude flows over the past two years have been tied to OPEC supply changes, refinery economics, and evolving trade patterns following Russia’s war in Ukraine.

Even with the 2025 decline, the United States remains one of the world’s largest crude exporters and a central supplier to global oil markets.

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EIA’s analysis shows that about 22 per cent of light-duty vehicles sold in the United States in 2025 were electrified in some form — including hybrids, battery electric vehicles (BEVs) and plug-in hybrids (PHEVs) — up from 20 per cent in 2024. However, the growth trajectory was uneven: hybrid electric vehicles continued gaining market share, while battery electric and plug-in hybrid sales declined over the year.

The divergence reflects seismic changes in tax policy. Two major incentives — the New Clean Vehicle Credit and the Qualified Commercial Clean Vehicle Credit, each worth up to US $7,500 — expired on September 30, 2025 as part of broader tax changes enacted by Congress. The credits had long been a cornerstone of U.S. EV policy, lowering purchase costs for consumers and supporting demand.

Industry analysts widely anticipated a drop in EV sales once those incentives ended. A market expert quoted by Reuters in September said the impending tax credit expiration would likely cause a “short-term dip” in EV sales as buyers rushed to close deals before the deadline.

Indeed, EIA’s figures show that BEVs reached a record share of 12 per cent of U.S. light-duty vehicle sales in September 2025, just before the tax credits disappeared. Afterwards, BEV sales fell to less than 6 per cent in each of the remaining months of the year, marking the first annual decline in battery electric vehicle sales and share in the United States.

Policy shifts and market reactions

Industry reporting confirms a sharp hit to EV demand post-credit expiry. A Yahoo Finance analysis found that EV sales at U.S. dealerships plunged by as much as 74 per cent from peak weekly levels after the federal tax incentive ended, highlighting the role subsidies played in consumer buying decisions.

Automakers have felt the impact. According to The Wall Street Journal, Ford Motor Co. saw electric vehicle sales decline sharply in November 2025, with BEV units down 61 per cent year-over-year as demand softened following the credit’s expiration. At the same time, hybrid sales — which were not eligible for the tax credit — increased, reflecting shifting buyer behaviour.

General Motors has also reported financial strain, with roughly US $6 billion in charges tied to declining EV sales and the loss of policy incentives, according to Associated Press reporting. GM’s ambitious electrification plans have been disrupted by a combination of subsidy cuts and looser emissions standards.

Why hybrids are gaining ground

Unlike battery electric vehicles, hybrid electric vehicles do not plug into the grid and rely on internal combustion engines coupled with electric motors. They were never eligible for the 2025 federal tax credits, yet hybrids continued to gain share throughout the year, buoyed by fuel-efficiency advantages and growing consumer comfort with electrified drivetrains.

Analysts point to price and convenience as key drivers. With federal incentives gone and many EV sticker prices remaining high — the average new EV transaction price exceeded US $60,000 in 2025 — hybrids have become an attractive alternative for mainstream buyers not ready to pay a premium for all-electric range.

Broader industry context

The U.S. trend contrasts with global EV markets, where overall plug-in sales continued to grow in 2025. Benchmark data indicates that global EV sales rose roughly 20 per cent, led by strong growth in European and Chinese markets, even as U.S. EV sales lagged due to fading incentives and weaker policy support.

China in particular remains dominant: EVs accounted for a majority share of the country’s automotive market in 2025, matched with aggressive local incentives and production scale. Those conditions continue to drive China’s outsized footprint in global EV manufacturing and sales.

Future outlook

Looking ahead, industry watchers say the U.S. EV market may stabilize or rebound if states, automakers, or future federal policy introduce new incentives or regulatory support. However, the 2025 experience highlights how sensitive EV adoption remains to public policy and cost incentives — a lesson likely to shape debates on electrification strategy and climate goals in 2026 and beyond.

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The EIA estimates that electricity generation by the U.S. electric power sector totalled about 4,260 billion kilowatt-hours (BkWh) in 2025. Generation is forecast to grow by 1.1 per cent in 2026 and 2.6 per cent in 2027, reaching 4,423 BkWh, driven largely by new solar capacity and rising electricity consumption.

While dispatchable power sources — natural gas, coal and nuclear — accounted for about 75 per cent of total generation in 2025, the EIA expects their combined share to fall to roughly 72 per cent by 2027. Over the same period, the share of electricity generated from wind and solar is projected to rise from 18 per cent to 21 per cent, continuing a longer-term shift toward cleaner sources.

Solar leads growth, especially in Texas

Utility-scale solar is expected to be the fastest-growing source of electricity generation in the United States. The EIA forecasts solar generation will rise from 290 BkWh in 2025 to 424 BkWh by 2027, supported by nearly 70 gigawatts (GW) of new capacity scheduled to come online in 2026 and 2027 — a 49 per cent increase in operating solar capacity compared with the end of 2025.

Much of that growth is concentrated in Texas, where the grid managed by the Electric Reliability Council of Texas (ERCOT) continues to attract large-scale renewable investment. Solar generation in ERCOT is expected to nearly double, from 56 BkWh in 2025 to 106 BkWh by 2027.

Bloomberg has reported that Texas’s relatively streamlined permitting, abundant land and strong power demand from industrial users and data centres have made it one of the most active solar markets globally. The expansion is increasingly supported by battery storage, which helps manage fluctuations in solar output. The EIA expects battery capacity in ERCOT to rise from about 15 GW in 2025 to 37 GW by the end of 2027.

Wind growth slows in the Midwest

Wind power, long concentrated in the central United States, is expected to see more modest growth in the coming years. In the Midcontinent Independent System Operator (MISO) region, which covers much of the Midwest, wind generation is forecast to average just over 100 BkWh annually through 2027, reflecting a slowdown in new wind installations.

Reuters has noted that rising costs, supply-chain constraints and transmission bottlenecks have tempered wind development in parts of the U.S., even as solar continues to expand. In MISO, new solar plants are beginning to offset slower wind growth, with solar generation expected to increase from 31 BkWh in 2025 to 46 BkWh in 2027, according to the EIA.

Natural gas remains dominant, but its share slips

Natural gas remains the largest single source of U.S. electricity generation, although its share has declined from a peak of 42 per cent in 2024. The EIA forecasts natural gas-fired generation will total 1,696 BkWh in 2026, roughly flat with 2025 levels, before rising slightly to 1,711 BkWh in 2027 as overall power demand increases.

Because total electricity generation is growing faster than gas-fired output, natural gas’s share of the power mix is expected to fall to 39 per cent by 2027, down from 40 per cent in 2025.

Regional growth in gas generation remains uneven. The EIA expects gas-fired output to increase 23 per cent in ERCOT and 5 per cent in the PJM Interconnection region, which covers much of the U.S. Mid-Atlantic. Both areas are seeing rapid growth in electricity demand from data centres, a trend Reuters and NPR have linked to the expansion of cloud computing and artificial intelligence infrastructure.

Coal declines after a temporary rebound

Coal-fired electricity generation rose 13 per cent in 2025 to 731 BkWh, supported by colder-than-average weather in some regions and relatively higher natural gas prices. But that rebound is expected to be short-lived.

With existing policies and planned retirements, the EIA projects coal-fired generation will decline by an average of 5 per cent per year over the next two years, falling to 661 BkWh in 2027. Coal’s share of total generation would drop to 15 per cent, from 17 per cent in 2025.

NPR has reported that while coal plants can still play a role during extreme weather or fuel price spikes, utilities continue to retire aging units as renewable capacity and storage expand and operating costs rise.

A power system in transition

Taken together, the EIA’s outlook underscores a U.S. power sector in transition: electricity demand is rising, driven by digital infrastructure and electrification, while solar and battery storage grow rapidly and fossil fuels gradually lose market share.

As Bloomberg has noted, the pace at which new generation and grid infrastructure can be built — particularly transmission and storage — will be critical in determining how smoothly that transition unfolds through the latter half of the decade.

Canada context: How U.S. power trends compare north of the border

While the United States is seeing rapid growth in solar power and battery storage alongside rising electricity demand, Canada’s electricity system is evolving along a different path — shaped by its heavy reliance on hydroelectricity and a slower pace of large-scale solar deployment.

Hydropower accounts for roughly 60 per cent of Canada’s electricity generation, according to Natural Resources Canada, providing a large source of dispatchable, low-emissions power that the U.S. largely lacks. Nuclear power contributes about 15 per cent, concentrated mainly in Ontario, while natural gas plays a smaller but growing role in provinces such as Alberta and Saskatchewan.

Unlike the U.S., where solar is the fastest-growing source of generation, Canada’s recent renewable additions have been led by wind power, particularly in Alberta, Ontario and Quebec. Utility-scale solar remains a relatively small share of Canada’s power mix, although installations are increasing in Alberta and Saskatchewan, where market structures and solar resources are more favourable.

Battery storage is also expanding more slowly in Canada than in the U.S., though several provinces are beginning to add grid-scale storage to support renewable integration and manage peak demand. Alberta and Ontario, in particular, have announced or approved new battery projects over the past two years.

One area where trends converge is rising electricity demand, driven by electrification, population growth and data centres. Canadian utilities and grid operators have warned that meeting future demand will require significant investment in generation, transmission and storage — even in hydro-rich provinces.

As in the U.S., the pace at which new infrastructure can be built, and how costs are managed for consumers, is emerging as a central challenge for Canada’s power transition.

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The EIA attributes the shift to uneven regional performance across U.S. basins. Although modest gains are expected in Alaska, the Federal Gulf of Mexico and parts of the Permian Basin, those increases will be offset by declines in other major producing regions. Production in 2024 grew by 300,000 b/d, followed by a 400,000 b/d increase in 2025, driven primarily by the Permian Basin in Texas and New Mexico, which remains the country’s most prolific oil-producing region.

Production outlook reflects price environment

The EIA expects a softer price environment to influence drilling and investment decisions through 2026. The agency forecasts West Texas Intermediate (WTI) crude prices to average US$65 per barrel in 2025 and US$51 in 2026, down sharply from the 2024 average of US$77/b. Lower prices typically weigh on capital spending, especially among shale producers with higher costs or more marginal wells.

Reuters reporting throughout 2025 has noted that U.S. shale companies have become more sensitive to price swings as they prioritise investor returns over rapid production growth. Many publicly traded operators have tightened spending plans and focused on free-cash-flow stability, a break from the high-growth strategies seen in earlier shale booms. According to Reuters, several producers have suggested they may reduce drilling activity in 2026 if prices fall toward the levels projected by EIA.

Bloomberg analysis adds that consolidation across the U.S. shale sector — including a wave of mergers and acquisitions in 2024–25 — has resulted in fewer operators controlling larger acreage positions. Analysts say this consolidation may contribute to flatter production profiles, as large companies typically pursue steadier, slower-growth development strategies.

Regional dynamics: Permian still growing, other basins softening

The EIA forecast shows the Permian Basin continuing to expand, though at a slower pace than in recent years. Technological improvements, high-quality drilling inventory and lower breakeven costs relative to other basins will sustain output in the region through 2026.

Alaska is also projected to record modest increases as new projects ramp up following multiyear development cycles. Offshore production in the Federal Gulf of Mexico is expected to rise slightly as recently completed platforms reach full output.

However, declines are forecast in other parts of the Lower 48. Several shale basins, including the Bakken and Eagle Ford, have shown signs of maturing, with reduced drilling activity, declining well productivity in some areas and more limited access to top-tier drilling locations. As a result, gains in the Permian and offshore regions are not expected to be sufficient to offset declines elsewhere.

Demand, inventories and global market context

The production forecast comes amid mixed signals for global oil demand. Bloomberg reports that world oil demand growth slowed in 2025 as efficiency improvements, electric-vehicle uptake and sluggish industrial activity weakened consumption in several advanced economies. Nonetheless, demand in emerging markets — particularly in India and parts of Southeast Asia — remained resilient, preventing a more significant global downturn.

Reuters notes that U.S. crude inventories increased modestly through 2025, contributing to downward pressure on prices. Combined with higher-than-expected non-OPEC supply growth, these inventories have helped keep Brent and WTI benchmarks in a lower trading range.

In the U.S., NPR reporting highlights how some households and businesses continue to experience cost pressures linked to energy, despite falling crude prices. Elevated refining margins and regional constraints have kept gasoline prices higher than expected in several markets. NPR also reported that diesel prices remained volatile in late 2025 due to global refinery outages and geopolitical disruptions, contributing to higher transportation costs.

Although crude prices are forecast to decline, the EIA cautions that geopolitical risks, supply disruptions or unexpectedly strong economic growth could shift prices upward, altering production incentives in 2026.

Implications for North American supply

A slight decline in U.S. production would not fundamentally alter North America’s supply position, but it signals a potential plateau after a decade of steady growth. U.S. output surpassed pre-pandemic levels in 2023 and set new records in 2024 and 2025. Even with a modest decline in 2026, production would remain historically high.

Analysts say the U.S. may be entering a phase where production levels fluctuate within a narrower band, shaped more by price cycles, consolidation and resource maturity than by explosive growth.

Outlook

The EIA’s December STEO will be revised as market conditions evolve, but the agency’s base case suggests 2026 will mark the first year of slightly lower U.S. crude output after four years of expansion. With producers adjusting to lower prices and varied regional trends, U.S. supply growth is expected to remain constrained, even as the Permian continues to anchor national production.

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The Nuna project, operated by ConocoPhillips, began production in December 2024. Output reached approximately 7,000 b/d in August 2025, with peak production expected at about 20,000 b/d as additional wells come online. The EIA report also highlights the upcoming Pikka Phase 1 development, operated by Santos and Repsol, which is scheduled to begin production in the first quarter of 2026. Pikka Phase 1 is forecast to reach peak output of roughly 80,000 b/d by mid-2026, accounting for nearly one-fifth of Alaska’s expected total production next year.

The EIA notes that recent well performance results from both projects show substantially higher productivity compared with the state’s existing producing wells. The agency reports that the newer wells tested at around 480 barrels of oil equivalent per day (BOE/d), whereas 78 per cent of currently producing Alaskan wells produced less than 400 BOE/d in 2023. The strong early results have led the EIA to assume continued above-average well productivity in its 2026 forecast.

Alaska’s annual crude-oil production has been in long-term decline since the late 1980s, when output peaked at more than two million barrels per day. Production has since fallen to between 440,000 and 480,000 b/d over the past decade, with year-to-year variations largely dependent on maintenance schedules, new project timing and weather-related operational challenges. The Nuna and Pikka developments are among the largest new oil projects to begin producing on the North Slope in more than a decade.

The EIA cautions that the 2026 projection is subject to uncertainty related to project timelines, well-performance outcomes and operational conditions. Delays in drilling or completion activity, supply-chain constraints or weather-related disruptions could reduce actual output below the forecast. The agency also notes that the production outlook assumes no major unplanned outages or extended maintenance cycles.

Both projects will increase oil volumes transported along the Trans-Alaska Pipeline System (TAPS), which has seen declining throughput as the state’s production has fallen. Higher volumes will improve pipeline operating efficiency, which can be affected when throughput declines because the pipeline was designed for much higher flow rates.

If the forecast increase materialises, 2026 would mark one of the largest single-year production gains in Alaska in recent decades. The EIA attributes nearly all of the projected growth to the ramp-up of the two new North Slope developments, with legacy fields expected to continue their gradual decline.

The agency will update its estimates in future monthly reports as new drilling, operational and production data become available.

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According to the IEEFA, “Higher natural-gas prices in 2025 and 2026 are the result of strong export growth that persistently outpaces U.S. natural-gas production.”

“In other words, the high demand for gas exports is also pushing up the price of the gas that supplies 40 per cent of U.S. electricity.”

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By Andrew Iraola, Trinity Manning-Pickett

The average number of active rigs per month that are drilling for oil and natural gas in the U.S. Lower 48 states has declined steadily over the past few years from a recent peak of 750 rigs in December 2022 to 517 rigs this October. The declining rig count reflects operators’ responses to declining crude oil and natural gas prices and improvements in drilling efficiencies.

Since December 2022, the oil-directed rig count has dropped 33 per cent to 397 rigs in October 2025, and the natural gas-directed rig count has declined 23 per cent to 120 rigs over the same period. Natural gas-directed rigs dropped to 96 rigs in September last year amid historically low and prolonged natural gas prices. Both natural gas- and oil-directed rig count declines stabilized in October 2025.

The traditional link between rig activity and output has weakened recently, with production at record highs despite reduced rig counts. In July 2025, crude oil production in the Lower 48 set a monthly record of 11.4 million barrels per day (b/d), and in August 2025 natural gas production set a record of 117.2 billion cubic feet per day (Bcf/d). Operators have been focusing on the most productive plays, drilling longer lateral lengths to access more hydrocarbons, and using more efficient completion techniques to ensure economic viability.

The Permian region is the largest U.S. crude oil producing region and the largest contributor to U.S. crude oil production growth despite the total number of rigs dropping 29 per cent since December 2022. Over this period, operators have increased oil production in the Permian by 18 per cent, or 1.0 million b/d.

The largest U.S. natural gas producing region is Appalachia, where the total number of rigs dropped 29 per cent while natural gas production increased 10 per cent (3.3 Bcf/d) after stagnating in 2024 during a period of relatively low natural gas prices.

In our November Short-Term Energy Outlook, we forecast Lower 48 crude oil production in 2026 to decline slightly by 0.1 million barrels per day (1 per cent) and natural gas production to increase by 0.4 Bcf/d (less than 1 per cent). We expect the West Texas Intermediate (WTI) crude oil price to average $51 per barrel in 2026, 21 per cent less than the 2025 average, and we expect the lower crude oil prices will limit oil-directed drilling activity. Conversely, we expect the Henry Hub natural gas price to rise to $4.02 per million British thermal units, 16 per cent above the average for 2025. With these price shifts, we expect that increasing production from natural gas-directed drilling will more than offset decreases in natural gas produced as a byproduct of oil-directed drilling.

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