Substantial oil surplus expected to persist through 2026

The global crude oil market underwent a notable transition between 2024 and 2025, marked by a clear decline in prices and a fundamental shift in market dynamics. Brent crude averaged around $80/bbl in 2024, but fell to $69/bbl in 2025, reflecting a year defined by heightened volatility and a substantial global oil surplus.

Policy uncertainty added to market instability in 2025. Donald Trump’s reelection as US president ushered in a tougher policy environment characterized by tariffs, sanctions, and renewed geopolitical frictions, periodically disrupting trade flows and contributing to frequent shifts in price sentiment.

Beyond political developments, the dominant structural force shaping crude prices in 2025 was the accelerated increase in production by OPEC+. As the group moved away from prolonged production restraint, large volumes of supply returned to the market. After years of coordinated cuts, the effectiveness of supply restraint in sustaining higher prices diminished, prompting a reassessment of strategy. As prices struggled to hold elevated levels, OPEC+ showed greater tolerance for lower prices while prioritizing the defense of market share and its longer-term position in the global energy system.

As a result, global oil balances in 2025 remained structurally oversupplied. According to estimates from the International Energy Agency (IEA), world oil demand increased by only about 830,000 b/d during the year, while global supply expanded by roughly 3.0 million b/d, leaving a persistent surplus. Even with ongoing geopolitical conflicts, sanctions, and precautionary inventory building providing intermittent support, supply consistently outpaced demand. Much of the excess accumulated in oil on water, Chinese crude stocks, and non-OECD inventories rather than at OECD pricing hubs, causing visible inventories to lag the implied balance and tempering downside price pressure to some extent.

Supply growth was broad-based. Non-OPEC producers contributed about 1.7 million b/d of the growth in 2025, led by Guyana, Brazil, Argentina, and the US, while OPEC+ production increased by an estimated 1.3 million b/d as curtailed volumes gradually returned to the market.

On the demand side, growth in 2025 was driven almost entirely by non-OECD economies, as OECD consumption remained broadly flat. Incremental demand was concentrated in middle distillates and petrochemical feedstocks. Looking ahead to 2026, structural efficiency gains, fuel switching, and uneven macroeconomic conditions are expected to keep global oil demand growth well below the pace of supply expansion. Lower oil prices and low US dollars may provide some offset by supporting consumption and encouraging strategic stock building in oil importing countries especially China.

Assuming no major unforeseen disruptions, the 2026 global supply-demand balance is expected to remain in surplus, with most market forecasts projecting an even larger excess than in 2025. Nevertheless, geopolitical risks remain a key source of uncertainty. Meantime, should prices fall to levels deemed unsustainable, OPEC may again adjust its policy stance, positioning itself as a stabilizing force by moderating supply growth. Another major uncertainty lies in China’s crude oil stockpiling, which is expected to continue into 2026, although the pace and scale remain uncertain. Continued strategic and commercial inventory accumulation could, however, provide a partial floor for global oil prices by absorbing excess supply during periods of market oversupply.

In contrast to the oversupplied crude market, downstream fundamentals diverged sharply. Refined product markets tightened in 2025—a trend carrying into 2026—with refining margins rebounding after 3 years of decline. This tightening was fueled by a 'pincer movement' of supply-side disruptions: intensifying Ukrainian drone strikes on Russian infrastructure and stricter Western sanctions that have effectively bottlenecked Russian diesel exports. These pressures were exacerbated by reduced system flexibility following permanent closures—notably the LyondellBasell Houston and Phillips 66 Los Angeles refineries—and the slower-than-expected ramp-up of complex units at Nigeria’s Dangote refinery.

Global economy, oil demand

The global economy was more resilient than expected in 2025. Supportive macroeconomic policies, easing financial conditions driven by expectations of technological gains, and expanding AI-related investment have provided support to demand, cushioning the impact of heightened policy uncertainty and growing trade barriers.

However, structural fragilities remain. Global trade growth has moderated following strong front-loading of merchandise trade earlier in 2025 ahead of anticipated tariff increases, though concerns over tariffs eased later in the year. Nevertheless, the impact of significantly increased tariffs continues to ripple through the global economy, affecting spending by businesses and consumers. Inflation has yet to return to target in some economies, and there are emerging signs of softening labor demand across countries.

According to the latest OECD economic outlook, global GDP growth remained around 3.2% in both 2024 and 2025, but is expected to slow to 2.9% in 2026 before stabilizing at roughly 3.1% in 2027. Inflation is anticipated to gradually reach target levels in most major economies by mid-2027.

Against this macroeconomic backdrop, global oil demand continues to expand, albeit at an uneven pace. IEA estimates that global oil demand will grow by 830,000 b/d in 2025, with a slight acceleration to 860,000 b/d in 2026. This growth remains heavily skewed toward non-OECD regions, as efficiency gains and the energy transition continue to cap consumption in advanced economies.

Global oil demand weakened sharply in second-quarter 2025, with y-o-y growth slowing to about 450,000 b/d amid heightened trade and policy uncertainty following the announcement of reciprocal US tariffs. The shock disrupted business activity across several emerging economies. Demand conditions improved markedly in the third quarter, however, with growth rebounding to around 1.1 million b/d as trade tensions eased and sentiment recovered.

Oil demand growth in 2026 is expected to benefit from lower oil prices, a weaker US dollar, and recovering industrial activity, particularly in emerging Asia. Even so, the recovery remains fragile and highly sensitive to trade policy outcomes and consumer confidence.

The composition of demand growth is also shifting. In 2025, middle distillates, including gasoil and jet fuel, account for more than half of total demand growth, supported by resilient freight activity and the continued recovery in aviation. Fuel oil demand continues to decline, reflecting substitution by natural gas and renewables in power generation, especially in the Middle East and South Asia. In 2026, growth is expected to become even more concentrated in petrochemical feedstocks. LPG/ethane and naphtha are projected to account for more than 60% of incremental demand, up from about 40% in the previous year, driven by expanding petrochemical capacity in Asia and the Middle East.

China’s oil demand growth has slowed sharply compared with historical norms. Apparent demand growth in 2025 is estimated at around 120,000 b/d, limited by the swift rise in electric vehicle adoption and a decrease in gasoline consumption. This growth slightly decreases from 2024's 150,000 b/d and is significantly lower than the average of 600,000 b/d recorded over the past decade. However, a modest recovery is expected in 2026, primarily driven by a major uptick in petrochemical feedstocks, partly offset by a sharper decline in gasoline demand.

India remains one of the fastest-growing sources of oil demand, supported by strong economic growth, rising mobility, and expanding LPG use. According to OECD Economic Outlook, India is the world's fastest-growing major economy, with projected growth of 6.7% in 2025 and 6.2% in 2026. In the Middle East, policy-driven fuel switching—particularly in Saudi Arabia—has significantly reduced oil use in power generation, limiting regional demand growth despite rising gasoline and aviation consumption.

Overall, global oil demand is still growing, but at a structurally lower and more uneven pace than in past decades. Incremental demand is increasingly concentrated in non-OECD economies and petrochemical uses, while electrification, efficiency gains, and fuel substitution continue to cap growth in transport and power generation.

Global oil supply

According to the IEA, world oil supply is projected to increase by 3 million b/d in 2025 to an average of 106.2 million b/d, followed by a further 2.4 million b/d rise in 2026 to 108.6 million b/d. Non-OPEC+ producers account for the bulk of the growth, adding 1.7 million b/d in 2025 and 1.2 million b/d in 2026, driven by expanding output across the Americas Quintet—the US, Canada, Brazil, Guyana, and Argentina. OPEC+ supply is expected to rise by 1.3 million b/d in both 2025 and 2026 under the current production agreement, assuming no further significant declines in output from sanctions-affected countries.

Following the March 2025 OPEC+ meeting, the group set out plans to begin a gradual restoration of roughly 2.2 million b/d of voluntary production cuts starting in April 2025, marking the beginning of a battle for market share. While the initial framework envisaged a measured unwinding, production increases were accelerated over the course of 2025. Taking into account the phased 300,000 b/d baseline increase for the United Arab Emirates (UAE), the bulk of these specific volumes had effectively been restored by September 2025, well ahead of earlier expectations.

By early 2026, OPEC+ shifted to a more cautious stance. After oil prices fell sharply in 2025 and forecasts pointed to a sizeable global surplus, the group’s eight core voluntary-cut participants—including Saudi Arabia, Russia, and the UAE—agreed to hold production steady through first-quarter 2026. This pause is intended to navigate seasonal demand weakness while preserving flexibility to adjust output later in the year, should market conditions improve.

Geopolitical supply risks remain a source of headline volatility, but their ability to materially tighten the oil market appears limited under current oversupply conditions. In Venezuela, the sale of crude held in floating and onshore storage and any easing of sanctions could lift output toward 1 million b/d in the near term, but a more substantial recovery or a return to production seen in 2010 would require significant, sustained investment to rehabilitate aging infrastructure. Iranian crude supply has remained broadly flat despite tighter US sanctions. While any material disruption would support prices, the overall market impact would likely be limited. Russian output has also remained largely steady at around 9.3 million b/d, with exports redirected mainly to China and India. Recent US and UK sanctions on Russian oil companies Lukoil and Rosneft could reduce Russian oil exports. On the other hand, a peace agreement between Russia and Ukraine, along with the lifting of sanctions, is expected to have a minimal effect on Russian production levels in the short term. However, it could increase price volatility within an already oversupplied market.

In 2025, average crude oil production from non-OPEC+ countries reached 54.6 million b/d, representing a 2.4% growth from a year earlier. While the supply-side balance has largely been shaped by competition between US shale oil and OPEC+, the global supply landscape has been undergoing gradual structural changes amid rapid production growth in countries including Guyana, Brazil, and Argentina.

In 2026, among the projected 1.30 million b/d of new non-OPEC+ crude oil supply, Guyana, Brazil, Argentina, and Norway are projected to be the main contributors, totaling about 1.15 million b/d. Moreover, according to a November 2025 report by Rystad Energy, Brazil, Guyana, and Argentina are expected to dominate non-OPEC+ oil production growth through 2030, potentially reshaping the global energy landscape.

Guyana’s rapid production growth is being driven by the expansion of deepwater developments in the Stabroek Block, operated by ExxonMobil (45%), Chevron (30%), and CNOOC (25%). In November 2025, Guyana’s crude output surpassed 900,000 b/d as the Yellowtail project reached its full design capacity of 250,000 b/d. Additional projects, including Uaru and Whiptail, are expected to come online in 2026–27, lifting production to about 1.3 million b/d by end-2027, with longer-term potential to reach 1.7 million b/d by 2030 as further developments such as Hammerhead and Longtail progress.

Brazil remains another major source of non-OPEC+ supply growth, underpinned by continued development of ultra-deepwater presalt fields in the Atlantic. These projects operate at breakeven costs estimated at $3–8/bbl and are characterized by long investment cycles and strong production inertia once brought online. Output growth is led by large deepwater projects supported by floating production, storage, and offloading (FPSO) units, making short-term production curtailments economically unattractive during periods of price weakness. Following an estimated 390,000 b/d increase in 2025, Brazil’s crude production is forecast to grow by a further 260,000 b/d in 2026, with total output averaging about 3.8 million b/d in 2025 and rising to roughly 4.1 million b/d in 2026.

Argentina has emerged as a growing contributor to non-OPEC+ supply as development of shale resources accelerates in the Vaca Muerta basin. The country ranks second globally in shale gas resources and fourth in shale oil resources, and drilling and completion activity continues to expand, with fracturing activity estimated to be up 18% in 2025. As infrastructure and productivity improve, Argentina’s total oil production is expected to reach about 880,000 b/d in 2026.

Norway’s production outlook is supported by sustained government backing, including generous refunds for exploration losses and regular licensing rounds. Rapid ramp-ups in the Carmen area are expected to add around 90,000 b/d of crude output in 2026.

Against this backdrop, US crude oil production growth is expected to slow. According to the latest US Energy Information Administration (EIA) monthly report, US crude output is projected to average 13.61 million b/d in 2025, up 380,000 b/d from 2024, before leveling off at 13.59 million b/d in 2026 and 13.23 million b/d in 2027. US production remains highly sensitive to oil prices, however, and sustained price weakness would likely keep new rig activity subdued, enough to outweigh ongoing increases in productivity and limit the potential for further supply increases.

Global oil inventories

According to latest IEA data, global oil stocks increased by an average of 1.2 million b/d during the first 10 months of 2025, underscoring the scale of the emerging supply overhang. A major driver of the inventory build has been oil stored at sea. Crude oil on water surged by 213 million bbl between the end of August and the end of November 2025, consisting of sanctioned barrels and recorded long-haul shipments. In contrast to the sea-based builds, on-land inventories drew by 41 million bbl in October, led by a 26 million bbl contraction in OECD stocks. Stocks at key pricing hubs (such as those in the Atlantic Basin for WTI and Dated Brent) have seen only marginal builds or remained notably low, limiting visible inventory pressure at benchmark-setting locations. Once the current inventory overhang begins to transition from oil on water into onshore storage—particularly at key pricing hubs—the price impact is likely to become more pronounced.

China’s inventory dynamics added a further layer of complexity. After two consecutive months of draws, China resumed crude stock building in November 2025. This shift followed the implementation of a new energy law in 2025, which made the holding of strategic petroleum reserves a legal obligation for both state-owned and private companies, reinforcing policy-driven stock accumulation alongside market-driven flows.

US economy, oil demand

Economic sentiment in the US rebounded quickly after a series of “breakthrough trade deals” were reached in the summer of 2025, helping stabilize activity following earlier tariff-related uncertainty. Major financial institutions, including J.P. Morgan, RSM, and Wells Fargo, project US GDP growth of around 1.8–2.2% in 2026. Fiscal policy is expected to provide additional support in the first half of the year, as the One Big Beautiful Bill Act (OBBBA) delivers tax refunds, while investment in AI continues to broaden beyond the technology sector and into the wider economy.

At the same time, inflation remains elevated at around 2.7–3%, above the Federal Reserve’s 2% target. After cutting interest rates to a range of 3.50–3.75% by end-2025, the Federal Reserve enters 2026 facing internal divisions over the appropriate path of monetary policy.

US oil consumption rebounded sharply in 2021, rising to 19.89 million b/d from 18.19 million b/d in 2020 as economic activity normalized after the pandemic. Since then, growth has moderated. Consumption averaged 20.28 million b/d in 2023, and rose further to 20.46 million b/d in 2024. In 2025, US petroleum product demand averaged 20.59 million b/d.

In 2026, total US petroleum product consumption is forecast at 20.6 million b/d, essentially unchanged from 2025. Modest gains in jet fuel and hydrocarbon gas liquids (HGL) are expected to offset declines in motor gasoline and other products.

Motor gasoline remains the largest component of US petroleum demand, but consumption has begun to soften. Demand rose from 8.05 million b/d in 2020 to a post-pandemic peak of 8.97 million b/d in 2024 before easing to 8.92 million b/d in 2025. Gasoline demand is forecast to decline further to 8.85 million b/d in 2026, reflecting ongoing improvements in vehicle fuel efficiency, increasing penetration of electric and hybrid vehicles, and longer-term shifts in commuting and travel patterns.

Jet fuel demand has shown the most sustained recovery among major refined products. Consumption increased from 1.08 million b/d in 2020 to 1.69 million b/d in 2024, rose to 1.73 million b/d in 2025, and is projected to reach 1.74 million b/d in 2026.

Hydrocarbon gas liquids continue to provide structural support to US liquids demand. HGL consumption rose from 3.23 million b/d in 2020 to 3.86 million b/d in 2025 and is forecast at 3.92 million b/d in 2026, supported by expanding petrochemical feedstock use and abundant supplies from US shale gas production.

US distillate demand has remained relatively stable, averaging 3.86 million b/d in 2025 and forecast to edge up slightly to 3.87 million b/d in 2026. Consumption remains closely linked to freight transportation, industrial activity, and agriculture.

Residual fuel oil and other minor petroleum products continue to account for a declining share of US consumption. Residual fuel oil demand averaged 0.31 million b/d in 2025 and is forecast to fall slightly to 0.28 million b/d in 2026.

US oil production

US crude oil production continued to rise through 2025, though signs of slowing momentum are emerging. Total output increased from 12.94 million b/d in 2023 to 13.23 million b/d in 2024, before reaching 13.61 million b/d in 2025. Despite a steep decline in the US rig count amid weaker oil prices in 2025, crude oil production has been only modestly impacted, highlighting the sector’s near-term resilience and continued gains in drilling efficiency. In 2026, US crude output is expected to edge lower to 13.59 million b/d, signaling a shift from rapid expansion toward a slowing down production trajectory.

Based primarily on Baker Hughes weekly drilling-rig count data, US oil rig activity steadily declined through 2025—falling from roughly the high-480s early in the year to just over 400 by yearend. Even with fewer rigs drilling for oil, production hit a record high last year, as increased well-level productivity more than compensated for the decline in rigs. Weekly US crude oil production peaked at about 13.86 million b/d in late 2025.

Production growth continues to be driven primarily by the Lower 48 states. Output from these regions rose to 11.29 million b/d in 2025 from 9.22 million b/d in 2020 and is expected to edge lower to 11.11 million b/d in 2026.

Within the Lower 48, the Permian basin remains the anchor of US shale supply. Permian crude oil production rose from 5.91 million b/d in 2023 to 6.31 million b/d in 2024 and increased further to about 6.59 million b/d in 2025. The multi-year rise reflects gains in drilling and completion productivity, longer lateral lengths, and continued infrastructure development, allowing output to grow despite a continuous decline in rig activity. In 2026, Permian production is expected to remain broadly flat at around 2025 levels. Cost competitiveness continues to underpin Permian resilience.

Outside the Permian basin, production trends are flatter to declining. Bakken output, which peaked earlier, is forecast to fall gradually to 1.18 million b/d in 2026 from 1.24 million b/d in 2024, while Eagle Ford production eases to 1.14 million b/d from 1.16 million b/d  over the same period.

Offshore and frontier production provides incremental stability. Crude output from the federal Gulf of Mexico averaged 1.91 million b/d in 2025 and is projected to rise to 2.0 million b/d in 2026. Alaska production, following years of decline, is expected to increase 12% to 0.48 million b/d in 2026, the most since 2018. The recent growth is attributable to two projects on Alaska’s North Slope: The Nuna project, owned by ConocoPhillips, and the Pikka Phase 1 project, jointly owned by Santos and Repsol.

Prices remain the key medium-term variable. While WTI prices below $60/bbl tend to curb drilling activity with a lag rather than trigger immediate output losses, a prolonged stay in the $40–60/bbl range would weigh on medium-term supply growth by restraining drilling activity and capital spending, gradually eroding the ability of productivity gains to sustain further production increases.

US refining

After years of structural margin pressure, global refining economics strengthened sharply in 2025, driven by a confluence of geopolitical, operational, and structural factors. Sanctions on key Russian oil producers, including Rosneft and Lukoil, and repeated Ukrainian drone strikes on Russian refinery infrastructure curtailed exports of middle distillates and other products from Russia. These disruptions amplified supply gaps across Europe, Asia, and Latin America, contributing to tighter refined-product balances and firmer crack spreads in major markets.

Operational setbacks at capacity and unplanned outages, such as delays at Nigeria’s Dangote refinery, and a continuation of permanent refinery closures in the US and Europe further accentuated the global supply squeeze. Collectively, these drivers elevated global refining margins in 2025, especially for middle distillates.

In this global context, US refiners maintained strong throughput and high rates of utilization, backed by strong product exports. Crude oil runs averaged 16.23 million b/d in 2024 and 16.35 million b/d in 2025, reflecting sustained operational intensity. Refinery utilization as a percentage of operable capacity averaged 91.8% in 2025, up from 90.5% in 2024. Gulf Coast refineries, advantaged by deepwater export infrastructure and competitive feedstock costs, maintained some of the highest utilization rates domestically.

Refining cash margins for the first 11 months of 2025, the latest data available, averaged $22.16/bbl for the Midwest, $13.35/bbl for the Gulf Coast, and $8.87/bbl for the East Coast, according to Muse Stancil & Co. These compare with cash refining margins of $18.19/bbl, $11.69/bbl, and $6.04/bbl respectively a year ago.

US refining capacity averaged 18.17 million b/d during 2025, compared to 18.35 million b/d for 2024. In 2026, US refining capacity will decline to 17.9 million b/d. This anticipated reduction is driven by a combination of permanent closures, partial conversions of sites to renewable fuel production, and limited greenfield additions. Looking into 2026, the decline in US refining capacity is expected to reinforce a structurally tighter downstream environment. While softer oil prices may temper crude runs at the margin, high utilization rates are likely to persist at remaining refineries. 

US oil trade

US crude oil exports averaged 3.96 million b/d over the first 10 months of 2025, down from 4.11 million b/d a year earlier. The Netherlands remained the largest destination, receiving 776,300 b/d, or nearly 20% of total exports, reinforcing Northwest Europe’s role as a key hub for US light sweet crude. Significant volumes also moved to South Korea, India, and Canada.

In contrast, US petroleum product exports strengthened further. Average products exports rose to 6.60 million b/d in the first 10 months of 2025, up 1.55% from the same period in 2024, supported by tightening global product supply. Mexico remained the largest destination at 1.07 million b/d, followed by China, Japan, and Canada.

HGL exports continue to expand rapidly. US HGL exports averaged 3.09 million b/d in the first 10 months of 2025, up 8.62% y-o-y, reflecting abundant NGL supply from US shale basins. China was the largest single destination, though shipments declined y-o-y. Propane exports averaged 1.80 million b/d, up 3.4% y-o-y, with Japan being the largest destination.

Distillate exports averaged 1.80 million b/d over the period, down 3.4% from a year earlier. Mexico received the largest share of US distillate exports, followed by Chile and the Netherlands. Gasoline exports were broadly flat at 762,800 b/d, with Mexico accounting for 57% of total volumes and Central and South America absorbing most of the remainder.

On the import side, US crude oil imports averaged 6.18 million b/d in the first 10 months of 2025, down from 6.59 million b/d in 2024. Imports from OPEC members declined from 1.0 million b/d to 856,000 b/d, while Saudi volumes eased to 268,400 b/d. Canada remained the dominant supplier, providing 3.90 million b/d, more than half of total US crude imports.

Overall, US oil trade in 2025 remains increasingly export-led. While crude exports softened modestly, rising exports of refined products continue to push excess domestic supply into global markets.

US oil stocks

US commercial petroleum inventories closed 2025 at about 1.3 billion bbl, up from 1.24 billion bbl a year ago, and are forecast to rise modestly to 1.34 billion bbl by end-2026.

Commercial crude oil inventories (excluding the Strategic Petroleum Reserve) increased to 420 million bbl at yearend 2025 from 413 million bbl at yearend 2024, and are projected to rise sharply to more than 480 million bbl by yearend 2026. The 2026 build reflects robust US crude production and lower refinery throughput.

Compared with yearend 2024 levels of 238 million bbl, US motor gasoline inventories ended 2025 higher by 2.7 million bbl. Distillate fuel oil inventories rose through 2025, increasing from 119.9 million bbl early in the year to 128.5 million bbl by December, compared with about 130.4 million bbl at yearend 2024. Jet fuel inventories were largely stable during 2025, finishing December at 44.0 million bbl—about 0.3 million bbl above the year-ago level. Residual fuel oil inventories fluctuated within a relatively narrow range over the year. In aggregate, total US oil product inventories increased modestly over 2025, reflecting net builds late in the year that partially offset seasonal draws earlier in the year.

Strategic Petroleum Reserve holdings increased to 413 million bbl at yearend 2025 from 394 million bbl a year ago, and are forecast to rise further in 2026.

US natural gas

In 2025, the average spot price of natural gas at Henry Hub was $3.53/MMbtu, a notable increase from $2.19/MMbtu in 2024 and $2.54/MMbtu in 2023, though still lower than the $6.42/MMbtu recorded in 2022. In early January 2026, Henry Hub natural gas prices exhibited volatility, fluctuating around $3/MMbtu, well below the late-2025 spikes near $5/MMbtu. The expectation of milder-than-usual temperatures for January is likely to reduce seasonal natural gas consumption, suggesting reduced upside pressure on prices in 2026 relative to 2025.

The US entered the 2025–26 winter heating season with working natural gas inventories roughly in line with last year’s levels, the highest for the start of winter since 2016. By the end of October 2025, inventories stood about 4% above the 5-year (2020–24) average, reflecting above-average injections for much of the storage refill season.

US natural gas consumption averaged 91.5 bcfd in 2025, up about 1% from the previous year, according to latest EIA data. Consumption in the electric power sector declined 3% y-o-y to 35.6 bcfd, reflecting higher renewable generation and efficiency gains. Industrial demand averaged 23.7 bcfd, accounting for roughly 26% of total domestic consumption and modestly exceeding 2024 levels. Residential and commercial demand increased in 2025, driven by colder-than-normal weather early and late in the year. OGJ forecasts total US natural gas consumption will decline slightly in 2026, averaging around 90 bcfd, as weather normalizes and non-gas generation gains continue to displace some gas burn.

On the supply side, US marketed natural gas production averaged 118.4 bcfd in 2025, while dry gas production averaged about 108 bcfd, both up roughly 4% from year-earlier levels. Dry gas output is projected to edge higher in 2026, supported by expanding pipeline capacity and strong demand from LNG exports. However, softer crude-oil drilling activity is likely to constrain associated gas output.

The Permian basin remains the primary driver of supply growth. Marketed gas production in the region increased by 10% to about 28 bcfd in 2025 and is projected to rise further in 2026 as new takeaway capacity is added, particularly in the second half of the year.

Marketed natural gas production in Appalachia increased 2% to nearly 36.4 bcfd in 2025, while output in the Haynesville rose 3% to about 15 bcfd. Production in the US Gulf of Mexico averaged about 1.9 bcfd in 2025, up over 5% from the year-ago level.

US net natural gas exports averaged nearly 16 bcfd in 2025, up from about 12.5 bcfd in 2024. In 2026, US net gas exports could rise by an additional 13% to 18 bcfd, fueled by a sustained surge in US LNG exports.

US LNG exports continue to be the primary driver of natural gas demand growth, averaging about 15 bcfd in 2025, a 26% increase from 2024. Export volumes are expected to continue rising through 2026 and 2027 as new liquefaction capacity ramps up, increasingly shaping upstream production trends and midstream investment decisions. By 2027, LNG exports could reach about 18 bcfd as additional export capacity comes online.

Global LNG market fundamentals remain supportive of high utilization rates at US export terminals, although the balance is expected to shift toward a more supply-led easing in 2026 as new global liquefaction capacity enters service.

Ongoing capacity additions in 2026 could bring total US LNG export capacity close to 19 bcfd, assuming new trains come online as scheduled. Plaquemines LNG Phase 1 shipped its first cargo in December 2024, while Plaquemines LNG Phase 2 and Corpus Christi Stage 3 began shipping cargoes in 2025 but have not yet reached full commercial operation. Both projects are expected to continue ramping up toward full output, while Golden Pass LNG is expected to begin operations by mid-2026. In addition, several US LNG export projects that have reached final investment decision are under construction, reinforcing expectations of structurally higher US LNG exports over the medium term.

US pipeline exports increased by nearly 3% in 2025, averaging about 9.4 bcfd, driven by Mexico’s growing reliance on US pipeline gas. Demand growth has been supported by rising consumption in Mexico’s power sector, which continues to outpace sluggish domestic production, as well as the addition of new cross-border infrastructure. US pipeline exports to Mexico are expected to remain strong through 2026, although short-term volatility could emerge due to pipeline constraint, including maintenance-related disruptions.

Europe continues to act as the key “swing” destination for Atlantic Basin LNG, particularly during periods of low inventories or stronger winter weather. Global LNG market fundamentals remain supportive for high US terminal utilization, although the balance is shifting toward a supply-led easing in 2026 as new global liquefaction capacity ramps up.

Pipeline exports remain a significant driver of growth, fueled by Mexico's increasing dependence on US pipeline gas. This expansion is supported by strong demand from Mexico’s electricity sector that exceeds Mexico's sluggish domestic production, alongside the introduction of new infrastructure. US pipeline exports to Mexico are projected to remain robust through 2026. Nevertheless, short-term fluctuations could arise from pipeline constraints within Mexico, such as maintenance challenges.