By Philippe Le Billon

War is costly. The ongoing American-Israeli war on Iran is already reverberating through the global economy. For most people, including American citizens, it means higher fuel prices and greater economic uncertainty.

But for a narrower group of entities, war can also be extraordinarily profitable. Chief among them are segments of the United States oil and gas industry, which have already profited from Russian President Vladimir Putin’s decision to invade Ukraine and the ensuing sanctions on Russian oil and gas exports.

Now, the escalation of hostilities between the U.S., Israel and Iran has once again rattled global energy markets. Fighting and the closure of the Strait of Hormuz — one of the world’s most important oil shipping routes — have triggered what some have described as “the biggest oil disruption in history.”

Read more: What is the Strait of Hormuz, and why does its closure matter so much to the global economy?

By early March, oil prices had briefly surged to US$119 per barrel — roughly double their level at the end of 2025. Prices have since settled at near US$100 a barrel, though volatility remains.

The escalation illustrates a familiar pattern in the political economy of fossil fuels: public costs paired with private windfalls.

The shock to global energy markets

Three months ago, few analysts expected 2026 to be a particularly profitable year for fossil fuel producers. Global supply was expanding rapidly and U.S. gas prices were expected to fall below US$3 a gallon.

Production growth in the U.S., Canada, Brazil and Argentina was colliding with weaker demand growth and the ineffectiveness of sanctions on exports from Russia, Iran and Venezuela. Many analysts warned of an emerging glut that could push prices downward. The International Energy Agency, for instance, projected a potential global oil surplus of nearly four million barrels per day in 2026.

That outlook changed abruptly following the U.S.-Israeli attack on Iran and the country’s retaliatory attacks on energy infrastructure and tanker traffic through the Strait of Hormuz, a strategic chokepoint that normally carries roughly one-fifth of the world’s traded oil and natural gas.

Even a partial disruption carries immediate consequences.

Though the strait has been a cornerstone of U.S. and world energy security for more than 60 years, the Donald Trump administration apparently underestimated the possibility that the Iranian regime would blockade it and pummel U.S.-allied countries in the region.

For consumers and most businesses, such price spikes function as a tax. Higher energy costs ripple through transport, food production, manufacturing and household budgets. American drivers feel the impact at the pump, while industries dependent on fuel or petrochemicals see their operating costs climb.

The hidden household costs of war

Estimates suggest that for every increase of US$10 per barrel, additional fuel costs amount to roughly US$560 per year per American household, including costs embedded in goods and services.

If prices remain at around US$86 instead of the expected US$51 forecast for 2026, the added burden could reach about US$2,000 per household annually.

These figures do not include the direct military expenditures, which were conservatively estimated at US$11 billion for the first week of strikes against Iran.

Even military spending of US$200 million per day (10 times less than the highest estimates at the current intensity) would amount to an additional cost of US$541 per household annually.

In short, a prolonged war combining high energy prices and sustained military expenditures would likely amount to between three to four per cent of the median U.S. household expenditure — roughly half of what many families spend annually on food or health care.

Lessons from recent wars

Recent history offers revealing precedents.

The costs of the Iraq War (2003 to 2011) for Americans has been estimated at about US$1.2-3 trillion in total long-term costs, equivalent to about US$16,700 to US$41,750 per household in current U.S. dollars. Yet the war did achieve the goal of reopening access to Iraqi oil fields for American oil companies.

More recently, the invasion of Ukraine by Russia cost an estimated one per cent of global GDP in 2022 and added 1.5 per cent to global inflation in 2022-23. Ukraine, of course, paid the largest price for the war, but direct impacts in Europe amounted to about 1 trillion euros.

Much of these costs ultimately translated into profits for oil and gas companies, especially liquefied natural gas (LNG) companies from the U.S. and producers in Australia and the Gulf states.

Profits on a single LNG shipment from the U.S. to Europe increased fivefold from about US$17 million to US$102 million.

A similar dynamic is now unfolding again.

Who really benefits from rising oil prices?

This time, with major Gulf states themselves exposed to the conflict, U.S. and other exporters less directly affected by the war may have even greater room to increase profits. American LNG companies could see windfalls approaching US$20 billion per month.

The main lesson is that petro-states, including Iran, Russia and the U.S., don’t hesitate to go to war partly because they believe oil revenues will bail them out, if not further enrich them.

In fact, in seeking to justify the attack on Iran and the continuation of the conflict, Trump argued that “the United States is the largest oil producer in the world, by far, so when oil prices go up, we make a lot of money.”

This, of course, depends on who “we” refers to. The populations of most petro-states have paid dearly for the wars involving their countries, whether it’s been Angola, Chad, Iraq, Libya, Nigeria, Russia, Syria and now Iran.

The U.S. has fared much better economically, but the gains have been mostly for its companies, not its population. Higher oil and natural gas prices generate enormous revenues for U.S. oil producers and LNG exporters along the Gulf Coast as global gas markets tighten. Investors and shareholders in these sectors stand to gain from rising margins and market valuations.

American households, however, face the opposite effect. Fuel prices rise. Inflationary pressures intensify. Transport and heating costs increase.

The gains accruing to producers are therefore not only partially financed by the most import-dependent countries with the least strategic reserves but also by low-income households who are stuck in a carbon-intensive economy they can least afford to escape.

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By Naveena Sadasivam

For more than a decade, the clean energy economy has been on a steep growth trajectory. Companies have poured billions of dollars into battery manufacturing, solar and wind generation, and electric vehicle plants in the U.S., as solar costs fell sharply and EV sales surged. That momentum is set to continue surging in much of the world — but in the United States, it’s starting to stall.

According to a new report from the clean energy think tank E2, new investment in clean energy projects last year was dwarfed by a cascade of cancellations for projects already in progress. For every dollar announced in new clean energy projects, companies canceled, closed, or downsized roughly three dollars’ worth. In total, at least roughly $35 billion in projects were abandoned last year, compared to just $3.4 billion in cancellations in 2023 and 2024 combined.

“That’s pretty jarring considering how much progress we made in previous years,” said Michael Timberlake, a director of research and publications at E2. “The rest of the world is generally doubling down or transitioning further, and the U.S. is now becoming increasingly combative and antagonistic towards clean energy industries.”

Timberlake said the Trump administration’s attacks on renewable energy are the main driver of the slowdown. Companies began pulling back their investments shortly after the November 2024 election, when a victorious Trump telegraphed that he would promote fossil fuels over solar, wind, and other clean energy technologies. For instance, TotalEnergies, the French oil-and-gas giant, paused development of two offshore wind projects in late November 2024, citing uncertainty after Trump’s election. The company has not restarted the projects since.

Trump followed through on those promises once in office: One of his first actions in office was to pause leasing and permitting for offshore wind. The freeze resulted in several wind developers indefinitely pausing or abandoning their projects while lawsuits trickled through the courts. (Federal judges have issued judgments in favour of the wind companies in recent months.) Trump’s administration also pulled billions of dollars in funding for a range of clean energy projects and cancelled or retooled Biden-era policies favourable to the industry, such as energy-efficiency measures, IRS tax guidance, and loans for a transmission line expected to carry solar and wind power.

Congress, at the behest of Trump, also passed the “One Big Beautiful Act” over the summer. In addition to sunsetting lucrative tax credits for renewable energy production, the law hammered the electric vehicle industry from multiple sides: It ended investment credits supporting the buildout of battery manufacturers, and simultaneously nixed the $7,500 tax credit available to American consumers who purchase EVs.

Timberlake cautioned against pinning clean energy’s disappointing year on any one policy. While the One Big Beautiful Act was the “biggest signifier” of the shift, “the overall policy and regulatory attack” is to blame for the glut of project cancellations, he said. “It’s not an environment that encourages more investment because no one knows what six months from now will look like.”

Electric vehicle and battery manufacturing have been hit the hardest over the past year. Each sector lost roughly $21 billion in investment over the past year, according to E2’s analysis, which includes some overlapping projects that serve both purposes. The industries also lost an estimated 48,000 potential jobs. These two industries likely lost the most investments because they had been growing the fastest in recent years, meaning they had more projects in the pipeline to cancel or downsize once President Trump was elected. The EV industry’s outlook, in particular, changed once Congress repealed consumer tax credits made available by former President Joe Biden. That, along with the general policy uncertainty, led to automakers revising their expectations for EV demand in the U.S. and reallocating their investments accordingly.

Some states were hit harder than others. In 2025 alone, Michigan lost 13 clean energy projects worth $8.1 billion — more than twice as many as any other state, due to its role as the capital of the U.S. auto industry. Illinois, Georgia, and New York also lost billions of dollars in investments.

Many automakers that scaled back electric vehicle plans last year redirected those investments rather than abandoning them outright. Ford, for example, had originally planned to build all-electric commercial vehicles at its $1.5 billion Ohio Assembly Plant in Avon Lake. But after revising its EV ambitions, the company pivoted the facility toward gas-powered and hybrid vans. Because Ford did not scrap the plant altogether, Timberlake said, facilities like Avon Lake could still be retrofitted for electric vehicle production if market conditions and policy outlooks improve.

“The silver lining view is they’re hopefully maintaining those facilities so that when there is certainty, those factories will still be available for making EVs down the road,” said Timberlake.

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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 New England Clean Energy Connect (NECEC) line, a 1,200-megawatt high-voltage direct current (HVDC) transmission project, began delivering electricity on January 16, 2026, after nearly a decade of planning, regulatory reviews, legal challenges and construction delays. Designed to carry firm hydroelectricity from Hydro-Québec into the Independent System Operator-New England (ISO-NE) grid, the line is widely positioned as a key element in decarbonising the region’s power mix and lowering wholesale electricity prices.

Officials in Massachusetts and Maine welcomed the start of commercial operations with rhetoric emphasising affordability, reliability and climate benefits. In a press release celebrating the milestone, Massachusetts Governor Maura Healey said the project will deliver around 20 per cent of the state’s electricity needs and generate more than US$3.3 billion in net economic benefits through lower wholesale costs over the life of long-term contracts with Hydro-Québec.

“Today power is flowing to Massachusetts through the New England Clean Energy Connect transmission line,” Healey said, noting that the project has been completed through “planning, partnerships and perseverance.”

But just days after NECEC began commercial operation, the region was hit by Winter Storm Fern — a blast of Arctic cold that pushed both Canadian and U.S. electricity systems to the brink of peak demand. During the cold snap, power flows on the NECEC link abruptly stopped on January 24 and remained offline until January 26 after Québec restricted exports to meet higher domestic electricity demand as temperatures plunged.

The interruption meant that rather than importing electricity from Hydro-Québec, the ISO-NE grid actually exported power back to Canada, a reversal that lasted from the afternoon of January 24 through the evening of January 25.

That reversal highlighted the very challenge NECEC is meant to address: tight energy markets during winter months when natural gas pipeline capacity is constrained and demand for power and heat surges. During the flow interruption, New England turned to petroleum-fired generation, producing more electricity from oil than natural gas — a less carbon-efficient outcome and a throwback to older fuel sources that clean energy advocates hoped to displace.

Industry observers have been quick to point out that extreme weather conditions — the same conditions that stress grid reliability — also stress water supplies behind major hydroelectric systems, potentially limiting Québec’s ability to export power precisely when it’s needed most. Reporting from Energywire noted that some analysts view the outage as a test of whether cross-border links like NECEC can deliver under peak stress, especially as New England faces growing electricity demand and a shifting generation mix.

Hydro-Québec has acknowledged the interruptions but framed them as a function of record cold and extremely high demand within Québec itself, where much of the population relies on electric heating. A spokesperson for the company told power sector outlets that deliveries were expected to resume and emphasised contractual protections that mitigate ratepayer exposure to shortfalls.

Still, critics argue the early weather test underscores the need for a diversified portfolio of generation resources. Dan Dolan, president of the New England Power Generators Association, told E&E News that while NECEC can help reduce gas burn and emissions under normal conditions, “there is no single answer that will stabilize the system” during peak stress without a mix that includes local generation, storage, renewables and fossil backstops.

Proponents counter that NECEC’s strengths are structural and long-term. Analyses from project backers like Avangrid and Iberdrola — which built the line — point to tens of millions in tax revenue for host communities and savings for ratepayers, who benefit from stable, long-term pricing tied to hydropower contracts.

The project’s ability to reduce New England’s reliance on volatile fossil fuel markets comes as natural gas prices and price volatility remain high, particularly in winter, and as regional policymakers pursue ambitious decarbonisation goals.

Despite the early operational hiccup, NECEC represents one of the largest pieces of cross-border energy infrastructure in North America and a model of regional cooperation between Québec’s hydro-abundant system and U.S. utilities seeking cleaner, more reliable power sources.

Whether it will deliver under peak stress conditions remains an evolving story — one that utilities, regulators and market observers will be watching closely as winter continues and as the region’s energy transition accelerates.

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By Jake Bittle

Since his presidency began last year, Donald Trump has embarked on an all-out campaign to destroy the nation’s nascent offshore wind industry. He has halted all wind lease sales in federal waters, issued stop-work orders for nearly-completed wind farms, and told oil industry executives that his “goal is to not let any windmills be built.” Last month, his Interior Department said it would terminate five major wind farms that are under construction in the north Atlantic Ocean, citing vague “national security” issues. These wind farms would together generate around 5.6 gigawatts of power, enough to supply around 4 million homes.

Trump’s actions have all but destroyed the U.S. offshore wind industry, which was already facing significant economic challenges during the Biden administration. While developers behind the terminated wind farms recently secured court orders allowing them to complete construction, other potential wind installations have been scrapped, and investors are retreating from offshore projects. Even as solar energy continued to grow at a rapid clip in 2025, wind saw virtually no growth in the United States.

That’s not just bad for the climate — it will also make it harder to keep the lights on in the U.S. northeast.  The nation’s densest region is counting on dozens of new wind farms to meet rising power demand; the stretch of coastal states from Maine to Virginia have collectively committed to buy more than 45 gigawatts of offshore wind power by 2040, almost ten times more than the five nearly-complete projects will provide. The region does not have many other good options for filling the gap. Without wind, residents of states like Massachusetts and New York will pay more money for dirtier fuel. The energy future of these states now hinges on whether they can tempt offshore wind developers back to a market that the federal government has just spent a year destroying.

“The market is at less than zero confidence right now,” said Kris Ohleth, director of the Special Initiative on Offshore Wind, an independent organization that supports the buildout of the industry.

The country’s first crop of major offshore wind farms has been a generation in the making. Developers have been trying to sink steel turbines onto the ocean floor since the turn of the century, but their projects collapsed amid high costs and community opposition. It wasn’t until the Obama administration that the federal government laid the groundwork for wind leases in federal waters near Long Island, conducting landmark studies that identified ocean zones where wind is strongest and environmental risks are lowest. That attracted major renewable energy developers like the Danish firm Ørsted and the Norwegian company Equinor, who leased territory in the north Atlantic and sketched out billion-dollar wind farms.

Even before Trump, these projects were on shaky financial ground. Ørsted and its peers signed power contracts with states including New York, New Jersey, and Massachusetts before the COVID-19 disruptions, but pandemic-driven shortages and the supply-chain chaos of Russia’s war on Ukraine drove up costs for construction materials like steel and copper. State governments also demanded developers put up more money for port improvements and onshore manufacturing jobs.

At the same time, developers encountered a wave of opposition from fishermen’s groups, conservative activists, and shoreline residents concerned about their ocean views. Prominent Republicans like U.S. Representative Jeff Van Drew of New Jersey championed these groups. The opposition filed several lawsuits that slowed down the permit process for a few major wind farms, with one suit even reaching the Supreme Court.

“These were new, first-of-a-kind-in-the-U.S. permits, and we were trying to improve the permitting process as we were going along,” said Elizabeth Klein, who led the Interior Department’s Bureau of Ocean Energy Management under former President Biden. (Klein said that by the end of Biden’s term the average environmental permit review took between two and three years, much longer than the more established procedure for offshore oil and gas.)

After the 2024 election, Trump’s sudden assault on the industry destroyed what little investor confidence was left. Even though several companies still hold leases that give them the right to build wind farms in federal waters, the industry has frozen in place. Other than the handful of major wind farms that are suing Trump for permission to finish construction, there are no large-scale projects in the pipeline. This freeze stands in stark contrast to the fate of solar energy, where installed capacity grew by 27 percent in 2025.

“In order for someone to get a commercial gleam in their eye, you need alignment with the federal government, the state government, and the market,” said an energy consultant who has advised offshore wind developers. “That’s gone, and it makes projects literally impossible. There’s no beating around it.” (The consultant requested anonymity in order to speak frankly given federal government backlash against the wind industry.)

Though the Biden administration focused primarily on the north Atlantic, it also auctioned federal wind leases in places like South Carolina, Louisiana, and Oregon. Klein believes that those states may now turn away from offshore wind given the market turmoil — and also because they have increasing access to alternatives like solar and cheap natural gas.

The Northeast does not have the same luxury. It is too dense and too cloudy to allow for large-scale solar farms, and other baseload power sources like nuclear will be hard to site, given population density and local opposition.

“There’s no other energy source coming to save them,” said Klein.

The situation is most acute in New England. In a report analyzing decarbonization scenarios, the energy nonprofit Clean Air Task Force found that offshore wind would have to make up almost half of all power generation by 2050 for the region to fully decarbonize. But it’s not just that these states need offshore wind to ditch fossil fuels. Experts also say that, with federal support, wind could be both the easiest-to-build and the most reliable power source for New England. That’s in part because communities across the region have mobilized against new gas pipelines and power plants. Furthermore, the region’s winter power needs will increase as more homes switch away from heating oil and begin to use electric heat pumps instead. Offshore wind turbines also fare much better in cold weather than power plants fuelled by natural gas and oil.

“For all the difficulties, building [wind] and interconnecting is easier than almost anything else you would do,” said John Carlson, the senior Northeast regional policy manager at Clean Air Task Force, which co-produced the report on New England’s decarbonization. “At the end of the day, this has to happen. There isn’t another option.”

The first prerequisite to a revival of the industry would be a cooperative federal government. Given how long it takes to build a wind farm, many experts believe that some form of permitting reform will be necessary to tempt investors back into the market. Clean energy lobbyists and oil industry groups alike have endorsed bills that would prevent presidents from pulling already-approved permits, but Congress has yet to pass one. The most recent negotiations collapsed after Trump’s attempt to terminate the five major wind farms. (Beyond the five nearly-complete wind farms, there are several more projects that have obtained most or all of their federal permits, and their developers may just try to wait out the administration.)

But there are other constraints, one of which is money. Industry insiders say global firms like Ørsted and Equinor have little desire to make further investments in the U.S. market, though they’re still holding on to their federal leases in windy sections of the ocean. There may be smaller developers who may want to take the leases off their hands. Before the current crop of massive European-built wind farms, smaller American developers tried to build minor farms along New England’s coast. These projects collapsed amid local opposition, but it’s possible that American energy developers may now want to get back into the fray. (Both Ørsted and Equinor declined to comment on their future investment plans.)

The problem is that these smaller companies will have a harder time borrowing the billions of dollars it takes to build big wind farms, and they may need to charge more money for the electricity they produce. Experts say that state governments in the region will likely need to grease the wheels for investment by putting up taxpayer money rather than asking developers to bear all the costs.

“The ability for the state to de-risk the investment environment is enormously valuable in terms of making Maine an attractive state,” said Jeremy Payne, a lobbyist for the government affairs firm Cornerstone and the former director of Maine’s renewable energy trade association. Payne said that the state could attract investment by training wind workers or coordinating with neighboring states on transmission corridors for wind power cables, taking some of the work off the developer’s hands.

Infrastructure is also a key constraint. The first wind projects required states to spend hundreds of millions of dollars on port upgrades and onshore construction. Massachusetts has spent well over $100 million to upgrade the old whaling port of New Bedford so it can serve as a staging area for massive wind turbine blades that can stretch the length of a football field. New York built a similar wind staging area along the harbor in Brooklyn.

But this infrastructure is still not sufficient to support wind development on the scale that the region needs. The New Bedford port is just a quarter of the size of an offshore wind terminal under construction at the port of Rotterdam in the Netherlands, and it may be too narrow to accommodate some large vessels. Massachusetts is planning to build a second facility in Salem — but Trump canceled a $34 million grant for that project, and its future is now uncertain.

The states along the eastern seaboard must invest now in order to make it easier for future projects to get off the ground. That includes upgrading transmission infrastructure, investing in workforce training, and expanding ports to accommodate larger turbines.

“We understand that whatever we’re doing now, we’re doing for 2029 or maybe 2030,” said Bruce Carlisle, the managing director of offshore wind for the Massachusetts Clean Energy Center, a quasi-state agency that supports the buildout of renewable energy. “We want to make sure we’re balancing state investment with realistic timelines.”

At the same time, Carlisle said states may not get all they originally wanted from wind projects. In the first go-round, states pushed developers to hire local workers for manufacturing and assembly, but Carlisle now says that the states may need to walk some of those requests back, because they will further raise costs for developers. Instead, states may need to let developers source labor and materials from Europe — which has built out far more offshore wind and therefore has a developed labor force and supply chains already — rather than demanding they build out a U.S. manufacturing base.

Given that President Trump has refused to issue new permits for offshore wind, it will likely be impossible for states like New Jersey and Massachusetts to achieve their current procurement targets on time. In the rest of the country, planned projects may never materialize. But offshore wind will still dominate the Northeast power grid in the long run, even if future projects are more expensive and require more state support. For all the blows the industry has taken, the region just doesn’t have good alternatives.

“I think it’s more a question of ‘when’ than ‘if,’” said Ohleth.

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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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By Jorge H. Sanchez-Perez

The American invasion of Venezuela — along with fresh threats to annex Greenland — provide the world with a unique opportunity to perform a post-mortem examination on what was once known as the international rules-based legal order.

This legal order was based on rules enshrined in the United Nations Charter of 1945. Its collapse creates uncertainty that requires careful consideration from all those interested in world peace.

Read more: Trump’s intervention in Venezuela: the 3 warnings for the world

First, however, it’s important to understand what legal orders are and how they can collapse.

Social rules come in different forms — some might be religious, some moral. But complex political communities tend to be ruled by another set of rules, legal ones.

Legal rules tend to be organized in what are commonly called legal orders, and these orders guide the actions of members of the political communities in their everyday lives. One goal of most legal orders is, usually, co-ordination among those who are part of a social group.

When we think about legal orders, we usually focus on the ones that are closer to our political communities, such as those connected to our cities, provinces and states. But there’s one legal order that tends to be ignored more often than not — the international legal order.

International law

One defining feature of international legal orders is that they are far removed from people within their own political communities, so negotiations to establish shared rules are usually carried out by representatives of large states or other powerful political entities.

Even though the international legal order feels isolated from everyday rules — like city laws telling us which side of the road to drive on — it shares the same basic features that make any system of co-ordination work.

One key feature is meeting the expectations of the people within a political community. For a legal order to last over time, it must do this. In other words, because legal orders are systems of co-ordination, they tend to endure as long as their rules are expected and accepted, even if those rules are unjust.

Although some people believe that a law must be just to count as law, that view is hard to sustain when we look at the past few hundred years of human history. Many periods offer clear examples of both domestic and international legal systems that upheld deeply unjust and morally troubling positions.

Yet it would be difficult to argue that there was no legal order in places like the Ottoman Empire or Nazi Germany. In both cases, genocide — among the gravest moral failures imaginable — occurred within functioning legal systems. This suggests that legal orders can persist even while enabling repeated immoral actions.

History also shows, however, that legal orders do collapse, and often more quickly and more frequently than many might expect.

The Ottoman Empire and Nazi Germany, for example, ceased to exist a long time ago. From a broader historical perspective, the legal order of the Roman Republic in the second century BCE no longer exists and bears little resemblance to the system governing modern Rome within Italy today.

Like the other legal orders mentioned, the post–Second World War order increasingly looks like a relic rather than a binding reality — a fact we must clearly recognize if we hope to save some of its positive features.

Fundamental rights

After the Second World War, one of the main agreements among most political communities around the world was that the previously held right to wage wars against other countries was no longer acceptable. Sovereignty consequently became one of the cornerstones of the international legal order.

This was enshrined in Articles 1 and 2 of the United Nations Charter. The logic was simple: as the charter’s preamble notes, repeated wars had brought immense suffering to people entitled to fundamental rights based on their dignity, worth and equality. As a result, this new order abolished the right of political communities to wage war for any reason.

In practice, however, this order rested on a watered-down version of that ideal. Even when sovereignty and human rights were violated via military action, the appearance of an aim to protect them had to be maintained. Powerful states could breach these principles so long as they preserved the illusion that they were attempting to uphold and safeguard sovereignty and rights.

This unspoken rule — that power could override law if the façade remained intact — underpinned the international legal order from 1945 to 2023.

As the world watched the assault on Gaza unfold — deemed a genocide by the United Nations — many western political communities that had helped build the post-war legal order abandoned even the pretense that sustained it.

Once the illusion of respect for sovereignty and human rights collapsed, the system lost a key element that had kept it functioning. This is why I’ve argued previously that the rules-based international order went to Gaza to die at the hands of those who created it.

Annexation made easy

Unlike U.S. President George W. Bush’s war in Iraq, which was framed by American diplomats as defending human rights, Donald Trump’s invasion of Venezuela and the capture of Nicolás Maduro weren’t presented as respecting any lofty principles.

His actions were grounded on the views that the U.S. has a claim to Venezuela’s oil. The intervention was driven by economic interests and hearkened back to the the Monroe Doctrine, an 1823 U.S. policy that promoted American dominance of the Western Hemisphere.

The events in Venezuela suggest the post-1945 international legal order, which emphasized sovereignty and fundamental rights, has been replaced by one more like the pre-Second World War system, when nations could go to war for almost any reason.

Read more: Trump’s squeeze of Venezuela goes beyond Monroe Doctrine – in ideology, intent and scale, it’s unprecedented

Under the legal order now in place, Canada and Greenland could easily be the next targets of American annexation. Similarly, Taiwan could be annexed by China and Ukraine by Russia.

What the world is witnessing now is the international rules-based order being stripped of whatever value it once had. It is time to accept this reality if we are to build a better international order next time.

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By Mitchell Beer

Donald Trump’s weekend raid on Venezuela has analysts debating how quickly the country can restore some of its past oil production, how much that activity will benefit Trump’s fossil industry donors and allies, and whether the White House agenda is about extracting more oil or asserting global power in a glutted oil market.

Meanwhile, national leaders from Colombia and Cuba to Canada, Greenland, and Denmark are reacting to a new geopolitical reality as Trump’s agenda for Western Hemisphere domination comes into sharper focus.

Venezuela holds the largest oil reserves in the world, at an estimated 303 billion barrels. At the media conference Saturday where he announced that U.S. forces had kidnapped Venezuelan President Nicólas Maduro and his wife, Cilia Flores, to stand trial in New York, Trump was clear about the plan, though not so much about how he expected to deliver on it.

“We’re going to have our very large United States oil companies, the biggest anywhere in the world, go in, spend billions of dollars, fix the badly broken infrastructure, the oil infrastructure, and start making money for the country,” he told media.

If that happens, it’ll also deliver a financial windfall to Trump’s billionaire supporter Paul Singer, co-CEO of Elliot Investment Management, which indirectly owns Citgo—a U.S.-based subsidiary of Venezuela’s state oil company that in turn owns three refineries on the U.S. Gulf Coast, 43 oil terminals, and a network of more than 4,000 independently-held gas stations, Popular Information reported Monday.

A New Balance of Power

Trump’s top-line message ricocheted through North American fossil fuel markets on Monday. Canadian oil sands giants Suncor Energy, Cenovus Energy, and Canadian Natural Resources Ltd. initially lost 4% to 7% of their share value before recovering somewhat through the day, CBC reports. That was because “refineries on the U.S. Gulf Coast are set up to process heavy crude like that produced in Alberta’s oil sands and in Venezuela,” The Canadian Press explains. “U.S. sanctions on the South American country have meant virtually none of its supplies go to the U.S. market today.”

But “if those restrictions were lifted, then Canada may have more competition right away in terms of Venezuelan oil that now technically can access the U.S. Gulf Coast,” Jackie Forrest, executive director of the ARC Energy Research Institute, told the news agency.

In the U.S., shares in Chevron Corporation, which operates in Venezuela, and ExxonMobil, which did in the past, moved “sharply higher”, The Associated Press writes, with analysts at JPMorgan projecting Monday that the U.S. takeover could “reshape the balance of power in international energy markets.”

And yet, “not much has changed in oil markets near-term and it could be months or even years before the fate of sanctions and Venezuela’s production shakes out,” CP writes, citing Dane Gregoris, managing director of the oil and gas research group with the Enervus analytics platform.

“Political changes happen quickly, but industrial changes happen very slowly,” he said.

Despite many years of international sanctions and poor maintenance of its oilfield infrastructure, “some oil industry analysts believe Venezuela could double or triple its current output of about 1.1 million barrels of oil a day and return the nation to historic production levels relatively quickly,” AP adds. “If or when that would happen, however, is more complex. Many energy analysts see a longer and more difficult road ahead.”

Bloomberg opinion columnist Javier Blas says Trump has set out to build “his very own oil empire,” with political sway over available reserves in the U.S., Latin America, and Canada. “Like it or not, all of them are living under the ‘Donroe Doctrine’—an increasingly belligerent Washington’s sphere of influence over the Americas,” he writes. “Together they account for nearly 40% of the world’s oil output” and 20% of global reserves, giving him “an economic and geopolitical lever no U.S. president has had since Franklin D. Roosevelt in the 1940s.”

Citing two sources from outside that sphere of influence, a U.S.-sanctioned Russian oligarch and a Kremlin envoy, Blas opines that “having de facto control of the Western Hemisphere’s petroleum wealth is a geopolitical game changer. For decades, U.S. military adventurism was constrained by the impact of any war on energy costs. Today the White House has primacy over oil-producing allies and adversaries alike—whether it’s Saudi Arabia or Iran, Nigeria or Russia.”

Fossils May Not Play Along

But not all analysts agree that U.S. fossil companies are likely to play along.

“For weeks, Trump has been courting oil companies, promising them a glorious return to Venezuela,” after the country “seized private assets decades ago in its push to nationalize the petroleum industry,” Politico Power Switch writes. The Maduro/Flores kidnapping “comes as a down payment of sorts to the industry—though not necessarily one that the U.S. oil majors are eager to collect.”

U.S. fossils have “longed” to re-establish their operations in petrostate Venezuela, Politico says, and Trump cabinet secretaries Chris Wright and Doug Burgum are now arm-twisting them to do just that. But “rebuilding decayed oil fields in a still socialist-led country amid a global oil glut is few people’s idea of a good time,” the news analysis states. “It’s likewise unclear how the U.S. would guarantee the safety of employees and equipment, how companies would be paid, and whether oil prices will rise enough to make Venezuelan crude profitable.”

Moreover, as the global oil industry “continues to stare down the prospect of a broad transition to renewable energy,” it’s “not obvious that future markets can justify a surge of investment in Venezuela,” says Grist staff writer Jake Bittle. “While there are buyers for additional oil that could be pumped in Venezuela—some of them on the U.S. Gulf Coast—experts say a total revival on the order that Trump is promising may not be in the cards.”

The market for heavy oil from Venezuela (or from Alberta, for that matter) is limited, and while analysts have different ideas about when global oil demand will start to decline, they mostly agree that the peak is coming, Bittle writes. “At that point, there may no longer be sufficient demand to keep exploiting new oil fields, no matter how large. And given that it will take many years just to update the infrastructure that will allow for increased oil production in Venezuela in the first place, investors may decide that the juice is not worth the squeeze.”

‘Northwards of $100 Billion’

On LinkedIn Monday, Patrick Galey, head of fossil fuel investigations at Global Witness, said it would cost “northwards of $100 billion just to get Venezuelan output back up to two million barrels per day (still less than half of Texas’ daily production). And the only player still there, Chevron, is notoriously cost averse these days.”

More likely, Galey adds, “this is a play to boost oil prices at a time when the world faces a 3.8-million-barrel-per-day oversupply (yes, really) of a product, demand for which is in terminal decline and U.S. production productivity of which has been trending downwards for a while now.”

Maria Pastukhova, programme lead, global energy transition at the London- and Brussels-based E3G energy transition think tank, agreed that restoring Venezuela’s oil infrastructure would be “slow, expensive, and risky” at a time when “the global oil market is well supplied, demand growth is fading, and China is signalling an approaching demand peak.” That means “control over Venezuelan oil is less about adding supply and more about geopolitical optionality. A U.S.-aligned Venezuela is unlikely to unleash a wave of new production, but it would significantly reduce access for China, Russia, and Iran, weakening their geopolitical leverage.”

Small wonder that the loss of a key ally had China strongly condemning the U.S. action Saturday. In a foreign ministry statement, Beijing said it was “deeply shocked by and strongly condemns the U.S.’s blatant use of force against a sovereign state,” the Globe and Mail reports. China described the raid and kidnapping as “hegemonic acts” that “threaten peace and security in Latin America and the Caribbean region.”

Trump’s Emerging Doctrine: ‘Strike, Then Coerce’

Over the last 72 hours, multiple analysts have cast Trump’s action as tangible proof of a new geopolitical doctrine. The raid in Caracas “capped a month of aggressive military action by Trump that also included targeting alleged extremists in northern Nigeria, attacking Islamic State militants in Syria, and threatening to restrike Iran,” the Wall Street Journal reports—not to mention repeated, controversial air strikes on fishing boats alleged to be carrying drugs in the Caribbean Sea and East Pacific Ocean.

“The flurry of military moves underscored Trump’s reliance on the surprise use of force during his second term,” the WSJ adds, “an emerging doctrine to strike and then coerce that is likely to be sorely tested as the White House seeks to press Venezuela and other countries he targets to comply with his demands.”

Within not many hours, Trump was threatening additional targets, including Colombian President Gustavo Petro, Cuba, Mexico, and Greenland. Over the weekend, he claimed Cuba “is in a lot of trouble,” while the U.S. “needs” Greenland for the sake of national security.

Trump’s statements had Mexican President and former IPCC scientist Claudia Sheinbaum categorically rejecting the U.S. intervention. “Unilateral action and invasion cannot be the basis for international relations in the 21st century,” she said in a three-page statement Monday. “They lead neither to peace nor to development.”

In Copenhagen, Greenlandic Prime Minister Jens-Frederik Nielsen and Danish Prime Minister Mette Frederiksen told Trump to stop threatening a takeover of Greenland, with Frederiksen warning that an attack on the semi-autonomous Danish territory would mean an end to the NATO military alliance.

“If the United States chooses to attack another NATO country militarily, then everything stops,” she told Danish TV Monday. “That is, including our NATO and thus the security that has been provided since the end of the Second World War.”

Canada’s former UN ambassador Bob Rae told CBC there’s “absolutely no room for complacency” in Ottawa’s response to the attack, adding that Trump claiming ownership over the entire Western Hemisphere amounts to “nonsensical” overreach.

“What the hell is this?” he asked. “You can’t unilaterally declare that you have unique jurisdiction over an entire half of the world, and all the people who live in that half of the world just have to put up or shut up.”

But Prime Minister Mark Carney’s statement Saturday was far more cautious, leading with a critique of Maduro’s “brutally oppressive and criminal regime” before calling for a “peaceful, negotiated, and Venezuelan-led transition process” that respects the democratic will of the country.

“In keeping with our long-standing commitment to upholding the rule of law, sovereignty, and human rights, Canada calls on all parties to respect international law,” Carney said. “We stand by the Venezuelan people’s sovereign right to decide and build their own future in a peaceful and democratic society.”

With Carney meeting European and British leaders in Paris to discuss security guarantees for Ukraine, foreign policy experts are urging the countries to “send a strong signal” against Trump’s action, the Globe and Mail reports.

“If we’re seen as condoning this, it’s giving a hunting licence to Putin and quite frankly Xi when it comes to Taiwan,” said Fen Hampson, chancellor’s professor and professor of international affairs at Carleton University. “It is not in our interest to revert to the law of the jungle, and it is not in the interests of the other countries that are meeting in Paris to revert to the law of the jungle. It’s time to send a message to Washington: We don’t like this.”

“There’s safety in numbers” for western leaders to defend “fundamental principles such as sovereignty, international law, and the non-use of force, unless there’s a credible reason, including self-defence, to intervene militarily in another country’s affairs,” agreed international affairs professor Roland Paris, director of the Graduate School of Public and International Affairs at the University of Ottawa.

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Canary Media reports that the town of 2,000, once anchored by coal mining and a coal-fired power plant that supplied jobs and tax revenue for decades, is now drilling into subterranean thermal resources to heat and cool buildings in a new industrial and business park. The project is intended not just to lower utility bills for prospective tenants but to help counter the economic shock of the local coal plant’s scheduled closure in 2028, town officials and residents say.

“This area, with the exception of agriculture, was built on oil and gas and coal,” Dallas Robinson, a former town councillor and lifelong resident whose family’s excavation business once supported the region’s fossil fuel infrastructure, told Canary Media. “It’s hard to see people lose their jobs and have to move away.”

From coal dust to geothermal loops

The geothermal project is part of a broader business park on 58 acres designed to attract firms seeking low, predictable utility costs. To achieve that, crews are drilling boreholes about 1,000 feet deep and installing ground-loop piping that will transfer heat between the earth and buildings’ heating and cooling systems. The municipal utility being formed to manage the system will spread infrastructure costs over customer energy bills rather than charging large upfront fees.

Town manager Mathew Mendisco told Canary Media that the initiative was a “long-term bet” on geothermal’s potential to eliminate dependence on coal and natural gas while anchoring sustainable economic activity. Geothermal systems use less energy than conventional space-conditioning and offer stable performance in both winter and summer, advantages that local officials say make them well suited to the Rocky Mountain climate.

The development is expected to provide more than 70 jobs and deliver energy costs roughly 40 per cent below conventional heating systems, according to Mendisco. Early adopters of the park’s geothermal energy include an industrial painting company and a regional distributor, suggesting that new industries see value in Hayden’s clean energy story.

Broader context for geothermal in Colorado and the U.S.

Hayden’s initiative comes as geothermal interest is rising across Colorado and the U.S. Though direct use of geothermal for heating and cooling is more common, the state has also seen a broader push to support geothermal networks. In 2025, the Colorado Energy Office awarded millions in tax credits to projects in Vail, Colorado Springs, Steamboat Springs and other communities, reflecting state efforts to help small towns diversify energy sources.

Across the Mountain West, rural communities are navigating the decline of coal and traditional energy jobs, with residents in nearby Craig, Colorado noting the broader uncertainty as mines close and employment shifts toward new sectors. “People have to start looking beyond coal,” one resident told Colorado Public Radio, echoing a sentiment felt in places like Hayden.

Nationally, geothermal energy — including both shallow ground-source systems like Hayden’s and deeper enhanced geothermal systems (EGS) — is gaining attention as a firm, low-carbon energy resource. While wind and solar dominate renewable discourse, geothermal’s ability to provide continuous heat or power gives it a unique value in energy portfolios. Bloomberg has reported that new drilling technologies and supportive federal tax incentives are helping geothermal projects edge closer to cost competitiveness with traditional fuels and intermittent renewables.

Geothermal proponents include companies like Calgary-based Eavor Technologies, whose proprietary closed-loop systems are designed to deliver scalable, dispatchable geothermal heat and power without relying on naturally occurring hotspots — potentially broadening geothermal’s applicability well beyond volcanic regions.

Geothermal as part of post-coal economic strategy

Analysts say geothermal and other renewables could play a meaningful role in diversifying economies that have long depended on fossil fuels. Geothermal heat pumps, for example, are noted for efficiency and environmental benefits; NPR reporting underscores their climate friendliness and energy savings compared with conventional furnaces or boilers in residential and commercial applications.

In Hayden, drilling has already begun on about half the district’s geothermal loops, with completion slated by 2028. Officials say the system’s low operational cost and sustainability could make the town an example for other communities facing similar transitions.

“Geothermal’s here to stay and its workforce is going to get bigger,” Bryce Carter, geothermal programme manager at the state energy office, underscoring how local capacity building could support long-term clean energy deployment, told the Colorado Sun.

Experts say the success of projects like Hayden’s — and eventual advances in deeper geothermal electricity generation — will depend on continued investment, improved drilling technologies, and supportive policy frameworks at state and federal levels. But for now, a former coal town is demonstrating that heat from beneath the earth can offer a viable path toward economic revival and energy resilience that resonates well beyond its mountain borders.

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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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