It took Donald Trump less than a week after his bombing raid in Venezuela to raise the ire of one major group of fossil industry donors, while threatening to freeze his country’s biggest publicly-traded oil company out of the production boom he thinks he can set in motion.

In the 10 days since the raid, Trump has claimed that Venezuela “will be turning over” 30 to 50 million barrels of oil to the U.S., that he will personally control the revenue from selling that oil, and that the U.S. fossil industry will pile in to Venezuela to restore its decrepit, poorly-maintained production infrastructure.

But that isn’t sitting well with fracking executives in Texas—many of whom “bankrolled the president’s return to office”—who expect any increase in production to push global oil prices below the threshold where they can continue to operate, the Financial Times reports.

“Problems in Texas’s oil industry are mounting, as cheaper oil forces producers to idle rigs needed to keep production ticking higher,” the Times explains. So “Trump’s drive to open up Venezuela’s oil riches, potentially subsidizing investors, has further strained relations with oil executives in Texas, who have been angered by his dogged pursuit of ever-lower crude prices.”

In the 2024 general election in the U.S., the fossil fuel industry spent $219 million to elect the country’s next government, Yale Climate Connections reported afterwards, most of it on Republican campaigns. That was after Trump invited about 20 oil and gas executives to his Mar-a-Lago estate in April to present what one independent journalist called a “breathtakingly corrupt proposal: If they raised a billion dollars to help him retake the White House, he would roll back any policy they didn’t like when he took office.”

Now some of those donors sound like they’re questioning the return on their investment.

“We’re talking about this administration screwing us over again,” one exec told the Times. “If the U.S. government starts providing guarantees to oil companies to produce or grow oil production in Venezuela I’m going to be… pissed.”

Some industry sources are angrily calling it a “betrayal” after Trump “flew to Texas multiple times in 2024 to tap deep-pocketed oil barons for cash,” the news story adds. Their problem is that “only the biggest [fossil] energy groups, such as ExxonMobil, Chevron,  and ConocoPhillips, have access to the tens of billions of dollars in capital, teams of lawyers, and security protection needed for a foray into Venezuelan oil. For smaller U.S. operators, a revitalized Venezuelan industry—if Trump can pull it off—means worsening the market glut,” with prices already below the US$60 per barrel that shale producers need to turn a profit.

“To me, the signal from the administration is: we’d rather spend our American money on propping up a Venezuelan oil business than supporting our current independent businesses,” said Trump donor Kirk Edwards, CEO of Odessa, Texas-based Latigo Petroleum.

“I think it’s an appropriate reaction by U.S. shale to be miffed,” added Pickering Energy Partners founder Dan Pickering. “Not just because Venezuelan production might go up but because the U.S. government, in theory, is going to subsidize that.”

On the surface, colossal fossil ExxonMobil may be miffed, as well, after Trump took umbrage at CEO Darren Woods’ assessment that his production plan would be “uninvestable”. After meeting with fossil CEOs Friday, Trump said Woods’ bad attitude might disqualify the company from any new business in Venezuela.

“I didn’t like Exxon’s response,” he told reporters. “I’d probably be inclined to keep Exxon out. I didn’t like their response. They’re playing too cute.”

Woods maintained that Venezuela would have to make “significant changes” before Exxon would consider investing there. “We’ve had our assets seized there twice, and so you can imagine to re-enter a third time would require some pretty significant changes from what we’ve historically seen here and what is currently the state,” he said. “If we look at the legal and commercial constructs, frameworks in place today in Venezuela, today it’s uninvestable.”

He also told Trump he was “confident” those changes “can be put in place,” the Times writes.

But Venezuela’s oilfields may not be the prize Exxon is after—or even the main motivation behind Trump’s takeover. Drilled Executive Editor Amy Westervelt recaps Exxon’s extensive investments in neighbouring Guyana and recalls Venezuela’s escalating threats against those operations before the U.S. removed President Nicolás Maduro from office.

Most of the other oil execs who met at the White House Friday “delivered optimistic messages to Trump about the prospect of reviving Venezuela’s oil sector,” the Times says. But at least one U.S. news site is reporting that industry insiders “are mocking the president behind his back, predicting companies will string him along to get on his ‘good side’ and never follow through” on their promises to invest.

“The big oil companies who move slowly, who have corporate boards are not interested,” U.S. Treasury Secretary Scott Bessent told Politico, in a sequence republished by RawStory. “I can tell you that independent oil companies and individuals, wildcatters, [our] phones are ringing off the hook. They want to get to Venezuela yesterday.”

But that only shows that “the most enthusiastic are among the least prepared and least sophisticated,” said one industry official. “Anyone with a degree of international sophistication is taking a more measured approach.”

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By Jake Bittle

Shortly after launching a dramatic raid in which U.S. forces abducted Venezuelan leader Nicolás Maduro on Saturday, President Donald Trump justified the action with a promise to revive Venezuela’s moribund oil industry. The country has by far the largest claimed reserves of crude oil in the world, accounting for almost a fifth of the planet’s remaining known crude oil, but its production has plummeted under Maduro, who has ruled the country since 2013.

“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,” Trump said during a press conference at Mar-a-Lago in which he announced Maduro’s capture.

This intervention comes at a pivotal moment for the global oil industry, which continues to stare down the prospect of a broad transition to renewable energy. For this reason, it’s not obvious that future markets can justify a surge of investment in Venezuela. On one hand, the country’s extra-heavy crude oil is perfect for diesel and jet fuel, which are helpful in hard-to-decarbonize industries. This makes it less threatened by the meteoric rise of electric vehicles displacing gasoline-powered cars. On the other hand, the world is already experiencing an overall glut of oil, and analysts expect demand to peak in the next decade. 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.

“There’s a guaranteed market for it, but a market that has its limitations in size,” said Antoine Halff, the founder of the climate and data analysis firm Kayrros and a nonresident fellow at Columbia University’s Center on Global Energy Policy.

As electric vehicles and renewable energy continue to expand, the world appears to be approaching a peak in oil demand. While the exact timing of that peak is disputed — it could happen within four years or in more than 15 years — almost all analysts agree that it is coming. 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.

Then there’s the matter of predicting future prices in a notoriously volatile industry. Oil companies only make a profit when global oil prices stay above a certain level. For the U.S. companies that produce oil from Texas shale, for example, that number is around $60 a barrel, which is close to the current benchmark price. For Saudi Arabia, it’s closer to $90 a barrel, because oil revenues back almost all the kingdom’s government spending. In the newest oil fields, such as those offshore of Guyana, it’s as low as $30. There are already concerns that an oversupply of oil worldwide could send prices tumbling over the next year, making new fields less palatable to investors. If demand plateaus, a surge of Venezuelan crude would push prices even further down. Since Venezuela is a member of OPEC, it would have to coordinate production along with Saudi and other major producers, who would likely prevent Venezuela from flooding the market.

Even so, there will likely be long-term demand for the specific kind of oil that Venezuela produces. That’s because any energy transition will not happen at equal speed across all parts of the transportation sector. The expansion of electric vehicles will first replace passenger cars and mopeds, which rely on lighter oil from fields like those of the Texas shale. Larger vehicles like airplanes and heavy-duty trucks are harder to replace — they need more power than EV batteries can feasibly provide at present — and they rely on heavy oil like Venezuela’s. A report from the oil trading firm Vitol found that “the initial pace of decline [for diesel] is expected to be slow compared to gasoline, but begins to gather pace from 2035 onwards.” Few other countries boast the same kind of extra-heavy reserves that Venezuela has, and those that do, like Canada, have much higher production costs.

“These are the hard-to-abate segments,” said Halff. “It’s the part of oil demand that looks like it’s not going to shrink quickly.”

Venezuela pumped more than 3 million barrels of oil per day at the turn of the century, but production totals have plummeted since then. After the government of Hugo Chávez nationalized major oil infrastructure in 2007, the United States imposed financial sanctions that forced Venezuela to sell its oil at steep discounts. Under the Maduro government, the state-owned oil company racked up debts and saw an exodus of skilled workers. Pumps and pipelines decayed out of service, storage tanks collapsed, and production bottomed out at around 500,000 barrels per day during the COVID-19 pandemic.

President Trump has promised that his aggressive raid on Venezuela will lead to a revival of this industry, and he has reportedly urged U.S. oil producers to aid him in the effort. In remarks following the Maduro raid, he promised that American companies would return to Venezuela and help export oil to other countries. Given how inefficient the state-run oil sector has become, analysts believe it would be easy to restore some production in the short term with outside investment and sanctions relief.

“Our assumption is that there are a lot of wells that just need a workover,” said Adrian Lara, the lead analyst for the Latin American oil industry at the research firm Wood Mackenzie, in a brief published last month before Maduro’s capture. “You can boost production through opex [operational expenditure], without needing much new capex [capital expenditure]” — in other words, a tune-up rather than a full surge of new investment.

In the short term, there is ample demand. The oil in the country’s vast Orinoco Belt is very heavy and viscous, like molasses, in contrast to U.S. shale oil, which is about as thin as vinegar. This makes it more expensive and more carbon-intensive to produce, but also makes it well suited for conversion into diesel fuel in trucks and for other uses like asphalt. There are several refineries along the Gulf Coast that were built to process this kind of heavy crude, and these refineries are operating below capacity. Right now, Venezuela exports most of its oil to China, which would also likely purchase more for its own refineries. An industry expert who spoke to The Wall Street Journal said access to those reserves could be a “game changer” in terms of increasing Gulf Coast refiners’ profits.

“Right now there’s plenty of appetite for heavy crude globally,” said Robert Auers, a refined fuels market analyst at the energy consultancy RBN Energy. “Even if Venezuelan production were to come back real strong, the global market could easily absorb that.”

But a grand revival like the one Trump has promised would be a much taller order, given that it would take decades to unfold. The energy analysis firm Rystad Energy projects that a return to pre-Maduro levels would require an investment of $110 billion, and these investments would not bear fruit for a decade or more. Even Chevron, the only U.S. oil producer that operates in the country, would need to invest an estimated $7 billion in order to add another 500,000 barrels, according to a former executive who spoke with The New York Times.

The climate pollution stemming from this crude might also play a factor in its market appeal. Right now, the heavy oil extraction in the Orinoco Belt is some of the most carbon-intensive in the world, in part because enormous amounts of methane are flared during the process. As governments continue to pursue Paris Agreement targets, however fitfully, they might shy away from such fields wherever possible and instead import lower-carbon barrels. (The European Union has already committed to do this.) Many experts believe that oil majors will hesitate before taking the plunge on a resource that is far tougher to handle than the crude in U.S. shale fields or the Middle East.

That’s all in addition to the political uncertainty that has followed Trump’s attempt to depose Maduro. It remains unclear what shape the new government of Venezuela will take. Given that other producers like Exxon Mobil lost billions of dollars when the Chávez government nationalized their assets, it’s far from obvious that these oil companies would want to invest under continued political instability. Past U.S. interventions have demonstrated similar dynamics: Oil production in Libya has still not recovered since the fall of Muammar Gaddafi in 2011, and it took almost a decade for Iraqi oil production to rebound after the U.S. invaded in 2003.

“I do not believe in a significant increase in the short term,” said Rudolf Elias, chair of the supervisory board of Staatsolie, the state oil company of Suriname, which is pursuing an offshore oil project in the waters east of Venezuela. “It will take years before the industry is revived … then it is dirty oil, and heavy, so it will not be first in the row.”

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The trend reflects a broader energy-market environment in which production has outpaced consumption and inventories have swelled, creating downward pressure on prices and reshaping market expectations for 2026 and beyond.

The EIA attributed the price decline largely to global oversupply of crude oil, noting significant stock builds in 2025 that were among the largest on record outside of the COVID-19 pandemic period. In its Short-Term Energy Outlook, the agency estimated that world petroleum production exceeded consumption by an average of more than 2.5 million barrels per day in the second half of 2025, contributing to higher inventories.

Reuters reporting on global oil markets later in 2025 echoed this assessment, highlighting that some OPEC+ producers maintained robust output levels even as demand growth faltered, partly to defend market share and compensate for earlier cuts that had tightened balances. The resulting surplus contributed to a downward trend in spot and futures prices.

The EIA also pointed to slower than expected demand expansion as a factor. Although petroleum use continued to grow in 2025, the pace was below historical norms, reflecting broader economic headwinds in major markets, particularly Europe and parts of Asia.

Global energy agency reports from the International Energy Agency (IEA) have noted similar patterns: slower industrial activity and structural shifts in energy consumption have tempered oil demand growth this decade. In its recent World Energy Outlook, the IEA highlighted that while demand will continue rising in absolute terms through the mid-2020s, the growth rate has softened compared with prior forecasts — in part because of energy efficiency gains and shifts toward electrification in key sectors.

Market analysts say that each downturn in crude prices over 2025 occurred against a backdrop of sporadic geopolitical events — including conflicts in the Middle East and supply disruptions in parts of Africa — that temporarily supported prices. However, those interruptions were not enough to counterbalance the broader oversupply trend, according to the EIA.

Bloomberg analysts noted that the market’s sensitivity to macroeconomic signals — particularly Chinese economic data and currency fluctuations — helped accentuate the price slide. Bloomberg cited softening industrial output figures in China in late 2025 as a key factor underpinning reduced crude demand expectations, which in turn contributed to lower crude futures prices.

NPR’s coverage of U.S. energy markets in late 2025 highlighted how falling crude oil prices translated to mixed outcomes for consumers. While retail gasoline prices declined in many regions, utilities and households faced higher electricity costs due in part to weather events, transmission constraints, and regional fuel mix differences. NPR’s reporting underscored that lower oil prices do not uniformly reduce all consumer energy costs, particularly where electricity and natural gas markets are driven by separate dynamics.

For oil producers, the 2025 price slide and inventory builds raise questions about future drilling and investment decisions. Reuters noted that U.S. shale operators are already signalling more cautious capital spending plans if price forecasts remain flat, focusing on efficiency rather than aggressive production growth.

The EIA’s outlook suggests that market balances could tighten if production moderates or if demand surprises to the upside — for example, through unexpected economic growth or accelerated fuel consumption in emerging markets. For now, however, inventories remain elevated and prices subdued relative to recent years’ averages.

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The Liberal government rejected a Conservative motion in the House of Commons this week that called for explicit federal backing of a large oil pipeline to tidewater. Ministers said the proposal oversimplified complex negotiations with provinces and Indigenous nations and failed to reflect the government’s approach to reconciliation and major project development.

Environment Minister Julie Dabrusin said the motion ignored the full context of a recent Canada–Alberta memorandum of understanding, which links any future pipeline discussions to climate policy, clean-technology investment and Indigenous engagement. She described the Conservative proposal as “immature” and said it misrepresented how large infrastructure projects move forward in Canada.

Poilievre, by contrast, argued that Canada’s economic interests require decisive action on export infrastructure. He has said waiting for unanimous agreement among provinces, communities and Indigenous nations risks stalling projects indefinitely and limiting Canada’s ability to access overseas markets, particularly in Asia.

“We need a pipeline,” Poilievre said in recent remarks, framing the issue as one of national interest and economic competitiveness. He accused the Liberal government of using consultation as a pretext for delay and challenged it to clarify whether it supports new oil export infrastructure at all.

The Conservative motion — which was non-binding — called on Parliament to affirm support for one or more pipelines capable of exporting at least one million barrels per day of bitumen from a British Columbia port. It also referenced potential changes to the federal oil tanker moratorium on B.C.’s north coast, while stating that the duty to consult Indigenous Peoples must be respected.

The pipeline debate has long been shaped by Indigenous rights and environmental concerns. Previous projects, including the Enbridge Northern Gateway pipeline, were opposed by dozens of First Nations over risks to land, water and treaty rights. That project was ultimately cancelled, and Ottawa later enacted legislation banning oil tanker traffic along much of northern British Columbia’s coastline.

Legal experts and Indigenous leaders have repeatedly warned that proceeding with major resource projects without consent could trigger lengthy court challenges. Canadian law requires meaningful consultation with Indigenous nations whose rights may be affected by development, and court rulings have reinforced the federal government’s obligation to engage early and substantively.

The issue also carries political weight as Parliament edges closer to an election cycle. Reuters has reported that the Liberal government’s position has been strengthened by recent defections from the Conservative caucus, reducing opposition leverage on key votes and policy initiatives.

As energy security, export access and reconciliation continue to collide in national debate, Poilievre’s comments underscore a clear dividing line between the Conservatives’ approach to resource development and the Liberals’ emphasis on consultation and consent — a contrast likely to feature prominently in the months ahead.

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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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By Mitchell Beer

With fossil fuel publicists touting decades of future demand, and those expectations baked into last week’s pipeline deal between Canada and Alberta, the global oil and gas industry already recognizes and is planning for its own decline, the UK-based Carbon Tracker think tank concludes in a recent review.

“A clear-eyed analysis reveals an oil and gas industry already conducting a quiet, rational, strategic retreat from long-term growth, despite public bravado from its supporters in the stands,” analysts Harry Benham and Guy Prince write in a Nov. 12 blog post.

“The cold data shows a sector preparing for plateau and decline, rewarding investors who push for harvesting with dividends and buybacks, and leaving investors who believe the growth rhetoric dangerously exposed.”

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This “say vs. do” chasm is playing out “in real-time company boardrooms and capital allocation plans,” Carbon Tracker concludes. The post cites four trends that contradict the “political rhetoric of robust future fossil demand”:

• Capital expenditure (“capex”) in the industry still stands at US$500 to $600 billion per year, but that’s about 40% below a peak of nearly $900 billion that now dates back more than a decade. “The industry has rationally concluded that this leaner, more efficient level of investment is sufficient to meet slowing demand and maintain a production plateau,” the blog post states. That makes the industry’s refusal to increase investment a “powerful vote of no confidence” in the notion of endless future growth.

• Spending on exploration for new oil and gas wells has fallen by about 60% in the last decade, and the major, new projects recently reported in Brazil are likely “more ornamental than truly productive and profitable”, with the world unlikely to need the new oil by the time the projects are ready to deliver it in 10 to 15 years.

• Credit agencies like Standard & Poors and Fitch Ratings have downgraded the sector after “listening to the numbers, not the speeches.” Those decisions show analysts “increasingly [treating] major new greenfield fossil fuel projects as potentially stranded from the day they are announced.”

• The continuing news of oil and gas mergers and acquisitions show a different kind of stranding, with bigger corporate players absorbing assets that aren’t meeting their revenue targets. “This is not production growth,” Carbon Tracker writes. “It is financial engineering—shuffling existing assets to cut costs and maintain dividends, and certainly not to expand a resource base.”

While not all companies are pursuing this new strategy, the ones that don’t “are increasingly punished by the market,” the authors state. “But legacy structures and political pressure still lead to capital misallocation at the margins—a key risk for investors to resist.”

Cooking the Books

Carbon Tracker posted its analysis just as the International Energy Agency was releasing its latest World Energy Outlook, long styled by the IEA as the “gold standard of energy modelling”. After months of intense arm-twisting from the Trump administration to cook the books and align its modelling with a “drill, baby, drill” agenda, the IEA resurrected its Current Policies Scenario (CPS) in this year’s WEO. It showed that rising oil and gas demand through 2050.

But that projection was just one of three in the WEO, and amounted to “a triumph of political gesture over foresight,” Benham and Prince state. “The CPS—which assumes no new climate policies at least until 2050—is a backward-looking relic that ignores the seismic shifts already reconfiguring the global energy system.”

That makes the CPS “a warning, not a forecast: it implies energy innovation stops in 2030, as if hitting some sort of intellectual brick wall,” they write. The reality on the ground is that “the pillars of oil demand growth are crumbling in real time, and irrespective of price—something front-line oil industry instinctively knows and can see.”

A Fossil Industry Collapse in Five Acts

Carbon Tracker says the collapse is being driven by these factors:

• Global gasoline demand is set to peak this year as vehicles electrify. “This isn’t a future prediction; it’s a present-day reality as EVs are on track to displace four to five million barrels per day of demand by 2030.”

• China is going through a “stunningly fast transition that undermines the core assumption of endless Asian fossil-demand growth,” with oil demand growth already declining and power sector emissions set to peak this year as renewables push coal below 50% of total generation.

• Growth in demand for petrochemicals and aviation fuels “cannot possibly offset the sweeping declines in road transport and power generation. They are a fleeting respite, not a revolution.”

• Liquefied natural gas (LNG) has drawn too much investment, so that any new expansion will threaten the financial viability of existing projects facing a global glut.

• Investors are voting with their dollars, with annual investment in renewable energy, grids, and electrification hitting $2.2 trillion per year, nmore than double the remaining capital expenditures in oil and gas.

“The market is already building the post-oil energy system, recognizing that fossil fuels, while important, are a diminishing part of a very new and different, larger energy mix,” Carbon Tracker states. And the pattern of the industry’s own investments “recognizes the very transition that industry supporters attempt to dismiss.”

That quiet retreat “is perhaps its most rational act in a decade,” Benham and Prince conclude. “The great irrationality now lies with investors who mistake this harvest for a rebirth, and with policy-makers who resuscitate outdated forecasts. The industry is no longer led by multi-billion-dollar, high-risk engineering megaprojects, but by sober capex reduction, and cash flow diverted into investors’ pockets.”

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

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

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

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

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

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

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

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By Mitchell Beer

Under intense pressure from the Trump administration, the International Energy Agency (IEA) has issued a carefully-hedged analysis that still shows fossil fuel demand peaking within years, but also portrays an alternate universe of sustained consumption where average global warming approaches 3°C.

Nearly five years after the Paris-based agency first reported no need for new investment in oil, gas, or coal development, this year’s edition of the World Energy Outlook (WEO)—long styled by the IEA as the “gold standard of energy modelling”—presents two energy futures scenarios that show greater reliance on fossil fuels and higher greenhouse gas emissions, along with a net-zero scenario that adheres more closely to a 1.5°C climate target.

“There’s poison on the menu,” said David Tong, global industry campaign manager at Oil Change International, commenting on a report that Politico headlined as a “global energy body’s fossil fuel backpedal”. But in a briefing following the report release Wednesday morning, the IEA said the net-zero scenario still indicates no new investment in longer-term oil and gas megaprojects.

This year’s IEA scenarios include:

• A Current Policies Scenario (CPS) that projects rising oil and gas demand through 2050 and 3°C average warming based on existing national laws, policies, and regulations;

• A Stated Policies Scenario (STEPS) that nearly triples renewable energy deployment by 2030 but still lands around 2.5°C, based on the current “direction of travel” in policies that countries have put forward but not yet adopted;

• The Net Zero Emissions by 2050 Scenario (NZE), which presents a pathway to bring energy-related carbon dioxide emissions to net zero by mid-century, deliver universal energy access by 2030, and reduce energy bills.

No Need for New Oil or Gas

The IEA’s modelling provides scant support for the new pipelines or liquefied natural gas (LNG) terminals that Canadian Prime Minister Mark Carney might want to include in his list of fast-tracked nation-building projects. While the Current Policies Scenario shows oil and gas demand growing through mid-century, countries do have the capacity to make different choices: STEPS projects oil demand flattening by 2030 and gas following suit by 2035, while the net-zero scenario eliminates fossil fuels at a faster pace.

“Natural gas demand has been revised up in this year’s STEPS, but questions still linger about where all the new LNG will go,” with the potential for higher global demand limited by “continued momentum behind the deployment of renewables, nuclear energy in some countries, and efficiency policies,” the IEA says. Across all three scenarios, “a downside risk to the uptake of natural gas and LNG is a failure by the industry to reduce methane leaks.”

The IEA identifies several common elements, addressed in different ways by each of the scenarios:

• Growing demand for energy services for a range of uses, including data centres and artificial intelligence;

• Serious concerns over the resilience of energy systems against a range of threats, from cyberattacks to droughts, storms, floods, and wildfires;

• The “acute vulnerability” of critical mineral supplies;

• The dawn of what the agency has previously dubbed the Age of Electricity, with electrification rising by about 40% by 2035 in the CPS and STEPS scenarios and 50% in the NZE;

• The increasing role of renewable energy;

• A “shift in the centre of gravity of the energy system” toward India and other emerging economies beyond China;

• A comeback for nuclear energy.

The IEA is postponing release of a fourth model—the Announced Pledges Scenario, which assumes that governments will keep their promises under the Paris climate agreement, in full and on time. Countries’ emission reduction commitments for 2035 have only recently been filed with the United Nations climate secretariat, and so far only 60 countries representing 63% of global emissions have bothered to submit their paperwork.

’Zombie Scenario’ vs. a 1.5°C Future

The mixed result produced a critical response from the climate and energy analysts who follow the IEA’s work.

“Trump has pressured the IEA to resurrect a zombie scenario from the past—the Current Policies Scenario, in which the current momentum of the energy transition evaporates,” said Climate Analytics CEO Bill Hare. “This is an unrealistic assumption when we look at the progress renewables are making around the world. And even if the CPS were realized, it only shows is that Trump’s vision is a disaster for the economy, household bills, and the climate.”

The IEA’s Net Zero Scenario “shows that, although overshoot is now inevitable due to insufficient action to date, it is still possible to bring temperatures back below 1.5°C before the end of this century,” Hare added.

“This year’s World Energy Outlook sets out a stark and simple choice: we can protect people and communities by aiming for 1.5ºC, settle for a disastrous business-as-usual 2.5ºC, or choose to backslide into a nightmare future of much higher warming,” said Oil Change’s Tong. “Holding warming to 1.5ºC means no further delay, no new fossil fuels, and public planning and funding to guarantee a just energy transition.”

The report “shows Donald Trump’s dystopian future, bringing back the old, fossil-fuel intense, high pollution Current Policies Scenario, charting an unrealistic pathway where governments drag their energy policies backwards and rates of renewable energy adoption stall, leading to high energy prices and unmitigated climate disaster,” Tong added.

“Crucially though, the IEA has also confirmed that no single country can stop the energy transition, with oil and coal demand to peak by 2030 in its business-as-usual scenario, with gas to follow by 2035. And, again, it has reconfirmed that there is no investment in new oil and gas fields for 1.5ºC.”

“The International Energy Agency has made a regrettable choice, published against a backdrop of the climate talks in Brazil, to no longer provide a credible scenario for keeping warming as close as possible to 1.5°C,” said Reclaim Finance analyst Christophe Etienne. “By avoiding the problem of fossil fuel expansion and offering a new scenario that leads us toward 3°C of warming, it is failing to provide the necessary economic, political, and financial guidance on managing the energy transition.”

But even though “some may wish to turn back the clock,” said European Climate Foundation CEO Laurence Tubiana, one of the architects of the Paris accord, “the direction of the energy system is clear. More than $10 trillion has been invested in clean energy since 2014, and oil demand is on track to peak before 2030 in the IEA’s main scenario. The electricity age is well under way. The choice now is between accelerating or paying later to undo the damage: every tonne of carbon we avoid today saves far greater costs tomorrow.”

“There’s a revolution happening right now and it’s in renewables and electrification. The evidence on the ground is overwhelming—EV sales are taking off in many emerging countries, solar is permeating even through the Middle East,” and “grid batteries now mean solar is increasingly dispatchable,” said Ember chief analyst Dave Jones. “Scenarios based on current policies and legislation are behind the curve of technology change as the electrotech revolution gathers pace.”

Giving In to the Bully

The WEO has always presented multiple scenarios, and in years past, climate policy analysts have paid close attention to the order in which those scenarios are presented—since the most prominent in the series makes the headlines that can guide many billions of dollars’ worth of energy investments. Beginning in 2021, when political change in the United States shifted the composition of the IEA board, the agency became a data-driven champion for a faster, wider energy transition.

That momentum began to shift over the summer, when the Trump administration threatened to pull out of the IEA—taking 40% of the agency’s funding along with it—if it didn’t bring its independent forecasts in line with the administration’s “drill, baby, drill” agenda.

“We will do one of two things: we will reform the way the IEA operates or we will withdraw,” U.S. Energy Secretary Chris Wright told Bloomberg in July. “My strong preference is to reform it.”

That threat reflected “growing tensions between the Trump administration’s energy priorities and the IEA’s focus on clean energy transitions,” Forbes reported at the time. The criticism from Wright, an oilfield services CEO before he joined the Trump cabinet, “centres on the IEA’s reports and projections, which he and other critics of the agency argue are overly optimistic about renewable energy adoption and fail to adequately prioritize energy security.”

The overt pressure had intensified by mid-September, prompting Bloomberg energy columnist Javier Blas to report on the IEA’s plans to restore the outmoded Current Policy Scenario and project healthy demand for oil through 2050. By giving the CPS pride of place as the first scenario in the series, the WEO became a case of “good analysis, but terrible comms,” veteran IEA-watcher Greg Muttitt writes on LinkedIn.

“We knew the IEA had acceded to U.S. demands to resurrect its obsolete Current Policies Scenario (CPS), which tells a story of continued fossil fuel growth. The trouble is how prominent CPS is: it’s the first scenario presented,” Muttitt explains.

“For all IEA’s warnings that CPS is not ‘business as usual’, putting it first means that’s how people will read it. And the name doesn’t help. The CPS doesn’t describe a future based on current policies—that comes later, in the Stated Policies Scenario”(STEPS).”

But “you have to wade through a lengthy discussion of the CPS before you get to the real story: where existing policies are taking us, in STEPS, [is] “the prevailing direction of travel for the energy system”.

In the IEA’s own cautious framing, the report invites readers to choose their own adventure. “There is no single storyline about the future of energy, which is why the World Energy Outlook presents multiple scenarios, none of which is a forecast,” the IEA states.

But even so, “options to reduce emissions substantially are well understood and, in many cases, cost-effective,” the report adds. “A pathway that mitigates the most severe risks from climate change remains feasible and there is strong momentum behind key technologies.”

But some countries’ commitments to the Paris targets have “waned” over the last decade, and countries’ new climate commitments for 2035 “do little, in aggregate, to move the needle beyond the outcomes already projected in the STEPS.”

So while the net zero scenario is still within reach, “implementing these actions at scale would require an intensified international push to increase transition-related investment in emerging and developing economies, and much more practical efforts to ensure that these investments deliver tangible near-term social and economic benefits.”

The post IEA Puts ‘Poison on the Menu’ But Maintains Net-Zero Scenario Despite Pressure from Trump appeared first on Thoughtful Journalism About Energy's Future.

By Faouzi Aloulou, Olga Popova, Jozef Lieskovsky

As U.S. crude oil and natural gas production have increased, so has the volume of production declines from existing wells. To offset the increasing declines, operators today must bring on new wells to sustain or increase production levels.

Between 2010 and 2024, hydrocarbon production from new wells in the Lower 48 states (L48) generally offset and exceeded declining production from existing wells. Because production from oil and natural gas wells declines over time as reservoir pressure decreases, new wells are required to maintain the same production level. The increasing number of horizontal wells has contributed to this trend because horizontal wells exhibit higher decline rates than vertical wells.

Crude oil production
In December 2023, L48 crude oil production averaged 11.0 million barrels per day (b/d). Production from wells that came online in 2023 or earlier fell to 6.7 million b/d in December 2024, a decline of 4.3 million b/d. Those declines were offset by the more than 15,000 new wells that were brought online in 2024—about 11,700 of which were horizontal wells. The new wells produced 4.4 million b/d of crude oil, enough to overcome declines from existing wells, bringing L48 crude oil production to 11.2 million b/d in December 2024.

Natural gas production
Between December 2023 and December 2024, natural gas production from wells that came online in 2023 or earlier fell from 115.4 billion cubic feet per day (Bcf/d) to 88.4 Bcf/d, a decline of 27.0 Bcf/d. New wells offset those declines, producing an average of 28.0 Bcf/d of natural gas in December 2024. L48 production for natural gas increased to 116.5 Bcf/d in December 2024.

Horizontal wells
In the mid-2000s, operators began to drill more horizontal wells, which allow them to recover more oil and natural gas quickly after initial production begins than from vertical wells. In December 2024, horizontal wells produced 94 per cent of oil and 92 per cent of natural gas in the L48 states. However, horizontal wells have a high initial production rate with a steep decline relative to vertical wells.

The rapid decline rates in horizontal wells are contributing to the trend described above with large numbers of new wells required to maintain or increase production levels.

The post Rapid declines from horizontal wells require more drilling to sustain production appeared first on Thoughtful Journalism About Energy's Future.

By Toril Bosoni, Head of Oil Industry and Markets Division

The post Opinion: As oil market surplus keeps rising, something’s got to give appeared first on Thoughtful Journalism About Energy's Future.