U.S. Refining Capacity Grows, But Looming Closures Threaten 2026 Output

(Reuters) — U.S. refinery crude oil processing capacity grew by nearly 40,000 barrels per day in 2024 to 18.4 million bpd, the U.S. Energy Information Administration said on June 20.

Motiva Enterprises’ Port Arthur, Texas, plant became the largest single refinery by capacity at 640,500 bpd, passing Marathon Petroleum’s Galveston Bay Refinery in Texas City, Texas, according to the report. Motiva’s increase of 14,500 bpd from a year ago was due to improving operating efficiency.

National capacity may possibly fall by as much as 402,476 bpd by next year’s report because of refinery closures: Lyondell Basell Industries permanently shuttered its 263,776 bpd Houston refinery in February, while Phillips 66 plans to close its 138,700-bpd Los Angeles refinery by the end of this year.

In 2026, assuming no growth at refineries through efficiency improvements, referred to as de-bottlenecking, U.S. capacity would fall below the 2023 level of 18.06 million bpd reported by the EIA.

Marathon, based in Findlay, Ohio, continues to be the largest single refiner in the United States with 13 refineries operating a combined production capacity of 2.96 million bpd equal to 16% of the national total, according to the EIA report, which is issued annually.

Valero Energy Corp., based in San Antonio, is the second largest, with 13 refineries operating 2.2 million bpd, equal to 12% of U.S. capacity, according to the EIA.

Exxon Mobil Corp. is the third-largest, with four refineries with 1.96 million bpd in crude oil throughput, equal to 10.6% of national capacity, the EIA report said.

The EIA report reflects refinery capacity as of January 1, 2025 and is based on reports filed by refiners on individual capacities for each refinery by January 1. As such, it provides a portrait of growth in the previous year.

The long-term trend in U.S. refining has been for shrinking numbers of refineries to overcome increasing capacity at remaining ones.

The total number of refineries in the United States remained unchanged at 132 from 2024, but the EIA report lists the 32,000-bpd CPI Operations refinery in Paulsboro, New Jersey as idle.

By: 6/23/2025

Adnoc exports nearly half of its oil through the strait

The crucial role the Strait of Hormuz plays in the flow of crude oil from the region has taken center stage since Israel first attacked Iran earlier this month. With the possibility of the closure growing very real this week, after Iran’s parliament reportedly voted for its closure as retaliation against the US and Israel following the US’ attack on Iran’s nuclear sites, we take a look at the UAE’s alternatives for oil exports — and how practical they would be in the event of the strait’s closure.

(** Tap or click the headline above to read this story with all of the links to our background and outside sources.)

DISCLAIMER- Even before US president Donald Trump announced a ceasefire between Iran and Israel, the consensus among analysts was that the closure of the strait would be an unlikely scenario, as it would put Iran in a difficult position with China, which is a key Iranian ally and receives most of its oil through the strait.

By the numbers: About 30% of the world’s daily oil supply and 20% of global LNG trade pass through the strait. The UAE moves about 1.5 mn bbl/d out of its 2.8 mn bb/d exports through the strait, Mees reported.

The UAE currently only has one option for bypassing the strait: The Adcop — or the Habshan-Fujairah pipeline — connects Adnoc’s Habshan crude oil processing plant in Abu Dhabi with the nation’s Fujairah export terminal on the Indian Ocean, bypassing the Strait, Mees reported. The pipeline has a capacity of 1.8 mn bbl/d — about 67% of the 2.85 mn bbl/d of crude oil exported from the Emirates this year.

The catch: The pipeline only links to Adnoc’s Murban onshore fields, leaving offshore-sourced crude reliant on the strait for market access. This means that about half of the UAE’s crude exports — 1.5 mn bb/d of offshore production — wouldn’t be up for diversion through Adcop, which would force the UAE to up its production from the onshore Murban facilities.

The good news is: The UAE is working on new alternatives. Adnoc is developing a USD 3 bn 1.5 mn bbl/d crude oil pipeline to link up its Ruwais’ Jebel Dhanna terminal with Fujiairah, but it won’t be operational until 2027. The Emirates would see its bypassing capacity almost doubled when the project is operational.

Any measure to restrict movement in the Strait of Hormuz would “paralyze the [Arabian] gulf and impact the entire world,” Iraqi economist Hilal al-Taan told Shafaq News. Notable ports like UAE’s Jebel Ali, along with oil-reliant nations Iraq, Bahrain, and Kuwait will incur catastrophic financial losses, al-Taan said. While the UAE and KSA have alternative routes, Iraq, Kuwait, Qatar and Bahrain are wholly dependent on the strait for their energy exports, leaving them as the most vulnerable for the closure.

The strait’s closure would also likely shock oil markets, with Bloomberg analysts crude estimating a rise in oil prices to USD 130 per barrel in that scenario.

By: 23 June 2025

Small Chinese refineries face trouble if their supply of cheap Iranian crude is restricted.

The conflict between Israel and Iran has already led to a sharp rise in global oil prices. Chinese refineries, long used to cheap Iranian crude supplies, are unlikely to escape the pain. China and Iran’s economic ties have grown closer in recent years, particularly since the two countries signed a 25-year comprehensive cooperation plan in 2021 — China is now Iran’s top trading partner, according to the Observatory of Economic Complexity, which monitors global commerce. Total China-Iran. 

By Dean Minello — June 22, 2025

With strong government backing and billions of dollars at their disposal, Middle Eastern oil giants are aggressively expanding into the global liquefied natural gas (LNG) market, aiming to nearly double their LNG capacity within the next decade. Companies like Saudi Aramco, Abu Dhabi National Oil Co. (ADNOC) and QatarEnergy are investing heavily in LNG production and trading, driven by the growing demand for natural gas as a transition fuel and a desire to diversify their portfolios beyond crude.

“LNG seems to be still the best bet across all different hydrocarbon commodities,” Ogan Kose, managing director at business consulting firm Accenture, told Bloomberg, adding that margins from LNG  investing and trading are “almost unheard of in any other hydrocarbon commodity.”

Whereas natural gas usually plays second fiddle to oil in global energy markets, LNG is seeing sustained demand and faster growth thanks to its role as a bridge fuel in the transition to renewable energy. However, many LNG projects have been hit by delays and large cost overruns, needing extra cash to get them to completion. This opens up an opportunity for cash-rich Gulf nations to flex their energy, financial, and geopolitical muscle in the space.

Further, the Middle East sees LNG as a golden opportunity to expand their commodity trading desks and close the gap with Europe’s energy trading giants Shell Plc (NYSE:SHEL) and BP Plc. (NYSE:BP). Saudi Arabia, Qatar, Bahrain, Kuwait, and Oman are all looking to expand in LNG trading. Oil and gas trading has become a major income source for oil and gas giants, especially when commodity markets are highly volatile.

And, the deals are coming thick and fast. Four days ago, Adnoc’s investment arm XRG PJSC  made an $18.7 billion offer for Australian fossil fuel producer Santos Ltd. (OTCPK:STOSF), good for a nearly 30% premium to Friday’s close, as the Middle East oil giant seeks to expand its LNG portfolio. Santos is pushing an aggressive investment plan to ramp up LNG output by 50% by the end of the decade. Whereas this strategy has frustrated investors looking for quick, near-term returns, it appears to have paid off by luring in a company like XRG searching for high-growth potential. XRG has been on a gas and chemicals buying spree as it targets an $80 billion enterprise value.

Last year, Qatar Energy kicked off production at the Golden Pass LNG project in Sabine Pass, Texas, project. The Golden Pass LNG project in Sabine Pass is a joint venture owned by QatarEnergy (70%) and ExxonMobil (NYSE:XOM), which owns a 30% stake. This more than doubled QatarEnergy’s North gas field expansion production from 77 million metric tons per annum (MMtpa) to 160 MMtpa. Golden Pass LNG is allowed to export up to 937 billion cubic feet a year of natural gas to Free Trade Agreement (FTA) and non-FTA countries on a non-additive basis over the next 25 years. In April, the JV secured regulatory approval by the  Federal Energy Regulatory Commission (FERC) to commission the project.

Two years ago, Aramco entered the LNG sector after it acquired a strategic minority stake in Australia’s MidOcean Energy for $500 million. Last year, Aramco upped its MidOcean stake to 49% and also agreed to fund the company’s purchase of a 15% stake in Peru LNG from Hunt Oil Company. MidOcean Energy has adopted a growth strategy to create a diversified global LNG business, with the company in the process of acquiring interests in four Australian LNG projects.

Meanwhile, Kuwait Petroleum is in talks with Australia’s Woodside Energy Group (NYSE:WDS) to purchase a stake in its proposed LNG project in Louisiana, U.S, Bloomberg has reported. Back in April, Woodside, Australia’s top gas producer, agreed to sell a 40% stake in the 27.6M metric tons/year Louisiana LNG plant to Stonepeak for $ 5.7B Woodside bought U.S.-based Tellurian for $1.2B in 2024, looking to develop the Louisiana LNG project to meet growing demand for gas. The first phase of the massive project is expected to cost ~$16B.

That said, the LNG craze is not limited to the Middle East. Malaysia’s state-owned oil and gas company, Petroliam Nasional Bhd., and other Southeast Asian companies are all looking to expand LNG production beyond their borders. Overall, the experts say the rapid expansion of LNG markets is a good thing, with a greater pool of suppliers likely to benefit LNG buyers, boost competition, and diversify options.

By Alex Kimani – Jun 22, 2025

The projects contributing to this capacity boost include those in Canada, Qatar, Nigeria and the UAE.

il and gas company Shell has announced plans to expand its capacity by up to 12 million tonnes (mt) by the end of the decade, reported Reuters, citing Shell’s Integrated Gas president Cederic Cremers.

This increase is attributed to several projects currently under construction, as confirmed by Cremers.

Cremers stated: “That is not an ambition. Those are all projects that are currently in construction.”

The projects contributing to this capacity boost include those in Canada, Qatar, Nigeria and the United Arab Emirates (UAE).

Shell’s current buying capacity stands at approximately 70 million tonnes per annum (mtpa) of contractual liquefied natural gas (LNG).

Shell LNG Marketing and Trading delivered nearly 65mtpa of LNG to more than 30 countries last year.

In addition to construction projects, Shell is also enhancing its supply capabilities through strategic acquisitions and partnerships.

Cremers highlighted the recent acquisition of Pavilion Energy in Singapore, which was completed by the end of the first quarter, and contracts with third-party suppliers as key to its strategy.

Looking to the future, Cremers noted that by 2030, a significant portion of new supply, around 60%, is expected to come from the US and Qatar, with demand primarily driven by Asia and sectors that are challenging to electrify.

Shell earlier this year projected that global LNG demand could surge by around 60% by 2040, spurred by economic growth in Asia, the impact of AI, and initiatives to reduce emissions in heavy industries and transportation sectors.

Earlier this month, Shell announced the final investment decision to initiate production at the Aphrodite gas field in the East Coast Marine Area in Trinidad and Tobago.

By: Offshore-technology / June 12, 2025

NEW YORK, June 9 (Reuters) – California’s fuel imports rose to the highest in four years in May as refiners turned to historical trading partners in Asia and tapped some unusual routes to make up for shortages in the No.2 U.S. oil consumer state, according to shipping data and traders.

The rise in shipments to California offers an early look at the future of the biggest gasoline and jet fuel markets in the U.S., which are expected to become more reliant on imports after Phillips 66(PSX.N), opens new tab and Valero(VLO.N), opens new tab close two major refineries in the state by next year, amid growing regulatory and cost pressures, and declining demand for gasoline.

“California’s refining capacity is shrinking faster than its fuel demand is declining, forcing the state into a long-term import-dependent position,” Kpler analyst Sumit Ritolia said.

California’s total petroleum product imports rose to 279,000 barrels per day (bpd) in May, the highest since June 2021, when a similar volume was imported, according to data from vessel tracker Kpler.

About 187,000 bpd, or nearly 70% of the imports came from South Korea and other Asian exporters, who have historically been the top trading partners for California and other West Coast states, which are geographically isolated from major U.S. refining centers along the Gulf Coast.

Recent outages in California at refineries owned by Chevron (CVX.N), opens new tab, PBF Energy (PBF.N), opens new tab and Valero(VLO.N), opens new tab caused a supply crunch in markets along the U.S. West Coast that necessitated more imports, traders and analysts said.

“We have seen tighter supplies due to several refinery outages,” StoneX oil analyst Alex Hodes said. That boosted prices in the U.S. Pacific Northwest substantially and led to increased imports, he said.

There were several days where San Francisco gasoline was more than $40 a barrel above Gulf Coast pricing, nearly double the year-to-date average of $21, WoodMac analyst Austin Lin said.

Flows on the route from the Caribbean were sporadic before this year’s refining outages, averaging just 6,000 bpd throughout last year, the data showed.

The Bahamas does not refine oil but exports fuel and blending components shipped there from the U.S. Gulf Coast refining hub as part of a workaround to a century-old U.S. shipping law to supply fuel to the East Coast when pipeline shipments are insufficient.

The Jones Act bars movement of goods between U.S. ports unless carried by ships built domestically and staffed by local crew. However, there were only 55 such petroleum tankers as of the start of 2024, according to a government report, making them expensive and hard to procure.

Sailing a tanker from Texas to California via the Bahamas is typically too expensive, but the recent refinery outages opened up the arbitrage to the West Coast from everywhere, a second U.S. gasoline trading source said.

By: Shariq Khan and Nicole Jao / June 9, 2025

Bitcoin meets Big Oil in what could be the industry’s most ambitious flare-gas mining play yet.

Could MARA (formerly Marathon Digital) be in exploratory talks with Exxon Mobil and Saudi Aramco to colocate Bitcoin mining units at oilfields, directly tapping flare-gas for power?

Crypto Twitter thinks it’s possible, and if confirmed, the partnership could turbocharge the scale and legitimacy of gas-to-Bitcoin operations, turning waste methane into a monetized digital asset while addressing ESG concerns.

MARA stock pumper Cryptoklepto thinks, “It is more likely than not that at least one of these scenarios plays out in the next 6 to 12 months for $MARA.”

While none of the companies have formally announced a deal, MARA CEO Fred Thiel hinted at “discussions with some of the largest energy companies in the world” on May’s earnings call, adding that “chunks of flare-gas generation” will soon come online where we’re able to deploy our Bitcoin mining operations.

The timing aligns with Aramco’s May 2025 announcement of 34 new MoUs with U.S. firms and follows Exxon’s earlier pilot with Crusoe Energy in North Dakota.

Pilot-Proven, Ready to Scale

MARA isn’t starting from scratch. In late 2024, it launched a 25-megawatt pilot in Texas using stranded shale gas, avoiding grid competition while qualifying for methane abatement credits. “The AI guys are prepared to pay almost any price for energy,” Thiel told Reuters. “Bringing crypto-mining to the raw power supply lets us avoid that fight.”

The company’s mobile, plug-and-play infrastructure is tailor-made for oilfields. These portable modules convert otherwise flared methane into electricity, which is then used to mine Bitcoin, a process that Exxon and Crusoe demonstrated at scale by diverting 18 million cubic feet of gas per month and cutting CO₂-equivalent emissions by up to 63%.

Saudi Aramco has previously denied any intention to mine Bitcoin. In 2021, the company labeled such reports “false and inaccurate.”

However, MARA’s Thiel recently claimed the firm has 4–5 gigawatts of excess capacity, a scale that could power tens of thousands of mining rigs. If even a small portion were redirected, it would surpass the total output of many standalone crypto facilities.

Exxon, meanwhile, has the institutional memory and data from its two-year Crusoe pilot, which could make fast-tracking a new venture with MARA less speculative than it seems.

Why Now? A Confluence of Pressure and Opportunity

Behind the scenes, regulatory momentum is building. A U.S. methane emissions fee under the Inflation Reduction Act kicks in this year, pushing oil producers to find ways to reduce or monetize their emissions. Flare-gas mining offers a low-capex, high-upside path to compliance, particularly when paired with carbon offset markets.

Further, bills have been approved in Texas specifically to encourage Bitcoin mining using flare gas.

At the same time, Bitcoin miners are grappling with compressed margins following the April 2025 halving. MARA, one of the industry’s largest listed players, produced 950 BTC in May but must now aggressively pursue sub-$0.03/kWh energy sources to remain competitive. Flare-gas, once a fringe energy input, could become a post-halving lifeline.

Skepticism remains warranted. No SEC filings, public agreements, or official comments confirm the Exxon or Aramco partnerships. Given Aramco’s past denial, any shift in stance would likely involve months of permitting, infrastructure build-out, and reputational calculus.

If oil majors greenlight Bitcoin mining at the wellhead, the flare-gas conversation will shift from “can it work?” to “how fast can it scale?” MARA, with its turnkey modules and Wall Street footprint, may be first in line.

What to Watch

Public filings or MoUs from Exxon, Aramco, or MARA confirming pilot collaborations.

Energy regulator responses to flare-gas mining amid the methane fee rollout.

Q3 production updates: MARA’s energy costs and BTC yield per site.

Community pushback around noise and emissions from MARA’s Texas flare site.

“You’re going to find is a mix of thermal, a mix of wind, solar and some flare gas. It really depends on the market and the partner.

We’re in discussions with some of the largest energy companies in the world that have a mix of all those energy sources and nuclear.

In regards to flare gas, there are a lot of gas assets around the world that are very applicable to this method…

And what I think you’ll see us doing more and more in the future is as we continue to work with especially oil and gas producers, you’ll see chunks of this flare gas type generation come online in different parts of the world where we’re able to deploy our Bitcoin mining operations, as a way to monetize that stranded gas. And we are super excited about those opportunities.”

By: Liam ‘Akiba’ Wright / Jun. 9, 2025

Investments in Norway’s oil and gas sector are set to hit a record high this year, led by increased investments in operating fields, Statistics Norway said on Tuesday in its latest survey of companies’ investment plans.

The quarterly survey of investment plans showed that total investments in oil and gas activity in Norway in 2025, including pipeline transportation, are estimated at $26.6 billion (269 billion Norwegian crowns), up by 6% compared to the estimates in the previous quarter.

“The upward adjustment for 2025 is to a large extent driven by higher estimates within the category fields on stream,” the statistics office said.

However, investments are expected to peak this year and begin to decline moderately from 2026 onwards. The estimate for 2026 is now at $20.5 billion (207 billion crowns), down by 4.3% from the expected 2025 investment level, according to the statistics office.

Investments in 2023 and 2024 jumped, due to Norway’s oil tax package from 2020 incentivizing operators to submit a plan for development and operation (PDO) for several new fields, Statistics Norway noted.

Inflation and rising supply chain costs have also boosted the value of the investments in the past two years.

Considering that “very few new developments have occurred since 2022”, it is not surprising that a moderate decline in investments in field development is indicated this year. But this decline in investment in field development is being offset by expectations of a very high planned investment activity in fields on stream, the statistics office said.

Further exploration efforts and new discoveries would be crucial to slowing the expected decline in Norway’s oil and gas production in the 2030s, the authorities of Western Europe’s largest oil and gas producer have said in recent years.

Production from the Norwegian Continental Shelf is expected to decline gradually in the coming years, the Norwegian Offshore Directorate said in April in its annual report.

“However, the level of this decline will depend on the volume of new resources discovered and how much of the discovered resources are developed and actually come on stream,” the regulator said.

By: Oil Price / May 28, 2025

ExxonMobil has started exclusive talks with Canadian fuel retailer North Atlantic over the sale of its stake in its French subsidiary Esso, including its Gravenchon oil refinery, the company announced on May 28.

A statement from ExxonMobil said it is negotiating with North Atlantic France over the acquisition of its entire 82.89% stake in the Esso business and its assets, including the 240,000 b/d refinery it operates in Normandy.

The companies are also discussing the sale of a 100% stake in ExxonMobil Chemical France, the statement said.

Subject to regulatory approval, the deal is expected to close in Q4 2025, after which North Atlantic will file a mandatory tender offer for the remaining shares of Esso SAF.

The Esso business is responsible for roughly 20% of the active refining capacity in France through its operation of Gravenchon and separate lubricants plant, according to its estimates.

Across the country, Esso also markets fuel and lubricants through a branded reseller network of around 750 sites.

In a new landing page on its website, North Atlantic set out aims to develop a “green energy hub” at Gravenchon with new low-carbon fuels and renewables projects, adding that the site is well-positioned to serve energy-intensive industries like data centers.

North Atlantic’s retail business in Eastern Canada and French territories Saint Pierre and Miquelon could also offer offtake certainty for the refinery, the company said, supporting strong utilization rates.

French divestments

For ExxonMobil, the Esso deal marks the culmination of a string of French divestments as it has concentrated on its US and Asian assets.

In 2024, the company began significantly downsizing its French downstream business, closing its chemicals operations in Gravenchon and later selling its 140,000 b/d Fos-sur-Mer refinery to a Trafigura-backed joint venture.

Completion of the Esso deal will leave ExxonMobil with just four remaining refinery stakes in Europe: Antwerp, Rotterdam, Fawley, and Germany’s MiRO.

Once a key asset for Exxon, Gravenchon attracted significant investment at the beginning of the decade, boosting yields of high-value products and helping it capture market share when rival Grandpuits stopped operating in 2021.

As France’s second-largest refinery, the site benefits from a direct pipeline connection to Paris airports and export flexibility from the nearby Le Havre terminal.

Nonetheless, the closure of the Gravenchon steam cracker signaled fading appetite from ExxonMobil to continue operating the site long-term, closing off the opportunity to capitalize on stronger petrochemicals integration as fossil fuel demand stalls.

In its statement, ExxonMobil said that the proposed sale aligns with its wider strategy, but stressed that Europe remains an “important region” for the business.

“ExxonMobil has been operating in France for over 120 years, and we plan to maintain a significant commercial presence with the Esso brand,” said Tanya Bryja, senior vice president of ExxonMobil Product Solutions.

Meanwhile North Atlantic CEO Ted Lomond called the acquisition a “pivotal moment” for the Canadian company to establish a European presence for the first time.

“We are eager to consolidate Gravenchon’s role as a vital center of French energy and industry for decades to come and grow North Atlantic into a premier transatlantic energy company,” he said.

European contraction

Analysts have warned that the exodus of IOCs from the European refining sector could precede a structural decline in margins around the turn of the decade.

According to an analysis by S&P Global Commodity Insights, ExxonMobil has already slashed its European refining capacity by around a third since 2000, mirroring downsizing by competitors such as Shell.

And as European producers eye rising operating costs and stalling oil demand, new global competitors in the Middle East, Latin America and West Africa promise to accelerate another wave of closures. Based on surplus capacity alone, the International Energy Agency sees at least 1 million b/d of European refining capacity at risk of closure by 2030.

After selling its Italian Augusta and Sarpom refineries and closing its 116,000 b/d Slagen site in Norway in 2021, ExxonMobil recently tried and failed to shed its stake in Germany’s largest refinery, MiRO, only to be blocked in court by co-owner Shell.

The exit of established refiners has encouraged smaller energy players and traders to venture into the sector, often with the aim of transforming assets to reduce their emissions.

Experts have warned that only investors with deep pockets, such as major commodity traders, will be equipped to properly fund billion-dollar decarbonization projects. However, Commodity Insights oil analyst Samy Tamarat said the transaction could signal a “potential lifeline” for Gravenchon.

“While the company’s low-carbon fuels ambitions will require significant investment, it will ensure the site has a future in a market where demand for traditional refined oil products is declining,” he said.

The completion of the Esso deal will include conditions to ensure continuous crude oil supply for Gravenchon and lasting purchase agreements for ExxonMobil, the company statement said. The deal valued Esso shares at Eur 149.19 ($168.86) per Esso share, before adjustments for changes in inventory value, cash payouts and other changes.

By Kelly Norways , Spglobal / May 28, 2025