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U.S. Refiners Keeping American Families On The Road

June 4, 2026 by Leave a Comment

U.S. oil refiners are running plants close to 95% utilization and deferring some maintenance to take advantage of strong domestic and international demand and high margins. Refinery shutdowns averaged 470,000 barrels per day from January to May, down from 700,000 a year earlier and 900,000 in 2024, with little maintenance scheduled for the second half. U.S. refiners usually shut down for maintenance in early spring to get ready for the summer driving season. Goldman Sachs expects global refinery utilization to approach an all-time high by year-end, with diesel and gasoline margins at $50 and $22 per barrel, respectively, in the fourth quarter. The longer refiners postpone maintenance while operating near full capacity, however, the greater the risk of unexpected breakdowns that can force units offline.

The Iran conflict and the effective closure of the Strait of Hormuz continue to disrupt global energy flows, prompting countries to turn to the United States for oil and petroleum products. Asian refiners cannot get the oil they need to produce their own petroleum fuels and are looking to import U.S. diesel and jet fuel, as is the case in Europe. With the U.S. summer driving season getting under way and gasoline stockpiles at multi-year seasonal lows, domestic refinery demand also will be heating up.

The United States has 132 refineries that can process 18.4 million barrels per day. The United States lost about 1.1 million barrels of daily refining capacity between 2020 and 2021, accounting for about one-third of global capacity losses during this period due to reduced demand resulting from the COVID pandemic and the resulting lock downs. Since then, some existing refineries expanded their processing capability.

ExxonMobil increased its Beaumont, Texas refinery’s capacity from 369,000 to 609,000 barrels per day at a cost of $2 billion, adding a distillation unit in 2023. Chevron invested $475 million to modernize its Pasadena, Texas, refinery in 2024, increasing its light crude processing capacity by almost 15% to 125,000 barrels a day. And, Marathon’s Galveston Bay refinery upped its capacity by 6% to 631,000 barrels per day, making it the nation’s second largest refinery behind Motiva’s Port Arthur facility that has a capacity of over 640,000 barrels per day.

Companies are choosing to upgrade their existing facilities rather than build new refineries mainly due to the onerous regulatory process. However, there has been a recent exception.  America First Refining is building a 168,000-barrel-per-day refinery in Brownsville, Texas, a deep-water port with direct rail and sea access, supported by investment from India’s Reliance Industries. The facility — the first new major U.S. refinery project in roughly 50 years — will operate on light shale oil. Many Gulf Coast refineries ‌are unable to process light, sweet oil from ⁠shale fields because they were configured in the last 40 years to run on lower-cost heavy, sour oil, which has a higher density. U.S. light oil resources were on the decline before hydraulic fracking and directional drilling brought an explosion in production. Heavy oil imports are readily available from U.S. neighbors, Canada and Mexico, and now also Venezuela.

California Shedding Refineries

Within the past nine months, California lost two refineries due to its onerous policies against oil and gas production. The Phillips 66 Los Angeles facility and the Valero Benicia Refinery closed due to stringent environmental regulations that increased operational costs, removing 17.5% of the state’s refining capacity. California now has only seven major refineries left and has to rely on more product imports, mostly from Asia. Because of the closure of the Strait of Hormuz those exports are increasingly scarce, however, forcing California to purchase fuel from refineries on the U.S. Gulf coast and to use President Trump’s waiver of the Jones Act for deliveries. Before the waiver, the state would send its product imports east to the Bahamas and then ship them to the California coast to avoid the higher costs of using U.S. ships manned by U.S. crews required by the Jones Act.

California is again making changes to its “cap-and-invest” program which could make it harder to meet and increase costs of refined products. Companies that are forced to participate in the program must either reduce their carbon emissions below a certain state-mandated limit or buy allowances from the market to offset emissions in excess of that limit. The state then “invests” in energy projects its leaders prefer under the justification of climate policy. The number of allowances available for purchase declines over time, making it harder to meet the cap and making it more expensive to do so. As the supply of available allowances falls, the price of each allowance, and the cost of compliance, rises.

The Western States Petroleum Association, a trade group, and Chevron, the state’s largest oil refiner, warned that unless the program’s emissions limits were loosened, companies could be forced to close additional refineries. The California Air Resources Board (CARB) voted to give up as much as $4 billion worth of free allowances to oil refiners and other industrial companies to help them comply with greenhouse gas limits imposed by the state’s cap-and-invest program. The plan would remove the 118 million metric tons’ worth of allowances from circulation, allowing companies to claim them for free, rather than be forced to purchase them.

Analysis

U.S. refineries are running all out to fill both domestic and international demands, many are delaying spring maintenance which normally occurs before the summer driving season. The U.S. refinery utilization rate is near 95% and diesel and gasoline margins are expected to be at $50 and $22 per barrel, respectively, in the fourth quarter. Some companies have added capacity to existing refineries to make up for some of the 1.1 million barrels per day of refining capacity lost during the COVID lockdowns. One new refinery is being built in Texas that will use light oil from shale basins rather than heavy oil that most U.S. refineries currently use. Due to its onerous regulatory program, California recently lost two refineries, forcing it to import more petroleum products.

*This article was adapted from content originally published by the Institute for Energy Research.

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California’s High Gas Prices Are Unnecessary And A Threat To Food Security

June 3, 2026 by Leave a Comment

The closure of the Strait of Hormuz has restricted the flow of energy to global markets, severely impacting oil prices. As a direct result of rising oil prices, gas prices have also risen worldwide, including in the United States.

Although the average prices of gas and diesel have risen in the U.S. to $4.51 per gallon of gas and $5.63 per gallon of diesel as of May 18, the rise in energy prices has been substantially more noticeable in California. On the same day, California reported average gas prices of $6.15 per gallon for regular and $7.41 per gallon for diesel.

Unfortunately, the impact of the rise in fuel costs in California goes beyond its borders, since Nevada and Arizona import sizable portions of their petroleum products from Southern California refineries, and, due to the amount of agricultural products produced in and exported from the state. 

The stark difference in cost between the national average of gas and diesel, which states such as California skew, and California’s ballooning prices, is a result of a combination of overregulation, which discourages the investment and maintenance of a robust energy sector in the state, unique blend requirements for oil refining, and an overreliance on foreign seaborne imports despite having significant known oil reserves. An overreliance and rising cost that is spilling over into other industries, such as agriculture and transportation.

California’s oil imports and high taxes

California imported the majority of its oil from Alaska (16%) and foreign sources (61.1%) in 2025, and has done so for many years. This means that, although having an abundance of known oil reserves, 1.72 billion barrels as of 2022, according to the Energy Information Administration, with some estimates being much higher, California only produced 22.9% of the oil it needs in-state in 2025.

Furthermore, of the foreign oil that California imports, 28% of it came via the Strait of Hormuz in 2025, Iraq (17.5%), Saudi Arabia (7.85%), and the United Arab Emirates (3.35%), which is now placing even greater pressure on the state to diversify its supply chain. Although this supply chain diversification includes sourcing from Asian refineries, it would be far simpler to lift production and refining restrictions in-state while continuing to take advantage of the Jones Act suspension to import oil from Gulf states such as Texas and Louisiana. 

The lack of in-state production is the result of years of policies that have vilified the oil industry, including complicated permitting processes, excessive environmental regulation, and a generally high cost of doing business in the state. A key portion of the uniquely high cost of gas in California comes from environmental compliance standards, which add approximately $0.54 per gallon, but the additional costs don’t stop there. With the highest gas tax in the country at $0.61 per gallon, and with the federal gas tax of $0.18 and the California state and local sales tax, which adds $0.12 per gallon, Californians are forced to pay far higher prices for gas than in any other state, including Hawaii. 

Compounding the problem are the closures of some of California’s already diminished number of refineries. In response to the increasingly rising cost of production for refineries in the state, two refineries, Phillips 99 and Valero, shut down major portions of their operations in November 2025 and April 2026. The combined loss of their refining capacity has reduced California’s overall capacity by upwards of 20%. Such a substantial loss of refining capacity will lead to even higher prices at the pump, all while Sacramento seems intent on blaming everybody but itself for California’s dire fuel circumstances.

A threat to food costs

California’s fuel crisis is not only about gas affordability. Given the state’s sheer size and current status as the most populous, and as thousands leave in search of a lower cost of living, it is a clear and rising threat to food costs. California is one of the largest agricultural producers in the country, providing a third of the nation’s vegetables, three-quarters of America’s fruits and nuts, and 20% of the country’s milk. These agricultural feats are not, on their own, a security risk. They have become a vulnerability because of California’s high fuel costs. 

As California’s gas and diesel prices rise, so does the cost of production for farmers. When the cost of fueling tractors increases, the overall cost of production rises. Additionally, since two-thirds of America’s agricultural products are transported via specialized heavy-duty trucks, the cost of food has noticeably risen, which, since such a significant amount of America’s food is produced in California, where fuel is much more expensive, translates into higher costs for the consumer. Although fuel costs are rising nationwide, California’s unique role as a primary food source for the nation has made the combination of its special blend requirements for refining, high excise taxes, reliance on foreign oil, and diminishing refining capacity a risk to the American food supply chain.

California has some of the strictest environmental regulations in the country. Combined with a generally high cost of living, this has led both people and businesses to join a rapidly growing exodus from the state.

By requiring specific blend requirements beyond what most people would deem necessary, by instituting the highest gas tax in the nation, and by making it too artificially expensive to operate a refinery in the state, Sacramento has unnecessarily placed Californians in a seemingly permanent position of paying far more for fuel than the rest of the country; except when those fuel prices spill over into the transportation industry and lead to the ongoing rise in food prices for the entire nation.

Caleb Jasso is a senior policy adviser at the Institute for Energy Research and a native of California.

*This article was originally published by the Washington Examiner.

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Domestic Energy Producers Saved American Families $4 Trillion Since 2007

May 31, 2026 by Leave a Comment

The University of California at Berkeley’s Haas Energy Institute released a study on the shale gas revolution, noting that advances in hydraulic fracturing and horizontal drilling caused U.S. natural gas production to increase significantly. As a result, the United States became the world’s largest exporter of natural gas when it previously had been a net importer of natural gas. In fact, since 2022, the United States has been the world’s largest LNG exporter. In 2025, the United States exported 9 billion Mcf of natural gas. U.S. natural gas consumers now use over 33 billion Mcf of natural gas annually – over 50% more than a decade ago.

The study calculated that U.S. natural gas consumers saved between $3.1 and $4.3 trillion between 2007 and 2025, equivalent to $164-$227 billion annually, by producing natural gas domestically rather than buying LNG. The authors found that 39% of the savings went to electric power customers, with 30%, 18%, and 13% savings for industrial, residential, and commercial customers, respectively. Texas saved the most of any state.

Source: Energy Institute at Haas

The study assumed that without shale gas, the United States would have been importing LNG and U.S. consumers would have been paying LNG prices observed in Europe or Japan. That is, the study assumed the marginal unit of natural gas would be LNG. This is a strong assumption, as the authors admit. U.S. LNG imports were growing prior to the shale gas renaissance, but were still small relative to the overall market. While increased U.S. LNG imports are an alternative, other alternatives include increased domestic gas production or decreased consumption from demand destruction and/or fuel switching. As a result, the study estimates may be on the high side. Other analysts who made earlier estimates of savings found them to be much lower.

To calculate the savings, the study used gas price differences between the United States, Europe, and Japan. Between 1995 and 2006, prices were reasonably close to prices for Europe and

Japan is both within $1 per Mcf of the U.S. price, on average. Between 2007 and 2025, the U.S. price was below or equal to the price in Europe and Japan. Relative to Europe, U.S. gas prices averaged $9 lower per Mcf. Relative to Japan, U.S. prices averaged $11 lower. The difference in prices corresponds closely with the growth of shale gas, with price differences appearing at the inflection point for U.S. natural gas production.

Source: Energy Institute at Haas

There were other price shocks during that period, such as the one in Europe in 2022 when gas prices rose as a result of the Russian invasion of Ukraine. It is likely that U.S. LNG exports helped gas prices in Europe and Japan from increasing further due to the shortages created by the war. That situation was not explicitly represented in this study, but likely would have increased the calculated savings from shale gas, particularly after 2016, as U.S. LNG exports had increased.

This is similar to the current conflict in Iran, where it is believed that U.S. oil and gas exports are helping keep prices from escalating further.  Gas prices in Europe and Japan doubled in the first 10 days of March 2026, right after the attacks by U.S. and Israeli forces on Iran. Iranian attacks on LNG infrastructure in Qatar and elsewhere pushed gas prices up further. In contrast, U.S. gas prices barely budged, largely due to shale gas and hydraulic fracturing.

Conclusion

The University of California at Berkeley’s Haas Energy Institute found that the shale gas renaissance saved U.S. consumers between $3.1 and $4.3 trillion between 2007 and 2025, equivalent to $164-$227 billion annually, by producing natural gas domestically rather than buying LNG on the international market. Advances in hydraulic fracturing and horizontal drilling have significantly increased U.S. natural gas production, making the United States the world’s largest gas producer and exporter.

*This article was adapted from content originally published by the Institute for Energy Research.

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Free Ride For EV Owners Might Be Coming To An End

May 29, 2026 by Leave a Comment

U.S. gas and diesel owners pay a federal tax at the pump when filling up for the construction and maintenance of federal roads and other transportation activities. So far, EV owners have escaped such a tax despite placing more stress on roads than their internal combustion engine counterparts because of their heavy batteries. Since 1993, gas vehicle owners have paid a fuel tax of 18.4 cents per gallon, while diesel vehicle owners have been charged 24.4 cents per gallon. Now, the House of Representatives has a bipartisan highway bill that proposes to add a $130 registration fee for electric vehicles and a $35 fee for plug-in hybrids. The fee would increase by $5 every other year starting in 2029, but would not exceed $150 for electric vehicles or $50 for hybrids. If passed by the Senate, the provision would be part of the five-year Surface Transportation Reauthorization bill, a bipartisan bill that invests in roads, bridges, rail, and other infrastructure.

Opponents to the bill argue that flat EV fees hit low-mileage drivers harder, sometimes costing more than the federal gas taxes paid by the drivers of equivalent gasoline vehicles. Many states, however, have already implemented such user fees on EV owners. Forty states impose higher annual vehicle registration fees on electric vehicles and some hybrid vehicles to help offset lost state gas tax revenue. The state fees range from $50 in Hawaii and South Dakota to $260 in New Jersey. The fees have generally been justified as modest efforts to offset the loss of gas tax revenue from electric vehicles, which advocates claim are more environmentally friendly but still put wear and tear on roads.

The U.S. market for electric vehicles has been sluggish since the EV tax subsidy of $7,500 expired at the end of September last year. Americans purchased about 216,000 new electric cars in the first three months of 2026, according to Cox Automotive. Sales were down 27% year over year, after dropping 36% in the previous quarter. In terms of quarterly sales volume, the EV market has been set back to levels seen in late 2022.

Source: Inside EVs

While the U.S. market for electric vehicles has quieted down since the expiration of the EV tax subsidy last year, the global market is booming. According to a report by the International Energy Agency, global EV sales surpassed 20 million last year, about a sevenfold increase from 2020. The EV sales share in the global car market increased to 25%, and about 5% of the global car stock is now electric. The rising trend in global EV sales is expected to continue this year amid surging gasoline prices, driven by the jump in oil prices following the Iran conflict.

Source: IEA

The rise in global EV sales is helping the Chinese EV market to expand as more Chinese electric vehicles than gasoline vehicles were exported for the first time in April. Electric vehicles and plug-in hybrids accounted for just over half of the 769,000 vehicles that China shipped abroad in April, with exports of “new-energy” vehicles (electric vehicles and plug-in hybrids) accounting for 52.7% of total exports, according to the China Passenger Car Association. Exports of new-energy vehicles more than doubled to 406,000 units in April. Exports are expected to become the main growth driver for China’s auto industry, as China’s domestic market has slumped, with retail sales of passenger cars in April falling 21.5% from a year earlier to 1.38 million units — a 16% decline from March. EV export growth is expected, particularly in Europe and Latin America. Brands like BYD and Chery are expanding rapidly in Europe.

Analysis

Last year, the United States eliminated subsidies of up to $7,500 for EV purchases and leases, substantially slowing U.S. EV sales. Now, a bill that has bipartisan support has been introduced in the House that would impose an annual federal fee on EV owners. According to the bill’s sponsors, the fee would help fund highway maintenance, which is partly paid for by federal gasoline and diesel taxes. But opponents of the bill see the new EV fee as unfair, arguing it is significantly higher than what most Americans pay in federal fuel taxes. Nonetheless, electric vehicles stress U.S. roads and infrastructure due to the weight of their heavy batteries. Forty states have already assessed fees for electric vehicles to supplement state gas tax revenue.

Globally, EV sales are doing well, surpassing 20 million vehicles last year, about a sevenfold increase from 2020. The EV sales share in the global car market increased to 25%, resulting in about 5% of the global car stock being electric. The rising trend in global EV sales is expected to continue this year amid surging gasoline prices, driven by the jump in oil prices following the Iran conflict. That has helped increase exports of Chinese electric vehicles, which have exceeded exports of gasoline vehicles for the first time in April.

*This article was adapted from content originally published by the Institute for Energy Research.

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President Trump Saves Families From Costly Biden-Era Grocery Regulations

May 27, 2026 by Leave a Comment

President Trump is easing Biden-era federal regulations on chemicals used in commercial refrigeration and air conditioning — primarily hydrofluorocarbons (HFCs) — in an effort to reduce grocery prices and overall consumer costs by providing businesses more time to phase out the chemicals. This action involves extending compliance deadlines for a 2023 rule and revising a 2024 act to exempt road refrigerant appliances from leak requirements. EPA Administrator Lee Zeldin asserts that rolling back these “costly” Biden-era regulations will save businesses and consumers an estimated $2 billion to $2.4 billion annually, create jobs, and directly reduce grocery prices by allowing businesses to choose the best refrigeration systems.

Zeldin criticized the Biden administration’s “rushed, frantic, reckless sprint” to phase out refrigerants, claiming the rules did not protect human health or the environment but imposed unattainable restrictions. The Associated Press reports that, according to some industry groups, the easing could raise prices because manufacturers have already redesigned products, retooled factories, and trained workers to build and service next-generation refrigerant equipment. But grocery store executives from supermarkets such as Kroger and Piggly Wiggly attended the announcement and supported the deregulation to maintain affordable prices.

The White House estimates the changes will result in $900 million in savings, with $800 million specifically for grocery stores, and an additional $1.5 billion from the exemption for road refrigerant appliances. It will also safeguard more than 350,000 American jobs. The changes to the Biden-era rules will allow businesses more flexibility in choosing their refrigeration systems, thereby saving consumers from cost increases.

Background

The Technology Transitions Rule was put in place in October 2023 and originally stated that all technologies emitting higher-GWP HFCs or HFC blends would need to be replaced by January 1, 2025. A later amendment to the regulation in December 2023 allowed for installations until January 1, 2026. These dates did not allow sufficient time to safely meet the new compliance deadlines, and the Biden administration allowed only a few options for compliance.  The Trump EPA’s final revisions to the 2023 Rule extend compliance deadlines for the use of hydrofluorocarbons (HFCs), making a wider variety of refrigerants available to businesses while still meeting statutory requirements under the American Innovation and Manufacturing (AIM) Act of 2020, signed by President Trump during his first term. The added flexibility will allow supermarkets, home AC systems, semiconductor chip manufacturing, and the transportation of medical supplies to meet the law at a lower cost.

The AIM Act of 2020 directs the EPA to phase down the production and consumption of hydrofluorocarbons (HFCs) in the United States, aligning the country with the goals of the Kigali Amendment to the Montreal Protocol. The Kigali Amendment to the Montreal Protocol on Substances that Deplete the Ozone Layer is an international agreement to phase down the production and consumption of HFCs by 80 – 85% by 2047.

In the 2024 Emissions Reduction and Reclamation (ER&R) Rule, the Biden administration established HFC leak-repair requirements for road refrigerant transport appliances. The leak repair requirements apply to appliances that contain at least 15 pounds of HFC refrigerant used to transport perishable goods, even though most appliances in the transportation sector contain more than 15 pounds of refrigerant. According to the Trump EPA, the Biden administration made an error by subjecting the refrigerant transport sector to these leak requirements, even though it poses a low risk to human health, which is why the Trump administration is exempting it. The Trump EPA will also reconsider the rest of the Biden 2024 ER&R Rule.

According to Kroger CEO Greg Foran, the Trump EPA action ensures “an orderly transition” that allows the company to update its equipment “in a way which keeps the price of groceries down.” Kevin McDaniel, whose company operates 14 Piggly Wiggly stores in Florida, Alabama, and Georgia, said that the Biden-era rule would have forced many independent grocers out of business. “It was thrown together too fast,’’ he said. “The technology is not there yet. It’s just way too fast. That’s the problem. Good idea, but it’s terrible.”

Analysis

The Trump administration loosened federal rules requiring grocery stores and air-conditioning companies to reduce HFC’s from cooling equipment, which is expected to help lower grocery costs and AC costs for consumers. The EPA actions, a final rule revising the Biden-Harris Administration’s 2023 Technology Transitions Rule and a proposed technical fix to the 2024 Emissions Reduction and Reclamation (ER&R), address expensive restrictions that limit the type of refrigerants American businesses and families can use and how quickly they must be deployed. The actions are expected to save over $2 billion. The Trump EPA is still expected to comply with the American Innovation and Manufacturing (AIM) Act of 2020, which President Trump signed during his first term.

*This article was adapted from content originally published by the Institute for Energy Research.

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The Unregulated Podcast #275: Keep On Prancing

May 26, 2026 by Leave a Comment

On this episode of The Unregulated Podcast Tom Pyle, Mike McKenna, and Alex Stevens review what recent primary shake ups means for the future of the GOP. Later in the show they are joined by a special guest to discuss her plans to attend the University of Florida this fall and beyond.

Links:

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Iran Conflict Supply Shocks Highlight Importance of Domestic Energy Production

May 21, 2026 by Leave a Comment

The Wall Street Journal reports that the Iran conflict has caused about 15% of global oil supply to be removed from the market. Due to the supply loss, Brent crude oil prices, the world benchmark, are above $100 a barrel, and U.S. gasoline prices are averaging over $4.50 a gallon. The loss of Middle East oil supply has resulted in changes to the oil market, and supply flows with clear winners and losers.  Asia has been hit the hardest because it relies on the Middle East for about 60% of its imported oil. The disruption has also affected petroleum products like diesel and jet fuel, which also transit the Strait of Hormuz, which has effectively been closed to transit by Iran. Non-Persian Gulf producers such as the United States, Russia, and Brazil are exporting greater volumes of oil to replace lost Middle Eastern supply and can somewhat insulate themselves from the price increases caused by the Iran conflict.

In the United States, for example, oil exports have climbed by a third to 5.2 million barrels a day in April after Iran effectively blocked ship traffic through the Strait of Hormuz. The Guardian reports that U.S. exports of jet fuel have doubled to a record high as Europe is looking to secure supplies and airlines are cutting flights. The United States is the world’s largest oil and natural gas producer and a major net exporter of both. While oil and gasoline prices have increased in the United States because oil is a global commodity, natural gas prices have not been affected, as they remain largely determined by U.S. supply and demand.

The U.S. decision to ease sanctions on Russian oil to assist with supplies helped the country to receive higher prices for oil it had already loaded onto tankers. Russia doubled its main source of oil tax revenue in April, keeping its economy from falling into a recession despite using part of the increase to keep domestic fuel prices from escalating. The increased revenues may be short-lived as Ukrainian attacks are hitting Russian infrastructure, and the easing of sanctions is likely only temporary.

South America has significant domestic oil and gas production, large renewable and hydropower resources, and several major sources of future oil and gas supply that lie outside the Gulf. Brazil, Guyana, and Argentina are expected to drive much of the growth in non-OPEC supply. Venezuela is also producing more oil after the United States captured Maduro and set up its new leadership. Venezuela’s oil exports have approached 1 million barrels a day in March, the highest level since 2019, and U.S. refiners that need heavy oil are capitalizing on those exports.

In the Middle East, most of Iran’s neighbors are suffering major losses. Saudi Arabia and the UAE have invested in pipelines to the Red Sea and the Gulf of Oman, allowing each to bypass the Strait of Hormuz for roughly half of its prewar exports. Iraq’s exports have fallen sharply. Kuwait has exported little oil or refined products for 10 weeks. Qatar’s liquefied natural gas exports are offline, and damage to some of the country’s export facilities during the conflict could take considerable time to repair. Iran is losing substantial oil exports as the U.S. blockade hinders crude oil shipments. Because its oil fields and export infrastructure on Kharg Island appear to have suffered relatively little damage to date, Iran may restore exports relatively quickly if and when the strait reopens.

As storage reaches capacity, Middle East producers have been forced to stop production of about 13 million barrels a day. Once the strait reopens, it could take months to restore that supply, especially in Iraq and Kuwait, where large mature fields and aging infrastructure make stoppages harder to reverse. According to Rystad Energy, restarting the Persian Gulf’s shuttered oil and gas fields and drone-damaged infrastructure is expected to cost between $34 billion to $58 billion, and some could take years to restart. So, other non-OPEC sources of supply will be needed, as well as non-Persian Gulf OPEC+ supplies.

China is a large net oil importer and has relied on oil imports from the Middle East, buying 90% of Iran’s oil exports. China’s April bill for crude oil imports rose 13% from a year earlier after it was shut off from exports from Iran and Venezuela. EIA reports that China holds 1,541 million barrels in strategic oil inventories as of the end of the first quarter 2026, 3.7 times the strategic oil inventories of the United States. China is curbing imports through the use of inventories and reduced refinery runs and is reselling crude oil it had contracted to buy to other countries, often at a profit.

China has been working to curb growth in oil consumption through electric vehicles, which accounted for half of all new domestic vehicle sales last year. It has also greatly increased its exports of renewable technologies, particularly solar panels. These have been aided by China’s dominance in mineral mining, especially in processing and refining, which are central to renewable energy. China’s exports of solar technology capacity doubled to a record high in March, the first month of the Iran crisis, to 68 gigawatts–more than Spain’s entire solar power capacity. Exports to Africa rose by 176%, compared with February, and exports to Asia doubled. Countries in the EU, including Italy and Poland, had record solar imports too.

Japan imports meet more than 85% of its energy consumption, and in 2025, nearly all its crude oil imports transited through the Strait of Hormuz. To get through the conflict, Japan has released the equivalent of about 70 days of its oil consumption from its strategic reserves. The Island is energy resource-poor and is heavily dependent on maritime trade for essential goods. Energy security has long been a policy concern in Japan and may result in the country restarting more nuclear reactors and using more coal.

India imports nearly 90% of the crude oil it consumes, with half coming from countries that depend on the Strait of Hormuz for transit before the conflict with Iran began. It is importing oil from Russia—but not at the steep discounts it enjoyed after Russia’s invasion of Ukraine, when sanctions on Russian oil were in effect.

Analysis

The conflict with Iran has led to a reduction in oil supply from the Middle East and higher oil prices. Some non-Middle East oil-producing countries have been able to insulate themselves from the price shocks and are producing more oil to supplement the global market. Asian countries have been hit the hardest due to their heavy reliance on oil supplies from the Middle East. The conflict will most likely lead countries to place greater emphasis on the security of supply.

*This article was adapted from content originally published by the Institute for Energy Research.

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President Trump Approves Expansion Of Bridger Pipeline

May 20, 2026 by Leave a Comment

The Bridger Pipeline Expansion would bring Canadian oil into the United States, carrying up to 550,000 barrels per day through Montana and Wyoming, where it would link with another pipeline. The pipeline needs additional state and federal environmental approvals before construction, which is expected to begin next year, with an expected online date by the end of 2028 or very early 2029. The proposed pipeline is close to securing the minimum commitments from oil companies that it needs to continue with the project. At peak volume, the 650-mile pipeline would move two-thirds as much oil as the Keystone XL pipeline, which was partially built before President Biden withdrew the Presidential permit approved by President Trump when Biden took office in 2021. President Trump signed approval for the Bridger pipeline to cross the border between Saskatchewan and northeastern Montana.

More than 70% of the Bridger pipeline would be built within existing pipeline corridors and 80% on private land, so it is not expected to cross any Native American reservations. The proposal seeks to build the pipeline alongside existing pipeline infrastructure, which could make it easier to obtain required permits. The 36-inch line would carry various grades of oil for export or refining in the United States. U.S. refineries use Canadian heavy oil, and many were retooled from processing light oil to heavy oil before the shale oil renaissance that produced volumes of U.S. light oil. Canada is our largest supplier of imported oil. The Bridger pipeline is also authorized to carry other petroleum products, including gasoline, kerosene, diesel, and liquefied petroleum gas.

The Casper, Wyoming-based company, True Companies, operates more than 3,700 miles of gathering and transmission pipelines in the Williston Basin of North Dakota and Montana and the Powder River Basin of Wyoming. True Companies is overseeing the Bridger Pipeline Expansion project’s permitting, construction planning, and safety tech, including its AI-driven leak-detection system, FlowState. Bridger Pipeline developed an AI-based leak detection system that enables it to be notified more quickly of any problems. It also plans to drill 30 to 40 feet below major rivers, including the Yellowstone and the Missouri, to reduce the risk of an accident.

The route of the proposed Bridger pipeline would originate near Keystone XL’s planned border crossing. In Canada, sections of the Keystone XL pipeline were completed before the project was canceled and the pipe was left in the ground, leaving open the prospect that those segments could be used and connected to Bridger. Bridger could revive about 93 miles of track on the Canadian side that were built and are sitting idle, which would reduce construction costs and impacts.

Bridger would increase Canada’s oil exports to the United States by more than 12%, bringing much-needed pipeline takeaway capacity to Canada. Oil companies have committed to move at least 400,000 barrels per day, or about 72% of the pipeline’s initial capacity. The company is seeking long-term contracts for 450,000 barrels per day in committed capacity to green-light the project, which is 80% of the initial capacity that pipeline operators typically require before moving ahead with construction. Reuters reports that the project would eventually increase ​to 1.13 million barrels per day. According to analysts, the current project is not an end market for oil, so additional links would need to be built to refining hubs such as Cushing, Oklahoma; Patoka, Illinois; and the U.S. Gulf Coast.

Canada’s Oil Has Been Landlocked

Canadian oil, produced in Alberta, has been landlocked and is looking for outlets. After President Biden withdrew the Presidential permit for the Keystone XL pipeline, Canada built the Trans Mountain pipeline expansion from Alberta to British Columbia to carry oil and petroleum products. The Trans Mountain pipeline carries oil to the Pacific Coast, where it can be loaded onto tankers for export, opening up markets for Canadian oil along the U.S. West Coast and in Asia. The expanded Trans Mountain pipeline was completed and went online on May 1, 2024, with its capacity tripled to 890,000 barrels per day, comparable to that of the Keystone XL pipeline. Before that, the U.S. Midwest was the major market for Canadian oil, importing 90%, around 4 million barrels per day, of Canada’s oil via North-South pipelines from its main oil-producing region of Alberta. The Trans Mountain pipeline is planning a series of enhancements that could increase its capacity by 360,000 barrels per day.

The commitments by Canadian oil producers for the Bridger pipeline expansion, however, show the additional need for takeaway capacity for the country’s oil. Other expansions are underway. Reuters reports that last fall, Enbridge ​approved expansions for its Mainline and Flanagan ⁠South pipelines, which will allow an additional 150,000 barrels per day of Canadian heavy oil to move to the U.S. Midwest and Gulf Coast. That expansion is expected to come online in 2027.  The company is also assessing commercial interest in a second phase of its Mainline expansion of 250,000 barrels per day, which ​could be in service in 2028.

Analysis

President Trump has approved a Presidential permit allowing construction of the Bridger pipeline expansion to cross the border between Saskatchewan, Canada, and northeastern Montana. The 650-mile pipeline would move about two-thirds as much oil as the Keystone XL pipeline, which was partially built before President Biden withdrew its Presidential permit in 2021. U.S. refineries are equipped to process the heavy oil that Canadian imports provide. In addition to oil, the proposed pipeline is authorized to carry petroleum products, including gasoline, kerosene, diesel, and liquefied petroleum gas. The pipeline has almost all the commitments from oil companies that it needs and plans to be built on existing pipeline corridors and private land, avoiding issues from potential protesters. It plans to be operational by the end of 2028 or very early 2029, hopefully before President Trump’s term ends.

*This article was adapted from content originally published by the Institute for Energy Research.

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It’s Time To Unleash The Gulf Of America’s Energy Potential

May 20, 2026 by Leave a Comment

According to Rystad, shale oil cannot close the production gap expected by 2050 alone. The energy firm is forecasting a 76 million barrel per day need for new oil supply by 2050 due to rising demand and capital competition. Oil is not only needed for transportation, but also for heavy industry and petrochemicals. Rystad is projecting that offshore, particularly deepwater, production could dominate future oil production growth, which it was projected to do before the shale oil revolution was found to be more economic. A new report by the American Petroleum Institute and the National Ocean Industries Association, Unlocking the New South-Central Gulf of America for Energy Development: Potential Economic Impacts and Opportunities, identifies the South-Central Gulf of America as a potential new frontier for domestic energy production.

To help replace the natural decline of mature oil fields and to respond to the growth expected in demand, the report forecasts that the region could produce more than 470,000 barrels of oil equivalent per day by 2040, which would supplement the existing offshore Gulf production of nearly two million barrels per day. Oil and other liquids production would account for around 84% of production, and natural gas for around 16%. In the past, access to the Eastern Gulf planning area was restricted and unavailable for oil and natural gas development. However, in November of 2025, the Bureau of Ocean Energy Management proposed that lease sales be held, beginning in 2029, for a limited area of the Gulf of America, “Program Area B”, which is the newly designed South-Central Gulf of America Planning Area, and which excludes areas anywhere near the coasts of Florida. The area is adjacent to the Central Gulf planning area, as depicted below.

Source: Energy & Industrial Advisory Partners

The report projects that the oil and natural gas industry exploration, production, and operational spending would reach $13.1 billion. Industry-supported employment from this spending is projected at around 130 thousand jobs, and supported GDP is projected at just over $11.3 billion. The government would stand to gain $1.5 billion in annual revenue from lease bids, rents, and royalties to federal and state coffers.

Based on leasing beginning in 2029, the study projects that through 2040, nine projects would come online in the South-Central GOA Planning Area, with the first project beginning production in 2035. Unlike onshore shale projects, which can be started relatively quickly, offshore developments require billions of dollars in upfront capital and years of planning.

According to industry data, the Gulf of America produces some of the least carbon-intensive barrels of oil in the world. As such, the South-Central expansion offers a way to meet global demand with a lower environmental footprint compared to many international alternatives. It would continue to guarantee U.S. energy abundance and fill the gap that may be looming in meeting future demand from both the decline in mature fields and the increase needed in supply. A leasing program that allows companies to plan and invest can ensure standards for safety and environmental stewardship using the best-in-class technologies and operations.

Analysis

Forecasters are projecting a shortage in oil supply by 2050. While there has been a tremendous push for wind and solar in the generating sector, these sources cannot fill all the myriad needs that oil provides in heavy industry, petrochemicals, and numerous manufacturing activities.

The South-Central Gulf represents a natural extension to oil development in the Gulf, with access to a specialized workforce and infrastructure that exists in the region. With a consistent schedule of lease sales beginning in 2029, companies can justify the capital outlays required for deepwater exploration. The federal government providing that signal would ensure that the capital stays in the United States rather than migrating to oil and gas basins in Guyana, Brazil, or West Africa.

*This article was adapted from content originally published by the Institute for Energy Research.

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AEA’s Statement On Confirmation of New Bureau of Land Management Director

May 19, 2026 by Leave a Comment

WASHINGTON DC (5/19/2026) – The U.S. Senate voted Monday evening to confirm former U.S. Congressman Steve Pearce (R-NM) as the new Director of the Bureau of Land Management (BLM). This position will play a pivotal role in advancing President Trump’s goal of unlocking America’s abundant energy resources. 

Tom Pyle, President of the American Energy Alliance, issued the following statement:

“The Bureau of Land Management requires a leader who will ensure that America’s public lands are managed with transparency, accountability, and in accordance with the law. Former Congressman Pearce has a long, well-documented history of advocating for responsible land use and energy development, and possesses the knowledge and experience needed for this critical position.

“President Trump has assembled a top-notch team to unleash American energy and ensure our country remains an energy superpower. In this position, Director Pearce will be well-positioned to bring greater certainty to the permitting process and expand access to domestic resources. I commend the Senate on this approval, congratulate the new Director on his confirmation, and look forward to working with him in this important role.”

AEA Experts Available For Interview On This Topic:

Additional Background Resources From AEA:

For media inquiries please contact:
THOMAS.PYLE@ENERGYDC.ORG

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