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Governor Spanberger Hits Families Of Virginia With New Energy Tax

June 18, 2026 by Leave a Comment

Virginia is scheduled to formally reenter the Regional Greenhouse Gas Initiative (RGGI) on July 1, after newly elected Virginia Governor Abigail Spanberger signed a budget bill including a provision mandating the state rejoin the program. Virginia’s previous governor, Governor Glenn Youngkin, withdrew the state’s participation in 2023 when he was governor. Following the commonwealth’s return to the program, Dominion Energy filed a request with the State Corporation Commission to reinstate “Rider RGGI,” a fee to cover the cost of Virginia’s participation. It is projected that residential customer bills could increase by about $13 per month for customers using 1,000 kilowatt-hours per month during the March 2027 through February 2028 rate year under the proposed carbon-trading rider. Spreading some of the recovery costs over two years would lower the projected monthly impact to about $10.36. The cost increase depends on auction prices for allowances that permit utilities to emit greenhouse gases.

The RGGI is a regional cap-and-trade program that requires power plants to purchase carbon allowances through quarterly auctions, which allow them to emit greenhouse gases. It includes a carbon tax and a cap-and-trade mechanism. The carbon tax is a price per unit of carbon dioxide emissions. The cap-and-trade mechanism sets the total level of permissible emissions for participating states and allows power plants to trade corresponding emissions allowances under that overall cap. Power plants must purchase one allowance for each short ton of emissions. The emissions cap for power plants declines each year, making it harder to meet and potentially increasing the auction price. The Rider RGGI Virginians were required to pay per month until Governor Youngkin left the RGGI in 2023; the amount was $4.40.

Virginia is set to participate in the September and December 2026 allowance auctions. Utilities can request to recover those compliance costs through customer rate increases. The most recent RGGI auction cleared around $35 per ton, significantly higher than prices during Virginia’s earlier participation from January 2021, when then-Governor Ralph Northam joined the program, to December 2023, when Governor Youngkin withdrew from the program.

Virginia generated about $825.8 million in RGGI auction proceeds from 2021 through 2023. Of that, $413.9 million went toward low-income energy-efficiency programs through the Department of Housing and Community Development, and $372.5 million supported community flood preparedness programs through the Department of Conservation and Recreation.

Power plants in Virginia are also subject to carbon-free electricity mandates under the Virginia Clean Economy Act (VCEA) that mandates that the state’s primary utility, Dominion Energy, deliver 100% carbon-free electricity by 2045. So layering RGGI on top of those costs will further increase electricity costs. Virginia’s renewed participation in RGGI assumes the state never left, subjecting it to much tighter emissions caps that mandate a 61% reduction in carbon dioxide emissions by 2030 and a 92% reduction by 2037 from 2027 levels. Its return to RGGI could create allowance supply shortages in the future, as participating power plants anticipate higher demand for allowances driven by the emissions generated from power plants associated with artificial intelligence (AI) data centers. Virginia and Texas currently lead all states in housing data centers. Virginia’s data center boom has generated nearly $40 billion in economic output and contributed to lower residential property tax rates in data center hubs.

Source: American Action Forum

Dominion projects that Virginia’s electricity demand will grow by 5% annually starting in 2025 and double by 2045 – mostly driven by data center demand. Most new energy sources in Virginia would need to be emissions-free, and some existing fossil fuel sources would need to be replaced to meet the emissions-reduction target. Dominion concluded in its 2025 annual report that fully retiring fossil fuels before 2045 would be prohibitively costly and impact grid reliability. A state-commissioned study confirms that fossil fuels would need to remain a critical component of Virginia’s power mix. Under RGGI, reducing emissions or controlling and capturing them will drive electricity prices higher.

Further, sources considered emission-free, such as wind and solar, are intermittent and weather-dependent. Maintaining reliability under renewable-heavy systems requires significant investments in transmission infrastructure and backup generation. Estimates indicate that to meet the growing clean electricity demand for 100% clean electricity by 2035 and a zero-emissions economy by 2050, transmission systems will need to expand by 60% by 2030 and could triple by 2050. Wind and solar, however, cannot provide the dispatchable power needed to sustain hospitals, military installations, manufacturing, and data center operations 24/7.

Conclusion

Under the new Virginia Governor, Spanberger, the state will be rejoining RGGI, effective July 1. Dominion Energy, Virginia’s primary utility, has filed for a rate increase that is expected to add about $13 per month to a typical residential electricity bill—up from about $4 or $5 a month when Virginia was previously in the program from 2021 to 2023. Ten other states are currently members of RGGI, and many of them have near the highest electricity prices in the nation, including Massachusetts, New York, New Jersey, Connecticut, and Rhode Island. Virginia, known as Data Center Alley, is also facing rising electricity demand, which Dominion estimates will grow 5% annually and double by 2040, adding to the difficulty of meeting the RGGI emissions reduction targets.

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

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Gavin Newsom’s Anti-Energy Policies Becoming A National Security Concern

June 17, 2026 by Leave a Comment

The Trump administration is considering creating a Strategic Petroleum Reserve in California to enhance national security and address the state’s energy isolation, according to Energy Secretary Chris Wright. The proposed reserve would initially store 370,000 barrels of oil, with a potential expansion to 30 million barrels, and would support military installations and refineries in the state. The action would undermine Governor Gavin Newsom’s goal to continue reducing the state’s dependence on fossil fuels.

A document that lawyers for Sable Offshore Corp. sent to the Energy Department shows that the company proposed a West Coast Strategic Petroleum Reserve “in response to the inquiries made by the Trump administration and in the furtherance of Sable’s ongoing discussions with the Department of War for the supply of oil and gas to California.” Sable began producing oil offshore Santa Barbara earlier this year as the Trump administration invoked national defense powers—an action opposed by Governor Newsom. Newsom has criticized Sable’s relationship with the Trump administration, accusing the company of defying court orders during its restart.

The document also states, “The storage facilities and the connected and adjacent pipelines would make any oil stored in the facility available to serve the military installations in central, northern, and southern California, the remaining refineries in California’s major population centers, and further available for maritime transport via the port facilities in both the San Francisco and Los Angeles metropolitan areas, for onward transport to the military installations in the Asia Pacific region.”

The U.S.’s current Strategic Petroleum Reserve (SPR) is located in a series of salt caverns in Texas and Louisiana and has been seriously depleted of oil reserves during the Biden administration in its quest to lower gasoline prices before the mid-term election in 2022. Oil prices had risen due to Russia’s invasion of Ukraine, prompting the Biden administration to release over 400 million barrels from the SPR.

Due to the conflict in Iran, the Trump administration is in the process of releasing 172 million barrels of oil from the SPR to ease the higher oil prices that resulted from the closure of the Strait of Hormuz. California, which is dependent on oil and petroleum imports, recently received oil from the SPR. About 460,000 barrels of Bayou Choctaw Sweet oil are moving to Chevron’s Richmond refinery in Northern California, while an additional 50,000 barrels were delivered to the company’s El Segundo refinery near Los Angeles.

It is unclear how effective a SPR in California will be, given the state’s closure of its refineries and its retooling of some refineries to produce expensive biofuels that the state heavily subsidizes. Two California refineries closed in the past year due to onerous regulations and policies from the Newsom administration. California lost about 17% of its refining capacity with the closure of the Phillips 66 refinery in Los Angeles and the Valero refinery near San Francisco. California now has 11 refineries, down from 42 refineries 40 years ago.

The state is increasingly dependent on gasoline imports from Asia, where it gets about 20% of its gasoline supply. Due to the conflict in Iran and the effective closure of the Strait of Hormuz, Asian refineries are unable to obtain oil imports from the Middle East and have had to scale back their petroleum exports, exacerbating California’s petroleum problems. With President Trump’s waiver of the Jones Act, California has received some gasoline shipments from Gulf Coast refineries.

California boasts the highest gasoline prices in the nation, about $1.70 higher than the national average due to its policies and regulations. California has the highest combined gas tax in the nation at $0.709 per gallon, plus numerous hidden fees resulting from a cap-and-trade program to lower greenhouse gas emissions, a low-carbon fuel program, underground gas storage fees, and a state and local sales tax, all of which add to the price of gasoline. While fuel tax revenues are typically used for road repair, California diverts some of them to subsidize “green” jet fuel production. Newsom has proposed a $1- to $ 2-per-gallon credit for every gallon of alternative jet fuel, sustainable aviation fuel (SAF), “produced for use in California,” funded by the road repair budget.

Conclusion

The Trump administration is considering an SPR in California to enhance national security, as a number of military bases are located within the state, and to address the state’s isolation, since its fuel specifications differ from those of the rest of the nation, and few pipelines connect it to the rest of the country. The state is dependent on imports to supplement its declining oil and petroleum production, which, due to the conflict in Iran, have been limited. California, under Governor Newsom, has enacted anti-oil-and-gas policies and regulations, resulting in higher fuel prices than the rest of the nation, refinery closures, and declining oil production. However, the current SPR has frequently been used as a political tool, rather than a strategic asset, and there’s no reason to believe a Californian SPR would be handled much differently.

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

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The Unregulated Podcast #277: Even Stevens

June 16, 2026 by Leave a Comment

On this episode of The Unregulated Podcast Tom Pyle and Mike McKenna discuss the future of the Democratic Party and the net-zero agenda.

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Karen Bass Asks LA Voters To Give Copper Thieves A Raise With Solar Streetlights

June 15, 2026 by Leave a Comment

Everyone is talking about the June 2 primary election in California, especially the results in LA. But there was another election on June 2 that you might not have heard of, as you needed to own property to vote in it.

The election, known as a Proposition 218 Ballot Process, will determine whether LA property owners will pay a special tax assessment to raise money to replace broken streetlights with solar-powered ones.

Special ballots were mailed in April, and were due June 2. The vote count is ongoing, and results will be announced on June 26.

The issue has arisen because of rampant copper wire theft, which is disabling streetlights across the city.

Keeping the streets lit in America’s second-largest city is no easy task under normal circumstances. With upward of 223,000 streetlights, including an underground network of 9,000 miles of conduit and 27,000 miles of copper wire, the city of Los Angeles’s streetlight network illuminates the city’s roads and neighborhoods for its millions of residents.

Unfortunately, copper wire theft has risen to substantial levels, as a result of soft-on-crime policies and an overstretched police force that has plagued the City of Angels for years.

Instead of addressing the root of the problem, Mayor Bass and most of the LA City Council backed a Prop. 218 tax to raise $125 million to replace and update streetlights. Many of the new ones would be solar-powered. 

Updating public infrastructure is not bad; however, the current approach does not address the underlying problem of high rates of copper theft, which creates a strong incentive for people to commit the crime in the first place.

The tax would also raise property owners’ fees by up to 120% in an already extremely expensive place to live, given that Angelenos pay over 55% more than the national average for energy.

In 2023 alone, there were 6,842 reported cases of metal theft, leading to the creation of the LAPD’s “Heavy Metal Task Force,” which was tasked with combating the problem.

Unfortunately, in classic LA fashion, even though it was formed with good intentions and initially yielded promising results, it was disbanded by the omniscient leaders of the city in July of 2025 due to budget problems.

When copper wire thieves are caught, they have a high rate of reoffending. This high rate is driven by laughably low enforcement, low penalties, and the difficulty of catching offenders before they commit multiple crimes, given how easy it is to steal copper wire from streetlights.

Under California Penal Code § 487j, those who steal copper wire valued at more than $950 commit grand theft, which can be punished as either a misdemeanor or a felony, depending on the value of the stolen copper and the number of prior offenses the person has committed. 

However, with a local justice system operating more as a revolving door than anything else, even with a maximum penalty of a $10,000 fine and up to three years in state prison, many are likely to commit copper wire theft repeatedly before being stopped. And they are likely to do so again upon release from prison — if they are imprisoned at all. 

When a copper wire thief steals a few hundred dollars’ worth of copper, he or she causes thousands of dollars in damage. Each streetlight can cost up to $2,000 each to fix, costing taxpayers up to $20 million a year. 

When presented with a solution — a hardened cover for each streetlight at the cost of $300 each — the city of Los Angeles decided to ignore the practical and financially responsible choice and moved forward with pushing to convert thousands of streetlights to solar at upward of $6,000 per unit.

The solar decision was also political, designed to conform to the city’s LA100 Plan to achieve 100% carbon free power by 2035. But it won’t actually solve the underlying problem of theft.

Criminals have already demonstrated a willingness to scale streetlight poles to steal not only valuable core components, but the entire solar panel itself, which renders the streetlight useless.

Even solar panels that survive have inconsistent output due to weather conditions. They also require battery replacement every three to five years, costing an additional $150 to $1,000 per replacement.

June 26 is the day of the city’s final consideration, after the ballots have been counted, to determine whether the assessment passes.

The city of Los Angeles should take this time to develop real solutions to end its revolving-door-like criminal justice system, rather than converting 60,000 streetlights to solar power, which doesn’t solve the underlying problem of rampant crime. 

*This article was originally published by the New York Post.

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China Converting Coal To Liquid Fuel While Pushing Anti-Coal Agenda On America

June 11, 2026 by Leave a Comment

China has been the world’s dominant coal user and is consuming over half of the world’s demand, consuming more coal than every other country combined. The second largest coal consumer is India, which consumes less than a third of the amount of coal that China consumes. China uses coal to fuel its enormous fleet of coal generators, which is larger than the entire U.S. generating fleet of all fuel types, but also to convert coal into liquid fuels using Fischer-Tropsch — a process discovered in 1925, and used by the Nazis during World War II and by South Africa during the oil embargo of the 1980s. China is making liquid fuels from coal because it lacks natural gas and oil resources, but has a large coal base.

China consumes about 380 million metric tons of coal as a feedstock for chemical and liquid fuel production, representing about 8% of the country’s total coal consumption of 4,939 million metric tons. The International Energy Agency expects the sector to grow between 5% and 10% in the coming years, offsetting a decline in coal consumption to produce cement and steel in China.

Source: Bloomberg

China has been converting some of its coal into chemical products and liquid fuels in the “traditional” coal chemical industry, starting with metallurgical coal, converted into coke, and transformed into ammonia-based fertilizers and acetylene-based chemicals. Over the last two decades, however, China has employed new variations of the original Fischer-Tropsch process, along with other innovative methods, including methanol synthesis, to produce petrochemical goods such as olefins, which are used to make plastics. The new variations are typically referred to as the “modern” coal chemical industry.

In the new industry, coal is mined underground almost directly beneath the chemical facilities and carried by conveyor to the furnaces where it is gasified and transformed. Commercial-scale projects became popular in the 2010s, particularly in China’s heartland, where the bulk of the country’s coal fields are located. Erdos, a coal liquefaction plant located in Inner Mongolia, was the first plant of the type and has been operating since November 2010. It is the largest coal-to-liquids complex outside of South Africa, with a capacity of 20,000 barrels per day. The plant, which cost $2 billion, produced 866,000 tonnes of oil products in 2013. It uses 7-12 metric tons of fresh water per metric ton of product and generates 4.8 metric tons of wastewater and nine metric tons of carbon dioxide per metric ton of product.

The process enhances energy security for China due to its reliance on imported oil and gas. For example, last year, China accounted for nearly 50% of U.S. ethane exports (230,000 barrels per day out of a total of 492,000 barrels per day), primarily used to produce plastics. The Trump administration sees these exports as an unacceptable risk due to their potential use in military applications. As such, the United States is making American exporters of ethane or butane apply for export licenses if they plan to ship ethane to China.

Source: EIA

Ethane is a natural gas liquid that is primarily extracted from raw natural gas during processing. It is primarily used as a feedstock for ethylene production, a crucial building block in the petrochemical industry. Ethylene is used to produce a wide range of products, including plastics, resins, and synthetic rubber. The United States and Norway are the only countries with the infrastructure to export waterborne ethane; however, ethane has not been separated from the natural gas stream in Norway over the past few years due to high natural gas prices in Europe.

China Is the World’s Largest Emitter of Carbon Dioxide

With China’s vast coal use, it is the world’s largest emitter of carbon dioxide, and converting coal to liquid fuels will only make the country emit more carbon, particularly as that industry grows. In 2023, China emitted 11,218 million metric tons of carbon dioxide — 32% of the total carbon dioxide global emissions in that year — and 6.1% higher than its carbon dioxide emissions in 2022.

China’s pledge to the United Nations is to have its carbon dioxide emissions peak by 2030 and then begin to reduce them, with net-zero emissions reached by 2060. Its quantitative targets for 2030 include cutting carbon dioxide emissions per unit of GDP by more than 65% from 2005 levels and increasing the share of non-fossil energy to around 25%. But its actions regarding its coal industry and uses show an entirely different direction, despite adding solar and wind power and housing the electric vehicle (EV) firm with the most significant global sales, BYD, which has surpassed Tesla in EV sales. China turned to manufacturing solar panels, silicon, and electric vehicles to increase exports by marketing them to Western countries that had stringent goals for reducing carbon dioxide.

Conclusion

China is the world’s largest consumer of coal for generation and industrial uses, but its coal is also being converted to liquid fuels to supplement China’s oil and petroleum imports. China is the world’s largest importer of oil, importing 11.1 million barrels per day in 2024. China imported almost half of the total U.S. exports of ethane in 2024, prompting the Trump administration to issue new licensing rules requiring companies to seek approval before exporting ethane or butane to China. China, as the world’s largest emitter of carbon dioxide, does not seem to be making inroads in reducing those emissions. Instead, it is finding new uses for its coal.

*This article was adapted from content originally published in June, 2025 by the Institute for Energy Research.

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America’s Grid Grows Stronger Under President Trump’s Energy Dominance Agenda

June 10, 2026 by Leave a Comment

According to the Federal Energy Regulatory Commission (FERC), U.S. grid reliability will improve this summer as 75 gigawatts of capacity are being added to the grid, and power plant retirements are expected to slow by more than 50% to 8 gigawatts. The increase in capacity is the largest one-year increase in over a decade. With the added capacity, resources, and operating reserves are expected to be adequate in all NERC assessment areas under normal operating conditions. However, high temperatures and extreme weather events, such as low snowpack, continued drought, and wildfires, could strain the grid in certain areas. Low water levels are also expected to restrict hydropower generation in key regions, particularly in the Colorado River Basin, where about 4.5 gigawatts of hydroelectric generation could be affected by August.

According to FERC’s annual summer market and reliability assessment, the capacity additions include nearly 26 gigawatts in the Electric Reliability Council of Texas footprint, close to 13 gigawatts in the Western Electric Coordinating Council region, and 11 gigawatts in the Midcontinent Independent System Operator region. Even with the new capacity, three areas in the United States face risks of power supply shortfalls during extreme conditions: the Pacific Northwest, New England, and part of western Texas.

Source: Canary Media

Natural gas demand and production are both expected to increase, providing more generation. U.S. natural gas demand is expected to average 101.3 billion cubic feet per day this summer, 1.6 billion cubic feet per day more than summer 2025 levels and 8% more than the previous five-year summer average of 93.8 billion cubic feet per day. FERC expects gas-fired generators will provide 39% of capacity this summer, followed by solar at 14%, coal at 13%, wind at 12%, and nuclear and hydropower at 7% each. The new capacity consists of 7 gigawatts of gas, 30.5 gigawatts of solar, of which only 16.4 gigawatts contribute during peak summer demand due to its inefficiencies, and over 16 gigawatts of expensive battery storage capacity. The capacity additions are heavily weighted towards solar and wind as the subsidy schemes of the Inflation Reduction Act continue.

Natural gas production is expected to be slightly higher this summer than last, driven by continued strong production from major shale fields. The Energy Information Administration (EIA) forecasts U.S. dry natural gas production to average 109.3 billion cubic feet per day during summer 2026–a 1% increase from the summer 2025 average of 108.2 billion cubic feet per day and is 7% above the previous five-year average of 101.8 billion cubic feet per day.

Source: FERC

Total electricity consumption is projected to reach 1,587 terawatt-hours this summer. EIA forecasts that electricity consumption from June to September 2026 will increase by 106 terawatt hours from the summer of 2021–a 7% increase. Summer 2026 is projected to grow 3% year-over-year compared to summer 2025, the most significant year-over-year growth since summer 2022, and is 4.5% above the previous five-year average of 1,518 terawatt hours. EIA’s projections for monthly consumption this summer indicate demand will peak in August 2026, at 426 terawatt-hours, a 5% increase from August 2025.

In several regions, coal and natural gas-fired plants that were slated to retire, more than 4,300 megawatts, are continuing to operate pursuant to DOE Orders under section 202 (c) of the Federal Power Act (FPA).

NERC projects that summer peak demand across North America will grow by about 224 gigawatts over the next decade, a 69% increase over the previous year’s ten-year forecast and about a 24% increase from 2025 peak demand.  Most of the new load is due to an increasing number of new data centers.

More new generating capacity is coming as power pools are fast-tracking interconnection reviews to get power supplies online quickly. SPP is advancing about 13.3 gigawatts concentrated in Oklahoma, Kansas, and Texas, with 2029/2030 online targets, and MISO is advancing 20.9 gigawatts mainly in Louisiana, Indiana, and Wisconsin, with 2027/2028 in-service dates.

To speed up permit times, FERC has proposed expanding its “blanket certificate” program for certain types of “routine” gas pipeline projects deemed not to require project-specific authorizations. The program was last updated in 2006. Projects identified as high risk, however, will continue to undergo a comprehensive review. In addition to gas pipeline projects, FERC is advancing blanket authorization initiatives for liquefied natural gas and hydropower facilities.

Analysis

FERC’s summer assessment views the grid to be reliable this summer under normal conditions. Under extreme weather conditions, three regions in the United States (the Pacific Northwest, New England, and part of western Texas) face risks of power supply shortfalls. U.S. utilities are adding 75 gigawatts to the grid this summer, composed of solar, wind, natural gas, and battery resources. While that increase is the largest one-year increase in over a decade, caution is warranted given the intermittency of wind and solar power, which provide only a fraction of their design capacity because the wind and sun are unreliable energy sources. Further, storage batteries are expensive and are not generators in themselves; they store power generated by other sources and release it when needed. The Trump administration has also slowed the retirement of over 4.3 gigawatts of fossil fuel generators, which will help this summer if needed.

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

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Gavin Newsom Spends Millions On “Free” Solar Panels For Non-Citizens

June 10, 2026 by Leave a Comment

California’s Farmworker Housing Component provides solar technology and efficiency upgrades to low-income farmworker households at no cost to them. The program is funded from revenues that come from California’s “cap-and-invest climate program,” which taxes companies that emit carbon and redistributes approximately $3 billion per year to energy programs and left-wing social causes. It is part of the state’s Low-Income Weatherization Program. Critics have reframed it as “California Is Giving Free Solar Panels to Illegal Aliens” since participants do not need to be citizens. The state has earmarked about $49 million since 2019 for the farmworker component, serving about 2,000 families, resulting in an average cost of about $23,000 per household.

To qualify, at least one household member must be an agricultural employee, and the household must meet income guidelines. They may not earn above a certain threshold–$49,000 for a couple, $62,000 a year for a family of four. That is, they must be at or below 80% of the Area or State Median Income. The property must be located in one of the targeted California counties with the highest farmworker populations. The farmworkers program began in two counties in 2019 and has expanded to 18 of the state’s 58 counties.

Services are provided for single-family homes as well as small multifamily buildings (2 to 4 units) that are either owned or rented by the farmworker family. Depending on the home’s needs, upgrades may include solar panels, central heating/cooling, insulation, water heaters, window replacements, and energy-efficient appliances (refrigerators, freezers, washers, dryers).

The program so far has not covered the cost of storage batteries, which would allow homeowners to store energy from sunlight for later use when the sun goes down. Voters approved a $10 billion climate bond last year, and the program would like to use that money to fund batteries, allowing participants to run their appliances and homes with stored energy. Using stored energy, the household would essentially be off the grid unless the batteries provide insufficient backup power.

The state has heavily advertised the program to California’s nearly 900,000 agricultural workers, half to three-quarters of whom are illegal immigrants. California’s Department of Community Services and Development acknowledges that non-citizens are eligible for the program and that they even accept identification from foreign governments. That is, participants do not need “legal status” in the United States. An estimated 18% of California’s farmworkers own homes and could benefit from energy upgrades.

California’s Department of Community Services and Development selected La Cooperativa Campesina de California, a nonprofit that serves farmworkers, to administer the program through a competitive procurement and an initial funding award of approximately $10.7 million. La Cooperativa, in turn, has partnered with a for-profit, “minority owned” company, MAROMA Energy Services, to help run the program. Contractors do the work of installing solar panels and other appliances in homes.

Another California Solar Program for the Poor

The Solar on Multifamily Affordable Housing (SOMAH) program began under Governor Jerry Brown, who signed legislation requiring a state commission to allocate up to $100 million per year from California’s cap-and-trade program (now cap-and-invest) to pay for installing solar panels on apartment buildings in low-income areas. California has allocated nearly $900 million to SOMAH in the hopes of obtaining 300 megawatts of solar power by 2030. Since 2015, the program has installed only 129 megawatts of solar power for approximately 65,600 residents—nowhere close to the target of 1 million “solar renters” that advocates wanted—at a cost of $131 million.

Customers were turned off by the paperwork, bureaucracy, and red tape. On average, projects take three and a half years to complete the program’s paperwork and inspections. More than 400 applications have been either canceled or withdrawn, or about a third of the total. Some projects that were fully installed have been waiting for permission to begin operating for a year or more. More than $700 million of the program’s budget has not been spent.

Some companies, however, are profiting. The managers of the SOMAH program have spent about $60 million on overhead, including salaries, conferences, and website development. And, San Francisco-based Sunrun Inc., a solar provider, has been the contractor for 78% of SOMAH projects. The company donated hundreds of thousands of dollars to political candidates—including $50,000 to Gavin Newsom’s campaigns—and has employed lobbyists in Sacramento. Newsom hired former Sunrun employees to work in his administration. The governor appointed the company’s public policy manager to the California Energy Commission and appointed its former chief policy officer to a regional water quality control board.

Analysis

California has solar and/or energy-efficiency programs that provide technology to low-income families at no cost to them. California’s Farmworker Housing Component and the Solar on Multifamily Affordable Housing program obtain their funds from California’s cap-and-invest program, which taxes companies that emit carbon and redistributes those funds to projects that fund “clean” energy. The farmworker program provides free solar, heat pumps, and appliances to farming households that qualify based on location, income, and housing type. Participants in that program, however, do not need to be U.S. citizens to qualify. In the case of SOMAH, the program is run so inefficiently that most poor families lose interest and cancel or withdraw. Neither program is reducing greenhouse gas emissions appreciably. And some poor folks find it hard to justify poking a hole in their roof for a small amount of benefit.

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

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The Unregulated Podcast #275: Firing In A More Moderate Manner

June 8, 2026 by Leave a Comment

On this episode of The Unregulated Podcast Tom Pyle, Mike McKenna, and Alex Stevens cover the top stories of the week and later they are joined by Diana Furchtgott-Roth, a Distinguished Fellow at The Energy Policy Research Foundation, for a discussion on the future of America’s energy policy.

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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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