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On this episode of The Unregulated Podcast Tom Pyle and Mike McKenna discuss the leftward lurch of Democrat primaries across the country, Republican’s odds of keeping their majority after mid-terms, updates coming online to the electric grid, and more.
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When there is less sun and less wind, solar and wind power output will drop. The same is true of hydropower. If there is less rain and snow and the water behind dams falls, hydropower output will be lower. In February 2021 in Texas, a major storm reduced wind power output, prompting the state to rely on natural gas and coal, yet many consumers still lost power. In 2024, a major hailstorm outside of Houston dismantled a large solar panel facility. And studies show that output from solar, wind, and hydropower has fallen in certain regions during El Niño years, as cloud cover, wind patterns, and rainfall change. El Niño is a natural climate cycle, typically recurring every two to seven years and lasting for about a year.
Texas Storms
Texas leads the nation in wind-powered generation and was the first state to reach 10,000 megawatts of installed wind-generating capacity, subsidized by state mandates and federal tax credits. By the end of November 2020, installed wind capacity in Texas was 29,230 megawatts, and wind turbines at Mes had generated over half of the Texas power generation. When a storm hit in February 2021, wind generation dropped off, demand surged because of the cold, and fossil-fuel generation increased to cover the supply gap. Between the mornings of February 7 and February 11, wind as a share of the state’s electricity fell to 8% from 42%. Gas-fired plants produced 43,800 megawatts of power and coal plants produced 10,800 megawatts—about two to three times what they usually generate at their peak on any given winter day. Between 12 a.m. on February 8 and February 16, wind power plunged 93% while coal increased 47% and gas increased 450%.
In mid-March, 2024, a massive hailstorm crippled a 3,000-acre solar panel facility 40 miles outside of Houston. The storm sheared hundreds of panels, prompting nearby residents to worry that toxic chemicals may be leaking from them and endangering local water tables. The hailstorm caused damage to the solar panels at the Fighting Jays Solar facility, a 350-megawatt project brought online in July 2022 in Fort Bend County, Texas. According to the Department of Energy, hailstones the size of baseballs can have sufficient kinetic energy to shatter solar panel glass completely. The hail ranged in size from quarters to golf balls and even baseballs.
Texas is not the only state that has been hit by hail. In June 2023, a massive hailstorm destroyed a PV solar facility in Nebraska. The solar panels at a 5.2-megawatt solar farm in Scottsbluff, Nebraska, were mostly destroyed by baseball-sized hail moving at 100 to 150 miles per hour. The system’s 25-year expected life was cut to less than 4 years, leaving a toxic mess to clean up.
El Niño Weather Effects
A 2024 study on renewables in Texas found that both solar and wind power supplies tend to decline during El Niño. Extreme El Niño-driven heat can increase solar generation but also drive electricity demand up and strain the grid. In parts of the Western United States, particularly California, as well as parts of South America, the Middle East, and eastern China, the researchers found that El Niño reduces solar radiation and causes solar energy to decline despite growing solar energy capacity. The study also found that the effects are strongest during ‘super El Niño’ events, which cause temperatures in the central and eastern Pacific Ocean to rise more than 2 degrees Celsius above their average levels. These events have only occurred three times since the early 1980s. Parts of Asia have seen declines in wind power during El Niño events. Based on past events, researchers estimate that the next super El Niño could reduce solar power output by about 5% in California and by 10% in parts of southeastern China.
For wind, El Niño can shift storm tracks and change wind speeds, sometimes leading to less consistent or weaker wind patterns in key Texas wind corridors. This can reduce the efficiency of wind farms, especially in the Panhandle and West Texas regions where Texas leads nationally. In Texas, the combination of reduced solar irradiance and altered wind patterns can create a dual hit to renewable generation. Lower solar and wind output during El Niño can increase reliance on natural gas and other dispatchable sources. Parts of Asia have also seen declines in wind power during El Niño events.
In some areas of South America and southern Africa, El Niño reduced hydropower output. In Colombia, where hydropower supplies up to 70% of the nation’s electricity, a strong El Niño in 2015 and 2016 caused water levels in the country’s dams to drop by 60 to 70%, according to a report from the World Energy Council. The 2015-2016 drought was the second-strongest in Colombia’s history. Rainfall was 40% below normal, resulting in a severe hydrological drought. Hydropower generation also dropped across other parts of the continent, including Brazil and Ecuador, as one of the worst droughts in decades affected the region. The Energy Information Administration reports that in the summer of 2015, a strong El Niño caused hydroelectric generation in Washington and Oregon, which provides the largest share of electricity generation in the Pacific Northwest, to be below normal, leading to increased reliance on natural gas and other fossil fuels to meet electricity demand.
El Niño comes as some world leaders, particularly in Europe and China, are considering expanding their renewable energy portfolios due to higher oil and gas prices resulting from the conflict in Iran. If countries continue on the renewable path, utilities and policymakers may need to adjust forecasts and reserve capacity to account for El Niño’s dampening effect on renewables.
Conclusion
Wind and solar power are affected by weather conditions and must have back-up, which essentially means a secondary system, whether that power is provided by coal, natural gas, or nuclear, or by very expensive storage batteries that store power when there is excess wind and/or solar power and release it when these sources are in a lull. Adding system costs to wind and solar power no longer makes them the cheap energy sources the media and environmentalists tout. Further, intermittent renewable sources are even more expensive when they no longer get the massive subsidies that they have been receiving for decades. With a super El Niño expected, the likelihood of solar, wind, and hydro output dropping is highly likely, and utility planners need to be prepared. Significant policy-driven changes have led to more weather-dependent energy sources in the United States and around the world, and utility planners must recognize the increased challenges to the reliability and affordability of these policies.
WASHINGTON DC (7/1/26) – The State of California’s excise tax on fuel is scheduled to increase today by an additional 2.2 cents per gallon of gasoline and 1.6 cents per gallon of diesel, adding yet another cost for motorists in a state that already has the highest average gas prices, as well as fuel taxes and fees, in the nation. The increase comes just ahead of one of the busiest travel weekends of the year.
Tom Pyle, President of the American Energy Alliance, issued the following statement:
“California families, who already pay the highest fuel prices in the nation, are about to pay even more thanks to a state government that treats their tax dollars as a slush fund for their reckless green agenda. This weekend, while we celebrate the 250th birthday of our great nation and the founders who rejected the idea of oppressive taxation, Californians will once again be hit with more burdensome taxes – you almost have to appreciate the irony.
“Gavin Newsom has continuously blamed the Trump administration for his state’s high gas prices in an attempt to deflect from his own failed ideological crusades. The fact is that Sacramento is deliberately imposing ever-increasing energy prices on its constituency through misguided, costly green mandates and ongoing tax hikes. Almost a third of Californians are living in poverty. It is unconscionable that their state government continues to make life even harder by piling on costs to those already struggling to make ends meet. This Independence Day, Californians should be celebrating our nation’s freedoms and looking for new representation as they consider their continued increasing taxation.”
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Chevron plans to reach a final investment decision later this year on a power plant that would use natural gas to supply Microsoft’s 2.7-gigawatt Project Kilby AI data center in Reeves County, Texas, under a 20-year agreement. The final investment decision will be made after the project receives all its permits, expected later this year. The Project Kilby data center would start receiving power in late 2028, and a fuller build-out would continue into the 2030s. Most of the electricity will come from large gas turbines supplied by Chevron’s partner, GE Vernova, with additional turbines provided by Caterpillar. The power will initially supply just the data center and will not be connected to the electric grid. Any excess power, however, will be provided to stabilize the grid when it connects to the grid at a later date, according to Jeff Gustavson, president of Chevron New Energies. Construction has not yet started on the data center.
Chevron is working with Joulent, an energy company launched by investment firm Engine No. 1, to build a power-generation complex to supply the data center with natural gas produced from Chevron’s fields in the area. The collaboration between Chevron and Joulent is their first big AI data center project. The 2.7 gigawatt center would be housed on more than 2,000 acres in the heart of the Permian Basin oil-and-gas field. The site is located about 20 miles south of Pecos, where Chevron has been producing oil and gas for years.
Wait times for grid-connected electric service can be five to seven years in many places. Because data centers need faster access to electricity, the concept of “Bring Your Own Power (BYOP)” provides faster access and avoids cost impacts on other ratepayers. About a quarter of all data center capacity under development plans to build their own power on-site. Data provider Cleanview is tracking 59 of those data centers with a combined capacity of about 90 gigawatts. The Trump Administration has encouraged companies to pursue this route where possible, to speed construction and deployment of infrastructure.
There are engineering challenges to building “behind-the-meter” projects. Without a grid connection, the Kilby project will require an overbuild of power equipment and a large battery storage system to maintain reliability. Because solar resources in West Texas are better than in other areas, and with the complex already planning a large battery storage system, the project developers may add solar power at a later date.
Microsoft plans to invest $190 billion in capital expenditures this year, up 61% from 2025. Because the rapid growth of AI requires energy infrastructure that can scale quickly and reliably, the partnership with Chevron makes sense, as Chevron can deliver natural gas from the Permian Basin, located in West Texas and southeastern New Mexico, to data centers at a competitive cost.
Microsoft needs power sources that can reliably meet the 24/7 demand of its data centers, which wind and solar power alone cannot provide due to their intermittency, despite the company having invested heavily in them earlier. To provide reliable power 24/7 and limit carbon dioxide emissions, Microsoft invested in the restart of the Three Mile Island nuclear plant in Pennsylvania in 2024. Constellation Energy plans to restart the nuclear plant on schedule in 2028, supplying power to Microsoft and helping stabilize the grid. The plant will be renamed the Crane Clean Energy Center; the restart will cost $1.6 billion, financed by the company’s funds. Microsoft agreed to purchase the plant’s Unit 1 electricity output for 20 years.
Other partnerships may be in the works. Late last year, Exxon Mobil partnered with NextEra Energy to develop a 1.2-gigawatt gas-fired power plant with carbon-capture technology. At the time, the companies were in talks with a potential data-center customer. NextEra and Google are developing three data center campuses and are seeking additional locations. In October, the companies announced a deal to restart a NextEra nuclear reactor in Iowa. NextEra’s goal is to have 15 gigawatts of new power generation for data center hubs operating by 2035.
How China Powers Its Data Centers
Last year, the International Energy Agency (IEA) reported that China’s data center electricity supply was dominated by coal, with a near-70 % share, followed by renewables with near 20%, nuclear power with near 10%, and natural gas accounting for the remainder. Between 2024 and 2030, coal is expected to remain the largest source of additional electricity for China’s data centers, with annual generation increasing by nearly 90 terawatt hours.
However, Oil Price reports that China has just launched the world’s first offshore wind-powered underwater data center, using seawater cooling and renewable electricity to reduce energy, water, and land requirements. The 24-megawatt-capacity Shanghai Lingang undersea data center demonstration project was made possible by an investment of around $238 million. It is located over 10 miles off Shanghai’s coast, submerged 10 meters below the water’s surface, and is mainly powered by an offshore wind farm.
Conclusion
Chevron and Microsoft are partnering to build a large data center in West Texas, fueled by natural gas turbines that will not initially be connected to the electric grid. The concept of “Bring Your Own Power” is becoming more widespread as data centers can obtain electricity more quickly by building their own power sources without affecting other consumers’ rates. A final investment decision on the Project Kilby data center power source is expected later this year, once permits have been obtained. If it is a go, the data center would start receiving power in late 2028, and a fuller build-out would continue into the 2030s. About a quarter of all data center capacity under development plans to build their own power on-site. The Trump Administration has encouraged companies to pursue this route where possible, to speed construction and deployment of infrastructure.
California has become one of the most expensive places to live in the United States. Whether it be the cost of housing, exorbitantly high income taxes, or especially the cost of energy, high costs have pushed many people and businesses to leave for more affordable states such as Nevada, Texas, or Florida.
Of the many famously high and onerous taxes that plague California, few come close to the celebrity of California’s fuel taxes, which are set to increase on Wednesday by an additional 2.2 cents to 63.4 cents per gallon of gasoline, and by 1.6 cents to 48.2 cents per gallon of diesel — just in time to celebrate Independence Day.
Terrible roads in exchange for the country’s fuel taxes
The cost of fuel in California has been high for many years due to a combination of environmental fees, totaling around 54 cents per gallon, self-imposed supply chain limitations that have led to refinery closures, and a progressively increasing state excise tax.
However, the abnormally high fuel cost has come under extra scrutiny recently due to price fluctuations of gas and diesel as a result of the Iran war and the chaotic closing and reopening, and then closing and reopening again, of the Strait of Hormuz. The strait serves as a transit corridor for upwards of 20% of the world’s global flow of energy, such as oil and natural gas, and California imports approximately 30% of its oil from the region.
Beyond the unnecessarily overextended fuel supply chain, much of which would be uncomplicated if in-state production were prioritized, let alone encouraged, lies the challenge of identifying how these high taxes and fees, upwards of $14.4 billion in 2025, are improving the transportation infrastructure of the state, given that it arguably has some of the worst roads in the nation.
Every state and the District of Columbia levies a fuel tax, in addition to the federal gas tax of 18.4 cents per gallon and the diesel tax of 24.4 cents per gallon, to fund transportation infrastructure, which is supposed to prioritize road maintenance. In California, even after collecting the highest fuel-related taxes and fees in the country, the transportation infrastructure remains abysmal.
The primary reasons are unsurprising given the notoriously poor management of the state’s political leadership. Bloated bureaucracy, high administrative costs, and excessive red tape have led to multiple years of backlogs and maintenance deferrals, increasing the cost of repairing and expanding California’s roads by billions of dollars.
Compounding the problem of inconsistent maintenance is California’s umbrella-like disbursement of funds without clear intent and a lack of genuine transparency or accountability. Even with the promise of increased transparency and a better allocation of funds from the Road Repair and Accountability Act of 2017, the spending discretion of funds by local and state bureaucracy has led to further distrust in public leadership and a tangibly low return on public investment for better roads.
Another key factor behind rising fuel taxes and poor-quality roads is the present and projected future loss of revenue, upwards of $1 billion by 2027, due to the forced adoption of electric vehicles and the general adoption of more fuel-efficient vehicles, including hybrids, by Californians.
Those who have been able to afford EVs, which have historically come with economically unfair tax subsidies, haven’t had to pay the gas tax, and those who have opted for more fuel-efficient vehicles simply don’t have to fill up as often. For this reason, Sacramento has been experimenting with a road usage tax calculated per mile driven, but it is unlikely that fuel taxes would go away if, and when, this were to be passed, given the tax-glutinous nature of California’s leadership and the improbability that millions of residents would trade in older, likely paid off, vehicles, in exchange for an EV they might not want.
Two hundred fifty years of independence just to pay high taxes again
Saturday marks the 250th anniversary of the United States, a nation founded on the principles of individual liberty, freedom, and the pursuit of happiness. Contrary to these important concepts, Sacramento continues to demonstrate a lack of understanding of America’s founding principles by once again raising a burdensome tax that has historically yielded a poor return on investment for Californians and imposing limitations on many seeking to travel, let alone drive to work or visit loved ones.
The indifference, arrogance, and contempt that California’s political leadership holds for its residents are precisely the qualities that Americans fought against in the nation’s war for independence as they sought freedom from taxation without representation. As Californians prepare to pay higher taxes on gas and diesel yet again, and just three days before Independence Day, they should really start to question whether America’s founders would have wanted people to be seen by their representatives as nothing more than a source of tax revenue.
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.
The Department of the Interior proposed major changes to Bureau of Land Management (BLM) rules regarding onshore oil and gas leasing and waste prevention to promote energy dominance and encourage domestic energy production. It is proposing to loosen two major Biden-era regulations: one on methane releases and the other on plugging non-operating wells. Producing more domestic energy provides jobs and enhances security while making products more affordable.
In 2024, the Biden administration dramatically raised the cost of bonds that oil and gas companies must pay the government to ensure that their wells will be cleaned up. The Trump administration is proposing to drop those rates back to their pre-Biden levels, before they increased them 20-fold from $25,000 statewide to $500,000 statewide. The rule would revert to the system in place at the beginning of 2024, “while gathering public input on a fair long-term approach.” In 2021, an analysis by non-profit Resources for the Future estimated that it costs about $20,000 to plug a single oil and gas well.
Also in 2024, the Biden administration clamped down on methane emissions from oil and gas produced on federal lands by requiring oil and gas firms to either certify that they will capture all of the oil and gas produced by their wells or produce a plan to reduce their methane releases. The Trump Interior Department is proposing to remove that requirement.
Oil drillers usually flare (burn-off) natural gas produced as a byproduct to oil when they lack pipelines to move it to market or when prices are too low to make transporting it worthwhile. Other reasons to flare natural gas include safety concerns and connectivity issues. However, it is always in the best interest of an oil and gas producer to capture and sell the supplemental natural gas on the marketplace whenever possible, and that is what oil companies do. A study of the flaring of natural gas from wells in the United States by consultant Rystad Energy for the Environmental Defense Fund determined that infrastructure capacity limits are the greatest reason for flaring gas that cannot be captured, but the Biden Administration had made it more difficult to build pipelines, lessening the alternatives for oil and gas companies. The Trump Administration has pushed to streamline permitting for pipeline construction which would serve as a win for the government and companies by reducing the need for flaring.
Nevertheless, U.S. oil and gas companies have reduced their methane releases. ExxonMobil, for example, has cut its methane emissions intensity by more than 60% since 2016 and expects to achieve its planned reduction of 70-80% in 2026.
The Interior Department is also expected to revise definitions for when venting and flaring, which release methane, is authorized, according to its press release. The rule is also expected to establish clearer definitions for avoidable and unavoidable losses, and emergency situations and measurement standards. The revisions to the waste prevention rule are expected to reduce compliance costs for energy operators by nearly $17 million annually.
According to Interior, the proposed leasing rule would also authorize noncompetitive leasing following competitive auctions, eliminate the expression-of-interest leasing preference review process, shorten public participation periods from 90 days to 10 days, modernize filing fees and provide replacement lease sales when scheduled offerings are canceled or delayed. Additional provisions would limit lease suspension approvals to one year while establishing new timing requirements.
According to Interior’s press release, the reforms will eliminate unnecessary obstacles to domestic energy production, modernize resource management, and strengthen the nation’s long-term energy resilience. They will further accelerate development, enhance clarity for operators, expand economic opportunity, and reinforce the nation’s commitment to responsible stewardship and American energy leadership.
The changes will undergo a 60-day public comment period following their publication in the Federal Register.
Conclusion
To increase U.S. energy dominance, the Trump Interior Department is proposing major changes to Bureau of Land Management rules regarding onshore oil and gas leasing and waste prevention. It proposes loosening two major Biden-era regulations on methane emissions and on plugging non-operating wells, as well as cutting public comment periods from 90 to 10 days, among other changes. It would lower the statewide bonding minimum from $500,000 required by the Biden administration to the previous standard of $25,000. It would remove the Biden-era requirement for oil and gas firms to either certify that they will capture all of the oil and gas produced by their wells or produce a plan to reduce their methane releases, as U.S. oil and gas companies are already making progress. Oil and gas companies would prefer to sell their excess gas as long as they have the pipeline capacity to move it to market.
WASHINGTON DC (6/25/26) – Today, a broad coalition of prominent conservative, taxpayer, and energy policy organizations sent a letter to Senate Majority Leader John Thune and House Speaker Mike Johnson urging support for a Congressional Review Act (CRA) resolution of disapproval to overturn the Environmental Protection Agency’s (EPA) final Renewable Fuel Standard (RFS) volume mandates for 2026 and 2027.
The EPA finalized the rule on April 1, 2026, setting the highest renewable volume obligations (RVOs) in the program’s history: 25.82 billion renewable identification numbers (RINs) in 2026 and 25.98 billion RINs in 2027. This makes it the most expansive and expensive RFS mandate in history.
AEA President Thomas Pyle issued the following statement:
“The RFS program was designed for a different era when America was dependent on foreign oil. Today, the United States is a net exporter of energy. These bloated mandates no longer serve their original purpose and instead act as a hidden tax that drives up costs for refiners and American families at the pump.
“The EPA’s own analysis acknowledges massive costs of more than $20 billion annually, against just $400 million in claimed benefits. Independent estimates place the total burden on consumers and refineries closer to $106 billion over the next two years. For American workers, businesses, and families already strained by inflation and high gas prices, this is the last thing they need.”
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President Donald Trump recently accused major oil companies of “gouging” consumers by failing to lower gas prices at the pump quickly enough despite sharply falling crude oil prices. In a late-night Truth Social post, he instructed the Justice Department to immediately investigate. We have heard this clarion call before from numerous politicians, though admittedly it usually comes from the Democratic side of the aisle. Let’s set the record straight on this – again.
Gasoline prices at the pump often increase immediately when crude oil prices rise, yet they decline at a frustratingly slow pace when oil prices drop. This asymmetry frustrates drivers and fuels accusations of price gouging from politicians. The reason, however, stems from the economics of the petroleum supply chain, not conspiracy or corporate greed.
Gasoline sold today is typically refined from crude oil purchased weeks earlier. Refining, transportation, storage, and distribution to retail stations take time, often 2 to 6 weeks or longer, depending on logistics, contracts, and regional infrastructure. When crude oil prices fall sharply, refiners and retailers continue to process and sell fuel made from higher-cost inventory already in the system. Cheaper crude must first be purchased, refined, and moved through the pipeline before it reaches the pump. Gas stations, the vast majority of which are independently owned, rotate their existing stock gradually rather than dumping it at a loss. This creates a natural delay on the downside.
On the upside, the dynamic reverses. Rising crude prices prompt quicker adjustments because businesses look forward. They anticipate higher replacement costs for future inventory and begin raising prices to protect margins. Consumer demand also plays a role, as drivers often accelerate purchases when prices are expected to rise, thereby tightening near-term supply. This is not unique to gasoline. Similar inventory lags appear in many commodity markets with long production and distribution chains, from coffee to steel. The difference with fuel is its visibility at every corner station, and thus, the price is more politically sensitive.
Multiple economic studies have examined this “rockets and feathers” phenomenon, in which prices rise like rockets, but fall like feathers. After controlling for taxes, seasonality, competition levels, and other variables, the asymmetry persists across regions and time periods, though its intensity fluctuates with market conditions, refinery utilization rates, and inventory levels.
Importantly, researchers have found little evidence that the pattern results from widespread collusion among oil companies or retailers. Instead, it emerges from rational incentives to hold higher-cost inventory during price drops and to hedge against future cost increases during price rises.
Despite periodic political claims of gouging during, official findings tell a sustained and consistent story. In 2008, in a period of very high gasoline prices, the Institute for Energy Research asked a straightforward question: How many times has the Federal Trade Commission found evidence of price gouging by energy companies? The answer was none. Subsequent investigations into the 2021–2022 price increases reached the same conclusion: price movements reflected global crude prices, supply disruptions, OPEC+ decisions, refinery outages, and seasonal demand, not domestic collusion or misconduct. Any investigation done by the Trump administration will surely return the same findings.
Proposals for price-gouging statutes or windfall-profits taxes surface quickly whenever prices rise, because they allow politicians to assign blame to identifiable “big oil” villains. These measures rarely lower prices at the pump. In many cases, they risk creating the opposite problem in shortages. When retailers cannot recover replacement costs or face penalties, they may reduce supply or exit marginal markets. Historical precedents are instructive, as Nixon-Carter era price controls in the 1970s produced long lines, rationing, and widespread shortages. Additionally, the 1980s windfall profits tax on domestic producers reduced investment, slowed U.S. output, and increased reliance on imported oil. Raising taxes or imposing punitive measures on U.S. energy companies today would likely produce similar results with higher long-term costs for consumers and greater dependence on foreign suppliers.
If the Trump administration wants gas prices to fall (as we all do), it should withdraw the EPA’s latest Renewable Fuel Standard (RFS) mandates. The RFS program, created in 2005, requires refiners and importers to blend ever-increasing volumes of biofuels into the nation’s gasoline and diesel supply. Originally designed to reduce dependence on foreign oil, the program has become obsolete: the United States is now a net exporter of petroleum and refined products.
According to EPRINC, the estimated additional cost from the RFS has risen sharply from 15 cents per gallon in January 2024 to 45 cents per gallon as of May 2026. Based on the current 45-cent-per-gallon estimate and annual U.S. gasoline consumption of approximately 140 billion gallons, the total annual economic burden on consumers exceeds $66 billion.
As you can see, these RFS mandates function as a regressive tax on American workers, families, and businesses, hitting hardest at the pump, even as inflation and high energy costs remain top concerns.
Gasoline prices are a predictable consequence of how crude oil is refined into fuel at the pump. Inventory lags, forward-looking pricing on the way up, and gradual stock rotation on the way down explain most of the observed behavior. Regulatory records and economic studies show that market fundamentals, rather than malicious behavior, drive the vast majority of price movements. Blaming energy companies may score short-term political points, but it distracts from the policies that actually influence long-term supply. Withdrawing the EPA’s latest RFS mandate is a more tangible path to lower prices than another senseless investigation from the Department of Justice.
*This article was adapted from content originally published by the Institute for Energy Research.
Approximately three years after construction began, the largest wind facility in the United States, the SunZia Wind Project, is scheduled to begin commercial operations this month, June. The wind facility, located in New Mexico, has a total net summer generating capacity of 3,650 megawatts, comprising 916 wind turbines, and a total cost of $11 billion. SunZia’s capacity is more than three times that of the next two largest wind facilities, Alta Wind in Southern California (1,098 megawatts) and Great Plains in northern Texas (1,027 megawatts). Some of the turbines began producing power in April, during a testing phase. The wind facility spans three counties and took almost two decades of permitting and planning. The northern part of SunZia, located in San Miguel and Lincoln counties, has 242 turbines, while the southern part in Lincoln and Torrance counties has 674 turbines. The wind facility is expected to export power to Southern California and Arizona.
Pattern Energy, the wind developer, also owns the SunZia Transmission Project—a 550-mile high-voltage direct current transmission line that goes from the SunZia Wind Project site in central New Mexico to south-central Arizona and is backed by the Canada Pension Plan Investment Board. SunZia Transmission line is rated at ±525 kilovolts and carries up to 3,000 megawatts of power — the largest voltage source converter installation in the United States, and one of the largest worldwide. By converting the wind power’s output from AC to DC at a converter station in Corona, New Mexico, and transmitting it as direct current across the corridor, the system dramatically reduces line losses. At the receiving end, a converter station inverts the power back to AC.
Of the SunZia transmission line’s 3,021 megawatt of power capacity, 2,131 megawatts will be delivered to Southern California via the Palo Verde Substation. On May 15, 2026, California’s grid operator recorded 7,122 megawatts of hourly wind generation, a figure 20% above the prior annual record, with SunZia’s turbines contributing during a pre-commercial testing phase. It is important to note that these massive transmission projects are needed to support wind and solar power, which must be sited far from demand centers since they need to be located where wind power is strong, and the sun is shining.
According to the Energy Information Administration, the Energy Department’s statistical arm, once SunZia comes online, wind power will account for 45% of the state’s energy capacity, followed by 19% each from solar and natural gas. These statistics are in terms of capacity, not generation, because wind and solar can produce only a fraction of the power that gas, coal, and nuclear can at the same capacity level due to their inefficiencies. While dispatchable plants can generate power at any time, non-dispatchable sources such as wind depend on the weather and need massive amounts of land. One advanced nuclear plant, for example, produces 33.17 megawatts per acre, while one offshore wind facility produces approximately 0.006 megawatts per acre, which is approximately 5,500 times less efficient than one nuclear plant, according to the Interior Department.
That is one reason why, in July 2025, President Trump signed an executive order directing the administration to end federal subsidies for wind and solar energy facilities. It is also because these renewable energy sources make the United States dependent on foreign-controlled supply chains that threaten national security. Wind and solar power require critical minerals that, in many cases, result in reliance on supply chains from China. Lithium, graphite, cobalt, and manganese are critical to the storage batteries used in wind and solar projects, and the rare-earth elements that China processes are needed for the development of wind turbines.
Before SunZia came online, New Mexico had approximately 3,997 megawatts of installed wind capacity. With SunZia, the state’s total wind capacity is about 7,647 megawatts.
The Permitting Took Almost Two Decades
According to Tech Times, Pattern Energy and its predecessors spent from 2006 to 2023 moving SunZia through federal environmental reviews, state regulatory approvals, route adjustments, and competing legal challenges before construction could begin. The project required Bureau of Land Management right-of-way approvals across federal land in two states, Arizona Corporation Commission certification for the transmission corridor, and coordination with multiple federal agencies, including the U.S. Fish and Wildlife Service.
Tech Times reports that in May 2025, the Ninth Circuit Court of Appeals reinstated a lawsuit filed by the Tohono O’odham Nation and the San Carlos Apache Tribe, which alleged that the Bureau of Land Management failed to properly consult the tribes before authorizing construction through a 50-mile segment of the San Pedro River Valley in Arizona. The district court that originally dismissed the case did so on statute-of-limitations grounds; the appeals court found those grounds incorrect and sent the case back for consideration on the merits. While construction on the entire line is now complete, the legal outcome could require post-construction mitigation, rerouting of future work, or formal remediation of culturally significant sites.
Conclusion
The U.S.’s largest onshore wind facility is about to begin commercial operation. Built in three counties in New Mexico, it will provide power to the state of Arizona and southern California. It consists of 916 turbines, has a capacity of 3,650 megawatts, and was built at a cost of $11 billion. Along with the wind facility, Pattern Energy, the wind developer, also owns the SunZia Transmission Project—a 550-mile high-voltage direct current transmission line that goes from the SunZia Wind Project site in central New Mexico to south-central Arizona. Of the SunZia transmission line’s 3,021 megawatt of power capacity, 2,131 megawatts will be delivered to Southern California via the Palo Verde Substation.
Wind power requires massive land use, is inefficient due to generating power at only a faction of the generation that an equivalent gas, coal or nuclear unit with the same capacity can generate, requires rare-earth minerals that China provides and is currently subsidized by the U.S. taxpayer that the One Big Beautiful Bill signed in July 2025 will eventually correct as wind is no longer a “new” technology and should stand on its own.
The United States has become the world’s largest oil exporter after sanctions against Russia for its invasion of Ukraine reduced its exports, and the conflict with Iran shut in some Saudi Arabian oil production, thereby reducing its exports. These wars are reshaping global energy trade. At one time, the United States was the world’s largest oil importer and had been dependent on Middle Eastern oil for decades. In 1973, the United States suffered an oil embargo imposed by some OPEC members, causing gas prices to spike and long lines at gas stations. Government policies flourished in the wake of 1973, resulting in the creation of congressional energy committees and the establishment of the Department of Energy under President Jimmy Carter. Yet the dependency continued and worsened. The situation changed in the late 2000s with hydraulic fracturing and directional drilling technologies that enabled the production of oil from shale basins. That enabled the United States to become the world’s top oil producer in 2019 after it repealed a 40-year export ban in 2015, in place since the Arab oil embargo, and it has since become the world’s top oil exporter.
According to Reuters, U.S. exports of oil and petroleum products rose to about 10.5 million barrels per day in May, driven by higher production and the release of strategic reserves, making the United States the top global exporter for the third month in a row. Russian exports were 7 million barrels per day in May, while Saudi Arabia’s exports were 5.9 million barrels per day. In 2025, Saudi Arabia exported about 8.1 million barrels per day, compared to 6.6 million barrels per day for the United States and 5.8 million barrels per day for Russia.
Oil production in the United States has been slowly increasing since the shale oil renaissance. Since 2000, oil and liquids production in the United States has nearly tripled to about 22 million barrels per day, while Saudi oil and liquids output has largely fluctuated between 10 million and 12 million barrels per day, depending on OPEC quotas between 2000 and 2026. Russian oil and liquids output increased from 6 million barrels per day to 10 million barrels per day between 2000 and 2010, grew by a further 2 million barrels per day during the 2010s, but has largely stagnated and declined to below 10 million barrels per day since 2020.
The United States has been providing the majority of supplies to meet growth in oil demand, as demand has risen from 87 million barrels per day in 2010 to 104 million barrels per day in 2025. The United States is now the principal supplier of oil to Europe and the second largest supplier of distillates. Since the war in Ukraine began in 2022, Europe has increasingly turned to the United States for fuel. Europe has purchased about 47% of U.S. oil exports so far this year, up from 37% in 2021. Asia has also turned to the United States for oil supplies, purchasing about 46% of U.S. oil exports in May, compared with around 37% last year.
The U.S. oil boom is driven by private firms that respond to price changes, in contrast to government quotas set by OPEC and its allies. When prices are high, U.S. firms expand production; when they are low, they cut production. That balancing settles into an equilibrium if no disruptions affect the system.
This reshaping of global oil trade could weaken the pricing power that the Organization of Petroleum Exporting Countries and its allies have held over oil markets for decades. That could be especially true since the United Arab Emirates, OPEC’s third-largest oil producer, left the bloc in May after nearly 60 years as a member. Once the Strait of Hormuz is reopened, the UAE will become a major OPEC competitor, no longer subject to OPEC’s quotas.
Strategic Petroleum Reserves
The U.S. Strategic Petroleum Reserve (SPR) is currently releasing oil at a rate of nearly 9 million barrels per week. On June 5, the reserve was at 349.2 million barrels. The SPR had been severely depleted by President Biden in 2022, when he ordered a major release to lower gas prices after Russia’s invasion of Ukraine and before the midterm elections. The Biden administration did not replenish much of the drawdown, and the physical structure has required repairs, which have hindered its refilling.
China, which holds the world’s largest oil stockpile at 1.2 billion barrels, has begun drawing on its reserves after first finding alternative suppliers, reducing refinery use, and cutting petroleum exports to preserve domestic supply. The switch to electric vehicles has also helped to lower usage and demand. Inventory draws from its reserves are expected to average about 1 million barrels a day in the coming months–about a third of the oil that China is no longer receiving since the effective closure of the Strait of Hormuz. China began releasing its reserves in May and drew down almost 25 million barrels between May and June 7, according to Bloomberg.
Conclusion
The United States has become the world’s largest oil exporter as Saudi Arabia’s and Russia’s exports have been affected by the conflict in Iran and the war in Ukraine. The conflicts have altered the global oil trade, potentially reducing OPEC+’s influence over oil prices in the future, particularly if the new trade flows become permanent. The United States became the world’s largest oil producer in 2019 due to the oil shale renaissance and the advent of hydraulic fracturing and directional drilling. It has nearly tripled its oil and liquids production since 2010, while other producers have grown more slowly. Since 2010, the United States has been providing the majority of supplies to meet growth in oil demand, which reached 104 million barrels per day in 2025.
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