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The U.S. Army has placed REalloys at the center of America’s drive to rebuild its heavy rare earth supply chain, selecting the company to build and operate the first-ever commercial critical mineral processing operation on a U.S. military installation.

REalloys plans to build a heavy rare earth processing complex at the Tooele Army Depot in Utah capable of refining dysprosium and terbium, two of the most strategically important rare earth elements used in high-temperature permanent magnets for defense systems.

Read more in Oil Price here.

The U.S. Army Just Took a Historic Step to Break China’s Rare Earth Dominance

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Intel Corp. is spending €5 billion ($5.7 billion) to expand its plant in Ireland, as the chipmaker attempts to regain its manufacturing dominance for the AI boom.

The investment will expand capacity at the Leixlip campus on the outskirts of Dublin as part of Intel’s drive to increase output of data center processors, Intel said in a statement. It will scale capacity of products such as the company’s flagship Xeon server processors as well as advancing research and development activities.

Read more in Bloomberg here.

Intel Invests €5 Billion to Expand Irish Hub in AI Chip Race

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The Trump administration Friday finalized a repeal of decades-old regulation that said habitat destruction was a form of harm to endangered species. 

Overturning that interpretation of one of the country’s bedrock environmental laws could allow for mining, ranching and other development to expand into previously protected areas.

Read more in the Washington Post here.

Trump rule says habitat destruction does not harm endangered species

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Heading into the August recess, policymakers continue to hash out the details of a comprehensive permitting bill in hopes of sending it to President Trump’s desk this Congress. There is bipartisan recognition that permitting reform is essential to improving energy affordability and reliability, and to meeting our environmental ambitions. As the discussions on Capitol Hill evolve, one law starting to receive more attention for reform is the National Historic Preservation Act (NHPA).

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History and the Open-Ended Processes of NHPA

The NHPA was enacted for good reason. Rapid post-World War II development destroyed cultural and historic sites at a staggering pace. By the time Congress acted in 1966, half of the National Park Service’s Historic American Building Survey sites had already been destroyed or irreparably damaged. 

Section 106 of the Act is the core compliance process that requires federal agencies to consider how projects they fund, permit, or carry out affect historic and cultural resources. The Act also established the institutions that carry out Section 106. It created the Advisory Council on Historic Preservation (ACHP), an independent agency that advises Congress and the President and writes the rules governing Section 106 review. It also established State Historic Preservation Offices (SHPOs) and was later amended to create Tribal Historic Preservation Offices (THPOs), creating a federalist system in which states and tribes, not Washington, lead most of the actual preservation work.

The compliance process is as follows. Agencies must determine whether the federal action constitutes an undertaking with potential effects. If so and the action does not fall under one of the defined program alternatives, agencies must identify historic properties within the Area of Potential Effects (APE). In this process, agencies involve SHPOs, THPOs, and other consulting parties, such as local governments, archaeologists, landowners, and the public, as necessary. 

The APE can include direct or indirect impacts the undertaking may cause, such as physical, audible, and visual effects. Consequently, the APE for large infrastructure projects, such as pipelines or transmission lines, can span thousands of square miles and take years to survey. 

If an agency finds nothing historic in the APE, it must document the finding and give the SHPO/THPOs 30 days to object. If no objection is raised, the consultation process ends. If an objection is raised, the agencies and SHPOs engage in additional consultation or refer it to the ACHP, which has 30 days to weigh in. The agency must then respond and explain why it reached their conclusion. 

If a historic property lies within the APE, the agency must assess whether the action it’s considering will affect the property. If the project has adverse effects, the parties negotiate a Memorandum of Agreement. This legally binding document outlines how the agency will mitigate harm to the historic property. There is no deadline for the negotiation to conclude, so it can drag on for months or years. Additionally, mitigation requirements may have little, if any, relevance to the preservation of the cultural site. For instance, mitigation agreements have included funding podcasts, roadside attractions, and fitness lanes. 

What’s Considered a Historic Property, Landmark or Artifact? 

The National Register covers a wide range of structures, buildings, and objects, including state capitols, courthouses, and neighborhood historic districts, as well as bridges, battlefields, cemeteries, monuments, and even amusement park rides. The former home of the New Orleans Saints, the Louisiana Superdome, is on the National Register of Historic Places. A property generally must be at least 50 years old and retain its historic integrity. Properties younger than 50 years can still qualify, but only in rare cases of “exceptional importance,” or if they’re part of a larger historic district that already qualifies.

Nominations typically start with a property owner, historical society, local government, or tribe, and go through the State Historic Preservation Office (or the Tribal or Federal Preservation Officer for tribal or federal land). The property must meet at least one of four significance criteria:  association with historic events, connection to important people, distinctive architecture or engineering, or archaeological potential.  The SHPO then notifies affected owners and solicits public comment before a state review board makes a recommendation. From there, the National Park Service’s Keeper of the Register makes the final call, typically within about 45 days of a complete nomination reaching Washington. Owner objection can block a listing outright. Start to finish, the process commonly takes one to two years.

>>>READ: Restoring Predictability to Historic Preservation Review

A National Historic Landmark (NHL) asks whether it’s of national significance, and the bar for proving that is considerably higher. Candidates go through a National Park Service survey, review by the National Park System Advisory Board, and a personal designation from the Secretary of the Interior, rather than a state-level sign-off. NHLs are subject to a tougher standard than ordinary Register-eligible sites, requiring agencies to loop in the ACHP and take concrete steps to minimize harm. Roughly 90,000 to 100,000 properties sit on the Register, and just over 2,600 have NHL status. 

It’s worth noting that even historic projects not listed on the Historic Register may still be included as an affected site, as long as it meets one one the four eligibility criteria. This requires federal agencies to evaluate both listed and unlisted structures.

Effects on Energy, Infrastructure and Conservation Projects

For large energy, forestry, and transmission projects, outdated tools, inconsistent implementation, open-ended timelines, undefined requirements, and opportunities for litigation have made Section 106 a serious bottleneck. For instance, defining the area of potential effects, identifying and evaluating historic properties, and conducting surveys have no fixed timeline. 

Lawsuits are also a problem, and there are many opportunities to bring a claim. When a federal agency’s Section 106 compliance is challenged in court, the lawsuit is typically brought under the Administrative Procedure Act, which means the court can only review the agency’s final decision and must defer to the agency’s judgment unless it was arbitrary or unreasonable. A recent Institute for Progress report notes that:

APA standard applies to procedural questions such as whether the agency appropriately defined and documented the area of potential effects; made a reasonable and good-faith effort to identify historic properties; consulted adequately with SHPOs, THPOs, Tribes, NHOs, applicants, local governments, and other consulting parties; evaluated National Register eligibility; assessed adverse effects; addressed objections or contrary evidence raised during consultation; and adequately documented its no-effect, no-adverse-effect, or adverse-effect findings and any avoidance, minimization, or mitigation measures the agency chose to adopt in an MOA, PA, or other resolution document. While mitigation measures are not legally required, an agency could still be found arbitrary and capricious in deciding not to adopt a mitigation measure that was proposed but that the agency declined to adopt without a reasonable explanation.

Lawsuits can result in injunctions, vacatur, or remand without vacatur, depending on the circuit’s precedent. 

Idaho Power’s proposed 300-mile transmission line, the Boardman to Hemingway project, spent 18 years in permitting before construction began in 2025. BLM initiated the Section 106 process in 2011, and that consultation was still ongoing as of 2025.

>>>READ: Permitting Reform – The Commonsense Fix for America’s Cost of Living Crisis

The SunZia Southwest Transmission Project illustrates the same challenge on a larger scale. The $10 billion, 520-mile line is one of the largest transmission projects ever built, and its Area of Potential Effects grew accordingly: an estimated 40,000 to 80,000 acres for direct effects, roughly the size of Washington, D.C., plus a five-mile buffer on either side for visual effects covering an estimated 5,200 square miles. Historic property determinations also came late in the process, contributing to litigation that continued even after construction was underway. With clearer APE standards and earlier, better-resourced consultation, developers would have more certainty, and tribes and historic preservation offices would have a more meaningful role earlier in the process, rather than a legal fight after the fact.

C3 Solutions has proposed reforms to Section 106 that would provide more certainty for developers, speed up critical energy and conservation projects, and maintain historic preservation.

  1. Clarifying the Area of Potential Effects (APE) and impact scope

At a Senate hearing last fall on NHPA, Montana Dakota Utilities’ Andy McDonald described how one of their projects was delayed at the APE stage. Rebuilding a three-mile distribution line, including upgrading it for wildfire safety, was delayed when agencies couldn’t agree on what counted within the Area of Potential Effects. One agency said the entire project, including private land, must undergo Section 106. The other limited review to the area within its own jurisdiction. In cases like these, having a lead agency driving the process would help ensure projects don’t get held up unnecessarily.

Clarifying what counts as an effect would also help. Speculative effects should not drive consultation; only direct, proximate, and causal impacts should count. SunZia’s five-mile, 5,200-square-mile visual effects buffer shows how much room the APE currently has to expand well beyond a project’s footprint.

  1. Narrowing Judicial Review

Because Section 106 is far less litigated than NEPA, its limited case law can create uncertainty for developers and agencies alike. As Stacey Bosshardt noted in a 2026 analysis for the American Bar Association’s Natural Resources & Environment journal, courts have at times treated Section 106 as requiring mitigation measures that are not found in the law itself.

The Supreme Court has already pushed back on similar NEPA interpretations in the Seventh County case, making clear that procedural statutes enforced through the APA do not require fully developed mitigation plans. Congress should bring the same clarity to NHPA. Alongside reforms such as limiting review timelines, narrowing review to the project at hand, and allowing remand without vacatur, these changes would make permitting more predictable without weakening historic protections or public participation.

  1. Prioritize Nationwide Digitization, Modeled After Utah and Washington

One of the biggest barriers to an efficient Section 106 process is that many cultural and historic records remain in paper files or fragmented databases. States such as Utah and Washington have shown that digitizing systems drastically reduces review times.

Utah’s State Historic Preservation Office fully digitized its records in a GIS-based system in 2017 and has since completed 98 percent of reviews within seven days, saving roughly $350,000 annually in printing and mailing costs. Washington State’s WISAARD platform has been similarly successful. It combines GIS mapping with electronic Section 106 submissions and allows reviews to be completed in just 3 to 4 days. To achieve this on a large scale, Congress should allocate funding and technical support to enable State and Tribal Historic Preservation Offices to build modern, centralized databases.

  1. Expand the Use of Programmatic Agreements

Some tools already exist to help agencies streamline the Section 106 process. Programmatic agreements allow federal agencies, the Advisory Council on Historic Preservation, and State or Tribal Historic Preservation Offices to agree in advance on how routine categories of projects will be reviewed. They are among the most effective tools available and can save significant time and money.

By creating a more predictable process for routine, low-impact work, or work done on a large scale, these agreements help agencies move projects forward more efficiently. For large-scale forest management projects, these agreements even allow consultation to proceed in phases while work begins in other areas, so critical management needed to ensure the safety of our forests and communities does not stall while every detail is finalized. Agencies should proactively incorporate more programmatic agreements into their historic preservation work.

  1. Explore Ways for Voluntary, Incentive-Based Mitigation

While Section 106 does not require mitigation outcomes under the law, preserving cultural and historic resources is an important goal. Congress and the Advisory Council on Historic Preservation should explore voluntary frameworks that reward developers who engage tribes and stakeholders early and reach agreements before the formal review process begins.

Certain environmental laws already use similar incentive-based approaches successfully, including wetland mitigation banking under the Clean Water Act and safe harbor agreements under the Endangered Species Act. Creating expedited review pathways and legal certainty for early agreements could encourage more of the kind of early, collaborative engagement that projects like SunZia would have benefited from.

As Congress pushes forward with permitting reform, the National Historic Preservation Act should remain a priority. Reform would continue to protect cultural and historic resources while giving agencies and developers the clarity and predictability needed to build the energy, transmission, and conservation projects the 21st century requires.

Modernizing the National Historic Preservation Act

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In 2011, after the Fukushima disaster, Germany made the fateful decision to switch off its nuclear plants. Now, two have been promised a second life as fusion-energy projects in a high-risk technology bet aimed at revitalizing Europe’s industrial core. 

The plan rides on two ventures that are pursuing the same dream—creating a star on Earth to create abundant low-cost clean energy—in different ways. 

Fusion requires heating and compressing nuclear fuel to make superheated plasma in which atomic nuclei combine, releasing energy. Power plants harnessing this process couldn’t melt down and would create only a little short-lived radioactive waste, but they remain theoretical. The challenge is controlling the plasma, which is (excuse the technical jargon) tricky stuff. There are two main options: magnets and lasers. Germany is betting on both. 

Read more in the Wall Street Journal here.

The Plan to Build Energy’s Sci-Fi Future in Shut-Down Nuclear Plants

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It’s always difficult to make predictions, as Yogi Berra said, especially about the future. However, looking back across the history of humanity, it is safe to say that the world will need more energy in the years and decades ahead, as it has steadily used more energy year after year in the past. 

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Oklahoma has a leading role to play in delivering the carbon-free, renewable electricity we will need, and doing so with a minimal environmental footprint. It won’t be magic. It’ll be the application of grid scale enhanced geothermal.

The Sooner state is in a leading position to develop geothermal because it requires similar technology, processes, equipment, and know-how as the oil and gas industry, which Oklahoma has been driving forward for decades.

Let’s consider how Oklahoma and the United States at large developed hydraulic fracturing (fracking) to extract tight oil. Those old enough to remember the turn of the century may also remember something we haven’t heard much about lately: Peak oil.

Here is how Tom Whipple, who helped guide American national energy policy for three decades as a CIA analyst, described the imminent onset of peak oil: “Shortages were going to occur; prices were going to rise; demand was going to drop; economies would falter; and eventually a major economic depression was going to occur.” 

Whipple drafted those words in 2014 for the Falls Church News-Press. In an unusual twist, he was predicting the past. He noted that his assessment had been conventional wisdom “ten years ago.” In an even more unusual twist, his prediction of the past was incorrect: by 2014 it was clear that the United States had become the world’s swing producer of oil. Because of fracking, prices plunged, supply soared, and the economy chugged along.

>>>READ: House Acts to Unlock America’s Geothermal Potential

The word that Whipple alluded to but refused to use was “fracking.” He kept pointing to “shale oil” as if it were obtained through the same process as conventional oil drilling. As Whipple himself noted in that 2014 piece, at that moment, “no other country as yet has gotten significant amounts of shale oil or gas into production.” Perhaps that was because no other country had given birth to Oklahomans like Lloyd Noble and Harold Hamm.

Hamm grew up as the youngest of 13 siblings. His entrepreneurial spirit was on display at a young age, as he founded Continental Resources in 1967 when he was just 21-years-old. The world was awash in oil at that time, with a barrel costing less than $30 (in 2026 money). Still, Hamm saw the value of developing different ways to drill for oil. Continental’s innovations showed that fracking worked, opening huge new areas for development. 

“Within two decades, it really transformed the entire industry,” Hamm said during an appearance at the University of North Dakota, where he established a school of geology and geological engineering. “We went from what everybody considered terminal decline of our production in the U.S. and having to import from the Middle East or Canada. Since that point, U.S. production has tripled to about 13 million barrels a day.” That is to say, fracking ended peak oil.

Even before fracking, another notable Oklahoman, Samuel Roberts Noble, showed the state and the U.S. the way to develop oil fields. 

>>>READ: This Clean Energy Company is On Track to Build the World’s First Superhot Geothermal Energy Plant

Noble was born before Oklahoma was even a U.S. state. He made a fortune in the traditional drilling industry of the pre-World War II era. In 1945, he set to work improving conditions above ground. He founded the Noble Research Institute to help revitalize farming and ranching after the Dust Bowl. The institute has grown into the largest independent agricultural research organization in the U.S. and employs nearly 400 people from 20-plus countries. His life and career highlight Oklahoma’s path from the first, land-rush settlers, to today’s high-tech drillers.

Because of men like these, the landscape is ready for grid-scale geothermal. 

Many think of geothermal energy as geysers: Old Faithful in Yellowstone National Park erupts with clocklike precision. However, in most places, the heat from deep in the Earth simply remains down there, far beneath our feet under solid rock. 

An enhanced geothermal system injects fluid into fissures deep within the Earth. The fluid heats up and brings that energy to the surface to turn turbines and generate electricity. When it cools, it can be reinjected into the ground as warmer fluid is extracted.

A study conducted last year by Princeton analysts indicated that advanced geothermal could supply up to 20% of the electricity the country needs by 2050. That’s clean, renewable, zero-emission electricity generation with a minimal above ground footprint.

A large chunk of America’s energy future is underground, just as it was when Lloyd Noble and Harold Hamm were getting started. They, and others in Oklahoma’s energy industry, have shown us how to unlock the future.

Oklahoma Leads the Way on Geothermal

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Waste incineration plants in Europe will have to pay for their carbon dioxide emissions under European Union plans to add the industry to ​the bloc’s emissions trading system, EU officials said on Wednesday.

The plans, which ‌aim to incentivise reuse of material, limit waste, and push operators to invest in emission-capturing technology, have met strong opposition from the industry, which argues they will unfairly penalise incinerator owners rather ​than the companies producing non-recyclable plastics.

Read more in Reuters here.

EU plans to impose emissions costs on waste incineration plants

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The American steel industry is reaping the benefits of the AI data-center construction boom. But now, steelmakers are warning of a high-stakes competition with their data-center customers for a commodity they both require: electricity.

Data centers’ insatiable demand for electricity is driving up power costs for steel companies by tens of millions of dollars a year and threatening the companies’ operations, according to a new report from the Steel Manufacturers Association.

“We as an industry are very reliant on electricity to make steel,” said Rob Simon, chief executive of JSW Steel USA, which uses an electric furnace at its Mingo Junction, Ohio, plant. “We’ve had stable electricity prices for decades, and now we think that’s at stake.”

Read more in the Wall Street Journal here.

AI Data Centers Have Been Great for the Steel Industry. Now, a Power Crisis Looms.

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This piece was initially published in RealClearEnergy.

Across state capitals and in Washington, policymakers are scrambling to address voters’ alarm over electricity bills. The Trump administration is unwinding major climate regulations, Democrats are focusing more on affordability concerns than climate change, and governors are quietly paring back clean energy subsidies and emissions mandates they championed only a few years ago. Climate policies are starting to bite, and the political strategy that helped enact them, downplaying costs and obscuring tradeoffs, is becoming harder to sustain as ratepayers see the impact on their bills.

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One of the country’s most popular climate policies has largely escaped this scrutiny. More than half the states have a renewable portfolio standard, or RPS, requiring utilities to source a specified share of electricity from qualifying renewable sources such as wind and solar. Many standards are scheduled to climb sharply in the coming years. Rhode Island, for example, requires 100% renewable electricity by 2033. Fifteen states plus D.C. will require more than 50% by 2050.

States should take a hard look at these mandates. RPS programs distort electricity markets, favor politically preferred technologies over least-cost generation, and hide costs in ways that make honest debate nearly impossible.

When most states adopted RPS programs in the 2000s, the standards were appealing partly because they avoided putting an explicit price on emissions reductions. The costs are real, but they are buried in rate-base calculations and other utility expenses, making it harder for ratepayers to see the true price of climate policy.

Obscuring costs does not make them disappear. The most visible channel is direct compliance, as utilities pay for renewable generation or buy renewable energy credits to meet the mandate. Lawrence Berkeley National Laboratory estimates these compliance costs averaged 4.3% of retail electricity bills in 2024. In some jurisdictions, the share was far higher. New Jersey’s compliance costs reached nearly 12% of bills, and the District of Columbia exceeded 15%.

RPS policies can also raise prices indirectly, through transmission expansion to reach remote wind and solar sites and the expense of backing up intermittent generation. Estimating the full effect is difficult, and some of the apparent connection between RPS and retail prices reflects pre-existing state characteristics rather than the policy itself. But studies of the long-run effects of RPS mandates have found retail prices in RPS states 11 to 17% higher than in comparable non-RPS states.

>>>READ: From Net-Zero to Net-Abundance

What is striking is that the evidence that RPS mandates caused large amounts of renewable deployment beyond what federal tax credits and falling technology costs would have driven is weak or inconsistent. More than 60% of new renewable capacity in 2024 was built outside RPS compliance frameworks. Much of the emissions reductions credited to the policies appear to come not from cleaner supply but from higher prices suppressing electricity demand.

 Even if those reductions are worth pursuing, RPS is a costlier path than the alternatives. Economists have long argued that pricing emissions directly, or crediting generators based on their actual emissions intensity, can achieve environmental gains at lower cost. Renewable mandates ignore cheaper options, such as switching from coal to natural gas, and instead force a binary distinction between “clean” and “dirty” technologies. The result is a policy that rewards favored resources rather than the cheapest path to lower emissions.

These costs are likely to become more visible. The One Big Beautiful Bill curtailed the Inflation Reduction Act’s clean-energy tax credits, shifting more of the cost of state renewable mandates from federal taxpayers onto state ratepayers, while state targets continue to climb just as electricity demand is projected to grow.

Now is the time to reconsider RPS. Over the past decade, West Virginia, Kansas, Montana, and Texas have variously repealed their standards, converted them to voluntary goals, or let them lapse. Most recently, the Arizona Corporation Commission voted to repeal the state’s RPS. The state attorney general is challenging the decision, but if it survives, it would be a step in the right direction.

Other states should follow. The best option is outright repeal. Short of that, mandates should be converted into voluntary goals that let governors signal climate commitments without forcing utilities to comply when renewables are not cost-competitive. At a minimum, states should freeze target increases and remove provisions that add further distortions, such as in-state sourcing requirements or technology-specific quotas.

Electricity affordability is now the defining concern in energy policy. The programs that deserve the most scrutiny are those that distort electricity markets, push prices up, and achieve their environmental goals less efficiently than the alternatives. RPS is an easy place to start, especially since rising targets will only push electricity bills higher. Now is the time to reform policies that ask voters to pay more than they should for climate ambition.

Why States Should Reconsider Renewable Portfolio Standards

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Virginia Gov. Abigail Spanberger (D-VA) defended the economic and national security importance of the state’s booming data center industry this week, days after approving a budget that imposes Virginia’s first tax on the sector’s electricity consumption.

Spanberger said the new budget strikes a balance between ensuring data centers “pay their fair share” while preserving an industry she said is critical to Virginia’s economy and the nation’s technological leadership in an interview with Politico.

Read more in the Washington Examiner here.

Spanberger draws a hard line on data center bans: ‘Walking away from the table’

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