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Conservatives have been vocal about our climate for years. Those voices won’t be ignored any longer.

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As major fires burn across Colorado and Utah this summer, the broader Western lesson is hard to miss. Colorado’s Aspen Acres fire forced evacuations and destroyed more than 160 structures. Utah’s Babylon Fire passed 100,000 acres recently, the state’s first fire to reach that mark in eight years. Colorado officials also issued air-quality advisoriestied to wildfire smoke moving through the region. In the West, wildfire risk does not stop at a state line, and neither do the economic and environmental costs.

Wyoming knows that reality well. Wildfire affects rangelands, watersheds, wildlife habitat, recreation, public health and the economies of rural communities. It also affects core questions of economic policy: how communities protect infrastructure, how land managers reduce long-term risk, how businesses operate during smoke events and how states navigate federal rules that do not always fit Western conditions.

Read more in WyoFile here.

  • The levelized cost of electricity is on the rise for all types of generation, including renewables, but unsubsidized renewable energy “remains the most cost-competitive form of new-build generation,” according to Lazard’s 2026 Levelized Cost of Energy+ report, released Monday.
  • The forces driving a rise in LCOE for all types of generation include “higher capital costs, sustained interest rates, tariff pass-through and supply chain repricing,” Lazard said. 

Read more in Utility Dive here.

President Donald Trump said Sunday night he’s considering making Canada financially compensate the United States for economic damage caused by wildfire smoke that drifted from Canada into parts of the U.S. last week.

While speaking to reporters after returning from the World Cup final, Trump said he spoke with Canadian Prime Minister Mark Carney at the match about the smoke that enveloped much of the Midwest and East Coast.

“I told him, ‘You got to stop these fires from coming in and poisoning our air, our air’s been poisoned,’” he said. “I have a good relationship with Mark Carney, but, you know, we have got to stop the fires up there. If we can help them, we’ll help them, but maybe they should pay us some damages or something, or we should do some tariffs.”’

Read more in the Washington Examiner here.

Electricity rates are rising faster than inflation and are felt by households across America. After decades of flat electricity demand, the country is experiencing significant load growth, driven by hyperscale AI data centers, resurgent domestic manufacturing, and the steady electrification of buildings and vehicles. The need for new energy generation is growing as utilities aim to bring new natural gas, clean firm, and renewable capacity online over the next few years to keep power affordable and reliable. Importantly, this also means upgrading and expanding the country’s transmission infrastructure. Recently, the Department of Energy released the draft of its National Transmission Needs Study, the triennial, congressionally commissioned report on the state of the nation’s high-voltage backbone.

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The study’s topline findings indicate that the country needs a substantial buildout of new transmission infrastructure simply to keep pace with new demand. When a bottleneck in the transmission network prevents the cheapest power from flowing, grid operators are forced to rely on higher-cost resources, resulting in an uneconomic outcome felt by customers across the system. The study also finds that connecting regional grids delivers outsized reliability and cost benefits, and that many grid operators across the country are approving their largest transmission expansions on record. As the DOE report notes, incumbent utilities built 98 percent of new transmission from 2016-2024, and laws incentivize utilities to build small-ball lines that may not be the most cost-effective and that are shielded from competition. 

The need for additional transmission is not in dispute, though disagreements exist on how much is needed. However, how the transmission is planned and built, and who pays for it, are critical to ensuring that Americans receive power at the lowest possible cost. 

That’s the question a coalition of right-of-center policy groups took up earlier this year. In an April framework, C3 Solutions, Americans for Prosperity, the Pacific Legal Foundation, the Abundance Institute, the American Conservation Coalition, the R Street Institute, and the Conservative Energy Network set out five principles for transmission reform, all centered on a simple idea: transmission exists to serve consumers, not to prop up any particular power source or pad a utility’s bottom line. 

For decades, transmission has been among the most poorly regulated parts of American infrastructure. Utilities receive a guaranteed return on whatever they build, which rewards new construction over cheaper upgrades to existing lines. Mandatory regional planning processes often crowd out voluntary, merchant-built transmission that could be delivered more efficiently and at a lower cost. States and localities can slow-walk permitting for reasons that have little to do with actual harm to residents. And in far too many parts of the country, there’s remarkably little transparency about how transmission decisions are made or who ultimately pays for them. Under today’s rules, the projects that get built are often the ones that are easiest to justify under a regulator’s cost-of-service formula, not the ones that deliver the most capacity per dollar. 

>>>READ: Closing the Local Project Loophole: The Case for Competitive Transmission

This group’s principles are relatively straightforward and should guide how the Trump administration and federal and state policymakers think about transmission policy reform: 

  1. Prioritize expanding and upgrading the existing transmission system. The quickest and least-cost ways to expand the transmission system are often upgrades to existing infrastructure. However, the cost-of-service regulatory model discourages transmission owners from pursuing upgrades voluntarily or from adopting solutions beyond in-kind replacements. Cost-of-service regulation should better align incentives so they do not favor any energy source over another and ensure “good utility practices” in adopting advanced transmission technologies and in the more efficient management of seams between regional transmission systems.  
  2. Remove barriers to greenfield transmission under the merchant transmission model. This model is economically advantageous because it relies on voluntary planning and cost allocation. However, it faces high regulatory barriers, under which it is routinely usurped by mandatory planning processes or deemed ineligible for compensation for providing key grid services. 
  3. Refine mandatory transmission planning and cost allocation practices, where necessary, to follow economic principles. Most of the greenfield transmission expansion will inevitably occur under mandatory planning and cost allocation processes run by utilities or regional transmission organizations (RTOs). The most economical manner to plan such projects is through robust cost-benefit and scenario analyses, planning horizons appropriate for long-lived infrastructure, allocating costs based on the beneficiary pays principle, and putting transmission needs or solutions out for competitive bid. Developers should have a reasonable expectation that beneficial transmission lines can be deployed.  This should include ensuring that developers have a credible means of proposing lines, that regulators evaluate them based on neutral criteria, and that, if selected, costs will be borne only by those who benefit, and only to the degree they benefit. 
  4. Streamline transmission permitting and siting. Priority improvements should be made at the state and local levels while protecting private property rights. These include tying permitting decisions to evidence of demonstrable harm (not speculation), improving information on project costs and benefits (including out-of-state), maintaining fairness across business models, and instituting appeals processes to vindicate the liberty of parties seeking redress on restrictive permitting and siting decisions. Any national changes to interstate transmission siting should only use federal backstop authority as a last resort. 
  5. Improve transmission governance. Greater transmission system transparency and accountability are needed across the country, but especially outside RTOs. Expanding the role of independent institutions, such as an Independent Transmission Monitor, to coordinate, audit, and assess transmission system operations and planning is warranted. Closing gaps in governance frameworks, such as the federal-state divide regarding local transmission projects, is imperative for cost containment. 

Interregional and cross-interconnection transmission can reduce costs for customers when lines are planned efficiently, and costs are allocated correctly. Greenfield transmission, combined with grid-enhancing and advanced transmission technologies, can enable the most economically efficient delivery of electricity to consumers. Simply adding new generation without evaluating how our high-voltage network can improve reliability at the lowest cost increases the risk of overbuild and stranded assets, costs that will fall directly on ratepayers. 

>>>READ: Blocking Data Centers Won’t Make Electricity Cheaper

As DOE opens its 60-day public comment period on the draft study, the real test for Congress and state regulators alike is whether the coming wave of transmission spending gets disciplined by transparency, competition, and robust cost-benefit analysis to protect taxpayers and ratepayers. 

Americans are worried about energy costs, grid reliability and falling behind China. The Supreme Court is about to weigh in on something that touches all three.

The case, Suncor Energy v. Boulder County, is one of the numerous climate litigation cases seeking to hold energy producers financially responsible for the purported consequences of climate change. Supporters view such lawsuits as an accountability tool; however, a more appropriate view is that these cases are a means of legislating through litigation.

In this case, Boulder, Colo., seeks to supplant established federal law with Colorado tort law. Federal law, under the Clean Air Act, Clean Water Act, and other federal statutes and regulations, has long established the environmental standards that must be met by industrial and other operations that affect the environment. As they should be, these laws have been properly debated and passed by duly elected federal lawmakers. Colorado now seeks to start a patchwork state approach by subjecting businesses to local standards.  

Read more in The Hill here.

“The endangered species list is not a dean’s list,” Wyoming Governor Mark Gordon said this week, standing near Big Sky, MT, with Interior Secretary Doug Burgum and the governors of Montana and Idaho. “It’s time this bear graduates.” After decades of federal control and an amazing tale of conservation success in America, the Interior Department has announced it will shift the daily management of the grizzly bear back to the states. Grizzly bears would, however, remain listed as threatened under the Endangered Species Act.

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The proposed rule is a revision under the ESA’s 4(d) rule, which governs how a threatened species can be managed short of full delisting. While the full details will be released later this week, officials made sure to point out that this change would not come with an open season for the bear, nor its delisting. 

Northern Rocky Mountain governors and congressmen have long advocated for the delisting of grizzlies and the transfer of management back to the states. After two attacks in May, a fatal encounter in Glacier National Park and a separate incident that injured two hikers in Yellowstone, Montana Congressman Zinke tweeted “These tragedies are a sobering reminder that grizzly bear populations have recovered well beyond sustainable levels, and it is past time for the federal government to delist them and give states the management tools they need to protect both people and wildlife, “Delist the grizzly.” 

But have the Grizzlies actually recovered enough to be handed to the states to manage? Studies show they have.

According to the U.S. Fish and Wildlife Service, the population in 1975, when the bear was listed, was a mere 700 to 800 in the lower 48. In 1993, the Service created a recovery plan that targeted recovery efforts in 6 ecosystems: the Greater Yellowstone, the Northern Continental Divide, the North Cascades, the Selkirks, the Cabinet Yaak, and the Bitterroot. 

>>>READ: What’s Going On With the Grizzly Bear Listing?

While repopulation efforts in the North Cascades and the Bitterroot ecosystems have been unsuccessful, many of the other recovery areas have met or even exceeded their recovery targets. Criteria for recovery include meeting population targets and a certain number of female bears with cubs identified. GYE’s recovery goal is a population between 800 and 950 bears. FWS counted 1,050 in 2024. The NCDE has 1,068 resident bears, exceeding their recovery goals as well. Every bear management unit that’s supposed to have females raising cubs in it does, in both ecosystems.

While more details are yet to be released, state management of grizzly bears can be beneficial for conservation. Montana, Wyoming, and Idaho all have existing grizzly bear management plans in place, built with years of input from state and federal wildlife managers. The NCDE and GYE already operate under interagency conservation strategies meant to guide bear management during the 5-year monitoring period following delisting. This move could also open the door to real incentive-based stewardship rather than top-down regulation, in which private landowners are rewarded for conservation. 

The Property Environment and Research Center has said in the past that moving management to the states, rather than a full delisting, can make litigation far less disruptive. Grizzly status has been changed numerous times since its delisting, resulting in a ping-pong match between states and the federal government. Each time there is a change, environmental groups sue. This middle ground is a great way to prove the states are ready to take over management. 

We’ve long known that states and tribes know best how to manage the wildlife close to home. Countless examples across the U.S. prove this, from the American Alligator to the Brown Pelican. It’s time to give the grizzly bears a shot at becoming the next conservation success story.

On May 23, 2025, President Trump, via Executive Order 14301, took multiple actions to jumpstart the nation’s long-dormant nuclear energy industry. Besides “expeditiously” processing applications for qualified test reactors and revising agency policies to further expedite review, approval, and deployment of advanced reactors under Energy Department supervision.

The goal was to enable operational test microreactors within two years following a completed application. Toward that end, the DOE created a pilot program with a goal of construction and operation of at least three reactors outside the National Laboratories (but under a DOE contract) to achieve “criticality” by July 4, 2026 – the nation’s 250th birthday.

Read more in RealClearEnergy here.

New York Gov. Kathy Hochul (D) is imposing the nation’s first-ever statewide freeze on new “hyperscale” data centers.

Hochul is pausing state-level environmental permits for “up to” a year to give the state time to put together a framework to protect the environment, the energy grid and New Yorkers’ electric bills, her office said.

Hochul aides told reporters that the pause would apply to data centers that can use 50 megawatts or more of power. 

Read more in The Hill here.

France’s state-owned energy group EDF temporarily shut down three nuclear reactors on Sunday, while warning that seven others may need to adjust their power output as the heatwave sweeping the country continues.

According to the company, the measure is an environmental protection requirement to avoid discharging excessively hot water into rivers already warming because of the heatwave.

Nuclear power plants use river water to cool their reactors before releasing the warmed water back into rivers.

Read more in Euronews here.

America is betting on a nuclear comeback, driven by a new generation of advanced reactors with lower capital costs and significant potential for economies of scale. Many of these reactors, however, require specialized fuel that has led the government to pour billions into a domestic supply chain. To ensure these investments pay off, federal officials should proactively eliminate artificial procurement barriers and permitting hurdles which threaten to stall nuclear fuel independence.

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To be clear, bipartisan laws in recent years and the Trump administration’s actions have already created favorable conditions for the nuclear industry. Reactor demonstrations have been funded at record levels, regulatory processes reformed, and long-term power purchased. What has long remained unclear is where the next wave of advanced reactors will acquire the enriched fuel they need to operate. 

That fuel is high-assay low-enriched uranium, or HALEU, enriched to between 5 and 20 percent uranium-235. This fuel, more highly enriched than that in conventional reactors, enables more power to be squeezed out of smaller reactor assemblies. Yet, it also requires new facilities equipped to enrich this fuel to a higher concentration. Beyond the expensive technical effort that is necessary, Russia has been the dominant global player in this market for years, in part because of state support to supply its own reactor fleet. Historically, nobody batted an eye at their dominant position in the supply chain.

But as announcements of new nuclear development expanded and the technology curried favor in Congress a few years ago, lawmakers viewed our Russian fuel dependency—especially in light of the invasion of Ukraine—as an unpalatable risk for the next generation of reactors. Just two years ago, this led Congress to both ban imports of Russian supplies by 2028 and give $2.7 billion to the Department of Energy to aggressively expand U.S. uranium enrichment capacity. The government created a signal for enrichment developers to build here in the United States. Fulfilling Congress’s request, DOE recently announced plans to share in the development costs of three enrichment complexes over the next several years, offering up to $900 million to each facility developer. 

>>>READ: The Department of Energy Takes on ALARA

Whether this funding is warranted is a valid debate with compelling points on either side. Supporters view the scarcity of private capital as a symptom of a coordination problem that government can help alleviate. Because enrichment plants take years to license and construct while demand is still emerging from reactors, relying solely on private dollars risks domestic fuel being unavailable when reactors come online. Critics question why these developers can’t raise capital without government intervention. If financiers genuinely forecasted that HALEU demand would materialize, they would buy in on their own. In their view, the lack of initiative from the private sector is a clearer indicator of weak demand than of a problem markets can’t solve themselves.

>>>READ: America’s Nuclear Renaissance Deserves a Fuel Policy to Match

As the government’s support charges forward however, it’s imperative that they preemptively remove regulatory barriers that make these projects—part of which taxpayers are footing the bill for—riskier or costlier than is absolutely justified. Removing obstacles for allied partners interested in building the enrichment orderbook and minimizing burdensome administrative proceedings are two productive roles for public policy.

Leveraging private sector support from nuclear-ambitious allies, such as Japan and South Korea, is a natural first step, but allowing their investment in these facilities requires final U.S. government signoff. This includes granting export licenses through the Nuclear Regulatory Commission (NRC), verifying compliance with bilateral nuclear energy agreements, and receiving approvals through the DOE and State Department. When trusted foreign partners approach a U.S. company, Washington should make it easy for them to invest and arrange offtake. South Korean participation in one facility is already under discussion, and it offers a working template for how buyer interest can strengthen our energy security and alliances at the same time.

There is also a noteworthy opportunity to expand permitting efficiency aside from the accelerated license reviews already being granted by the NRC. 

DOE is seeking to cluster facilities across the nuclear fuel supply chain in what it calls Nuclear Lifecycle Innovation Campuses. Done well, those campuses could bring enrichment closer to upstream and downstream infrastructure, which would lower transportation risk, improve coordination, and make it easier to permit the fuel cycle. Delivering fuel involves logistics, security, and transportation challenges. Transporting HALEU specifically requires rigorous physical security and route planning, compliance with strict packaging regulations, and additional NRC approvals to ensure the fuel’s stability. In short, bringing other nuclear manufacturing steps nearer to enrichment facilities can lighten both short- and long-term administrative burden on the U.S. nuclear industry.

As some American companies and utilities look to nuclear energy to provide abundant, reliable electricity, the potential for a fuel constraint looms large. If the federal government chooses to sustain its financial commitments to developing uranium enrichment domestically, it should pair this with a commitment to regulatory efficiency. As the DOE inks billion-dollar contracts with HALEU development prospects, policymakers owe it to the American people to welcome procurement from our global allies and ease the nuclear permitting burden.

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