Concentric is proud to announce a series of well-deserved employee promotions across the firm, recognizing individuals who have consistently demonstrated service excellence, strategic leadership, and an exceptional commitment to our clients.

Peter Blazunas was promoted to Vice President

Michael Buckley was promoted to Senior Project Manager

Wale Akanni was promoted to Project Manager

Tom Dolezal was promoted to Project Manager

Bryan Hu was promoted to Project Manager

Viktoriya Rutkovskaya was promoted to Project Manager

Riley Burns was promoted to Senior Consultant

Nolan Souza was promoted to Senior Consultant

Somann Rauf was promoted to Consultant

Aanchal Saini was promoted to Senior Analyst

Will Roberts was promoted to Senior Analyst

Nico Serpico was promoted to Senior Analyst

Shannon Downing was promoted to Business Development & Marketing Coordinator

Paul Dauderis was promoted to Director of IT

Sarah Andrukonis was promoted to Manager of Employee Development

“I am continually inspired by the dedication and excellence our team demonstrates. These promotions are a testament to the remarkable contributions each individual has made to Concentric’s success,” said Danielle Powers, Chief Executive Officer.

“Each of these individuals has made significant contributions to our success and consistently embodies our firm’s values through their commitment and diligence,” added Dan Dane, President.

Please join us in congratulating our employees on their achievements.

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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such. 

Published: December 17, 2025

By: Concentric Staff Writer

Key Takeaways:

New wholesale energy markets forming in the West will create a host of new market seams issues, especially between market and non-market areas, a new Federal Energy Regulatory Commission white paper says.

Eastern areas where organized markets and regional transmission organizations currently function provide some learning examples, but there are key differences in the current markets in the East and emerging markets in the West.

Tools to manage this new environment include flow-based rather than contract-based transmission scheduling, reliability standards, and resources such as Parallel Flow Visualization and interchange optimization.

Emerging market complexities in the Western U.S. energy landscape will require new and enhanced approaches to market seams, according to a new report from federal energy regulators. Seams are boundaries between markets and balancing authority areas that create reliability, operation, and market efficiency hurdles according to a white paper from the staff of the Federal Energy Regulatory Commission (FERC), “Seams Coordination in the Western Interconnection,” exploring these evolving dynamics. The paper does not necessarily reflect the positions of the Commission itself, the document says.

The West is changing with new markets under development, such as the California Independent System Operator’s (CAISO) extended day-ahead market (EDAM), due to launch in May 2026 and the Southwest Power Pool’s (SPP) Markets+ day-ahead market due to launch in late 2027.

In addition to EDAM and Markets+, there is also the expansion of SPP’s Regional Transmission Organization (RTO) footprint as well as the ongoing presence of bilateral energy trading going on between more than 30 balancing areas in the West. This “multi-market” environment will create barriers to efficiency of reliability, grid operation and markets, the paper says. SPP’s RTO will eventually include portions of Arizona, Colorado, Montana, Utah, and Wyoming, according to the paper:

“As numerous stakeholders have pointed out, this new, complex environment will require formal seams coordination, and Commission staff believes it will be worthwhile for the relevant parties to work toward crafting new coordination agreements to address seams issues,” the paper says.

Seams are created from differences in transmission modeling, access rights, and scheduling between adjacent transmission owners that can cause congestion and potentially create reliability issues from loop flows. These issues could diminish the economic benefits of both EDAM and Markets+ as they limit the opportunity for interchange trade, although these new markets will still bring economic benefits of their own through optimized unit commitment and market-wide dispatch, the paper says.

The East has provided lessons in three key areas FERC staff said: congestion, reliability, and economic market transactions. But there are significant differences in the West that limit the applicability of these lessons, since eastern RTOs and independent system operators function as single Balancing Authorities (BAs) and as transmission operators.

In EDAM and Markets+, market participants will not turn over functional control of their transmission systems, and balancing authority areas will remain distinct and not consolidated, the report says, while some BA’s will not join centralized markets at all.

As a result, seams agreements in the West could entail more parties in the region, including market operators, BA’s, federal power marketing administrations, public power entities, and governmental entities, and must be aligned across multiple open access transmission tariffs and market protocols.

Efforts to address market seams in the West are already underway, such as one by CAISO’s RC West, the reliability coordinator for 24 BA’s and 40 transmission operators, and the SPP’s Reliability Coordinator’s development of a new proposal to expand procedures and solutions for managing unscheduled flows. This includes a North American Energy Standards Board (NAESB) proposal for “explicit treatment” of system operating limits and interconnection reliability operating limits.

Transmission availability in the West is still primarily modeled on the basis of contract paths rather than flow-based modeling used in the East, FERC staff said.

“The continued use of contract-path based modeling and the use of different modeling methodologies may complicate efforts to maintain reliability, mitigate congestion, and enhance economic benefits in the Western Interconnection. Western entities could therefore investigate whether adopting flow-based modeling across the entire West could aid West-wide coordination,” the white paper says.

Coordination to maintain reliability and manage congestion are tied together, however, and because EDAM and Markets+ participants will not transfer that functional control of transmission systems or consolidate balancing authority areas, schedules cleared in one market can produce parallel loop flows through facilities outside of a given market’s footprint. This will reduce energy transfer capability during times of stressed system conditions, which could affect system operating and interconnection reliability limits and possibly result in system curtailments or redispatch of generation, along with economic impacts.

Another difference between the West and the East is the approach to coordination in efforts to enhance economic benefits, the paper says. Reduced costs to participate in centrally cleared markets can create efficiencies and transaction costs could be reduced by establishing clear and consistent rules around market participation and scheduling at market interfaces. Other tools could include standardizing data interfaces and definitions for transmission availability, scheduling rights, and transactions across borders.

Efforts to schedule and track market transactions in the West stretch back to the 1990s, including initiatives to promote open access and competition in wholesale energy markets such as the Energy Policy Act of 1992 and FERC Order Nos. 888 and 889. To facilitate energy transfers across long distances in the West, methods were developed to facilitate bilateral commercial arrangements and minimize unwanted consequences for third parties.

Under NAESB standards, implementation of interchange transactions begins with a system operator or market participant submitting to the Sink BA1 a request for interchange that includes the financial and physical path of the transaction. The Sink BA has the responsibility to confirm the transaction will not create reliability problems and the information for the transaction is recorded in an “e-Tag.”

e-Tags are also used to manage interchange schedules, with parties to the transaction able to request changes to the interchange schedule for economic or reliability reasons. Reliability Coordinators (RCs) and BA’s can also request change to the interchange schedule for reasons such as the need to manage a physical transmission path defined in a commercial contract that could create a reliability risk.

Shifting to a flow-based modeling approach uses actual power flows to calculate available transmission capacity by identifying the transmission facilities, or flow gates, and their physical parameters and limits. This method is considered to be more consistent and efficient than the contract-based methodology currently used in the West, the paper says.

The flow-based approach has been explored in various FERC proceedings such as its Western Resource Adequacy Technical Conference. Various parties encouraged FERC to direct the North American Electric Reliability Corporation to make the use of flow-gate modeling to calculate available transmission capacity.

“Western entities could consider whether the expansion of centralized markets has sufficiently changed transmission usage patterns and modeling needs such that it is appropriate to move to flow-based modeling across the region,” the paper says.

Contract-based modeling might have been appropriate in a system that is dominated by bilateral contracts and delivery, but a shift to centrally cleared markets such as exists in RTOs might make other modeling methodologies more appropriate, FERC staff said.

Flow-based modeling has made seams coordination more effective, the paper says, such as between the PJM Interconnection and the Midcontinent Independent System Operator, which has created the ability to share grid topology, outage, and dispatch data in real time. This flow-based modeling will exist in both EDAM and Markets+, but BA’s not participating in day-ahead markets could still be scheduling based on contract paths, creating a conflict between the centralized markets and BA’s, leading to inconsistent modeling and estimates of flows.

In the area of reliability, energy transfers between BA’s can maintain system stability in situations of extreme weather, such as experienced with Winter Storms Uri and Elliott. Agreements that formalize these arrangements between market and non-market areas would provide more information for system operators and aid cooperation between BA’s, the paper says. Western entities should consider whether these reliability agreements coordinate modeling of data and models, provide for protocols during emergency weather events and manage loop flows.

Other areas of analysis include market-to-market agreements as are used in the East, which improve reliability and management of congestion, but such agreements do not cover flows in areas not using locational marginal pricing (for flows to/from non-market regions). For transactions between market and non-market regions, tools such as Parallel Flow Visualization could be effective, according to the report.

Additionally, using coordinated trading or interchange optimization on the border of EDAM, Markets+ and the existing Western Energy Imbalance Market could further enhance economic benefits of interchange, the paper says. Interchanges can be managed in different ways, with seams coordination in the East again serving as an example. But each coordination agreement has its own data requirements, forecasting challenges and latency in the optimization process.

Through robust analysis of potential seams issues in the West in the future, the FERC paper provides a valuable resource for grid operators, market participants and others that must function in this new and highly complex environment.

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A new white paper authored by Tom Dolezal and Joshua Nowak examines the climate volatility increases utility companies face due to growing challenges in managing weather-related risks. From hurricanes to wildfires, these events not only disrupt operations but also impact financial performance. The frequency and intensity of these events are continuing to increase; Climate.gov reports that 2024 had the second most number of climate disasters that caused over $1 billion in damages, trailing only 2023.¹

This white paper describes a practical approach to map the Federal Emergency Management Agency National Risk Index to utility service territories, enabling better assessment of weather risk and its implications for utilities and customers. The goal is to provide regulators and utility professionals with a data-driven framework to better understand the weather risk that impacts utility service territories and to inform regulatory outcomes that more accurately reflect that risk. A specific application to risk analysis supporting a return on equity determination is presented.

¹ Smith, Adam B. “2024: An active year of U.S. billion-dollar weather and climate disasters.” NOAA Climate.gov, 10 Jan. 2025, https://www.climate.gov/news-features/blogs/beyond-data/2024-active-year-us-billion-dollar-weather-and-climate-disasters.

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All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The authors’ views are based upon information the authors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Concentric Energy Advisors, Inc. (“Concentric”), continues to expand its regulatory expertise with the strategic hire of Ms. Ashley Botelho as an Assistant Vice President.

Ms. Botelho has over 15 years of experience in the public utility sector, specializing in the fields of revenue requirements and performance-based ratemaking. Before joining Concentric, she spent more than ten years at Eversource Energy, where she most recently served as the Director of Revenue Requirements. In that role, Ms. Botelho led a team responsible for developing annual revenue requirement calculations of approximately $2 billion for the electric and gas distribution companies in Massachusetts and New Hampshire. She managed multiple regulatory initiatives, executed complex base distribution rate cases, and provided expert witness testimony on financial and regulatory policy matters.

“I’m excited to join the Concentric team,” Ms. Botelho said. “Concentric is dedicated to serving the energy industry with an unwavering work ethic and commitment to service excellence. I look forward to contributing to the culture of client success.”

Danielle Powers, Concentric’s Chief Executive Officer, and Daniel Dane, Concentric’s President, warmly welcomed Ms. Botelho, emphasizing her exceptional industry background as a strong foundation for addressing regulatory challenges. “Our clients will benefit from Ashley’s extensive expertise and hands-on experience,” Ms. Powers enthusiastically noted. Mr. Dane added, “Her proven track record of delivering measurable results will enhance our service offerings and drive client success.”

To learn more about career opportunities at Concentric or to receive industry news and insights, please visit Concentric’s Careers page and subscribe to the Concentric Connection.

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Published: November 5, 2025

By: Concentric Staff Writer

Key Takeaways:

U.S. Energy Information Administration forecasts for household spending on heating this winter vary among resources, with electricity higher, natural gas flat with last year, and propane and heating oil expected to drop.
U.S. inventories of fuels also vary, with natural gas and propane higher and heating oil lower.
The primary heating fuel for houses in winter in the U.S. is natural gas, followed by electricity, propane, and heating oil at much smaller percentages.
Residential electricity prices have increased most sharply in the Mountain, Middle Atlantic, and South Atlantic regions due to increases in natural gas prices, and expenses associated with storms and wildfires.

Financial expenditures on heating fuels for the upcoming winter are forecast to be a mixed bag, but only prices for electricity used for heating houses are due to rise, according to a new report from the U.S. Energy Information Administration (EIA).

Average winter household expenditures across the country for natural gas this winter are expected to be about the same as last year, while propane and heating oil are set to drop, according to the EIA’s Winter Fuels Outlook. These fuel types, along with electricity, are the primary heat sources in winter, with natural gas at 46 percent of that demand, electricity at 43 percent, propane at 5 percent, and heating oil at 3 percent. The usage of certain fuel types also varies depending on the region of the country.

“The consumption and expenditure forecasts in the Winter Fuels Outlook apply to a home’s main space heating fuel,” the report says. “For most households, the main space heating fuel is also used for other purposes. Households primarily heating with natural gas equipment, for example, may also use natural gas for water heating, cooking, or clothes drying.”

The report forecasts average residential consumption, price, and household expenditures for various fuels for up to four U.S. Census regions: the Northeast, Midwest, South, and West. The prices will be updated throughout the winter in the Short-Term Fuels Outlook.

Temperatures are always an uncertainty in forecasts, but they are expected to be similar to last winter, which drives a similar pattern of residential energy consumption, according to the report. This means that much of the expected expenditures for energy will be driven by energy prices.

Winter could be slightly milder across much of the country, especially in the Northeast, EIA said, with heating degree days (HDD) used to measure winter weather effects. Five percent fewer HDDs are expected in the Northeast this winter, with three percent fewer HDDs in the South and 1 percent fewer in the Midwest and West.

Fuel inventories are also a factor in winter supply and affect prices, with stocks for natural gas and propane currently at higher levels than the five-year average for 2020-2024, keeping prices generally below last year. Distillate fuel inventories, including heating oil, are slightly below the five-year average, and lower crude oil price forecasts are expected to push down heating oil prices.

The report examines a base case with slight drops in heating expenditures for the country as a whole and drops in every region in the U.S. except the Midwest. EIA also looked at scenarios where winter is 10 percent colder than last year and 10 percent warmer. Energy expenditures in a given household are also dependent on the size and efficiency of individual homes.

The impact of wholesale energy prices on retail prices also varies among fuel types, with the impact of natural gas on electricity prices subject to a lag because of the way utilities are regulated. But natural gas prices correlate more directly with electricity prices over longer periods.

“Some state utility commissions set the rates utilities can charge for natural gas deliveries a year or more in advance of billing to reflect the cost of wholesale natural gas that utilities purchased over many months,” the report says.

State regulators also vary in their timing and frequency of rate change approvals, with retail rates sometimes adjusted several times a year in times of high fuel-price volatility. Charges other than commodity natural gas prices also affect bills, such as utility operating costs and costs to transport natural gas and distribute it to customers.

Increases in electricity costs might pass through to customers more quickly in states with retail choice and energy markets compared to traditionally regulated states. However, wholesale prices for propane and heating oil pass through to retail customers much more quickly, within a period of four to six weeks, because prices for those commodities are not regulated by state public utility commissions.

While 46 percent of U.S. homes use natural gas as a heating fuel, EIA’s base case predicts that slightly milder winter temperatures will reduce natural gas consumption by 2 percent this winter. But that slightly lower natural gas consumption is offset by an average 1-percent increase in natural gas prices, with variations across different regions.

In EIA’s 10 percent colder scenario, a 6-percent, or 6-million cubic-feet (MCF) increase in natural gas consumption is projected compared with last winter. The warmer-weather scenario would push down natural gas consumption by 8 percent compared with last winter and lead to a 4-percent decrease in energy expenditures for households.

Winter household natural gas bills in the Midwest are due to rise about 2 percent to about $610, driven by slightly higher natural gas prices in that region. Midwest natural gas customers are expected to consume about the same amount of the resource as last year: 59 MCF.

Households primarily using electricity for heating are expected to pay an average of 4 percent more this winter nationally due to a projected 5-percent increase in electricity prices. But these effects will be offset by a projected 1-percent drop in consumption due to the milder winter.

Electricity expenditures in the Midwest and South are expected to increase by a similar 4 percent despite slightly lower consumption, while expenditures in the Northeast and South are expected to increase by about 3 percent.

Winter expenditures will logically be higher in colder regions, with the Northeast spending the most at an average of $1,520 over the winter, followed by the Midwest next at about $1,280 over the season.

Residential electricity prices have increased most sharply in the Mountain, Middle Atlantic, and South Atlantic regions due to increases in natural gas prices, expenses associated with storms and wildfires, increasing insurance costs, and infrastructure expansions due to load growth.

Retail electricity prices are set to increase in the Northeast, which includes the Middle Atlantic and New England states, by about 6 percent to an average of 24 cents per kilowatt-hour (kWh). In the Middle-Atlantic division, New York, New Jersey, and Pennsylvania, prices are due to increase more than the Northeast average of 6 percent.

In the West, which includes the Pacific and Mountain regions, residential prices are expected to average 20 cents per kWh, with the smallest jumps in California, Oregon, and Washington, and the lowest expected increase at about 2 percent.

For propane, lower spot prices are driving a trend towards lower household prices, and the slightly milder winter is set to push prices down. Propane inventories are higher than the five-year average.

Working natural gas inventories in the U.S. are currently at about 5 percent above the five-year average and wholesale price increases this summer were eased by “robust” production and lower power sector consumption. Prices are expected to increase going into winter as natural gas exports increase and storage withdrawals begin to exceed storage injections.

While price changes for natural gas are expected to be modest nationally, certain regions will see more extreme changes, such as the Mountain region where prices are expected to rise. Prices in the Pacific and South regions are expected to be much lower than last winter.

The information in the report is for all end uses associated with a certain home’s main heating fuel, which are generally a subset of a household’s total energy costs except for all-electric homes, the report says.

Household consumption and financial expenditures for space heating were based on information from EIA’s Residential Energy Consumption Survey (RECS). In developing forecasts, it converts annual RECS data to monthly values and EIA also uses monthly forecasts available in its Short-Term Energy Outlook.

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Published: October 9, 2025

By: Concentric Staff Writer

Key takeaways:

New initiatives and investments under the administration of President Donald Trump are aimed at dramatically increasing nuclear development through the quickening of permitting timelines and other efforts.
The U.S. is pursuing multiple partnerships with other countries with the goal of increasing mutual nuclear development.
Billions of dollars are pouring into the industry, bolstered by a renewed federal focus on new technologies such as nuclear fusion.

There is a nuclear renaissance going on in the United States as grid planners and other interests search out new technologies to power the modern system and the U.S. partners with other countries to push nuclear forward.

A new report from nuclear interests lays out the potential for nuclear and its challenges, saying strong federal support will be needed. President Donald Trump in May issued an executive order (14302) calling a strong nuclear industry a matter of national security, mentioning artificial intelligence and “mission capability resources” at U.S. military bases and national laboratories that are subject to electrical outages.

The new report from the Energy Innovation Reform Project (EIRP) said that private companies in the U.S. are competing against primarily state-owned development internationally. Thus, it is very difficult for them to compete in an environment that does not support or hinder nuclear development.

“Many forces are driving the country’s renewed enthusiasm for nuclear energy, including intensifying geopolitical, security, and techno-economic competition; rapidly growing demand for electricity (especially to power new AI data centers); and increasing appreciation for nuclear energy’s ability to provide reliable, clean power,” the report says.

EIRP describes itself as a nonpartisan organization that aims to promote policies that advance innovation in energy technologies and practices, improving affordability, reliability, safety, and the security of the U.S. energy supply and energy economy.

Nuclear power is more regulated than other generation technologies, the report says, and there are opportunities for the White House and Congress to limit the regulatory burden on nuclear. Regulatory reform is just one tool to achieving nuclear energy dominance, which would take decades, according to the report.

Also complicating efforts are the fact that competitive and fully regulated markets border each other, creating different market dynamics. A focus on least-cost energy is also muddying the waters, it said.

Globally, Russia is dominating nuclear reactor exports and China has launched a large-scale nuclear reactor program, the report says, with China ready to dominate the global market if left unchecked. There is a global nuclear race underway that the U.S. is in danger of losing, it says.

“Indeed, China’s nuclear sector has high technical capabilities, strong human capital, and well-developed supply chains. It will soon have the largest operating fleet of large water-cooled reactors along with massive manufacturing and construction overcapacity in the sector, permitting it to undersell its competitors,” the report says.

For example, China already has a high-temperature gas reactor in commercial operation, while the U.S. has not yet begun to build one and will likely not have one in operation until the 2030s. This gives China cost and financing advantages that will be difficult to compete with, the report says. Other nations that lack the U.S safety regime could dominate the sector and lead to nuclear accidents and proliferation, the report warns.

Among the report’s findings are that the U.S. should deploy reactors domestically and export them internationally, and that in addition to permitting and regulatory reform, there will be a need to build confidence in nuclear among investors, customers and the public.

Other urgent needs are a secure, reliable, and affordable supply of nuclear fuel; a structured, government-wide approach to nuclear development; adequate staffing at nuclear-related agencies; and the development of a workforce that includes engineers, skilled construction workers, and trained reactor and fuel-manufacturing plant operators.

Accordingly, the White House Office of Management and Budget, White House Office of Congressional and Legislative Affairs, and other relevant governmental departments should place high priority on ensuring adequate financial resources for full implementation of President Trump’s executive order, the report says.

In the area of boosting domestic deployment of nuclear, the report recommends allowing regulated utilities to take advantage of the investment tax credit on new reactors immediately, rather than requiring developers to spread it out over the years when the asset is depreciating.

Other recommendations include:

Providing risk insurance and other policy support.
Directing the U.S. Department of Energy to prepare a report comparing the full system costs of intermittent renewable power.
Fully funding the Advanced Reactor Demonstration Program and GenIII+ Small Reactor Modular Reactor Program, as well as the Advanced Nuclear Fuel Availability Program.
Preserving funding for the DOE’s Loan Program Office for both credit subsidy costs and program management, with the office’s efforts focused on industries that align with the Administration’s priorities.

In the area of exports, the Department of State should negotiate more than one hundred new agreements in accordance with President Trump’s executive order and the Nuclear Regulatory Commission should increase coordination with foreign regulators, especially in Canada, the United Kingdom, Japan, and other U.S. allies, the report says. The National Energy Dominance Council should also accommodate nuclear energy export policies and programs like the Foundational Infrastructure for Responsible Use of SMR Technology, which helps governments in potential export markets strengthen their nuclear energy policy and regulatory capacity to be part of a strong international market for small modular reactors.

There have also been advances made relatively recently in fusion nuclear technology—traditional nuclear technology employs “fission” technology, in which two light atomic nuclei are split into two. Fission employs fuel like Uranium-235 or plutonium-239 and releases energy because the total mass of the resulting fragments after fissioning them is less than the original nucleus.

In contrast, fusion refers to the process of combining two light atomic nuclei to form a heavier nucleus, such as using two hydrogen isotopes like deuterium and tritium to form helium. The mass of the resulting nucleus is slightly less than the sum of its parts, with the missing mass converted to energy.

Major recent fusion energy breakthroughs include TAE Technologies’ new reactor prototype, known as “Norm,” which demonstrates enhanced plasma formation and optimization. The breakthrough fundamentally advances the performance, practicality, and reactor-readiness of the company’s fusion technology, it said in a press release.

China’s Energy Singularity has also initiated operations of the HH70 Tokamak, the first to utilize high-temperature superconductors exclusively for its magnet system, which aims to make fusion reactors more compact and cost-effective.

Also, Japanese startup Helical Fusion intends to launch the world’s first steady-state nuclear fusion reactor by 2034, with commercial operations projected in the 2040s.

Additionally, the International Thermonuclear Experimental Reactor (ITER) project completed the sixth and final component of its central solenoid, a magnet powerful enough to levitate an aircraft carrier, according to the company. This achievement is seen as a significant step toward achieving the first plasma by 2025.

Researchers at DOE’s Princeton Plasma Physics Laboratory also set a new record with a fusion device internally clad in tungsten, which is seen as the best fit for commercial-scale machines required to make fusion a viable energy source, the lab said.

“The device sustained a hot fusion plasma of approximately 50 million degrees Celsius for a record six minutes with 1.15 gigajoules of power injected, 15% more energy and twice the density than before,” the lab said in an internet posting. “The plasma will need to be both hot and dense to generate reliable power for the grid.”

The developments in new nuclear technology come as countries are increasingly collaborating with the U.S. on nuclear development.

The U.K.’s Office for Nuclear Regulation on September 15, 2025 announced a refreshed memorandum of understanding with the U.S. to streamline regulation and accelerate deployment of advanced nuclear reactors across both countries’ markets. The agreement reaffirms a separate one signed in 2020 to cooperate closely and exchange technical information as the two countries “move towards the deployment of safe and secure nuclear technologies globally,” according to an announcement from the Office for Nuclear Regulation.

The agreement is designed to cut duplication and fast-track decisions, targeting a goal of reviewing reactor designs within two years and nuclear sites within one year. Regulators will lead specific aspects of review and mutually recognize each other’s assessment, according to the announcement, and when one regulator has already assessed a design, the second regulator will maximize acceptance of completed work to avoid duplication. The program will focus on technologies that are already in licensing or ready to enter the licensing process in the U.S. and the U.K.

Another initiative is an agreement between Centrica and X-energy to jointly develop the U.K.’s first advanced nuclear reactors and pursue 6 gigawatts of new nuclear capacity in the country.

The first project is expected to be at EDF and Centrica’s Hartlepool site, setting up development of 6 GW of advanced reactors, which could generate up to $54 billion in economic activity and thousands of new jobs, according to a press release.

The DOE, the U.S. Department of State, and the Republic of Korea also announced a Memorandum of Understanding on Principles Concerning Nuclear Exports and Cooperation, which finalizes a provisional understanding reached by the two countries in November 2024.

“The United States and Republic of Korea have worked together on civil nuclear power for more than 70 years,” a DOE announcement says. “The cornerstone of this cooperation reflects the two countries’ mutual dedication to maximizing the peaceful uses of nuclear energy under the highest international standards of nuclear safety, security, safeguards, and nonproliferation.”

In July, the DOE also announced a new pilot program to accelerate the development of advanced nuclear reactors and strengthen domestic supply chains for nuclear fuel. DOE issued a request for application, seeking U.S. companies to build and operate nuclear fuel production lines to help end the country’s reliance on foreign sources of enriched uranium and other materials, intended to help stimulate private-sector investment in nuclear power.

The DOE said it is currently reviewing potential applicants and anticipates selecting at least three advanced reactor designs over the summer that have the potential to achieve criticality by July 4, 2026.

Also, DOE Secretary Chris Wright in April announced the release of a third loan disbursement to Holtec for the reopening of the Palisades Nuclear Plant in Michigan. The initiative released $46.7 million of the up to $1.52 billion loan guarantee to Holtec for the plant, which will provide 800 MW when completed.

“In advancing President Trump’s commitment to meet our growing demand for affordable, reliable and secure electricity, America needs to utilize all forms of energy that grow our economy, create new jobs, and secure energy independence,” Wright said. “With projects like the Palisades Nuclear Plant, the Energy Department is working to ensure America’s nuclear renaissance is just around the corner.”

Overall, it is clear the Trump Administration is pushing for billions of investment in nuclear and partnering with other countries, with the hope that it will increase its profile as an energy source as the U.S. deals with unprecedented demand for electricity.

Sources used in this article:

Centrica and X-energy Sign Joint Development Agreement to Deploy U.K.’s First Advanced Modular Reactors and Pursue 6 Gigawatts of New Nuclear Capacity in the U.K. X-energy.

Deploying Advanced Nuclear Reactor Technologies for National Security. The White House.

Energy Department Announces Pilot Program to Build Advanced U.S. Nuclear Fuel Lines and End Foreign Dependence. U.S. Department of Energy.

Fusion record set for tungsten tokamak WEST. Princeton Plasma Physics Laboratory.

Helical Fusion Unveils “GALOP”—A Groundbreaking Liquid Metal Blanket Testing System Essential for Commercial Fusion Reactors. Helical Fusion.

How America Can Achieve Nuclear Energy Dominance. Energy Innovation Reform Project.

International Thermonuclear Experimental Reactor (ITER)

Joint Statement of the United States of America and the Republic of Korea on the Expansion of Peaceful Nuclear Energy. U.S. Department of Energy.

Nuclear regulators renew transatlantic collaborative agreement. Office for Nuclear Regulation (ONR).

TAE Technologies Delivers Fusion Breakthrough that Dramatically Reduces Cost of a Future Power Plan. PR Newswire.

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Published: September 16, 2025

By: Concentric Staff Writer

Key takeaways:

The PJM Interconnection’s latest base residual auction for capacity was subject to a federally approved price cap of $329.17 per megawatt-day (MW-day).
Concentric Energy Advisors’ Chief Executive Officer, Danielle Powers, said that PJM’s capacity market was designed for a set of circumstances that no longer exist, mentioning a massive influx of zero-fuel-cost renewables.
The assumption underlying the original market design, which was that energy prices would rise and reliance on capacity market revenues would decrease over time, has not materialized, Powers said.

The PJM Interconnection’s most recent auction for future adequate power generation is once again drawing attention for high prices, amid a larger conversation about the efficacy of the capacity market and whether it is serving its intended purpose across the organization’s 13-state region.

PJM’s 2026/2027 Base Residual Auction (BRA), held in June, reached a federally mandated price cap of $329.17 per megawatt-day (MW-day) for unforced capacity generation (UCAP), not a welcome signal for load serving entities in PJM. The auction covers the delivery period of June 1, 2026 to May 31, 2027.

The second year of high auction clearing prices raises questions about the capacity market design and whether it is suitable for an energy landscape that has significantly changed.

Concentric Energy Advisors’ Chief Executive Officer, Danielle Powers, said in an interview that the PJM capacity market auction structure is now operating in “a world that was not anticipated.” This includes increasing levels of contracted renewable generation, the retirement of large fossil-fueled generation, and unprecedented demand growth.

Of price signals in general in the capacity market, however, Powers said, “I think it’s largely been successful—the capacity auction has sent the appropriate price signal when new capacity is needed, as both the energy markets and the ancillary services markets have demonstrated positive outcomes. The challenge lies in the delay between the price signal indicating the need for new generation and the actual connection of resources to the system. This process typically takes around five to seven years, which presents a significant obstacle. It is hard to tolerate that lag.”

But overall, the markets were designed for a different electrical system, she commented. “The capacity markets worked for a time, and under a set of circumstances that are fundamentally different than those in today’s environment,” Powers said.

PJM’s capacity market, also known as the Reliability Pricing Model, is designed to procure adequacy three years out, according to PJM documents. The capped price of $329.17 compares with a price of $269.92 in the previous auction (2025/2026), reflecting an increase of about 22 percent. The exceptions in the 2025/2026 auction were the Baltimore Gas & Electric (BGE) zone in Maryland and Dominion Energy, which includes portions of Virginia, North Carolina, and South Carolina. BGE cleared at $466.35 per MW-day and Dominion at $444.26 per MW-day in the previous auction but this year cleared at the same cap as the rest of the PJM region.

The 2026/2027 auction, held in July, procured 134,211 MW of UCAP and demand response across PJM’s regional footprint, which includes more than 67 million people and also encompasses the District of Columbia, PJM said.

“Wholesale capacity accounts for a relatively small portion of retail electricity bills; PJM would expect the cap price to translate to a year-over-year increase of 1.5–5% in some customers’ bills, depending on how load-serving entities and states pass on wholesale costs to consumers. Given that prices decreased in two zones, it is possible that consumers in some areas could see a drop in retail rates,” PJM said.

The auction shows that generation suppliers are reacting to price signals from the previous 2025/2026 auction, PJM said. The total amount of new generation and generation uprates added in the most recent auction was 2,669 MW of UCAP, the first increase in new generation and uprates in the last four auctions, it said. Despite PJM’s conclusions, there are indications that the market is not working as intended

Also, 17 generating units totaling approximately 1,100 MW of capacity have withdrawn their retirements since the 2025/2026 auction, another indication that suppliers are reacting to price signals as intended.

But price signals only work if there is enough time to act on them. A three-year forward auction may buy investors certainty, but it doesn’t guarantee shovels in the ground, fuel security, or new steel in time to meet reliability needs. The question today isn’t just whether the market sends the “right” price – it is whether those prices arrive with enough runway for real investment to happen.

In addition, Powers points out that when it was designed, the capacity market was intended to be a residual market, which means the base residual auction is intended to procure only the remaining, or residual, capacity needs in the region after accounting for self-supply (vertically integrated utilities meeting their own load) and bilateral contracts between capacity suppliers and load-serving entities outside of the auction.

The market cap flows from a complaint filed in December 2024 by Pennsylvania Governor Josh Shapiro to the Federal Energy Regulatory Commission (FERC) that argued PJM’s auction demand was flawed, with the issue exacerbated by rising demand and a clogged generation interconnection queue. This resulted in PJM agreeing to the price cap for the latest auction in order to avoid billions of dollars of projected additional costs for customers in the PJM footprint. The price cap came along with a floor of $175 per MW-day. FERC formally approved the settlement in April of this year. Other states, such as Maryland, Illinois, Delaware, and New Jersey, supported the complaint.

States are beginning to recognize that if they bear responsibility for resource adequacy, then reliance on competitive markets to meet those requirements requires that the markets function effectively. States are wondering why they are paying higher prices without the generation that they need coming on line, Powers said.

“The market is sending the signals,” she explained. “But it’s seven years before you can actually get generation on line. So, that’s the frustration.”

Another factor is load growth due to new and planned data centers. Pressure on capacity markets was also supposed to lessen with higher energy prices, but prices actually declined, Powers commented, putting pressure on the capacity market, which is now showing signs of structural failure.

“This highlights that there may not have been enough consideration given to the combined impact of thousands of megawatts of zero-variable-cost resources, the retirement of large generating units, and surging demand growth,” she said.

The issues seen in PJM are likely to spread to other regions, such as the Midcontinent Independent System Operator, Powers commented.

“In PJM, the challenges are immediate and pressing, whereas in other regions, the same issues are beginning to emerge. They may have a bit more time, but the pressures are inevitable,” she said.

Sources used in this article:

2026/2027 Base Residual Auction Report

PJM Auction Procures 134,311 MW of Generation Resources; Supply Responds to Price Signal

Complaint of Governor Josh Shapiro and the Commonwealth of Pennsylvania

Order Accepting Tariff Revisions and Dismissing Complaint re Commonwealth of Pennsylvania v. PJM Interconnection, L.L.C. under ER25-1357

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Published: September 5, 2025

By: Concentric Staff Writer

Key Takeaways:

Arizona is moving to repeal its renewable energy standard mandate, saying it has led to excessive and artificial costs to state ratepayers.
Arizona’s power demand is expected to increase sharply due to economic growth, including the construction of new data centers.
The projected increase in demand led state officials to recently approve a new, multi-billion-dollar natural gas pipeline to meet expected rising demand.
Tucson city officials recently rejected a new data center, Project Blue, related to Amazon Web Services, but the developer is exploring alternate sites that could lead to the facility still being constructed.

Arizona is putting the brakes on its renewable energy mandate as electricity demand explodes in the state and it recently rejected a proposal for a massive new data center—although the project is almost certain to resurface.

The state is gearing up for major increases in demand for energy and water with at least 20 data centers proposed, leading to the approval of a new natural gas pipeline to help bolster natural gas-fired power plants.

Perhaps the most significant development in the state is a decision by the Arizona Corporation Commission (ACC) to repeal that state’s renewable energy standard. The ACC at its Aug. 14 open meeting directed its staff to take the next step to repeal the Renewable Energy Standard and Tariff (REST) established by the commission in 2006. The regulation required the state’s utilities to generate a certain percentage of their electricity from renewable resources, with a goal of 15 percent by 2006.

“The idea that the deployment of renewables in Arizona will come to a halt if REST is repealed is doom and gloom fear-mongering at its worst,” ACC Chair Kevin Thompson said in a written statement. “If renewables are truly the most affordable and reliable option, as we are frequently reminded by advocates, the generational technology should be able to prevail on its own without the need for mandates that have added millions of dollars in extra costs for ratepayers each year.”

Arizona utilities have already met the renewable standard requirements, but commission members called the rules outdated and said renewable resources should be “able to stand on their own,” according to Commission Member Rene Lopez, quoted in the press release.

The ACC said it estimates the renewable standard rules have resulted in about $2.3 billion in surcharges on state ratepayer bills since 2006. This has led to an artificial increase in the cost of energy, they said. Under the ACC decision, commission staff must file a Notice of Rulemaking Docket Opening with the Office of the Secretary of State by Sept. 19, according to the release. The commission will hold three public hearings on the matter Nov. 10 in Tucson, Nov. 12 telephonically, and Nov. 13 in Phoenix.

Amid the concerns of demand growth and water availability, the Tucson City Council recently rejected a plan for a massive data center near the city.

Project Blue’s primary development site was in Pima County, with the initial phase of the project due to become operational as soon as 2027, according to city council documents. A second phase was under exploration by the developer, which would also utilize reclaimed water. A feasibility study was underway for a third site, meaning that development could proceed at a different site in the future.

Water usage is closely tied to climate and weather conditions, according to the city council documents, and could vary in any given year. After build-out of the primary and secondary projects, Project Blue’s water usage was projected to not exceed 6 percent of the state’s reclaimed water portfolio, or 1 percent of the city’s available water.

The city council on Aug. 6 directed its staff to reject the data center as proposed and directed its city manager and staff to end negotiations regarding the Project Blue development agreement and related annexation. It also directed staff to “take any other steps necessary to end the process for the consideration of the annexation.”

However, the data center project is still alive and could be developed at a different site. Tucson Electric Power on Aug. 25 submitted to the ACC an energy supply agreement for the data center, being developed by Beale Infrastructure.

The rejection of Project Blue comes as the ACC realizes it needs additional natural gas supply—native natural gas is scant in the state—to meet rising demand.

The actions come as Arizona utilities have experienced record demand this summer, with the state seeing a new temperature peak of 118 degrees Fahrenheit on Aug. 7. There were also record temperatures in Prescott, which hit a record of 99 degrees that day, and Yuma, tying its record of 114 degrees that day.

Energy Transfer LP on Aug. 6 announced it reached a positive financial investment decision for the expansion of its $5.3 billion Transwestern Pipeline to increase the supply of Permian Basin natural gas in Arizona and New Mexico.

“Transwestern’s Desert Southwest pipeline expansion will provide reliable economic supplies of natural gas to support the long-term energy needs for utilities and energy providers in the region driven by population growth, high-tech industry demand and data center expansion,” the company said in a news release.

The project includes 516 miles of 42-inch pipeline with a capacity of 1.5 billion cubic feet per day. The extension will enhance reliability and provide additional options to serve demand in the Southwestern U.S., the company said. It is expected to be in service by the fourth quarter of 2029. About $600 million has been approved for funds during construction and already has “significant” long-term commitments from customers with an expectation that remaining capacity will be subscribed after an open season is launched later this quarter.

The developer said it will prioritize U.S. steel pipe manufacturers and will utilize up to 5,000 local workers and union labor construction jobs. Energy Transfer also operates nearly 200 natural gas-fired power plants and about 140,000 miles of pipeline and related infrastructure, it said.

Arizona falls sixth on the list of states projected to see the highest percentage of data center load, following Virginia, Texas, California, Illinois, and Oregon, according to a report from the Electric Power Research Institute (EPRI). Assisting in meeting this demand are the plentiful solar resources in the state, amid a low risk of natural disasters and overall market growth, EPRI said. Challenges include water scarcity and a need for sustainable cooling infrastructure.

Data centers accounted for about 7.43 percent of electricity load in the state in 2023, according to EPRI, which is projected to grow to about 8.81 percent by 2030 in a “low-growth” scenario and 12.73 percent in a high-growth scenario.

Arizona is currently working to balance its need for new demand while regulating massive new requirements on its power grid and revisiting its renewable energy goals.

Sources used in this article:

Decision by the Arizona Corporation Commission

Tucson City Council Documents

Project Blue Updated Fact Sheet_250713

Motions Adopted Under Aug. 6, 2025, Study Session Item 8/Project Blue

Request to Approve Special Agreement for Electric Service

ACC Supports Natural Gas Pipeline Expansion; Electricity Capacity in Arizona Steadily Increasing Year-to-Year

APS Customers Set New All-Time Record For Peak Energy Use

Energy Transfer Announces Natural Gas Pipeline Project to Serve Growing Southwestern U.S. Markets | Energy Transfer

Powering Intelligence: Analyzing Artificial Intelligence and Data Center Energy Consumption

—

Published: August 6, 2025

By: Stephen Wemple

A number of recent actions by the Federal Government have created headwinds for various states’ Renewable Portfolio Standard (RPS) goals. These headwinds are likely to result in higher compliance costs, delays in the timelines to achieve RPS goals, or some combination of the two.

Headwinds come from:

Opposition to Offshore Wind (OSW) Projects:

President Trump issued an executive order in January halting offshore leasing in federal waters and pausing permits and approvals on public lands and waters pending review by the Secretary of the Interior. This has caused many Mid-Atlantic and New England states to reassess the likelihood of additional projects being built, which will delay progress towards their RPS goals. In addition, the Federal government issued a stop work order on April 16th for the Empire Wind 1 project in New York but ultimately reached an agreement to allow the project to proceed. New York’s draft State Energy Plan was updated last month to assume that there will be no new OSW projects through 2035 beyond the completed South Fork project and the under-construction Sunrise and Empire Wind 1 projects. In addition, the New York Public Service Commission has formally withdrawn its request to the NYISO to build transmission to support OSW under the Public Policy Transmission Needs process.

Elimination of Investment and Production Tax Credits:

The federal budget enacted on July 4th terminated the Section 45Y Production Tax Credit (PTC) and Section 48E Investment Tax Credit (ITC) for wind and solar projects that are not in service by December 31st, 2027, and do not begin construction by July 4th, 2026. Also, a recently announced executive order could impact the “safe harbor” provision for late-stage projects seeking those credits. The loss of those tax credits will increase the cost of future wind and solar projects, increasing the costs to consumers for complying with RPS programs and meeting sustainability goals.

Impacts on different resources

Nuclear power:

The result of these headwinds increases the value of nuclear power as a source of emission-free energy. Several large datacenters are negotiating or have executed long-term offtake agreements to meet their energy needs from nuclear generating plants.

Several companies are evaluating options to restart and/or build new nuclear units. New York’s Governor Hochul has announced the state is seeking to add a new nuclear plant.

Existing renewable resources:

The higher cost of building new renewables is likely to increase the value of existing renewable generation. This impact should be most pronounced for those units that have shorter offtake arrangements and/or sell into state-administered RPS markets.

To learn more about how Concentric Energy Advisors’ Wholesale Energy Markets practice can assist you in navigating the intricacies of wholesale electric market design, please contact Stephen Wemple.

Sources used in this article:

Temporary Withdrawal of All Areas on the Outer Continental Shelf from Offshore Wind Leasing and Review of the Federal Government’s Leasing and Permitting Practices for Wind Projects │ The White House

Director’s Order │United States Department of the Interior

Amendment to Director’s Order of April 16th, 2025 │ United States Department of the Interior

Draft 2025 Energy Plan – New York State New Energy Plan │ NYSERDA

Commission acts to protect ratepayers as federal offshore wind permitting stalls │ Department of Public Service

H.R.1 – One Big Beautiful Bill Act, 119th Congress (2025-2026) │ congress.gov

Ending market distorting subsidies for unreliable, Foreign‐Controlled energy sources │ The White House

Governor Hochul directs New York Power Authority to develop a Zero-Emission Advanced Nuclear Energy Technology power plant │ Governor Kathy Hochul

—

Published: July 16, 2025

By: Concentric Staff Writer

Key takeaways:

The President Donald Trump Administration submitted its Fiscal Year (FY) 2026 budget request for the U.S. Department of Energy (DOE).
Energy Secretary Richard Wright outlined the budget request at a recent hearing of the U.S. Senate Committee on Energy and Commerce.
The administration’s priorities reflect an opposite approach to his predecessor, President Joe Biden, particularly in the area of regulations and permitting, fossil fuels and climate policies, and funding.
DOE also indicated a focus on nuclear energy, including small modular reactors (SMRs), developing artificial intelligence (AI) data centers, and stimulating production and export of fossil fuels.

The Trump Administration’s FY 2026 budget request for DOE reflects a departure from the previous administration in many ways, with a focus on emerging issues such as demand growth and new technologies.

DOE’s budget request reflects goals of securing the nation’s place in development of artificial intelligence and nuclear energy while also focusing on weapons stockpiles and meeting Cold War legacy waste commitments, according to DOE materials. The fiscal year begins on Oct. 1, 2025.

“The Department of Energy is capable of meeting these critical missions while increasing efficiency, unleashing innovation, and ensuring we are better stewards of taxpayer dollars,” Wright said at a June 18 hearing of the U.S. Senate Committee on Energy and Natural Resources. “President Trump is committed to balancing the budget and implementing fiscal restraint – focusing agency funding on the crucial goal of unleashing American energy dominance.”

The President’s 2026 Discretionary Budget Request totals $163 billion, a 22.6-percent drop from current-year spending.

The document describes a departure from policies of the previous Administration, a line-by-line review of spending, and consideration of whether certain governmental services could be better provided by state or local governments.

Generally, DOE proposed reductions in clean-energy programs and spending while making fossil fuel production a priority. Among the announced goals are increasing domestic exports of liquified natural gas (LNG) and decreasing timelines for permitting review and approval for LNG-related infrastructure. According to Wright, DOE so far has approved projects totaling more than 11.45 billion cubic feet per day (Bcf/d), an amount that eclipses the total annual exports of the world’s second-largest LNG exporter, Australia.

The Administration has also focused on reducing costs for consumers and expanding customer choice by cutting nearly 50 regulations and eliminating standards for electrical equipment, reducing regulations for building and energy production, and easing certain requirements for grant recipients. DOE rules that have been nullified involve equipment such as walk-in coolers and freezers, as well as efficiency standards for gas-fired instantaneous water heaters and commercial refrigeration equipment.

Trump has also indicated a focus on nuclear power, supporting the reopening of the Palisades Nuclear Energy Plant in Michigan and the DOE budget allocating high-assay low-enriched uranium material to several advanced nuclear energy developers.

“It is imperative to jumpstart America’s nuclear energy industrial base, and I am taking immediate action to accelerate the deployment of small modular reactors (SMRs). As electricity demand continues to grow, fueled by AI development and the growth of American manufacturing,” Wright said at the hearing.

The budget request provides for $46.3 billion in discretionary budget authority for FY 2026, a $3.5 billion (7-percent) decrease from the previously enacted level. The largest chunk of the budget, $30 billion, would go to the National Nuclear Security Administration (NNSA) which funds nuclear and fossil energy, invests in national laboratories, particularly in the areas of nuclear fission and artificial intelligence, and implements Trump’s announced “Peace Through Strength” initiative. There is also an announced goal of increasing production of domestic energy resources such as coal, natural gas, petroleum, and nuclear. The budget includes $1.37 billion for the Office of Nuclear Energy and $750 million in credit subsidy for the Loan Programs Office to accelerate deployment of nuclear energy.

Next to the National Nuclear Security Administration, the second-largest budget request is for environmental management ($8.09 billion) and the Office of Science ($7.09 billion), with nuclear energy receiving $1.37 billion. Less than $1 billion apiece is proposed for programs involving energy efficiency and renewable energy, fossil energy, and other areas. The Office of Fossil Energy would get $595 million.

The DOE budget traditionally gets submitted by the President in May of each year, including detailed proposals, at which point the House and Senate Budget Committees consider the request and pass a budget resolution known as a non-binding framework. Total discretionary spending is then allocated and divided among 12 appropriations committees and energy and water development subcommittees.

The House Energy and Water subcommittee recently announced a delay in its scheduled July mark-up of the budget request. After approval in subcommittee the full appropriations committees vote, disagreements in the House and Senate versions are reconciled in Congress before being submitted to the President for signature.

During Wright’s June 18 testimony on Capitol Hill, Rep. Scott Peters (D-CA) questioned him on the agency’s plans to accelerate the construction of electric transmission lines. Peters noted that previous “national-interest” transmission corridors with enhanced federal authority to site lines that were created in 2005, similar to those funded in the Inflation Reduction Act of 2021, have never been utilized. He also asked Wright if he would work with the Federal Energy Regulatory Commission to get permitting parity between natural gas lines and electric transmission lines.

“Absolutely. The United States needs to build more energy infrastructure of all kinds, and certainly including transmission lines,” Wright replied.

Peters also mentioned reliability issues such as North American Electric Reliability Corporation reports that 35 GW of transmission transfer capability among regions would lower costs and make the system more resilient to extreme weather.

“I agree with my colleagues that we are walking into an affordability and reliability crisis,” Peters said.

Wright said there is no doubt that the country would benefit from more transmission, and that National Environmental Policy Act environmental protests have lengthened the permitting process. The need for dynamic ratings allowing more efficient use of lines and wrong incentives in the regulatory environment are other issues, he said.

Rep. Robert Menendez (D-N.J.) asked Wright if he supported an “all of the above” energy strategy and Wright said he did not and that he would not support energy resources that are less reliable and more expensive. He added that he has worked in the solar, geothermal, and nuclear fields.

When Menendez asked if “increased production of all types of energy, including renewables, bring down costs for energy,” Wright replied “absolutely not. That is not at all how the marketplace has worked.”

“’Absolutely not,’” Menendez said, quoting Wright, “I’m going to make a note of that.”

Other discussion was declining costs in Texas with the addition of renewables, with Menendez questioning Wright on whether he would acknowledge that prices had come down because of the addition of renewables to the Texas grid. Wright said he didn’t think there was a correlation between the addition of renewables and lower energy prices.

Wright also said that large amounts of renewables had been added there because “you can build things in Texas.”

In conjunction with the budget request, DOE issued an Appropriations Detail including each allocation program and office, allowing comparison of enacted levels for FY 2024–25 versus FY 2026. This includes entities such as the Western Area Power Administration, Southeastern Power Administration, and Southwestern Power Administration.

The Atmospheric Protection Program was eliminated through a $100-million funding reduction, with the program described as “an overreach of Government authority that imposes unnecessary and radical climate change regulations on businesses and stifles economic growth. By prioritizing climate change over job creation and energy independence, the program has burdened American industries with costly mandates, ultimately hurting consumers and taxpayers,” according to DOE documents.

Other funding was removed for certain renewable energy, electric vehicle and battery manufacturers; the Advanced Research Project Agency Energy (ARPA-E) program; “non-essential” nuclear research; and climate and social programs. Other funding went towards securing access to critical energy and mineral resources.

ARPA-E will be refocused on high-risk, high-reward energy research focused on technologies that increase energy reliability, according to Wright.

Also proposed in the budget is a 157-percent cut in Infrastructure Investment and Jobs Act (IIJA) Funding for energy. Total cancellation of IIJA funds is proposed at $15.3 billion along with a $2.6 billion reduction in Energy Efficiency and Renewable Energy program funding, which would halt investment in “Green New Deal” programs. DOE also issued Budget justification for the FY 2026 request.

At the hearing, Wright described AI as “the next Manhattan Project,” and that it is essential that the U.S. lead in its development. DOE has a “significant role to play” in AI deployment for scientific discovery, energy innovation, and national security. He said the U.S. should not overburden AI developers with restrictions and regulations, including those needed for data centers.

“We need all energy sources to power the global AI race and meet growing data centers energy demand, including natural gas, nuclear, geothermal, and coal, while also ensuring the security of the grid,” Wright said.

Other topics discussed at the hearing included energy costs, cybersecurity, generation retirements, and grid reliability.

Wright had previously ordered the refilling of the Strategic Petroleum Reserve and its infrastructure, including plans to safeguard the reserve.

The final submitted budget bill must be signed by the President on or before the beginning of the fiscal year, which is Oct. 1.

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