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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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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: 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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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: 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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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: 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

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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: 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 

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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: 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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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: July 9, 2025

By: Concentric Staff Writer

Key takeaways:

• U.S reliability officials expect adequate energy supply this summer, but there are areas of concern in the mid-continent and Texas, especially if there is extreme heat.
• Challenges to the grid include generation retirements, an influx of more variable solar and wind generation and problems with inverter-based renewable energy resources.
• A surge in battery storage, especially in California and Texas, will help address demand in evening hours and help to store solar and wind energy when it is available.
• California officials expect adequate supply this summer, citing the addition of 20 GW of new supply since 2021 and more than 10 GW of energy storage.

U.S. electricity grid planners are preparing for summer demand, with concerns in many areas about demand growth and generation retirements that could create tight supply conditions.

The North American Electric Reliability Corporation’s (NERC) 2025 Summer Reliability Assessment projects an aggregated peak demand increase across all 23 of its assessment areas. Sources include new data centers, electrification of transportation and other infrastructure, as well as increased industrial activity.

All areas in NERC’s territory, which includes the U.S. and parts of Canada, are expected to have adequate resources under normal conditions, but if there is above-normal demand, periods with low wind and solar generation and widespread heat could present a problem, NERC said. Growth in renewable resources is being offset by generation retirements, and those new resources introduce more complexity and energy limitations, the organization said.

The summer risk profile is shaped by rising demand, growth in generation, and changes in the resources mix, NERC said in the assessment. Peak demand has increased by 10 GW across all assessment areas in the new analysis, more than double that which occurred between the summers of 2023 and 2024, while 30 GW of new solar and 13 GW of new energy storage have been added. New wind resources will provide 5 GW during on-peak times, the analysis says, but in general the generation fleet has less flexibility and more variability.

“While the grid faces several challenges this summer, areas such as Texas, California, and across the U.S. West have seen an influx of battery energy storage systems in recent years, which is reducing energy shortfalls associated with supply variability and demand spikes,” Mark Olson, NERC’s manager of reliability assessments, said in a May 14 news release. “This is improving system operators’ ability to manage energy risks during challenging summer periods.”

Areas of concern include the Midcontinent Independent System Operator’s (MISO) 15-state territory in the middle of the country, where a decline in generation capacity and firm imports has led to worries about shortfalls if demand grows too high. In the Southwest Power Pool—which covers all or part of 14 states—wide areas with increased heat could leave grid operators with insufficient resources flexible enough to counter the variability of wind, NERC said.

There are also concerns in the Electricity Coordinating Council of Texas due to an influx of solar energy that could leave the grid short when the sun goes down.

In New England, reserve capacity has declined since last summer due to the loss of resources and higher demand, which increases reliance on neighboring regions when demand is high.

NERC, over the past couple of years, has also focused on problems created on the grid from inverter-based resources (IBR) such as wind and solar, which led to the creation of inverter-based reliability standards. The Federal Energy Regulatory Commission (FERC) in February 2020 formally approved three key NERC reliability standards for inverter-based resources, including disturbance monitoring and reporting, general disturbance monitoring and reporting, and mitigation of unexpected IBR events.

“As solar, wind, and battery resources continue to be the predominant types of resources being added to the bulk power system, it is imperative for industry, vendors, and manufacturers to take the recommended steps for system modeling and study practices, and IBR performance,” John Moura, NERC’s director of Reliability Assessments and Performance Analysis, said.

In the Western Electricity Coordinating Council-Mexico area, a 3.7 GW peak demand will be met by a 5.6 GW resource mix that is primarily natural gas (4.2 GW), with some geothermal, solar, wind, and oil-fired generation. The 14% reserve margin in the WECC-Mexico region exceeds the margin needed for reliability (10%) calculated by WECC, NERC said.

“For the upcoming summer, NERC assesses that historically average generator outage rates for peak demand periods can cause a supply shortfall within the WECC-Mexico assessment area and trigger the need for non-firm resources from neighboring areas,” NERC said in the document.

Above-average summer temperatures are expected across much of North America, along with below-average precipitation in the Northwest and Midwest, the organization said. Temperature is the primary driver of demand and can also contribute to forced generation outages for generation and other equipment on the bulk electric system.

Last summer, temperatures were not as high as summer 2023 but still ranked among the top four hottest summers on record, with record-setting highs in many areas. But there were few energy emergency alerts issued between June and September 2024, and no supply disruptions resulting from balancing authorities, transmission operators, and reliability coordinators. There were, however, a number of operational mitigations and demand-side measures that were employed. Natural gas-fired generation also broke records, illustrating its role in meeting demand, NERC said.

Load growth is also a significant factor, as 15 of 23 assessment areas are expecting an increase in peak demand from last summer. A 10 GW projected increase in peak demand is more than double the increase between 2023–2024, with one of the largest increases in the U.S. West, where about 5% load growth is forecast. In the West, heat is a major reliability concern among balancing areas in WECC, exacerbated by predictions of lower-than-normal precipitation. Natural gas plants and demand-side management “could be important” in offsetting lower-than-expected hydro generation.

NERC’s southeast region is also projecting a sizable increase in demand, expected to rise more than 2% from last year. This is due to economic growth as well as increased industrial and data center growth.

Another worry is the aging of generation facilities, as forced outage rates for conventional generators, as well as wind, have been increasing in recent years. Some generators have been in operation for about 60 years, which is a particular concern in the Southeast. Planning needs to consider increased forced outage rates for these resources, NERC said, and older generators can also require overhauls and other refurbishments that take them out of service.

“System operators face increasing risk of resource shortfalls and operating challenges caused by forced generator outages, especially during periods of high demand or when relatively few conventional resources are dispatched to serve load,” NERC said.

Battery storage is helping address energy shortfall risks that can arise from the variability of intermittent renewable resources and new demand peaks, with special improvement in Texas, California, and in the U.S. West. Batteries can not only help meet the evening generation ramp when the sun goes down and solar wanes but also help meet peak demand, along with natural gas-fired plants.

While NERC is working on long-term solutions to the problem of inverter-based resources like wind and solar tripping offline, grid operators need to remain vigilant about these resources. NERC in April published its “Aggregated Report on NERC Level 2 Recommendation to Industry: Findings from Inverter-Based Resource Model Quality Deficiencies Alert.” This study revealed that many grid operators do not have the data they need, interconnection process requirements for inverter-based resources are inadequate, and two-thirds of the protection settings used by grid operators on these resources are not set to provide the maximum capability. This creates an artificial limitation of these resources’ ability to “ride-through” system disturbances.

Gas-electric system coordination remains an issue, and operators of natural gas-fired power plants should maintain lines of communication with natural gas pipeline operators to ensure grid reliability, FERC said. Natural gas power plants broke records last summer, with a monthly peak average in July of 208 TWh of output. The U.S. Energy Information Administration projects that rising demand for natural gas exports this year as liquified natural gas production increases, combined with lower field production levels could create tightening on natural gas supplies relative to last summer, NERC said. With increasing load, natural gas generation could set another record this summer, the organization said.

At the federal level, U.S. Energy Secretary Chris Wright issued an emergency order May 23 that the White House said is intended to minimize the risk of blackouts and address “critical grid security” issues in the Midwestern region of the country amid expected high electricity demand.

The order directs the MISO to work with Consumers Energy to ensure the 1,560 MW J.H. Howard Campbell coal-fired power plant in West Olive, Michigan remains operating and addresses any energy shortfalls. The plant was scheduled to shut down on May 31, 15 years before its scheduled design life, DOE said.

“Today’s emergency order ensures that Michiganders and the greater Midwest region do not lose critical power generation capability as summer begins and electricity demand regularly reach high levels,” Wright said in a written statement.

The emergency order issued by DOE’s Office of Cybersecurity, Energy Security, and Emergency Response is authorized by the Federal Power Act and is in accordance with President Trump’s Executive Order “Declaring a National Energy Emergency,” Wright’s office said.

The DOE release mentioned NERC’s Summer Reliability Assessment, pointing out that the organization said MISO’s region is at an elevated risk of electric supply problems.

California officials in May also held a workshop on summer reliability, saying that the addition of resources should ensure adequate supplies, although widespread extreme heat events could cause problems. More than 20 GW of new supply has been added since 2021, including 13 GW of battery energy storage that will help supply the grid in the evening hours.

The California Legislature also created a Strategic Reliability Reserve with 4 GW of back-up resources, including virtual power plants and demand response. The state also extended operations at the Diablo Canyon nuclear power plant and state agencies are better coordinating on energy planning, including a memorandum of understanding between the CAISO, the California Public Utilities Commission, and the California Energy Commission.

An extended day-ahead market due to launch in May 2026 will also help resource-sharing, while the Western Energy Imbalance Market has led to better reliability and billions of dollars in benefits to its participants since 2014.

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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: May 29, 2025

By Concentric Staff Writer

Key takeaways:

• The U.S. Department of Energy stayed 2024 rules requiring new federal buildings or those undergoing certain renovations to reduce usage of fossil fuels.
• Energy Secretary Chris Wright said the stay will allow federal buildings to utilize the most efficient energy resources that are available.
• Under the stay, federal buildings are not currently required to comply with the rules created under the administration of President Joe Biden.

The U.S. Department of Energy (DOE) on April 30 stayed for one year compliance deadlines for rules requiring the federal government to reduce fossil fuel consumption in new buildings or those undergoing certain renovations.

DOE announced the stay May 5, saying it will review deadlines for “newly adopted provisions regarding Clean Energy for New Federal Buildings and Major Renovations of Federal Buildings.” Effective May 5, compliance deadlines in the Code of Federal Regulations (CFR) for 10 CFR part 433, subpart B, and 10 CFR part 435, subpart B are stayed until May 5, 2026.

“Under President Trump’s leadership, the Department of Energy is embracing a strategy of energy addition – leveraging all sources that are affordable, reliable and secure. This pause will ensure that our federal buildings are able to utilize the most efficient power available, lowering costs and reducing regulatory overreach,” U.S. Secretary of Energy Chris Wright said in a written statement.

DOE issued the regulations on May 1, 2024 under President Joe Biden. The regulations require new buildings undergoing major renovations to be designed in a way that reduces usage of fossil fuels and provides a process for federal agencies to petition for the requirements to be adjusted downward if applicable. The final rule, which applied the standards to certain renovations or new buildings for which construction began after May 1, 2025, became effective July 15, 2024.

The rules apply to construction and major renovation of federal buildings, including commercial buildings, multi-family high-rise residential buildings, and low-rise residential buildings. They require reductions in the usage of fossil fuels, including coal, petroleum, natural gas, oil shales, bitumens, tar sands, and heavy oils.

President Donald Trump announced new energy goals for the federal government shortly after DOE published an implementation guideline document and a petition template, the agency said in a Federal Register notice.

“DOE is currently reviewing the recent implementation guidance and the template for petitions for downward adjustments to ensure that they are consistent with the policies of the current Administration,” DOE said. “To avoid regulatory burdens that would result if Federal agencies adhered to these guidance documents, DOE will not process petitions for downward adjustment during its review of the implementation guidance documents.”

Because of the stay, federal agencies are not currently required to comply with the standards, DOE said.

The rules had applied to two subsets of federal buildings: any federal building that is new or undergoing major renovations that is a public building if a total expenditure in excess of $1.5 million is required to construct, alter, or acquire the public building; and those that are not public buildings and for which the construction cost or major renovation cost is at least $2.5 million, in 2007 dollars, adjusted for inflation. They required that buildings be designed so that a building’s fossil fuel consumption be reduced as compared to a similar building as of fiscal year 2003, as measured by the Commercial Buildings Energy Consumption Survey or Residential Energy Consumption Survey.

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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.

 

 

 

Key takeaways: 

• President Donald Trump issued a series of executive orders aimed at bolstering the U.S. domestic coal industry. 

• Among these efforts are boosting the mining of coal, using it more for the generation of electricity, and increasing exports. 

• Many of Trump’s orders involve unraveling the priorities of former President Joe Biden regarding fossil fuels. 

• Trump is realigning the priorities of federal energy agencies to promote more usage of coal, drawing fire from environmental groups. 

President Donald Trump is set on revitalizing the nation’s coal industry, issuing a series of executive orders to stimulate coal mining, increase coal exports, and encourage usage of the resource to power artificial intelligence, and other sources of rising demand for electricity. 

Among the efforts is Trump’s April 8 executive order dubbed  “Reinvigorating America’s Beautiful Clean Coal Industry and Amending Executive Order 14241,” which strives to accelerate coal mining on federal lands and undertake other actions to bolster the industry. The actions drew fire from environmental groups such as the Sierra Club. 

“It is the policy of the United States that coal is essential to our national and economic security,” the White House said on its website when announcing the order. “It is a national priority to support the domestic coal industry by removing Federal regulatory barriers that undermine coal production, encouraging the utilization of coal to meet growing domestic energy demands, increasing American coal exports, and ensuring that Federal policy does not discriminate against coal production or coal-fired electricity generation.” 

The order directs the chair of Trump’s National Energy Dominance Council (NEDC), Secretary of the Interior, Doug Burgum, to designate coal as a mineral that entitles it to the benefits of a separate executive order under Trump that is intended to increase mineral production.  

The order also directs Interior Secretary Burgum, Secretary of Agriculture Brooke Rollins, and Secretary of Energy Lee Zeldin to submit a joint report to the president that identifies coal resources on federal lands, assesses impediments to mining coal, and proposes policies to address those impediments. The Energy Secretary was also directed to analyze the impact that the availability of that coal could have on electricity costs and grid reliability. 

The order says the Secretaries of State, Commerce, and Energy, and other officials involved with financing energy projects should review “their charters, regulations, guidance, policies, international agreements, analytical models and internal bureaucratic processes” to ensure they don’t discourage financing of coal mining and use of coal in electricity generation projects. 

The Secretary of State, the Secretary of Commerce, and other officials are also to take all actions necessary to identify and promote opportunities for coal and coal technologies, as well as facilitate international offtake agreements for United States coal. 

Other directives in the order are expanding the usage of categorical exclusions that could further the production and export of coal; exploring whether coal used in the production of steel meets the definition of a “critical material” under the Energy Act of 2020, and if so, placing it on the critical materials list. 

In the area of powering artificial intelligence data centers, the Secretary of the Interior, the Secretary of Commerce, and the Secretary of Energy are to identify regions where coal-powered infrastructure is available and suitable for powering data centers and high-performance computing operations and submit a report to the NEDC. 

Trump’s order, following his public pronouncements that clean-coal technology should be developed, directs the Secretary of Energy to accelerate the development of such technologies “including technologies that utilize coal and coal byproducts such as building materials, battery materials, carbon fiber, synthetic graphite, and printing materials, as well as updating coal feedstock for power generation and steelmaking.” 

Trump in another April 8 executive order, “Regulatory Relief for Certain Stationary Sources to Promote American Energy,” granted nearly 70 coal-fired power plants an extension to comply with regulations restricting emissions of chemicals such as mercury, arsenic, and benzene.  

Under Trump, the U.S. Environmental Protection Agency had previously signaled it would grant the two-year exemptions to the Mercury and Air Toxic Standard (MATS), a Biden-era regulation that drew lawsuits from 23 states. Compliance with the rule would cost the coal industry about $790 million in the decade beginning in 2028, including at least $92 million for the power sector, according to EPA. 

“President Trump is delivering on the mandate Americans gave him last November by empowering different forms of domestic energy to drive down costs, increase domestic energy supply, and improve our grid security as we pioneer the path to become the Artificial Intelligence capital of the world,” EPA Administrator Lee Zeldin said in a written statement. 

The current MATS rule has caused “significant regulatory uncertainty,” especially for coal plants in Florida, Illinois, Kentucky, Mississippi, Missouri, Montana, North Carolina, North Dakota, Pennsylvania, Texas, West Virginia, and Wyoming, EPA said. 

The Sierra Club environmental group reacted to the MATS order by Trump, saying: “By rolling back the most recent update to those protections, the administration is senselessly prioritizing outdated, polluting energy sources over the well-being of American communities—maybe your community. The exempted power plants and coal-burning units are in every region of the country—from Arizona to Pennsylvania, Wyoming to Alabama, from the Dakotas down to Texas, and in Illinois, Indiana, Missouri, and throughout the Midwest.” 

Other actions under consideration by EPA include: 

• Reconsideration of the Biden-Harris Administration’s Clean Power 2.0 regulations for power plants, which were struck down by the Supreme Court in 2022. 

• Revising Biden’s PM2.5 National Ambient Air Quality Standards regarding particulate emissions, with EPA saying it is a major obstacle to permitting new energy projects. 

• Reconsidering implementation of the Clean Air Act’s Regional Haze Program, which EPA said “has imposed significant costs on power plants and other sectors, calling into question the supply of affordable energy for American families.” 

• Advancing cooperative federalism and encouraging states to pursue oversight and permitting of coal ash within their borders.  

• Reviewing whether to extend compliance deadlines for the Legacy-Coal Combustion Residuals Management Units rule. 

• Rescinding EPA’s Guidance on the Preparation of Clean Air Act Section 179B, Demonstrations for Nonattainment Areas Affected by International Transport of Emissions, which EPA said, “made it unnecessarily difficult for states to demonstrate that foreign air pollution is harming Americans within their borders.”  

• EPA granted the Salt River Project’s Coronado Generating Station’s application for an extension of the deadline to meet requirements under the Resource Conservation and Recovery Act regulations for the management of coal ash. 

In response to Trump’s declaration of a “National Energy Emergency,” Interior Secretary Burgum implemented emergency permitting for a list of domestic energy resources, including coal. Other resources include crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, biofuels, geothermal, kinetic hydropower, and critical minerals. 

“These measures are designed to expedite the review and approval, if appropriate, of projects related to the identification, leasing, siting, production, transportation, refining, or generation of energy within the United States,” a release from the Department of the Interior said. 

The effort will reduce permitting from a multi-year process to a maximum of 28 days, according to the White House. Current delays in approvals of energy projects pose risks to the nation’s economic stability, national security, and foreign policy interests, it said. The efficiencies will use existing regulations under the National Environmental Policy Act, Endangered Species Act, and the National Historic Preservation Act.  

Under the National Environmental Policy Act, projects requiring an environmental assessment that normally take up to one year will be reviewed in about 14 days, according to the agency, while projects that require a full environmental impact statement will see timelines reduced from about two years to 28 days. 

An expedited consultation process under Section 7 of the Endangered Species Act will allow the energy-related bureaus to notify the Fish and Wildlife Service that they are using emergency procedures, and the decision whether to proceed will be left with the bureaus. Bureaus will also follow alternative procedures under the National Historic Preservation Act.  

Sources used in this article: 

• Reinvigorating America’s Beautiful Clean Coal Industry and Amending Executive Order 14241| The White House 

• Establishing the National Energy Dominance Council | The White House 

• Regulatory Relief for Certain Stationary Sources to Promote American Energy | The White House 

• Administrator Zeldin Releases Statement on POTUS’ New Energy-Related EO Signed Today | US EPA 

• Poisoning Our Future: The Trump Administration’s Dangerous Coal Exemptions | Sierra Club 

• Declaring a National Energy Emergency | The White House 

• Interior Implements Emergency Permitting Procedures to Strengthen Domestic Energy Supply | US Department of the Interior 

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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: April 25, 2025

By Concentric Staff Writer

Key takeaways:

• The Western utility landscape is set for major changes with the formation of two competing day-ahead market proposals: the California Independent System Operator’s (CAISO) extended day-ahead market (EDAM) and the Southwest Power Pool’s (SPP) Markets+.
• Markets+ recently received support from a decision by the Bonneville Power Administration to join that market, while CAISO’s EDAM moved forward with the introduction of new legislation in California to create a regional organization to manage it.
• SPP is also moving forward with an expansion of its existing regional transmission organization (RTO) from the Eastern Interconnection into the Western Interconnection, receiving approval from the Federal Energy Regulatory Commission (FERC) for what is known as RTO West.

There are major movements happening in Western wholesale energy markets, with two major competing efforts to launch a day-ahead trading market and billions of dollars in future market transactions at stake.

Across the West, the development of new day-ahead markets and the an RTO are the key factors Western utilities are monitoring  as they determine which choice in a market is the optimal one. The goals of these markets are maintaining grid reliability and controlling costs for energy consumers, more efficient dispatch of power plants, and in many areas, enabling a transition to cleaner energy resources.

A recent seismic shift in Western energy markets occurred when Bonneville Power Administration (BPA), which markets power from 31 federal hydropower dams in the Northwest and manages 15,000 miles of high-voltage transmission lines, chose a day-ahead market to join. Western market players for years had been wondering where the federally regulated entity would land, but BPA on March 5 announced a “policy direction” that it will select the SPP’s Markets+ day-ahead market over the CAISO’s EDAM.

Utilities across the West are looking for the best place to collaborate on resource trading, which becomes critical during times of grid stress. In the West, this grid stress mostly occurs in summer  evenings, when air conditioning load decrease solar output  leads to peak grid demand.

Currently, the only two major Western organized regional markets are the CAISO market and its Western Energy Imbalance Market (WEIM), a real-time trading market that has led to billions of dollars in benefits for market participants. But the real-time market lacks day-ahead scheduling of power, which provides better reliability and scheduling abilities.

SPP has its own version of a regional market similar to CAISO’s WEIM, which is known as the Western Energy Imbalance Service Market. Imbalance markets differ from day-ahead markets in that they are real-time grid balancing markets and do not include  day-ahead energy trading, which improves  reliability, economic efficiency, and transparency .

The difference between a full RTO and the current visions of Markets+ and EDAM is that in an RTO, utilities and other participating entities hand over full control of their transmission systems to the RTO, which manages the dispatch of power plants and the flow of power. This is the system that has long been in place in regional markets that have operated across the country, such as the PJM Interconnection in the Mid-Atlantic, the Midcontinent Independent System Operator, and ISO New England.

CAISO’s EDAM has been under development for years and the tariff for the day-ahead market gained approval from the Federal Energy Regulatory Commission in December 2023. Entities that have announced intentions to join EDAM include the Los Angeles Department of Water & Power (2027), the Balancing Authority of Northern California (2027), PacifiCorp (2026), and Portland General Electric (2026). According to the CAISO, entities that are “leaning towards EDAM” are Idaho Power, NV Energy, BHE Montana, and Public Service Company of New Mexico.

SPP’s Markets+ is due to begin operations in 2027. In addition to BPA, Salt River Project, Tacoma Power, Arizona Public Service, Tucson Electric Power, and UniSource Energy Services have signed on to participate in the market.

The main issue around the emerging Western markets, which would bring the West into a more advanced market design similar to other RTOs around the country, is how the market will be governed and who will oversee it. Western states and California alike want to ensure that they retain control over resource mix and other planning and environmental decisions if and when they join an organized market.

Likewise, environmental groups and trade unions in California have resisted expanding CAISO into a regional market. Unions, a powerful force in the Golden State, have also opposed the regionalization of CAISO over worries that jobs will be lost to other states. As a result, for years, legislative attempts to regionalize CAISO in the California State Legislature have failed.

The CAISO Board of Governors is appointed by the California governor. The Board of Governors oversees the CAISO wholesale market, while the WEIM is governed by the WEIM Governing Body, which has shared authority with the CAISO board on many market decisions but is nominated by a nominating committee rather than being appointed by the governor.

In an effort to absolve these concerns about governance in the EDAM, the West-Wide Governance Pathways Initiative (WWGPI) was created in October 2023. The initiative was meant to ease concerns about governance through the creation of a regional organization (not a full-blown RTO) to manage the EDAM that is governed by multiple states, not just California. WWGPI officials are hoping that the initiative will lead to a full Western RTO.

The WWGPI got a major boost in late February when legislation was introduced to move the initiative forward, Senate Bill 540. The bill would allow the WWGPI and its transmission owners to participate in energy markets governed by the regional organization created through the WWGPI process. It has gained support from electrical worker and labor unions that have traditionally opposed the expansion of CAISO.

In a press release announcing the introduction of SB 540, bill sponsor Senator Josh Becker (D-Menlo Park) said, “As we move toward achieving California’s 100% clean energy goals, we must look at all possible solutions to reduce costs, improve reliability, and cut emissions,” Becker continued, “Pathways strikes that balance by unlocking the benefits of a regional energy market while safeguarding California’s critical public policy priorities. It offers a win-win scenario for California—achieving cleaner energy, more reliable power, and real savings for ratepayers.”

Little Rock, Arkansas-based SPP, which has operated an RTO in the Eastern Interconnection, has an expansion project underway into the Western Interconnection, known as RTO West.

The Federal Energy Regulatory Commission (FERC) on March 20 approved SPP’s tariff revisions for RTO West. It is the first RTO to have a footprint in both the Western and Eastern Interconnections. The RTO expansion is part of SPP’s five-year plan to bring western entities into its markets, known as ASPIRE 2026.

“I am pleased to announce FERC’s approval of the amended RTO tariff,” SPP president and CEO Barbara Sugg said in a press release. “Expanding the RTO into the Western Interconnection is an exciting step in SPP’s growth, bringing value to new and existing members while enhancing reliability in both interconnections.”

Utilities and others that plan to participate in RTO West are Basin Electric Power Cooperative; Colorado Springs Utilities; Deseret Generation and Transmission Cooperative; Municipal Energy Agency of Nebraska; Platte River Power Authority; Tri-State Generation and Transmission Association; and three regions of the Western Area Power Administration: Colorado River Storage Project, Rocky Mountain Region, and Upper Great Plains-West.

“The Western expansion of the SPP RTO bolsters reliability and resiliency for our members as we grow and diversify our resource portfolio while reducing emissions,” Tri-State Generation and Transmission Association CEO Duane Highley said in the release. “We greatly value the full benefits of the SPP RTO, including day-ahead and ancillary services markets, efficient regional transmission planning, a common transmission tariff and participatory governance model that help us to further reduce costs for our members across the West. Prior to SPP RTO West entry, we will be making a filing with our state regulators highlighting these market benefits.”

Some Western market participants have pointed out that the creation of two large day-ahead markets—EDAM and Markets+—will create a large “seam” across the West between the two markets. Markets without seams are considered favorable because one large market allows more resource sharing and more efficient plant dispatch, which would deliver greater reliability, cost, and environmental benefits. But unless Markets+ and EDAM are merged, it appears that this seam will be taking shape in the future.

There are many moving parts in play in the two day-ahead market proposals and much work still to be done, but it is clear that major changes are in the works for Western energy markets.

Background Information:

This article drew upon reports from materials from CAISO, SPP, WWGPI, and California legislation.

Links to Cited Sources:

BPA website

SPP website

CAISO website

WEIM website

PJM web site

MISO web site

ISO New England website

EDAM website

FERC website

SPP ASPIRE website

SPP Markets+ website

WWGPI website

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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.

 

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