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December 14, 2025

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PUCO: Data Centers Must Guarantee Power Purchases from AEP Ohio

The Public Utilities Commission of Ohio has granted AEP Ohio’s request for tariffs requiring data center developers to financially guarantee they will use the electricity they are requesting. 

Customers requesting more than 25 MW of new power for data centers will have to pay for at least 85% of the energy for which they are subscribed — whether they use it or not — for eight years. A ramp-up period of up to four years will be allowed before the eight-year term. 

The July 9 PUCO ruling in 24-0508-EL-ATA is among the first attempts in the U.S. to address the high costs associated with the huge new power demands that may result from data center buildout. 

It seeks to ensure that other ratepayers are not stuck with paying for infrastructure upgrades made to accommodate demand that does not materialize as requested. 

Along with the financial guarantee mechanism, the new tariff will create a sliding scale for small and mid-sized facilities to allow for some flexibility; require data center owners to prove they are financially sound and able to meet the requirements; and impose an exit fee for projects that are canceled or fail to meet the terms of their contract. 

The state is seeing heavy interest in data center development, thanks in part to favorable policies. The Columbus area in the center of the state already has a strong concentration of these facilities. 

In March 2023, AEP placed a moratorium on data center service requests in central Ohio so it could analyze the impacts of this trend. 

In May 2024, it requested the data center-specific tariff, saying it was facing 30 GW of potential new load, some of it from sectors it considered to have elevated risk of not meeting their commitments. (See AEP Ohio Asks PUCO for Data Center-specific Tariffs.) 

Representatives of data centers and other industrial sectors criticized the tariff request as an unprecedented and potentially chilling move. On Oct. 10, 2024, they submitted a settlement proposal. 

AEP said some details in that proposal were problematic while other important details were omitted. On Oct. 23, the utility submitted its own settlement agreement, which revised or deleted some aspects of its original request. (See AEP Ohio Proposes Revised Data Center Tariff.) 

Signing on to the submission were PUCO staff, the state consumer utility advocate, an organization for large industrial ratepayers and a coalition of 54 community energy advocacy agencies. 

PUCO’s unanimous ruling adopts AEP’s settlement proposal, with some modifications to exit fees and other details. It directs AEP to file updated tariffs and lift the moratorium as soon as possible. 

“Today’s order represents a well-balanced package that safeguards non-data center customers on an industrial and residential level while establishing a dependable and reasonable environment for data centers to continue to thrive within Ohio,” PUCO Chair Jenifer French said in a news release. 

The industry membership group Data Center Coalition, which was an intervening party in the case, continues to maintain that no one industry or class of customer should be singled out for disparate rate treatment by a utility. 

“The decision is a stark departure from solutions enacted in other key data center markets and, more consequentially, is a deviation from the long-established, sound ratemaking principles that have carried both Ohio and the nation through periods of electricity demand growth and flat demand,” DCC Director of Energy Policy Lucas Fykes said in a statement. 

“The data center industry is committed to paying its full cost of service. DCC will continue to advocate for evidence-based solutions in Ohio and across the country that support data center development and advance an affordable and reliable electricity grid for all customers.” 

In a news release, AEP Ohio President Marc Reitter said the ruling would support the state’s growing tech sector and keep the industry in the U.S. while protecting other customers from shouldering the costs of providing power to it. 

“I am grateful for the collaboration of all the parties involved in this filing, which ultimately brings clarity and certainty for infrastructure planning,” he said. “We are looking forward to ending the moratorium and continuing to support development of more data centers in our service territory.” 

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U.S. Clean Energy Sector Faces Cuts and Limitations

The winners and losers in the energy sector are delineated clearly by the One Big Beautiful Bill Act engineered by President Donald Trump.

But it remains to be seen how big the losses will be for wind and solar power, and how many caveats accompany the wins scored by fossil fuels.

On July 7, three days after he signed OBBBA into law, Trump issued an executive order with strict-sounding directions for carrying out the bill’s provisions targeting wind and solar energy, with critical details to be determined in weeks and months to come.

His on-again-off-again tariff threats — not least the 50% levy on copper imports he announced July 8 — could impose significant costs on the fossil fuel industry, which OBBBA clearly was intended to benefit.

What is clear now is that development of wind and solar power — which provided 14% of utility-scale generation in the United States in 2023 and accounted for 78% of capacity additions in 2024 — will become significantly more expensive.

New projects will need to begin construction by July 5, 2026, or be placed in service by Dec. 31, 2027, to qualify for the generous investment and production tax credits of the 2022 Inflation Reduction Act — a much earlier sunset than specified by the IRA but not as fast a termination as was sought by the strongest critics.

Wind and solar developers also will need to follow complex rules pertaining to fire-walling their projects’ finances from FEOCs — foreign entities of concern, particularly in China. (Norton Rose Fulbright needed more than 3,200 words for a FEOC explainer it published July 8. The Bipartisan Policy Center needed nearly 3,000.)

Peter Fox-Penner, an energy policy and strategy expert and a principal at The Brattle Group, told RTO Insider that the energy provisions of the 800-page OBBBA are a clear and significant threat to wind and solar power development, both of which are frequent verbal targets for Trump.

“I’m struck by what a direct assault this is, in particular on wind and solar, talking about the supply side of electricity,” Fox-Penner said. Combined with measures targeting residential energy efficiency and electric vehicles, OBBBA is a major change for many aspects of the energy sector, he added, as well as for the economy, domestic manufacturing, electricity ratepayers and the environment.

Not everyone is unhappy with OBBA.

Some other emissions-free technologies — geothermal, hydropower, storage — do not face the same rapid and drastic tax credit cutbacks as wind and solar.

And the fossil fuel sector — oil, natural gas, coal — has much to smile about.

“This is the most important energy bill in a generation,” American Petroleum Institute CEO Mike Sommers said in a news release. “President Trump has delivered on his promise to unleash American energy by unlocking opportunities for investment, supporting global competitiveness and opening lease sales onshore and offshore from the Gulf of America to Alaska.”

But many entities in the renewable energy and environmental advocacy sectors are not smiling at all:

    • “A vote that will live in infamy.” — Greenpeace
    • “This stands to be the biggest job-killing bill in the history of this country.” — North America’s Building Trades Unions
    • “This bill will be a major step backwards on energy security, prices and jobs in communities across the country.” — Clean Energy Business Network
    • “Ceding the race to build the clean energy economy of tomorrow to China.” — Sierra Club
    • “The clean energy provisions in the legislation President Trump championed will prove devastating.” — Environmental Defense Fund
    • “Congress has turned its back on the very industries that are adding the majority of the new electricity generating capacity to the grid.” — Solar Energy Industries Association
    • “Whatever promises the White House may have made when twisting the arms of some House Republicans, the Treasury Department has a duty to administer the law fairly, in a way that provides certainty to the businesses relying on these tax credits.” — National Resources Defense Council

The NRDC comment pertains to Trump’s July 7 executive order, in which he orders the strictest possible enforcement of OBBBA’s provisions on construction start dates, safe harboring and FEOCs.

And it alludes to Trump’s reported promise to the House Freedom Caucus — which was unhappy with even the limited leeway being given to wind and solar — that his administration would use its executive powers to the maximum extent in limiting wind and solar subsidies.

On July 3, U.S. Rep. Ralph Norman (R-S.C.), a founding member of the caucus, explained this in a CNBC interview.

A day after Trump’s executive order, Norman posted on Facebook: “This order dismantles the green energy giveaways pushed under the Biden administration — programs that propped up costly, inconsistent sources like wind and solar while leaving taxpayers on the hook and our grid exposed to instability.”

So what will Trump do now?

His executive order was strongly worded. But he often speaks in strong terms, and he changes his stance often.

Trump has long followed what is sometimes called the Trump Uncertainty Principle, keeping everyone guessing about his strategy so they cannot counter it.

He is hardly the first president with such an approach — President Richard Nixon had the Madman Theory — but Trump has embraced it more openly than most.

For the offshore wind industry, struggling to build momentum in the United States, the uncertainty presented merely by Trump’s re-election was enough that multiple developers paused their U.S. projects.

For the established solar and onshore wind industries, OBBBA presents a more nuanced challenge, particularly with projects that are not ready to break ground and might not qualify for subsidies under terms that may be revised or re-interpreted.

Some projects will be delayed or canceled because the financial calculations on which they are based will change for the worse.

Some of the domestic manufacturing facilities that were to be a legacy of the IRA will not be built. E2 counts $15.5 billion worth of cancellations from January through May, and that is just the publicly announced cancellations.

This in turn means continued reliance on foreign manufacturing that is potentially subject to Trump’s tariffs and OBBBA’s FEOC rules.

And there’s that word again — “potentially.” The beauty of creating uncertainty through vague wording and implied threat is that general trepidation cannot be challenged in court the way a stop-work order or funding clawback could be. The profit-driven private sector is left to ponder the odds as it weighs investment decisions.

“I do think we see some of that, in the sense that the developers and the financial community that finances the developers [are] aware of the uncertainties and the unpredictability of the federal policies now,” Fox-Penner said. “And I do think that has an incremental effect on them. I can’t quantify it, but I think it is there.”

He added: “It is, I think, part of a conscious policy to try and slow [wind, solar and EV adoption] down.”

Princeton University’s ZERO Lab projects $500 billion in lost capital investments through 2035 because of OBBBA and calculates Americans’ annual energy expenditures will be $52 billion higher in 2035. It projects that clean energy production will continue to increase but will be 820 TWh lower in 2035 because of OBBBA than it would have been in mid-range projections under Biden-era policies.

Fox-Penner agrees: Solar and wind generation will continue to be built. Not as much as there would have been, he said, and not enough to meet the growing U.S. demand for power, but dozens of new gigawatts still will come online, despite OBBBA.

Wind and solar are so much faster and cheaper to build than other types of generation that they will carry on, albeit at a slower pace, he explained.

“We have done some analysis at Brattle Group and others have done some analysis that shows that wind and solar construction will be adversely affected substantially by this bill. But at the same time, it will continue at a significant pace in parts of the country even without these subsidies, because it remains the cheapest form of raw kilowatt hours,” Fox-Penner said.

In regions where electricity is expensive, wind and solar still could be economical without federal subsidies, he added.

The problem in some of those expensive electricity markets is that the cost of energy development also is expensive, and there is no quick replacement at the state or regional level for the disappearing federal tax credits.

New York is such a place — it has grand ambitions for renewable energy and is placing much of the cost of decarbonizing the grid on ratepayers who already have some of the most expensive electricity in the nation. Further subsidies would be a hard decision to make.

The New York State Energy Research and Development Authority, which helps manage the state’s clean energy transition, told RTO Insider it has not fully analyzed the impacts of OBBBA but implied that they would be considerable.

A spokesperson said: “The new law puts thousands of jobs at risk and could cut billions in funding and impact overall market momentum. This bill undermines New York state’s demonstrated leadership in advancing clean energy technologies as a part of an all-of-the-above energy strategy including investments in wind, solar, hydroelectric and nuclear power to create a clean, affordable and reliable energy grid.”

Fox-Penner said there is no quick way to refill the pipeline and meet rising demand with other technologies if solar and wind projects are cancelled.

The backlog on large gas turbine orders is several years long, and construction of new nuclear generation may not scale up before the mid-2030s. Few observers expect anything beyond delayed retirements for coal, either.

“We do not see evidence of any significant expansion in coal to date, nor do we think it makes economic or environmental sense,” Fox-Penner said.

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BPA Sued in 9th Circuit over Day-ahead Market Decision

A group of nonprofits sued the Bonneville Power Administration on July 10 in the 9th Circuit Court of Appeals over the agency’s decision to join SPP’s Markets+ instead of CAISO’s Extended Day-Ahead Market, saying the move will drive up costs and risk reliability in violation of federal statutes.

Represented by Earthjustice, the organizations asking the 9th Circuit to review and vacate BPA’s record of decision (ROD) include NW Energy Coalition, Idaho Conservation League, Montana Environmental Information Center, Oregon Citizens’ Utility Board and the Sierra Club.

The group alleges BPA rushed into its day-ahead market decision without considering the environmental impacts of its decision. The agency also now risks increasing costs for customers while ignoring its obligations to prioritize conservation and renewable power.

The group asks the court to vacate the day-ahead market decision and brings claims under the National Environmental Policy Act, the Pacific Northwest Electric Power Planning and Conservation Act, and the Administrative Procedure Act.

“Bonneville’s decision on markets will affect the transmission and generation of electric power across the West and is exactly the type of major federal action that should first consider the harms it could cause to our air quality, grid system reliability, fish and wildlife, etc.,” Jaimini Parekh, senior attorney with Earthjustice, said in a statement. “This is exactly why Congress enacted NEPA — to examine the consequences before acting. Here, however, the agency has completely ignored its obligations under federal law.”

The allegations will sound familiar to those who have followed BPA’s day-ahead market process.

In a news release, the group cites an analysis by state agencies in Washington and Oregon using BPA’s data that found the agency could have saved its customers $4.4 billion through 2035 by joining EDAM.

Those arguments follow a production cost study by Energy and Environmental Economics (E3) commissioned by BPA in 2024 that showed participation in EDAM could deliver the agency up to $106 million in greater benefits than Markets+. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)

Proponents of EDAM have pointed to the E3 study and another by The Brattle Group — not commissioned by BPA — that found by 2032, the agency could earn $65 million in benefits from participating in EDAM versus an $83 million net loss in Markets+. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

The suit argues that because EDAM provides a larger market footprint, BPA’s customers will miss out on significant cost savings, improved energy reliability and greater access to clean energy resources. EDAM also is “more geographically contiguous, its market participants include more of Bonneville’s historic trading partners and, consequently, the transmission system is better developed than is the case for Markets+,” the group claims.

“Moreover, Bonneville’s day-ahead market decision will likely require regional electricity providers to construct additional power generation facilities and/or increase operation of existing facilities, including natural gas, and coal plants, as a consequence of Bonneville’s participation in the smaller and less efficient, less diverse Markets+,” the suit states.

By joining Markets+, BPA also is leaving CAISO’s Western Energy Imbalance Market (WEIM) and will lose the benefits of participating in that real-time market, the organizations say.

Meanwhile, BPA has argued consistently its day-ahead markets process has been conducted with significant stakeholder input, noting in its final market decision issued in May that other electric utilities that have taken steps to join either Markets+ or EDAM have done so “without public process or transparency.” (See BPA Chooses Markets+ over EDAM.)

As for the production cost studies, the agency has contended those failed to factor in other key issues, like governance. BPA says the SPP market’s governance structure is “superior” to that of EDAM, despite ongoing efforts by the West-Wide Governance Pathways Initiative to relax the state of California’s oversight for CAISO’s EDAM and WEIM.

Still, the plaintiffs in the underlying suit claim BPA has prioritized governance over other obligations the agency is required to consider under law, such as protecting wildlife and promoting renewable energy.

The organizations also bring up the seams likely to arise after the launch of the two separate day-ahead markets, claiming BPA is contributing to the creation of artificial barriers to trade that will require complex negotiations between parties to ensure effective trade can continue.

However, BPA staff have noted throughout various public meetings that the agency is not solely responsible for creating seams and already manages a non-contiguous balancing authority area that spans six states that is adjacent to 18 other BAAs. BPA staff also noted the agency has more than 75 years of experience managing operations across seams, while acknowledging that day-ahead markets will add a new layer of complexity.

Reaction was swift:

“BPA’s decision to join Markets+ is inconsistent with its responsibility to maximize customer benefits in accordance with sound business principles,” said a statement released by Seattle City Light and attributed to Dawn Lindell, CEO and general manager. “Seattle City Light is deeply disappointed in the agency’s decision. BPA’s own record and analysis shows that Markets+ will increase costs for BPA and its customers. At a time when City Light and other utilities throughout the region are working to contain rising costs to meet growing energy needs, BPA’s disregard for the economic impacts associated with its day-ahead market decision is alarming. Our ratepayers will bear the burden of this decision as it increases energy costs $20 million to $40 million every year.”

When asked for a response, BPA said it doesn’t comment on active litigation.

SPP released a statement from Carrie Simpson, vice president of markets: “SPP is aware that a legal challenge has been filed regarding Bonneville Power Administration’s decision to participate in Markets+. We remain confident in the integrity of BPA’s decision-making process but respect the right of all stakeholders to have their concerns heard, and we trust the judicial process to appropriately consider the issues raised. We stand committed to working with BPA and others across the West to deliver reliable, efficient, and transparent market solutions that benefit the entire region.”

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Stakeholders Mixed on Massachusetts Energy Affordability Bill

At a pair of recent events, clean energy advocates and a range of stakeholder groups expressed support for a sweeping energy bill introduced by Massachusetts Gov. Maura Healey while offering suggestions for avoiding “unintended consequences.”

The legislation is intended to provide immediate and long-term rate relief in the wake of high winter energy prices and amid concerns about high costs associated with the clean energy transition.

“Energy advocates have embraced many of the proposals in this bill, but as with any major piece of legislation, concerns have also surfaced about some of the particular provisions,” Tim Snyder of the Alliance for Climate Transition, a clean energy trade group, said during a webinar held by Advanced Energy United on July 8.

Snyder praised the Healey administration for taking a comprehensive and collaborative approach to addressing energy affordability in the bill and for being receptive to input and concerns.

“As the federal government guts financial support for renewable energy, it is essential that places like Massachusetts continue to set policy in a way that ensures the continued viability of the energy transition,” Snyder added.

Michael Judge, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs (EEA), said the administration has “generally received a pretty positive reaction to the overall thrust and direction of the bill.” He said the bill is a “starting point” for discussions, noting it has a long way to go in the legislative process.

“We want to engage with people and get this right, and so, where there are opportunities to make some adjustments, let’s talk through that,” Judge said.

The bill includes multiple policy changes, including an overhaul of clean energy procurements, authorization of new financing mechanisms for infrastructure investments and electrification upgrades, a reduction in net metering credits for public net metering facilities and the phaseout of the state’s Alternative Portfolio Standard (APS). The administration has estimated the legislation will save ratepayers in the state more than $10 billion over the next decade. (See Mass. Gov. Healey Introduces Energy Affordability Bill.)

Some of the most vocal concerns about the bill have come from the solar industry, which has opposed reducing net metering credits for projects that are already in development, along with a proposal to require all net metering projects to qualify for the state’s Solar Massachusetts Renewable Target (SMART) program.

During the webinar, Judge said the net metering changes are focused on reining in rates for public net metering facilities, which must be owned, operated or procured by a municipality or government entity. He said the changes would not affect residential, rooftop or community solar projects, which “would still receive roughly the same compensation that they receive today.”

At a lengthy legislative hearing on June 25, Valessa Souter-Kline of the Solar Energy Industries Association stressed that “all changes should be prospective to ensure that businesses and consumers who have made decisions based on what’s in place … don’t have retroactive changes.”

Jessica Robertson of New Leaf Energy said the proposed changes to net metering compensation and eligibility criteria, which would apply to projects that have not interconnected by Jan. 1, 2026, would affect those that have been stuck in the interconnection process for years.

Robertson said the company is developing two public net metering projects that submitted interconnection applications in 2018 and 2019 but “have been subject to yearslong interconnection delays.”

“Those projects finally have their interconnection agreements, but they won’t actually be interconnected until 2027 at best because of how long it takes to build those grid upgrades,” Robertson said. “Under the current bill language, these projects would have the rug pulled out from under them.”

She said retroactive changes would hurt investor confidence in the state and recommended that the changes should only apply to projects that submit their interconnection agreements after the bill was filed.

Ally Niphakis of SRECTrade said the bill’s requirement for all net metered systems to enroll in the SMART program could impose significant new costs associated with deploying the metering equipment needed to participate.

Also at the hearing, Clean Fuels Alliance America and the Massachusetts Energy Marketers Association, which represent the alternative fuels industry in the state, said the APS should not be repealed until the state implements its longstanding proposal for a clean heat standard.

“While electrification is an important pathway to reducing carbon emissions, it cannot be the only pathway,” said Stephen Dodge of Clean Fuels. “The APS program is currently the most cost-effective way to reduce carbon emissions immediately from the thermal heat sector.”

The state released a draft program framework for the CHS in 2023 and had announced plans to finalize the standard in late 2025, with the program taking effect in 2026. However, the administration has walked back this timeline; at the hearing, EEA Secretary Rebecca Tepper said there is no implementation timeline for the CHS, adding that “we continue to look at it, but right now it’s not ready.”

In contrast to the biofuels advocates, representatives of climate organizations applauded the proposal to eliminate the APS, arguing that the program, which includes support for combined heat and power systems, is not aligned with the state’s decarbonization targets.

Judge said the APS was “designed to support mostly natural gas-powered combined heat and power facilities” but has been expanded to support additional technologies, including fuel cells and heat pumps. He said recent analysis indicates the program is “not really driving a lot of new projects” and supports some projects with minimal climate benefits.

The legislation would also repeal the requirement for any new nuclear facilities in the state to be approved by a statewide ballot measure. This provision received a mixed response at the legislative hearing, with major climate groups largely refraining from weighing in on the issue.

“We want to be able to look at new nuclear technologies, particularly small modular reactors, as a solution to both our clean energy needs and energy affordability,” Judge said during the webinar. “We just see this as an unnecessary barrier to building these projects; these projects would still have to go through a very robust permitting process at the federal and state levels.”

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Report: Hydrogen Transportation Future Down Significantly in California

Hydrogen transportation is struggling to find momentum in California, with the number of fueling stations decreasing again in 2024, while fuel prices continue to increase, a state government report found. 

Hydrogen fuel prices went up from about $15/kg in 2022 to more than $35/kg in 2024. The large jump could be the result of higher natural gas prices, increasing labor and materials costs because of inflation, and reduced value of the state’s low carbon fuel standard credits, the report said. The report is published annually by the California Energy Commission and the California Air Resources Board (CARB). 

The CEC has allocated about $234 million to developing public hydrogen fueling infrastructure in the state through its Clean Transportation Program. Forecasts estimate about 20,000 fuel-cell electric vehicles (FCEV) will be on the road by 2030, down from a previous forecast of 62,600 by 2029. There currently are about 14,415 FCEVs in the state.  

California now has 62 hydrogen stations, but 20 of these are considered temporarily non-operational, leaving 42 stations open. Thirteen stations in Southern California were affected by a supply disruption and are not open to the public, the report says. 

Shell closed seven stations in 2024, which left the Sacramento Area with one open station. This station cannot handle the increased demand without requiring a “mandatory 10-minute wait time between fills to avoid equipment failure,” the report says. 

“As a result, drivers could spend hours waiting for an opportunity to refuel,” the report says.  

The number of planned new stations also is down. Equilon Enterprises, under Shell Oil Products U.S., canceled its $41 million grant agreement in 2024, which would have funded 50 new stations and one station upgrade, the report says.  

Even so, by 2030, California is projected to have 129 hydrogen stations open to the public, which could support about 195,000 FCEV — more than nine times the fueling needs of the projected FCEV population in 2030, according to the report. 

“When assuming 80% of nameplate capacity, these stations are capable of supporting nearly 156,000 FCEVs, which is more than seven times the fueling needs of the projected FCEV population in 2030,” the report says. 

The number of stations isn’t the only reason for the slow uptake in the Golden State. FCEV drivers “continue to suffer from lack of confidence in fuel availability because of stations being unavailable and unreliable,” the report says. 

From the third quarter of 2023 to the second quarter of 2024, the average availability of open retail stations was about 62%, due to maintenance, equipment failures, supply chain constraints and hydrogen supply disruption. Recent station unavailability has been caused mostly by unexpected equipment failure, spare parts shortages and hydrogen supply disruptions, the report says. 

Most of the hydrogen fueling — 64% — takes place in the Los Angeles region. About 28% occurs in the San Francisco Bay Area. Hydrogen fueling infrastructure and FCEVs are part of California’s zero-emission vehicle goals in Gov. Gavin Newsom’s Executive Order N-79-20. 

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Federalist Society, Peskoe Debate Competition in the Power Industry

The Federalist Society held a webinar July 9 looking into whether the federal government should continue to rely on wholesale electricity markets in the face of rising prices and narrowing reserve margins.

The development of markets came from the states, many of which — enabled by FERC guaranteeing open access to transmission in Order 888 after some prompting from Congress — restructured their utility industries beginning in the 1990s, recalled Harvard Law School Electricity Law Initiative Director Ari Peskoe.

States started to restructure after several bad bets by utilities, largely on nuclear power, with Peskoe highlighting a project Boston Edison invested in that never got built and led to losses that equaled the firm’s profits in its entire history.

“This would have bankrupted the utility if they had to absorb all the losses,” Peskoe said. “What often happened in these cases was that utility shareholders paid some and ratepayers paid a lot as well. … The one here in Boston was never even finished, so they got paid money for nothing. So, this is a risk allocation problem.”

Restructuring the utility removed the regulated wires firm from the generation function, though often those firms kept subsidiaries that were involved in new markets for generation.

“Now there’s a problem, though, with the development of these markets, which is that utilities controlled market access that would give them an unfair advantage in these new markets. No one’s going to invest in the market if it’s controlled by the utilities,” Peskoe said.

That brings up the issue of market power, which can be dealt with via transmission that investor-owned utilities had always used to improve their own systems’ reliability and enhance trading opportunities with their neighbors.

“Transmission is the industry’s medium of coordination that enables the industry to unlock for short-run and long-run efficiencies through trading real-time operations and joint planning,” Peskoe said. “But to be more straightforward about it, if you control transmission, you can decide who generates power, where it’s generated, the types of fuels used and where it’s delivered to.”

FERC had the authority to prevent “unduly discriminatory” transmission practices for decades, but it was not until the 1990s that it imposed open access on the industry to ensure the new competitors in the generation space, and smaller cooperatives and municipal-owned utilities that had complaints about the old system, could access the grid.

“FERC’s goal was to harness markets to generate power, and it had the idea that really to do that effectively, what you have to do is separate transmission ownership from its control,” Peskoe said. “FERC encouraged utilities to create new entities that it called independent system operators. These would be entities that would oversee and implement FERC open-access transmission rules.”

The ISOs and RTOs developed markets that the competitive suppliers could bid into and planned the transmission grid that enabled that to happen.

But markets have always had their detractors, and the Federalist Society’s John Kennerly Davis Jr., who is a former assistant attorney general in Virginia and worked for Dominion Energy, said one issue is that restructuring has just made things more complicated.

“One thing about the state-centered model was that it was a regulatory system that oversaw and held accountable a single corporation, for the provision of cost-effective, reliable electric service in the franchise service territory,” Davis said. “Now the corporate form emerged a long time ago, I think sometime in the early 1600s, and it has endured over the centuries because it’s a very powerful legal mechanism that combines efficiency with accountability.”

Accountability is a powerful concept and one that can be tricky in the restructured markets, he continued. NYISO might have knitted together seven utility systems into one grid, but its management process involves hundreds of stakeholders, and that model has been repeated around the country.

“No one entity — not a transmission utility, not a power generator, not an ancillary service provider — no single entity in this disaggregated model is responsible to provide electric service like the traditional integrated corporate utility was under the traditional model,” Davis said.

The utilities are still in charge of the distribution system, which is where most outages occur, Peskoe noted. On that level, states’ ability to hold them accountable has been untouched, he said.

“I would argue that some of the best examples of regulators actually holding utilities accountable are in the restructured states where you’ve had winter storms; for example, in my part of the country here, where there have been pretty significant punishments laid down by regulators,” Peskoe said. “So, accountability is only as good as the regulators are willing to sort of punish the utilities for poor performance.”

Davis also argued that subsidized renewables are driving down the prices for other technologies and making the grid less reliable in the process.

“You’ve got a system that is based on power supply technologies that are overly dependent on renewables, which, because of their intermittent, weather-dependent nature, don’t provide the kind of 24/7 reliability support that the customer really needs,” Davis said.

Wind and solar do present some challenges, but Peskoe argued that they were not insurmountable and cautioned against “techno-pessimism.”

“And I would say that the far bigger subsidy, again, is vertical integration, which is a much bigger intervention in the market than any tax credit,” he added.

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FERC Launches Section 206 Proceeding for Idaho Power

Idaho Power must prove it does not have unjust market power in its balancing authority area, FERC ruled July 8.

Idaho Power failed the wholesale market-share indicative screen for its balancing authority area (BAA) in three of four seasons for the December 2022 to November 2023 study period. FERC presumes the existence of horizontal market power when a seller fails a screening.

FERC said it will launch a Section 206 proceeding under the Federal Power Act “to determine whether Idaho Power’s market-based rate authority in the Idaho Power balancing authority area remains just and reasonable and to establish a refund effective date.”

On April 25, 2025, Idaho Power reported a notice of change in status to report a 230-MW increase in its generation capacity in its BAA. The filing included market power analyses for eight BAAs, including its own.

Despite the screen failure, Idaho Power argued in its filing that a price test indicates it does not have market power.

However, FERC said “we conclude that Idaho Power’s failures of the non-summer market share indicative screens provide the basis for the commission to institute the instant Section 206 proceeding.”

“As the commission has previously stated, sellers submitting evidence, such as a delivered price test, in support of a contention that they do not possess market power should not expect that the commission will postpone instituting a Section 206 investigation while it examines the supplemental information,” the order stated.

Idaho Power has 60 days to show why FERC should not revoke its market-based rate powers in its BAA. The utility also can file supplemental evidence like “historical sales and transmission data to rebut the presumption that it has the ability to exercise horizontal market power in the Idaho Power balancing authority area,” according to the order.

Alternatively, Idaho Power can file a proposal that would mitigate its market power or “inform the commission that it will adopt the commission’s default cost-based rates or propose other cost-based rates and submit cost support for such rates.”

FERC expects to issue a decision by Jan. 7, 2026.

Idaho Power is an investor-owned utility based in Boise. It serves an area of about 24,000 square miles in Idaho and Oregon and relies on hydroelectric power for much of its energy mix.

It reported that its control of generation in the Idaho Power BAA increased in May as it began service under a long-term firm power purchase tolling agreement that allows the utility to charge and discharge the output of Kuna BESS LLC’s 150-MW (600 MWh) battery energy storage system. The PPA runs through May 19, 2045.

In June, the utility’s Happy Valley BESS, an 80-MW (320 MWh) standalone BESS, started operations.

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CAISO Looks to Improve Visibility of Distributed Battery Storage

CAISO is working on an initiative to improve the visibility of distributed battery storage resources on the grid, especially for when they are needed for resource adequacy purposes.

The additional information will allow operators to see potential real-time operational limitations of the resources on the distribution system, CAISO said in a June 30 presentation.

Part of the challenge is that distributed batteries are often operated by a local utility, which might request placing certain charging and discharging restrictions on them. Sometimes that request conflicts with CAISO’s request for the same resource. When this happens, a battery resource should follow CAISO’s request, unless human safety or electric facilities would be knowingly put at risk, the ISO said in a discussion paper.

Another challenge for CAISO is figuring out how charging constraints are affecting distributed batteries during dispatch times. For example, if a storage resource is restricted from charging in the afternoon, then it might not be able to discharge to its full capacity in the evening, the paper says.

To address this problem, CAISO could identify distributed units in its master data file using a specific flag, the paper says. This approach would provide a good first step in providing needed transparency and was supported by two stakeholders in the initiative, the paper says. However, six stakeholders preferred updating CAISO’s resource modeling tools, such as its real-time telemetered capabilities, and extending the dynamic limit tool, the paper says.

In California, distributed battery storage capacity has grown from about 330 MW in 2022 to about 420 MW in 2023 and nearly 1,400 MW in 2025. It has not grown much over the past year, however: Capacity was about 1,250 MW in 2024.

As part of the same initiative, CAISO is studying the availability of mixed-fuel resources, such as solar and battery storage facilities, on the grid. Currently, the ISO is struggling to obtain accurate and reliable data from mixed-fuel resources, specifically about a resource’s high sustainable limit (HSL). The HSL is an estimate of the instantaneous generating capacity of a variable energy resource. For this problem, CAISO proposed to evaluate how HSLs are developed in its Business Practice Manuals. Doing so could improve short-term forecasts of co-located and standalone variable resources, the paper says.

Comments on the paper are due July 16.

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PJM Monitor Calls for Bidding Limits on NRG Generation, DR in LS Deal

PJM’s Independent Market Monitor told FERC on July 7 that NRG Energy’s proposed purchase of power plants and demand response from LS Power would increase structural market power in the RTO (EC25-102).

The Monitor asked for the commission to impose behavioral constraints on the proposed merger, which includes assets in other markets, though the biggest overlap is PJM. (See NRG Energy Seeks FERC Approval for LS Power Deal.)

“The transaction would increase structural market power in PJM markets,” the Monitor said. “The significant increase in the concentration of ownership of emergency and pre-emergency demand resources is especially noteworthy given the newly pivotal role of these resources and the absence of any applicable market power mitigation rules.”

DR does not have a must-offer obligation, which allows for physical withholding and no offer caps, allowing for economic withholding, according to the IMM.

“This absence of market power mitigation rules is much more significant now than ever before in the history of the PJM capacity market as a result of the fact that demand resources are included in the reserve margin for the first time ever in the 2025/2026 delivery year,” the Monitor said. “The PJM capacity market would have been short of meeting the reliability requirement in the [Base Residual Auction] for 2025/2026 but for these demand resources.”

The behavioral commitments would ensure competitive behavior on behalf of NRG and be applied uniquely to the firm’s portfolio of emergency and pre-emergency demand resources. The Monitor said the conditions were warranted because of their “extreme increase in concentration.”

The IMM listed nine commitments in its filing that NRG should follow to ensure its bids are competitive even with the higher market power once the deal closes.

    • All resources should develop cost-based offers using a fuel-cost policy that passes the IMM’s review and are limited to just $1/MWh of markup.
    • All resources should be required to refrain from using crossing price and cost-based energy market offer curves to ensure no price-based offers with high markups will be dispatched by PJM.
    • All operating parameters should be based on physical limits as defined in PJM’s tariff.
    • NRG should have to agree to only retire power plants when they become uneconomic, meaning avoided costs are expected to exceed projected revenues.
    • The company should have to bid into the capacity market at prices that do not exceed net avoidable costs to ensure that market offers stay competitive, even if PJM changes its rules.
    • It should have to bid all supply at its full installed capacity of all its cleared unforced capacity megawatts into the day-ahead and real-time markets.
    • NRG should be required to base its energy offers, including the pre-emergency and emergency DR strike price, on the documented cost of dispatch and all its capacity offers on the net avoidable cost of the resources’ participation in DR programs.
    • All emergency and pre-emergency demand resources should be offered in the capacity market following the transaction.
    • NRG should commit to not removing resources from PJM’s markets for co-location deals until final rules are developed by FERC to ensure continued competitive results in the wholesale markets.
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N.J. Mulls PJM Withdrawal amid Energy Shortfall Predictions

Anger over a recent dramatic rate hike and fears of energy shortfalls because of a predicted future rise in demand have prompted New Jersey to look anew at whether the state should consider pulling out of PJM or otherwise reorganize the relationship with the RTO. 

A bill introduced by three Assembly Democrats, A5902, would require the New Jersey Board of Public Utilities to “work in collaboration with other states to explore alternative options to PJM’s capacity auction for securing the capacity necessary for grid reliability.” 

Specifically, the states would study whether they should withdraw from PJM’s Reliability Pricing Model and develop a multistate compact to engage in the fixed resource requirement (FRR) alternative to secure electric capacity through contracts with private entities, competitive capacity auctions or some combination. 

The group also would look at whether they should “withdraw from the regional, high-voltage electric transmission grid operated or managed by PJM Interconnection.” And the group would look at the merits of creating an independent electric transmission grid or joining “an existing electric transmission grid that operates within another state or region.” 

In an unrelated move, the BPU has organized a technical conference Aug. 5 to focus on “concerns over resource adequacy.” Among the conference goals is to “evaluate alternatives to the PJM capacity market” and to “identify potential paths forward in achieving long-term resource adequacy within the state of New Jersey.”  

Protecting Ratepayers

The two initiatives spotlight a concern New Jersey has voiced or studied several times in the past decade: that it does not get the energy quantity or quality — mainly enough clean energy — it wants from its partnership with PJM. Past efforts have not resulted in significant changes, but this time the severity of the situation — dramatic electricity rate hikes and a potential future power shortage — could have an impact. 

Assemblyman Robert Karabinchak (D), a bill co-sponsor, said in a release announcing the bill’s introduction that it will “start the tough but necessary conversation about PJM’s future.” 

The RTO has “for far too long” operated in a way that “ignores the needs of the states in our region and saddles our residents with higher utility bills,” he said. “Their inability to adapt has become harmful to families and businesses across the Northeast, and it’s time we push for a system that works for us.” 

Assemblywoman Lisa Swain (D), in the same release, said it is “time we explore our options to find an energy partner that is better aligned to serve our communities.” 

“We have heard from our constituents, and we are committed to finding the most effective solution, whether or not PJM is a part of it,” she said. 

But PJM dismissed the suggestion that New Jersey would be better off if it departed from PJM. 

“New Jersey needs new electricity supply; a ‘leave PJM’ bill is not going to solve that problem,” said Jeff Shields, a spokesman for PJM. “Actually, it will make the investment climate for new supply in New Jersey far worse by creating uncertainty for private developers seeking to earn a return on their investments in New Jersey through PJM’s markets.” 

He rejected the suggestion that PJM is at fault for the rate hike, calling it a “red herring.” PJM has reformed its interconnection process and has approved 46,000 MW worth of power projects that are not getting built “due to industry challenges that have nothing to do with PJM,” Shields said. “Of these, about 1,500 MW are in New Jersey, and another 1,800 MW are in the transition queue,” he said. 

“Even if you get both of these categories to build out in full, New Jersey is still very short of creating a balanced supply portfolio,” Shields said. 

Past Studies

The legislation follows a similar study launched in March 2020 by the BPU after FERC expanded its minimum offer price rule (MOPR) to include “all resources receiving state support,” which effectively made clean energy resources more expensive in the auction, according to the order setting up the study. New Jersey considered the move a “direct attack” on the state’s clean energy programs and feared it might disrupt state efforts “to shape its electric generation” and hinder clean energy development in favor of fossil fuel generation. (See FERC Extends PJM MOPR to State Subsidies.) 

The BPU study was conceived to look at whether New Jersey could achieve its clean energy objectives “under the current resource adequacy paradigm” at PJM. If not, the order said, the study should “recommend how best to meet New Jersey’s resource adequacy needs.” 

The BPU updated that report in 2022. But friction with PJM had erupted before: Then-BPU President Joseph Fiordaliso in 2018 threatened to pull the state out of PJM over frustration at a lack of coordination between the RTO and member states.  

The recent proposals were triggered by the events that led to the 20% increase in the average electricity bill on June 1, levels that were set by the state’s basic generation services (BGS) auction in February. State officials say the hike was shaped by PJM’s capacity auction in July 2024, in which prices were 10 times higher than in the previous auction.  

PJM says the sudden hike stemmed in large part from an unforeseeable rise in demand — mainly due to heavy energy-using data centers — and a looming energy shortfall, as the rapid closure of old fossil-fuel generators outpaces the much slower introduction of new clean energy facilities. 

New Jersey officials, however, say the PJM capacity auction was flawed, with prices driven up by an inaccurate count of the impact of new clean energy sources. New Jersey Gov. Phil Murphy (D) has asked FERC to investigate “potential market manipulations” in the PJM Base Residual Auction (BRA). (See N.J. Gov. Urges FERC to Investigate PJM; Christie and Phillips Defend PJM.) 

BPU President Christine Guhl-Sadovy, in a written statement to FERC on May 28, as the agency prepared to hold a June hearing on the issues, said states like New Jersey “must be allowed to play a significantly greater role in ensuring resource adequacy at the lowest cost to ratepayers than is currently allowed by PJM.”  

“This includes being free to procure some or all of states’ capacity needs outside of PJM’s Reliability Pricing Model, commonly referred to as the PJM capacity market,” she said. Guhl-Sadovy also called for “significant reforms to PJM governance” to give states a greater role in resource adequacy planning. 

Starting Anew

Yet the previous study, completed by BPU staff and the Brattle Group, showed that changing the status quo would be far from simple. An unrelated study also concluded it could be expensive. 

“Incorporating New Jersey’s clean energy goals in the regional market is the most efficient way to provide New Jersey consumers with reliable, affordable and carbon-free electricity,” the Brattle report concluded, saying it would be “premature to consider leaving the regional market structure.” 

Project researchers studied several “resource adequacy alternatives that involved leaving the regional market and adopting a New Jersey-centric resource adequacy model under the fixed resource requirement alternative,” the report said. Under such a plan, New Jersey — and perhaps other states — would set up their own capacity auction, for developers to commit to developing future capacity, while remaining inside PJM for the energy market. 

But the report concluded the state should wait while “important market reforms are being considered at the regional and federal level that could facilitate the rapid decarbonization of the electricity sector.” The report found that customer costs under MOPR were the highest, but if it were removed, customer costs under the existing system would be cheaper than other options studied. 

However, the report also said that “New Jersey should continue to explore the option to implement a New Jersey or multistate ICCM [integrated clean capacity market] under the FRR structure.”  

The 2022 update report, largely echoing the previous report, said New Jersey could meet its “clean energy targets at substantially lower costs by participating in a regional clean energy ‘buying pool,’ such as an ICCM, to purchase clean energy attributes.” 

Development Costs

The BPU eventually did not pursue any of the discussed changes, in part because PJM largely dropped the MOPR, removing the state’s main concern. In addition, the election of President Biden created a more friendly environment to renewable energy. 

Observers of the situation said one difficulty with New Jersey departing PJM would be the sheer logistics of setting up a new system, coupled with coordination issues associated with adding other states to the mix that would be needed to make the venture viable. Another challenge would be attracting energy suppliers in an environment in which energy supply is expected to be scarce, putting New Jersey’s venture in competition with PJM’s own auction. 

Furthermore, the cost of setting up the system could be hefty. A report by the Independent Market Monitor for PJM, titled “Potential Impacts of the Creation of New Jersey FRRs” and released in May 2020, concluded that net load charges for an FRR that covered all of New Jersey would cost between $32 million and $386.4 million, depending on the way it was calculated. 

The monitor also questioned the efficiency of such a system. 

“Creation of an FRR creates market power for the small number of local generation owners from whom generation must be purchased in order to meet the reliability requirements of the FRR entities,” the report concluded, emphasizing that it is a “non-market approach” that excludes competition. “In the FRR approach, there is no PJM market monitoring of offer behavior by generation owners, there are no market rules governing offers, and there are no market rules requiring competitive behavior.” 

Given the challenges, the suggestion that the state could leave PJM may be more of a negotiating strategy. 

Alex Ambrose, a researcher for New Jersey Policy Perspective, a liberal-leaning think tank, said the main impact of the bill may be to refocus PJM. 

“What would happen with this bill is that then BPU would study it,” she said. “PJM will feel that pressure and New Jersey gains some leverage, and PJM implements the reforms that we want,” such as improved governance and greater transparency in the RTO’s decision-making, she said.  

Another possibility is that the BPU concludes that the state is better off leaving PJM, she said. 

“What will end up coming out of this bill is better governance, more supply and better market rules for New Jersey,” she said.