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December 16, 2025

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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. 

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Trump Executive Order Targets Renewable Energy Tax Credits

President Donald Trump issued an executive order July 7 targeting renewable energy tax credits as strongly as possible under the One Big Beautiful Bill Act. 

The law accelerates to 2026 the phaseout of the large tax credits created by the Inflation Reduction Act of 2022 in line with Trump’s strong opposition to renewables and support for fossil fuel. He signed it at a July 4 ceremony. (See related story, Trump Signs Big Beautiful Bill into Law on Independence Day.) 

The order, “Ending Market Distorting Subsidies for Unreliable, Foreign-controlled Energy Sources,” directs Treasury Secretary Scott Bessent to determine and then take all actions needed to terminate 45Y and 48E clean energy production and tax credits for wind and solar facilities. 

The OBBBA specifies construction start dates and safe-harbor provisions for the remaining period of eligibility for these tax credits, and Trump’s order directs that these rules not be circumvented by eligibility manipulation. 

Trump also directed prompt implementation of the bill’s enhanced restrictions on foreign entities of concern. And he directed Interior Secretary Doug Burgum to look for and eliminate any codified forms of preferential treatment for wind and solar over dispatchable energy sources. 

The reasons stated in a White House fact sheet are familiar speaking points for Trump and some of his Republican allies: 

    • Wind and solar are unreliable, denigrate the natural beauty of the American landscape and displace dispatchable energy, compromising the grid.
    • Reliance on green subsidies threatens national security by making the U.S. dependent on supply chains controlled by foreign adversaries. 
    • Ending these massive taxpayer subsidies is vital to energy dominance, national security, economic growth and the fiscal health of the country. 

Trump specifies that his order be implemented consistent with applicable laws. However, there may be some room for interpretation of the energy-related provisions of the 870-page OBBBA. 

Investment analysis firm Jefferies in a note to clients earlier July 7 said the House Freedom Caucus sought a strict interpretation by the administration of the “beginning of construction” provisions during negotiations as a condition for support. It said the concern now is whether the Trump administration will attempt to “change the goal posts” for these safe harbor provisions. 

The order directs the Interior and Treasury departments to report back within 45 days on their findings and the actions they have taken or planned. 

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NYISO Management Committee Briefs: June 30, 2025

The NYISO Management Committee passed two motions at its brief June 30 meeting, unanimously recommending that the Board of Directors approve them.

The committee recommended revisions to the ISO’s Joint Operating Agreement with PJM for the upcoming activation of a phase angle regulator at a new 345-kV Dover substation for approval. The project is part of the AC Transmission Segment B public policy transmission project, which is intended to reduce congestion between the Capital District and downstate. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The committee also passed revisions to the NYISO tariff to implement transmission owners’ right of first refusal over upgrades in the reliability and economic planning processes. (See “Committees Approve Updates to ROFR Implementation,” NYISO BIC & OC Briefs: Week of June 16, 2025.)

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DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030

The U.S. Department of Energy released a report July 7 saying that retirements and delays in new firm capacity “will lead to a surge in power outages and a growing mismatch between electricity demand and supply,” especially from growth driven by data centers. 

The Report on Evaluating U.S. Grid Reliability and Security responds to President Trump’s executive order from April, which DOE used to keep open power plants in MISO and PJM that were set to retire in May. Trump’s order directed DOE to come up with a uniform method of studying resource adequacy. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

“This report affirms what we already know: The United States cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” Energy Secretary Chris Wright said in a statement. “In the coming years, America’s reindustrialization and the AI race will require a significantly larger supply of around-the-clock, reliable and uninterrupted power. 

The report argues that “absent decisive intervention,” the grid will be unable to meet projected demand for manufacturing, re-industrialization and data centers, which make adversary nations control the future development of artificial intelligence, thus jeopardizing economic and national security. 

The status quo of additional generator retirements and “less dependable replacement generation” is not consistent with winning the AI race or maintaining reliability, the report said. “Absent intervention, it is impossible for the nation’s bulk power system to meet the AI growth requirements while maintaining a reliable power grid and keeping energy costs low for our citizens.” 

The report estimates an additional 104 GW are set for retirement by 2030, which is planned to be replaced by 209 GW, though only 22 GW of that is from “baseload sources.” Retirements and load growth combined could lead to 100 times greater risk in power outages by the end of the decade, the report said. 

“Antiquated approaches to evaluating resource adequacy do not sufficiently account for the realities of planning and operating modern power grids,” the report said. “At a minimum, modern methods of evaluating resource adequacy need to incorporate frequency, magnitude and duration of power outages; move beyond exclusively analyzing peak load time periods; and develop integrated models to enable proper analysis of increasing reliance on neighboring grids.” 

The report said it used a model based on NERC’s Interregional Transfer Capability Study, which uses time-correlated generation and outages based on historical data. It looked at a range of projections for data center demand by 2030 from major projects and picked a midpoint of 50 GW, allocating it regionally based on a forecast from Standard & Poor’s. 

The report includes several models, including one with the 104 GW of retirements that are in line with NERC and Energy Information Administration projections, another without power plant closures and a scenario with replacement capacity. 

The only regions that did not fail to meet reliability thresholds in the power plant retirement category were ISO-NE and NYISO, which are not expected to see additional data center growth. But every other region saw higher risks of outages in the closed power plant case. Even if all the power plants were to stay open, the report still found shortfalls in PJM, SPP and the Southeastern Electric Reliability Council. 

The report found that at least 23 GW of new “perfect capacity” is needed to meet future demand, especially in ERCOT and PJM (particularly in Virginia and Maryland). 

The report calculates unserved energy (USE) for different regions of the country based on its forecast supply and demand and found troublingly high levels of the metric in some regions for 2030. 

“It should be noted that USE is not an indication that reliability coordinators would allow this level of load growth to jeopardize the reliability of the system,” the report said. “Rather, it represents the unrealizable AI and data center load growth under the given assumptions for generator build outs by 2030, generator retirements by 2030, reserve requirements and potential load growth. These numbers are used as indicators to determine where it may be beneficial to encourage increased generation and transmission capacity to meet an expected need.” 

The report does not use common probabilistic measurements of resource, such as expected unserved energy (EUE) or loss of load expectation (LOLE), instead using deterministic equivalents. 

The report was released midafternoon July 7, so most people had limited time to review it. Advanced Energy United Managing Director Caitlin Marquis said it appears to exaggerate the risk of blackouts and undervalues the reliability contributions of wind, solar and battery storage. 

“We are working quickly to dig into the numbers to unpack how DOE reached its conclusions, but it’s troubling that the report was not subject to public input and scrutiny, especially since the executive order that mandated it calls for it to be used to identify power plants that should be retained for reliability,” Marquis said in a statement. “If the analysis is overly pessimistic about advanced energy technologies and the future of the grid, consumers will end up paying too much for resources we no longer need.” 

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NYISO Proposes ICAP Changes for New Entry Ahead of CHPE

NYISO on July 2 released its proposed changes to certain capacity market parameters to accommodate the Champlain Hudson Power Express transmission project, as well as facilitate the new entry of resources.

The changes, presented to the Installed Capacity Working Group, would see NYISO developing two sets of market parameters for capability years where “triggering resources” did not enter the market by May, the first month of the ISO’s capability year.

This would mean that NYISO would use an alternative set of market parameters as the foundation of the market until the resource begins participating. The ISO would run two installed reserve margin (IRM) studies: one assuming the new resource (in this case CHPE) is in service, and one assuming it is not. This would create two sets of transmission security limit (TSL) floors, locational capacity requirements, capacity accreditation factors, system translation factors, unforced capacity demand curve parameters and load-serving entity minimum capacity requirements.

CHPE is a 1,250-MW HVDC line that will run between Quebec and New York City and is expected to go into service in 2026 — but the exact date is unknown. NYISO is keeping an eye on its progress, but it is worried it will be mistimed with the beginning of the capability year. Most of the ICAP market is predicated on annual inputs, with limited seasonality. CHPE’s entry would have major implications for the reliability parameters in the New York City zone.

While NYISO does not anticipate CHPE to shift the IRM, it does anticipate the TSL floor to increase by about 4%, which would impact “downstream” parameters.

NYISO is also proposing that notice requirements for new capacity resources be changed so they must achieve commercial operation prior to notifying the ISO that they intend to participate in the market. The ISO must receive the notification by the first business day of the month before the month the resource wants to qualify for participation. This would only apply to resources whose entry would change contingencies evaluating the transfer capability into a zone.

Stakeholders questioned the rigidity of the timing NYISO laid out, saying that it could possibly create a situation where the market parameters were acting under the assumption that a new resource was not participating when it was.

“If commercial operations start during the middle of June, that means that the resource wouldn’t be able to provide capacity until September,” one stakeholder said. “I’m having trouble understanding why you think this is an improvement.”

There was also some back and forth with Zach Smith, senior manager of capacity and resource integration for NYISO, about why changing the ICAP market parameters could not be moved more swiftly. Smith said that he would look into whether it was possible to increase the flexibility of the proposal.

Another stakeholder asked NYISO to make the forecasted commercial operation dates of resources like CHPE available to the market so they could plan for the shift in market parameters.