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January 30, 2025

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NYPA Finalizes Road Map for Renewables Development

The New York Power Authority has finalized a plan to begin executing in its expanded role as a renewable energy developer. 

NYPA said it is pursuing 37 solar and storage projects totaling 3 GW of nameplate capacity, most of them in partnership with private-sector developers. 

The final plan is noticeably smaller than the draft plan offered in October 2024, which envisioned 40 proposals rated at 3.5 GW. NYPA officials had cautioned at the time that there would be substantial attrition among that initial list of proposals, as there would be with any list of early-stage renewable energy projects. 

Public power advocates have been hoping for a 15-GW road map and have been sorely disappointed with NYPA’s much lower ambition for its first tranche. With release of the final plan, they renewed their call for the ouster of CEO Justin Driscoll. 

During a budget hearing Jan. 28, Driscoll faced some pointed questioning by legislators who also had hoped for more from NYPA, which until recently had limited itself to small solar and battery projects, often in cooperation with other entities. 

In 2023, they and like-minded legislators gave the U.S.’ largest state-owned power entity expanded development powers as private-sector efforts to decarbonize New York’s power grid were proving to be slow and expensive. 

The idea was that without a profit motive, NYPA could accomplish the task at lower cost to New Yorkers, who already pay some of the highest electricity rates in the U.S. and are looking at significant increases as aging power infrastructure is expanded or replaced. 

The move would also democratize energy, they hoped, giving the public a greater voice in how its state is powered. 

The initial interaction of this vision, the Build Public Renewables Act, never made it into law; the version that subsequently was enacted is less ambitious or more achievable, depending on one’s perspective. 

Driscoll did not bend under questioning, telling legislators that NYPA is proud of its freshman effort. Three gigawatts is only the first tranche, he said. 

“We’re going to be amending the plan that we just approved today to add additional projects within the next six months. … This is a long journey toward achieving these goals, but we think we’re playing a significant role, along with others.” 

Driscoll noted that the three projects that dropped out of the draft plan are not dead; they are just moving forward separately from NYPA. 

State Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee, asked Driscoll what NYPA needed from the legislature to help it move forward. 

The requirement that NYPA own at least 51% of joint projects has caused some setbacks, Driscoll responded. 

“We’re finding that some developers don’t want to have a minority interest with us,” he said. 

The coalition Public Power NY ripped into this idea.  

“Justin Driscoll’s suggestion to strip the public ownership requirement out of the Build Public Renewables Act shows he is unfit to serve as NYPA CEO and not accountable to New Yorkers, legislators and labor demanding NYPA build 15 GW of renewables, but instead serves the interest of private energy developers,” it said in a press release. 

Other legislators wanted to know about progress toward another mandate placed on NYPA in the same 2023 law: retirement of its 11 small natural gas power plants by 2030, if grid resource adequacy allows. 

NYPA is making progress and on schedule to meet the May 2025 deadline to report its plans, Driscoll said. It has reached the framework for a potential agreement with developers who want to convert two of the peakers into battery facilities and is in similar negotiations on three others. 

NYPA generates up to a quarter of the state’s electricity, mainly through huge hydropower projects that harness the outflow of two of the Great Lakes; it operates a third of the state’s high-voltage transmission; its pumped hydro facility is by far the largest energy storage system in New York; and it is 94 years old. 

A PPNY activist and an NYPA executive who spoke separately to NetZero Insider after release of the draft plan in October laid out a classic chicken-and-egg impasse: 

PPNY: NYPA could use its strong bond rating to boost the energy transition at a lower cost.  

NYPA: Our bond rating is strong because we operate judiciously. 

PPNY: NYPA should concentrate less on preserving its bond rating and more on preserving the planet. 

NYPA: Our ability to develop planet-saving renewables depends on our strong bond rating. 

This week’s events suggest the two sides will have to agree to disagree a while longer. 

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Overheard at USEA State of the Energy Industry Forum 2025

WASHINGTON ― The National Association of Regulatory Utility Commissioners will hold roundtables on demand growth at each of its major conferences this year, Executive Director Tony Clark said at the United States Energy Association’s State of the Energy Industry Forum on Jan. 23.

The former FERC commissioner and North Dakota regulator was asked how NARUC is addressing the challenges of data centers and demand growth. NARUC is very good at convening and educating, he answered, which is exactly what it will do on the topic beginning with the Winter Policy Summit in Washington, D.C.

Each roundtable will have “21 people, who at each of the meetings [are] going to have a deep dialogue on just these issues. … Seven state commissioners, seven folks from the utility industry and seven folks from the demand side of the equation ― hyperscalers, data centers, things like that ― [will be] encouraging this kind of dialogue so we can get to, hopefully, some of the answers.”

Todd Snitchler, CEO of the Electric Power Supply Association, pointed to the combination of different state clean energy goals and demand growth as driving market transformation.

Varying state climate goals have “challenged market operators in a way that is not something they were originally constructed to do,” Snitchler said. “So, we’re going through some growing pains in order to sort out how we deliver” reliable, affordable and increasingly clean power, he said.

The restarting of decommissioned nuclear plants ― Palisades in Michigan and Three Mile Island in Pennsylvania ― possibly to power co-located data centers “suggests that restructured markets are finding ways to deliver,” he said. “They are working to define innovative approaches in order to supply power in a way that is cost effective, and they can deploy perhaps new mechanisms in order to achieve those outcomes. That’s going to require a bit of a different approach and different thinking.”

With estimates of coming demand growth still rising, what’s needed are “rules of the road that make it clear about who pays how much [and] what is required for approvals. That will accelerate the process; that will help everyone navigate the situation in a fashion that I think is better and helps achieve the policy goals that the country has,” he said.

Clark called for federal-state cooperation to get more generation and transmission online, arguing that federal roadblocks on permitting are often the primary cause of delays, rather than state processes.

But he cautioned that simply federalizing permitting may not solve the issues. “It will actually promote longer lead times if you don’t reform the underlying problems that the federal government is having. … The federal government and states fighting over some issue rarely turns out well.”

Leveraging state resources and regulatory models must be part of the process. Clark is optimistic about working with new FERC Chair Mark Christie, also a former state regulator, who “has shown a willingness to really listen to the concerns of the states,” he said. (See President Trump Names Mark Christie as FERC Chair.)

When Nuclear?

Data centers’ voracious appetite for power is creating new momentum for nuclear energy, but questions remain about when new plants, including small modular reactors, will come online.

Maria Korsnick, CEO of the Nuclear Energy Institute, pointed to a growing industry pipeline of permitting applications at the Nuclear Regulatory Commission, including 23 for plant upgrades or license extensions.

“Just in the next few years, we expect nine site permit applications,” she said. “We expect five construction permits. We have two construction and operating permits,” along with the restarts of Palisades and Three Mile Island.

But to get new plants online, tax credits and other federal incentives for nuclear will be imperative, she said; for example, the Department of Energy’s Advanced Reactor Demonstration Program, which is providing $2.5 billion to support early deployments of SMRs.

Federal support will be critical for “early mover support” to building out critical supply chains pipelines for advanced nuclear, she said.

Arshad Mansoor, CEO of the Electric Power Research Institute, said the goal should be for nuclear to become “a catalog technology … that you can go to a catalog and buy. Gen III, Gen IV, small modular reactors … these are not catalog technologies, yet we need to deploy at least 10 of them before they become a catalog technology.”

With ongoing support from Congress and the National Laboratories, Mansoor said, next generation nuclear could go catalog in five or six years.

Andrew Holland, CEO of the Fusion Industry Association, said his members now estimate nuclear fusion plants will be putting electricity on the grid in the 2030s, “with about 85% saying in the first half” of the next decade.

Fusion ― which could produce massive amounts of power by combining, rather than splitting, atoms ― “is now moving from the place where it has that long, long horizon, to something that is indeed on the horizon and coming closer, and the reason is because we’re moving from the National Labs and the universities into the marketplace,” Holland said.

Started four years ago, the FIA has 40 members working to commercialize fusion and 100 affiliate members, representing “the whole big tent of … both supply chain and end users for fusion power,” he said. Another key sign of growth, the industry has raised more than $8 billion in private investment.

In 2023, Microsoft signed a power purchase agreement with fusion startup Helion, with a delivery date of 2028. Holland said fusion could be a comprehensive solution to a range of energy industry challenges “when we get it.” It will be always available and abundant, and he argued the U.S. has to get serious about winning the global race for it.

“Fusion should be treated just like every other emerging energy source has been treated,” he said. “That means public-private partnerships should be funded at significant levels,” similar to the ARDP.

Wildfires a ‘Societal Problem’

The closest reference to climate change came in a taped message from Pat Vincent-Collawn, interim CEO of the Edison Electric Institute. With wildfires still burning in Southern California, Vincent-Collawn acknowledged that fire threats have become “a year-round problem,” but they are “a societal problem that requires societal solutions.”

A major policy priority for EEI is the development of a comprehensive national strategy that focuses on adaptation, including “community protection, wildfire prevention, responsible investment and rapid recovery,” she said.

The Electricity You Don’t Use

Paula Glover, president of the Alliance to Save Energy, kicked off the final panel of the day by noting that no one thus far had talked about energy efficiency, which she argued should be “foundational” in discussions about demand growth.

“It almost sounds as if we assume there is nothing we can do,” and that demand will just continue to rise, Glover said. “But what really makes an impact on customers, whether they are business customers, large and small, or residential consumers, is the ability of people to use energy for whatever they need, but not as much.”

Whatever generation technology is used, efficiency should be a “first field, [so] that thing that you don’t use has far more value.”

One priority for ASE going forward is working with RTOs, such as MISO and PJM, on their implementation of FERC Order 2222, specifically as it applies to the integration of virtual power plants on the grid and measuring the value of the efficiency they can provide, Glover said.

She also believes that even as AI becomes pervasive, it will become more efficient. “So, when we’re thinking about increased generation [and] demand because of AI, we also know that 20 years from now, what AI uses today is probably going to go down because of that technology.

“And so, the argument is always, if you think about what industry can do when you’re planning, then you’re not building as much; you’re not buying as much; people aren’t using as much,” she said. “And we know it’s just going to get better, better, better as time goes on.”

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FERC Upholds $150K Penalty for Facility Misratings

A $150,000 penalty leveled by SERC Reliability and multiple other regional entities for violations of NERC’s reliability standards at several wind and solar power facilities operated by Duke Energy will stand, after FERC confirmed in a Jan. 29 filing that it would not further review a settlement between the REs and Duke (NP25-4). 

NERC filed the settlement with the commission Dec. 30, 2024, in a spreadsheet notice of penalty. The ERO also filed a separate spreadsheet NOP for violations of the Critical Infrastructure Protection standards, but information on these infringements was not disclosed for security reasons. The commission also approved the CIP violation settlements. 

Commissioner Judy Chang did not participate in FERC’s decision, according to the commission’s filing. 

The spreadsheet NOP did not identify the other REs involved in the settlement besides SERC. However, it did list the facilities where violations were found. These facilities were located in Texas, Oklahoma, North Carolina, Wyoming, California, Iowa and Kansas, suggesting that the Texas Reliability Entity, Midwest Reliability Organization and WECC could be parties to the settlement as well. SERC said in the filing that the facilities were part of an existing coordinated oversight agreement. 

All of the facilities involved were built by Duke Energy Renewables and operated by the utility until 2023, when DER was acquired by Brookfield Asset Management and rebranded Deriva Energy. Duke Energy Renewables Services continued to operate the facilities. 

According to the spreadsheet NOP, Duke informed SERC in 2023 that the solar and wind facilities were not compliant with FAC-008-5 (Facility ratings). Requirement R6 of the standard mandates that transmission owners and GOs must “have evidence to show that [their] facility ratings are consistent with the documentation for determining” those ratings.  

A total of 12 of the documented facilities had lacked accurate facility ratings since their registrations first became effective, SERC said, ranging from July 2009 to April 2023. In eight cases, the documented rating was higher than the rating of the facility’s most limiting element; the magnitude of the difference ranged from 1.23 MVA to 17.35 MVA. The other four had ratings lower than the most limiting element. 

Three more facilities had accurate ratings at the time their registrations became effective, but the facilities were rerated in February 2023 after a vendor miscalculated the capacity of the wind turbines at each site. As a consequence, the utility established new ratings that were lower than the previous ratings. These errors were corrected by June 2023. 

In addition, DERS had all of its entities perform an extent of condition review, which identified inaccurate equipment ratings at seven more solar and wind facilities. These locations “documented accurate overall facility ratings but had included several inaccurate equipment ratings for individual elements in the workpapers supporting the facility ratings,” SERC said. 

The RE determined that because of the length the inaccuracies persisted, FAC-008-5’s predecessors FAC-009-1 and FAC-008-3 were infringed as well. It attributed the root cause of the violations to a “programmatic failure resulting from deficient fleet-wide internal controls,” noting that DERS did not perform a secondary review to identify errors in the initial facility rating calculations and that “numerous errors in the initial … evaluation still occurred” despite the utility’s practice of capturing element ratings through nameplate photos. 

SERC assessed the risk posed by the infringement as “elevated” because of the widespread nature of the issues, caused by the programmatic failure. The RE observed that running in excess of the facility rating, as occurred at three facilities, could lead to damaged equipment and outages, although this did not happen in practice. Also, SERC said the incorrect ratings could lead to system instability “because planning models and system operating limits would not accurately reflect the true limits of the facility.” 

SERC and the other regions did not award mitigating credit for self-reporting because DERS submitted the reports after it was notified of an upcoming compliance audit. 

Deriva took several actions to mitigate the noncompliance in addition to updating the element and facility ratings. These include updating the NERC implementation checklist to require a walkdown to verify ratings before registration, developing a new procedure for creating and updating the facility ratings spreadsheet, training relevant staff on documentation updates and completing on-site walkdowns of all appropriate facilities to verify ratings. 

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ACEEE Report Highlights Success of ‘Next Generation’ Efficiency Policies

The American Council for an Energy-Efficient Economy released a report Jan. 29 highlighting the success of states that have adopted “energy efficiency resource standards” (EERS), which require utilities to achieve multiyear energy savings targets.

Twenty-six states and D.C. have adopted such standards. They make up about 59% of the U.S. population but 82% of the savings from utility energy efficiency programs, according to the report, “Next Generation Energy Efficiency Resource Standards Update.” EERS policies set long-term or multiyear targets for electric or natural gas savings, make the targets mandatory and include funding to meet the goals.

“On average, in 2023, utilities achieved 99% of their EERS goals, with some utilities exceeding goals and others falling a little short,” the report says. “Utilities exceeding goals were often aided by performance incentives that reward utilities for exceeding EERS minimums.”

If just savings targets are set, the tendency will be to implement low-cost programs that achieve targets for the lowest price. But other objectives, such as emissions targets or low-income requirements, can help make the programs more beneficial.

The study examined four next generation elements for EERS policies: mandatory emissions-reduction targets; electrification; minimum targets for underserved customers such as low-income households; and energy burden maximums or affordability provisions. A few states have other options, like Texas’ peak demand savings, but because they are infrequent, the study does not go into depth on them.

Instead, the study examines the programs in Illinois, Massachusetts, Michigan, Minnesota and New York, for which those next generation elements are increasing low-income and electrification activity.

“Next generation policies are also contributing to complementary policies such as new construction requirements in Massachusetts and New York, electric rate redesign efforts in Massachusetts and low-income rates in Illinois and Minnesota,” the report says. “More impacts are likely to become apparent in the next few years after new programs and policies triggered by recent legislation and commission orders take effect.”

The paper recommends that the 24 states that do not have EERS policies adopt them either through new legislation or by an order from the utility commissions. Four states — Arizona, Arkansas, North Carolina and Wisconsin — have EERS policies with no “next generation policies,” and the paper suggests adding emissions targets, electrification goals or low-income provisions.

But even the states that have EERS programs with next generation provisions, including D.C., could add ones that they lack or expand existing programs.

“States with next generation components should regularly review and refine those components, such as New York did with its 2022-2023 interim review; Massachusetts is doing with its new three-year plan covering 2025-2027; and Minnesota and Illinois have been doing with new legislation,” the report says. “These reviews should be publicized so other states can learn from them.”

Low-income requirements are the most common next generation policy, and also the only one adopted in enough states to permit analysis of their effect.

“Many EERS states encourage or require explicit programs to serve low-income customers, as these customers often live in inefficient homes and apartments but can least afford high energy bills,” the report says. “Of the 26 states plus D.C., 21 have the next generation feature of specific targets for serving low-income customers.”

Across all states, low-income program spending averaged $14, but in EERS states, the customer class got an average of $26.

“Going forward, states should consider requiring utilities to account for multiple factors when setting a spending target for low-income customers,” the report says. “Some examples include socioeconomic characteristics of their service territories, percentage of income-qualified customers to total participants and the total amount of the utility’s portfolio investments.”

Carbon policies increasingly have been added to efficiency standards in recent years, but only 16 of the 26 EERS states have explicit decarbonization targets.

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NEPOOL TC Votes Against Compliance Proposal for Interconnection Order

The NEPOOL Transmission Committee has declined to support a compliance proposal from the New England transmission owners for a recent FERC order preventing the TOs from charging interconnection customers for operations and maintenance fees associated with network upgrades.  

In December, FERC sided with clean energy advocacy group RENEW Northeast in a dispute over who must pay for the upkeep and operation of interconnection network upgrades. The commission determined these costs should not be paid by the interconnection customer, shifting them over to transmission rates. (See FERC Sides with New England Developers on Interconnection Complaint.) 

In response to the order, the TOs propose to amend the RTO’s tariff to remove operations and maintenance costs from network upgrade requirements.  

However, RENEW argues the TOs’ proposal does not “remove all the annual costs associated with network upgrades, stand-alone network upgrades and distribution upgrades as required by the order.” 

RENEW wrote that the TOs’ proposal fails to address “some remaining annual costs … such as cost of capital, federal and state income taxes, and other related costs,” which still could be assigned to interconnection customers, it wrote in a memo published prior to the Jan. 29 TC meeting. 

The group also argued that provisions of the TOs’ proposal that assign “repair and replacement” costs to interconnection customers are “directly contrary to the requirements” of the Dec. 19 order. 

Finally, RENEW opposed the proposal to continue billing operations and maintenance costs until the TOs recalculate their billing formulas, and to issue refunds for these charges by mid-June. The group argued that continuing these charges is prohibited by the order.  

The TOs’ proposal failed to pass with just 33.3% support from the committee, backed by members of the transmission and publicly owned entity sectors. Members of the generation, alternative resources, supplier and end user sectors opposed the proposal. It now will head to the Participants Committee (PC) in February for a vote, without the backing of the TC.  

Also at the Jan. 29 meeting, the TC voted to support a Transmission Operating Agreement for the New England Clean Energy Connect transmission line and discussed compliance with FERC Order 904. 

Order 904, released in November 2024, prohibits transmission providers from including charges in transmission rates to compensate generators for reactive power which falls “within the standard power factor range by generating facilities.” 

The committee also discussed improvements to the ISO-NE’s economic study process. ISO-NE economic studies are intended to evaluate and address potential market inefficiencies or transmission congestion or integrate new resources or load.  

The RTO is in the second phase of a project to improve these studies, which is focused on making changes to identify “system efficiency issues and needs by establishing a clear trigger for when to issue a Request for Proposal (RFP), defining benefit metrics for evaluating RFP responses and streamlining the RFP process into a single stage.” 

Patrick Boughan of ISO-NE noted that the RTO plans “an interregional model that explicitly models the projected future demand and resources of surrounding regions,” instead of relying on historical data, as it has done in the past. The RTO also plans to transition from modeling imports as zero-cost resources to estimating their cost based on the interregional model. 

Boughan also said ISO-NE “does not propose to pursue consideration of capacity savings” in the Phase 2 project, noting the RTO simultaneously is developing a major overhaul of its capacity market and has “no reliable method to estimate capacity savings” over the 10-year planning horizon.  

He also noted the RTO plans to mirror how its longer-term transmission planning process treats aging transmission equipment. 

“If a proposal includes rebuilding or eliminating a transmission element that is on the Asset Condition List, or an element that is more than 40 years old, the avoided cost of that upgrade will be counted as an avoided transmission investment,” Boughan said.  

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FERC Rejects Blanket Extension of MISO COD Deadlines for Gen Developers

FERC has rejected MISO’s attempt to implement a blanket, two-year extension of commercial operation dates for generation developers that entered the interconnection queue about seven years ago.  

FERC said MISO’s proposed waiver of its usual operations deadline was neither limited in scope, nor did it address a concrete problem (ER25-150). That leaves generation developers who entered the queue in 2018 or 2019 and need extra time to place projects in service appealing to FERC on a case-by-case basis.  

MISO in recent years has experienced generation developers struggling to bring projects online according to the commercial operations dates they specified when entering the queue. The RTO said supply chain issues have developers even exceeding its three-year grace period, leaving many developers to apply for waivers of MISO’s deadlines with FERC to avoid project cancellation.  

MISO is working on a plan to allow projects up to nearly 11 years to enter service after the project entered the queue’s definitive planning phase for studies; however, that proposal would apply only to projects that entered the queue in 2020 or later. (See MISO to Relax Commercial Operation Deadlines in Interconnection Queue.) For the approximately 200 developers that entered projects in the 2018 or 2019 queue cycles, MISO proposed a simpler, two-year waiver.  

But FERC said MISO didn’t show that the proposed waiver of its tariff would apply only to interconnection customers that still are unable to achieve commercial operation after the grace period. The commission said the waiver could extend to developers who may not need it.  

“While we appreciate the desire for administrative efficiency by combining multiple interconnection requests facing a similar fact pattern into the same waiver request, administrative efficiency cannot come at the expense of providing sufficient information to demonstrate that the request meets the commission’s waiver criteria,” FERC said.  

FERC also said MISO did not explain why a two-year extension is sufficient for all 2018 and 2019 projects to reach operations or attempt to demonstrate that projects are at risk without the blanket waiver.  

“While MISO and some commenters have provided general details of lead time delays, MISO has not provided sufficient information regarding the practical effects of these lead times for each interconnection request in the 2018 and 2019 DPP study cycles,” FERC said.  

The commission said while it wouldn’t entertain an across-the-board waiver, individual interconnection customers remain free to approach FERC when time is running out on their commercial operation deadlines.  

MISO says its developers are bogged down by long lead times on acquiring transformers, breakers, panels and inverters. It sought the mass extension to lessen the risk of interconnection request terminations. EDP Renewables, Cordelio, Invenergy, NextEra and MISO’s Independent Power Producers supported the waiver, while MISO South state regulators said a broad waiver would “eliminate the need for submission of numerous project-specific waiver requests by developers.”  

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PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor

PJM announced Jan. 28 it will seek to establish a $325/MW-day price cap on capacity prices and a $175/MW-day floor for the 2026/27 and 2027/28 Base Residual Auctions (BRAs) following discussions with Pennsylvania Gov. Josh Shapiro to resolve a complaint he filed over increased capacity costs.

The RTO has scheduled a special session of the Members Committee on Feb. 7 to consult with stakeholders on the prospective Federal Power Act Section 205 filing, with meeting materials expected on Jan. 31. Consultation with transmission owners also would be necessary. PJM spokesperson Susan Buehler said the specifics of the proposal will be discussed Feb. 7 and clarified that the price cap and floor would extend to all zones.

The 2026/27 BRA is scheduled to be conducted in July, with several pending filings at FERC seeking changes to the auction design and stakeholder processes envisioning even more. Across several of those dockets, PJM has requested orders by Feb. 21, which it stated is necessary to ensure it has adequate time to implement the changes in time for the auction.

The RTO noted that any changes are “subject to consultation with the PJM members and the PJM Board of Managers.”

“PJM did the right thing by listening to my concerns and coming to the table to find a path forward that will save Pennsylvanians billions of dollars on their electricity bills,” Shapiro said in his own announcement. “My administration will continue to work to ensure safe, reliable and affordable power for Pennsylvanians for the long term.”

In his complaint and letters to PJM’s board, Shapiro argued the current price cap structure, which takes the greater of the gross cost of new entry (CONE) or 1.75 times net CONE, would result in total capacity costs $20.4 billion beyond what is necessary to maintain resource adequacy. (See PJM in Discussions with Gov. Shapiro on Capacity Price Cap.) The complaint sought to rework that formula to 1.5 times net CONE, arguing that would be the highest price necessary to ensure the reference resource, a combustion turbine, is profitable (EL25-46).

The governors of New Jersey, Maryland, Illinois and Delaware filed comments and sent letters supporting Pennsylvania’s complaint.

In a statement, Maryland Gov. Wes Moore’s office said he appreciates PJM’s responsiveness to mitigate unnecessarily high capacity prices.

“Today’s announcement of a path toward resolving a complaint filed by Pennsylvania — that was backed by Maryland and other states served by PJM — shows the grid operator has an understanding of the need to limit the future impacts of major price hikes on our ratepayers,” it said. “The governor remains concerned that while PJM has agreed to cap electricity costs, successful implementation of this approach depends on details that need to be worked out ahead of federal approval.”

Mila Myles, spokesperson for Delaware Gov. Matt Meyer, said he shares the other governors’ concerns about potential capacity cost increases.

“We welcome the news that PJM has reached a tentative settlement that will protect consumers in Delaware and other states from excessive increases in their electric bills,” she said in an email. “This is an example of how PJM can work with states to ensure that our constituents are protected from abrupt changes in energy markets.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, told RTO Insider the agreement follows years of PJM being influenced by stakeholders to change market rules that disadvantage them, showing an institutional vulnerability that opens the door to any parties filing FPA Section 206 complaints and negotiating directly with PJM staff to satisfy politically driven interventions. He called the prospective price floor “window dressing” given the likelihood PJM and members discussed high prices in the 2026/27 auction.

“This is no longer a market when you’re just picking prices,” he said. “This is how wholesale markets die.”

In addition to the direct impact of suppressing prices in the coming auctions, he argued  the repeat rule changes undermine investor confidence in the prices set by the capacity market. He noted that generation deactivation requests have been filed for the Elwood plant, owned by J-Power USA, and Avenue Capital Group’s Elgin generators in the ComEd zone. While Elgin has rescinded its request to retire following the 2025/26 price print, Sotkiewicz said the decision to continue Elgin on the path to deactivation makes sense even in the face of near-term high prices given the volatility PJM has created.

“You can’t run a market this way; there’s no way an investor can have confidence in a ruleset,” he said. “I have more certainty about building a generator in California than PJM.”

Sotkiewicz said the process of negotiating directly with one governor on the market design for an RTO with 14 jurisdictions and market participants who will be directly affected tells stakeholders their perspectives don’t matter. He said PJM repeatedly has eschewed the stakeholder process to instead follow various special processes, often giving minimal notice to members before filing major redesigns on the capacity market.

“Why are we having a stakeholder process about anything when you’re just going to do whatever the hell you want?”

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Calif. Officials Propose New Safety Measures for Battery Storage

California regulators have proposed new safety standards for battery energy storage systems following a series of incidents at the facilities, including a major fire Jan. 16 at Vistra’s Moss Landing site. 

The California Public Utilities Commission is proposing the standards as an update to General Order 167, which likely was adopted in 2004 and sets safety standards for electric generating facilities. The commission is expected to consider the update, known as GO 167-C, during a March 13 voting meeting. 

“Regulatory oversight of ESS [energy storage system] facilities is necessary because of the safety and reliability risks that can occur if ESS facilities are not properly operated and maintained,” the CPUC said in a proposed resolution to adopt the standards. 

In addition, a bill has been introduced in the California legislature addressing battery storage system safety. Assembly Bill 303 would restore local oversight for energy storage projects in the state, according to its author, Assemblymember Dawn Addis (D). 

Under the CPUC’s proposed standards, battery energy systems would face similar requirements to those of electric generating facilities.  

For example, ESS owners would be required to file operation and maintenance plans with the CPUC, steps now required of generating asset owners. ESS owners also would be required to report safety-related incidents to the CPUC within 24 hours — just as generating asset owners must do now. 

And in a new mandate for both energy storage and electric generation, facility owners would be required to work with local authorities to develop an emergency response and emergency action plan. 

The changes are in response to direction from state lawmakers in Senate Bill 1383 of 2022 and SB 38 of 2023. 

The CPUC held three workshops in 2024 to gather feedback while developing the proposed standards. 

Battery Blazes

Battery storage is seen as key to meeting the state’s clean energy goals. Batteries can store solar energy during the day and release it during peak demand in the evening. 

California’s battery energy storage capacity increased from 770 MW in 2019 to 13,391 MW in October 2024, with about 3 GW of that added since April 2024. (See California Hits Milestones for Batteries, DR Grid Support.) 

That puts the state at about a quarter of its projected energy storage need of 52,000 MW by 2045. 

But battery storage presents safety concerns. The worries were underscored Jan. 16, when a fire broke out at Vistra’s 300-MW energy storage facility at Moss Landing in Monterey County. The lithium-ion battery facility is one of the world’s largest battery energy storage systems. 

The fire, which prompted the evacuations of 1,200 people, is under investigation. Staff from the CPUC’s Safety and Enforcement Division visited the site Jan. 22 as part of its probe. 

The CPUC listed nine other safety incidents at battery facilities since 2021, including four in 2024. In one incident in September 2024, a fire at a San Diego Gas and Electric battery storage facility in Escondido prompted evacuations. 

Evacuations also were ordered in May 2024 during a fire at REV Renewables’ Gateway Energy Storage facility in Otay Mesa. 

Battery Safety Bill

AB 303 from Assemblymember Addis is known as the Battery Energy Safety and Accountability Act. 

The bill would prohibit battery energy systems of 200 MWh or more on an environmentally sensitive site or within 3,200 feet of a “sensitive receptor,” such as a home, school or community center. 

The bill also would exclude battery storage projects from the California Energy Commission’s opt-in certification process, a streamlined path to approval. (See 2 Huge Solar-plus-storage Projects Planned in California.) 

Under the opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits. 

“AB 303 is a proactive measure that will ensure companies like Vistra go through the normal, local, regulatory process,” Addis said in a statement. “It is designed to build trust, increase safety and give communities a choice by restoring local community processes for permitting these projects.” 

The California Energy Storage Alliance is opposed to the bill, saying it is “excessive and does nothing to enhance public safety.” 

“Instead, it creates unnecessary barriers to the deployment of critical energy storage systems needed to stabilize our grid and support California’s transition to a clean energy future,” CESA said in a release. 

AB 303 is awaiting assignment to committee. 

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Chevron, Engine No. 1 to Power Data Centers

Chevron and activist investor firm Engine No. 1 are teaming up on plans for what they expect will be the first multi-gigawatt gas-fired power plant co-located with a data center.

They said Jan. 28 that their partnership to build a new company to develop scalable and reliable power solutions for U.S. data centers is based on President Donald Trump’s supportive early moves for U.S. energy development, including in support of artificial intelligence.

They said they have secured manufacturing slots for seven of GE Vernova’s 7HA gas turbines and expect to install them at data centers in the Southeast, Midwest and West that they are calling “power foundries.”

They would total as much as 4 GW of capacity and would be targeted to be in service by the end of 2027. There is potential to expand beyond this capacity and potential for future addition of carbon capture and storage or other carbon-reduction strategies.

The generating units initially would not send power through the grid. But the model is designed to allow future interconnects.

Chevron, Engine No. 1 and GE Vernova offered comments directly in line with their roles as an oil supermajor, an industrial investment firm and a power equipment manufacturer.

Chevron CEO Mike Wirth said: “We are proud to play our part in bringing to fruition President Trump’s vision for a new American golden age, powered by our enormous energy resources and unrivaled workforce.”

Engine No. 1 CIO Chris James said: “By using abundant domestic natural gas to generate electricity directly connected to data centers, we can secure AI leadership, drive productivity gains across our economy and restore America’s standing as an industrial superpower.”

GE Vernova CEO Scott Strazik said: “GE Vernova is uniquely positioned to provide the energy systems and support required to make this large-scale endeavor possible, as the leading U.S. energy manufacturer.”

Almost all observers expect U.S. electricity demand to increase in coming years, in part because of the rise of energy-intensive artificial intelligence computing. There has been some disagreement on how sharply it will increase, however.

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Brattle Study Shows Big Benefits for California in ‘Expanded’ EDAM

California ratepayers would save millions more in a CAISO Extended Day-Ahead Market (EDAM) encompassing nearly all the West than in one that includes only those utilities likely to join the market, according to a new Brattle Group study. 

The study, commissioned by the California Energy Commission, covers nearly every utility in the state — except the Imperial Irrigation District (IID) — and not just members of CAISO, whose balancing authority areas accounts for about 80% of the state’s electricity load. It represents yet another in a series of Brattle — and other — production cost model studies published during the increasingly contentious competition between EDAM and SPP’s Markets+. 

Brattle Principal John Tsoukalis presented “preliminary” findings from the study during a Jan. 24 CEC workshop that examined the potential impact on California from the West-Wide Governance Pathway’s “Step 2” plan to establish an independent “regional organization” (RO) to oversee CAISO’s EDAM and Western Energy Imbalance Market (WEIM). 

“A larger market means a larger and more diverse pool of transmission and generation resources,” Tsoukalis said. “And what that means is … the market is able to more effectively shift from less efficient resources to more efficient resources. It finds the lowest-cost resource that can serve load in every given hour, and that leads to production cost savings for customers.” 

The study differs from previous Brattle studies in that the “Baseline” case is not the status quo — that is, the current arrangement before the launch of EDAM or Markets+ — but assumes a scenario in which EDAM already is operating but includes only CAISO and those entities that already have formally committed to that market. Those entities include PacifiCorp; Portland General Electric; Balancing Authority of Northern California (BANC) and its largest member, Sacramento Municipal Utility District; and Los Angeles Department of Water and Power (LADWP). 

Under Brattle’s “Baseline” case, California’s estimated total system cost is $4.511 billion a year.  

That figure drops by $112 million (to $4.399 billion) under a “Baseline+” case in which EDAM also consists of entities likely to join the market, which includes Idaho Power, NV Energy and Public Service Co. of New Mexico.  

But the biggest savings for California by far are found in the “Expanded EDAM” case, in which the CAISO market includes nearly every Western BA except for Western Area Power Administration entities already engaged with SPP markets, Public Service Co. of Colorado (PSCo) and IID. In that scenario, Golden State ratepayers save $780 million annually compared with the “Baseline” case. 

“Intermediate EDAM footprints [are] likely to produce benefits between the Baseline+ and Expanded EDAM ‘bookend,’” according to a slide from the Brattle presentation. 

But California likely would see significantly lower benefits than the top end — $182 million — in what will be the most likely outcome in the West — the “Split Market” case, where Markets+ consists of Powerex, the Bonneville Power Administration and most Washington utilities, NorthWestern Energy, PSCo, Arizona’s utilities and El Paso Electric. 

“The only difference between the Baseline+ case and the Split Market case is that we have Markets+ forming in that Split Market case, and what we see is there is a slight benefit, actually, to California customers from Markets+ forming, but it is about $500 million less than the Expanded EDAM case,” Tsoukalis said. 

The study drew that conclusion based partly on the assumption of a “relatively efficient seam” between EDAM and Markets+, an improvement over the current bilateral day-ahead market that would provide California customers with “increased access to low-cost resources in the Markets+ footprint.” 

Tsoukalis nalso oted the study’s day-ahead market benefit estimates likely are “conservatively low,” just as previous studies had underestimated the actual benefits from the WEIM. 

Emissions, Reliability Benefits

Brattle’s study also shows significant carbon emissions benefits for California in the Expanded EDAM, with in-state gas generation falling by 31%, wind and solar curtailments falling by 10% and CO2 emissions declining by 11.2% — though emissions in the rest of the West would increase 1.3%. Under the Split case, emissions in California fall by 3.5% and rise by 2.1% in the rest of the West. 

The study also represents the first of the Brattle market studies that attempts to capture potential reliability benefits from the day-ahead market for all participants. To do that, it estimates the change in “market supply cushion,” representing “the available generating capacity not committed to serving load” during each hour, which Tsoukalis said consists only of dispatchable resources and explicitly excludes hydro, wind and solar. 

The study found that the supply cushion is about 25 GW higher in the Expanded than in the Split case. 

“Focusing on the 10 tightest hours of the year, the supply cushion in the EDAM is 20,000 MW larger in the Expanded EDAM case than in the Split Market case (27.8% of load vs. 24% of load),” the study said. 

Michael Wara, of Stanford University’s Woods Institute for the Environment, who followed Tsoukalis’ presentation with his own that showed the reliability benefits of Western grid regionalization, said he was “encouraged” to see Brattle’s findings around reliability. 

“I would have been surprised and a little depressed if their analysis, using a different method, said ‘not much benefit,’ but 25 GW of additional capacity is a substantial benefit on a hard day,” he said.