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December 13, 2025

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Home Batteries Provide 535 MW to CAISO Grid on VPP Test Day

An aggregation of more than 100,000 residential batteries provided an average 535 MW of support to California’s electricity grid during a July 29 test to prepare for the hot summer period ahead. 

The sea of home batteries formed a virtual power plant, comprising a group of customer-owned battery storage systems that are typically paired with solar panels. Local utilities, CAISO, the California Energy Commission and other energy companies, such as Sunrun, released charge from the fleet of batteries onto the grid for two hours, from 7 p.m. to 9 p.m. 

The VPP visibly reduced CAISO’s net load during those peak demand hours, said representatives of The Brattle Group, which studied the results of the test. 

“Performance was consistent across the event, without major fluctuations or any attrition,” said Ryan Hledik, a Brattle principal. “Residential batteries — and other sources of distributed flexibility — can serve CAISO’s net peak, reduce the need to invest in new generation capacity, and relieve strain on the system associated with the evening load ramp.” 

Most of the 535 MW would not have been available had the test not been initiated, according to Brattle. 

“On peak days, using VPPs to serve CAISO’s net peak could reduce the need to invest in new generation capacity and/or relieve strain on the system associated with the evening load ramp,” Brattle said, adding that would help address challenges with California’s “duck curve.” 

“Optimized VPP program design and coordination with the system operator could further maximize the value of the battery output to the system,” Brattle noted. 

Pacific Gas and Electric customers made up about 50% of test participants, Southern California Edison about 38%, and San Diego Gas & Electric about 12%. 

Most of the batteries in the test are part of the CEC’s Demand Side Grid Support (DSGS) program, which rewards customers who support the electric grid during extreme events. Rewards include payment for demonstrated capacity at varying monthly rates based on VPP capacity and duration, according to the CEC. 

As of October 2024, the DSGS program had 515 MW of capacity and more than 265,000 participants. The program, which began in 2022, operates from May to October and is intended to help reduce the risk of rotating power outages during peak demand months. In 2024, the DSGS program turned on its VPP system 16 times. 

The test on July 29 was not the first of its kind this summer: On June 24, Sunrun participated in a similar event in which its power resources provided 325 MW to the grid from 7 to 9 p.m, according to Sunrun. Participating Sunrun customers can receive up to $150 per battery per dispatching season, while Sunrun is paid for dispatching the batteries, the company said.

The CEC on Aug. 14 is holding a workshop on the performance of the DSGS program in 2024, specifically on VPP performance. 

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PSEG Sees Data Centers Surge amid Rising Demand Forecasts

The Public Service Enterprise Group is waiting for New Jersey to address the region’s predicted energy shortage as the utility sees a dramatic rise in potential demand from data centers, said CEO Ralph LaRossa.

Developer inquiries for large load projects seeking new service connections jumped by 47% between March and June to 9,400 MW, LaRossa said Aug. 5 during the company’s second-quarter earnings conference call.

There’s growing concern in New Jersey and in other states that the PJM region is facing a chronic future energy shortage. Rapid demand growth is happening while aging fossil fuel plants are closing faster than new generators, mostly renewable energy, can open.

“The resource adequacy challenges in New Jersey and across the entire 13-state PJM region are becoming more acute,” LaRossa said. “Recent reports reflect an increasing amount of new large load applications that are quickly eroding existing reserve margins. Within the confines of PJM, it’s hard to see the path to new generation through existing market signals, which may require the consideration of a new approach to procuring capacity and resource planning.”

Underscoring the seriousness of the situation, LaRossa said the utility hit a peak load of 10,229 MW during the three-day heat wave in June, the highest level since 2013. New Jersey, a net importer of power, imported about half its energy during the heat wave, LaRossa said. But while the state in the past could rely on energy imports from other PJM members that generate excess power, such as Pennsylvania, that “convenient option is quickly being absorbed by rapid growth of native load in those states,” he said.

Much of the new demand is for large-load projects, mainly data centers used for artificial intelligence and other projects. LaRossa said about 90% of the 9,400 MW in large load projects — which include mature applications, feasibility studies and initial leads — comes from planned data centers. He said he expects 10 to 20% of the total to be completed eventually.

One of the projects included in the large load figure is a data center that AI cloud computing company CoreWeave plans to build on a 107-acre campus in Kenilworth, N.J., LaRossa said. CoreWeave announced on Aug. 4 it has completed the land purchase.

Capacity Auction Concerns

The earnings call was PSEG’s first since PJM completed its capacity auction and announced on July 22 the outcome price of $329.17/MW-day (UCAP) RTO-wide for delivery year 2026/27. The price would have been $388.57/MW-day without a price cap put in place by PJM in agreement with Pennsylvania Gov. Josh Shapiro (D). He filed suit seeking changes in the system after the auction in 2024 raised prices about tenfold to $269.92/MW-day, the result of load growth, generation deactivations and changes to risk modeling that shrank reserve margins. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

The dramatic hike in the last capacity auction triggered widespread concern among officials in New Jersey and other states for its impact on ratepayers. The average electricity bill in New Jersey increased by 20% on June 1.

LaRossa said the company anticipates “a near flat impact on customer electric bills” from the recent auction when it is factored into the state’s Basic Generation Service rates that will take effect June 1, 2026.

In the longer term, one measure that would help the state increase its generating capacity is a bill, A5439, that would allow electric public utilities to own and operate electric generation facilities, LaRossa said.

“In New Jersey, policymakers have begun to actively weigh the priorities of economic growth with system reliability and affordability and the state’s environmental policies,” he said.

PSEG is pushing the state to address some key issues, he said: “What are the forecasts they’re looking for? What are the reliability outcomes they’re targeting? What are the affordability targets they have? And then finally, the environmental policy goals. When you put those four pieces together, we think we’ll be able to find the right answer and solution for the state.”

However, he said PJM’s capacity process, especially its governance, needs reform, echoing concerns expressed by other critics of the RTO.

“We’ve been very vocal about that for many years,” he said. “We don’t think that it is attracting additional generation. … The facts are that there has not been any new base load generation built in New Jersey for quite some time.”

“The governance at PJM doesn’t allow for a lot of the things that people are talking about to just be unilaterally implemented,” he said, citing the example that for state governors to get involved in the process, PJM members must give a vote of approval. “This governance process is the core problem.”

Nuclear Advances

LaRossa said PSEG is taking steps to enhance its nuclear power generation, noting that an enhancement project at the Hope Creek Generating Station nuclear facility operated by the company in Salem, N.J., will add 200 MW. He characterized the enhancement, which is expected to go online between 2027 and 2029, as “the size of a small modular creator of incremental, carbon-free, dispatchable power.”

He said the company also will benefit from the recent federal funding bill, which continued the production tax credits for nuclear facilities and extended depreciation rules that will help PSEG’s nuclear fleet.

PSEG’s second-quarter results for 2025 grew from $434 million ($0.87/share) in 2024 to $585 million ($1.17/share). Non-GAAP operating earnings for the quarter were $384 million ($0.77/share) in Q2 2025, compared with $313 million ($0.63/share) in the same period last year.

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U.S. Peak Electricity Demand Sets Back-to-back Records

Peak electricity demand in the 48 contiguous states set records twice in the last week of July, reaching 758,053 MW and 759,180 MW over one-hour periods July 28 and 29. 

The U.S. Energy Information Administration announced the developments Aug. 5 and attributed it to a heat wave coming amid the continuing growth of power demand. 

The previous record was 745,020 MW, recorded July 15, 2024. 

There is disagreement about how much and how quickly U.S. electric demand will increase, but there is wide consensus that growth will occur, due to transportation and building electrification, reshoring of manufacturing and rise of energy-intensive artificial intelligence data centers. 

The EIA’s forecast calls for electricity demand to grow by an annual rate of just over 2% in 2025 and 2026. 

This is a marked change from much of the century so far, EIA said, noting that average annual increase in demand was only 0.1% from 2005 to 2020 and just 0.8% between 2020 and 2024. 

The back-to-back demand records at the end of July 2025 came as much of the nation was within a heat dome, subjecting tens of millions of Americans to very high temperatures and causing their air conditioners to consume more electricity. 

Preliminary data from EIA’s Hourly Grid Monitor indicates the new all-time peak, 759,180 MW, was reached about 6 p.m. Eastern time July 29. 

The Grid Monitor indicates that in the 60-minute period: 

    • The highest demand was in the Mid-Atlantic (154,380 MWh), Midwest (129,574 MWh) and Texas (81,572 MWh). 
    • The major energy sources meeting this demand were natural gas (348,891 MWh), coal (133,711 MWh), nuclear (95,287 MWh) and solar (88,389 MWh). 
    • Two other renewables were far behind — hydropower was near its peak output for the day at 39,392 MWh, while wind turbines produced only 25,772 MWh, down 57% from their peak output for the day, reached 16 hours earlier. 
    • The U.S. imported 5,883 MWh from Canada and exported 230 MWh to Mexico. 

Daily demand peaks began to subside after July 29, preliminary data shows, dropping to 631,287 MWh from 6-7 p.m. Aug. 1.  

Over the weekend, the peaks dipped further to 588,925 and 600,233 MWh. They bounced back to 645,449 MWh as the work week began Aug. 4. 

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MISO Stakeholders Move to Enshrine Conduct Rules in Governance Guide

MISO stakeholders have adopted the spirit of MISO’s new code of conduct into their comprehensive rulebook while adding rules that empower committee chairs to shut down rude behavior or order attendees out of conference rooms.

MISO’s Steering Committee voted to include rules similar to MISO’s code of conduct in the Stakeholder Governance Guide at an Aug. 5 meeting.

A draft version of the guide now provides a “Respectful Conduct in Stakeholder Meetings” section that calls for “a foundation of mutual respect, professionalism, fair debate and dialogue.” It details a zero-tolerance policy for name-calling, sarcastic comments, demeaning remarks, repeated interruptions and disruptive behavior. MISO’s code of conduct, introduced in early July, similarly forbids rude or callous language, deliberate meeting disruptions or disregarding committee chairs’ instructions. (See New MISO Stakeholder Code of Conduct Forbids Rude or Callous Language.)

MISO Reliability Subcommittee Chair Ray McCausland, of Ameren, said while MISO published its own conduct rules, the list to be included in the Stakeholder Governance Guide is written by stakeholders and considered separate from MISO’s. The MISO Code of Conduct is set to be included in an appendix to the Stakeholder Governance Guide.

Steering Committee Chair and ITC’s Brian Drumm said stakeholders can think of the code as a notice to be on their “best behavior.”

The guide’s more detailed language that largely tracks MISO’s code replaces years-old and less specific conduct language that laid out MISO’s grounds for stakeholder removal due to abusive or disruptive behavior. The new insert goes a step further than MISO’s new code and confers responsibility on committee chairs and vice chairs to quell unruly meetings.

The guide says chairs and vice chairs can:

    • Call a meeting participant to order “immediately upon a breach of decorum.”
    • Warn an individual about consequences for continued disruptions.
    • Refuse to recognize a participant “until order is restored.”
    • Order a participant to leave for the remainder of a session.
    • Initiate disciplinary procedures, “which may include formal censure, suspension or removal from the stakeholder group.”

“These rules exist, not to silence disagreement, but to preserve a space where all voices can be heard without hostility or harassment,” the guide’s draft wording concludes.

Market Subcommittee Chair Tom Weeks, of the Michigan Public Power Agency, said while he supports “civil and professional discourse” in meetings, he’s heard concerns from stakeholders that the code and accompanying guide changes could stifle conversation because some stakeholders’ points might be perceived as intimidating. He said while he didn’t oppose the new wording, stakeholders’ concerns are not “overblown.”

“We don’t want to swing the pendulum to the other side where people don’t feel free to make substantive comments,” Weeks said. He asked stakeholders to keep in mind that some stakeholders can deliver comments with more passion and enthusiasm than others.

The revisions concerning conduct were part of a larger batch of edits to MISO’s Stakeholder Governance Guide, which is altered as stakeholders deem necessary. The Steering Committee either adopted suggested edits and sent them along for final review from MISO’s Advisory Committee or determined that certain changes needed more refinement and sent them back to the Stakeholder Governance Working Group, which drafted the changes.

The Steering Committee did not approve another edit to the guide that would have allowed MISO itself to present motions during stakeholder meetings. Some questioned the appropriateness of MISO raising voting motions.

McCausland said the intent of the change was to spell out that MISO could introduce a motion but that a stakeholder is required to move such a motion to the floor for a vote. Some Steering Committee members said the wording wasn’t clear, and the committee ultimately sent the item back to the working group for revision.

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CISA Releases New Cyber Tools for Defenders

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released two software tools to help cybersecurity teams detect and respond to attacks against their networks.

CISA announced the releases a day apart, on July 30 and 31. First out was the Eviction Strategies Tool, developed alongside engineering and information technology consultancy MITRE. The agency then revealed Thorium, created with the help of Sandia National Laboratories.

The Eviction Strategies Tool comprises COUN7ER — a database of adversary tactics, techniques and procedures (TTP) matched to appropriate countermeasures — and Playbook-NG, a web application through which cyber defense teams can draw strategies from COUN7ER.

To use the tool, an entity’s cyber staff first input TTPs from MITRE’s ATT&CK matrix or describe threat actor activities. Playbook-NG provides a list of recommended responses, which the user can export for later use. Users can also start with a template created by CISA that describes “specific collections of TTPs … that a cyber defender may use as is or quickly customize.” No information about the users or their inputs is saved.

Jermaine Roebuck, CISA’s associate director for threat hunting, said in a statement that the agency had “seen organizations struggle with identifying the right steps to take and the correct sequencing of actions” to remove cyber intruders from their networks. COUN7ER is meant to serve as “a Rosetta Stone of defensive measures cross-referenced with multiple threat frameworks. CISA will regularly update COUN7ER to account for new incidents and threat intelligence, and it will test countermeasures through internal tabletop exercises.

Thorium provides a platform to integrate multiple forensic analysis tools and index for malware threat information. It is intended to help analysis with the “vast amounts of malware” affecting organizations across the public and private sectors, which currently rely on “a long list of malware analysis tools with specific capabilities” that often were not meant to work together.

According to CISA, the software can process more than 10 million files per hour and schedule over 1,700 jobs per second. The tool provides search and text-tagging functions, access controls and automated tools for scaling and virtualization. Roebuck said the agency hoped by sharing the platform to “empower the broader cybersecurity community to orchestrate the use of advanced tools for malware and forensic analysis.”

Grant Applications Open Through Aug. 15

CISA, along with the Federal Emergency Management Agency, also announced on Aug. 1 the last round of grants for the State and Local Cybersecurity Grant Program (SLCGP) and Tribal Cybersecurity Grant Program (TCGP).

The programs, created by the Infrastructure Investment and Jobs Act of 2021, are intended to support state, local, territorial and tribal governments in reducing cyber risk and building resilience against cybersecurity threats. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.) $91.7 million will be available for state and local governments through the SLCGP, and $12.1 million for tribal governments through the TCGP.

According to the Notice of Funding Opportunity, interested parties must file their applications for either program by Aug. 15. This represents a much shorter window than the last time applications opened in 2024, when applicants had from Sept. 23 to Dec. 3 to submit their requests. (See DHS Offers $280M in Grants for Cyber Investments.)

Candidates must address at least one of four objectives in their submissions:

    • Establish appropriate governance structures to improve cyber response capabilities and ensure continuity of operations;
    • Identify areas for improvement in their current cybersecurity postures;
    • Implement security protections in accordance with the risks they face; and
    • Ensure organization personnel are appropriately trained in cybersecurity.

Awards under SLCGP have a ceiling of $4.2 million and a floor of $256,000; TCGP awards have a $2.7 million ceiling and a $39,000 floor.

“CISA is proud to empower state, local and tribal governments to build more resilient cyber ecosystems,” CISA’s Acting Director Madhu Gottumukkala said in a press release. “This unified DHS approach enables innovative solutions that strengthen digital infrastructure, and helps communities invest in meaningful cybersecurity improvements to protect the critical services they provide. This is another example of investing in our communities while being good stewards of our taxpayer dollars.”

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Feds Pile on More Barriers to Wind and Solar

The Trump administration has taken further steps to thwart renewable energy development, adding new directives limiting wind and solar development on federal land and at sea. 

Most notably, an Aug. 1 order (SO 3438) from Interior Secretary Doug Burgum prioritizes efficient use of federal land for energy generation — an impossible challenge for sprawling solar and wind farms, which need square miles to generate as much power as a fossil or nuclear plant covering just a few acres. 

In other recent moves, the Department of the Interior’s Bureau of Ocean Energy Management on Aug. 4 rescinded the schedule of seabed leases for offshore wind power development, one of President Donald Trump’s regular targets. 

On July 30, BOEM rescinded designation of all wind energy areas on the outer continental shelf along the East, West and Gulf coasts — more than 3.5 million acres determined to hold the best potential for wind farms. 

A July 29 order (SO 3437) from Burgum ended “preferential treatment” for wind projects and placed new potential hurdles to its development. (See Trump Administration Takes Another Swing at Wind Power.) 

A July 15 internal directive required any and all decisions and actions pertaining to wind and solar at Interior to be reviewed and signed in succession by two high-level deputies and then Burgum himself. (See Interior Dept. Places Solar, Wind Under Close Review.) 

The steady stream of directives is becoming increasingly redundant in their intended effect if not their specified actions. 

There are likely multiple reasons for this, Ted Kelly, lead counsel for U.S. clean energy at the Environmental Defense Fund, told NetZero Insider. If one strategy falls to a court challenge, the others might stand. Also, the administration is very message-oriented: Serial announcements make Interior look good to Trump’s inner circle and make Trump look good to his core constituency, he added. 

The number and tenor of the directives also can create paralyzing uncertainty within the profit-driven private sector. 

“I think we’ve seen it in different areas; they kind of have a dual strategy of, create the uncertainty as much as they can, and then also get to the aggressive attacks when they can,” Kelly said. 

EDF saw this two-track approach with the stop-work order on Empire Wind 1 and revocation of a loan guarantee for the Grain Belt Express transmission line, he added. 

Kelly said EDF is challenging some actions in court, but others are not actionable yet. 

Burgum offered a robust justification with his Aug. 1 order, announcing it as an effort to “Rein in Environmentally Damaging Wind and Solar Projects.” He said the order would better manage federal lands and minimize environmental impact on them: “Gargantuan, unreliable, intermittent energy projects hold America back from achieving U.S. energy dominance while weighing heavily on the American taxpayer and environment.” 

Federal law requires Interior to make judicious decisions about use of federal land and seabed, the news release continued. “These laws ultimately raise the question of whether the use of federal lands for wind and solar projects is permissible, given these projects’ encroachment on other land uses and their disproportionate land requirements, especially when reasonable project alternatives with higher capacity densities are technically and economically feasible.” 

Interior can do only so much to thwart onshore renewables development: It holds sway over public land, but plenty of private land is available. 

Offshore wind energy development, however, is entirely within federal purview, unless the turbines are placed close to shore in state waters — a politically and technically challenging step that has not been proposed. 

On his first day in office, Trump directed a halt to all new offshore wind power leasing and directed an ominous-sounding review of existing leases for potential modification or termination. In the wake of that memorandum, federal permitting reviews and other regulatory work essential to planning an offshore wind farm slowed or halted. 

But notwithstanding the weekslong Empire Wind stop-work order — which actually may have been an attempt to twist the arm of the governor of New York state over natural gas pipeline permitting, rather than a true attempt to stop the wind project — the Trump administration has allowed construction to continue on the five active projects: Coastal Virginia Offshore Wind, Vineyard Wind 1, Revolution Wind, Empire Wind 1 and Sunrise Wind. 

The administration has moved to prevent any steel from being placed in the water on other projects, however, including a revocation of the EPA air permit for Atlantic Shores Offshore Wind and a challenge of the Maryland construction permit for US Wind. 

Wind opponents are suing the federal government (1:2025cv00152 and 1:2024cv03111) for approving construction of US Wind’s Maryland proposals. The government told the U.S. District Court for Delaware on July 28 that it plans to move for a voluntary remand of US Wind’s construction and operations plan. 

If granted, this would send the massive 90-part blueprint approved by the wind-friendly Biden administration back for review by the Trump administration, potentially dooming it. 

Boosting fossil fuel production and sidelining the renewables sector is exactly the turnabout from the Biden years that Trump promised on the campaign trail. 

But it is not good policy, Kelly said, given that major increases in generation capacity are at least five years away for natural gas and 10 for nuclear. 

“There’s the real contradiction and hypocrisy of their insistence, on the one hand, that there’s an energy emergency and that we need to get all generation online as quickly as possible,” he said. “But on the other hand, these clean energy types of projects don’t count as energy, and we’re going to throw up roadblocks in the middle of them, when really they’re the only things, other than some gas plants that are already under construction or under order, we can build in the next five to 10 years.” 

Wind and solar provided 14% of utility-scale generation in the U.S. in 2023 and accounted for 78% of capacity additions in 2024. 

In January 2025, shortly before President Joe Biden left office, the National Renewable Energy Laboratory released an analysis showing federal lands hold the potential for 5,750 GW of utility-scale photovoltaics, 975 GW of geothermal and 875 GW of wind generation. 

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Calif. Fights to Maintain ZEV Momentum

In the face of federal attacks on California’s landmark zero-emission vehicle regulations, the state is “doubling down” on efforts to spur ZEV adoption. 

The California Air Resources Board (CARB) in July completed a series of four public sessions seeking feedback on ways to encourage ZEV adoption — part of an initiative called ZEV Forward. Input from the sessions will help shape recommendations CARB will send to Gov. Gavin Newsom in August. 

“Across the country, people are looking to California to fill that void that now exists at a federal level,” California Transportation Secretary Toks Omishakin said during a session in Sacramento.  

And CARB on July 24 approved amendments to its Advanced Clean Trucks (ACT) regulation to give truck manufacturers more flexibility in complying with the rules. ACT requires truck makers to deliver for sale in the state an increasing percentage of ZEVs over time. 

ACT is a complement to CARB’s Advanced Clean Cars II regulation, under which car manufacturers must provide an increasing percentage of ZEVs through 2035, when all new cars sold in the state must be zero-emission or plug-in hybrid. 

The federal government is now trying to overturn those regulations. 

But CARB has prepared for challenges to ACT. In July 2023, the agency entered into the Clean Truck Partnership with truck makers, promising to provide more compliance flexibility to manufacturers in exchange for a pledge to comply with the regulations regardless of the outcome of litigation or changes to CARB’s authority to enforce them. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)  

“One of the reasons that we were really interested in this Clean Truck Partnership is to provide both certainty to the state and to manufacturers going forward, where there might be a potential for a change in the federal posture around clean energy and clean technology,” CARB Executive Officer Steven Cliff said during the July board meeting. 

The ACT amendments the board approved July 24 include a pooling provision, in which a manufacturer may transfer surplus ZEV credits generated in one state to another state that has adopted ACT.  

Amendments adopted in October 2024 gave manufacturers three years, rather than one, to make up a ZEV credit deficit from a particular year. The amendments also allow manufacturers to use credits from near-zero-emission trucks to make up part of a deficit. (See Calif. Revises Clean Truck Rules to Ease Compliance.) 

The Waiver Battle

In May, Congress adopted three resolutions to roll back EPA waivers that allowed California to enforce three of its clean vehicle regulations: ACT, ACC II and an omnibus rule that sets emission standards for internal combustion heavy-duty trucks sold in the state. 

On June 12, the day President Trump signed the resolutions, California filed a lawsuit in U.S. District Court calling the overturn of the EPA waivers unlawful.  

To rescind the waivers, Congress used the Congressional Review Act, which was designed for overturning federal rather than state rules, according to the complaint. In addition, the EPA waivers are not rules and thus aren’t subject to the CRA, the lawsuit said. 

In addition to California, plaintiffs include 10 other states: Colorado, Delaware, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington. 

Also on June 12, Gov. Gavin Newsom fired off an executive order “doubling down” on the state’s commitment to clean cars and trucks. 

“We won’t let this illegal action by Trump and Republicans in the pockets of polluters stand in the way of commonsense policy to clean our air, protect the health of our kids and compete on the global stage,” Newsom said in a statement. 

The order directs state agencies, including CARB and the California Energy Commission (CEC), to make recommendations to the governor within 60 days on ways to spur ZEV adoption in the state.  

It also directs CARB to develop an Advanced Clean Cars III regulation “consistent with state and federal law” that would build on existing regulations or provide an alternative if California doesn’t prevail in the court on its regulations. 

Ideas to surface at the July public meetings included offering more incentives and loan programs for ZEV buyers, expanding hydrogen-vehicle infrastructure or offering pooled insurance programs for car share fleet operators. 

Others emphasized the need for approaches that don’t require a federal waiver. 

ZEV Sales Growth

In the second quarter of 2025, 21.6% of new vehicles sold in California were ZEVs, amounting to 100,670 vehicles, the California Energy Commission (CEC) reported. That number is lower than sales in the second quarter of 2024. 

The dip in sales was driven by lower Tesla sales, while non-Tesla ZEV sales remained strong, the CEC said. 

At the national level, EV sales in the first half of 2025 were up 1.5% year-over-year, with 607,089 vehicles sold, according to a report from Cox Automotive’s Kelley Blue Book. Second-quarter figures were down 6.3% year-over-year. 

“With government-backed incentives set to end in September and economic pressures mounting, the second half of the year will be a critical test of EV demand,” Stephanie Valdez Streaty, senior analyst at Cox Automotive, said in a statement. “Q3 will likely be a record, followed by a collapse in Q4, as the electric vehicle market adjusts to its new reality.” 

For medium- and heavy-duty trucks in California, manufacturers sold 131,552 vehicles from model year 2024. Of those, 30,026 were ZEVs, or 22.8%. Cliff provided the figures during CARB’s July board meeting. 

And manufacturers have accumulated about 26,000 more ZEV credits than are needed to comply with ACT, he said. 

Coalition Formed

California is not alone in its ZEV efforts. 

In May, Newsom and governors of 10 other states launched the Affordable Clean Cars Coalition, an initiative organized by the U.S. Climate Alliance. The goal is to make cleaner vehicles more affordable and accessible by reducing costs, increasing options and expanding infrastructure. 

Participants are California, Colorado, Delaware, Maryland, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island and Washington. 

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Exelon Continues to Explore Getting Back into Generation

Exelon reported earnings of 39 cents/share for the second quarter as it deals with a large pipeline of new data centers and rising wholesale prices that are costing its customers across its six utilities, all in PJM.

“We have remained very active across a variety of federal and state proceedings to solve an ever-evolving set of opportunities to better serve our customers and advance our state’s energy and economic goals,” CEO Calvin Butler said on an earnings call held July 31.

The Illinois legislature examined a broad omnibus energy bill this session that would have affected transmission, energy storage, efficiency and resource planning efforts but ultimately did not pass it.

“The process offered us and other stakeholders the opportunity to discuss critical issues, and we remain optimistic that Illinois will continue to lead the nation in advancing progressive, constructive legislation that enables effective partnership across private and public entities,” Butler said.

Other states like Pennsylvania and New Jersey are looking into ways to expand their power generation supplies as PJM’s market is increasingly tight, which could allow Exelon and other utilities to own generation. Butler indicated Exelon was interested in utility-owned generation in an earlier earnings call, but he offered more details this time. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.)

Through the recently enacted Next Generation Energy Act, Maryland is seeking over 3,000 MW in new supply through a competitive process beginning in October. COO Michael Innocenzo told analysts if that falls short, it could present an opportunity for utility-owned generation.

“It’s clearer now than ever that states should be thinking broadly about how to secure the energy futures for our citizens,” Butler said. “Exclusive reliance on PJM enabled low and relatively steady supply costs for its customers in a period of low demand growth, and when states weren’t yet facing significant turnover in their generation-supply driven by economics, policy and technology.

“But the volatility and unpredictability we are seeing in supply costs, along with a steady increase in warnings from institutions like NERC and [the U.S. Department of Energy] is undermining the faith in the status quo. Despite higher prices, we are not seeing the market respond fast enough. We saw some new generation entry, but demand growth was double that amount.”

Demand response is one of the quickest to market supply options, but despite the tightening supply-demand balance in PJM, the number of megawatts bid into the market fell this past auction, Butler said.

“Bigger, longer-term fixes are available with legislative action, and we stand ready to be part of that solution,” Butler said. “We look forward to continuing the dialogue with our states to be a part of the solutions to ensure energy is delivered reliably and cost-effectively, in a manner that best suits their goals. Time remains of the essence in adding supply to the grid.”

Exelon has 17 GW of large loads in its pipeline looking to connect to the grid (with deposits already paid), and an additional 16 GW are in advanced planning stages but not quite as far. Its Commonwealth Edison subsidiary in Chicago is holding another cluster study window in August, in which several gigawatts of additional projects have shown interest.

Exelon used to be a major player in the power markets with the country’s largest nuclear fleet and a large retail business, but all of that was spun off into Constellation Energy in 2022. If Exelon and other utilities are successful in directly owning generation, Butler said the market would still have a role to play.

“We will continue to partner with PJM, but we do see it as an ‘and’: The competitive markets and regulated generation being part of the solution,” he said.

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Gov. Newsom Proposes Additional $18B for Calif. Wildfire Fund

California Gov. Gavin Newsom is promoting legislation that would add billions of dollars to California’s utility wildfire fund after deadly fires destroyed more than 18,000 homes in the Los Angeles area in January.  

Of the proposed $18 billion, $9 billion would be paid for by utility customers and the other $9 billion by shareholders of each participating utility in the fund. Customer contributions would come from a 10-year extension of an existing non-bypassable charge on customer electric bills that currently expires in 2035, the governor’s office told RTO Insider. 

“This is an existing charge, so customers will not experience an increase in their bills from this proposal, while shareholders will be required to immediately commit to collectively contribute an additional $9 billion,” Newsom’s office said. 

“We continue to work with the Legislature on policy that will stabilize California’s Wildfire Fund to support the recovery of wildfire survivors and to protect California utility consumers — even as wildfires become bigger and more destructive due to climate change,” Newsom’s office added in a separate statement. 

The L.A. wildfires created significant uncertainty regarding the adequacy of the wildfire fund “to protect against electrical corporation bankruptcy risks and undermined confidence in the financial stability of the state’s electrical corporations,” the draft legislation says. 

“The prospect that electrical corporations and their customers could be required to bear, on an ongoing basis, losses of the magnitude of those wildfires is unsustainable,” the draft says. 

Financial markets are demanding higher costs for capital to account for the increased risk of investing in or lending to California’s electric companies, which increase electricity rates, the draft says. The wildfire fund’s durability is “being further compromised by hedge funds and other speculators seeking to profit from the fund,” the draft says.  

After the January 2025 wildfires, some insurance companies sold their subrogation rights to private equity and hedge funds, which “profit by demanding even higher recovery than the insurance companies, draining the wildfire fund’s resources and capacity to pay fire victim claims,” the draft legislation says. 

The draft legislation is supposed to stop hedge fund speculation by capping insurance subrogation claims at 40%, the governor’s office said. 

The state’s wildfire fund began in 2019 after years of deadly fires ignited by Pacific Gas and Electric’s equipment sent the utility into bankruptcy court. The wildfire fund is financed by PG&E, Southern California Edison (SCE), San Diego Gas & Electric and California electricity ratepayers. 

Of the L.A. fires, the Eaton Fire and the Palisades fire were the two most destructive. The L.A. County Fire Department and the California Department of Forestry and Fire Protection (Cal Fire) are still investigating the cause of the Eaton fire, but videos of the fire’s early stages suggest a possible link to SCE’s equipment, SCE representatives said in February. (See SCE Probes Link Between Equipment and Eaton Fire.) 

On July 23, SCE announced a new wildfire recovery compensation program for victims of the Eaton Fire. The program is expected to operate through 2026, a company press release said. 

Separately, the California Public Utilities Commission (CPUC) on July 28 issued a proposed decision that approves SCE’s 2025 general rate case to increase customer bills by $16.15 per month on average. A significant portion of the rate case is for capital expenditures for wildfire reduction risk purposes — about $5.1 billion for wildfire mitigation work from 2025-2028, the proposed decision says.  

The CPUC decision approved about $3.1 billion of the request, “reflecting our judgment that the long-term benefits of these investments justify the costs,” said CPUC administrative law judges Colin Rizzo and Ehren Seybert, who co-wrote the proposed decision. 

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NYISO Drops Seasonal CAFs from Winter Reliability Project

ALBANY, N.Y. — NYISO surprised stakeholders July 29 when, as part of an update on where it was with the Winter Reliability Capacity Enhancements project, it revealed it was no longer considering seasonal capacity accreditation factors (CAFs) because it found they would disincentivize participation in the capacity market.

“We are pretty set on retaining annual CAFs for this project,” Alexis Drake, a senior market design specialist for NYISO, told the Installed Capacity Working Group.

The Winter Reliability project is an initiative by the ISO to consider changes to the capacity market to reflect New York’s transition from a summer-peaking system to a winter-peaking one, and resource adequacy becomes more of a concern in the latter season.

CAFs — which represent the reliability contribution of different resource types, expressed in percentages — are set annually for each capability year. NYISO had considered setting them biannually instead, with winter and summer figures, as part of a broader move toward a seasonal capacity market. Because CAFs historically hinge on the annual loss-of-load expectation, and New York has historically been a summer-peaking system, the figures are more representative of resource adequacy contributions during the summer.

But Drake’s presentation did not contain NYISO’s reasoning for maintaining annual CAFs, leading to attendees expressing frustration and demanding an explanation.

Mike Cadwalader, president of Atlantic Economics, said that working groups are supposed to be the forum where market design, rules and policy are discussed in the open and that he did not appreciate that, according to him, NYISO has been presenting “take it or leave it” proposals.

“This is the first time the ISO has presented its proposal not to do seasonal CAFs, and it’s a pretty compressed discussion,” Cadwalader said. “What you have done is you’ve gone off for the last few months to think about it among yourselves. You have not been discussing with market participants.”

Other stakeholders said they would appreciate a presentation of NYISO’s thinking and internal discussions on seasonal CAFs. Cadwalader and Doreen Saia, chair of Greenberg Traurig’s natural resource practice, asked NYISO to present its thinking quickly so that stakeholders could understand where the ISO was coming from before discussions of tariff revisions occur. Cadwalader said that rushing to tariff revisions before conceptual agreement was “putting the cart before the horse.”

Drake said that from the ISO’s perspective, implementing seasonal CAFs might cause price volatility and disincentivize certain kinds of generators from participating in the market all year. If a resource, like a non-firm gas generator, received a 0% value for a seasonal CAF, there would be no incentive for it to participate in that season.

“We felt it would disincentivize participation, which is not what we are trying to achieve,” Drake said.

The other elements of NYISO’s update did not draw as much attention. The ISO is considering requiring External-to-Rest-of-State Deliverability Rights and Unforced Capacity Deliverability Rights holders to submit distinct seasonal elections for the winter and summer capability periods. These seasonal elections would be subject to a must-offer requirement. To participate in the capacity market during that capability period, the holders would need to offer capacity during the periods they are participating in.

NYISO is also proposing to expand the existing New York Control Area minimum ICAP requirement to develop seasonal requirements. These would still be based on the Installed Reserve Margin study. Seasonal transmission security limits and winter locational minimum installed capacity requirements would also need to be implemented.

With seasonal minimum ICAP requirements, the current seasonal capacity adjustments on the demand curve would not be required because the seasonal requirements directly represent the capacity needed to maintain reliability. NYISO will review the demand curve parameters again to see if any additional adjustments are needed.