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December 11, 2025

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Eddystone Ordered to Remain Operational for PJM 90 More Days

The U.S. Department of Energy has issued another emergency order keeping Units 3 and 4 of the Eddystone Generating Station in Pennsylvania in operation. 

The dual-fuel, 380-MW subcritical steam boiler-turbine generator units are 55 and 58 years old, and Constellation Energy had scheduled them for retirement May 31. 

But Energy Secretary Chris Wright on May 30 issued an emergency order keeping them in operation to minimize the risk of energy shortfalls in the Mid-Atlantic region. 

That order was to expire the evening of Aug. 28. Wright issued the follow-up order to Constellation Energy and PJM the evening of Aug. 27. 

In an Aug. 28 news release, he said keeping Units 3 and 4 operational has improved energy security in the PJM region. He pointed to the June and July heat waves, when PJM called on the two units to generate electricity. And he said the emergency conditions that led to his first order persist. 

The new order continues until Nov. 26. 

PJM spokesperson Jeff Shields described the order as a “prudent, term-limited step” to keep Eddystone operational. 

“PJM has previously documented its concerns over the growing risk of a supply-and-demand imbalance driven by the confluence of generator retirements and demand growth. Such an imbalance could have serious ramifications for reliability and affordability for consumers,” he wrote in an email. “PJM supports the U.S. Department of Energy’s extension of its order, originally issued May 30 pursuant to Section 202(c) of the Federal Power Act, to defer the retirements of certain generators operating in PJM’s footprint, which spans all or part of 13 states and the District of Columbia.” 

FERC approved a PJM filing to allocate the costs across all RTO load that Constellation incurs keeping Eddystone operational. But that proposal was effective only until Aug. 28. Stakeholders are working toward a longer-term solution for addressing cost allocation for DOE emergency orders through the DOE 202(c) Cost Allocation Senior Task Force. The RTO did not answer questions about whether another Critical Issue Fast Path (CIFP) process is expected to be required for costs under the latest DOE order. (See FERC Approves Cost Allocation for Eddystone Emergency Order.) 

President Donald Trump, Wright and other administration officials have been pushing to halt retirement of gas- and coal-burning power generation facilities as part of their pro-fossil, anti-renewable campaign for American energy dominance, saying a power generation crisis is developing. 

Wright also blocked retirement of the J.H. Campbell coal-burning plant in Michigan in May and issued a follow-up order Aug. 20 extending its potential operation for another 90 days. 

Wright also lifted annual run-hour restrictions on the H.S. Wagner Generating Station Unit 4 in Maryland in July. 

In both cases, Wright cited a shortage of generation capacity.

Constellation said it is prepared to continue operating Eddystone into the fall.

“Constellation is continuing to work with the Department of Energy and PJM in taking emergency measures to meet the need for power at this critical time when America must win the AI race. Constellation will continue to operate Eddystone Units 3 and 4 during the fall,” Constellation said in a statement about the order.

These orders and others issued by Wright are under authority of Section 202(C) of the Federal Power Act, which historically has been an obscure provision but is seeing more frequent use in the second Trump administration. 

The Biden administration issued 11 emergency orders under Section 202(c) in four years, all weather-related. With the Eddystone order, the Trump administration has issued eight orders and two extensions in a little more than four months.

Environmental groups and others have railed against the orders, calling them unnecessary, expensive and causing further pollution.

The DOE order “undermines our energy security and endangers public health and the environment,” Tracy Carluccio, deputy director of the Delaware Riverkeeper Network wrote in a statement.

FERC decided that “the cost of keeping the plant open can be charged to consumers, compounding the harm to our communities who have to now pay to be polluted,” Carluccio added.

“The order should be rescinded and the company should rightly refuse to comply with it,” Carluccio wrote. Pennsylvania Gov. Josh Shapiro (D) “should intervene to stop this egregious order to protect the public and the environment from any further pollution from Eddystone. Anything less makes Pennsylvania and the company complicit with the human health and environmental harms being caused.”

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Solar and Battery Cheaper than Gas, Jefferies Finds

Investment bank Jefferies’ latest analysis finds that the levelized cost of solar-plus-battery storage is cheaper than that of gas, saying slow turbine deliveries and inflationary equipment pricing make the renewable alternative an “attractive” opportunity as data centers drive demand. 

Jefferies’ analysis for combined-cycle gas turbines shows levelized cost of energy (LCOE) at $87/MWh, while paired solar-plus-four-hour battery energy storage systems have a levelized cost of $77/MWh, despite several obstacles ahead, the investment bank said in an Aug. 27 research note. 

The renewable alternative still will be cheaper at $83/MWh even after new rules on foreign entities of concern (FEOC) become effective in 2026, according to Jefferies. The rule is intended to prevent tax credits from going to companies owned or controlled by entities tied to China, North Korea, Iran or Russia. (See Tax Credit Phaseout Threatens Projects, Jobs in New England.) 

“Given the elongated delivery timelines for turbines coupled with inflationary equipment pricing upending project economics, we see attractive solar+battery development opportunity with [investment tax credits] relatively intact,” the bank said. 

Jefferies’ analysis follows the Trump administration’s tightening of tax credit rules on new wind and solar construction. However, the new guidance was not as strict as many in the industry had feared. (See IRS Guidance on Wind and Solar Credits Not as Bad as Feared.) 

To establish eligibility for tax credits under the new rules, developers now must show that significant physical construction has been started before July 5, 2026, proceeded continuously and was completed within four calendar years. 

Jefferies said in its update that the “optimum route for developers” is to procure Chinese solar and BESS and claim the base 30% tax credit, while forgoing a 10% tax incentive aimed at promoting U.S.-sourced materials. 

“Going into 2026 once FEOC kicks in, we estimate the ideal route is to procure U.S.-made solar panels, but Chinese batteries (still competitive vs. U.S. due to reliance of U.S. on Chinese supply chain) thus claiming ITC+domestic content adder on solar only,” Jefferies said. 

The bank added that FEOC, tariffs and other potential levies related to national security concerns “will be a major swing factor in our equation.” 

Gas plants have timelines of five to six years, given slow turbine deliveries, while renewables have much faster deployment cycles, according to Jefferies. This can give paired solar and batteries the upper hand as data centers continue to drive power demand, the bank said. 

“With gas equipment increasingly inflationary, while renewable technology continues to improve AND get cheaper (holding tariffs constant), we see hybrid generation as an increasingly viable solution to meet power demand/supply gap on a timely basis,” Jefferies contended. “As data centers begin to explore paths to work with interruptible service (which is happening), expect these tailwinds to strengthen.” 

Jefferies’ report is consistent with findings published in June by financial advisory firm Lazard. (See Lazard: Solar and Wind Retain Lowest LCOEs.) 

Lazard concluded that wind and solar are the least expensive new-build power generation for the 10th year in a row, while new gas-fired generation has hit a 10-year high, with equipment shortages expected to drive further increases. 

“Batteries are not fungible equivalents to gas alternatives — they are simply just available ‘today,’” Jefferies said in its note. “We are seeing wider adoption from geographic perspective (Midwest/etc.) to help accelerate data center timelines. Core markets (TX/CA), however, appear to offset meaningful growth elsewhere for storage. What’s more is the low cost of Chinese alternatives could yet incent developers to side-step the ITC altogether, given procurement impediments to qualify for [One Big Beautiful Bill Act] benefits.” 

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NRG, PJM IMM Disagree on LS Power Deal’s Market Power Impact

NRG Energy is pushing back against arguments from PJM’s Independent Market Monitor (IMM) that its deal with LS Power would increase market concentration in the RTO and needs to meet conditions before FERC approval (EC25-102).

In an earlier protest, the IMM called for bidding limits on generation and demand response resources. (NRG will acquire CPower in the deal.) Those resources have grown in importance as the supply-demand balance in PJM has narrowed. (See PJM Monitor Calls for Bidding Limits on NRG Generation, DR in LS Deal.)

NRG told FERC in an Aug. 7 response that its deal to buy power plants and a DR aggregator from LS Power would not have an adverse impact on PJM. NRG filed a delivered price test (DPT) and updated analysis from economist John Morris. As in past proceedings, the IMM proposes conditions that are directed at the effectiveness of the PJM markets and mitigation measures as a general matter that goes beyond FERC’s normal merger review process, NRG said.

The DPT analysis from Morris “showed that the transaction will have no adverse effect on competition in PJM or any relevant or potentially relevant PJM sub-market,” the firm said. “Indeed, while applicants are not required to show that the transaction will enhance competition, the DPT analysis shows that the transaction would actually reduce concentration in the PJM market and all relevant or potentially relevant sub-markets in most time periods.”

FERC staff posted a deficiency letter Aug. 13, seeking more information on the deal, including questions about whether demand response resources were included in the horizontal market screens for PJM and NYISO. Staff asked other questions about data NRG submitted around generation.

The IMM filed an answer Aug. 27 arguing that NRG failed to rebut findings that its structural market power would grow with the deal as measured by the “three pivotal supplier [TPS] test.”

“NRG applicants should not be permitted to exercise market power, and the transaction should not be approved without reasonable measures to protect the public interest in competition and competitive market outcomes,” the IMM said.

The deal will increase market power in sub-markets of PJM, and NRG misstates the deal’s impact on the concentration of ownership in demand response, the IMM said.

“The applicants must provide record support for a finding that a transaction is consistent with the public interest,” the IMM said. “Showing that a transaction has net positive benefits for competition would provide evidentiary support … consistent with the public interest finding. Showing that a transaction does not harm competition is the minimum. No transaction can be approved under the applicable standard if it harms the public interest.”

NRG pushed back by saying the IMM failed to provide enough evidence backing up its “alternative competitive analysis” and instead relies on a dataset that is not available to NRG or the public.

“Over and above the unfairness to applicants of accepting such an analysis, doing so would create massive regulatory uncertainty extending beyond this proceeding as entities considering transactions involving assets in the PJM market would be left with no way of evaluating, in advance, whether those transactions could even potentially be deemed to present competitive issues,” NRG said.

Morris’ initial analysis argued that the deal essentially will flip the supply positions of NRG and LS Power in PJM, with very little change in market concentration. NRG would grow from 1.2% of supply to 5.4%, but LS’ share falls from 6.5% to 2.4%, resulting in lower market concentration across the RTO.

The IMM and consumer advocates ignore the second part of the deal, NRG said, focusing on NRG’s growth and ignoring the shrinking supply of LS Power, which will remain as a competitor in PJM.

While FERC previously said it does not rely on the TPS test for analysis of mergers, NRG noted that even so, the market already has rules in place when a firm fails the TPS test — when its generators are dispatched for constraint control, the unit is dispatched at the lower of the cost or price offer, NRG said.

While FERC has said it does not condition approval of mergers on the TPS test, it has never said the Monitor’s analysis is irrelevant or uninformative, the IMM said.

“The transaction creates new opportunities and/or enhances existing opportunities for NRG to raise energy market prices (LMP) to the benefit of its generation through economic or physical withholding because PJM needs NRG’s supply to manage transmission constraints,” the IMM said. “The transaction creates new opportunities for NRG to raise capacity market prices, and energy market prices on peak days, by significantly increasing ownership concentration in PJM demand response resources. Both areas of concern are relevant to the transaction.”

NRG also pushed back on worries about DR — noting the resource does not operate as a separate product in PJM and is bid into its markets alongside generation.

“Moreover, even as to measures of who controls demand response, the figures provided in the IMM report are misleading, because as Dr. Morris indicates, curtailment service providers, like CPower, are just ‘intermediaries between retail customers and PJM,’ and it is the retail customers that ‘control whether demand response will be provided and, if accepted as a capacity resource, whether they will perform,’” NRG said.

“It is also the case that demand response represents a small percentage of the total capacity in the PJM market. What appears to concern the IMM is not increased concentration in some imagined demand response market but instead perceived inadequacies in the rules governing demand response participation in the broad energy, capacity and ancillary services markets.”

The IMM said that was wrong and PJM’s own tariff defines Curtailment Service Providers as market participants.
“This is an incorrect and misleading characterization of how demand response works in the PJM markets,” the monitor added. “CSPs are market participants that control market strategy, control market offers, and hold the responsibility for demand response performance in the PJM markets.”

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Stakeholders Mixed on ISO-NE Prompt Capacity Market Proposal

As the first phase of ISO-NE’s capacity market overhaul nears its final form, New England stakeholders remain mixed on the proposed move from a forward to a prompt capacity auction.  

While the second phase of the RTO’s capacity auction reform (CAR) project — centered on capacity accreditation changes and splitting capacity commitment periods (CCPs) into seasonal periods — likely will draw more attention, the prompt changes still would cause a major shift in the region’s approach to procuring capacity and could have significant effects on market outcomes.  

ISO-NE’s proposed transition from a forward capacity market, with auctions held more than three years before each capacity commitment period (CCP), to a prompt capacity market, with auctions less than a month prior to each CCP, requires significant changes to the RTO’s rules regarding resource entry and exit from the market.  

In a prompt market, new resources would need to prove they are fully operational to gain a capacity supply obligation (CSO), and resources under development would have no guarantee of future capacity revenues until they come online.  

This also would affect the costs resources are allowed to include in bids: generators could include only incremental costs associated with assuming a CSO in their bids and not include development costs that already have been incurred.  

The shift to a prompt market also would significantly affect ISO-NE’s rules for retiring resources. The RTO currently processes retirements in the capacity auction process, providing the region with about four years’ advanced notice on retirements. In a prompt auction format, ISO-NE has proposed decoupling the retirement process from the capacity auction process and would require retiring resources to submit a binding deactivation notice one year prior to the relevant CCP.  

The effects these changes will have on resource entry and exit is unclear; while some NEPOOL members are optimistic the new auction format will more accurately reflect the capacity available to the region in each CCP, stakeholders also have expressed concern it will create challenges for resource development and could lead to more prolonged reliability must-run (RMR) agreements.  

Tom Kaslow, chief market policy officer at FirstLight Power, said the prompt proposal “appears to present both improvement and concern.” 

He said the requirement for resources to be fully operational before participating in auctions will eliminate market distortions caused by new resources that gain CSOs in the forward capacity market but fail to come online in time to meet their obligation.

However, he said it is unclear how this requirement will affect the ability to develop new resources that lack long-term power purchase agreements with states or utilities. 

“The prompt auction framework also raises questions regarding the extent to which existing resources will be able to reflect their going forward costs, such as major maintenance, in capacity auction offers,” Kaslow said. “In addition, if the cost of new entry is sunk before a new resource’s first capacity auction opportunity and existing resources face difficulty in reflecting the full extent of their going forward costs, the market could face greater volatility where sizable exit and entry occur.” 

Some stakeholders also have raised the concern that ISO-NE’s proposal could increase reliance on long-term state power purchase agreements to ensure resource adequacy. 

This concern is not universal, however, and one representative of a renewable energy company expressed optimism that a prompt market would lower risks for solar and storage developers, as they would not have to commit to a CSO years prior to their commercial operations date.  

ISO-NE said in a statement that the prompt auction format “allows new resources to sell capacity as soon as they are operational and no longer have to predict their commercial date three years in advance.” 

“We generally expect that capacity revenues are just one piece of a project’s economics that developers consider in addition to the expected energy and ancillary services a resource can contribute over the project’s lifetime,” ISO-NE added. “The capacity revenue for a single year comprises only a small portion of these expected lifetime revenues.” 

Some NEPOOL members have argued ISO-NE’s proposed one-year notification timeline for resource retirements could increase the length of reliability-must-run agreements if retiring resources trigger reliability issues, saying that developing a reliability solution within a year would be challenging.  

ISO-NE initially proposed a two-year retirement notification timeline, but reduced it to one year, saying a shorter timeline “allows resources to consider as much relevant information as possible, maintaining as much option value as possible, hence improving the probability of efficient deactivation decisions.” 

At the NEPOOL Markets Committee (MC) meeting in August, the RTO acknowledged “the shortened notification timeline may increase the duration of a reliability retention.” 

“However, the improvement in a resource’s assumptions about future market prices and operating conditions may prevent a premature deactivation, thereby potentially eliminating the need for a reliability retention,” said ISO-NE analyst Kevin Coopey. 

Unclear Effects on Market Outcomes

Multiple stakeholders emphasized the difficulty of forecasting how the prompt changes will affect market outcomes, especially when coupled with the seasonal and accreditation changes. The two phases of CAR will be filed separately with FERC but both are intended to take effect for the 2028/29 CCP.  

The Massachusetts Attorney General’s Office (AGO), which advocates for the state’s ratepayers, has asked ISO-NE to provide quantitative analysis on the prompt proposal, but the RTO has provided little information on how the updated proposal would affect market outcomes.  

ISO-NE commissioned Analysis Group to conduct a preliminary analysis in late 2023 on a prompt-seasonal market. The findings indicated that, relative to the existing forward capacity market, a prompt-seasonal format would reduce total capacity payments by about 12% and that the prompt changes alone would reduce total costs by about 10%. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.) 

In a recent statement, ISO-NE said this analysis demonstrated “numerous benefits to consumers and suppliers, as well as market efficiency gains, which helped inform the decision to pursue the Capacity Auction Reforms.” 

The RTO plans to conduct a comprehensive impact analysis during the second phase of the CAR project, allowing it to quantify the effects of both the prompt and the seasonal/accreditation changes.  

In a recent interview, the Massachusetts AGO said it has been closely following the proposed resource entry and exit changes associated with a prompt auction, but added it lacks clear insight into how the changes will affect prices, and is eager to see more specific numbers on the expected impact of the proposal.  

Other consumer advocates in the region expressed a similar interest in better understanding how the changes will affect costs for ratepayers. 

Matthew Fossum, director of regional and federal affairs at the New Hampshire Office of the Consumer Advocate, emphasized the importance of ensuring the shift to a prompt market “does not create for New England the kind of issues that we have seen recently in other regions, particularly PJM.” 

“With the long lead times and supply chain we are hearing about for investments in generation resources, and with the uncertainty around state and federal policies at present, we need to be thoughtful about the reforms that shorten the time frame for capacity auctions so New England does not end up designing markets that land us in the same unwelcome place,” Fossum added. 

Connecticut Consumer Counsel Claire Coleman said she hopes transitioning to a prompt auction “will reduce costs for consumers by removing some of the risk that suppliers build into their capacity auction bids” and “will make it easier to bring new energy supply online and facilitate more accurate modeling of what generation assets are available for use within the region.” 

However, she acknowledged the impact on consumers “remains to be seen” and said the Office of Consumer Counsel is approaching the capacity market overhaul “with the hope that some of these changes will result in bills reductions for consumers down the road.” 

Next Steps

In a memo Aug. 20, ISO-NE announced a one-month delay to the NEPOOL voting schedule for the prompt proposal and now plans to seek a vote at the MC in November and the Participants Committee in December. The RTO said this delay will not affect the timeline for commencing work on accreditation.  

Several NEPOOL members said they are anxious to get started with the work on the seasonal/accreditation changes, which almost certainly will be the more controversial phase of the project, and ultimately may have a riskier path to approval with FERC if the RTO is unable to build a broad consensus.  

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New Study Highlights Winter Benefits of OSW in New England

The addition of 3,500 MW of offshore wind capacity would have reduced ISO-NE energy market costs by about $400 million over the past winter, according to a recent study by Daymark Energy Advisors. The study also found the added capacity would have eliminated $128 million in costs associated with a higher capacity price in the Southeast New England capacity zone.

The study, sponsored by clean energy association RENEW Northeast, comes in the wake of the Trump administration’s stop-work order on Revolution Wind, a 704-MW project contracted by Connecticut and Rhode Island that is estimated to be 80% complete. (See BOEM Slaps Stop-work Order on Revolution Wind.)

“This study shows that delays in bringing offshore wind projects online are costing New England families and businesses real money,” said Francis Pullaro, president of RENEW Northeast.

Daymark used historical weather data to estimate the offshore wind production profile over the past winter and compared this forecast production with ISO-NE real-time energy offer data. The firm estimated that the added wind resources would have contributed 3.6 billion kWh of electricity over the winter months, reducing the need for high-cost fossil units. The study also found that the wind resources would have reduced carbon emissions by about 1.8 million tons.

In the capacity market, Daymark noted that a shortage of capacity cleared in the Southeast New England zone caused a higher clearing price ($3.98/kW-month) than the rest-of-pool (ROP) price ($2.611/kW-month). It said the injection of 3,500 MW of offshore wind would have avoided this issue, saving $128 million in capacity costs by substituting the higher zone-specific price with the ROP price, “even after accounting for increased cost of winter excess capacity.”

“The OSW capacity would have also displaced the highest price cleared capacity in ROP, likely decreasing the ROP price,” Daymark added. “Our analysis conservatively assumes no additional savings from this likely outcome.”

New England faced high electricity prices and high consumer energy costs over the past winter due to consistently cold weather.

The region’s power sector has become increasingly reliant on natural gas over the past decade, but gas infrastructure into the region is constrained, leaving it susceptible to large price spikes during cold periods. Gas generators typically do not enter firm gas supply contracts, and gas resources often struggle with gas supply during cold periods when heating demand from gas distribution utilities is high.

According to ISO-NE, energy costs over the past winter were 147% higher than the previous winter, driven by a 179% increase in gas prices, and the total estimated wholesale market cost of electricity increased by about $2.4 billion. (See New England Energy Market Costs Grew by over $2B in 2024/25 Winter.)

The RTO has said offshore wind’s increased production profile during the winter would provide significant reliability benefits by allowing generators to conserve stored fuel. (See ISO-NE Warns Halting Revolution Wind Boosts Reliability Risk.)

However, the offshore wind industry in the region faces an uncertain future due to antagonism from the Trump administration, which has created both short-term challenges and long-term concerns about the ability to attract the investment needed for development.

“With several OSW projects already contracted but delayed, the findings underscore the urgent need to accelerate offshore wind deployment to meet both economic and climate goals,” Pullaro said.

Susan Muller, a senior energy analyst at the Union of Concerned Scientists, said the Daymark study “shows the power of offshore wind to lower energy prices in New England, especially in winter,” and added that “New Englanders need rate relief and a more reliable grid now, and President Trump’s nonsensical decision to stall a nearly completed project cannot stand.”

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Newsom Renews Call for Passage of Pathways Bill

California Gov. Gavin Newsom renewed his call for state lawmakers to pass a bill to authorize CAISO to relinquish governance of its electricity markets and allow it and the state’s utilities to participate in a new “regional organization” designed to oversee a West-wide market. 

The bill would implement the plans of the West-Wide Governance Pathways Initiative, a multistate effort to create an independent “regional organization” (RO) to govern CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market (EDAM), the latter set to launch in 2026.  

“I’m calling on the Legislature to pass a viable proposal to expand regional power markets — it’s our best shot at affordability this year,” Newsom said in press release Aug. 27. “Over $1 billion in economic benefits to our state is on the line, and failure to get this done will mean higher electric bills, more pollution and a less reliable power grid. Californians deserve action now to make their electric bills more affordable.” 

The statement was the first from the governor on the issue since the Legislature resumed the 2025 session Aug. 19 after a monthlong summer recess.   

Newsom’s reference to a “viable proposal” suggests it’s still an open question whether the legislation will be Senate Bill 540 — known as the “Pathways” bill — or another bill. With the legislative session set to wrap up Sept. 12, the clock is ticking on any effort to get a bill passed. 

SB 540 passed the state Senate in June on a 36-0 vote, but the bill’s first hearing in the Assembly’s Utilities and Energy Committee, scheduled for July 16, was delayed until after the summer break at the request of the bill’s author, Sen. Josh Becker (D). (See Calif. Pathways Bill Delayed After Orgs Withdraw Support, While Newsom Signals Backing for Effort.) 

Becker sought the delay after 21 organizations pulled their backing for the bill in response to an amendment that would establish a new Regional Energy Market Oversight Council charged with ensuring CAISO’s participation in the RO “serves the interests of the state.” The new council would be authorized to mandate withdrawal by the ISO and utilities if those interests are compromised.  

The organizations — which include Environmental Defense Fund, PacifiCorp, Advanced Energy United, Amazon and Portland General Electric — called the amendment “unacceptable” and asked lawmakers to remove it. 

Responding to a reporter’s question during a July 31 press conference, Newsom reiterated his previous support for the Pathways effort and praised the coalition behind SB 540, saying, “I’m not aware of a more diverse and large coalition I’ve seen on an issue of energy in some time.” The group includes labor unions and publicly owned utilities that strongly opposed past efforts to “regionalize” CAISO. 

Newsom’s Aug. 27 press release contained a link to an Aug. 13 post on the governor’s X account showing him meeting with a coalition of Pathways supporters.  

“I’m calling on the Legislature to enable the expansion of regional energy markets to lower energy costs, reduce air pollution and avoid power outages,” Newsom said in the post. 

Pathways Leader ‘Optimistic’

But the language coming out of the offices of Newsom and Assembly Speaker Robert Rivas has left open the possibility that the provisions in the original Pathways bill could be tacked on to another bill. With fewer than three weeks left in the session, SB 540 hasn’t been scheduled for an initial Assembly committee hearing. 

Still, when  RTO Insider  previously asked the two offices about the potential for other strategies that don’t include SB 540, both declined to comment, while a source in the governor’s office said Newsom would let lawmakers take the lead on the effort. 

In an Aug. 26 email to RTO Insider, Kathleen Staks, co-chair of the West-Wide Governance Pathways Initiative’s Launch Committee, noted that Newsom and Rivas have come out in “very public support” of the Pathways bill.  

“In addition, there continues to be an enormous diverse coalition in support of getting this policy done this year (entirely separate from the Launch Committee, which is not engaging in legislative efforts),” said Staks, who is executive director of Western Freedom. While the committee is not involved in lobbying, some of its California members are working to advance the bill in their other organizational capacities. 

“The bill has not yet been scheduled for a policy committee hearing in the Assembly because it has been in negotiations between the Gov’s office, Senate and Assembly, along with some other big energy issues,” Staks wrote. “The coalition continues to advocate for passing a version of SB 540 that works for the West, and we are optimistic that it will get done this year.” 

The offices of Sen. Becker and Speaker Rivas did not respond to requests for comment in time for publication of this article. 

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N.J. Plan Would Put RGGI Funds into Storage, Infrastructure

New Jersey is looking to broaden the portfolio on which it will spend hundreds of millions of dollars from the Regional Greenhouse Gas Initiative (RGGI) to include electrifying multifamily housing and accelerating investment in wind and solar infrastructure.

The state’s draft investment plan for 2026 to 2028 — known as the “Auction Proceeds Scoping Document” — also calls for investment to boost energy storage capacity and to provide incentives for development of the clean energy supply chain and manufacturing facilities.

The proposal outlines how the state, which has received a total of $922.9 million for two funding plans since it rejoined RGGI in 2020, could use its third tranche of funds. The final plan will be shaped by stakeholder input from four public hearings and other comments. The first hearing took place Aug. 21. Three more are scheduled.

Under the RGGI system, which includes New Jersey and 10 other states, the coalition sets a steadily declining regional cap on carbon dioxide emissions. Certain plants that exceed the cap must pay for a “RGGI CO2 allowance” for every short ton of CO2 emitted, and the proceeds are distributed among the participating states for use in combating climate change emissions.

New Jersey’s two earlier funding plans focused on projects to cut emissions in the transportation sector, the largest emitting category with 34% of the state’s emissions, and building electrification. While electricity generation is the second-largest category, with 17%, the three components of the building sector — residential, commercial and industrial buildings — account for 32% of the state’s emissions.

Innovation Sought

The new elements in the latest plan seek to cut that pollution, Sean Sonnemann, manager of clean energy for the New Jersey Economic Development Authority (EDA), said at the first hearing to gather input on the plan. The agency administers about 60% of the RGGI funds, while the New Jersey Board of Public Utilities (BPU) and Department of Environmental Protection each administer 20% of the funds.

“We are considering supporting multifamily buildings in the state, especially those that may not be covered by other state programs, such as corporate or cooperatively owned buildings, senior housing and public housing,” he said.

The agency also is considering “other ways to encourage the development of zero-energy new construction buildings, rather than continue with business as usual, older technologies that may be more damaging to the environment,” he said.

The BPU, meanwhile, intends to support programs such as commercial-scale geothermal projects. It also plans to support income-qualified customers who use existing energy efficiency programs to implement additional decarbonization efforts such as heat pumps, he said.

New Jersey’s emphasis on using RGGI funds to address transportation emissions continues as a key element of the third plan. The plan says the state’s number of non-private charging stations, which now stands at 4,400, increased 30 to 40% between 2023 and 2024. It proposes for the first time to fund the installation of EV workplace charging stations and the creation of “charging depots” for medium- and heavy-duty vehicles.

Other new elements include providing support for “managed charging programs and other capacity limiting measures” that help cut ratepayer bills by reducing energy use in peak hours. The plan also looks to “promote electric micro-transit and community mobility, public-serving vehicles and related infrastructure.”

Alternative Energy

The public airing of the plan drew a handful of speakers. One asked if the state planned to look beyond “wind, solar and batteries” to “more innovative clean energy technologies — for example, “waste heat to power.” He noted that the federal government provides a tax credit to support such projects, but the state does not.

Sonnemann, of the EDA, said the state wants to dedicate funds for non-traditional “emerging renewable and clean technologies” but has not yet put together a list of what the endorsed technologies might be. He said the intent can be found in a section of the plan that says the state could invest in technologies such as “fusion, tidal.” The section also calls for investment to create “innovation hubs and related clean energy technology accelerators” and to strengthen the clean energy supply chain.

“New Jersey has the potential to be a leader and clean energy technology exporter, by developing innovative technologies” that could be used to “decarbonize other economies across the globe,” the plan says.

Another speaker, Matt Polsky, said that given the change in attitude toward clean energy in the federal government, he felt New Jersey’s plan was insufficient.

“They have gone from being a partner to actually part of the problem,” he said of the current administration. “And therefore you really, really need to be thinking out of the box a lot more than I’ve ever seen you do over the decades.”

‘Leakage’ Concerns

The plan comes amid criticism that RGGI, having successfully pushed New Jersey to reduce or eliminate emissions from fossil fuel generators, may be hampering the state as it searches for ways to address the expected significant shortfall of generation.

Data center expansion amid fossil fuel generator retirements is exacerbated by the slow pace that new energy sources are coming online. Emissions restrictions imposed by RGGI may limit the development of some of those new sources.

Liam Baker, senior vice president for regulatory affairs at Alpha Generation, a Connecticut-based electric generation company, expressed concern at an Aug. 5 resource adequacy conference held by the BPU that while RGGI had been “very successful” at cutting emissions, it now is “increasing PJM-wide emissions by millions of tons while costing New Jersey ratepayers hundreds of millions of dollars annually.”

Baker and other critics, among them Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, argue that the RGGI system causes “leakage.”

“Leakage means it’s cheaper to operate coal-fired generation in Pennsylvania and export it to New Jersey,” Baker said at the Aug. 5 conference. “It’s cheaper to do that than operate our clean in-state combined-cycle fleet.”

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Hepper Replaces Cupparo as SPP Board Chair

SPP said Aug. 27 that Vice Chair Ray Hepper has been serving as the Board of Directors’ chair since Aug. 12. 

Hepper replaced John Cupparo, who is stepping away from the position’s time commitments because of personal reasons, SPP said. 

Cupparo was not present for the board’s August meeting, but did call in. He was elected to the board in 2022 and became chair in 2024. He plans to continue participating in the Strategic Planning and Corporate Governance committees and Interim Markets+ Independent Panel. 

The RTO said it will announce a new vice chair before October. 

Hepper has more than 30 years of experience in the electric utility industry. He served as ISO-NE’s general counsel until retiring in 2018. He also represented California in restructuring the billions of dollars’ worth of power contracts entered into during the 2000 energy crisis. 

Hepper briefly served on ERCOT’s board in 2021. However, state law following that year’s Winter Storm Uri required that the ISO’s independent directors all reside in Texas. 

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State-level Efforts to Limit Renewables Blunted in 2025

Proposals that would negatively affect renewable energy far outnumbered supportive legislation introduced in state legislatures in the first half of 2025, Clean Tomorrow reports. 

But of the 305 bills in 47 states tracked by the clean energy advocacy organization’s Siting Solutions Project, only 39 have been signed into law or are still pending — 10 of them permissive and seven restrictive. 

Clean Tomorrow brought the details together in its new report “The State of Siting: 2025 Legislative Roundup.” 

Not surprisingly, the report flags a stark partisan divide among those making the proposals: Restrictive legislation proposed by Republicans outnumbered their permissive proposals by a 9-1 ratio. Democrats authored substantially fewer proposals, but their supportive measures outnumbered their restrictive measures by a 2-1 ratio. 

Both parties proposed a similar number of bills judged likely to have a neutral or ambiguous effect, such as through small procedural or technical adjustments. 

Notably, the small number of bipartisan proposals were more evenly split between restrictive, neutral and permissive. But 40% of them became law — twice the percentage of Democratic proposals and four times the percentage of Republican proposals enacted. 

The greatest number of restrictive bills involved increasing the number and types of local approvals required for renewable energy proposals — a frequent rallying cry for home rule advocates and clean energy opponents, and a potential quagmire for developers. 

Other common restrictive policy proposals entailed: 

    • increasing local zoning authority; 
    • expanding setback requirements; 
    • imposing financial security mandates; 
    • extended notification and hearing processes; 
    • limits on siting on agricultural land; and 
    • limits on development on public lands. 

Solar, storage and wind development has been a divisive subject for years and became more polarizing as President Joe Biden guided a massive renewables funding package into law and President Donald Trump cranked up the anti-renewable rhetoric as part of his second-term pro-fossil energy dominance initiative.

In its Aug. 22 announcement of the legislative analysis, Clean Tomorrow cited a June report by the Pew Research Center that contrasted results of 2016 and 2025 surveys. 

Wind and solar had been the types of energy development most heavily supported by Democrats and Republicans alike surveyed in 2016 and remained the most favored by Democrats in 2025, Pew said. But wind and solar are now Republicans’ least-favored option, behind nuclear, offshore drilling, hydrofracking and coal mining. 

Clean Tomorrow noted the importance of state-level policies in determining the future of the nation’s clean energy economy and said the 2026 legislative season will help clarify whether the flurry of restrictive proposals in 2025 is more than a temporary backlash. 

The report predicts significant siting legislation will advance in Colorado, Indiana, Louisiana, Oklahoma, Pennsylvania and Virginia in 2026, and summarizes the issues. 

It also breaks down specifics on 2025 developments in key states. 

Other takeaways from the report include: 

    • Restrictive legislation is most common in states that have had the largest wind and solar generation additions. 
    • Opponents tried to repeal or weaken permissive siting reforms that several states had enacted in the past four years. 
    • Texas, Illinois and New York led the nation in number of legislative proposals; restrictive measures outnumbered supportive measures by a wide margin in all three states, but New York saw a much larger percentage of neutral proposals than Texas or Illinois. 
    • Siting and permitting reforms that are technology-agnostic fare better in states with at least one Republican legislative chamber but tend to be opposed by environmental advocates because they smooth the path for new natural gas infrastructure. 
    • In 2025, Texas saw the nation’s greatest number of restrictive legislative proposals, some of which had the potential to eviscerate the renewable energy industry there. But only three of 32 measures became law, and they carried only modest changes. 
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Texas RE Speaker Discusses Cyber Recovery Obligations

With threat actors becoming more aggressive and sophisticated in their tactics, companies must be prepared for hard decisions after a data breach, a cybersecurity lawyer told attendees of a webinar hosted by the Texas Reliability Entity. 

Speaking at Texas RE’s regular Talk with Texas RE event Aug. 26, Rebecca Jones, a partner at cybersecurity-focused law firm Mullen Coughlin, said over the past three years, the firm has seen a steady rise in the number of data breach incidents it handles — from just under 3,000 incidents in 2022 to more than 4,200 in 2024. In the first six months of this year Mullen Coughlin dealt with more than 2,100 incidents. 

The most common type of event that Jones and her colleagues have dealt with since 2022 is a business email compromise. These attacks, constituting 34 to 38% of the firm’s business each year, involve malicious actors gaining control of an official company email and using it to trick real employees into sharing sensitive information or credentials. 

Ransomware is the next most common incident type, with 23 to 26% of events handled each year. Jones said this style of attack has become more elaborate recently, with a growing incidence of what the firm calls “double extortion” — cases in which the threat actor encrypts a target’s files so that they are inaccessible until a ransom is received, while also copying the data to use for their own ends. 

“Threat actors [are] increasingly becoming more aggressive with their victim companies and engaging in harassment tactics to get them to pay the demand, or at least to engage in negotiations,” Jones said. “That might look like a threat actor calling employees, calling the CEO, calling board members on their cell phones, letting people know that there has been an attack and … threatening to expose data publicly, on the dark web or on the regular internet.” 

In any incident, Jones said victims need to be ready to protect their interests; the incident response team is “really the meat and potatoes of the firm,” accounting for most of the attorneys there. She presented a potential “road map” for such a scenario, outlining steps the firm’s clients have taken from the beginning to the end of the process.  

The map starts with the detection of a compromise, followed by mobilizing the victim’s incident response team and following its process for restoration of data if necessary. An outside forensics team may be engaged to investigate the cause of the incident. 

While the forensic investigator may also be tasked with negotiating with the attackers themselves, Jones said companies often prefer to hire a separate negotiating team with experience in such incidents. Although many companies end up paying the ransom to recover their systems, a good negotiator can usually bargain a payment down from an initial extreme figure to one that is more manageable, she explained. 

The firm will usually recommend that victims hire a public relations firm as well, ensuring that their communication is accurate and does not trigger unnecessary obligations. Companies must comply with the legal disclosure requirements, Jones emphasized, but they should also be aware of the impact that their public messaging has.  

“We don’t use the term ‘breach’ if we can avoid it … because it’s something that people will say without knowing what it means,” Jones said. “A breach means that there was unauthorized access or acquisition of legally protected information, and you have to notify individuals and probably regulators. Saying that you have a breach can imply that you have all of these obligations, so it’s not something that you would want to use at the outset of an incident when you may not even have a breach.”