The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) is calling for comments on a draft guide to help federal agencies generate or request a software bill of materials (SBOM) for their products.
SBOMs are formal records of each component used in building a software application, including its developer and supply chain. Modern applications are usually not individually coded from the ground up but built in large part from bits of code available in public or private repositories, which are often copied and pasted into developers’ projects with few changes.
This means that if one of these bits of code contains a vulnerability, it can spread quickly to customers throughout the world. This happened with Log4j, an open-source software library from Apache present in software used by companies in a wide range of industries. In December 2021, researchers discovered a weakness in the code that could be used by remote actors to take control of affected systems.
An SBOM helps to mitigate this issue by giving customers a quick, machine-readable reference for the provenance of various components. The NTIA’s guidance in 2021 “defined expectations for SBOM implementation,” CISA said in the introduction to its guidance, but with advancements in the “SBOM state of art” since then, the agency released the new document to update “baseline data fields, practices and processes for SBOMs generated or requested by U.S. agencies.”
3 Categories for Elements
Like the earlier document, CISA’s guidance separates the minimum elements into three categories: data fields, automation support and practices and processes. This organization is meant to “support an evolving approach to software transparency by capturing both the technology and the functional operation.”
Data fields provide baseline information about each component of the software application, including the developer, the component’s name, its version number, a timestamp of the most recent update to the SBOM data, any licenses under which it is made available and its relationships with other components. Some of these elements are updated from the NTIA guide for improved clarity, while others, such as the license, are new to CISA’s document.
Automation support means ensuring that the SBOM can be read as widely as possible through standardized file formats. CISA acknowledged that the decision about which format to use can vary based on factors specific to each organization and encouraged agencies to “accept any widely used, interoperable and machine-processable SBOM format,” though it also suggested readers not accept SBOMs in deprecated versions of any format in order to maintain the widest compatibility.
Elements of SBOM practices and processes include ensuring that a new SBOM is generated with each new build or release of a software application, listing all known software dependencies and identifying areas where information is incomplete, making SBOMs available promptly to those who need them and accommodating updates, including corrections to SBOM data.
The draft also provided further areas for consideration as SBOMs and their tooling continue to mature: SBOMs in cloud environments and artificial intelligence systems, validation methods for SBOM formats and correlating SBOMs with industry security advisories. CISA said continued discussion of these and other emerging issues can help ensure that the minimum elements and best practices keep up with the changing pace of industry evolution.
“[An] SBOM is a valuable tool that helps software manufacturers with addressing supply chain risks, and several best practices have evolved significantly in recent years,” Chris Butera, CISA acting executive assistant director for cybersecurity, said in a statement. “This voluntary guidance will empower federal agencies and other organizations to make risk-informed decisions, strengthen their cybersecurity posture and support scalable, machine-readable solutions.”
CISA is accepting feedback through the Federal Register. The agency said comments will be used to refine the document ahead of the final draft.
Public Service Company of New Mexico will provide $175 million in benefits to customers and the state as part of Blackstone Infrastructure’s acquisition of PNM’s parent company, TXNM Energy, according to an Aug. 25 regulatory filing.
The benefit package includes a $105 million acquisition rate credit, which would be the largest in state history, according to PNM’s filing with the New Mexico Public Regulation Commission (PRC). The credit would be paid to PNM customers over four years and would lower the average residential customer bill by 3.5%.
The filing includes a $25 million commitment to speed progress toward the state’s energy transition goals, including funding for new technologies.
Another $35 million would be used for economic development programs, such as job training in the utility industry. And $10 million, to be paid over 10 years, would go to the PNM Good Neighbor Fund for low-income customers.
By infusing funds into PNM, the acquisition would help it to thrive “in a rapidly changing energy environment,” PNM and Blackstone said in a press release.
“This transaction keeps PNM rooted in New Mexico while giving it the financial strength to transform our grid and harness the opportunities to benefit our customers and communities for decades to come,” PNM CEO Don Tarry said in a statement.
$11.5B Acquisition
TXNM Energy and Blackstone Infrastructure announced the proposed acquisition in May. In addition to PNM, TXNM owns Texas New Mexico Power, a transmission and distribution utility in Texas that serves about 280,000 customers.
Under terms of the $11.5 billion deal, Blackstone would pay $61.25/share in cash upon closing. The purchase would be funded through equity and assumption of existing debt.
The agreement, which is subject to regulatory approvals, is expected to close in the second half of 2026. TXNM shareholders will meet Aug. 28 to vote on the deal.
On Aug. 25, TXNM Energy filed applications for approval of the proposed acquisition with the New Mexico PRC, Public Utility Commission of Texas (PUCT) and FERC.
The filing with the PUCT details $50 million in benefits, including a $35 million rate credit paid over four years, $10 million in economic development over 10 years and $5 million in additional community support.
The FERC filing states that the acquisition would not raise rates charged to either wholesale power sales or transmission service customers.
FERC and the PUCT each have 180 days to consider the application. The New Mexico PRC doesn’t have any deadlines for its review, but TXNM expects the process to take about a year.
No Layoffs Planned
According to PNM’s filing with the PRC, PNM customers won’t pay any costs incurred by PNM or its affiliates related to the acquisition. PNM will remain under PRC jurisdiction, and PNM and TXNM headquarters will remain in New Mexico.
PNM said it won’t lay off employees or cut pay for at least three years after the deal closes. Blackstone Infrastructure has promised to hold TXNM Energy for at least 10 years.
In June, Blackstone Infrastructure completed the purchase of 8 million newly issued shares of TXNM Energy common stock at $50/share, for a total of $400 million, through a private placement agreement.
PNM previously had planned to be acquired by Avangrid. But after final approval for the deal got bogged down at the New Mexico Supreme Court, and the deadline to close the transaction was extended multiple times, Avangrid pulled out of the agreement in January 2024. (See Lights out for Avangrid’s PNM Acquisition.)
The Markets and Reliability Committee rejected three proposals to revise aspects of PJM’s effective load-carrying capability (ELCC) accreditation model, which has been criticized as opaque and lacking incentives for resource owners to invest in boosting performance.
The PJM proposal, which received 30.7% sector-weighted support, would introduce a “forgetting factor” to weigh resource performance during more recent performance assessment intervals (PAIs) more heavily. The RTO said that would allow modeling to more quickly reflect improvements made to units without fully erasing historic data or relying on counterfactuals. It also would align the days performance is drawn from with the respective weather and load scenarios, establish winter capacity ratings and produce detailed documentation on how the ELCC model functions.
When building load models for future delivery years, the historic weather data is shifted six days backward and forward to develop 13 scenarios for each year back to the 1993/94 delivery year. PJM’s Pat Bruno walked the committee through an example where the analysis for Aug. 9, 2026, would draw weather data from each year between 1994/95 and 2024/25, with each year including data from Aug. 3 through Aug. 15. He said those extra days effectively have downplayed the correlation between resource performance, weather and load.
The winter capability portion of the proposal would create parallel installed capacity (ICAP) and capacity interconnection rights (CIRs) for the winter by analyzing how resource outages and capability differ with ambient conditions and how that output is deliverable during those months. Resources with capacity commitments would see their energy market must-offer requirements and seasonal capability tests based on their winter ICAP rating.
Several generation owners argued that including higher winter ratings when determining the output a resource is expected to be able to provide during a PAI could result in units with higher capability in the winter being penalized for not being able to match that performance during a summer event.
Bruno said annual ratings are meant to reflect possible output across all risk hours in a delivery year, including periods where a resource is expected to over- and under-perform. He compared it to the accreditation for solar resources including the possibility of a PAI occurring during the night. He said the incremental winter capability would add a significant amount of supply to the 2028/29 Base Residual Auction (BRA), between 800 MW to 1 GW, largely by improving the capability of wind resources.
Sensitivity analysis PJM ran on its proposal using the 2026/27 auction as a base case found that the alignment of the weather rotation data would increase the installed reserve margin (IRM) by 3.3%, shift seasonal loss of load hours (LOLH) toward the winter by 18% and reduce the unforced capacity (UCAP) margin by 4 GW. Winter ratings would decrease the IRM by 1.1%, reduce the winter share of LOLH by a third and increase the UCAP margin by 1.8 GW. The performance weighting factor would have minimal impact on the IRM, while increasing the winter LOLH by 4%.
Stakeholder perspectives on the proposal were mixed, with many arguing there is not sufficient understanding of how ELCC functions nor the outcomes the proposed changes might have. Consumer advocates and some generation owners also said it overstates weather and correlated outage risks. Supporters said it is not a panacea for their concerns with ELCC, but one step toward improving the paradigm. It received the strongest support from the other suppliers sector, at 54.5% voting to endorse, followed by generation owners at 45.8%, transmission owners at 42.9%, end-use customers at 5.9% and electric distributors at 4.2%.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said he doesn’t believe there’s sufficient transparency on the functioning of the ELCC modeling to vote on changes to its methodology, noting the Board of Managers has directed PJM to bring on a consultant to review ELCC and “identify additional recommended enhancements.” He said the 0.2 value for the exponential smoothing used in the performance weighting is arbitrary and the proposal overall aims to address correlated outage risks he does not believe exist. (See “Board Overrides Stakeholder Rejection of Auction Parameters, Directs Hiring of Consultant,” PJM Board Initiates CIFP Addressing RA, Large Loads.)
Gregory Pakela, manager of regulatory affairs for DTE Energy Trading, said the RTO’s proposal ignores changes PJM has made in its operating procedures that have had a significant impact on resource performance and system risks, namely the addition of capacity performance (CP) and advance commitments through conservative operations. While the correlated outage risks may continue to exist with gas generation, he said that should be further investigated through a study before making market changes.
James Wilson, a consultant for several consumer advocates, said the aligning of weather and performance days further exacerbates overstated extreme weather risks caused by outlier data associated with winter storms in January 1994.
Dominion’s Jim Davis said the proposal provides a reasonable incremental improvement to ELCC and asked that PJM continue pursuing transparency improvements allowing resource owners to verify their accreditation regardless of the outcome of the MRC’s endorsement.
“We shouldn’t let the perfect be the enemy of the good here,” he said.
LS Power’s Tom Hoatson said the company has had success replicating the ELCC modeling and managed to produce results similar to PJM’s, making the methodology less of a black box. While there are additional improvements the RTO can make to ELCC, he said the proposal would be an improvement, particularly the winter CIR component.
ODEC Proposes to Reduce Winter Storm Elliott and Polar Vortex Weighting
The Old Dominion Electric Cooperative (ODEC) offered an alternative adopting the changes in PJM’s proposal and reducing the probability of the Monte Carlo simulation built into the ELCC model selecting performance data from the December 2022 Winter Storm Elliott or the 2014 polar vortex by 33%. The proposal received 63% sector-weighted support, with electric distributors unanimous in their endorsement, 94.1% of end-use customers in support, 58.3% of other suppliers, 37.5% of transmission owners and a quarter of generation owners.
Reducing the weight of those storms aims to reflect that PJM has made changes to its operations around winter storms which reduce the likelihood of the poor performance seen during those events from recurring, ODEC’s Mike Cocco said, pointing to the addition of CP and conservative operations. Including the data from those storms without some acknowledgment of the changes PJM has made would result in overly conservative accreditation and create a paper capacity shortage on top of a burgeoning actual shortage.
He compared the 24% forced outage rate during Elliott with the 9% outage rate observed during the 2025 Martin Luther King Day storm. Both events had similar weather patterns and occurred during a holiday weekend, periods where gas procurement has proved challenging, but the latter saw a 63% lower forced outage rate he attributed to advance resource commitments PJM secured through the conservative operations protocol.
PJM Senior Vice President of Operations Mike Bryson said the RTO engaged in a lot of review after Elliott and made operations improvements but can’t quantify those impacts.
Pakela argued that PJM’s proposal ostensibly appears more sophisticated than ODEC’s, but the same results could be reached by changing the arbitrary 0.2 exponential smoothing value. While PJM has pushed back on approaches that would rebalance the winter-skewed risk modeling toward the summer, he said there have been several pre-emergency operations declarations, shortage pricing events and load management deployments in summer 2025.
Even though there have not been any PAIs, there were reserve shortage events not captured in the ELCC modeling which he says support a shift toward summer risk, particularly given the growing concerns around large load growth pushing summer peaks higher.
PJMVice President of Market Design and Economics Adam Keech said while there may be more summer capacity deployments, the magnitude and duration of winter events tend to be much greater.
Monitor Proposes Alternative Approach to ELCC
A proposal from the Independent Market Monitor would jettison all elements of PJM’s proposal and replace it with three components: remove all unit performance data from Elliott and the polar vortex from the ELCC modeling on the grounds they are not indicative of future resource performance, make ELCC unit-specific and include the full winter capability of thermal resources.
For new resources, accreditation would continue to be based on a class average with unit-specific data rolled in over time, similar to the precursor to ELCC — equivalent forced outage rate demand (EFORd).
Vistra’s Erik Heinle argued eliminating performance data would disincentivize good performance by sending a signal that PJM will erase data from events with large-scale under-performance.
Bowring said PJM changed its operational approach after the commitment and dispatch mistakes of Elliott that led to the poor performance during the storm.
“Given those changes, illustrated by PJM’s conservative operations during Polar Vortex 2025 in January, the performance during Elliott is not a useful risk metric,” he said.
He said PJM’s “forgetting factor” arbitrarily changes weights rather than relying on logic and actually increases the weight of Elliott in the ELCC calculations. He added PJM’s ELCC for gas-fired combined cycles is only 75% based on Elliott performance data, while that ELCC is 96% on a forward-looking basis.
“No one other than PJM thinks that combined cycles are only 75% reliable,” Bowring said.
Bowring also said while it is appropriate to recognize the increased winter capability of thermal resources, PJM’s approach would arbitrarily increase the measured capability of thermal resources year-round, exposing generators to the risk of not meeting their maximum winter output even during the summer when maximum output is appropriately lower.
The Monitor’s proposal received 35.8% sector-weighted support, with end-use customers unanimously supporting it and all other sectors voting with a quarter or less in support.
ISO-NE warned that any significant delay of the Revolution Wind project will increase risk to the reliability of the New England grid and undermine the region’s economy.
The grid operator’s Aug. 25 statement came three days after the Trump administration halted construction of the 704-MW wind farm off the Rhode Island coast, citing national security interests and potential interference with reasonable uses of territorial waters. (See BOEM Slaps Stop-work Order on Revolution Wind.)
The project is 80% complete after more than a year of construction and had been on track to start commercial operation in the second half of 2026.
While President Donald Trump’s animosity to offshore wind and other renewables is well known, and his policy moves to thwart future development have become commonplace, halting the work in progress on a multibillion-dollar project raises the campaign to another level.
Offshore wind proponents, labor unions, environmentalists, local politicians and others decried the shutdown of construction on Revolution Wind, which is contracted to send 400 MW to Rhode Island and 304 MW to Connecticut.
Grid Asset
The nation’s only completed and operational utility-scale offshore wind array, South Fork Wind, has reported strong performance — a 53% capacity factor in the first half of 2025. It is adjacent to Revolution Wind, has the same developer and uses the same turbine technology.
Commissioner Katie Dykes of the Connecticut Department of Energy and Environmental Protection said at a news conference Aug. 25 that Revolution would supply 2.5% of New England’s power needs and there is no identified replacement for that power if Revolution is not completed.
ISO-NE said in a news release that delaying Revolution “will increase risks to reliability,” and noted that it “is expecting this project to come online, and it is included in our analyses of near-term and future grid reliability.”
The RTO said resource development delays “adversely affect New England’s economy and industrial growth, including potential future data centers,” and implied that the Trump administration’s move could discourage future investments in new resources, increasing consumer costs.
While ISO-NE previously said it foresees minimal reliability risks through the end of the decade, it is counting on Revolution to begin providing capacity in 2026.
Revolution has a 150-MW capacity supply obligation (CSO) in the winter months of the 2026/27 capacity commitment period (CCP) and a 67-MW CSO in the summer months. For the 2027/28 CCP, the resource’s CSOs are set to increase to a 466-MW winter commitment and a 203-MW summer commitment.
For context, to meet NPCC resource adequacy standards, ISO-NE needs 30,305 MW of capacity for the 2026/27 CCP and 30,550 MW of capacity for the 2027/28 CCP.
ISO-NE forecasts reliability risks to increase by the mid-2030s, largely driven by growing demand from electrification, and has emphasized the importance of offshore wind for reducing these risks.
A 2023 ISO-NE study, looking at the year 2032, showed significant winter reliability benefits of offshore wind resources. The study, which assumed 5,600 MW of offshore wind, found that limiting offshore wind development to 1,600 MW increased shortfall in the worst-case winter weather event by up to 193%. Conversely, ISO-NE found that replacing 1,000 MW of fossil resources with offshore wind would reduce shortfall by up to 42%. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
ISO-NE CEO Gordon van Welie, speaking before the House Energy and Commerce Committee in March, said ISO-NE studies “have shown substantial reliability benefits of offshore wind, primarily because it delays or displaces the consumption of gas and oil so that it will be more available in the subset of high demand periods when the wind does not blow.”
“If the large amount of offshore wind that has been contracted for by the states is significantly delayed or ultimately does not materialize, the region would need to assess the potential impacts and determine what other options might be needed to meet resource adequacy needs in the future,” van Welie said.
Varied Reactions
Offshore wind opponents were pleased by the stop-work order, as they were when the Trump administration shut down work on Empire Wind 1 for several weeks starting in April.
On X, Protect Our Coast NJ posted “Bravo!” and ACK4whales posted, “We are hopeful there will be more halt-work orders coming.”
The Empire stop-work order cost developer Equinor millions of dollars a day and was widely speculated to be an attempt to twist New York’s arm on gas pipeline proposals the state previously had rejected.
The ulterior motive for the Revolution Wind stop-work order, if any, was not clear.
Connecticut Gov. Ned Lamont (D) said he thinks there is a motive, he just does not know what it is.
“I think there’s a deal to be had, and I’ve got to see what the ask is. I knew what it was for [Gov.] Kathy Hochul down in New York,” he said at the Aug. 25 news conference. “I think we’re going to get this going again.”
Lamont said Connecticut already has had productive discussions about increasing the supply of American natural gas and other types of energy in the state.
U.S. Sen. Richard Blumenthal (D), a former U.S. attorney and Connecticut attorney general, said: “This action is nuts, crazy, insane … it is also blatantly illegal.”
He said there is reason to believe federal officials broke laws with these actions.
U.S. Sen. Chris Murphy (D) said: “When the oil industry showed up at Mar-a-Lago with a set of demands in exchange for $1 billion of campaign support for Trump, this is what they were asking for: the destruction of clean energy in America.”
He added: “This is a story of corruption, plain and simple. President Trump has sold our country out to big corporations with the oil and gas industry at the top of the list.”
Other Developments
In other developments Aug. 25:
Revolution developer Ørsted said it would continue with its plans to raise $9.3 billion, much of that to cover the cost of financing Sunrise Wind, a New York project that potential financing and equity partners shied away from after the Empire Wind stop-work order. The Revolution stop-work order only reinforces the need to raise the funds, the company said.
Shares of Ørsted stock shed 16.4% of their value to close at their lowest level ever since public trading began in June 2016.
Ørsted’s former development partner, Eversource, saw its stock price close 4.7% lower on investor concerns about the New England utility’s exposure to losses on Revolution Wind. When Eversource sold its stock in the project to Global Infrastructure Partners, it guaranteed GIP a rate of return and assumed liability for certain cost increases. (Eversource remains involved in onshore aspects of the project.)
Ørsted said it will explore all options ranging from expeditious dialogue with permitting agencies to potential legal action.
Ørsted said investment of about $1.6 billion is needed to complete Revolution Wind; its share is $753 million. It said annual EBITDA on the project once commercial operation begins is estimated at around $160 million. Total investment in Revolution Wind and Ørsted’s remaining active U.S. project — Sunrise Wind — is approximately $16 billion.
New England Power Generators Association President Dan Dolan criticized the stop work order: “Actions like this erode investor confidence and jeopardize long-term electric reliability in the region. … That undermines reliability, raises costs and damages the credibility of our energy markets.”
Rhode Island Gov. Dan McKee (D) said: “At a time when we should be moving forward with solutions for energy, jobs and affordability, this administration is choosing delay and disruption. We are working with our partners in Connecticut to pursue every avenue to reverse this decision. Revolution Wind is key to Rhode Island’s economic development, energy security and long-term affordability for our residents.”
North America’s Building Trades Unions President Sean McGarvey said: “Let’s call the Department of the Interior’s stop-work order for Revolution Wind what it is: President Donald Trump just fired 1,000 of our members who had already labored to complete 80% of this major energy project. A ‘stop-work order’ is the fancy bureaucratic term, but it means one thing: throwing skilled American workers off the job after they’ve spent a decade training, building and delivering.”
FERC on Aug. 25 approved CAISO’s Western Energy Imbalance Market (WEIM) implementation agreement with Imperial Irrigation District (IID).
The approved agreement specifies how CAISO will bring IID into the WEIM, including the costs and the scope of work involved. The commission’s order notes the ISO said the plan “adopts substantially similar provisions to WEIM implementation agreements previously approved by FERC” (ER25-2789).
Under the agreement, IID will pay CAISO a fixed implementation fee of $120,000, and either party can terminate the agreement for any or no reason after first engaging in good faith discussions for 30 days to resolve any differences. The agreement also outlines limits of liability, notices and dispute resolution language, among other elements.
CAISO and IID are also developing an implementation agreement for the ISO’s Extended Day-Ahead Market (EDAM). CAISO plans to admit IID into the WEIM and EDAM on the same day, no later than Oct. 1, 2028.
Located in Southern California, IID provides power to about 165,000 customers and operates more than 1,800 miles of transmission and 5,000 miles of distribution lines. IID in May announced its intention to join the CAISO markets, a move the utility’s, general manager, Jamie Asbury, said “is a significant step toward modernizing how we purchase and manage power.” (See Imperial Irrigation District Inks Agreement to Join CAISO Markets.)
In its order, FERC also granted CAISO a waiver request to allow IID’s WEIM implementation date to occur more than 24 months after the implementation agreement effective date of Sept. 2, 2025, which allows the utility to join the WEIM and EDAM concurrently in 2028.
“CAISO and IID will require more than 24 months from the requested effective date of the WEIM Implementation Agreement to undertake the implementation steps needed to allow for IID’s concurrent participation in WEIM and EDAM,” CAISO said in its filing with FERC.
The commission said it approved the waiver because CAISO “acted in good faith” by “promptly” filed the request shortly after the ISO and IID executed their agreement and “sufficiently in advance of the proposed effective date.”
Two laws signed by New Jersey Gov. Phil Murphy (D) aim to dramatically expand community solar and storage incentive programs as the state searches for new generation sources to help meet a predicted energy shortfall.
One of the laws, S4530, instructs the New Jersey Board of Public Utilities (BPU) to increase the capacity of community solar by 3,000 MW by 2029, or whenever the limit is reached. The state’s current allowed capacity is 150 MW a year, although a one-time measure increased it to 250 MW in 2025.
The second law, S5267, requires the BPU to launch an incentive program that would stimulate the development of “transmission-scale energy storage systems,” those with a capacity of at least 5 MW that are connected to PJM. The total project capacity would be 1,000 MW. In the first phase of the project, the legislation requires the BPU to approve projects with a capacity of at least 350 MW by the end of 2025 and approve the remainder by June 30, 2026. Eligible projects must have a commercial operations date of no later than Dec. 31, 2030, and have completed the PJM connection process to the system impact study stage.
Under the law, the BPU must allocate $60 million each year to the incentive fund.
“This legislation addresses real problems,” said BPU President Christine Guhl-Sadovy. “More New Jerseyans will get access to the benefits of expanded community solar programs — one of the best ways for residents to lower their utility bills while contributing to clean energy in the Garden State. And large-scale battery storage will strengthen our electric grid and keep the lights on when we need it most.”
Officials in New Jersey, an importer of energy, argue that solar and storage development are key elements in the effort to boost electricity generation, and that the two methods can create power more cheaply and rapidly than would be possible by developing other sources, such as nuclear or gas generation.
New Jersey, like other states in PJM, faces a dramatic increase in demand, due mainly to the expected development of energy intensive data centers. PJM also argues that future energy capacity has been hindered by the closure of fossil generating sources at a faster pace than new sources — mainly clean energy — have come online to replace them.
Officials say the predicted shortfall in generation contributed to a 20% increase in the average New Jersey electricity bill in June.
Powering 1M Households
Murphy said he expected the new laws to “build a cleaner, more resilient future” for state residents.
“By accelerating the process for bringing new sources of energy online and rapidly building new energy storage facilities, we will meet growing demand while also making life more affordable for our state’s families,” he said at a press conference Aug. 22.
The New Jersey branch of the Sierra Club said the solar legislation would “enable the equivalent of one million households to receive solar power by 2028.” The storage bill will “vastly” accelerate the construction of storage in the state, the environmental group said in a release.
“Energy storage is essential to make renewable energy sources like solar provide energy to its fullest potential by allowing excess energy generated during sunny periods to be saved for peak demand,” said Anjuli Ramos-Busot, director of the club’s state branch. “Incentivizing transmission-scale energy storage while increasing community solar targets will generate more power capacity, help reduce cost of electricity, improve grid reliability, reduce emissions and combat climate change.”
New Jersey’s community solar program has been a bright spot, and a source of pride for state officials. The first two solicitations in the program were fully subscribed, allocating 500 MW of capacity. A third solicitation is underway. The program is seen as a key element in the state’s goal to reach 12.2 GW of solar energy by 2030 and 32 GW by 2050.
The BPU’s June report showed that 456 community solar projects were providing 740 MW, or about 11%, of the state’s 6.56 GW of installed solar capacity. BPU officials in the past opposed efforts to dramatically expand the program, saying the extra stress would negatively impact the state’s solar programs. (See NJ BPU Opposes Community Solar Program Expansion.)
New Jersey has struggled to develop storage. The state missed a legislative goal of developing 600 MW of storage by 2021 and now is seeking to put 2,000 MW of storage in place by 2030. (See Developers Seek Deadline Extension in NJ Storage Plan.)
FERC on Aug. 25 granted NextEra Energy’s request to waive certain rules under MISO’s tariff to allow the company to restart its Duane Arnold nuclear plant by the end of 2029.
The commission ruled that NextEra is free to combine interconnection service and alter a point of interconnection, bringing the company a step closer to recommissioning the 50-year-old Duane Arnold Energy Center in Palo, Iowa (ER25-2989).
NextEra is in the process of reinstating the plant’s operating license with the Nuclear Regulatory Commission and claims it could resume commercial operation on the plant by the end of 2028 at the earliest and the end of 2029 at the latest.
In its Aug. 25 order, FERC permitted NextEra to combine leftover interconnection service at the site and use a nearby standalone interconnection agreement from a NextEra affiliate company to accommodate Duane Arnold’s historical peak winter net capacity range of 600-619 MW.
The commission also allowed NextEra to use MISO’s generator replacement process to support recommissioning, even though an affiliate company — and not NextEra itself, the historical owner — is heading recommissioning efforts and cannot meet the original commercial operation deadlines of the stitched-together interconnection services.
The Duane Arnold plant was idled in August 2020 after a derecho damaged the plant’s cooling towers and Alliant Energy ended its power purchase agreement five years ahead of schedule. NextEra subsidiaries quartered Duane Arnold’s interconnection service among four planned solar farms, only one of which was constructed and sold. The three remaining solar generator interconnection agreements are set to be bundled with NextEra affiliate Kinsella Energy Center’s 200-MW interconnection service to support the nuclear plant’s re-entry on the grid. NextEra plans to consolidate the interconnection service at the 161-kV level.
NextEra said equipment necessary to repower the plant, including generator step-up transformers, isn’t scheduled to arrive until 2028, making the 2026 commercial operation target of the trio of original solar plans infeasible. The plant’s boiling water reactor is currently in long-term storage after being de-fueled.
‘Old-fashioned Way’
In its order, FERC also accepted NextEra’s request for a Dec. 31, 2029, commercial operation deadline and agreed with the company that a late 2029 restart date would allow for “unexpected delays resulting from challenges driven by the complexity of a project of this nature including parallel supply chain activities, physical site work and regulatory processes that will be required to return the plant to power operations.”
NextEra said it and MISO agreed that a change to the point of interconnection would have “no material adverse impacts” on the grid or other interconnection customers.
NextEra said without waivers of MISO’s interconnection rules, it could have been forced to start fresh and apply to enter the RTO’s interconnection queue, which could add years to the restart goal.
FERC said NextEra “acted in good faith in investing significant capital and securing interconnection rights in order to pursue a consolidated [generator interconnection agreement] necessary to recommission Duane Arnold.” NextEra said it could invest anywhere from $50 to $100 million over 2025 to fire up the plant within three to four years.
The commission said without the waivers, MISO would have been forced to terminate the existing interconnection rights that Duane Arnold is counting on to reconnect. It said granting extra time would give NextEra the space to “obtain regulatory approvals, procure necessary equipment and recommission Duane Arnold.”
Pamela Mackey Taylor, director of the Iowa Chapter of the Sierra Club, protested the waivers and said they weren’t necessary because they weren’t caused by unforeseen circumstances. Taylor argued also that the nuclear restart would lead to the abandonment of about 600 MW of solar development, making impacts more pronounced than NextEra claimed. Finally, she said NextEra has no guarantee from the NRC that Duane Arnold can reopen.
NextEra said data centers’ need for high-capacity baseload generation led it to alter its solar power plans at the nuclear site.
FERC said it wasn’t presented evidence that the solar projects will be “wholly abandoned.” The commission also said it would not opine on NextEra’s proceeding at the NRC.
Speaking at Infocast’s 2025 Midcontinent Energy Summit on Aug. 19, MISO Senior Vice President Todd Hillman said nuclear power could play a bigger role in the RTO.
“In MISO, we’re just doing it the old-fashioned way. We’re turning on old stuff,” Hillman joked, referencing nuclear power plant restarts at Palisades in Michigan and Duane Arnold in Iowa.
On July 29, at 7 p.m., California’s three investor-owned utilities, in partnership with SunRun and Tesla, orchestrated the largest activation to date of customer-sited batteries across 100,000 locations.
Within seconds, 539 MW of power from this aggregated virtual power plant (VPP) was flowing back into the grid, reducing peak evening demand. This may have been the largest demonstration of its kind to date. It won’t be the last.
An Expanding Resource: Pacific Gas and Electric (PG&E) noted in its press release that the batteries were enrolled in California’s Emergency Load Reduction Program (ELRP) — which calls for 20 hours of dispatch annually — and the Demand Side Grid Support (DSGS) initiative — which requires at least one event per month. “If no real emergencies happen,” the utility said, “test events like this one will continue to make sure everything works as expected.”
Peter Kelly-Detwiler
California leads the nation with 686 MW of commercial and 1,829 MW of residential distributed batteries as of April, at more than 25,000 sites. That population is growing quickly in California and elsewhere, often in tandem with solar installations. SunRun reported that in Q2 of 2025, 70% of its customers also bought batteries (up from 54% during Q2 of 2024). The company is dispatching its battery fleet across the U.S., providing 340 MW of batteries to grids in California, Massachusetts, New York and Puerto Rico during a single June day.
Tesla operates in California but also is coordinating battery-based VPPs in Texas, where it gained approval in 2023 to participate in ERCOT’s Aggregated Distributed Energy Resource (ADER) pilot project serving Houston and Dallas. It coordinates with VPP platform company Energy Hub to provide services to Massachusetts, Connecticut and Rhode Island while overseeing a separate aggregated offering in Puerto Rico.
Utilities Increasingly Embrace VPPs: Across the U.S., more utilities are deploying batteries to push the boundaries at the grid edge, offering reliability to customers while creating capacity management, renewables integration and grid balancing services.
To cite some examples, Utah’s Rocky Mountain Power launched a pilot six years ago, connecting 12.6 MW of batteries deployed by solar and storage company Sonnen to its control room. Following that success, it received approval from the state’s regulators in 2020 for a tariff to retrofit batteries to existing distributed solar installations. This year, it went further, signing an agreement with Torus for up to 70 MW of distributed storage systems using batteries and flywheels.
Batteries on Wheels help school districts access grid revenues | Electric School Bus Initiative
Vermont’s Green Mountain Power (GMP) continues to expand its battery program started in 2016. By 2023, it had 22 MW of distributed batteries that had delivered 10,000 hours of backup power to customers during the previous winter. Under GMP’s program, customers can lease the batteries or own them and receive rebates for participation in the utility’s Bring Your Own Device aggregation program, which pays participants up to $10,500. As of 2025, 5,000 customers are engaged in the program, with batteries both providing backup power and helping GMP reduce exposure to wholesale power costs by an estimated $3 million this year.
Minnesota’s Xcel Energy is adopting a unique approach, installing solar arrays and batteries as part of a distributed capacity program including up to 1,000 MW of DERs in a utility-owned and rate-based VPP. The plan won regulatory approval in February, with a detailed proposal expected this October.
VPPs Go Well Beyond Batteries: While batteries form the backbone of many VPPs, other technologies often are involved. Grid-interactive water heaters frequently participate in load-shifting and peak management programs and have provided frequency regulation services.
Air conditioners and smart thermostats also are part of the mix, with VPP programs expanding in recent years as technology improves. Late in 2024, for example, NRG teamed up with Renew Home and Google Cloud in Texas and aims to distribute, connect and orchestrate hundreds of thousands of thermostats into a 1,000-MW AI-powered VPP by 2035.
Electric Vehicles: Class of Their Own: EVs represent a potentially massive and growing resource. Sophisticated charging architectures and improved batteries now can accept charges of 300 kW or more (and trucks can exceed 1MW). It will become increasingly important to manage when they are charged. The cost of not doing so can run quickly into the billions, as distribution grids come under significant related stress.
Water heaters can shift load, AND help manage frequency | Brattle Group
EV batteries are big, especially when compared to residential storage. The bidirectional capable battery in the smaller of the Ford 150 Lightning models is 98 kWh, more than seven times larger than a 13.5-kWh Tesla Powerwall battery, while the large Ford version boasts 130 kWh. For its part, a typical “Type C” school bus battery sits around 200 to 300+ kWh.
Multiple auto manufacturers now include vehicle-to-grid (V2G) capabilities in charging and battery architectures to take advantage of the potential grid revenue streams. When BlueBird upgraded the warranty on its Type C bus battery to 360 MWh of lifetime throughput, it specifically cited the ability of EV fleet operators “to sell excess energy stored in school bus batteries back to electric power companies at a profit.”
While only a handful of drivers participate in bidirectional charging pilots, vendors and utilities are addressing the technical and behavioral challenges holding this potential back. School Bus V2G programs are having the most initial success, with 26 utilities in 19 states having rolled out programs to date.
Last year, leasing company Zum announced a program to deliver 2,100 MWh of energy annually from 74 electric buses (leased to the Oakland Public School District) back to PG&E. This month, PG&E teamed up with Fremont Unified School District (FUSD) and The Mobility House to manage 14 bidirectional-capable school buses.
The Outlook: Fast, Flexible, and Expanding: As electricity demand grows, and generation has trouble keeping pace, VPPs offer a nimble alternative. A recent Department of Energy report (now unavailable on DOE’s website) found that VPPs can be built over just six to 12 months, far faster, and at a lower cost than batteries or gas-fired generators. The report also suggested that VPPs eventually could grow to represent as much as 10 to 20% of U.S. peak demand.
The DOE report noted that VPPs still face some critical obstacles. Areas to be addressed include simplification of asset enrollment, increased standardization of operations and improved integration of these aggregated resources into both utility and wholesale markets.
The VPP world is fragmented and generally characterized by pilots and evolving initiatives. There is a long way to go before we move from today’s typical demand response programs — with limited numbers of dispatch events — to a more seamless and price-responsive future, in which on-site assets simply react predictably to price signals or specific grid conditions.
Nonetheless, solutions providers are making true progress, and the achievements are considerable. To take some other examples: EnergyHub reports 2,000 MW of flexible load, made up of 1.7 million DERs. Demand response provider CPower manages 6,700 MW of dispatchable load across 23,000 customer sites, while its competitor Voltus stated recently that it is dispatching distributed assets every single day.
Timeline to add 20 MW of dispatchable peaking capacity, months | DOE
The challenge of resource adequacy will become increasingly critical as supply resources struggle to keep up with rapidly growing demand. However, as artificial intelligence and grid software improve, VPPs will become an even more helpful tool for improving economic efficiency, reliability and resilience. Keeping the lights on in the decades to come may in part depend on how quickly these virtual power plant resources become a normal part of our electricity landscape.
Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.
Adapting charging of electrical vehicles to real-time grid conditions could save utilities up to $30 billion annually by 2035 and reduce peak energy demand, according to a new report by The Brattle Group and smart charging provider ev.energy.
The purported benefits would come from enabling managed-charging programs that encourage off-peak charging. This reduces strain on the grid and can help utilities avoid costly infrastructure upgrades, according to an Aug. 21 press release.
The report finds that managed charging can save up to $575 for each EV and 10% on home utility bills, with benefits potentially doubling with the inclusion of bidirectional charging, according to the release.
“As demand grows, and the world electrifies, there’s a real risk that households across the U.S. will face higher energy rates,” Nick Woolley, CEO of ev.energy, said in a statement. “The challenge for utilities is demand is rising fast, and traditional solutions — like building power stations — are slow to deliver and costly.”
Enabling demand flexibility can provide a solution and reduce rates across the board, Woolley added.
Citing data from the U.S. Energy Information Administration, the report states that forecasts show a 15% increase in peak demand by 2030.
“Electric vehicles represent a massive portion of this surge,” the report states. “While some forecasts predict a near-term slowdown, even conservative estimates project a 1400% increase to 60 million EVs by 2035 (Bloomberg, 2025), while others expect nearly 80 million (Edison Electric Institute, 2024),” the report states.
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. Cox also noted the industry is facing further headwinds with government-backed incentives ending in September and economic pressures mounting. (See Calif. Fights to Maintain ZEV Momentum.)
Still, “the fundamental per-vehicle value is so significant that the business case for managed charging remains urgent even under more conservative adoption scenarios, such as those highlighted in recent industry reports,” according to ev.energy and Brattle’s report.
A similar report by Brattle published in February found that New York could achieve 8.5 GW in “grid flexibility” measures by 2040, saving consumers more than $2 billion a year by using programs like managed charging. (See Study Finds Considerable ‘Grid Flexibility’ Potential in New York.)
The February study said implementing grid flexibility improvements could avoid $2.9 billion a year in power system costs by 2040, $2.4 billion of which could be returned to consumers. These cost savings come primarily from reducing how much investment in generation capacity would be needed to maintain reliability. Avoided distribution and energy costs were $408 million and $384 million, respectively.
Managed electric vehicle charging, heat pump load control and residential behind-the-meter storage all had significant potential for increasing grid flexibility, according to the February report.
In a statement on the most recent study, Ryan Hledik, principal at The Brattle Group, said: “Past analyses have shown that virtual power plants can deliver reliable power at costs up to 60% lower than traditional generators. This new research goes further — offering a rigorous, quantitative framework that confirms EV flexibility as a critical, cost-effective tool for preserving both grid reliability and affordability.”
IESO officials say they will release more information on how the ISO constructed its study of the potential for incremental energy savings in Toronto after stakeholders complained they lack enough details to comment meaningfully on the analysis.
At a webinar Aug. 21, IESO said it and Toronto Hydro could cost-effectively secure 219 MW of incremental summer demand savings and 50 MW of incremental winter demand savings through energy efficiency, demand response and behind-the-meter DER programs.
The savings are in addition to the forecast 847 MW (summer) and 757 MW (winter) of future electric demand side management (eDSM) program savings already reflected in the Toronto Integrated Regional Resource Plan (IRRP), according to the study, which was conducted with consulting firm ICF.
The results from the ISO’s draft Local Achievable Potential Study will affect recommendations for how non-wire alternatives can defer or reduce the need for more electric infrastructure. “The results show that incremental eDSM alone is not able to meet Toronto’s needs,” the ISO said in a presentation.
IESO asked for feedback on the results by Sept. 11. The final report is set to be published on the Toronto Regional Planning website in October.
But several stakeholders said they would be unable to respond intelligently based on the information the ISO has released to date.
“It would be very helpful if you could provide us with the draft report that you’ve got so we can look at your input assumptions, look at your analysis and give you meaningful feedback,” said Jack Gibbons, chair of the Ontario Clean Air Alliance. “Because some of your assumptions may be wrong. Some of your analysis may be wrong. And we don’t want to just take your findings that you’ve given us today on faith.”
IESO’s Tom Aagaard noted that the ISO received feedback on its input assumptions in a webinar in December and said the ISO still was refining its conclusions. “We’ll have to take back [to see] what we’re able to share sooner.”
“You’ve got a draft report from ICF. I don’t see why you can’t just share it now and be transparent,” Gibbons persisted. “What harm is it going to do to give us what you’ve got now?”
The study uses a bottom-up approach to estimate the total electricity savings at the station level. It employs a “digital twin” of Toronto’s building stock, to which eDSM measures are applied. The resulting savings are simulated at the building level and aggregated to the transformer station for each scenario. | IESO
Keith Brooks of Environmental Defence, Chris Caners, general manager of renewable energy co-op SolarShare, and David Robertson, of Seniors for Climate Action Now, agreed with Gibbons.
“Without an understanding of what the final assumptions are in more detail, it’s really, really impossible to give meaningful feedback,” Caners said.
IESO responded in an email the day after the webinar, saying it would work with ICF “to expedite the release of more detailed information on methodology and assumptions, including measure characterization and more information on achievable potential established from economic potential results.” The information will be posted on the Toronto Regional Planning engagement website.
Methodology
The study used two load forecasts:
A reference scenario assuming a steady increase in demand based on current policies and growth in EVs and electrified heating and “low/steady growth” of data centers.
A high-electrification scenario that assumes Toronto will meet its net-zero targets for buildings by 2040 (with 30% EV adoption by 2030 and 100% by 2040) and see “elevated” data center growth.
For each scenario, the study identified three levels of potential electricity savings:
Technical Potential. Savings from implementing all technically feasible measures regardless of cost-effectiveness and customer awareness.
Economic Potential. Savings from technically feasible measures that are cost-effective based on avoided generation (capacity and energy) and transmission costs and forecasted retail rates.
Achievable Potential. Savings that realistically can be acquired based on expected adoption rates considering market barriers and customer awareness.
The study used “digital twins” of Toronto’s building stock, to which DSM measures were applied. The resulting savings were simulated at the building level and aggregated to the transformer station for each scenario.
Draft Results
In 2045, the study concluded that achievable savings under the reference scenario were 1,066 MW in summer and 806 MW in winter:
Demand response (including EV charging, HVAC equipment and water heaters) had an achievable potential of 440 MW in summer and 324 MW in winter under the reference scenario. IESO said the difference in achievable potential between the reference and high-electrification scenarios is modest because the reference case includes significant heating electrification and because of the poor cost-effectiveness of EV demand response programs due to time-of-use pricing.
Energy efficiency (heat pumps, HVAC, lighting, appliances, weatherization and hot water) could save 605 MW (summer) and 471 MW (winter).
Behind-the-meter distributed energy resources (including battery storage and solar) could save 21 MW (summer) and 11 MW (winter). The low winter potential reflects the “limited value of solar to meeting winter needs,” the ISO said. Technical and economic potential match because measures in current Save on Energy programs including solar and solar-plus-storage were judged cost-effective. The reference and high scenarios had identical potential because the technical potential is affected by factors like usable rooftop area for solar rather than load.
Robertson and Brooks questioned the gaps between economic and achievable potential.
“It’s hard for us to give feedback on the results if we don’t understand how you arrived at them,” Brooks said.
“It would be really helpful and useful if there was something in your reports and presentations that talk about how do you close the gap,” said Robertson.
Existing Measures
IESO said the achievable savings in the study were muted because the Toronto IRRP already assumes 847 MW (summer) and 757 MW (winter) of new peak demand savings in 2045 from eDSM programs. In January, the Ontario government announced it would spend up to $10.9 billion on its eDSM programs through 2036.
The IESO and Toronto Hydro’s EE programs already have reduced peak demand by 800 MW in the past 15+ years.
The city’s Green Standard’s high energy performance requirements reduce the amount of additional cost-effective efficiency opportunities in new construction.
“Robust” participation in net metering, microFIT and other DER programs reduce the remaining rooftop solar potential, the ISO said.
Vehicle-to-grid
Another point of contention was the ISO’s decision to exclude bidirectional charging measures (vehicle-to-grid) from the study. The ISO said it could not properly model V2G based on current information and lacked confidence “that a program of meaningful scale could be delivered cost-effectively in the near future” because of the limited availability of vehicles capable of bidirectional charging, uncertain customer acceptance, costs and technological barriers.
Robertson questioned the ISO’s conclusion, saying “a study [with a] horizon to 2045 should anticipate developments” such as V2G.
Aagaard said it would be “kind of reckless” to include savings from V2G based on current information.
“We have very, very limited core data [to make] really important modeling assumptions to understand how much technical potential is actually out there. How many vehicles are actually going to have bidirectional charging capability? Do customers actually want this? Will [they] be willing to participate in programs when they’re called upon?” he said. “There’s just a million kind of consumer choice factors that come into play. … To include it in the modeling would be like really pulling numbers out of a hat.”
