Utilities face significant forecasting risks from large loads, prompting the industry to develop strategies to eliminate counting of speculative projects, experts said during a Western Interstate Energy Board webinar.
Natalie Frick, deputy department leader of energy markets and policy at the Lawrence Berkeley National Laboratory, and Shana Ramirez, director at Energy and Environmental Economics, discussed the challenges of large loads during a Sept. 12 webinar.
Citing data from the Electric Power Research Institute, Frick noted that all 25 utilities participating in a study on load forecasting reported challenges incorporating data centers into load forecasts.
About half of the utilities in the study included the full requested data center capacity in their load forecast, a third included a derated capacity and six utilities did not include any of the data center requests in their forecast at all, Frick said.
“All of the utilities that they interviewed identified that they’re facing challenges with incorporating data centers into load forecasts, in particular because of the speculative nature of the service requests that they’re receiving,” Frick added.
There is no agreed-upon approach for load forecasting, but speculative load interconnection requests can skew the numbers across the board, Frick’s presentation slides showed.
Georgia Power forecast a 107% compound annual growth rate for commercial large load summer peak load in the 2025 interconnection request process. But several projects have pulled out, and net load reductions are concentrated across data center projects, “particularly those that were in the earlier stages of advancing through the interconnection process,” Frick said.
Dominion Energy forecast $1.5 billion in data center capital spending between 2025 and 2027. After staff further reviewed the interconnection requests, they removed $853 million in data center expenditures “because they identified that those were speculative,” Frick said.
“They didn’t think that … those customers had enough skin in the game to really include them in the forecast,” she added.
Also, there is no “standard large load tariff,” Frick said.
“Regulators can design the tariffs to meet their state energy goals, and those could be a variety of things,” she noted. “They could be seeking to improve or strengthen resource adequacy, affordability, attracting large load customers and also air pollutant emissions reductions. And so those are all kind of some of the motivations behind these tariffs.”
Ramirez highlighted that large load growth exposes utilities to nonpayment risks, as well as potential stranded assets and credit challenges, underlining the need for effective risk mitigation strategies.
Ramirez said there is a spectrum of what utilities are doing to mitigate those risks, ranging from “very lenient” to “very strict.”
Dominion recently proposed collateral of $1.5 million per MW for large load customers that would be included in their rate costs.
This is “much higher than what we’re seeing in other utility jurisdictions that probably have more risk, like Evergy Kansas, Evergy Missouri, where they’re just asking for two years of minimum bills as collateral,” Ramirez said.
Ramirez said there are some “best practices” utilities can implement. The practices should enable cost recovery, support responsible growth and promote fair treatment of all customers, according to the presentation.
“They should be flexible, transparent, consistent, scalable, adaptable and standardized, and [they] should align the financial security requirement with evolving risks,” Ramirez said.
Political efforts to curtail gas supply and demand have met with limited success. Methane rules, drilling restrictions on public land and opposition to new pipelines have only incrementally slowed the growth of natural gas in the United States. But the obstinate anti-fossil-fuel lobby and its government allies want much more: moratoriums on new gas service and bans on natural gas usage and appliances.
Bans by municipal jurisdictions with (presumably) the legal authority to do so have been in the news for some time. The City of Berkeley initiated municipal efforts in July 2019 to electrify (especially via electric heat pumps and electric stoves) by prohibiting natural gas in new buildings. (Incidentally, the initiative was struck down by the courts.)
Since then, various municipalities and states have sought to restrict the use of gas in new buildings. For example, as of early 2024, dozens of local governments in seven states and the District of Columbia had imposed or passed ordinances for natural gas restrictions. New York became the first state to pass legislation imposing statewide natural gas restrictions affecting the state’s local governments. Some cities have even considered banning or restricting natural gas appliances from existing homes and businesses, as well.
Kenneth W. Costello
The primary purpose of these efforts is to mitigate climate change, however infinitesimal in the whole, by making buildings zero-carbon. A ban is much more extreme than just creating a tax to discourage consumption of a product or service. With a tax, the decision is left to consumers on how much of a product or service to purchase. A tax can counter a negative externality that is unaccounted for in the decisions of either suppliers or consumers, such as pollution or second-hand smoke; a gas ban obliterates consumer choice for meeting space and water heating needs, not to mention a flame for superior cooking and taste.
More fundamentally, such prohibition violates consumer freedom to purchase a wanted product or service like natural gas in place of an inferior one, namely electricity. Cheapness and quality are sacrificed on the altar of an environmental fixation that is debatable.
In economic terms, a gas ban fails miserably, with the benefits virtually zero and the costs potentially high. Thus, the benefit-cost (B-C) ratio is close to zero or the C-B ratio is infinite; or as public policy, a ban is off the charts as being exceptionally socially destructive.
Here is why: Less than 9% of carbon-dioxide emissions in the U.S. come from direct use of natural gas in homes and buildings. The U.S. emits about 15% of world CO2 emissions. Thus, converting all buildings to all-electric, and assuming that all electricity is produced from “clean” sources (it is not), reduces worldwide emissions less than 1.5%, which according to climate models, would have less than a detectable effect on global climate, temperature, sea level or otherwise.
A ban can look good politically by giving the false impression that a severe problem is receiving immediate, absolute attention. And a ban certainly is less widespread than a carbon tax or a budget gap from new taxpayer subsidies. But at least these two approaches preserve consumers’ option to choose their energy source, rather than preclude them from doing so with a ban.
The observation that a gas ban descends predominantly from a quasi-religious opposition to fossil fuels is credible given the lopsided cost-benefit calculus. Climate activists regard natural gas as competing with renewable energy in power generation and for electricity in end-use applications. Their position seems to be that “getting rid of the competitor” would make it easier to have more renewable energy and clean electricity.
It is only because of special interests that local and state governments would even consider prohibiting consumers from choosing natural gas as an energy source to meet their space, water heating and cooking needs. After all, in most parts of the country where gas is available, it is the most economic and desired source of energy.
Gas bans are little more than symbolic, reflecting a stance of “we have to do our part,” or perhaps more accurately “whatever it takes to combat climate change,” even if bans resoundingly fail a cost-benefit test.
Good public policy balances the economic and environmental consequences in enhancing the public interest. Because a gas ban — command-and-control policy at its worst — has virtually no effect on global climate and inevitably will increase cost and reduce quality for consumers, one would have to look hard to find a governmental action on energy that is so intrusive, imbalanced and detrimental to society’s welfare.
One cannot avoid concluding the craziness of banning or even restricting a product like natural gas that has greatly benefited, and will continue to do so, both energy consumers and the economy. A ban on natural gas is throwing out the baby with the bathwater.
Kenneth W. Costello is a regulatory economist and independent consultant who resides in Santa Fe, N.M.
Entergy Arkansas says a recently enacted Arkansas law strengthens the case for its plan to build a new natural gas plant, a proposal that has drawn criticism from the state’s attorney general and regulatory staff.
The utility applied to build the 754-MW Jefferson Power Station near Redfield, Ark., in early August, but staff with the Arkansas Public Service Commission and state attorney general’s office asked the PSC in early September to deny the utility’s proposal.
The two agencies cited underdeveloped studies, a neglected analysis of alternatives, uncertain costs and a lack of ratepayer protections (25-047-U). The proposed plant would be adjacent to the utility’s White Bluff coal-fired power station, which is slated for retirement in 2028. Entergy envisions the gas plant would begin operation in 2029.
In a Sept. 19 round of filings, Entergy Arkansas’ rebuttal to state officials invoked acts 373 and 940, both passed by the Arkansas legislature in 2025.
Act 373, also known as the Generating Arkansas Jobs Act, makes it easier for electric utilities to finance new construction projects, while Act 940 adds review for retiring dispatchable generation and emphasizes a reliable, adequate and affordable power supply with the PSC fostering development. Both laws contain emergency clauses.
John Bethel, director of public affairs at Entergy Arkansas, said the Jefferson Power Station is exactly the type of resource the state legislature envisioned and will be “critically important” as the utility’s largest gas plant.
Bethel said the plant is “undoubtedly necessary for [Entergy Arkansas’] long-term ability to provide adequate supplies of reliable, affordable and dispatchable power to all customers.”
In accordance with the two laws, he said, Entergy is prioritizing speed to market for new, dispatchable generation to serve economic development. He added the utility was able to secure in-demand components for the plant “at a time when it is very difficult to procure new gas resources of this kind.”
Entergy hasn’t publicly disclosed the cost of the plant, citing an incomplete engineering, procurement and construction agreement. The utility has redacted total price estimates in public filings.
Entergy also has proposed that the Cypress Solar project — consisting of a 600-MW solar array and a 350-MW battery energy storage system — be paired with the natural gas project. The utility estimates that both projects would add $4.87 to an average residential customer’s monthly bill.
Kandice Fielder, Entergy Arkansas’ senior manager of resource planning, said no one has disputed the utility’s need for the new capacity. She said Entergy’s analyses show that adding the gas plant would “yield substantial net benefits to customers” by using land the utility already owns and White Bluff’s interconnection rights.
Fielder said more than 80% of project costs would originate from two competitive solicitations Entergy Arkansas conducted.
‘Methodological Flaws’
Jeffrey Bower, a consultant with Daymark, in early September filed testimony on behalf of the Arkansas PSC contending that Entergy failed to meet the commission’s resource planning guidelines because it didn’t compare the self-built resource to “market opportunities.” He also said that Entergy didn’t propose any cost containment or consumer protections or compare the new gas plant with a conversion of White Bluff to burn an alternative fuel.
“The attempts by the company to compare the project to alternative options are either inadequate or contain methodological flaws,” Bower said. He noted that Entergy appeared to assume EPA regulations eventually requiring carbon capture technology would be repealed even though they’re not yet dismantled.
Bower asked the PSC to order Entergy to supplement the application with more analysis and protections for ratepayers.
But Bethel said Bower’s stance “must be revisited” given that the legislature has charged the Arkansas PSC with eliminating obstacles to developing a “diverse” generation fleet that includes “cost-effective dispatchable electric generation.”
Bethel also said Entergy may consider converting White Bluff’s coal units into a natural gas peaker plant. However, that conversion would not be enough of a substitute for the Jefferson Power Station. He said ordering a comparison of the coal plant conversion to the new gas plant “is a red herring because the resources are not directly comparable.”
Arkansas Attorney General Tim Griffin similarly opposed Entergy’s proposal. Scott Norwood, an energy consultant who filed testimony on behalf of Griffin’s office, said Entergy hasn’t shown the Jefferson plan would come in at a reasonable cost or “is the best available resource for meeting [Entergy’s] system capacity need in 2030.”
Norwood also said that the utility did not explore the alternative of converting White Bluff from coal to gas, which “would have a far lower cost.” He added that Entergy’s other economic analyses of the plant are “based on unreasonable cost assumptions that serve to overstate the benefits.”
Meanwhile, in its Sept. 22 report, The Dirty Truth, the Sierra Club faulted Entergy for overcommitting to natural gas and backpedaling on sustainability goals.
Entergy in 2019 committed to reducing its emissions by 50% by 2030, followed by a 2021 commitment to 50% carbon-free generating capacity by 2030. However, in late 2024, the utility said its capacity goal would be “delayed for an as-yet undetermined period beyond 2030” and said its emissions timeline could slip based on growing demand. Entergy said it recognized that “some of our new generation resources will be cleaner but not carbon-free.”
The utility said it remains committed to its long-term carbon target of net-zero emissions by 2050.
The PSC has scheduled a public hearing for the Jefferson plant Oct. 30 and expects to issue a final order near the end of January 2026.
With the age of hyperscalers ramping up, Meta is the latest major tech firm to ask FERC for market-based rate authority as it sets up its own internal power marketer: Atem Energy (ER25-3440).
Meta, which owns Facebook and Instagram, is one of many firms developing artificial intelligence applications that have been a major contributor to the resumption of overall power growth after a couple of decades of stagnation.
Atem Energy is a Delaware-based company that has been formed to act as a power marketer to sell energy, capacity and certain ancillary services at wholesale in the United States. The firm’s MBR application does not specify where it will market power.
Meta is not the first big tech firm to seek MBR authorization: Alphabet’s Google has had it since 2010 (ER10-2835), Amazon since 2015 (ER15-1905) and Microsoft since 2021 (ER21-964). Companies in other sectors have been at it even longer, notably Walmart, which set up its in-house power marketer, Texas Retail Energy, in 2002.
A major company setting up its own power marketer to secure power supplies comes with some benefits, but significant costs as well, Electric Advisors Consulting’s Frank Lacey said in an email.
“In the plus column, you can design an electricity product tailor-made to your needs, including renewable attributes, risk management strategies, billing allocations and other,” Lacey said. “You can also avoid the profit margins built into other suppliers’ products.
“On the flip side of that coin, you have to build out an energy team, presumably with some trading and risk management expertise,” he said. “You have to be registered with FERC to sell electricity at market-based rates. You need to be a member of each RTO you have facilities in and bear those costs, including credit requirements.”
If Meta wants to become a state-regulated retailer to supply its facilities, it needs to register with their regulatory commissions and set up data exchanges with the relevant utilities, he added.
“You have to bear the risk of your own energy hedges and non-hedged positions, and as an RTO market participant, you own a share of the marketwide risk should any market participants go bankrupt,” Lacey said. “If the company has the resources to do all of this, it might make sense. On the other hand, I would think a company like Meta would have enough horsepower to attract a lot of attention from the existing suppliers in the market.”
Neither Atem nor its upstream ownership at Meta own any facilities that are for the generation, transmission or distribution of electric power. Meta CEO Mark Zuckerberg owns more than 10% of its shares, which triggers additional requirements, but he does not “directly or indirectly own or control a 10% or greater voting interest” in any generator or other energy assets in the United States, the application said.
The lack of existing assets in the power markets means Atem lacks horizontal or vertical market power, which satisfies the requirements for FERC to grant MBR authority, the application said.
The application seeks authority to sell ancillary services at market rates in CAISO, ISO-NE, MISO, NYISO, PJM and SPP. Atem asked for an effective date of Nov. 16, 2025, for its MBR authority.
BOSTON — Energy experts and officials stressed the importance of proactive transmission planning, interconnection reform and increased demand-side flexibility at Raab Associates’ New England Electricity Restructuring Roundtable on Sept. 19.
Speakers at the event reflected on the challenges the One Big Beautiful Bill Act (OBBBA) and the Trump administration’s executive actions have created for clean energy development in New England, but they generally expressed optimism around the region’s ability to withstand the federal headwinds.
“There will be pain, there will be companies that close, there will be less deployment as a result of the changes at the federal level,” said Nathan Phelps, managing director of regulatory advocacy at Vote Solar.
However, “solar will not fall off a cliff” because “the price of solar has come down a lot, and it continues to be an attractive investment,” Phelps said.
The OBBBA dramatically expedites the expiration of federal tax credits for wind and solar developers, and new projects must either begin construction by July 5, 2026, or come online by Dec. 31, 2027, to qualify for the full tax credits established by the Inflation Reduction Act. (See U.S. Clean Energy Sector Faces Cuts and Limitations.)
In New England, the looming tax credit phaseout has caused a mad dash for solar developers to try to lock in credits for later-stage projects, which may boost development in the short-term. Meanwhile, projects unable to begin construction in time for the deadlines likely will face increased risks of cancellation or major delay.
While the longer-term effects of the shift in federal policy are less clear, the Trump administration’s antagonism toward offshore wind in particular threatens to undermine the buildout of a strong regional supply chain and workforce, which could have effects extending well beyond Trump’s second term. (See Tax Credit Phaseout Threatens Projects, Jobs in New England.)
In the wake of the Trump administration’s stop-work order on Revolution Wind, “it’s really hard to have any confidence around what we can expect from the federal level,” Phelps said.
Alicia Barton, CEO of Vineyard Offshore, emphasized the importance of offshore wind for meeting load growth in the coming decades.
“I don’t think we have a choice — the region needs offshore wind,” Barton said.
She declined to comment on the halt on Revolution Wind, which is being developed by Ørsted, but said Vineyard Wind, which is being developed by Vineyard Offshore and Avangrid, still aims to achieve commercial operations by the end of the year.
“We are still constructing, we are still moving forward,” Barton said, adding that Vineyard Wind has created 3,400 jobs, including 1,400 union jobs.
Speakers also discussed how reducing the soft costs of renewable development — including costs and delays associated with siting, permitting and interconnection — could help mitigate the effects of federal policy changes.
On interconnection, “the most important near-term thing is implementation of Order 2023,” said Caitlin Marquis, managing director at Advanced Energy United.
FERC Order 2023 requires transmission operators to adopt first-ready, first-served cluster processes for interconnection. ISO-NE’s first cluster study under the new rules will begin in October.
“ISO-NE deserves a lot of credit for holding a robust stakeholder process to implement Order 2023,” Marquis said, while emphasizing that interconnection reform must go further than Order 2023 compliance to better integrate interconnection planning into the transmission planning process.
Marquis also highlighted the potential benefits of processes that allow new resources to share interconnection service with existing ones. She noted that ISO-NE has a surplus interconnection service option in its tariff but that stakeholders seek more flexibility.
At the state level, the administration of Massachusetts Gov. Maura Healey (D) has “made good strides” toward a more proactive approach for resource interconnection but is seeking to “consolidate some of the siloed processes into a more comprehensive planning process,” said Michael Judge, undersecretary at the Massachusetts Executive Office of Energy and Environmental Affairs.
He said state officials hope to replace the Capital Investment Project process, a provisional program intended to enable fixed distribution interconnection costs, with a proactive interconnection planning process incorporated into the utilities’ five-year electric-sector modernization plans.
Rob Gramlich, president of Grid Strategies, praised increased transmission planning initiatives taking place across New England. He noted that ISO-NE rated poorly in a pre-Order 2023 interconnection “report card” but that the Order 2023 compliance changes should help address some of the issues. (See Transmission Report Card Grades MISO ‘B,’ Southeast ‘F’.)
“Transmission planning is the key solution here,” he said.
Demand Response
Multiple speakers stressed the need to focus on demand response and flexibility.
For policymakers looking to decarbonize at the lowest possible cost, “one resource is way more important than all the others, and that’s the demand side,” said Paul Hibbard, principal at the Analysis Group and former chair of the Massachusetts Department of Public Utilities.
Hibbard said unlocking the full potential of demand response will require “fundamental changes” to rate design and programmatic spending.
“The technological hurdle to this is not a big one, it’s really getting the price incentives up and running and the infrastructure in place,” he said, adding that states must begin this work as soon as possible given the “painfully slow” pace of ratemaking.
Massachusetts’ electric utilities aim to finish deploying advanced metering infrastructure across their service territories by the end of the decade, which should enable increased retail price incentives to reduce demand during peak periods.
“Electrification depends on it, affordability depends on it, and ultimately the commonwealth’s decarbonization policy depends on it,” Hibbard said.
PHILADELPHIA — Virginia Gov. Glenn Youngkin requested that PJM reopen the nomination process for two open seats on its Board of Managers to consider two candidates recommended by the states.
Speaking at a technical conference on the state of PJM, Youngkin said there needs to be real reform immediately at PJM, with states being given a greater voice in decision-making atop the list. Much of the full-day conference focused on the prospect of governance reforms and how the RTO can meet the challenge of rising data center load.
The request comes after Youngkin and Pennsylvania Gov. Josh Shapiro co-signed a letter to the Board of Managers urging the RTO to consider nominating former FERC Commissioners Mark Christie (R) and Allison Clements (D) to serve as board members and for a larger discussion to be launched on setting aside two seats for candidates nominated by member states.
The PJM Nominating Committee instead opted to nominate Robert Ethier, a former ISO-NE executive, and Le Xie, faculty co-director of the Power and AI Initiative at the Harvard School of Engineering and Applied Sciences. The Members Committee is set to vote on appointing Xie and Ethier during its Sept. 25 meeting, which is the voting deadline FERC granted in response to PJM’s request for a delay. (See Robert Ethier, Le Xie Nominated for PJM Board.)
In response, seven state governors signed onto a letter expressing disappointment that Christie and Clements were not nominated, saying that would have signaled that PJM is listening to the states. They wrote that the lack of board representation for consumers and state regulators is a core concern for the governors.
“Our recommendation was intended to provide a constructive solution that would have both strengthened PJM’s governance and signaled that voices representing the public interest are afforded a meaningful place in decision-making at PJM,” the governors wrote. “The Nominating Committee’s decision to disregard our recommendation indicates that our concerns for our consumers are not being taken seriously and underscores how the states’ role in PJM is being minimized.”
“PJM cannot expect to continue making decisions that affect the daily lives of our citizens and the economic future of each of the states while hiding behind stale process and refusing to grant the opportunities for meaningful input that exist in other RTOs,” they continued. “This is a fundamental and existential challenge: PJM must find ways to provide sufficient representation for the millions of consumers we represent.”
The governors added that they do not mean to discredit the qualifications of Ethier and Xie but believe they do not have the backgrounds needed to address the crisis state leaders see. They advised the board “to embrace a new, more meaningfully collaborative, vision for PJM’s relationship with the states as a whole and to take steps to ensure greater ratepayer representation as the RTO makes major decisions in the coming months.”
“Please recognize the urgency of this moment — the need is not simply for indisputably talented individuals like Dr. Ethier and Dr. Xie, but for leaders who understand the uniqueness of PJM’s member states, our citizens and our shared responsibility for the reliability and affordability of electricity,” they said. “There is a pressing need to restore trust in PJM’s governance and legitimacy.”
‘Move More Quickly’
Speaking at the conference, Youngkin said PJM has failed to forecast rising load in its footprint in time to get ahead of it, introducing interconnection bottlenecks and causing a resource adequacy crisis.
“And that is why we are working on legislation that will allow Virginia to reassess whether our utilities will continue to be part of PJM. Virginia will need to decide what is best for Virginia ratepayers. This doesn’t mean that we are walking away, but it does mean that collectively we recognize we need to represent and protect our ratepayers. And that means sending a clear, unifying signal that PJM must modernize, must reform. PJM must improve its planning and, above all, PJM must work to restore confidence that recently has been so badly lost.”
Opening the technical conference, Shapiro said PJM is at an inflection point where the states have empowered it with increasing authority to not only coordinate power flows but also ensure resource adequacy. Now it has responded too slowly to reform its interconnection process to facilitate the generation growth needed to meet rising demand.
He said the situation has been made more difficult by the Trump administration creating barriers and cutting funding for new generation. PJM was founded in Philadelphia nearly a century ago, and there’s an opportunity now to reform its governance to provide more opportunity to work with its member states.
In a press conference following his address, Shapiro said PJM should revise its leadership structure to provide more authority over decision-making to the states. And while he prefers to take a cooperative approach, he’s prepared to seek legislation requiring utilities to leave PJM absent changes.
He said PJM will need to become more sensitive to the needs of the states and consumers, including giving a voice to those entrusted to lead the states, as well as cultivating a more direct connection between state utility commissions and PJM leadership than currently exists. For those changes to be effective, he said PJM has months, not years.
“We need PJM to move more quickly … if PJM cannot do that, Pennsylvania will look to go it alone,” he said.
Maryland Gov. Wes Moore said the unified voice of 13 governors underscores the crisis at PJM, with families facing double-digit rate increases driven by the mismanagement of the regional grid. Grid oversight lacks transparency and responsiveness, which creates a need for states to have more of a hand in governance, he said.
Following the conference, 11 states signed onto a joint statement of intent outlining plans to create a PJM Governors’ Collaborative to “promote greater state and consumer representation in the governance and decision-making processes of PJM.”
The group would not hold regulatory or enforcement power, but would coordinate communications among PJM, state regulators and elected officials, FERC, the Organization of PJM States Inc (OPSI) and Consumer Advocates of the PJM States (CAPS). It also could provide technical support on topics before PJM, identify issues for the states to address, and “develop and advance joint positions and strategies related to PJM issues.” Only West Virginia and Kentucky did not sign onto the statement.
POUGHKEEPSIE, N.Y. — It was standing room only at the Town Board meeting here Sept. 3. A glance at the agenda for the night, dominated by property maintenance orders and police officer hires, would not hint at what drew so much of the public out on a Wednesday evening. But it quickly became apparent once residents began speaking.
“Lithium battery stations often go on fire,” one said. “There’s been many of them, and I understand that you can’t use water to put them out … so they let fire smolder, just pouring toxins into the air.”
The board was considering whether to adopt new zoning codes to regulate the construction of battery energy storage systems (BESS) that would overturn an 18-month moratorium. Public comment both for and against the rules went on for about three hours at the meeting, with people voicing concerns about fire safety, pollution, environmental impact and grid stability.
“I think batteries will help us be less dependent on polluting plants, like the one in Newburgh,” another resident said. “My electric bills are going up; there are consistent rate hikes. I think batteries can help keep our bills low.”
Town Supervisor Rebecca Edwards said New York state recently adopted fire codes for BESS, the strictest in the U.S. Councilmember Ann Shershin said if the town wanted solar projects, it would need BESS nearby.
Councilmember Michael Cifone said he didn’t see the benefit to the town’s residents and expected it to go to developers and utilities.
After more discussion, several failed amendments and one minor adjustment to construction setbacks, the seven-member board narrowly passed the zoning rules along party lines, with the four Democrats voting in favor. This makes Poughkeepsie one of the first municipalities in New York to overturn a BESS construction moratorium.
This scene is playing out in towns and cities across New York as the state pursues its goal of 6 GW of energy storage by 2030. The Hudson Valley, New York City and Long Island are at the forefront of a massive battery rollout. Because of the state’s strong home rule provisions, municipalities have significant power over whether BESS facilities get built. A bill to get BESS under state siting authority died in committee in 2025.
Similar debates are being held on Staten Island and in Mahopac. Westchester County passed a local law upping safety requirements for BESS systems after a fire in 2023. That same year, National Grid pulled out of a BESS and solar installation in the Adirondacks because of community outcry. Another battery battle is gearing up in Kingston where Terra-Gen is planning a 250-MW facility on the site of a closed high school. Local officials and state representatives are divided on the issue, per Energy Storage News.
The Poughkeepsie Town Board had been thinking about BESS zoning for roughly a year. In September 2024, the matter was brought to its attention when locals learned of a local project and descended on the board with demands and questions.
Key Capture Energy, the developer of the project, had been eyeing an industrial parcel owned by Vassar College since 2019, Phil Denara, director of development for the company, said in an interview in 2024. The company wanted to build a 20-MW/80-MWh battery energy storage project there because it was close to a local substation. The project fell through before the zoning ordinance could be passed.
“We’re attracted to continuing to develop in New York primarily because of the policy mandates that are driving a lot of the industry,” Denara said. “The Climate Leadership and Community Protection Act set an initial storage target which has been doubled by Gov. [Kathy] Hochul.”
Denara said the industry needed to “take ownership” and respond to the concerns of local residents and officials.
“We’re coordinating a lot at the local level, educating local communities and ensuring that they understand that this technology is important for our decarbonization goals both in New York state and more broadly across the globe,” he said.
Fire Safety
One of the most frequently voiced concerns in the debate over BESS facilities is over fire safety. In Facebook groups opposing local BESS projects, people share videos of e-bikes exploding. Others share conspiracy theories about Chinese military-linked companies infiltrating the U.S. battery storage supply chain.
But the recurring star of the show is the Moss Landing Fire in California, when in January a 300-MW BESS caught fire. People in nearby areas were evacuated. The cause of the fire remains under investigation, and EPA is leading an ongoing cleanup.
The environmental impacts are unclear. While local scientists at Elkhorn Slough, a national estuary reserve near Moss Landing, found that heavy metal contamination spiked in the aftermath of the fire, they aren’t certain about long-term ecological or health consequences.
“We don’t know yet what is going to happen in terms of the estuary habitats here,” said Ivano Aiello, a scientist at San Jose State University who studies the wetland dynamics of the area. “We are monitoring the microbes; we are monitoring the [animals, from] invertebrates all the way up to the sea otters, to understand whether those metals are moving through the food web.”
The Moss Landing site previously was a gas plant. Aiello said that it was unclear whether the pollution seen from the battery fire was comparable to the effects of previous emissions.
“We use sediments as a time machine,” Aiello said. “Once the emergency ends here, it’s one of the things I’d like to use the core samples as a way to assess.”
Matthew Paiss, a technical adviser on energy storage safety for Sandia National Laboratories and former firefighter, lives near Moss Landing. He said that in general, consumer-grade rechargeable lithium batteries were not manufactured to the same high standards as utility-scale batteries.
“People are looking for the cheapest battery they can, and if your job is as a gig employee and you’re delivering Uber Eats, and your $500 battery loses capacity, you’re going to take it to a local shop and get a couple cells changed out,” Paiss said. This kind of tweaking, coupled with hard physical wear and tear, was the cause of most failures, he said.
Paiss has studied the general causes of BESS failures using BESS Failure Database data from the Energy Policy Research Institute. In general, he said utility-scale battery fires occur because of installation errors and failures with overall protection systems. The Moss Landing facility kept many of their batteries in old buildings on site, which may have contributed to the fire by reducing “fire segmentation,” he said.
“Best practices moving forward are to limit the amount of propagation,” he said. “That’s why we’re seeing a lot of outdoor containers.”
Lakshmi Srinivasan, the team lead for EPRI’s energy storage program, said that since 2011, the rate of BESS fires has declined worldwide as the industry improves safety. Of the failures they’ve been able to isolate causes for, the battery cells themselves were not the most likely to cause fires. Other components, installation problems, bad thermal management and HVAC systems were the most common causes.
“The key takeaway from this work was actually that we know how to engineer controls and the balance of the system to prevent these kinds of failures going forward,” she said.
Local Government Outreach
What seemed to have the most impact on the Poughkeepsie Town Board’s decision to implement zoning was a panel discussion in June in which the Dutchess County Mayors and Supervisors Association met with experts to discuss BESS facilities.
The meeting, held at the Board of Cooperative Educational Services Conference Center, attracted policy wonks, local government officials, firefighters, first responders and concerned citizens. The crowd listened to presentations by Paul Rogers, a former New York City Fire Department lieutenant working for the Energy Safety Resource Group; Jeffrey Seidman, a Vassar College professor; and Jennifer Manierre, director of clean energy siting for the New York State Energy Research and Development Agency.
Seidman helped organize the meeting with town Supervisor Edwards. What originally had been an “old boys club” for local government officials became, for one night, a policy discussion forum.
Seidman explained the benefits of utility-scale batteries, primarily load shifting, enhanced grid reliability and reduced use of expensive peaker plants. Batteries would help reduce energy costs if built in sufficient numbers across the state, he argued.
“Demand for electricity is going up absolutely everywhere,” Seidman said. This meant more demand for substations and transmission lines. “Batteries save us money by not making us have to do those expensive upgrades.”
Manierre offered NYSERDA’s service to help local officials with zoning and planning and explained the role of batteries in the state energy plan.
Rogers reviewed the New York Fire Code development process, the safety considerations afforded to firefighters and the relative risks of fires at battery plants compared to more conventional buildings. Each facility needs to have an on-call person to handle emergencies and coordinate with first responders, he explained.
“We put these things in place to try to help … because our thing is to keep everyone safe,” Rogers said. “I’ll never say ‘never,’ but we significantly reduce the risk of an event taking place,”
Battery storage facilities were required by the fire code to undergo large-scale fire testing, he explained. This meant that manufacturers needed to test-burn entire battery cabinets.
“What the [testing] proves and validates is that if something takes place that it doesn’t leave the container, it stays in the container,” Rogers said.
Seidman told RTO Insider that local organizers were setting up another forum in Ulster County, where several battery facilities are planned. He hopes that by mid-November, a similarly productive conversation can happen there too.
“I think a lot of people are not ideologically or otherwise opposed to batteries, but they just don’t mean anything to them,” Seidman said. “Like, ‘why should we put our necks out?’”
Seidman said that he received a good response from town officials after the meeting and that one had invited him to a local temple to give a talk on batteries. He said he hopes his efforts can make a difference for the climate and local air quality.
“I’d love to make this a traveling road show,” he said. “This is something I would like to repeat.”
As NYISO continues its Capacity Market Structure Review, the Market Monitoring Unit used its second-quarter State of the Market report to highlight potential issues with how the ISO forecasts resource availability, with the late June heat wave as a test case.
All-in prices were up across all zones of the New York Control Area, driven by an increase in natural gas prices. But “in addition to the gas prices, I think the extraordinarily high load level that peaked in late June … certainly added a lot to real-time prices,” Pallas LeeVanSchaick, vice president of Potomac Economics, told the Installed Capacity Working Group on Sept. 8.
LeeVanSchaick offered a breakdown of the performance of fossil fuel generators, emergency capacity and large curtailable loads during the heat wave. He said the MMU wanted to highlight these resources because they have not been the focus of prior capacity accreditation discussions.
“It’s sort of outside the standard analyses that we do,” he said. “It has to do with capacity accreditation. … Obviously we and … NYISO and other regional market operators have spent a lot of time on how to improve capacity accreditation.”
The analysis compared the performance of fossil fuel resources systemwide during the June heat wave against their weighted average equivalent demand forced outage rate (EFORd), which measures how much capacity a resource could reliably provide when in demand. During peak hours in the heat wave, the MMU found that units were out of service more than predicted by their average EFORd.
“The concern here is if you look at the stuff that was unavailable due to either forced outages or performance, the number comes out to 24.9% on the 24th, compared to an average EFORd of 5.9%,” LeeVanSchaick said. This means that EFORd is being calculated too low because it is not taking into account how certain generators are being used, he said.
Some fossil fuel plants, like peakers, are dispatched to run at high outputs very rarely. These plants are aging, which reduces their ability to operate at high output. If they aren’t called on to push high power out frequently, EFORd will not capture when they fail to function at those levels, leading to far more optimistic rates. This problem also occurred with steam turbine units during the heat wave.
“This heat wave presented a unique opportunity because we haven’t seen conditions where so many units were asked to operate at high levels,” he said.
In addition, some capacity that was available to the ISO was not recognized by its real-time model as available. About 213 MW that previously participated in the Capacity Limited Resource and Emergency Capacity programs were not scheduled and did not produce energy; 73 MW of capacity that were not scheduled but produced voluntarily were also not recognized.
“What we found was that there was not an operating procedure to utilize these megawatts that was ready to be used on these days,” LeeVanSchaick said. “Although the conditions and operating reserve shortages would have warranted using this capacity, it wasn’t actually scheduled.”
Roughly 90% of large loads across 600 MW of demand response programs voluntarily curtailed during the peak load hour June 24, he said. These were resources participating in the Special Case Resource (SCR), Demand-Side Ancillary Service (DSASP), distributed energy resource and Behind-the-Meter Net Generation programs.
These DR actions had some inefficiencies. Over 200 MW of SCRs were curtailed when they could have provided DSASP reserves; 70 MW of SCRs curtailed for four hours as requested but then increased consumption during the peak, meaning they weren’t deployed when they were most valuable.
“We’re going to need to think further about how to potentially refine these programs so that these things are consistent for resources to be participating efficiently,” LeeVanSchaick said.
The U.S. Department of Energy is kicking off its Speed to Power initiative by seeking input on large-scale grid projects that would serve large-scale data centers.
The move is the latest in a series of efforts President Donald Trump initiated hours after his inauguration to boost American energy production. There has been an emphasis on boosting production and consumption of fossil fuels while hindering development of intermittent renewable energy resources, but energy infrastructure also is a priority.
DOE said Speed to Power is centered on multi-gigawatt generation, transmission and grid infrastructure projects that will enable the U.S. to accelerate artificial intelligence buildout.
“With the Speed to Power initiative, we’re leveraging the expertise of the private sector to harness all forms of energy that are affordable, reliable and secure to ensure the United States is able to win the AI race,” Energy Secretary Chris Wright said in a Sept. 18 news release.
The same day, DOE’s Grid Deployment Office issued a request for information that would help it identify projects that enable minimum incremental load of 3 GW and support up to 20 GW of incremental load.
These can include building new interregional transmission (minimum 1,000 MVA); reconductoring existing lines (minimum 500 MVA); bringing retired thermal generation facilities back online or using their interconnection capacity for new “reliable” power generation; and constructing new generation.
DOE reminded respondents about the funding and technical assistance programs available for such projects.
The interactive map offers some of the information developers need as they conduct site assessments, including: power demand from data centers that are planned, under construction or in operation; fiber-optic cable networks; transmission lines; power plants; substations; natural gas pipelines; day and night population; NERC reserve margins; FEMA risk indexes; and railroads.
DOE said its launch of Speed to Power will “ensure the United States has the power needed to win the global artificial intelligence race while continuing to meet growing demand for affordable, reliable and secure energy.”
The Problem Solvers Caucus, a bipartisan group of House members, has released a framework for energy infrastructure permitting legislation as momentum for a bill grows in Congress.
The caucus’ Permitting, Energy and Environment Working Group, led by Reps. Scott Peters (D-Calif.) and Gabe Evans (R-Colo.) and co-chairs Reps. Brian Fitzpatrick (R-Pa.) and Tom Suozzi (D-N.Y.), developed the framework over the past few months by working with energy producers, industry experts, members of relevant congressional committees and other stakeholders.
“America faces a choice between cheap, abundant energy from all-of-the-above sources or higher energy prices, falling behind China and an increased risk of blackouts,” Peters said in a statement. “It’s obvious where we need to go. To get there, we know we need to update our environmental laws to meet the challenges of today and invest in a grid for this century. This platform represents a bipartisan commitment to set aside ideology and solve this problem for the American people. I look forward to working with my colleagues to keep the momentum going and turn this into legislation that can pass both chambers of Congress.”
The framework for permitting reform covers a range issues from efforts to streamline reviews under the National Environmental Policy Act to changing how the largely untested National Interest Electric Transmission Corridors (NIETCs) work by allowing just one line (rather than a broader region) to qualify as a corridor. The NIETCs are designated by the Department of Energy and any lines qualify for backstop siting at FERC.
The NIETC process would be amended to allow for simultaneous state and federal reviews (recognizing state authority), and it would require DOE to act on applications within 90 days.
The process for judicial review of DOE- and FERC-approved linear infrastructure projects would be consolidated under the exhaustion and judicial review provisions of the Federal Power Act.
The framework includes categorical exemptions for simple updates to existing linear infrastructure, especially in disaster-prone areas. The Forest Service’s management and wildfire mitigation activities in utility rights-of-way should be expedited.
To help meet rising demand, the framework calls for FERC to initiate interregional planning (excluding ERCOT), with Congress providing “strong guidance on the allocation of the costs of these infrastructure projects” while excluding cost allocation to customers who receive no or trivial benefits.
On domestic supply chains, the Problem Solvers Caucus calls for DOE to “regularly assess electricity generation and transmission supply chains for security and resilience.”
“Reforming our permitting system is crucial, and this framework meets the moment for much-needed change. The demand for affordable and reliable energy of all kinds becomes increasingly urgent,” Evans said in a statement. “By cutting through red tape, we can meet energy demand, lower costs, strengthen national security and create high-quality jobs in America, while being responsible stewards of the environment and maintaining our position of global leadership and not cede ground to China. The urgency is real, and I am proud of this bipartisan push for change.”
The caucus’ permitting reform framework was welcomed by Grid Action Executive Director Christina Hayes, who said it shows Democrats and Republicans can come together to find solutions that strengthen the grid, cut red tape and speed up the development of transmission infrastructure.
“As demand for electricity soars, driven by the rapid growth of artificial intelligence, new data centers, and the everyday needs of families and businesses, the urgency of bipartisan action has never been clearer,” Hayes said. “This framework recognizes that meeting those demands means modernizing our permitting system so that transmission projects can move forward quickly, reliably and affordably.”
