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December 21, 2025

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PG&E Bomber Sentenced to 10 Years in Prison

Peter Karasev, the California man who pleaded guilty to bombing electrical transformers owned by Pacific Gas and Electric in December 2022 and January 2023, has been sentenced to serve 10 years in federal prison and pay more than $200,000 in restitution to the victims of his attack.

U.S. District Judge Beth Freeman handed down the sentence on Dec. 16, the Department of Justice wrote in a press release, just over three years after Karasev carried out his first bombing. After his prison time, which Freeman recommended be as close as possible to Karasev’s family in Atlanta, the defendant must serve three years of supervised release.

Karasev, who was 36 at the time of his arraignment, initially pleaded not guilty to two counts of damaging energy facilities and one count of using fire and an explosive to commit a felony, but changed his pleas on the energy facilities charges after reaching an agreement with prosecutors in April. (See California Man Arraigned for Substation Bomb Attacks.) Prosecutors agreed to drop the third charge as part of the deal.

Karasev’s guilty plea agreed that “the attacks were premediated and deliberate,” DOJ said, mentioning that the defendant “conducted extensive internet searches regarding explosive materials, infrastructure attacks and geopolitical conflicts.” According to court records, Karasev, a naturalized citizen born in Russia with family in both Russia and Ukraine, had frequently mentioned the military conflict between the two countries in the months prior to his first attack “and was often upset when doing so.”

Karasev carried out his first attack around 1:30 a.m. Dec. 8, 2022, exploding a homemade bomb between the cooling fins of a transformer near a shopping mall. The second attack occurred shortly before 3 a.m. Jan. 5, 2023, at a transformer near a shopping center. 1,451 PG&E customers lost electric service because of the first attack, while the second attack affected about 55 customers.

The indictment said “PG&E initially assumed the outages were cause by internal transformer failures,” but later investigation revealed that both incidents were caused by explosive damage. Officers with the San Jose Police Department checked surveillance footage after the second bombing and saw “a single suspect wearing dark clothing and a backpack.” The person in the video arrived by bicycle around 2:48 a.m., then put his backpack near the transformer box, lit it on fire and left on his bicycle. The transformer exploded a few minutes later.

Karasev was tracked down through cell phone data obtained via a warrant, which showed only a single active device within the targeted area during the relevant time period. That device was traced to Karasev, and a check of his search history revealed additional incriminating information, such as a search for the phrase “san jose news” within 30 minutes of the December 2022 bombing and further searches for “shaped charge” and “sjfd [San Jose Fire Department] explosion.”

Peter Karasev | San Jose Police Department

Officers who searched Karasev’s home uncovered homemade explosives, firearms, a bicycle resembling the one from the security footage and a methamphetamine lab with finished drugs. Explosives, drugs and ammunition were found in his vehicle and office at self-driving car company Zoox.

DOJ emphasized the potentially serious impact of Karasev’s actions, observing that 15 of the households affected by the bombings were enrolled in PG&E’s Medical Baseline Program for customers requiring uninterrupted electric service for medical needs.

Judge Freeman’s order includes $214,880.67 of restitution to PG&E, Best Choice Dental, CalStar Management and Round Table Pizza. The indictment named Round Table among businesses in the shopping center where Karasev carried out the first attack and mentioned that the second explosion “shattered the windows of” a nearby dentist’s office.

Karasev “aimed to inflict widespread disruption and harm, but we remain steadfast in our commitment to holding accountable those who threaten the safety and well-being of the residents of San Jose,” said Craig Missakian, U.S. attorney for the Northern District of California. “We and our law enforcement partners will leverage every available resource to ensure that violent extremists like the defendant face the full force of justice.”

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N.Y., Ontario Collaborating on Nuclear Power Development

New York and Ontario are teaming up to develop nuclear power generation.

New York Gov. Kathy Hochul (D), Ontario Premier Doug Ford (PC), and the leaders of the New York Power Authority (NYPA) and Ontario Power Generation (OPG) gathered Dec. 19 in Buffalo, N.Y., to sign a memorandum of understanding on nuclear development.

NYPA and OPG will share information, resources and institutional knowledge to support the economic, technology and workforce initiatives needed for advanced nuclear development on both sides of the border.

The leaders of both governments have made nuclear an important part of their energy strategies:

The first small modular reactor in a G7 nation is under construction in Ontario and three more are planned nearby, while New York has begun the development process for at least a gigawatt of advanced nuclear capacity.

NYPA and OPG have a long history of collaboration with their hydropower generation plants on the Niagara and St. Lawrence rivers, which form the U.S.-Canadian border.

NYPA recently named as its senior vice president of nuclear energy Todd Josifovski, who was director of the $13 billion (CAD) overhaul of OPG’s four-reactor Darlington Nuclear Power Station, now nearing completion. (See Former Ontario Power, NRC Leaders Join NYPA Nuclear Effort.)

Most of OPG’s nuclear fleet is on the north shore of Lake Ontario. New York’s commercial fleet, operated by Constellation Energy, is entirely on the south shore.

The combined age of New York’s four reactors is 198 years. Among them are the oldest and second-oldest operating commercial reactors in the nation.

But the state relies on their over-90% capacity factor to meet its power needs and emissions reduction goals. New York pays half a billion dollars a year in subsidies for their operation and is considering extending the subsidy framework by 20 years. (See N.Y. Makes Case for Extending Nuclear Subsidies to 2049.)

Meanwhile, large scale renewable energy development in New York is lagging well behind the hoped-for pace, and many fossil-fired plants still are running at or beyond the average retirement age.

Against this backdrop, Hochul in June ordered the nation’s largest state-owned public power organization to develop at least 1 GW of advanced nuclear capacity. (See N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.)

NYPA once operated nuclear reactors but divested them decades ago. Its neighbor across the border presents a broad contemporary knowledge base to draw from as New York positions itself to be an early mover in the nuclear renaissance many policymakers are attempting to engineer.

“This first-of-its-kind agreement represents a bold step forward in our relationship and New York’s pursuit of a clean energy future,” Hochul said in a news release. “By partnering with Ontario Power Generation and its extensive nuclear experience, New York is positioning itself at the forefront of advanced nuclear technology deployment, ensuring we have safe, reliable, affordable and carbon-free energy that will help power the jobs of tomorrow.”

Premier Ford said in his own news release: “From building the first small modular reactors in the G7 to building the first large-scale nuclear facilities in decades, Ontario is proud to lead the world in nuclear innovation. By working together with New York, we’re creating good-paying jobs, growing our economies and delivering clean, affordable power for families and businesses on both sides of the border for generations to come.”

Beyond the nuclear memorandum of understanding, the two leaders signed a declaration of intent for continued economic cooperation at a time when border crossings, trade and tourism have been affected by U.S. policy changes.

This idea of cross-border cooperation and trade was a recurring theme as Hochul and Ford spoke. Hochul referred to threats and hostility toward Canada from President Donald Trump via his trade policies and tariffs. In October, Ford famously angered Trump by airing an anti-tariff commercial.

But Hochul also said she had spoken to Trump about the arduous, decadelong federal permitting process for nuclear construction, and she said he agreed that it was too slow. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.)

Her complaint was a bit ironic, given New York’s reputation as a slow and expensive state with a thick regulatory structure for energy developers, but there, too, efforts are underway to streamline the siting, permitting and interconnection processes.

NYPA has begun laying groundwork for its nuclear project, including by seeking host community support for what remains a controversial and worrisome prospect for many Americans. (See Wanted: N.Y. Community Eager to Host Nuclear Reactor.)

In her remarks at the Dec. 19 ceremony, Hochul said NYPA has heard responses from eight communities and 21 developers that want to be part of the project.

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UPDATED: NV Energy Filing Reveals Extensive Talks Around EDAM RA Program

Future participants in CAISO’s Extended Day-Ahead Market already have held extensive talks about developing an alternative to the Western Power Pool’s Western Resource Adequacy Program for non-CAISO EDAM members, NV Energy confirmed in a filing with Nevada utility regulators.

A smaller group of utilities began initial discussions as early as spring 2025, with participation expanding during the summer, according to the Dec. 18 filing the Las Vegas-based utility holding company submitted to the Public Utilities Commission of Nevada (PUCN) in response to questions about its decision to withdraw from the WRAP.

The Pathways Initiative’s Regional Organization for Western Energy has been floated as a potential overseer of an EDAM-aligned RA program. (See Pathways’ ROWE Could Offer Western RA Program, PGE Says.)

“Currently, the discussions have been informational to gain a better understanding of CAISO’s capabilities for this type of service and a high-level understanding of other resource adequacy design choices,” NV Energy, parent of Nevada Power and Sierra Pacific Power, wrote in the filing. “The group is beginning to discuss high level preferences on design in order to understand if there is enough consensus to move forward into more detailed discussions.”

“CAISO is participating in regular discussions with those EDAM participants that are exploring concepts around resource adequacy in the West,” ISO spokesperson Jayme Ackemann told RTO Insider in an email. “Those exploratory conversations are being led by participating utilities. CAISO’s involvement to date has been engaging through participation in a technical advisory capacity in weekly, informal work group discussions.”

Ackemann said CAISO could potentially play a role in facilitating the program, “but no specifics have been determined at this time.”

The group of EDAM utilities, whose names have been redacted from the version of the document made available publicly, met seven times this summer to discuss a potential program.

Discussions among the larger group began after a summer meeting between WRAP participants and WPP leaders to talk about “outstanding issues” with the WRAP ahead of the upcoming Oct. 31 deadline for committing to the program’s first “binding” — or penalty phase — season in winter 2027/28.

Five utilities withdrew from the WRAP before the deadline, including four future EDAM participants: NV Energy, PacifiCorp, Portland General Electric (PGE) and Public Service Company of Nevada (PNM). Of the 16 participants committing to the program, most plan to join SPP’s Markets+, which requires participation in the RA program. (See WRAP Wins Commitments from 16 Entities.) Some withdrawing entities have indicated they could re-enter the program if certain concerns are addressed.

According to the filing, the EDAM group discussed whether “there was a desire to work on a potential resource adequacy program for EDAM and what guiding principles might be important.”

The group on Oct. 15 held a kickoff meeting for “more robust” and regular discussions and weekly meetings began Oct. 31, with a two-day, in-person session to be held in January 2026.

“The group is working towards high-level design consensus between potential participants with an understanding that the overall program will need to be designed in detail through a stakeholder process,” NV Energy wrote.

The filing reveals that the smaller group met almost every other week from April until August, commissioning the Western RA study published by The Brattle Group in November that found “the non-CAISO EDAM footprint offers significant resource adequacy benefits, on par with and possibly exceeding the resource adequacy benefit of the current WRAP footprint.” (See Brattle Study Finds Similar PRMs Under Alternative Western RA Footprint.)

Brattle prepared the report on behalf of the Balancing Authority of Northern California, Idaho Power, the Los Angeles Department of Water and Power, NV Energy, PacifiCorp, PGE, PNM, the Sacramento Municipal Utility District and Seattle City Light.

Among that group, only Idaho Power and Seattle City Light have committed to the WRAP’s first binding season, although the former’s commitment came with qualifications about how certain elements of the program takes shape over the next two years.

“The Brattle study illustrates that an EDAM resource adequacy footprint would be comparable to the subregions that currently exist in WRAP,” NV Energy wrote in its filing. “Therefore, there is potentially a viable option that could be developed for EDAM without the WRAP issues identified in” the company’s Aug. 29 testimony to the PUCN, which pointed to the “high financial risk” it faced from WRAP penalties in the binding phase, along with other issues with the program. (See NV Energy to Withdraw from WRAP.)

Although it did not sign on to the Brattle study, California’s Imperial Irrigation District has told RTO Insider it has participated in the EDAM RA program discussion.

‘Excessively High’

NV Energy’s Dec. 18 filing quantifies the financial risk the company foresaw from participating in the WRAP.

While a chart in the filing redacts the megawatt values of NV Energy’s capacity surpluses and deficiencies for the WRAP’s summer and winter seasons between 2023 and 2028, the company notes its subsidiaries have met program requirements for every non-binding winter season since 2022/23 and likely would meet winter requirements for 2026/27 and 2027/28.

But summer is a different matter. NV Energy was short resources for each summer season between 2023 and 2025 and is expected to come up short in the first binding summer of 2027. That shortfall would have exposed the company to more than $90.7 million in deficiency charges, or just under $22.7 million with a potential 75% reduction in penalties in the early part of the binding phase, according to its estimates.

NV Energy pointed out that its “primary issue” with WRAP is its “excessively high” deficiency charge, which is calculated on a $91.81/kW-year cost of new energy (CONE) value, set by the WRAP CONE Penalty Task Force in 2022.

A WRAP proposal “states that the WPP will update the CONE annually, but this has not occurred. This is the only value that has been published to date; therefore, this is the value that [NV Energy] utilized for the deficiency charge calculations knowing that today’s penalties are likely much higher,” NV Energy wrote.

NV Energy notes that a proposal by the WRAP’s Resource Adequacy Participants Committee to implement a policy of deferring deficiency charges for up to five years if a participant shows it is making a commercially reasonable effort to resolve a shortfall does not address its concern about the level of the charges.

“Regardless, this proposal has merit and could be of assistance in the event of any penalty, given the supply chain issues and industry uncertainty currently in place,” the company wrote.

NV Energy also expressed concerns about the feasibility of efforts by the WRAP’s Day-Ahead Market Task Force to possibly align the program’s operational subregions with the EDAM and Markets+ footprints.

“The approved concept paper envisions an operations program sharing calculation that occurs at each individual market footprint for sharing amongst those participants before a sharing calculation between the participants in both markets,” it wrote.

The company said the concept remains “incomplete” in that it does not yet address how participants that will remain in CAISO’s Western Energy Imbalance Market and not join a day-ahead market will function under a paradigm designed for the two day-ahead markets.

NV Energy said the concept paper also fails to address how the WRAP’s forward showing regions would be affected by such an alignment with respect to issues such as transmission connectivity to support the viability of a footprint.

“The forward showing footprint matters because it is utilized for the modeling of the one event in 10 year loss of load metric to determine the [planning reserve margins] or resource adequacy requirement for the participants,” the company wrote. “If the market footprint does not have access to the same forward showing footprint used for planning, then the participants within that market will no longer be planning for the reliability metric which has been used as an industry standard.”

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BPA Triggers $40M Surcharge Following Low Water Years

The Bonneville Power Administration announced a $40 million surcharge to rebuild financial reserves depleted after three years of low water, saying the move could increase the annual average effective rate 2.2% for most power sales.

BPA said the surcharge for power customers is due to increased costs in power purchases because of challenging water levels over the past three years. The administration announced Dec. 18 that it would recover the $40 million surcharge in rates from December 2025 through September 2026.

“We know that a surcharge was unexpected by our ratepayers,” BPA Administrator John Hairston said in a statement. “Our third-quarter forecast indicated a low probability of triggering a surcharge, but continued cost increases in power purchases, resulting from a third bad water year in a row, were the primary driver.”

BPA implemented the surcharge under its Financial Reserves Policy (FRP). The policy aims to maintain sufficient financial reserves and promote rate stability. BPA said the policy and other cost-management efforts “have resulted in rates that are flat or below national inflation over the previous decade.”

The final Power FRP surcharge rate is $1.01/MWh, and the final annual rate is $0.84/MWh. BPA said the surcharge would increase the annual average effective rate 2.2% for non-slice Tier 1 rates, according to the announcement.

Tier 1 “non-slice” contracts represent most of BPA’s power sales. “Non-slice” refers to a type of contract in which the customer is guaranteed a specified volume of energy regardless of conditions on the hydro system; in contrast, total volumes delivered to “slice” customers can vary based on availability.

Hairston wrote in a Dec. 11 letter that the agency discussed the surcharge during its fourth-quarter review in November. The agency settled on the surcharge amount after a public review and comment period on preliminary calculations. (See BPA Looks to Fill 155 Positions After Hiring Freeze.)

“We received only one comment on the surcharge and the process itself, and none on the data or calculations,” Hairston noted.

The surcharge comes after the agency announced in July that customers’ power rates could increase by about 8 to 9% over the BP-26 rate period covering the 2026/28 interval. (See BPA Customers to See Increased Power, Transmission Rates.)

“We recognize this surcharge impacts our customers, and we are actively working to improve our forecasting and transparency,” Hairston said. “BPA is committing to leading a holistic reevaluation of our current risk mitigation measures, including surcharges, prior to our next rate case and leveraging the lessons learned from these three consecutive poor water years and their strain on the agency’s financial reserves.”

‘Sound Risk Management’

BPA said it has triggered a surcharge only once — in 2020.

“Since then, BPA has provided rate reduction through its reserves distribution clause in 2022, 2023 and 2024, for a total dividend distribution of $529 million,” according to the announcement. “These dividends help reduce mid-period rate pressure and keep the annual average rate change from 2020 to 2026 at 1.5%, significantly less than ongoing inflation in those years.”

Fred Heutte, senior policy associate at the Northwest Energy Coalition, said in an email to RTO Insider that BPA could take three steps to alleviate the impact of hydro deficits, including supporting the new Northwest Energy Efficiency Alliance joint utility initiative on demand response. He also pointed to the agency’s transmission initiatives: the Grid Access Transformation and the Grid Expansion and Reinforcement Program.

“Together these will open the door to thousands of MW of new renewables and other resources that will expand supply and diminish our exposure to super-peak market prices,” Heutte said. He added that the agency should reconsider its choice to join SPP’s Markets+ day-ahead market. (See BPA Chooses Markets+ over EDAM.)

“BPA’s own studies show that having two power markets running on top of their grid will raise costs for everyone in our region and across the west,” Heutte said. “The Extended Day-Ahead Market is poised to substantially expand the benefits of the Western Energy Imbalance Market, which almost all of the Northwest is in. That will provide further protection from market price spikes and reliability concerns when we most need it and reduce the risk of future wholesale rate surcharges.”

Scott Simms, executive director of the Portland, Ore.-based Public Power Council, told RTO Insider the 2.2% increase in wholesale power costs is “a modest adjustment in the context of total rates, but not insignificant for utilities managing tight budgets and facing cost pressures and affordability issues in their communities.”

“The surcharge also comes on the heels of the 8.9% wholesale rate increase from the BP-26 rate proceeding that came into effect Oct. 1,” Simms said. “It’s important to acknowledge that rate increases are a real and growing concern for utilities and their customers, and at the same time, BPA’s action reflects sound risk management to protect long-term rate stability. PPC sees the surcharge as temporary, targeted, and tied to transparent policy triggers rather than arbitrary cost shifts, and we remain vigilant in thoroughly reviewing any BPA rate changes and their drivers.”

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Maryland Governor Issues Executive Order on Affordability and Reliability

Maryland Gov. Wes Moore (D) issued an executive order aimed at ensuring reliable and affordable power just a couple of days after PJM’s capacity auction cleared short of its reserve margin target. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

The order, “Building an Affordable and Reliable Energy Future,” was issued Dec. 19 and seeks to optimize permitting processes, agency review and site preparation to facilitate the deployment of shovel-ready projects needed to close the projected capacity gap.

“Over the last few years, utility bills have spiked, and for many Marylanders, energy policy has stopped being technical and started being personal,” Moore said in a statement. “This order addresses the untenable system causing these costs to skyrocket. We are putting affordability and reliability at the center of the conversation to ensure our system works for the people who use it, not just the companies that run it.”​​

The order creates a new “Energy Subcabinet” that will be chaired by the director of the Maryland Energy Administration (MEA), with members from cabinet agencies, Moore’s deputy chief of staff and other cabinet-level officials as designated by the governor.

A day before the executive order, Moore’s office announced that Kelly Speakes-Backman would be the new director of the MEA effective Dec. 24, after former Director Paul Pinsky retired. Speakes-Backman is a former Maryland PSC commissioner and deputy assistant secretary at the U.S. Department of Energy.

“Kelly Speakes-Backman is a trailblazer in the energy industry with the deep expertise and track record to lead the Maryland Energy Administration,” Moore said in a statement. “She is a proven public servant who believes in our state, understands our energy system and knows how to turn policy into lasting results. We are proud to welcome her back to state service as we work together to build a more affordable, competitive and sustainable future for all Marylanders.”

The Energy Subcabinet will meet at least quarterly to align state resources and ensure that energy policy decisions support the state’s affordability, reliability, economic competitiveness and environmental goals. The subcabinet will review proposed energy legislation or administrative policies and draft recommendations on them.

In addition to the subcabinet, the order creates the Maryland Energy Advisory Council, which will be chaired by Speakes-Backman and include representatives from the state Senate, the House of Delegates, the PSC, the Office of People’s Counsel, the Maryland Clean Energy Center, regulated utilities, PJM and other stakeholders.

The council is charged with identifying barriers to the deployment of generation facilities and affordability. Within 180 days, it will submit a memorandum to the subcabinet identifying the biggest challenges to affordability and reliability.

The MEA must submit written recommendations to the speaker of the House of Delegates and the president of the Senate by Jan. 16, 2026, that identify strategies to mitigate rate impacts. It will evaluate regulatory, administrative and planning tools that align implementation of the State Energy Plan with affordability and reliability, and it will outline consideration for any energy legislation next session.

The order includes a clause saying nothing in it will impact the PSC’s independence, but MEA will file some petitions with the regulator. The first will seek a review of the budget billing programs at utilities. The second will seek a regulatory strategy that prioritizes flexible and optimized lower-cost grid solutions. The third will seek rule changes requiring utilities to evaluate advanced transmission technologies (ATTs) and grid-enhancing technologies (GETs).

A work group of the subcabinet will examine ways to modernize the state’s transmission infrastructure, including using ATTs and GETs and building new transmission lines and other infrastructure such as battery storage on state-owned rights-of-way.

Another work group of the subcabinet will be set up to examine sites around the state that can be used quickly to develop new energy infrastructure.

The American Council on Renewable Energy welcomed Moore’s executive order in a statement.

“ACORE commends key provisions in the order to increase the deployment of advanced transmission technologies; streamline the siting and permitting of high-voltage transmission, energy storage and other infrastructure; advance wholesale market reforms; and more,” ACORE CEO Ray Long said. “As the country enters a new era of electricity demand, initiatives like Gov. Moore’s will facilitate significant progress toward building a modern and reliable grid needed to maintain economic competitiveness and keep the lights on.”

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Michigan PSC OKs DTE Energy’s 1.4 GW Data Center Contract, AG Pans Process

The Michigan Public Service Commission has approved a special contract that will allow DTE Energy to continue its plans to supply a hotly contested, $7 billion data center with nearly 1.4 GW of power.

The less-than-two-month approval process and ensuing agreement with redacted sections elicited harsh words from the Michigan attorney general.

The Michigan PSC conditioned its Dec. 18 approval on DTE absorbing “any” costs to serve Open AI, Oracle and Related Digital’s proposed 1,383-MW data center in Saline Township (U-21990). DTE on Oct. 31 requested expedited approval of the large load supply agreement. The 250-acre data center campus is poised to add more than 10% to DTE’s peak demand.

The terms of the supply agreement specify a 19-year contract; a requirement that the data center owners pay 80% of the contracted electricity use, even if their actual usage is lower; and an early termination fee of up to 10 years’ worth of the minimum 80% payments.

The PSC’s final approval is contingent on DTE updating its emergency procedures so that should load shedding occur, the data center is first in line to be reduced or cut before other customers.

To submit a commentary on this topic, email forum@rtoinsider.com.

The commission directed DTE to amend the renewable energy plan in its next integrated resource plan that compares what it needs to do to comply with Michigan’s renewable portfolio standard with and without the data center, and how it plans to equitably recover possible additional costs associated with meeting clean energy goals. The PSC said DTE needs to update its capacity demonstration and furnish an analysis showing how the new large load will affect its capacity demonstration.

The deal includes a proposed energy storage agreement in which Oracle, over 15 years, would fund development of 1,383 MW of energy storage facilities to match the data center’s contracted demand. DTE would own and operate the facilities, but Oracle would receive market revenues from operating the energy storage facilities in MISO’s wholesale markets. Like the supply agreement, the storage agreement would require a payout if Oracle exits DTE’s territory prematurely.

The PSC said the arrangement would not increase rates on other customers and “therefore met the standard for an ex parte review under Michigan law and precedent established by Michigan courts going back decades.” The PSC said in the past, it has approved other large special contracts between DTE Electric and customers including Ford, Fiat Chrysler Automobiles and the University of Michigan.

Ex parte proceedings in Michigan don’t allow public hearings, nor do they let interested parties conduct discovery or file testimony.

“These protections will ensure that Michigan is able to reap the benefits of adding a significant new energy user to the grid while keeping any related costs off the utility bills of other customers,” Michigan PSC Chair Dan Scripps said in a press release. Scripps said he heard from “thousands of Michiganders concerned about the risks of higher utility bills for everyday customers and reversal of progress the state has made in decarbonizing its energy production.” He said the commission shares those concerns and enacted cost protections while “supporting economic development.”

The commission said the agreement would make rates more affordable because the data center would share in fixed system costs previously shouldered by DTE’s existing customers. DTE estimated an approximate $300 million net benefit to other customers.

Michigan AG, Enviros, Consumer Advocates Condemn Skipped Hearings

Michigan’s attorney general and environmental and consumer advocate groups said the PSC should not have fast-tracked the contract and should have let hearings play out in a contested case.

Michigan Attorney General Dana Nessel criticized what she called a rushed approach to the massive data center project that kept the public in the dark.

“I am extremely disappointed in the MPSC’s decision to fast-track DTE’s secret application to service this massive data center without holding a contested case hearing. While I am relieved that the commission at least purports to have placed some conditions on DTE’s application, without being able to see the full, unredacted contract, and study the predicate conditions and enforcement mechanisms set by the commission, it is impossible to verify any of these claims today,” Nessel said in a Dec. 18 statement.

Nessel said her office is considering steps it could take to protect residents. She noted that her office fielded more than 5,500 public comments, “overwhelming opposition from community leaders and bipartisan calls from public officials urging the commission to slow down.”

Nessel said the “secret contract still leaves Michiganders scrounging for hidden and vital details that could harm ratepayers should these AI corporations leave, move out of state or simply go bankrupt.” She said she didn’t know what exit fee provisions would be in place before December 2027, as DTE prepares for the construction phase.

Nessel previously said a public hearing would have been the only avenue to ensure transparency and validate details of the deal.

DTE said the data center deal would have been at risk if the commission had not expedited its evaluation.

The Sierra Club, Michigan Environmental Council, Natural Resources Defense Council and Citizens Utility Board of Michigan criticized what they called a rushed approval process and DTE’s “significantly” redacted proposal, which “foreclosed the ability of the public to scrutinize and meaningfully weigh in on an application that will have significant consequences for their communities and could substantially increase utility bills.”

They said the PSC’s multiple conditions on approval remain an “open question” and asked how regulators would hold the companies to their promises. They also said Oracle has increasing debt obligations and waning stock prices and that the PSC “largely punted” on the question of how DTE would meet clean energy mandates to future proceedings.

“We are disappointed that the commission conceded to DTE’s demand for a rushed, ex parte review of a heavily redacted, 19-year contract for one of the largest new electric loads in state history,” Shannon Fisk, an Earthjustice attorney, said in a statement. Earthjustice represented Sierra Club and the other groups in the proceeding. “While billions of dollars and massive amounts of energy will be needed to serve the proposed Oracle data center, DTE provided virtually no support for its claim that the project somehow won’t raise costs for everyday customers or undermine Michigan’s clean energy laws.”

“Unfortunately, the commission has signaled that it’s willing to forgo reasonable public process and scrutiny when big tech wants to make a backroom deal with a utility,” Sierra Club Michigan Director Elayne Coleman said in a statement. “This kind of behavior puts all of us at risk and clearly signals that everyday ratepayers aren’t playing at the same level. The disclosures the commission is seeking belong in a contested case hearing where impacts are reviewed prior to approval — not after.”

“We appreciate the commission’s efforts to shield other ratepayers from harm from the data center, but the contested case process exists exactly to do this and skipping over it sends the wrong message to other companies looking to do business in Michigan,” added Charlotte Jameson, chief policy officer with the Michigan Environmental Council.

The Michigan PSC noted that it doesn’t have authority over the construction and location of data centers, nor permitting power over water use.

DTE previously announced in a third-quarter earnings call that it’s in discussions with other large load developers for projects that could total about 3 GW of additional demand, with the added potential of 3 to 4 GW in new co-located data center load and generation. Company officials have said they likely would need to build new gas plants to accommodate the demand.

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Maine Public Advocate Asks FERC for Hearing on Asset Condition Costs

The Maine Office of the Public Advocate has asked FERC to initiate evidentiary hearing procedures to answer questions about the prudency of investments by New England transmission owners in asset condition projects placed in service in 2022.

In a filing submitted Dec. 17, the OPA wrote that it has “serious doubts about whether the policies and practices that governed the decisions that led to the asset management projects included in the 2023 ISO transmission rates were prudent” (ER20-2054).

Asset condition spending, which typically is intended to address issues with deteriorating transmission infrastructure, has risen significantly in recent years and accounts for the majority of New England’s pooled transmission investment. TOs spent nearly $4 billion on asset condition projects placed in service between 2020 and 2024 and forecast nearly $1.5 billion on projects placed in service in 2025.

Reining in asset condition costs has been a top priority for consumer advocates and the New England states, and earlier this year, ISO-NE agreed to assume a nonregulatory asset condition project reviewer role to help provide transparency into these investments. (See ISO-NE Gives Update on Asset Condition Reviewer Role.)

The OPA’s request comes after a FERC ruling in September that required New England TOs to provide more information responding to a series of questions issued by the OPA to the companies in 2023.

FERC’s ruling required the companies to provide more details about the timing of projects and directed transmission owners to provide more information about how they evaluated needs and selected solutions. (See FERC: New England TOs Must Disclose More Info on Asset Upgrades.)

In a concurrence with FERC’s order, Commissioner Judy Chang emphasized the TOs’ transparency obligations under formula rate protocols.

“If further action by the commission is needed to ensure customers have access to information needed to assess the prudence of transmission owners’ investments, I encourage parties to bring the issue to the commission,” Chang wrote in her Sept. 18 concurrence.

The OPA wrote that the responses it received following FERC’s order still failed to adequately address questions about the TOs’ processes for minimizing their asset management costs.

Denis Bergeron, an expert tasked by the OPA with reviewing the TOs’ responses, wrote they raised questions about a lack of information on how the companies “weighed various alternatives and their relative costs,” along with concerns about “unexplained differences among the useful life assumptions by New England transmission providers.”

The responses raise “serious doubt as to whether these starkly different practices taken together are providing cost-effective results for the region’s consumers,” he said, adding that it is his “informed conclusion that these questions are left unresolved with the data provided by the transmission owners and can only be answered through further discovery in a hearing to explore the prudence of the transmission owners’ replacement projects.”

He noted that while Vermont Electric Power Co. assumes about a 60-year life expectancy for its structures, Eversource Energy wrote in its responses that “while the physical life of a transmission line may exceed 35 years, due to changing load patterns, it cannot be assumed that the line will be electrically viable after 35 years.”

He said National Grid’s response indicated a complicated and potentially contradictory approach to evaluating the useful life of assets. He was not able to discern Rhode Island Energy’s approach to asset life from the company’s response, he added.

Regarding the evaluation of project alternatives, he said the companies failed to “quantitatively demonstrate how the alternatives were weighed.”

While the responses specifically relate to already-in-service projects, Bergeron said Eversource’s approach raises concerns about the company’s proposed rebuild of the X-178 line in New Hampshire. The project would replace about 580 structures on the 49-mile transmission line, which has an average structure age of about 46 years. Construction is slated to begin in early 2027, according to the project website. (See New England States Raise Alarm on Eversource Asset Condition Project.)

“The [Public Service Company of New Hampshire] decision to undertake this project was presumably based on the same policy governing earlier replacement projects,” he wrote. “If so, it raises a serious doubt about whether the criteria they apply result in the most economic projects.”

Representatives of Eversource, National Grid and Avangrid declined to comment on the OPA’s request.

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New England Coordinated Procurement Nets 173 MW of New Solar

Representatives of Connecticut, Maine, Massachusetts and Vermont have selected a cumulative 173 MW of new solar generation through a coordinated procurement process, the states announced Dec. 18.

The expedited process was aimed at procuring “advanced-stage projects” that could take advantage of expiring federal clean energy tax credits.

The Connecticut Department of Energy and Environmental Protection (DEEP) initiated the process with a request for proposals issued Sept. 10 and proposals due Oct. 10. The solicitation was open to renewable resources including onshore wind, solar and co-located storage.

The RFP noted the DEEP would “coordinate bid evaluation and selection” with any New England states that opted to join the procurement.

The project selections include:

    • Viridis Solar in Panton, Vt. (50 MW)
    • Husky Solar in Plainfield, Conn. (50 MW)
    • Fair Haven Solar in Fair Haven, Vt. (20 MW)
    • Knox Solar Energy Center in Warren, Maine (33.1 MW)
    • Turner Meadow Solar Station in Turner, Maine (19.9 MW)

DEEP selected about 67 MW across three projects; the Massachusetts Department of Energy Resources selected about 41 MW across two projects; the Maine PUC selected about 51 MW across five projects; and Vermont utility Green Mountain Power selected about 14 MW from one project. All projects are expected to be in service by the end of 2030.

The process highlights increased collaboration among New England states to procure clean energy and transmission. Massachusetts collaborated with Rhode Island and Connecticut on an offshore wind procurement in 2024, and the six New England states worked with ISO-NE to establish the new Longer-term Transmission Planning (LTTP) process. The first LTTP procurement focused on onshore wind development in Maine. (See ISO-NE Provides More Detail on Responses to LTTP Procurement.)

Meanwhile, the Maine PUC is hoping to work with other states on an onshore wind and transmission solicitation intended to complement the ongoing LTTP procurement.

Announcing the solar selection, Connecticut Gov. Ned Lamont (D) said “regional collaboration is critical to expanding and diversifying our energy supply, especially as we work to bring down the cost of electricity for Connecticut ratepayers.”

“By working together with New England state partners, and working quickly to take advantage of competitively priced projects, we are able to secure greater affordability and reliability benefits for Connecticut at a fraction of the cost,” DEEP Commissioner Katie Dykes said.

Multistate procurements are “becoming much more of the norm than the exception,” Dykes said at an industry event earlier in December.

Aidan Foley, CEO of Glenvale Solar, the developer of the Knox Solar Energy Center and Turner Meadow Solar Station, applauded the states’ “resolve to advancing low-cost, locally produced, carbon-free energy,” adding that the selections “will benefit communities and energy consumers throughout New England for decades to come.”

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House Passes SPEED Act to Quicken Infrastructure Permitting

The U.S. House of Representatives passed the SPEED Act in a vote of 221 to 196, with just 11 Democrats crossing the aisle to support the Republican-backed infrastructure permitting legislation.

House Natural Resources Committee Chair Bruce Westerman (R-Ark.) and Rep. Jared Golden (D-Maine) were the two main sponsors of the bill, which would speed up reviews under the National Environmental Policy Act (NEPA) and limit the time and opportunities for lawsuits.

“The passage of the SPEED Act is a win for America,” Westerman said in a statement. “For too long, America’s broken permitting process has stifled economic growth and innovation. To build the infrastructure needed to deliver affordable energy to American families and defend against 21st-century threats, we must fix this process. The SPEED Act will encourage investment, bring certainty to permitting, end abusive litigation and allow America to build again.”

The bill would streamline the analysis required in NEPA documents, reducing the burden on developers, and would clarify when a NEPA review was triggered by defining “major federal action.” It would establish a 150-day limit for any lawsuits on NEPA decisions.

More than 11 House Democrats had expressed interest in permitting changes, but many in the end were unsatisfied with the bill and voted against it. Rep. Scott Peters (D-Calif.) spearheaded a letter signed by 30 Democrats seeking some changes from the committee version of the bill to win their support, which did not happen.

“The environmental laws of the 1970s were designed to stop projects. The environmental imperative of today is to build,” Peters said in a statement. “That’s why I support permitting reform and why reforming NEPA is necessary if America is going to remain competitive.”

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Peters said he hopes the Senate can craft “truly bipartisan solutions that can become law” and explained what he and his colleagues want changed to win their support.

“We emphasized that projects that comply with the law must be protected from political interference, that courts should have a targeted role to ensure decisions are based on accurate analysis, and that local stakeholders should continue to have meaningful input early in the process,” he said. “We also highlighted the need to avoid provisions that could backfire, delay projects or reduce the quality of environmental reviews. Our goal is simple: a permitting process that is efficient, predictable and fair for investors, communities and the environment alike.”

In the end, conservative Republicans won out and changed the SPEED Act so that even if it becomes law, President Donald Trump will be able to pull previously approved permits for offshore wind, while the version passed by the Natural Resources Committee would have prevented such a move for all kinds of permitted projects. (See Permitting Bill Runs into Difficulty Involving Offshore Wind.)

‘Undermining the Intent’

The change on offshore wind led to the American Clean Power Association withdrawing its support for the SPEED Act and calling for the Senate to pass technology-neutral permitting reform.

The Edison Electric Institute (EEI) welcomed passage as an important first step in cutting red tape.

“At a time of unprecedented electricity demand, our outdated permitting processes can no longer stand in the way of unleashing American energy dominance,” EEI CEO Drew Maloney said in a statement. “We value Chairman Westerman’s leadership and urge the Senate to take the next step on this commonsense legislation that will help provide relief for customers and support the energy infrastructure that powers the American economy.”

EEI also will work to make the permitting system more predictable and durable for all forms of energy as the legislative process continues, he added.

Electric transmission trade group Grid Action also welcomed passage as demonstrating momentum for permitting legislation, Executive Director Christina Hayes said.

“Modernizing permitting is essential, but today’s economy demands more than a faster status quo,” Hayes said. “With electricity demand surging from AI, data centers and new manufacturing, we need permitting reform to strengthen transmission as the missing link needed to achieve a more affordable, reliable grid. As the bill heads to the Senate, Congress must further strengthen siting and permitting reform to reduce the cost of development and, in turn, lower costs for customers.”

Offshore wind group Oceantic Network has said it would welcome permitting changes, but Senior Vice President Sam Salustro decried the late amendment.

“Oceantic is disappointed in the late inclusion of an amendment which is discriminatory toward renewable energy, inviting additional, harmful actions while undermining the intent for tech neutrality and universal permitting certainty,” Salustro said in a statement. “We encourage senators on both sides of the aisle to restore the heart of bipartisan permitting reform and ensure that all American energy sectors are treated equally so all forms of much-needed power reach the grid, lower costs for ratepayers and create jobs.”

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N.Y. PSC Directs Con Edison to Create Plan to Avert Energy Shortfall

Consolidated Edison has been tasked with creating a contingency plan to avert the energy shortfall that it and NYISO have warned may develop in New York City.

The New York Public Service Commission initiated the proceeding Dec. 18 (25-E-0764). It directed Con Edison to first identify the reliability needs facing it over the next 10 years, then start a planning process to identify potential solutions to those needs.

The PSC is limiting those solutions to clean and non-emitting options: energy storage, distributed renewables and demand-side management such as energy efficiency, demand response and virtual power plants.

“Con Edison’s proposed NYC Reliability Contingency Plan must ‘turn over every stone’ to define a portfolio that is consistent with the state’s clean energy and climate goals,” the order states.

Further, the plan must prioritize solutions that are cost-effective for ratepayers; are straightforward and timely to deploy; and avoid or minimize impacts on disadvantaged communities.

With its limitation on emissions, the directive to Con Edison takes a narrower focus than the state Energy Plan, a directional guidebook that was updated Dec. 16 to include an all-of-the-above approach with the possibility of new fossil infrastructure. (See N.Y. Embraces All of the Above in Energy Strategy Update.)

But New York City has air quality problems, and the prospect of new fossil generation there — at a time when existing fossil plants may need to run much longer than many initially had hoped — is politically sensitive.

Con Edison also is directed to identify transmission and distribution upgrades needed to implement the solutions it proposes. The order includes both resource adequacy and transmission security under the “reliability” umbrella.

A spokesperson for the utility offered a broad response to the order: “We have a strong record of meeting system needs through both innovative solutions and traditional infrastructure investments, from pioneering non-wires solutions to building transmission that addressed the Indian Point contingency. We will continue to work collaboratively with NYISO, regulators, policymakers and other stakeholders to make sure the reliability needs of our customers are met, now and in the future.”

NYISO’s third-quarter 2025 Short-Term Assessment of Reliability (STAR), issued Oct. 13, identified reliability violations in Zone J (New York City) and Zone K (Long Island) starting in the summer of 2026.

NYISO’s 2025-2034 Comprehensive Reliability Plan, issued Nov. 21, did not identify actionable reliability needs, but it highlighted three converging trends that threaten reliability in New York: the aging generation fleet, the rapid growth of new large loads and the increasing difficulty of developing new dispatchable resources. Additionally, the advanced age of the fleet raises concerns about performance failures.

Con Edison’s 2025 Local Transmission Plan, submitted to NYISO stakeholders Dec. 3, identifies reliability needs in NYISO Zone J starting at 250 MW of peak need in 2030 and rising to 1,325 MW by 2035.

These reports are the basis for the PSC’s Dec. 18 order. The order “encourages” but does not direct the Long Island Power Authority (LIPA) to initiate a similar planning process leading to a contingency plan for Zone K. LIPA is a state entity not subject to PSC regulation.

NYISO meanwhile is awaiting the results of a Nov. 10 solicitation for short-term reliability process solutions to address the generator deactivation reliability needs identified in the third-quarter 2025 STAR report. Responses are due by Jan. 9. Natural gas generation can be proposed as a solution.

A PSC spokesperson told RTO Insider that the efforts by NYISO and now the PSC are complementary: The commission is setting up a process that is broader than the ISO solicitation but will reflect solutions identified by NYISO from its solicitation, thereby providing the widest possible range of options to address the problems.

NYISO welcomed the PSC’s order. “We’re pleased by the commission’s actions today to bolster reliability of the electric system in New York City and Long Island,” a spokesperson said. “The NYISO has long warned through our planning studies of declining reliability margins in New York City and the need for additional generation to meet rising demand. The order will be beneficial to meet reliability requirements and incentivize investment in new resources, while also supporting the newly approved state Energy Plan.”

PSC Chair Rory Christian spoke not only of the imperative of keeping the lights on in New York City but the impossibility of taking a cookie-cutter approach, as well as the need for innovative thinking if new electrons are to be brought onto the grid without creating new emissions.

“So as we explore solutions to the need identified, we’ll also need to explore new options and new opportunities to enhance reliability created through the ongoing integration of customer-side energy efficiency, demand response, battery storage, renewable energy and other measures,” Christian said. “I believe our utilities can rise to this challenge and look forward to the results of their work.”

The PSC voted 6-0 in favor of the order.