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December 23, 2025

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Texas PUC Approves TEF Backup Power Program

The Texas Public Utility Commission has put out a proposed rule for public comment that would establish the fourth and final program under the $10 billion Texas Energy Fund.

The PUC endorsed staff’s proposal laying out procedures to apply for grants or loans to procure, install and operate backup power systems under the TEF’s Texas Backup Power Package Program during its Dec. 18 open meeting (59024).

The program would provide $1.8 billion in funding for qualifying entities to install and operate backup power equipment at hospitals, nursing homes and other facilities that support community health, safety and well-being. Staff’s proposed rules define a backup power package as a stand-alone, multiday backup power source for facilities without passing through a utility electric meter.

“Applications to this program could be in the thousands,” staff’s Rama Singh Rastogi told commissioners.

She said the program’s loans are structured as forgivable loans, with 100% forgiveness should the applicant comply with performance requirements. The program excludes sourcing power from electric school bus batteries until the PUC further studies their use and integration into the program.

Comments are due Jan. 30, 2026.

The commission also approved staff’s recommendation to approve more than $282 million in grants to six applicants for their 14 projects under the TEF’s Outside ERCOT program. The program offers grants for facility modernization, facility weatherization, reliability and resiliency, and vegetation management (58492).

Southwestern Public Service Co. is eligible for about half of the loans. It applied for $200 million in reliability and resiliency awards and was approved for $148.6 million, covering three projects. El Paso Electric was approved for $61.3 million in loans for two applications covering a variety of reliability projects.

The applicants still must pass a review by the PUC’s executive director before any funds are disbursed.

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Maine PUC Issues Multistate Transmission, Generation Procurement

The Maine Public Utilities Commission, in collaboration with the regulators of four other New England states, has issued a request for proposals to procure clean energy in Northern Maine and 1,200 MW of transmission to connect it to the ISO-NE grid.

While Northern Maine is notable for its significant onshore wind potential, much of the area is not directly connected to ISO-NE; it is part of the Eastern Interconnection through New Brunswick.

As states look to add clean energy to meet growing demand and decarbonize the grid, Northern Maine has the potential to be a major area of clean energy growth, but the lack of transmission remains a significant barrier.

The RFP is intended to be complimentary to ISO-NE’s first Longer-term Transmission Planning (LTTP) procurement, which aims to reduce transmission constraints in Maine and establish a new interconnection point to help enable the development of 1,200 MW of onshore wind. The RTO intends to select a project from this procurement by September 2026. (See ISO-NE Provides More Detail on Responses to LTTP Procurement.)

Building on the ISO-NE procurement, the Maine PUC issued its RFP on Dec. 19 in coordination with Connecticut, Massachusetts, Rhode Island and Vermont. The solicitation is contingent upon the success of ISO-NE’s procurement; the PUC wrote that the transmission proposals would need to connect to the RTO “at the northern terminus of the facilities constructed as a result of ISO-NE’s [LTTP] solicitation.”

The RFP allows project bidders to submit standalone transmission or generation projects, or joint projects. The PUC wrote it “will give preference to projects that provide the lowest delivered cost of contract products and exhibit an ability to harmonize the generation and transmission components.”

Proposals are due Feb. 27. The PUC expects to decide on the bids by the end of May 2026. The commission noted that the RFP is intended to align with the timeline of the 2026 ISO-NE cluster request window, which is scheduled to open in October 2026.

Transmission and generation project in-service dates should roughly coincide with the in-service dates of the proposals for the ISO-NE LTTP procurement, the PUC said. The estimated in-service dates for the bids received by the RTO range from the fourth quarter of 2032 to the third quarter of 2035.

The PUC wrote it “is coordinating with other New England states in the evaluation of proposals and consideration of a joint selection in which all or some other combination of the coordinating states would participate.”

The RFP seeks to procure energy and renewable energy credits over a 20-year power purchase agreement. The procurement also allows project developers to include energy storage systems in their proposals.

“Proposals to include an energy storage system must demonstrate how the storage system will be designed and utilized to maximize use of the transmission line and reduce costs for ratepayers,” the PUC wrote.

On the transmission side, proposals “must be capable of delivering at least 1,200 MW of energy to the ISO-NE system from the generation component to the LTTU [Longer-term Transmission Upgrade] northern terminus in the Pittsfield, Maine, area.”

The PUC conducted a similar transmission and generation procurement in 2021 and 2022, selecting a transmission project submitted by LS Power and an onshore wind project submitted by Longroad Energy. However, the commission terminated the process in late 2023 after LS Power said it could no longer meet the fixed contract price.

LS Power attributed the cost increase in part to a delay caused by Maine’s efforts to include Massachusetts in the procurement at a late stage in the process. “The introduction of Massachusetts as a participant added delay due to the need to negotiate contracts in Massachusetts and have such contracts filed for approval in a contested case before the Massachusetts Department of Public Utilities,” the company wrote in 2024 following the termination.

“After a year of delay, without signed contracts in either state, and having no certainty that contracts that would support project financing were even achievable, we could no longer hold our price or schedule,” the company added.

By coordinating with other states from the outset, the PUC’s second attempt at a Northern Maine procurement may be able to avoid some of the risks that derailed its first attempt.

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Large Load Customers Languish in PSCo Interconnection Queue

With a surge in interconnection requests from large load customers, Public Service Company of Colorado (PSCo) has fallen behind on processing applications, a situation that has sparked concern from state regulators.

The Colorado Public Utilities Commission held an informational meeting Dec. 16 to hear about large load service issues. The meeting was part of an investigatory proceeding the PUC launched in October after hearing a range of concerns from PSCo large load customers including whether they can execute contracts with utilities in a timely manner. The state may have lost some potential large customers as a result, a commission order said.

PUC staff said PSCo’s interconnection delays seem to be a recent phenomenon. The utility was receiving two or three interconnection requests a year from large load customers up until 2024, when the number of requests jumped to 18.

In the past three years, PSCo has received 37 large load interconnection requests, PUC staff said. Only two of those applicants have made it to a signed interconnection agreement. Eight have dropped out or are on hold.

Nineteen requests are stalled in the system impact study (SIS) phase, one of the first steps in the interconnection process. The SIS identifies system constraints and needed upgrades and may include a cost estimate.

Applicants pay a fee for the study and agree to a delivery time frame, which has typically been four months but more recently has increased to six months.

Ten of the 19 applicants stuck in the SIS phase paid for the study six to 12 months ago; four paid more than a year ago. The other five paid two to six months ago.

Of the 37 interconnection requests in the last three years, PUC staff found only one in which the SIS was finished on schedule.

PSCo’s Open Access Transmission Tariff specifies that the utility complete the SIS within 60 days of a signed study agreement. If the utility is going to miss the deadline, it must give the customer an explanation and a new completion date.

“The 60-day timeline … appears overly optimistic relative to PSCo’s ability to process the large load requests it has received in the past three years and is inconsistent with the SIS agreements PSCo is signing with large load applicants,” PUC staff said in a presentation.

One reason for the delays is that PSCo is short-staffed, PUC staff said, in part because employees who handled interconnection requests left for jobs with data center companies. Commissioner Tom Plant found “a little irony” in the situation.

Xcel Energy Responds

In an emailed statement, PSCo parent Xcel Energy acknowledged that large load customers have faced delays and uncertainty with their interconnection requests.

The company has been working over the past year to improve large load customer service. Measures include adding staff, hiring consultants, modernizing processes and collaborating more closely with customers.

But the improvements “will not solve everything,” Xcel said.

“Even with faster project studies and better communication, Xcel Energy cannot energize these customers without adding significant generation and transmission capacity to the grid that serves our communities,” the company said. “Over the past 18 months, the scale and speed of growth have outpaced what Colorado’s energy system was built to handle.”

Xcel is working with the PUC and stakeholders to bring new resources online. The company expects to file a large load tariff in early 2026.

“Customers need certainty to plan investments, and we support efforts to create fair, transparent rate structures that balance flexibility with affordability for all Coloradans,” Xcel said.

Customer Perspectives

As part of their research, PUC staff interviewed representatives of 13 companies and organizations that were current or prospective large load customers of the state’s PUC-regulated electric utilities: PSCo and Black Hills Colorado Electric. Interviewees were with data center companies or other industries with high power demand.

They suggested ways to streamline the interconnection queue and discourage speculative loads. Those included larger, nonrefundable study fees and, for data centers, proof of end user and developer track record.

On the topic of large load tariff design, customers were interested in an option to “bring your own generation” — either in front of or behind the meter.

Many said they’d consider flexible loads to speed up interconnection, especially if their load flexibility could be monetized.

Customers said they’d like to see more consistent large load processes within Colorado, as well as nationally.

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Idaho Power Can Retain Market-based Rate Authority, FERC Rules

Idaho Power can continue to sell power at market-based rates after it acquired more than 200 MW in resources in 2023 and 2024, FERC ruled Dec. 18.

The decision — which covers Idaho Power’s market-based rate authority (MBRA) in its own balancing authority area, first-tier markets and CAISO’s Western Energy Imbalance Market (WEIM) — came after the Boise-based utility had submitted a series of change in status notices to report ownership of and control over new resources that came online during those years (ER10-2126 et al.).

Those filings, submitted in October 2023 and July 2024, reported that the utility added a net cumulative 211.8 MW of generation output after entering agreements to take power from two solar facilities and energizing — and then expanding — its Hemingway standalone battery storage facility.

Idaho Power explained that its own market power analysis showed that the utility still passed FERC’s pivotal supplier and wholesale market share screens for the WEIM and the utility’s adjacent first-tier markets, which include the Avista, Bonneville Power Administration, NorthWestern Energy, and PacifiCorp East and West BAAs.

But the analysis also showed Idaho Power failed wholesale market share screens in its own BAA in the winter, spring and fall, with market shares of 31.3, 41.8 and 30.3%, respectively. That put the utility well above FERC’s 20% threshold, prompting the commission to institute a Section 206 proceeding under the Federal Power Act to scrutinize the utility’s MBRA eligibility.

In allowing Idaho Power to retain its MBRA within its own BAA, FERC agreed with the utility’s contention that the commission should give more weight to the utility’s delivered price test (DPT) analyses rather than a sensitivity analysis based on activity at the Northwest’s Mid-C electricity trading hub.

The DPT analyses showed that, when Idaho Power’s obligation to serve its native load was taken into consideration, its “available economic capacity” — that is, energy available to be sold into the market — fell under the 20% market share threshold and the allowable threshold for market concentration of generation capacity as measured by the Herfindahl-Hirschman Index (HHI).

“Because Idaho Power has native load obligations, we find that the available economic capacity measure more accurately captures conditions in the Idaho Power balancing authority area,” FERC wrote. “The October 2023 DPT and the July 2024 DPT show that, using the available economic capacity measure and based on [Electric Quarterly Report] prices and the Mid-C hub prices, Idaho Power’s base case analyses indicate that Idaho Power is not pivotal in any season. The base case analyses indicate that Idaho Power’s market share under the available economic capacity measure is below 20% in almost all season/load periods, and market concentration in those periods is below the commission’s HHI threshold of 2,500.”

FERC’s Dec. 18 order does not cover a separate Section 206 proceeding the commission instituted for Idaho Power in July 2025, after the utility filed a change in status notice showing the addition of 230 MW of generation (EL25-91). The commission expects to issue an order in that proceeding by early January. (See FERC Launches Section 206 Proceeding for Idaho Power.)

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NYISO Meeting Briefs: Dec. 16-19, 2025

Installed Capacity Working Group

The final meeting of the Installed Capacity Working Group for the year, held Dec. 16, focused on proposed manual changes for several projects.

These include the alternative ICAP market parameters and the Control Area System Resource capacity market participation projects, which are to facilitate the integration of the Champlain Hudson Power Express transmission line. The parameters are to accommodate the line if it is late in beginning operation, as it will have a major impact on market prices and reliability. The CASR revisions would patch a few linguistic holes regarding how the manual addresses equipment failures.

NYISO will seek approval of the changes from the Business Issues Committee at its next meeting in January. Both projects have related tariff revisions pending before FERC.

The ISO also presented its Market Vision plan to stakeholders, emphasizing familiar themes of a changing grid, decreasing reliability margins, and the role of capacity and energy markets in meeting the energy and reliability needs of New York. The plan is a high-level overview of the timeline of major projects the ISO is undertaking, including the capacity market structure review, CHPE integration and handling the grid’s transition to winter peaking, among many other projects.

NYISO also presented improvements it is working to develop for the Thunderstorm Alert Settlement system because of issues that arose in July. Currently TSA settlements are reviewed manually, which can be time consuming.

Finally, the ISO presented a brief update confirming that it would continue the Storage as Transmission project into 2026.

Management Committee

The Management Committee on Dec. 17 approved two motions recommending the Board of Directors approve and file the tariff revisions for the Improved Duct-Firing Modeling project and the Hydro Quebec-NYISO interconnection agreement.

The committee also heard brief presentations of the accomplishments of NYISO under the 2025 Strategic Plan, and a repeat of the November Operations Report.

Transmission Planning Advisory Subcommittee

The Transmission Planning Advisory Subcommittee on Dec. 18 received a project update on the model development for the 2025-2044 System and Resource Outlook study. The study has nailed down a model for the base case and inputs for several other cases. Cost modeling will be finalized for all cases in the coming weeks.

TPAS also received an extremely short update on NYISO’s compliance with FERC Order 1920. Stakeholders were informed of the timeline of tariff revision development with a tentative filing date of April 30, 2026. (See NYISO Presents Preliminary FERC Order 1920 Plan to Stakeholders.)

Load Forecasting Task Force

The Load Forecasting Task Force heard a presentation Dec. 19 on the 2026 peak load forecast.

NYISO forecasts a peak load of 31,578.6 MW, roughly half of which (15,312 MW) is located in the New York City suburbs, Long Island and the city itself.

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All U.S. Offshore Wind Construction Halted

The Trump administration has ordered work halted on all five offshore wind facilities under construction in U.S. waters.

The Dec. 22 announcement by the U.S. Department of Interior said the Department of Defense had identified wind farms as national security risks — claiming that the towers and the spinning blades create a clutter in radar signals that generates false targets and obscures legitimate targets.

Interior said it is pausing the offshore wind leases to give all relevant government agencies time to work with the leaseholders and state governments to mitigate those risks.

The move is a sharp escalation of the campaign against offshore wind power President Donald Trump kicked off on the first day of his second term.

This has included suspension of leasing, attempts to pull back approvals issued during the Biden administration, the end of tax credits and separate stop-work orders against two offshore wind farms under construction.

Some of the individual actions have fallen flat: A federal judge in September lifted the stop-work order imposed on Revolution Wind, and a different federal judge in December ruled Trump’s Day 1 order halting onshore and offshore wind leasing and permitting was unlawful.

But taken together, Trump’s efforts have created a level of risk and uncertainty that has led multiple developers to shelve or cancel their plans in U.S. waters.

Just two U.S. offshore wind farms are in operation, one small and one tiny. Four large facilities and one very large facility are in various stages of construction. The rest of what had been a very ambitious pipeline formed during the Biden administration and first Trump administration is in tatters, some of that due not to Trump but to cost and logistics problems that beset the nascent U.S. industry in 2022.

The five projects affected by the Dec. 22 order are Coastal Virginia Offshore Wind (CVOW), Empire Wind 1, Revolution Wind, Sunrise Wind and Vineyard Wind 1.

The order did not address the two facilities already in operation: the 30-MW Block Island Wind farm in state waters near Rhode Island, and the 132-MW South Fork, which is farther south off the Rhode Island coast and directly adjacent to or near Revolution, Sunrise and Vineyard in a cluster of nine wind energy lease areas.

Interior’s announcement Dec. 22 cited the findings of unclassified government reports that turbine towers are highly reflective of radar. This and dozens of spinning blades create radar interference, Interior said; radar operators can change the alarm threshold to reduce false alarms from this clutter, but doing so may cause actual threats to be overlooked.

Interior said recent DOD reports provide further basis for the pausing leases.

The 2.6 GW, 176-turbine CVOW is near the concentration of major military facilities in southeastern Virginia. Its potential to interfere with radar, air and naval operations was flagged early in the federal review process. The Jan. 28, 2024, federal approval of CVOW’s construction and operations plan includes a series of conditions, one of which is a radar impact mitigation agreement to be negotiated with the North American Air Defense Command.

Empire, Revolution, Sunrise and Vineyard are near lesser concentrations of military assets, but their environmental impact statements each contain numerous references to radar. Their construction and operations plans — all approved during the Biden administration — also contain directives to address national security concerns.

What has changed since then, aside from the energy priorities of the White House, is not immediately clear. The recent DOD reports are classified.

But in the announcement, Interior Secretary Doug Burgum said the threat environment has evolved since the approvals were granted: “Today’s action addresses emerging national security risks, including the rapid evolution of the relevant adversary technologies, and the vulnerabilities created by large-scale offshore wind projects with proximity near our East Coast population centers. The Trump administration will always prioritize the security of the American people.”

Reaction fell along expected lines.

Dominion Energy said: “Stopping CVOW for any length of time will threaten grid reliability for some of the nation’s most important war fighting, AI and civilian assets. It will also lead to energy inflation and threaten thousands of jobs. … The project has been more than 10 years in the works [and] involved close coordination with the military, and [its] two pilot turbines have been operating for five years without causing any impacts to national security.”

U.S. Rep. Jeff Van Drew (R-N.J.) said: “For years, I’ve warned that offshore wind can interfere with military radar and threaten our coastal defenses. This pause is the right move. National security always comes first.”

The Oceantic Network said: “The Trump administration’s construction pause issued today on five U.S. offshore wind projects set to deliver nearly 6 GW of much-needed power is another veiled attempt to hide the fact that the president doesn’t like offshore wind. … The U.S. offshore wind industry has continuously worked with the Department of Defense to address national security concerns, and its own clearinghouse has signed off on every offshore wind lease ahead of construction.”

The Committee for a Constructive Tomorrow said: “Today was a historic victory for the little guy taking on the twin Goliaths of big government and big green energy. The Trump administration’s decision to deliver a lump of coal to five major offshore wind projects by placing a hold on their permits delivers a wonderful Christmas gift to those of us who’ve been fighting in the trenches for years to halt them.”

Vet Voice Foundation said: “This isn’t about national security — it’s a political gift to fossil fuel donors that will raise electricity bills for U.S. households and increase our risk of blackouts this winter.”

U.S. Rep. Andy Harris (R-Md.) said: “Good. National security cannot be sacrificed in pursuit of expensive, untested energy experiments that put both the Eastern Shore and the nation at risk.”

Advanced Energy United said: “PJM just failed to secure enough generation in its latest capacity auction this month, and if these wind projects are delayed, it will make keeping the lights on during an energy crunch even more difficult in the Mid-Atlantic.”

U.S. Rep. Chris Smith (R-N.J.) said: “Empire Wind’s close proximity to major international airports, including Newark Liberty, LaGuardia and JFK, and critical military installations, such as Joint Base McGuire-Dix-Lakehurst and Naval Weapons Station Earle, make the project especially dangerous. It must be halted.”

The American Clean Power Association said: “All the projects suspended today underwent rigorous national security reviews during the first Trump and Biden administrations. Today’s decision creates needless uncertainty for any company that seeks to build an energy project in the United States. In America today, the greatest threat to a reliable energy system is an unreliable political system.”

On the Facebook page of Protect Our Coast NJ, users posted “BEST Christmas gift EVER”; “Alleluia”; “Thank YOU Lord Jesus and President Trump”; “Stop onshore wind too”; and “A pause is nice a permanent ban is better. Get it done.”

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FERC Rejects Complaint over SPP’s Accreditation Practices

FERC has dismissed as moot a complaint by several public interest organizations over SPP’s accreditation methodologies for thermal and renewable resources (EL24-96).

In a Dec. 18 ruling, the commission said its approval in July of SPP’s new resource accreditation framework rendered the complaint’s target “no longer effective.” (See FERC Approves SPP’s ERAS Process, Accreditation.)

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project filed the complaint in April 2024 under sections 206 and 306 of the Federal Power Act. They charged the grid operator’s effective load-carrying capability methodology for renewable resources and performance-based accreditation methodology for conventional resources were unjust and unreasonable as well as unduly discriminatory or preferential.

At the time, SPP accredited thermal and other conventional resources based primarily on installed capacity. It accredited wind and solar resources based primarily on a given unit’s output during 60% of certain peak load hours and storage resources based on performance under a capability test.

The RTO filed tariff revisions in September 2024 to the proposed PBA methodology, adding fuel assurance incentives for conventional resources. FERC noted the public interest groups said the new accreditation methodologies “would completely replace the existing methodologies that are the target of this complaint.”

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CAISO Readies EDAM Tariff Changes as New Market Nears Opening

CAISO is proposing a set of tariff changes for submission to FERC early in 2026 to help ease participants into the ISO’s new Extended Day-Ahead Market.

The planned tariff revisions range from formatting changes to rule adjustments that affect the overall market design, said Andrew Ulmer, CAISO assistant general counsel, at a Dec. 17 joint meeting of the ISO Board of Governors and Western Energy Markets (WEM) Governing Body. CAISO plans to file the proposed revisions with FERC in the first quarter of 2026 to keep EDAM’s May 2026 opening date on track.

The first proposed revision is associated with CAISO’s rules for intertie modeling and scheduling. Intertie resources in CAISO are currently modeled at specific scheduling points, but the ISO in 2025 proposed to model intertie resources under EDAM at generation aggregation points (GAPs). A GAP is the collection of supply resources in a balancing authority area or group of BAAs.

The GAP approach would have significantly improved power flow and market accuracy, improved alignment with actual power flows by reducing phantom congestion and reduced operator conformance of transmission limits in real-time, CAISO staff wrote in a November white paper. (See EDAM Intertie Scheduling Processes Raise Stakeholder Concerns.)

But many stakeholders raised concerns about the GAP approach, saying it could lead to a market with multiple prices for the same intertie.

CAISO therefore adjusted its approach in its tariff revisions proposal: The ISO plans to price and model schedules at intertie scheduling points as it does today, CAISO Vice President of Market Design and Analysis Anna McKenna said in a memo presented at the Dec. 17 meeting.

“This [proposed approach] will enable market participants to transition to EDAM without impacting existing commercial arrangements for transactions at the ISO balancing area interties,” McKenna wrote in the letter. “Management will work with stakeholders to determine when the market should transition to modeling and pricing the ISO balancing area intertie scheduling points using the aggregate modeling locations.”

Sticking with the current intertie scheduling approach largely preserves intertie scheduling and modeling practices for ISO interties, McKenna wrote. The current approach represents a reasonable compromise to implement EDAM and reflect the congestion impacts of intertie transactions, she wrote.

“I want to make sure I really understand this. … The generation aggregation points [approach] is being deferred,” Robert Kondziolka, WEM Governing Body member, said at the meeting. “Is it your understanding that stakeholders support how GAP should be implemented, whether it’s 2027 or sometime after that?”

“I think there are questions about how GAPs are modeled,” CAISO Regional Markets Section Manager replied. “That’s where [future] stakeholder workshops … will help tease out those questions.”

“It sounds like what we are moving toward is a model that prices electricity differently depending how it got there,” added Board of Governors Chair Severin Borenstein. “This is sort of moving away from a nodal pricing model, which … worries me because of gaming [opportunities].”

For resource adequacy imports, CAISO’s proposed tariff changes would allow certain scheduling coordinators to reassign their system resource capacities prior to the day-ahead market — specifically when the resource supporting that import is in the EDAM area.

The RA tariff revisions would also allow participants to continue to bid RA imports at CAISO interties that are also EDAM transfer locations, specifically when those imports are sourced from outside the EDAM area, McKenna said in the memo. This approach is similar to how the market treats RA imports today, Bosanac said.

At the Board of Governors’ Dec. 18 general session, board members nominated Joe Eto to be the board’s new chair in 2026, replacing Borenstein. Eto joined the board in 2023 after retiring from the Lawrence Berkeley National Laboratory after 40 years.

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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.