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January 27, 2026

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State Briefs

CALIFORNIA

State Surpasses 2.5 Million ZEV Sales

The state has surpassed 2.5 million cumulative zero-emission vehicle sales in 2025, according to the Energy Commission.

In the fourth quarter of 2025, Californians bought 79,066 new ZEVs, accounting for 18.9% of all new vehicle sales. Meanwhile, cumulative new ZEV sales have grown by more than 300% since 2019.

More: EV Infrastructure News

CONNECTICUT

Green Bank Sues Bankrupt PosiGen for $22M

The Connecticut Green Bank filed a lawsuit seeking repayment of $22.2 million in outstanding loans made to PosiGen, a solar panel leasing company that filed for bankruptcy in November.

The Green Bank, which receives roughly $23 million per year from ratepayers through a charge to invest in green technology, partnered with PosiGen between 2015 and 2021 to lease solar panels to low- and moderate-income households. Overall, the bank loaned PosiGen a total of $56.7 million “through a variety of loan facilities,” but it said it did not lend any ratepayer funds.

More: Inside Investigator

IOWA

House Passes Bill Banning Eminent Domain for Carbon Pipelines

The House of Representatives voted 64-28 to pass a bill that ban the use of eminent domain for carbon capture pipelines.

The bill now goes to the Senate for consideration.

More: Iowa Public Radio

MARYLAND

Gov. Moore Proposes Record Funds for Renewables

Gov. Wes Moore proposed a record $306 million for renewable and clean energy programs in the fiscal year 2027 budget.

Much of that money would be drawn from the Strategic Energy Investment Fund, which is managed by the state Energy Administration and is funded by utility payments and proceeds from the Regional Greenhouse Gas Initiative. Climate funding from SEIF in the fiscal year 2027 budget stood at about $328 million.

Moore’s total budget was $70.8 billion and accounts for an estimated $1.5 billion cash shortfall.

More: Inside Climate News

MASSACHUSETTS

Gov. Healey to Spend $180M to Help Reduce Utility Bills

Gov. Maura Healey plans to spend $180 million as part of a plan to temporarily reduce electricity gas bills by 25% and 10%, respectively, for residential customers for the months of February and March, the administration announced.

A spokesperson for Energy and Environmental Affairs Secretary Rebecca Tepper said the $180 million the administration plans to tap will cover an estimated 15% reduction in electricity bills. Utilities will then delay collecting an additional 10% of electric bills in February and March, with plans to recover those payments April through December. Companies will also plan to defer an estimated 10% of gas bill payments during February and March.

More: WBUR

MINNESOTA

PUC Rules Burning Trash, Wood ‘Carbon-free’

The Public Utilities Commission last week confirmed a law that says burning trash and wood to generate electricity will now be considered a carbon-free source.

The PUC ruled that facilities that burn municipal waste or biomass to generate electricity can still be considered carbon-free, even if they emit large amounts of carbon dioxide or other greenhouse emissions. They can do so if they pass a life-cycle analysis that proves burning trash or biomass generates fewer greenhouse gases than what would most likely occur if the wood or waste were disposed in another manner.

Only about 2% of electricity generated in the state comes from biomass and trash incineration.

More: MPR News

NEVADA

NV Energy Offers to Make Overcharged Customers Whole

NV Energy, which balked weeks ago at fully reimbursing overcharged customers, is reversing course and proposing to pay $63 million to more than 100,000 residential customers it has overcharged since 2002, the company announced.

The utility, which owed customers a total of $65.4 million, initially offered to reimburse a portion of affected customers just $2.5 million, claiming regulations limited their obligation to repay customers for just six months of overcharges. The offer “ensures that compensation is provided expeditiously” following Public Utilities Commission approval, NV Energy said.

More: Nevada Current

TEXAS

EPE Requests Gas Plant for Data Center

El Paso Electric is seeking Public Utility Commission approval for a 366-MW natural gas power plant that will fuel a $1.5 billion, 1-GW Meta data center.

The plant will be exclusively connected to the data center for the first five years, according to filings. Then it would be connected to the broader El Paso Electric grid. Meta would be responsible for all the costs during the first five years.

The plant will require approvals from both the PUC and the Commission on Environmental Quality. If approved, it is expected to be operational by 2027.

More: Inside Climate News

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ERCOT Stakeholders Mark TAC’s 30th Anniversary

AUSTIN, Texas — ERCOT stakeholders used their first Technical Advisory Committee meeting of 2026 to mark the committee’s 30 years of existence and achievements, sharing memories of their work together and recognizing members past and present.

“It has been an honor and privilege to serve on this committee and contribute to the greatest competitive retail and wholesale power market in the world,” Reliant Energy Retail Services’ Bill Barnes said during TAC’s Jan. 21 meeting.

The committee, composed of several subcommittees and working groups, recommends policies and procedures to ERCOT’s Board of Directors and is responsible for prioritizing projects through protocol revision requests, system change requests and guide revisions.

SPP staff went through their files and found the names of 64 members who have served at least five years on the committee. Mark Dreyfus, who represents the city of Eastland and other municipalities as part of TAC’s consumer segment, said he knew all the people on the list, calling some “giants of the industry.” He reserved singular praise for one past member: Reliant’s John Meyer.

“I hope there are statues to him in the office building,” Dreyfus said. “He led the stakeholders when we developed these processes and when we developed the original protocols, and he really deserves all our honor and recognition. If you don’t know him, it would be really good to talk to somebody and find out what he was about and why he took the time to create this process.”

American Electric Power’s Richard Ross, the only member with 25 years of service, said over the phone that TAC and ERCOT’s stakeholder process “really does cast a very big shadow.”

Richard Ross, AEP | © RTO Insider LLC

“It cast a shadow to the north and had a heavy influence on my experience with trying to get SPP’s stakeholder process set up in much the same way, with the way we so transparently change rules and give everyone a free opportunity to comment and debate,” Ross said. “If you ever looked at the process in SPP, you would see a great deal of similarities from things that we copied from.”

Barnes recalled the “completely ridiculous process” in the zonal market that predated the current nodal framework, where the zones’ boundaries would be redefined every year. He said “millions and millions of dollars amongst companies” would change hands.

“It was incredibly contentious and also extremely entertaining to be a part of,” he said. “One particular year … it literally moved a large coal plant from one zone to the other. I just remember Richard [Ross] playing a very critical part of the final vote, which I think it probably took three or four attempts to get through.”

Ironically, Ross gave up his seat this year and has been replaced by AEP’s Erin Rasmussen, one of three new TAC members.

“I’m watching from afar this year, but thank you for 25 years,” Ross said. “Keep up the good work.”

Engie’s Bob Helton, another TAC veteran, saw his 18 years of service elevated to 19 in real time when ERCOT staff found a Robert T. Helton mentioned in the files.

“This has to be wrong, okay? It can’t be. I’m not old enough to have done it,” Helton said. “I’ve served with pretty much everybody that’s on that list and I’ve served with a lot of very, very good people. We’ve made a lot of good decisions to make this market, as Bill said and it’s been noted, as the best in the country. We’ve gone through a lot of adversity. We’ve had some fun.”

Large Load Issues Pile Up

When TAC got down to the more mundane business at hand, ERCOT staff told members that the grid operator’s large load interconnection queue had dropped from 237.2 GW to 232.5 GW in January after several cancellations in December.

The great majority of requests (199.3 GW, or 85.7%) are for standalone facilities.

“We do expect that there may be some additional projects that are cancellations as well,” ERCOT’s Agee Springer said, noting that large loads do not need to explain why they are pulling projects from the queue.

Jeff Billo, ERCOT | © RTO Insider LLC

The grid operator plans to introduce a quarterly stability assessment (QSA) for large loads in February to support those preparing to energize. It would be one of the first times ERCOT has published a structured QSA framework for tracking readiness and energization of large loads, according to consulting firm Electric Power Engineers.

“You need to pay attention to the QSA’s dates. [Large loads] are coming much faster than you think,” Longhorn Power’s Bob Wittmeyer, chair of the Large Load Working Group, told the committee.

ERCOT’s Jeff Billo told members that staff will reveal a draft framework of the proposed batch interconnection process for large loads during a Feb. 3 workshop. These large loads are currently studied individually, but under the batch process, they would be grouped and evaluated all at once. (See ERCOT Finds Stakeholder Support for Batch Process for Large Loads.)

Billo said ERCOT will likely request a good-cause exception from the Public Utility Commission after a recent rule change that requires large loads go through a full interconnection study similar to those generators undergo. Assuming the board approves the process, staff will have to file protocol changes to codify the batch studies.

“This is necessarily moving quickly because there are a lot of projects, a lot of these large load projects that are being developed,” he said. “The customers who are developing those want certainty as to how this is going to work, how this is going to impact their project, so we want to try to provide that.”

Smith, Henson to Lead TAC

Members re-elected Jupiter Power’s Caitlin Smith and Oncor’s Martha Henson as TAC’s chair and vice chair, respectively, for 2026. It will be Smith’s third year leading the committee.

“I’m planning on this being my last term,” she said.

Smith noted TAC’s accomplishments during the year, topped by getting the Real-time Co-optimization Battery (RTC+B) project’s last items “across the finish line” before it went live. She pointed also to stakeholders’ endorsement of ERCOT’s first 765-kV projects and growing TAC’s relationship with the board.

“We have done a lot … but we’re looking at a lot of work, namely [dispatchable reliability reserve service (DRRS)] and the load ride-through requirements we need to get done by the first half of the year. So, it’s not all fun and games, but [I’m] excited.”

Tier 1 Project on Combo Ballot

TAC’s unanimously approved combination ballot, or its consent agenda, included a $117.4 million transmission build that was reclassified as a Tier 1 project and needing board approval.

South Texas Electric Cooperative submitted the project, which will accommodate a 300-MW ammonia plant near Victoria on the Texas Gulf Coast, costing an estimated $65.5 million. ERCOT’s Regional Planning Group analyzed eight options and chose one of four short-listed alternatives, all with higher price tags.

Staff attributed the cost increase and reclassification to the higher 138-kV rebuild capability standard on AEP’s portion of the project. AEP’s Doug Evans said tariff rates on some steel and aluminum items increased between 15 and 50%, also increasing cost estimates.

The project is expected to be in service in June 2028.

The combo ballot also included the withdrawal of a change to the Nodal Operating Guide (NOGRR264) for an earlier iteration of the DRRS product (See RTC Deployed, ERCOT Takes on New Challenges in 2026); TAC’s subcommittee and subgroup leadership for 2026; and three protocol changes (NPRRs) and two revisions to the Planning Guide that, if approved by the board, will:

    • NPRR1304: Incorporate the Other Binding Document “Procedure for Identifying Resource Nodes” into the protocols to standardize the approval process.
    • NPRR1305: Add the Other Binding Document “Counter-Party Credit Application Form” into the protocols to standardize the approval process.
    • NPRR1311: Correct an error in the real-time reliability deployment price adders’ calculation for ancillary services when ERCOT is directing firm load shed during a Level 3 energy emergency alert in the RTC+B’s protocols, ensuring final ancillary services prices cannot exceed $5,000/MWh.
    • PGRR127: Outline the additional generators that may be added to the planning models to address the generation shortfall introduced by the implementation of House Bill 5066’s requirements and increased load growth. The PGRR would also add a supplemental generation sensitivity analysis for Tier 1 Regional Planning Group project evaluations to minimize the effects of the additional generation on transmission project evaluations.
    • PGRR132: Clarify that new resources must interconnect to ERCOT through a new standard generation interconnection agreement.
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Stakeholders Support Adopting NAESB Standards

NERC and other stakeholders have endorsed FERC’s proposal to introduce new standards to improve coordination between the electric and natural gas industries, with some commenters urging the commission to go further in support of grid reliability.

Commenters were responding to FERC’s Notice of Proposed Rulemaking from October 2025 that would incorporate the latest changes to Version 4.0 of the Standards for Business Practices of Interstate Natural Gas Pipelines adopted by the Wholesale Gas Quadrant of the North American Energy Standards Board (NAESB) (RM96-1). (See NOPR Would Get Pipelines to Offer More Information for Grid Operators.)

NAESB’s updates include a revised standard that creates a central location on pipeline websites for information on critical events that RTOs and ISOs can use to assess potential impacts to their systems. Two new standards would facilitate the posting of applicable scheduled quantity information for power plants that are directly connected to gas pipelines and support the inclusion of geographic information of affected areas, locations and/or pipeline facilities by a transportation service provider when issuing a critical notice.

In its comments, NERC called the commission’s proposal “critical for reliable operations of both [the] gas and electric systems, providing a common platform for operational data exchange and unified situational awareness.” Observing that “the electricity sector is the largest consumer of natural gas,” the ERO highlighted its own efforts to promote gas-electric coordination.

These include NERC’s Electricity-Natural Gas Work Plan, presented to the organization’s Board of Trustees in August 2025. As part of the plan, NERC has updated its Long-Term Reliability Assessments to include natural gas impacts on grid reliability and is “reviewing updates to its tool for Situational Awareness for FERC, NERC and the regional entities … to better integrate gas system data.”

NERC also mentioned several reliability standards intended to address natural gas fuel issues, including EOP-011-4 (Emergency operations) and TOP-002-5 (Operations planning), both approved by the commission in 2024, along with TPL-008-1 (Transmission system planning performance requirements for extreme temperature events), BAL-007-1 (Near-term energy reliability assessments) and EOP-012-3 (Extreme cold weather preparedness and operations).

Other electric stakeholders joined NERC to back the commission’s proposal. The ISO/RTO Council wrote that the NAESB standards would “provide more timely and actionable information about gas system constraints and disruptions that may impact electric system reliability” while enabling “more effective coordination of operational decisions across the gas-electric systems.”

National Grid, Consolidated Edison, Old Dominion Electric Cooperative and Washington Gas Light — filing jointly as the Utility Coalition — called NAESB’s standards “a meaningful advancement toward enhancing real-time operational transparency across” the gas and electric systems. But the utilities also suggested the commission “widen its aperture to … consider steps that can be taken to preserve and enhance interstate pipeline service reliability.”

These suggested steps include requiring annual reports from interstate pipelines on reliability metrics, revising its pipeline force majeure policy and reservation charge crediting policy to create reliability incentives for pipelines, and implementing “greater standardization of pipeline scheduling and confirmation practices.” The coalition added that the commission could direct additional modifications to NAESB’s standards to address pipeline reliability.

The American Gas Association also expressed support for adopting the NAESB standards, which it said would “promote greater gas-electric coordination and situational awareness during severe weather events.” AGA suggested possible future steps to further improve communication between the gas and electric industries, including updating the force majeure provisions, as the Utility Coalition said, and promoting investment in gas storage and demand response programs.

Finally, the Interstate Natural Gas Association of America endorsed adoption of the NAESB standards but requested the commission ensure its final rule in the proceeding is timed so the effective date of the modifications “does not occur during the winter heating period.” The association also asked that pipelines be allowed “the flexibility to implement the modifications on or before 180 days from the date compliance filings are due in this proceeding.”

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Hydro-Québec Halted NECEC Deliveries amid Reliability Concerns

As extreme winter weather descended on the Eastern U.S. and Canada, Hydro-Québec suspended power exports to ISO-NE on the New England Clean Energy Connect (NECEC) transmission line because of reliability concerns in Québec starting on the afternoon of Jan. 24.

The suspension continued throughout tight system conditions across the Northeast on Jan. 25 and 26.

“The polar vortex has brought extreme and sustained cold air across Québec,” Serge Abergel, chief operating officer for Hydro-Québec Energy Services, said in a statement. “The demand for power in Québec caused us to suspend deliveries over the New England Clean Energy Connect from Saturday afternoon until the present (with partial deliveries occurring between 1 p.m. and 3 p.m. on Sunday).”

He said Hydro-Québec expects deliveries to resume early Jan. 27, but he noted that “there could be yet further interruptions at peak hours over the next several days.”

According to ISO-NE data, NECEC deliveries dropped from about 1,100 MW to zero over a half-hour period midafternoon Jan. 24. Hydro-Québec sent power over the line for about two hours on the following day, sending up to about 600 MW before again cutting deliveries.

The loss of supply from the NECEC line appears to have significantly affected real-time energy prices: The ISO-NE real-time Hub LMP more than doubled during the 40-minute period NECEC cut supply Jan. 24, while the brief burst of supply Jan. 25 coincided with about a 33% decline in the hourly real-time LMP despite relatively steady demand.

Amid high prices in New England, ISO-NE has consistently been exporting power to Québec over the Phase 2 transmission line since the afternoon of Jan. 24, including about 830 MW during that day’s evening peak.

The NECEC line began commercial operations Jan. 16. (See NECEC Transmission Line Ready to Begin Commercial Operations.) The project includes supply contracts between Hydro-Québec and Massachusetts electric utilities requiring the company to send firm power to ISO-NE. The company does not have new capacity supply obligations associated with the line.

Hydro-Québec could face significant penalties for falling to meet the delivery requirements of the contracts. According to the power purchase agreement, supply interruptions that are not the result of a force majeure or a physical outage on the line can be cured by the additional deliveries within the same year or following year. Delivery shortfall during peak hours can only be cured during peak hours, and delivery shortfall in the winter can only be cured in the winter (D.P.U. 18-64, et al.).

“We are aware of the historic constraints on the Canadian grid due to the extreme cold,” said Maria Hardiman, a spokesperson from the Massachusetts Executive Office of Energy and Environmental Affairs.

“Hydro-Quebec is facing steep penalties for each day they are not providing power to Massachusetts, and we know they are working to resume power as quickly as possible,” Hardiman said. “Our contract ensures that ratepayers will still see lower-priced electricity, regardless of the power flowing over the line.”

Robert McCullough, principal of McCullough Research, said the suspension on the NECEC line appears to be a product of Hydro-Québec’s slim reserve margin for the current winter. According to the Northeast Power Coordinating Council’s 2025/26 winter reliability assessment, Québec had about a 1% reserve margin. Hydro-Québec’s peak load exceeded its 50/50 winter forecast by over 200 MW on Jan. 25.

McCullough attributed the slim reserve margin to “combination of bad weather, neighbors not able to help and insufficient maintenance on some of the dams.” NPCC’s report notes that Hydro-Québec’s available winter capacity was reduced by 5,594 MW because of maintenance and derates.

Abergel called the contention of insufficient maintenance “simply not accurate.”

In New England, ISO-NE peak load reached 20,182 MW on the evening of Jan. 25, slightly exceeding the region’s 90/10 winter forecast. Hourly Hub LMPs have reached as high as $777 $/MWh.

The RTO has avoided the need to take emergency actions throughout the weather event. It issued a precautionary alert on the morning of Jan. 25 and obtained a waiver from the U.S. Department of Energy allowing generators to override air permit limits to provide extra power.

Dan Dolan, president of the New England Power Generators Association, said the ISO-NE fleet “has performed exceptionally well this weekend using every different fuel and technology to maintain reliable, stable operations through arctic temperatures, heavy snowfall and even needing to send power to support our neighbors in Quebec.”

He highlighted the significant role oil generation has played in maintaining grid reliability. With gas generation limited because of high demand for heating, oil generation has consistently accounted for roughly a third of generation in the region since the suspension of deliveries on the NECEC line.

“Part of the diverse generation mix in New England is a large capability to use oil in periods of stress,” he said. “That has happened at a tremendous scale, which creates strain on fuel infrastructure. But the system is holding up through this first stretch.”

With more cold weather in the forecast over the next few days, “it is all hands on deck,” Dolan said.

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PJM Stakeholders Endorse 2026/27 Third Incremental Auction Parameters

The PJM Markets and Reliability Committee and Members Committee endorsed the RTO’s recommended installed reserve margin (IRM) and forecast pool requirement (FPR) for the third 2026/27 Incremental Auction (IA), scheduled to be conducted Feb. 24.

The vote is advisory to the Board of Managers, which determines the values to be used in the auction.

The IRM would fall from the 19.1% used in the 2026/27 Base Residual Auction to 18.6%, while the FPR would increase from 0.9170 to 0.9291. (See “Stakeholders Endorse IRM and FPR for 2026/27 Capacity Auction,” PJM MRC/MC Briefs: March 19, 2025.)

The inputs for the parameters were based on the 2026 load forecast, which predicted lower load in the long term and shifted the concentration of reliability risk toward the summer, though the majority still lies in the winter at a 55.9% loss-of-load expectation. (See Pessimistic PJM Slightly Decreases Load Forecast.)

Most resource classes would see a modest increase in their effective load-carrying capability (ELCC) ratings, with four-hour storage resources seeing the largest benefit, going from 50 to 54%. Owing to its stronger winter performance, offshore wind generation would see a decrease from 69 to 64% and onshore wind from 41 to 38%.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the influence load has on the amount of supply that resources can offer creates a dynamic that runs contrary to economic logic. The volatility of class ratings undermines the ability for investors to make sound decisions, particularly because the control they have over their assets’ ratings is limited. Pointing to the contributions solar made in maintaining reliability during the heat waves of summer 2025, he argued ELCC is making the RTO look shorter than it is.

“This calls into question the validity of PJM’s ELCC model because if we see load decreases continue in the future … as the load increases, capacity accreditation falls and the IRM goes up,” he said.

PJM’s Patricio Rocha Garrido said the relationship between load uncertainty and the IRM has always been present, including under the previous PRISM modeling software.

“What we’re trying to do here is determine what are the risk hours” and determine resource performance at those times, he said, adding that was also the goal under the equivalent forced outage rate demand (EFORd) accreditation paradigm.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said several consumer advocates will abstain from votes on the IRM and FPR values because it seems stakeholders have little sway on the values the RTO is proposing. He said staff put in good work developing the values, but if it’s going to be more than a check-the-box exercise for stakeholders, there needs to be more of a process around how the numbers are produced and presented.

Responding to stakeholder questions on what the vote means to the board, PJM Senior Vice President of Market Services Adam Keech said he views the vote as pertaining to whether staff followed the process for determining the IRM and FPR values. If stakeholders feel those processes should be revised, that should be pursued through a separate process.

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PJM MRC/MC Briefs: Jan. 22, 2026

Markets and Reliability Committee

Definition of Offline Secondary Reserves

PJM’s Suzanne Coyne presented the RTO’s Markets and Reliability Committee with revisions to Manual 28: Operating Agreement Accounting to clarify how resources are defined as offline for the purpose of determining whether they are eligible for lost opportunity cost (LOC) credits. (See “Stakeholders Endorse Quick Fix on Offline Resource LOC Eligibility,” PJM MIC Briefs: Jan. 7, 2026.)

Coyne said that while the governing documents state that resources that are offline when committed for secondary reserves are not eligible for LOC credits, the manual language can result in resources improperly being considered online if they begin operations between when they are dispatched and when the commitment begins.

The market clearing software has visibility into whether a resource is offline when it assigns a commitment; however, the settlement calculations consider only whether a unit is online when the commitment interval begins 10 minutes later.

The proposal would use real-time security-constrained economic dispatch data to determine whether a resource is online, unifying the discrepancy between dispatch and settlement, she said. If endorsed by the MRC in February, the language would be implemented March 1.

Must-offer Requirement for Self-Scheduling Resources

Mike Cocco, of Old Dominion Electric Cooperative (ODEC), presented a quick-fix proposal to define a capacity resource as having met its obligation to offer into the energy market if it self-schedules and provides its full output.

The quick-fix process allows a problem statement and issue charge to be brought concurrently with a proposed solution.

Cocco said the proposal would ensure that gas generation resources that self-schedule to ensure they are able to operate and consume fuel procured on ratable take contracts are not at risk of non-performance penalties if there is a performance assessment interval (PAI). Cocco said that all the parties he has reached out to, including PJM and the Independent Market Monitor, have said they interpret Manual 11: Energy & Ancillary Services Market Operations as already providing that protection, but he said ODEC believes that should be codified in the language.

PJM Senior Vice President of Market Services Adam Keech said the parameter-limited schedule (PLS) process is intended to cover these circumstances and questioned whether the proposal is meant to complement or replace that. When a resource owner seeks a PLS exception, it must meet a higher burden of proof that it has diminished flexibility because of the ratable take.

Cocco responded that the proposal as envisioned would not require generation owners to obtain PLS exceptions, but he wanted to consider the comment further and would reach out to PJM staff to discuss.

Members Committee

Stakeholders Endorse Minimum Capitalization Changes

PJM’s Members Committee endorsed by acclamation a proposal to increase the minimum capitalization requirements for participating in the RTO’s markets. (See PJM Presents 1st Read on Minimum Capitalization Requirement Proposal.)

The proposal would revise the tariff to double the tangible net worth requirement to $2 million for those participating in financial transmission rights markets. For entities not participating in FTR markets, there would be a transition period in which the requirement would first increase from the current $500,000 to $1 million and then increase by $200,000 annually over five years. The proposal also adds a 3% fixed annual escalator.

The proposal would not change the alternative tangible asset threshold of $10 million for FTR participants and $5 million for non-FTR participants.

Consumer Advocates Form Residential Affordability User Group

New Jersey Division of Rate Counsel Director Brian Lipman announced the creation of an Affordability and Reliability for Residential Consumers User Group intended to reduce the impact on ratepayers of accelerating load growth from data centers.

Along with his agency, Lipman said the user group includes the Delaware Division of the Public Advocate, D.C. Office of the People’s Counsel, Illinois Citizens Utility Board, Maryland Office of People’s Counsel, Office of the Ohio Consumers’ Counsel and the Pennsylvania Office of Consumer Advocate.

Lipman said the group’s first meeting on Jan. 27 will include voting on the draft charter and the concept of revising governing documents to include affordability in PJM’s mission statement and Operating Agreement.

Vitol’s Jason Barker said he appreciated the goal of the user group, and while his company has no position on whether it should be formed, he objected to the announcement stating that consumer advocates only have 1% of the voting power in lower standing committees.

Barker said that when sector-weighted voting is accounted for in the MRC and MC, consumer advocates can have the power to sway votes. He pointed to the Critical Issue Fast Path process conducted in 2025 on large load growth, in which 10 consumer advocates cast votes that accounted for half the end-use customer sector, meaning those offices held 10% of the sector-weighted vote.

The 1% figure references the diluted voting power consumer advocates hold outside the MRC and MC, where each of PJM’s 1,111 members can cast votes.

Barker said it is typical for only about 10% of those members to vote in the lower committees.

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Government-proposed ‘Backstop’ Auction to Test PJM Stakeholder Process

PJM stakeholders Jan. 22 kicked off discussions on creating a “backstop” auction to be held in September at the insistence of the Trump administration and the governors of the RTO’s 13 states.

The Members Committee discussed the feasibility of holding such an auction and how the logistics of creating the rules for doing so should be balanced with other elements of the Critical Issue Fast Path (CIFP) proposal the Board of Managers selected for addressing large load growth Jan. 16.

The White House’s National Energy Dominance Council (NEDC) and state governors, issued the same day as the board announced its choice, envisions a one-time auction that procures new resources for a 15-year commitment period. (See White House and PJM Governors Call for Backstop Capacity Auction.)

“The PJM board should file tariff revisions expeditiously, as PJM has already received stakeholder input through the 2025 [CIFP] process, and no further CIFP processes are necessary,” they said in a statement of principles.

In its announcement of its CIFP proposal choice, the board said the RTO’s existing backstop capacity procurement method should be accelerated: It is currently triggered only after three consecutive capacity auctions fall short of the reliability requirement. (See PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth.)

“Accelerating a backstop capacity procurement is especially necessary in light of FERC’s recent decision on co-location and its request for more information on utilization of this backstop procurement framework,” it said in a letter to stakeholders.

Addressing the MC on Jan. 22, board Chair and interim CEO David Mills said both the government’s and the board’s proposals don’t bear any resemblance to the existing backstop. PJM’s load forecast shows data center demand is likely to rise for a significant amount of time. “A one-time auction is not going to scratch the itch completely,” he said.

Designing an auction able to provide certainty for the supply and demand side of the auction on that timeline will require the states and FERC to be involved and take ownership over the outcome, Mills said. What can’t be allowed to happen is for there to be extended fruitful discussions only for an uninvolved party to fire a flare in the final hours, he said.

Even with a backstop auction, Mills said there are significant barriers to getting new resources built, including transmission upgrades, financing, tariffs, siting, permitting and supply chain constraints. Significant new capacity is unlikely to be available until 2032.

Manager Vickie VanZandt said the challenges of siting transmission could impede any resource adequacy benefits a backstop auction might provide. States and transmission owners will have to work together to overcome the likelihood of immense public pushback against network upgrades required to make new resources procured through a backstop deliverable.

Pennsylvania Deputy Secretary of Policy Jacob Finkel said he could not underscore the gravity of a bipartisan group of 13 governors and the White House calling on PJM to conduct the auction. He pushed back against suggestions that the September deadline was meant to be before the midterm elections in November, saying nine months seemed to be workable.

“We want this RTO to work; we want to solve this problem, but changes have to occur,” he said.

Constellation Energy Vice President of Wholesale Market Development Adrien Ford said the feasibility of holding a backstop auction in September depends on the design PJM decides to adopt and whether it tries to build off the existing capacity product or define a new one.

She said Constellation has been working with Vistra to revise the backstop mechanism that a coalition of resource owners and data center developers proposed during the CIFP process that would build off the existing definition of capacity, triggering if a capacity auction cleared below 98% of the reliability requirement and allowing for up to seven-year commitments. The auction would be open to new or reactivated resources; existing resources with offers higher than the maximum price for the Base Residual Auction that cleared short; and traditional demand response. (See “Joint Stakeholder Proposal,” PJM Stakeholders to Vote on Large Load CIFP Proposals.)

Mills said his vision of success is a ready-to-launch mechanism that accomplishes what PJM has been asked to do: Establish a market mechanism that marries new committed demand to new supply. To get to that point, stakeholders will need to chew through a lot of details, but he said that’s within their capability. He said he believes that in four to six weeks, there will be great progress on creating a workable design.

Unintended Consequences

Mills also called for stakeholders to identify areas where unintended consequences could be created by running auctions to procure capacity outside BRAs. One such challenge could be the creation of an additional cycle of grid upgrades being triggered.

The PJM Public Power Coalition’s Carl Johnson warned that a parallel capacity auction with the potential to deliver higher value for sellers could cannibalize projects already in the interconnection queue. If a substantial number of planned resources that PJM expected to come online and offer into the Reliability Pricing Model instead seek to participate in a backstop auction, there would be no net change in the amount of supply available to the grid, and the market would be even more short.

The Natural Resources Defense Council’s Claire Lang-Ree said the success of the backstop auction relies on the other components of the board’s CIFP proposal. If the bring your own new generation (BYONG) and “Connect and Manage” DR pathways for data centers aren’t strong enough, she said it would be hard to see why they would want to participate in a potentially more expensive backstop auction.

The BYONG model would allow large loads to meet their own capacity needs with new resources, which would qualify for an expedited interconnection track. Large loads that do not participate in BYONG would be subject to curtailment through load-serving entities ahead of pre-emergency load management resources in a model similar to PJM’s proposed mandatory non-capacity backed load (NCBL) brought during CIFP — though the load would remain in the capacity market. (See PJM Revises Non-capacity Backed Load Proposal.)

Mills said those changes are another area that will require buy-in from states to be successful: Because PJM cannot distinguish between consumers directly, it will be up to state utility commissions and utilities to disentangle large loads from organic economic growth.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he is concerned an auction awarding multiyear commitments would shift risk onto consumers.

Consumer advocates and representatives of Pennsylvania Gov. Josh Shapiro’s office urged PJM to extend the price collar that limited capacity prices to between $175 and $325/MW-day for the 2026/27 and 2027/28 auctions. Finkel said the 2028/29 BRA is not going to be able to procure enough supply and will clear at the $550/MW-day maximum price, a jump in prices he argued would not come with any reliability benefit. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor.)

Paul Sotkiewicz, president of E-Cubed Policy Associates, said constraining capacity prices would ensure that a parallel backstop auction would cannibalize resources from RPM.

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Power Grids Weather Winter Storm Fern, Face Continued Cold Snap

The winter storm that moved through Texas and much of the Eastern Interconnection over the Jan. 24-25 weekend cut power to hundreds of thousands of people and stressed the bulk power system, but it did not create major disruptions like storms earlier in this decade.

The storm dumped snow, sleet and freezing rain across its path, with the most power outages occurring on its southern edge — especially in the lower Mississippi Valley, according to the National Weather Service. Entergy Louisiana said Jan. 26 that most customers who lost power in its territory would be restored by Jan. 28, with some repairs taking a day longer.

NYISO wholesale power prices briefly hit quadruple digits at about 11 p.m. ET Jan. 25 (Sunday), while the Dominion Zone in PJM saw prices above $1,000/MWh for much of the day.

PJM is actually expecting higher demand Jan. 27, with lower temperatures prompting it to issue a maximum generation alert and a low voltage alert. The RTO could break its winter peak record that day, as it forecasts peak demand of 147.2 GW, which would beat the mark of 143.7 GW set a year ago.

The RTO said that it could see peak demand hit 130 GW for seven straight days, which would be a first for winter.

“This is a formidable arctic cold front coming our way, and it will impact our neighboring systems as much as it affects PJM,” Senior Vice President of Operations Mike Bryson said in a statement. “We will be relying on our generation fleet to perform as well as they did during last year’s record winter peak.”

PJM was one of several grid operators to take up the Department of Energy on its offer to issue emergency orders under Section 202(c) of the Federal Power Act. (See Wright Ready to Use Emergency Powers to Dispatch Backup Generation During Storm.)

PJM asked DOE to issue a 202(c) order to allow it to dispatch every generator in its footprint at is maximum level without violating air quality laws — an order that remains in place through the end of January.

DOE issued a similar order to ISO-NE as New England deals with the same cold. One generator informed ISO-NE that it was running up against its permitted emission limits.

“This prolonged severe cold weather event is expected to result in a sustained high level of demand for electricity,” ISO-NE told DOE in its order application. “While the vast majority of generating units in the ISO-NE region continue to function adequately, some units may experience difficulty due to emissions/air permitting limitations or other operating constraints.”

A graph from PJM’s Data Viewer showing real time prices by different zones as the storm passed through its territory. Dominion saw the highest prices. | PJM

NYISO is facing the same winter weather as its two neighbors, announcing last week that it could see peak demand exceed 24 GW, which was near expectations for this winter, but falls short of its all-time winter peak of 25.7 GW set in 2014.

“Our assessment finds there are adequate resources to serve demand on the grid under forecast conditions, but we’ve also seen generators in recent winters challenged with accessing adequate fuel capacity during very cold conditions,” NYISO Vice President of Operations Aaron Markham said in a statement.

MISO also issued a cold weather alert that remains in place through the end of January as low temperatures impact its footprint. It also issued a conservative operations declaration covering the cold snap.

MISO saw prices peak at about $1,802/MWh on Jan. 23, although they averaged just $178.04 across its entire footprint, while prices were slightly lower by Jan. 25.

SPP Back to Normal Conditions

SPP had returned to normal operating conditions as of 12 p.m. CT Jan. 26, after expiration of conservative operations and resource advisories that were in effect during the storm. However, it extended its weather advisory — considered normal operations — through noon Jan. 28 to maintain awareness of potential weather-related effects on system resources.

A spokesperson said the RTO had sufficient generation and met reserve obligations in its 14-state footprint during the storm, with load reaching about 46 GW during the morning peak Jan. 26. Load is forecasted to remain in the mid-40-GW range through the remainder of the week. SPP’s winter peak record of 48.1 GW was set in February 2025.

“We did not experience any major transmission losses, but we did get reports of local outages, particularly in the southern portion of our footprint,” SPP’s Derek Wingfield said.

He said the grid operator remained in close coordination with neighboring systems throughout the event, providing energy exports as needed and as available generating capacity allowed.

“We will continue to monitor conditions closely and will issue additional advisories as necessary,” Wingfield said.

Stronger ERCOT Grid Performs

The ERCOT grid breezed through the storm, a marked contrast to the dayslong outages during the disastrous Winter Storm Uri of February 2021. Since then, winterization has become mandatory for power plants and critical natural gas infrastructure. ERCOT has also added about 40 GW of capacity since the 2021 storm to bulk up its energy supplies.

About 90% of the new generation added since 2021 has been wind, solar and battery storage. Batteries provided more than 7 GW of energy at 8 a.m. CT Jan. 26. ERCOT’s instant storage discharge record stands at 9.7 GW, set in December 2025.

Natural gas provided more than 50.8 GW of energy at one point Jan. 26, another record, according to Grid Status.

This comes after DOE granted ERCOT’s request for an emergency order under the FPA because of the storm. The order allows certain electric generating units to operate up to their maximum generation output in certain limited circumstances, despite federal or state environmental standards and requirements.

The order is effective until 11:59 p.m. Jan. 27.

Early demand projections of 83 GW failed to materialize. Demand is now expected to peak at around 78 GW on Jan. 27.

ERCOT did declare a transmission emergency late Jan. 25 because of the loss of generation and transmission-line issues in the San Antonio and Houston areas. The emergency was canceled during the morning hours Jan. 26.

ISO staff have also canceled the operating condition notice (OCN) issued ahead of the approaching cold weather system. OCNs are the first of ERCOT’s “four levels of communication issued in anticipation of a possible emergency condition” and are issued when the system’s safety or reliability is compromised or threatened.

More than 61,000 Texas customers were out of power as of noon Jan. 26, primarily in the northeastern region of the state where American Electric Power subsidiary Southwestern Electric Power Co. and Entergy Texas operate.

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ISO-NE Responds to Feedback on Asset Condition Reviewer Role

ISO-NE responded to stakeholder feedback and provided more detail on its proposed asset condition reviewer role at the NEPOOL Transmission Committee meeting Jan. 21.

The reviewer role is intended to increase transparency and scrutiny into local transmission upgrades of existing assets. Asset condition costs have risen in recent years. According to the October update to the transmission owners’ asset condition database, the cost of asset condition projects placed in service since the start of 2020 totals about $4.67 billion. The transmission owners forecast an additional $1.97 billion to be added to this total by the end of 2026.

The growth in costs, coupled with concerns about a lack of regulatory oversight into the spending, has driven efforts to standardize asset condition procedures and increase public information and engagement.

As proposed, the ISO-NE asset condition reviewer would have limited authority — its findings would be advisory; it would not take over management or planning responsibilities from the transmission owners; and it would not make legal determinations on the prudency of investments. However, the reviewer would provide information on asset condition projects (ACPs) and practices that third parties could use to challenge the prudency of projects.

“The new function is envisioned to provide an independent review and opinion of ACPs” and help the states and the public better understand “the technical merits of proposed projects,” said Al McBride, vice president of system planning at ISO-NE.

The RTO aims to establish the role by January 2027, subject to FERC approval of the budget and governing documents. It plans to hire dedicated staff with technical expertise to review projects, McBride said.

In October, ISO-NE asked for feedback on the role’s objectives, governance structure, criteria for project review, stakeholder engagement, ties to holistic system planning and outputs.

McBride said the feedback ISO-NE received emphasized the need for technical expertise, credibility and strong scrutiny of proposed projects.

“Respondents generally agree that the [asset condition] reviewer should produce clear, detailed reports that evaluate alternatives, technical needs and cost-effectiveness, and that these reports must be transparent, well-documented and completed before construction begins,” he said.

In comments submitted in December, the New England States Committee on Electricity (NESCOE) wrote, “It is imperative that the review ultimately provide information of sufficient detail to enable states, consumer advocates and others to rely upon it to challenge or support the asserted need, the project option selected and/or costs, as needed.”

McBride noted that the RTO received a range of feedback on the governance structure, with some stakeholders advocating for the creation of a new department within in ISO-NE System Planning “to better achieve efficiency and build towards the objectives of more holistic outcomes, such as right-sizing,” while other commenters pushed for a standalone department “to better ensure impartial oversight.”

After accounting for the feedback, ISO-NE proposes to create a new department in system planning. McBride said this would help avoid “duplication of expertise” and would enable “future coordination with other planning activities, such as right-sizing.”

As proposed, the role would regularly report to the ISO-NE Planning Advisory Committee on transmission owner asset management practices and would review individual projects with an estimated cost of “greater than or equal to $30 million to $50 million on an individual line or at a single station/substation over a period of five years or less.”

The reviewer would look to identify inconsistencies between the asset management practices of transmission owners and look for opportunities for standardization.

For individual project reviews, ISO-NE would evaluate whether the transmission owner justified the project need and adequately evaluated project alternatives. The RTO would also give an opinion on the transmission owner’s preferred solution.

Projects would not be allowed to begin construction until the review is complete. Material modifications to a project or a change in the preferred solution would trigger reevaluation by the reviewer.

To establish the role, ISO-NE plans to add a new attachment to the Transmission Operating Agreement to “establish requirements for information provision, standardization and reporting.” It is targeting a technical committee vote in June on its proposal.

McBride said ISO-NE plans to discuss the “development of a right-sizing capability” after the asset condition reviewer design is largely complete, likely in the third quarter of 2026. Consumer advocates in the region have expressed a strong interest in developing a right-sizing process to prevent duplicative transmission projects and identify the potential for long-term cost savings. NESCOE wrote in its comments that establishing an asset condition reviewer should add confidence to future right-sizing discussions.

Surplus Interconnection Service

Also at the Transmission Committee meeting, ISO-NE kicked off discussions on surplus interconnection service. The RTO included the topic in its 2026 work plan at the urging of several stakeholders. It plans to analyze the current rules to evaluate stakeholder concerns and “the need for and scope of potential solutions.” (See ISO-NE Publishes Draft 2026 Work Plan and Stakeholder Forum: Surplus Interconnection Can Maximize Capacity in ISO-NE.)

Alex Rost, director of transmission services at ISO-NE, noted that the RTO implemented its existing surplus interconnection service (SIS) rules in 2019 in response to FERC Order 845. He said the SIS process is intended to allow interconnection customers “to take advantage of unused capability through the use of surplus interconnection service at existing points of interconnection.”

Surplus customers are not required to go through the ISO-NE interconnection process, which is part of the reason the topic has drawn interest from stakeholders. However, surplus customers still may need to undergo studies “if the performance characteristics of the new generating facilities are materially different from the existing generating facilities,” Rost said.

He emphasized that surplus customers are subordinate to the original interconnection customer. If the original customer retires, the surplus customer would lose access to the surplus service. This constraint is part of the reason there is only one instance of a surplus interconnection agreement in the region, he said.

He asked for written feedback by Feb. 6 on any “outcomes stakeholders are ultimately looking for related to this review … and any use cases they can provide.”

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Where are Utilities Best Serving Customers?

PJM had a big day Jan. 16.

The governors of states in the RTO’s territory met at the White House to discuss the flailing market; the administration’s Energy Dominance Council released a fact sheet on bringing big power plants back to solve PJM’s generation problems and a statement of principles urging it to make tariff revisions to right the ship; and the RTO’s Board of Managers released a letter directing its staff to make operational and market modifications, including revising its methods of load forecasting, instituting a reliability auction and forming a Bring Your Own New Generation (BYONG) plan for large load customers.

Alison Williams | Power for Tomorrow

The series of overlapping and likely coordinated actions has been received well by the energy community. And yet, what are being proposed are merely ideas. As Commissioner David LaCerte commented at FERC’s open meeting Jan 22: “These issues raised in these announcements will make their way to FERC soon.” Translation: We’re still talking about solving problems, not actually solving them.

So if we’re still in the planning phase, policymakers would be wise to look beyond PJM to find successful examples of the mutually beneficial outcomes everyone wants: American energy dominance, industrial competitiveness and customer protection.

Vertically integrated utilities have been doing this successfully for more than a century. In regions like the Southeast, this electric industry structure — where utilities own generation, transmission and distribution — is shielding customers from price spikes while supporting economic growth.

The data overwhelmingly support the vertically integrated model. On average, based on 2024 prices, residential customers in “deregulated” states paid 42% more for electricity than residential customers in states with vertically integrated utilities. Excluding Alaska and Hawaii — outlier states with unique geographic considerations — eight of the 10 most expensive states for electricity have a “competitive” structure.

Competition’s promise was lower prices, right? The hard data show that this promise has failed, costing residential customers billions. For example, in Illinois, a national consumer group has found that electric customers have paid $2 billion more for electric “choice” than they would have with the default utility.

The success of the vertically integrated utility isn’t by chance. And it isn’t monopoly power run amok. Rather, the vertically integrated utility model exists to serve the public interest and place the customer front and center. When Congress passed the Federal Power Act, it chose this approach because electricity requires massive infrastructure investment and therefore demands a different framework. We don’t need to imagine what thousands of wires individually bringing power to homes would look like because we see that in some parts of the world, and that is the way power was delivered in New York City in the late 19th century.

The primary operating principle of the vertically integrated utility is an obligation to serve all customers. These utilities are required to conduct extensive long-term planning where supply and demand must be balanced over decades and the procurement of resources must be the best combination of least cost and least risk. None of these actions or plans can move forward without oversight and approval by state regulators, who hold the dual objectives of supporting state-based growth and ensuring electric rates are fair, reflect actual costs and are allocated fairly across all customers. This relationship between utilities and their regulators is the original public-private partnership — and it doesn’t just work for electricity; it’s also a successful model for water, sewer and gas heating.

Yet, despite a century of success and recent data affirming that customers win under the vertically integrated model, some believers in “competition” continue to make the case for expanding it throughout the electric sector, including pushing for open solicitations for transmission projects. But the data are clear there too, and the pattern repeats: “Competitive” transmission delivers the same disappointing results as “competitive” electricity markets.

Consider what “competitive transmission” actually means. Planning entities determine which transmission projects are needed before any competition begins. Developers (the ones supposedly competing) merely bid to see who builds projects, not on identifying needs or providing ongoing competitive service. Indeed, competitive transmission operators have been fighting for years to be treated like regulated utilities when it comes to prices. Moreover, their so-called competitive bids routinely fail to translate into actual customer savings, proving the theory wrong.

A revealing example comes from New York in 2022, where a “competitive” bid came in 22% lower than the local utility’s proposal. Advocates of competitive transmission celebrated this as proof that competition in transmission can work. But the developer encountered cost overruns of about $74 million above its cost cap because of regulatory delays, transmission line rerouting, tree clearing and wetland mitigation. Tellingly, the original bid failed to account for these costs — whether through strategic omission to win the contract or unfamiliarity with local terrain and regulatory requirements. Ultimately, this project’s cost reached $249 million, up 38% from the winning bid and exceeding what the experienced local utility would have charged.

These stark examples of “competition” failures are particularly important now, as many state legislative sessions resumed at the start of the year and legislators are feeling pressure to find solutions to rising energy costs. Perennial bill proposals on energy often include doubling down on market structures, deregulation and pushes for retail or industrial “choice.” But these options can be best described as “competition for competition’s sake.”

Today’s policymakers should ask a simpler question for finding energy solutions: “What approach best serves customers?” The answer is clear: Well-regulated, vertically integrated utilities have a proven track record of protecting customers.

Electric utilities overseen by smart regulators provide the actual benefits that “competition” is supposed to deliver — downward pressure on prices, accountability for performance and incentives for efficiency — but with additional protections that markets cannot provide, including mandatory service obligations, reliability requirements, and protection from price volatility and market manipulation.

Regulators disallow cost recovery for imprudent investments, enforce lowest reasonable cost standards, and ensure balanced consideration of customer and shareholder interests. These are not theoretical benefits; they are demonstrated outcomes from a century of sound regulatory practice. We have examples of success popping up across the country, where vertically integrated utilities are recruiting data centers and advanced manufacturing with fair electricity rates that don’t harm small customers and average citizens.

The choice facing policymakers is straightforward: proven regulatory approaches that prioritize customers, or continued experimentation with “competitive models” that have repeatedly failed to deliver on their promises. After a century of evidence and recent high-profile market failures, the answer should be clear.

Alison Williams is senior vice president of Power for Tomorrow, a nonprofit that provides practical research, commentary and information regarding how the regulated electric utility model protects consumers and promotes consumer benefits.