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January 23, 2026

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N.Y. Extends ZEC Nuclear Subsidies to 2049

New York is extending its nuclear power subsidies as far as 2049 at a cost to ratepayers as high as $33.4 billion.

The four reactors and their 3.36 GW of output constitute an indispensable part of New York’s power portfolio and decarbonization strategy, NYISO and various stakeholders have said.

They are expensive to operate, however, and not economical at market power prices.

The state in 2016 created the nation’s first Zero-Emissions Credit (ZEC) program in recognition of these factors, and on Jan. 22, the Public Service Commission (PSC) extended the program’s expiration date from 2029 to 2049 (case 15-E-0302).

Constellation Energy, which operates all four reactors, has sought financial certainty as it plans the future of the two oldest operating reactors in the nation. They are licensed to operate only into 2029, and the deadlines to apply for their relicensing are March and June 2026.

“Failing to extend the ZEC program creates a risk of these plants closing, which could have significant impacts on reliability, resource adequacy and achievement of statewide clean-energy goals,” PSC Chair Rory Christian said in a news release.

Later Jan. 22, Constellation said it was still reviewing the order and deferred comment.

The PSC had long been moving toward extension, and in a July 2025 white paper, its staff at the Department of Public Service laid out the justification for what is being called ZEC 2.0.

A broad range of commenters offered opinions in support or opposition for a broad range of reasons.

Many clean energy advocates in the state are particularly unhappy that the state is embracing nuclear rather than doubling down on renewable energy.

New York is a national leader in small-scale solar, but deployment of wind, large-scale solar and storage so far has not matched grand ambitions, and it is unlikely to get easier under President Donald Trump.

The four reactors are a combined 202 years old. But unlike the planned wind and solar farms, they are online now and they produce a lot of power — 21% of in-state generation and more than 40% of the state’s emissions-free power.

NYISO reports that the reactors, with a combined nameplate capacity of 3.36 GW, generated 27,073 GWh in 2024.

The four reactors typically post annual capacity factors in the low- to mid-90% range and are steady except for refueling outages.

The output of New York’s wind and solar installations varies noticeably by region and greatly by time of day or time of year. NYISO assigned a capacity accreditation factor of 10.5 to 12.24% to solar panels for the 2025/26 capability year and 16.61 to 18.2% for land-based wind, with exact amount depending on location.

Mixed Reactions

Meanwhile, the state’s existing fossil generation is aging, the Trump administration is blocking offshore wind development, land-based renewables are slow and increasingly expensive to deploy, the governor’s vision of new nuclear development may not become reality for a decade, and the dispatchable emissions-free resources state energy planners are counting on to backstop a carbon-free grid do not exist in scalable or economical form.

The existing nuclear reactors, therefore, are viewed as indispensable and, for now, irreplaceable.

In Oct. 20 comments submitted on the ZEC proceeding, NYISO wrote: “The existing fleet of four nuclear generation resources must remain operational to avoid resource adequacy shortfalls and other electric system reliability issues.”

ZEC 1.0 cost $468.4 million to $600.5 million per year and $3.73 billion total in its first seven years.

ZEC 2.0 is capped at $33.4 billion, or about $1.6 billion a year, but DPS staff said the actual cost to ratepayers is expected to be much less — perhaps more than 50% less — due to rising market revenue for the electricity they produce.

The costs to consumers resulting from retirement of the reactors would be greater, staff said.

ZEC 2.0 was modified to include contract performance requirements, a mechanism to reduce the payments if Constellation obtains other financial support, a four-year review process and other ratepayer safeguards.

The PSC vote was cheered by Carbon Free NY, a business-labor-environmental-community coalition that includes Constellation.

John Carlson of the Clean Air Task Force said: “The ZEC program supports more than 14,000 jobs across the state and prevents more than 16 million tons of carbon pollution each year, providing the foundation for a more affordable and cleaner grid for New Yorkers. We applaud the New York Public Service Commission for extending the ZEC program to preserve existing nuclear resources and bolster the program’s tangible economic public health benefits.”

Food & Water Watch decried what it called a massive corporate bailout — the largest single use of ratepayer dollars and the largest subsidy to a single company ever approved by the PSC.

“It’s outrageous that New Yorkers will once again be forced to bail out this toxic, money-burning industry with billions and billions more in the coming years. Despite decades of evidence that nuclear power is both inherently dangerous and cost-foolish, Governor [Kathy] Hochul insists on throwing good money after bad, with everyday families footing the bill,” said Food & Water Watch’s New York state director, Laura Shindell.

The most recent nuclear reactor retirements in New York — Indian Point units 2 and 3 in 2020 and 2021 — resulted in a substantial increase in reliance on natural gas-fired generation.

NYISO reports 51.4% of the electricity generated in New York was produced with fossil fuels in 2024, compared with 39% in 2019, the last year of full operation for Indian Point.

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NERC Modernization Task Force Leaders Present Final Recommendations

The task force developing recommendations for updating NERC’s standards development process is preparing to post its final recommendations for industry comments, the final opportunity for stakeholders to submit feedback before a formal presentation to the ERO’s Member Representatives Committee in February.

Leaders of the Modernization of Standards Processes and Procedures Task Force presented an overview of their recommendations at the MRC’s pre-meeting conference call Jan. 22. Task force Chair Greg Ford said the proposal would be posted on or before Jan. 26, with comments due by Feb. 5. The MRC will discuss the recommendations at its open meeting Feb. 12 in Savannah, Ga., with the Board of Trustees deciding what action to take, if any, at its open meeting the same day.

NERC leaders launched the MSPPTF in February 2025, saying the rapidly revolving risk environment has made it increasingly difficult for the ERO’s consensus-based standards development approach to keep up with new threats to grid reliability. (See NERC Leaders Highlight Canada-US Collaboration.) The challenge was put on display in late 2024, with the board invoking Section 321 of the ERO’s Rules of Procedure to shorten the normal process in order to meet a FERC deadline twice in less than six months. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.)

The task force’s final recommendations propose an overhaul of the standards drafting process, with changes across all stages of the development cycle and the addition of two new groups to help create new standards. Leaders presented the changes according to the phase of development to which they apply: standard initiation, standard drafting and balloting.

Per the proposal, the initiation process would now take the form of a review and prioritization process conducted by the Reliability and Security Technical Committee. Todd Lucas, the task force’s vice chair, said stakeholders would have the opportunity to submit standard initiation requests throughout the year. The RSTC would review requests twice a year and determine the appropriate action, which could mean creating a new standard or other steps like developing a nonbinding guideline or technical reference document.

If the RSTC determines that a new standard is needed, it would hand the proposal to a newly created subcommittee of the Reliability Issues Steering Committee. The subcommittee would consult with industry to determine a plan for development, and NERC staff would work with a newly created pool of on-staff subject matter experts to create a term sheet outlining the goals of the proposed standard, which would guide the standard development phase.

Lucas said the task force also envisioned a “fast track” process for urgent projects, such as a directive from FERC or the board. This process would bypass the general intake and review stages and begin with term sheet development. He emphasized that stakeholders would still have the opportunity to provide comments and influence development in the standard drafting phase.

Ford took over the presentation of the standard drafting updates, which are intended to eliminate the multiple comment and ballot periods that are part of the current process. Under the MSPPTF proposal, NERC staff and the SME pool would develop a “version zero” draft standard to be taken up and modified by the project team, rather than requiring the team to write a new standard itself.

The project team would conduct informal industry outreach to shape the standard, then post their draft for stakeholder comment and a straw poll. Further revision periods would be followed by a confirmation ballot.

The task force’s proposals for the balloting stage would introduce new rules for the registered ballot body, including the consolidation of large and small electricity end users (Segment 7 and 8, respectively) into a single segment, and doing the same for segments 5 (electric generators) and 6 (electricity brokers, aggregators and marketers). Segment 10, regional entities, would be removed from the RBB entirely, while other segments would see their weighting in the ballot body revisited.

Ford expressed optimism that the board will accept the MSPPTF’s recommendations and that NERC will be able to implement the proposal by the end of 2026.

“We’ve got to change the Rules of Procedure [and] Standard Processes Manual, [and] committee charters need to be worked on. … There’s a lot of opportunity for us, I’m sure, as we go through this process, but the focus is going to be on starting with [ROP] and then move forward on that as we go through the year,” Ford said.

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Questions Abound over MISO Idea for Zero-injection Agreements

Stakeholders have several lingering questions as MISO continues to draw up a “zero-injection” avenue for large loads with planned on-site generation.

Marc Keyser, with MISO’s external affairs team, said the RTO is looking to define and standardize the process, though it already maintains a few signed generator interconnection agreements with no electricity injection specified.

The RTO said in late 2025 that it would create interconnection agreements where generation dedicated to large load facilities is barred from injecting into its system. Those generation projects would be able to bypass the generator interconnection queue and interconnect in a matter of months, not years. (See MISO Floats ‘Zero Injection’ Agreements to Bring Co-located Gen Online.)

“We would like to make a filing soon. The first quarter is a great goal to have,” Keyser said at a Planning Advisory Committee meeting Jan. 21.

MISO Director of Expansion Planning Jeanna Furnish added that the RTO would also continue to vet the proposal through its stakeholder process over spring.

“We understand that there are a lot of questions we have to work through,” Furnish said.

Keyser said a zero-injection agreement would restrict local generation to providing for its co-located load. He said the generation would be prohibited from running if the load isn’t operating to accept it.

“It’s potentially reducing network upgrades to interconnect,” Keyser said of the arrangement that would get new generation on — and simultaneously keep it off — the system.

MISO’s plan specifies that load can extract generation from the larger network if the generation isn’t on, but its designated generation can never inject into the system from its point of interconnection.

But stakeholders still had questions about how MISO would prevent the netting of behind-the-meter generation with load, a practice FERC prohibits.

Keyser said MISO would require separate metering and telemetry data of the load and generation. “This is not an opportunity to net load and generation behind the meter,” he said.

MISO Director of Resource Utilization Andy Witmeier said the process won’t allow netting because the RTO will have full visibility into both the generation and load from a planning and operations perspective.

For studies, MISO said a zero-injection resource would be modeled the same as any other resource. It plans to study NERC contingencies and conduct reliability analysis, accounting for steady-state, voltage stability and dynamic stability.

“Broadly, our studies are designed to capture contingencies,” Keyser said. However, MISO said reliability studies will always include scenarios where zero-injection resources are offline.

MISO said network upgrades wouldn’t be needed for zero-injection resources even when the most severe contingency occurs and generation trips offline. Keyser said the studies would be designed to “quickly reflect” that load has sought its own generation.

Staff said MISO has struck zero-injection agreements for three unnamed customers so far, including chemical processing plants in MISO South.

“I wouldn’t say this is readily available,” Witmeier said of the arrangements. He said the process isn’t documented in MISO’s tariff or Business Practices Manuals.

Mississippi Public Service Commission consultant Bill Booth asked if the prohibition on generation injections would be voluntary or if MISO would require physical elements to prevent injection. “How can you rely on voluntary participation if you’re not scanning the system for injections?” he asked.

Keyser said that of MISO’s existing zero-injection agreements, some have equipment to bar injections while others have committed to not injecting.

Booth said barring an electric interlock, the RTO should deliberate on the difference between a voluntary promise not to inject and a guarantee to not inject.

The Sustainable FERC Project’s Natalie McIntire asks what would happen if a large load supported by a dedicated generator tripped offline suddenly and the affiliated generator could not turn off output “really quickly.”

“We know that we owe it to stakeholders to be more specific about what it means to be zero,” Keyser said. “It’s an important question. We do plan on addressing it.”

He said MISO is holding conversations about operational reliability and is discussing elements such as how long it’s appropriate for a 150-MW generator, for example, to churn out 151 MW.

“I just don’t want MISO to gloss over all of these really technical questions as you’re trying to develop this really quickly,” McIntire said.

Arkansas Electric Cooperative Corp.’s David McRae said interrupting inertial generators can harm the generation. He asked how the RTO envisions dedicated generation ramping down over multiple cycles, if needed.

Keyser acknowledged that MISO has more work to do on those details as well.

At a Dec. 18 Organization of MISO States meeting, OMS counsel Brad Pope said the RTO’s zero-injection plan could harbor some “real reliability concerns” if it isn’t carefully thought out. OMS has scheduled a Jan. 23 meeting to discuss the proposal with RTO officials.

WEC Energy Group’s Chris Plante said the no-netting rule should apply universally across all markets, including the capacity market. He asked how MISO would accredit generation dedicated solely to a single customer.

“I would encourage MISO not to design this behind closed doors and include stakeholders on the design,” Plante said.

Booth said the RTO must figure out where the co-located load fits into a load-serving entity’s obligation to serve. “We can’t ignore it.”

Anthony Alvarez, of the Iowa Office of Consumer Advocate, asked if the co-located load could become demand response or load-modifying resources.

Keyser said MISO will have to explore that more, but the large loads would be firm, full-rights load and other loads are entitled to become LMRs.

However, Keyser also said MISO would have to work out “what does demand response and market participation look like.”

Wolverine Power Cooperative’s Sawyer McClure said he didn’t see why would-be zero-injection generation wouldn’t just pursue retail behind-the-meter generation status to serve the large loads.

But Keyser said behind-the-meter status is meant for only generation connected at the distribution level.

“If the required connection is at the transmission level, that wouldn’t work,” Keyser said.

MISO said it would provide more details on its proposal at the PAC’s meeting Feb. 25.

“This is not the extent of large load integration or ‘helps’ to incorporate large load,” Keyser said of MISO’s proposal.

Additionally, MISO will hold a workshop on how it plans to handle future large loads Jan. 30.

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Wright Ready to Use Emergency Powers to Dispatch Backup Generation During Winter Storm

U.S. Energy Secretary Chris Wright on Jan. 22 sent a letter to reliability coordinators and balancing authorities saying the department is ready to use its authority under Section 202(c) of the Federal Power Act to dispatch backup generation from large customers if needed ahead of a major winter storm over the following days.

The Department of Energy estimates about 35 GW of backup generation are available around the country, and using them during emergency conditions could mitigate blackouts and cut costs during the winter storm expected to impact much of the Eastern Interconnection.

“The Trump administration will not stand by and allow the previous administration’s reckless energy subtraction policies and bureaucratic red tape put American lives at risk,” Wright said. “We have identified more than 35 GW of unused backup generation that exists across the country and are taking action to ensure that if the nation needs it, the generation will be made available. Rest assured, President Trump and the Energy Department remain committed to doing everything in our power to mitigate blackouts and lower energy costs for the American people.”

The National Weather Service said a major storm was moving across the country, from the southern Great Plains and lower Mississippi Valley on Jan. 23 and then toward the Ohio Valley, Mid-Atlantic and New England over the weekend. Heavy snowfall is expected across the northern part of the system, with mixed precipitation across the South.

Wright and others at DOE have talked about using backup generation in public comments, but the letter offers new details on the idea — such as the use of FPA Section 202(c), which the department has used to stop central-station generators from retiring over the past year.

“Across the country there are gigawatts of readily available backup generation that have remained largely untapped until now,” Wright said in the letter. “This backup generation can and should be used to save American lives and avoid billions of dollars in economic devastation, as energy subtraction policies of the previous administration cause acute scarcity events.”

Wright said he has directed the department to prepare 202(c) orders, which would ensure backup generation that would otherwise be idle is available during emergency conditions.

If RCs or BAs contact DOE during the storm, even with a phone call, and say that they are facing an emergency that warrants a 202(c) order, Wright wrote that he would review the facts and issue one as needed. The backup generation would run “as a last resort before” rolling blackouts.

“There are certain facilities whose operations are of such criticality that it would be inappropriate to require their backup generation to run early in an emergency (like military installations and hospitals),” Wright wrote. “I expect the reliability coordinators and balancing authorities to work closely with the facilities within their service territories to deliberately prioritize the dispatch order of backup generation to achieve the greatest benefit to the bulk power system while balancing mission-essential functions.”

Wright said he has directed DOE staff to coordinate with RCs or BAs ahead of the storm.

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FERC Directs ISO-NE to Cap Pay-for-Performance Balancing Ratio at 1.0

FERC on Jan. 22 partially granted a complaint by the New England Power Generators Association (NEPGA) about the design of ISO-NE’s Pay-for-Performance mechanism (EL25-106).

The commission directed ISO-NE to cap the PFP balancing ratio at 1.0 but rejected NEGPA’s complaint about the RTO’s method of allocating stopped losses.

ISO-NE’s PFP rules incentivize performance during capacity scarcity events. While all resources are eligible to earn credits, only resources with capacity supply obligations (CSOs) are subject to penalties for underperformance.

The complaint stems from a scarcity event on June 24, 2025, that coincided with ISO-NE’s highest peak load in more than a decade. PFP credits totaled about $114 million during the event.

In a complaint filed in late July, NEPGA contended that a pair of “flawed rules” caused capacity resources to accrue $51 million in “improper charges” during the three-hour scarcity event.

The balancing ratio, which is used to calculate resources’ performance responsibilities during scarcity events, averaged about 1.031 during the June 24 event, causing “$25 million in improper charges to capacity resources,” NEPGA wrote in its complaint. It argued for a cap on the balancing ratio, writing that capping the ratio at 1.0 would prevent resources from being required to supply more than their CSOs. (See NEPGA Seeks Relief for ‘Improper’ Pay-for-Performance Costs in ISO-NE.)

The association also called for changes to ISO-NE’s rules spreading the costs of under-collected PFP penalties across all capacity resources. Monthly stop-loss limits on the total penalties each resource can incur can cause under-collection of credits. Instead of charging these losses to all resources with CSOs, NEPGA proposed to deduct under-collected credits from the payment pool for overperforming resources.

The association noted that there was a $26 million under-collection of credits during the June 24 event. This deficit was charged to all capacity resources that did not hit their stop-loss limit during the event.

In response to NEPGA’s complaint, ISO-NE did not oppose capping the balancing ratio but opposed the proposed changes to the allocation of under-collected credits. The RTO argued it is fair to allocate stopped losses to capacity resources because the stop-loss rules benefit these resources by limiting their financial risks. (See ISO-NE Open to PFP Changes Following NEPGA Complaint.)

In its ruling, FERC agreed with NEPGA’s contention that the lack of a balancing ratio cap is not just and reasonable, noting that “in the absence of such a cap, resources with capacity supply obligations in ISO-NE may be subject to financial charges even when they are providing their maximum possible physical output during capacity scarcity conditions.”

The commission wrote that, under the current design of ISO-NE’s Forward Capacity Market, resources are frequently accredited near their maximum capability. Notably, this could change under the new rules proposed by the RTO in its Capacity Auction Reform project, which would accredit resources based on their expected reliability contributions during periods of shortfall and likely would reduce the overall accreditation value for many resources.

Capping the balancing ratio appears unlikely to hurt reliability, FERC wrote, reasoning that resources still would have received a significant performance incentive if the ratio had been capped on June 24. Capping the ratio at 1.0 would have lowered the effective performance rate from $9,337/MWh to $7,243/MWh during the event.

Regarding NEPGA’s complaint about the allocation of stopped losses, FERC agreed with ISO-NE’s argument that all capacity resources benefit from the stop-loss rules. It found the existing methodology to be “consistent with the beneficiary-pays principle.”

“The stop-loss mechanism provides each capacity resource with insurance against the possibility of suffering net financial losses in excess of the stop-loss limit,” FERC wrote. “Even a capacity resource that performs at its capacity supply obligation benefits from the stop-loss mechanism and should pay its share of the mechanism’s costs.”

FERC gave ISO-NE 180 days to file tariff changes capping the balancing ratio at 1.0.

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FERC Addresses PJM’s Ongoing RA Issues at Open Meeting

FERC held its regular open meeting Jan. 22, but much of the discussion focused on events at the White House and in PJM’s headquarters a week earlier.

That’s when the White House’s National Energy Dominance Council and all 13 governors from PJM states agreed to call on the RTO to hold a separate backstop capacity auction for data center load, saying some hyperscalers had agreed to participate. (See White House and PJM Governors Call for Backstop Capacity Auction.)

“I want to recognize this historic agreement reached between the administration and a bipartisan coalition of 13 governors who represent the customers of PJM,” FERC Chair Laura Swett said at the open meeting. “This is a monumental moment.”

Later on the same day as the White House announcement, PJM released the proposals its board had been considering under the Critical Issue Fast Path (CIFP) process to deal with the influx of large loads in its footprint. (See PJM Board of Managers Selects CFIP Proposal to Address Large Load Growth.)

As a power pool, Swett noted, PJM is almost 100 years old and for most of that time has maintained a reliable grid, but now it faces “enormous challenges,” as its load is growing and supply has lagged.

“The market rules of PJM drive decisions to finance, build and operate resources that are needed to support our country’s reindustrialization and to win the AI race against our adversaries,” Swett said. “We are at a crossroads of deciding critical issues to maintain national and economic security, but we need to ensure that hardworking Americans don’t shoulder increasing energy bills.”

The CIFP proposals and PJM’s response to FERC’s recent colocation order include many of the ideas the 13 governors and the White House called for in their statement, Swett said.

“I expect PJM will carefully consider its next steps, and FERC is ready to quickly evaluate any proposals that come before us,” she added.

FERC also acted on rehearing proposals from MISO and SPP to speed up shovel-ready generation as they face their own issues around load growth and resource adequacy. Commissioner David Rosner noted the trend is national and other organized markets — or jurisdictional utilities outside them — face similar issues.

“The message I really want to underscore today is that other transmission providers, I hope, will take a look at what we did with PJM, and what SPP did for themselves, with their stakeholders, with very broad stakeholder support, and consider bringing similar ideas that work for your region,” Rosner said. “And solve the problems that we need to solve, which is get new generation online fast, get large loads connected, and make sure we don’t harm our reliability or raise costs for regular people.”

Commissioner Lindsay See noted that it was rare to see all 13 governors in PJM — who represent states with very different politics — agree on a set of principles.

“As someone who used to work in state government for one of those 13 states, I can confirm that does not happen very often,” the former West Virginia solicitor general added.

Commissioner Judy Chang noted that the issue of large loads is being addressed around the industry and said it was time to start thinking outside the box.

“Just generally, the supply challenge is tricky,” Chang said. “And the great people at PJM are smart and hardworking, and I want to continue to recognize their efforts, both the leadership and the stakeholder community, to continue again to address the challenges and put on their problem-solving hats to address the issues in the Mid-Atlantic region. I know that PJM staff is working hard to address the supply crunch in a very complicated and really difficult environment with very few quick fixes, or very few easy or obvious solutions.”

‘Necessary Partners’

Commissioner David LaCerte said FERC will hopefully have a package of capacity reforms from PJM in front of it soon, and like the other four commissioners, he noted the commission a day earlier had issued an order approving the RTO’s changes to the reliability pricing model (RPM) based on its most recent quadrennial review (ER26-455).

PJM must update its variable resource Requirement (VRR) curve every four years, including major inputs like the gross cost of new entry (CONE) and the expected energy and ancillary services (EAS) net revenues offset.

In the order, FERC accepted a combustion turbine plant as the reference resource for the 2028/29 delivery year and beyond. The peaker plants get most of their revenue from the capacity market, making it easier to calculate the EAS.

“A more accurate and stable EAS offset, in turn, results in a more accurate and stable VRR curve, which provides load and capacity suppliers with greater confidence in capacity auction prices,” the order said.

FERC also approved the shape of the VRR curve PJM proposed, which faced protests from the RTO’s Independent Market Monitor and Maryland’s Office of People’s Counsel because it discounted the EAS offset by 25%. PJM did that to hedge against the risk of overestimating the EAS and thus underestimating net CONE.

“PJM explains that even though it has historically hedged against this same risk by inflating the price cap by a certain percentage, its proposal to inflate gross CONE and deflate the EAS offset achieves the same effect,” the order said. “In addition, PJM correctly notes that capacity market prices should be able to rise above Net CONE during tight market conditions such that the price averages net CONE in the long term.”

FERC also accepted the RTO’s proposals for net CONE and the EAS offset. The order drew a concurrence from Rosner who pointed out states are an important part of resource adequacy in PJM.

“Given states’ authority over siting generation and transmission, public utility commissioners, governors’ offices and state legislatures are all necessary partners in any effort to ensure energy infrastructure is built out at the pace needed to stay ahead of load growth and keep energy affordable and reliable for PJM customers,” Rosner wrote.

“Just as PJM must earn buy-in from its states and its members to achieve durable market rules, we depend on PJM states, load-serving entities and developers to take the financing, procurement, permitting and construction steps needed to turn PJM market signals into steel in the ground. The PJM market is intended to support these efforts — not supplant them,” he wrote.

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Stakeholders Suggest Cost Overruns Ubiquitous as MISO Reviews Long-range Tx Project

Stakeholders told MISO that it might have anticipated an impending cost increase for a long-range transmission project under development in Minnesota that jumped about 43% in price to nearly $1.4 billion.

The 345-kV Iron Range-Benton County-Big Oaks project in Minnesota, from MISO’s 2022 collection of long-range transmission projects, is undergoing a variance analysis by the RTO for the cost increase. (See MISO Launches 2nd Review of Long-range Tx Project for Cost Overruns.)

Joint developers Minnesota Power and Great River Energy have upped costs to build the line from an originally estimated $970 million to $1.39 billion, citing an increase in labor and materials costs, an engineering refinement to substation work and routing redesigns. The project is set to connect Minnesota Power’s Iron Range substation in Itasca County to Great River Energy’s Benton County substation.

WPPI Energy’s Steve Leovy said MISO and stakeholders could have predicted cost overruns much earlier. He noted that the developers told the Minnesota Public Utilities Commission in August 2023 that costs could range from MISO’s $970 million estimate to $1.35 billion.

“It occurs to me that some of these things were known and should have been known some time ago,” Leovy said of the increases during a Planning Advisory Committee meeting Jan. 21.

“I just want all of us to get a better handle on cost estimates,” Leovy said. “We should have been on notice in August of 2023 that the costs would go higher. … I don’t think anyone should be surprised that it ended up in that neighborhood.”

Leovy said he didn’t want to suggest negligence or malfeasance on the part of the developers.

Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said the range Minnesota Power and Great River Energy submitted to the Minnesota PUC was not a final number, and the high end at the time represented a worst-case scenario.

Doner said the increase is a confluence of escalating materials costs and routing changes. He said the project first encountered routing cost changes because of permitting changes in Minnesota.

“Ultimately, Minnesota decided that there were additional co-location opportunities … to minimize impacts,” he said.

Some stakeholders said it shouldn’t be a surprise that state commissions would want routes to use existing rights of way as much as possible.

Doner said it wasn’t until the second half of 2025 that the transmission owners notified MISO of material and construction cost escalations.

“Collectively, that information drove the variance analysis trigger,” Doner said. “I note that everyone wants us to move as quickly as possible through this process.”

The Minnesota developers said the rise in costs for substation equipment, steel and labor accounts for 25% of the increase, while routing changes and the more fleshed-out work plan for the substation facilities account for the remaining 18%.

Doner said the developers are still trying to meet the project’s original 2030 in-service date.

Ørsted’s Eva Kaso-Collette asked if the timeline “slippage” brought on by the changes and review would last months or years. Doner said he could not speculate on the developers’ timeline.

Doner said he similarly could not put an estimate on how long MISO’s review would take.

“These truly are very case by case,” Doner said of the variance analysis process. “We are going to strive to work through these as quickly as possible.”

The first, $10.4 billion long-range transmission plan has grown to $10.7 billion, according to MISO’s latest quarterly reporting released in September 2025.

The Sustainable FERC Project’s Natalie McIntire asked if MISO transmission developers are encountering across-the-board cost increases for construction materials and whether the RTO should expect more overruns.

Doner said that while transmission owners are receiving larger-than-anticipated bids on materials, equipment and labor, it’s not a universal occurrence. He also said that in some cases, transmission developers are saving money by adjusting routes.

“We are not seeing a blanket, 30 to 40% cost increase,” Doner told stakeholders, though he acknowledged “upward pressure on prices and costs.”

Customers Call for Tighter Variance Analysis Rules, Oversight

Meanwhile, MISO’s transmission customers continue to advocate for narrower triggers to set variance analyses in motion, citing escalating costs.

They have asked MISO to equip the variance analysis with a 20% overbudget threshold to trigger the study (instead of 25%) and to consult with third-party experts and its Board of Directors on projects’ fates. (See MISO TOs Oppose Tx Cost Containment Suggestions.)

At a Dec. 16 stakeholder meeting on cost allocation, Ken Stark, with the Coalition of MISO Transmission Customers, said the “Damocles sword of high energy costs does hang over consumers’ heads in the years to come.”

Stark said the MISO industrial customers’ viewpoint remains unchanged, especially given booming transmission planning and ratepayers’ rising bills for electricity service. He said MISO’s second variance analysis is further proof of the need.

After it wraps up a variance analysis, MISO can decide either to let projects stand as they are, develop a mitigation plan for them, cancel them or assign them to different developers if possible.

Stark argued that the board should approve the outcomes of variance analyses.

“The MISO board approves the MTEP [MISO Transmission Expansion Plan]. It only makes sense they should approve material changes to the MTEP,” he said.

At the time, Leovy said it might be time for MISO to sharpen its cost estimation so that it better anticipates financial impacts to transmission projects.

Relatedly, the Organization of MISO States has engaged with nonprofit Regulatory Assistance Project for “technical assistance” on transmission cost oversight over the first quarter of 2026.

MISO has two active requests for proposals for two 345/765-kV competitive transmission projects in Iowa.

The nearly $1.5 billion Marshalltown-Lehigh-Sub T-Montezuma-East Adair and the $1.23 billion East Adair-Minnesota/Iowa State Line-Arbor Hill-York Avenue projects hail from MISO’s second, $22 billion long-range transmission portfolio. The two Iowa projects round out the seven projects that were eligible for competition from the portfolio.

Proposal deadlines for both occur in May; both projects are expected to be completed in 2034.

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Texas Officials: ERCOT Better Prepared for 2026 Winter Storm

With a major winter storm bearing down on Texas, state officials have assured residents the ERCOT grid is in much better shape to take on freezing conditions than it was five years ago when Winter Storm Uri caused a dayslong outage.

“The ERCOT grid has never been stronger, never been more prepared and is fully capable of handling this winter storm,” Texas Gov. Greg Abbott said during a Jan. 22 press conference. “There is no expectation whatsoever that there’s going to be any loss of power from the power grid.”

“We’ve been preparing for this storm over the last couple of days,” ERCOT CEO Pablo Vegas said. “At this time, we are not anticipating any reliability concerns on the statewide electric grid as a result of this weather event.”

Vegas said the grid operator published an operating condition notice telling generators and transmission operators to cut short outages to ensure as much capacity as possible is available. He said that since Winter Storm Uri, staff have conducted more than 4,000 weatherization inspections at generator and transmission facilities, and increased reserve margins to strengthen backup supplies.

ERCOT has issued a weather watch for Jan. 24-27 in anticipation of the storm’s forecast sub-freezing temperatures and the potential for frozen precipitation, higher electrical demand and possible lower reserves. It says grid conditions are expected to be normal during the watch.

The National Weather Service has placed much of Texas under a winter weather advisory through Jan. 25. It says Winter Storm Fern, as The Weather Channel calls the storm, is likely to bring mixed precipitation on its southern side, with “significant” ice accumulations from freezing rain and the potential for long-duration power outages.

ERCOT is expecting demand to peak at nearly 83 GW on the morning of Jan. 26, with about 125 GW of available capacity. The grid operator’s all-time peak is 85.3 GW, set in August 2023.

“[It’s] quite interesting to see ERCOT get closer and closer to be in the winter-peaking region,” Keith Collins, ERCOT vice president of commercial operations, said during a Jan. 21 meeting of the ISO’s Technical Advisory Committee.

He told stakeholders that “preparedness and communication” will be essential to minimize problems during the storm.

“We don’t anticipate any issues, but things do come up, and that’s where preparedness and communication is really important,” Collins said, “and so to the extent that things happen on your end, I think these are the two things that will help us.”

“We coordinate days in advance of an event like this making sure that the key supply chains, the access, the critical facilities, are known, and we know if there’s going to be any risks or issues on the grid that are ready to deal with those before they become a problem,” Vegas said.

Along with Public Utility Commission of Texas Chair Thomas Gleeson, Vegas and Abbott stressed any outages will be at the local distribution level. They noted most of the state’s utilities have launched vegetation-management programs following Uri and 2024’s Hurricane Beryl.

Gleeson singled out Oncor for its work, noting the North Texas utility has trimmed vegetation on an additional 8,000 line miles above and beyond what it would have done before state legislation passed after the 2021 storm.

A joint FERC–NERC report on that storm highlighted the role of natural gas supply disruptions from freezing infrastructure on the outages, which were not resolved for five days. Gleeson said he is not concerned about similar problems during Fern. (See FERC, NERC Release Final Texas Storm Report.)

“We have an historic amount of gas in our system. There will be adequate gas supply to fuel all of our gas units,” he said. “Additionally, [gas utilities] have put crews throughout the state to ensure if there is any type of freezing, that it can be addressed very quickly and responded to. I have no concerns at this point about any issues with our generation fleet.”

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New N.J. Governor Rapidly Confronts Electricity Crisis

Taking office on Jan. 20, New Jersey Gov. Mikie Sherrill (D) immediately signed two sweeping executive orders that sought to control the state’s aggressively rising electricity rates through ratepayer credits and generation expansion.

The governor outlined plans to use funds from the Regional Greenhouse Gas Initiative and two other sources to provide ratepayer credits. The directives also aim to increase generation capacity by accelerating solar and storage development; better manage peak loads by creating a virtual power plant; and enhance the production of existing gas generators by improving efficiency.

At a morning swearing-in ceremony in Newark, Sherrill said she would be “fighting for” the people of the state and turned to the state’s power challenges as an example. During the election, Sherrill made affordability a central element of her campaign and pledged to take on the state’s increasing electricity prices with a rate freeze upon taking office. The average rate bill in the state rose by 20% in June. (See N.J. Backs Clean Energy Democrat for Governor.)

“I hope, New Jersey, you remember me when you open your electric bill and it hasn’t gone up another 20%,” she said. “I can promise you, it won’t be because I waste your money on a ballroom at Drumthwacket,” she said, referring to the governor’s mansion.

Sherrill’s proposals drew a warm reception from environmental groups, and the New Jersey Business and Industry Association said it is “encouraged to see that Gov. Sherrill is taking on the energy affordability and reliability issues head on.

“Energy policy needs to be grounded in realism, and these executive orders recognize the issues and set forth potential solutions,” said Ray Cantor, a lobbyist for the organization. “They are very positive.”

He added that it is hard to “predict the ultimate impact” of the orders, but they lay the “groundwork” for future actions.

Abe Silverman, a former counsel for the New Jersey Board of Public Utilities who is now an assistant research scholar at Johns Hopkins University in Baltimore, said the breadth and depth of the two EOs show the importance of the issue to the state and to Sherrill.

“The fact that the first two EOs of a new administration are about energy affordability — that sends a pretty loud signal to the world that this is a priority,” Silverman said.

He said he was impressed that the EOs contained a significant number of “meaty,” concrete and realistic proposals, in addition to longer-term strategies such as paying utilities based on performance rather than a percentage of capital spent.

“I would give it very high marks for viability. I would give it very high marks for the ability to dent any cost increases,” he said of the plan outlined in the two EOs. “I think we have to give it a bit of an incomplete on whether they’ll be able to implement a rate freeze, because we simply don’t know how big the cost increases on the PJM system are going to be.”

Rate Cost Offsets

Sherrill’s first order directs the BPU to create Residential Universal Bill Credits to “offset increases in the cost of electricity supply due to take effect in 2026.”

The order says funding for the credit would come from RGGI, the state Societal Benefits Charge and the state Solar Alternative Compliance Payment account. Similar sources funded a $100 credit to the state’s 3.9 million residential ratepayers announced in August to mitigate the June rate hike.

The order also requires the BPU to conduct a “study regarding modernization of the traditional distribution utility business model” and to look for ways to increase support for energy efficiency programs for low-income ratepayers. It directs the BPU to “consider pursuing a pause, abeyance or modification of the schedule governing any proceedings in which electric distribution utilities seek approvals for rate increases or cost recoveries to the extent permitted by law.”

“The current cost of electricity has reached the point of crisis for many residents and families, and requires bold action to provide short-term relief and medium- and long-term strategies and reforms to improve our energy system,” the order says. It adds that electricity rates in New Jersey are “among the highest in the continental United States and in the Mid-Atlantic region.”

Boosting Solar, Gas Generation

The second order calls for a push to develop more solar and storage, saying their shorter development timelines — “often months rather than years — makes them particularly critical technologies to meeting the state’s and the region’s electricity supply.”

The order requires the BPU to accelerate solar generation with a new solicitation for grid-scale solar under the existing Competitive Solar Incentive and an offering of 3,000 MW of generation under the Community Solar Program. An existing storage incentive program will launch a solicitation for “transmission-scale” battery storage.

The order also requires the BPU to develop a VPP that it says will “drive down peak demand by aggregating behind-the-meter distributed energy resources.”

Sherrill also called on the BPU to investigate ways to reduce or expedite the state permitting process, including for existing gas-fired power plants, in a modernization effort that should “increase generation capacity, reduce emissions and improve efficiency.”

Her order also requires utility companies to prepare a report on ways to “improve the efficiency and speed of interconnection of new projects.” And it calls for the creation of a Nuclear Power Task Force to “formulate and implement a strategy for the development of new nuclear generation facilities in the state.”

Rapid Demand Escalation

Sherrill succeeds fellow Democrat Phil Murphy, who has faced criticism that he focused too much on clean energy in his two terms and left the state short of generating sources.

But New Jersey officials say after two decades of flat demand, they could not have predicted the sudden demand surge from data centers.

PJM says the state’s difficulties echo those throughout its service region, where politically driven decisions by the states mean old, mainly fossil-fuel generators have closed at a faster rate than replacements have come online. That dynamic has been dramatically worsened by the sudden appearance of demand from heavy energy-using data centers, the RTO says.

In the first order, Sherrill attributes the state’s rising electricity prices to “the escalating cost of transmission and distribution infrastructure on which the grid relies, volatility in the price of natural gas and the skyrocketing price of the future supply of reliable, wholesale electricity — also known as capacity — in the regional PJM market.”

New Jersey’s task of needing to speedily build capacity is especially difficult. The centerpiece of Murphy’s energy plan—11 GW of offshore wind generation — has largely stalled. The developers of the state’s most advanced projects, Ocean Wind and Atlantic Shores, withdrew as rising project costs threatened their economic feasibility, and the Trump administration has sought to shut down wind projects. The state currently has no active wind project.

The impact of Sherrill’s measures on the state’s rate woes, and generation shortfall, is unclear.

Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association and a solar developer, said “there is a lot of good stuff” in the two orders. That includes the effort to accelerate the development of solar and storage projects, the VPP and a grid modernization plan, he said.

Still, he questioned whether the state could handle an increase of 3,000 MW in the community solar program, calling it an “enormous amount” and adding that its implementation could cause “some chaos.” He was skeptical that the state could connect that capacity so quickly to the grid.

But the biggest drawback in Sherrill’s proposal is the lack of “emphasis given to reform of PJM, which we think is the only thing that is going to bring prices back down or stabilize them in the near term,” he said. “The primary focus needs to shift to that, or else there’s no way that any other measures will be effective.”

But environmental groups had few doubts about Sherrill’s proposals.

Anjuli Ramos-Busot, director of the Sierra Club’s New Jersey chapter, said the two orders would “will freeze electric rates and put more clean, cheap energy generation on the ground.”

Jackson Morris, director of state power policy at the Natural Resources Defense Council, said his organization is “confident those important deliberations will result in a robust energy portfolio that maximizes renewables and energy efficiency for the benefit of all ratepayers.”

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CPUC Urges ‘Stop the Brakes’ Tool for EDAM Congestion Revenue Approach

The California Public Utilities Commission wants CAISO to come up with a way to pause settlements of certain congestion revenue allocations in the ISO’s upcoming Extended Day-Ahead Market if participants begin to game the market through extensive self-scheduling.

If such “rampant pervasive behavior” appears, CAISO should consider reverting to using the ISO’s prior settlement methodology, the CPUC’s Energy Division said in January comments submitted to an ISO EDAM working group.

The congestion revenue allocation issue, specifically in situations of parallel flow on the electric system, was CAISO’s top priority last year. CAISO approved a new methodology to address the concern in June 2025, and FERC approved the methodology two months later. (See CAISO’s EDAM Scores Simultaneous Wins at FERC.)

Under the new methodology, certain congestion revenues stemming from parallel flows will be allocated to the BAA where the energy is scheduled rather than where the constraint is located — the previous methodology. Those revenues will be allocated based on a transmission customer’s eligible firm Open Access Transmission Tariff transmission rights submitted and cleared as day-ahead balanced self-schedules.

However, the new methodology will maintain a “suspected underfunding problem for the immediate future if other BAAs decide to self-schedule their bids in order to receive this congestion revenue,” the CPUC said.

“The expansion of the day-ahead market should not come at the expense of California ratepayers, who have invested millions, if not billions of dollars, into building a reliable grid,” the CPUC said. “Therefore, rather than allocating away congestion revenue tied to parallel flows to the BAA causing the parallel flow, any long-term CRA methodology should return that congestion revenue to the BAA in which the constraint occurred.”

Although the new allocation methodology has flaws, it was necessary to implement “as a stopgap measure for EDAM go-live to occur on time,” the CPUC added.

The CPUC recommended CAISO build out a “stop the brakes” mechanism, such as a pause in settlements, if the new methodology starts to show signs of gaming.

In December, CAISO published a proposed set of design principles that would help eliminate or reduce self-schedule incentives in the approved congestion revenue allocation design. Self-scheduling incentives could lead to significant unintended cost shifts, experts cautioned earlier in 2025. (See CAISO Looks to Eliminate Self-schedule Incentives in EDAM Congestion Revenue Design.)

The CPUC asked also CAISO to confirm the ISO’s settlements system will be able to break out the congestion revenue tied to a parallel flow that crosses multiple BAAs. This potential issue will not be a concern when EDAM launches with PacifiCorp as its first participant in May 2026, but the ability to break apart congestion revenues will become more important when Portland General Electric and other entities join the market later in the year and in 2027, the CPUC said.

The agency asked also CAISO to clarify how it is treating congestion revenue tied to parallel flows caused by flows from another market, such as Markets+.

“Is this congestion revenue assigned to the BAA in which the constraint occurs, or is this congestion revenue returned to the market participant in the other market?” the CPUC said. “If the latter, has CAISO initiated these conversations with Markets+? Or does EDAM simply keep these congestion revenues?”

EDAM Benefits Approach Drafted

Separately, CAISO on Jan. 20 published its draft methodology for how the ISO and EDAM participants will estimate EDAM’s gross economic benefits.

The draft proposes to calculate EDAM benefits based on production cost savings in the electric system with EDAM versus the cost of the system without EDAM.

For hydroelectric resources, the EDAM benefit methodology will use an adjusted bid value to calculate production costs of the resource. This is because hydroelectric market bids might include both the value of water and certain external limits, CAISO says. Some of these external limits include FERC minimum flow requirements, recreational reservoir levels and forecast reservoir level targets, the draft says.

Estimating EDAM benefits does not require additional market tools or external data sources, and EDAM participants are not required to submit more data than what they already submit in a market run, the report says.

CAISO plans to finalize the benefits calculation methodology in the first quarter of 2026 before EDAM opens in May.