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December 16, 2025

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Extreme Heat Triggers Capacity Deficiency in New England

ISO-NE declared a capacity deficiency, implemented a Power Caution and took extra actions to maintain grid reliability during what may have been the highest peak load since 2013, driven by extreme heat and humidity, on the evening of June 24. 

ISO-NE entered the day with a slim reserve margin and declared a Power Caution in the early evening “after the unexpected loss of generation left the region short of the resources needed to meet both consumer demand and required operating reserves.” 

A Power Caution indicates that the RTO can no longer maintain its reserves through “normal measures.” ISO-NE lifted it at 9 p.m., after the evening peak had subsided, but maintained a precautionary alert of abnormal system conditions, which was instituted June 23 because of the heat.   

Demand peaked at 26,024 MW around 7 p.m. June 24, according to preliminary data from the RTO. This would be the highest peak demand in the region since 2013 and about 200 MW higher than the forecast peak for the day. 

Heading into the summer season, ISO-NE projected a 24,803-MW seasonal peak in typical weather conditions and a 25,886-MW seasonal peak with above-average temperatures. 

The sudden generation loss that triggered the Power Caution may have come from a gas resource; just before ISO-NE issued the power caution, gas generation in the region declined rapidly by about 1,000 MW, according to RTO data. During the peak-load period, natural gas accounted for about 45% of the region’s fuel mix, followed by nuclear at 12%, oil at 12%, net imports at 11% and renewables at about 5%. 

Behind-the-meter solar also contributed to a significant peak reduction. ISO-NE estimates demand would have peaked at over 28,400 MW without its contributions. BTM solar pushed the peak multiple hours later in the day, from midafternoon to midevening. At 6:50 p.m., with solar production on the decline, BTM solar still contributed to an over-600-MW reduction in the peak.

Locational marginal prices spiked during the capacity deficiency, with the hourly Hub LMP reaching $1,110/MWh between 6 and 7 p.m., more than doubling the day-ahead Hub price of $475/MWh for the same hour. 

The extreme temperatures affected most of the country and caused tight system conditions throughout the Northeast on June 24. NYISO issued an Energy Warning late in the day, while PJM issued a Maximum Generation Alert and MISO remained under a Max Generation Warning. (See related stories, NYISO Issues Energy Warning as Heat Wave Boils New York and MISO Declares Max Gen Emergency in Heat Wave.) 

Across New England, thousands of distribution customers faced power outages amid the heat wave, which brought temperatures as high as 102 degrees Fahrenheit in Boston, marking the fourth-hottest day on record in the city. 

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Half of MISO States Oppose DOE Order on Campbell Plant, Add Rehearing Request

Half of the Organization of MISO States said the U.S. Department of Energy’s directive to keep the J.H. Campbell coal plant in Michigan operating through late August wasn’t well reasoned, violates the law and tramples on state-jurisdictional planning.  

OMS registered a June 23 request for rehearing, adding to a growing pile of challenges to DOE’s order to keep Consumers Energy’s 63-year-old J.H. Campbell coal plant from retiring as scheduled until Aug. 21, 2025. (See Order to Keep Campbell Plant Running Challenged at DOE and FERC.)  

OMS said DOE relied on an “overly broad and speculative interpretation” of what composes an emergency under the Federal Power Act and invoked federal authority when there was no supply squeeze. It pointed out that it was the first time DOE used such an order outside of a severe weather event or emergency and said it improperly interfered with state and regional planning processes.  

“This expansive use of emergency powers sets a troubling precedent, enabling intervention in routine, state-approved planning decisions without an actual crisis and risks establishing its use to circumvent normal utility, RTO and states processes, and likely exposes ratepayers to costs that should not be borne. Such preemptive action risks undermining the credibility of future emergency orders, distorting market signals and eroding the statutory balance between federal and state authority,” OMS wrote.  

OMS said DOE didn’t consult with MISO, Consumers Energy or the Michigan Public Service Commission or other state regulators responsible for integrated resource planning before issuing the edict. It also said DOE’s move was an arbitrary and capricious action under the Administrative Procedures Act.  

OMS asked DOE to vacate its May 23 order or revise it if DOE can demonstrate a reliability need after subjecting the order to stakeholder scrutiny and a more open process.  

The public service commissions of Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota and Wisconsin signed off on the rehearing request. The New Orleans City Council also added its endorsement.   

MISO South regulators from Arkansas, Louisiana, Mississippi and Texas abstained from voting to support the filing in addition to the public service commissions of the Dakotas. The Manitoba Public Utilities Board and the Montana Public Service Commission, on the other hand, didn’t participate in a vote on the request or become involved in drafting the OMS filing.  

OMS said this year’s resource adequacy survey in partnership with MISO, the 2025/26 MISO capacity auction, MISO’s summer readiness assessment and Consumers Energy’s plan “all do not indicate a regional reliability emergency, shortfall or an unmet reliability criterion that justifies reversal of a planned and approved resource retirement.” (See MISO, OMS Report Stronger Possibility for Spare Capacity in Annual RA Survey.) 

It pointed out that MISO’s capacity auction cleared beyond a one-day-in-10-years reliability standard. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)  

OMS said DOE failed to show a “dependable and comprehensive reliability assessment” that shows MISO is faltering. NERC’s Long Term Reliability Assessment (LTRA) — the primary data the DOE used to show MISO in crisis — should not be relied upon, OMS said. The organization said NERC employs inconsistent data collection between RTOs, unverified data inputs and “dubitable” evaluation metrics.  

“At their core, the NERC LTRA and seasonal assessments are undependable because they lack stakeholder input and verification. The NERC LTRA and seasonal assessments have been called into question over the past several years, as the assessments have gained traction and increased use, questions from MISO, multiple states and, most recently, MISO’s Independent Market Monitor.”  

NERC earlier in June said it would downgrade MISO’s risk level from “high” to “elevated” after MISO’s IMM accused the reliability regulator of failing to distinguish between installed capacity with unforced capacity when calculating the assessment’s totals. (See MISO IMM Blasts NERC Long-term Assessment, Says RTO in Good RA Spot.)  

“More accurate, timely and relevant information was and is available and was not expressly reviewed or contemplated by the DOE order, and no avenue exists to allow this more relevant information to be considered by DOE,” OMS wrote.  

Finally, OMS said DOE’s lack of a cost recovery framework for the 1.6-GW Campbell plant’s monthslong extension creates “legal, jurisdictional and equity concerns.” DOE created a cost-intensive action through its order, OMS said, yet tasked FERC with creating a means to assign costs to reimburse Consumers Energy. It said parties that don’t benefit from the plant’s paused retirement nevertheless could help fund it.  

MISO has not designated the plant as a system support resource necessary for grid reliability and isn’t equipped with any rules on the books to allocate the costs of keeping the plant running.  

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UPDATED: Oregon Lawmakers Pass Bill to Limit Utility Rate Increases

Oregon lawmakers have passed a bill that aims to mitigate the impact of rising energy costs on consumers by prohibiting residential rate increases during the winter and requiring energy companies and regulators to analyze consumer affordability when setting rates.

The state Senate voted 20-9 to approve House Bill 3179, also known as the FAIR Energy Act, on June 24, following its passage in the House on a 35-8 vote. The bill now advances to the desk of Gov. Tina Kotek for signature.

“Oregonians are struggling with unpredictable, poorly explained utility rate hikes that strain family budgets,” Sen. Janeen Sollman (D) said in a statement after the vote. “House Bill 3179, the FAIR Energy Act, fixes this by requiring real-world impact assessments before rate increases, banning winter hikes and ensuring clearer billing — delivering the affordability, fairness and transparency our constituents need.”

“I have heard repeatedly from my constituents how frustrated they are with the dramatic and repeated increases in their utility bills,” Rep. Nathan Sosa (D) said. “This bill will prevent the historic price shocks we have seen in recent years.”

The FAIR Energy Act directs the Oregon Public Utility Commission to consider the economic impact of a proposed residential rate hike on consumers. It allows the commission to adjust rates to mitigate an increase “if the increase would affect the ability of customers to maintain adequate utility services.”

The bill also requires electric or natural gas companies to file an analysis of economic impacts on the company’s residential ratepayers “if the company’s return on equity is subject to review and modification.”

The bill also will impose a freeze on residential rate increases from Nov. 1 to March 31 and would require companies to establish a multiyear rate plan that is no less than three and no more than seven years long. The bill also prohibits increases within 18 months of a previous hike until Jan. 2, 2027, or when the PUC adopts new rules on multiyear rate plans.

Utilities also must share a visual breakdown to inform customers what they are paying for.

Subject to PUC approval, the bill allows a public utility to issue bonds and securitize debt to cover costs associated with capital investments or other expenses.

“We’ve seen a huge response from customers who are fed up with constant energy bill increases,” Jennifer Hill-Hart, policy and program director at the Oregon Citizens’ Utility Board, said in an email to RTO Insider ahead of the vote.

“Last year, nearly 5,000 Oregonians wrote to the Public Utility Commission about rate hikes. Before 2024, we would see maybe 200 public comments a year,” Hill-Hart said. “We are pleased to see lawmakers listening to the needs of communities.”

Since its introduction in January, the bill has undergone several amendments, including updating the timeline for when utilities can increase rates and clarifying what data should be included in the rate analysis of the economic impact on consumers.

In the first version of the bill, the PUC would have determined whether the proposed rate is fair by first assessing if it would result in the public utility’s revenue increasing by 2.5% or more. That requirement was removed from the final bill.

‘Major Change’ to Ratemaking

“There is optimism HB 3179 can not only help smooth customer rates but also offer utilities a constructive/improved ratemaking process,” investment bank Jefferies noted in a June 23 newsletter.

Simon Gutierrez, a spokesperson for PacifiCorp, told RTO Insider ahead of the bill’s passage that Western utilities and the industry face “broad affordability challenges” because of inflation and wildfire risk.

“We understand price increases can be a burden to Oregon families, and we remain steadfast in our commitment to customers and communities and will continue seeking new ways to reduce impacts to customer bills,” Gutierrez said. “With HB 3179 now in the final stages of consideration by Oregon lawmakers, Pacific Power commends the legislative and stakeholder efforts to help mitigate the potential impacts included in this bill.”

“If it becomes law, HB 3179B will mark a major change to regulated utility ratemaking in Oregon and will provide the OPUC with new tools to manage utility bill affordability for our customers,” Portland General Electric spokesperson John Farmer said before the June 24 vote. “We look forward to working with stakeholders and the OPUC to implement this bill.”

Garrett Martin, policy adviser at the Oregon PUC, said in addition to freezing rate increases during the winter months, “HB 3179 also includes provisions that will allow the commission to proactively schedule rate cases and multiyear rate plans rather than only react to utility filings covering a single future year.”

“This shift will allow the OPUC to create more predictable rate changes and manage regulatory workloads so investigations can rigorously focus on affordability,” Martin said. “HB 3179, if enacted, will also aid the OPUC in considering additional factors when determining utility rates and provide additional clarity for the commission and utility customers about how utilities spend customer dollars.”

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Vegas: ERCOT Grid ‘Strong’ Heading into Summer

Much like a president addressing Congress, ERCOT CEO Pablo Vegas stood before his Board of Directors and declared the state of the ERCOT grid to be “strong.” 

“The grid is seeing improvements from a reliability perspective, season over season, and that’s important as we get into the start of the summer season to understand really what is the state of the grid,” Vegas told his directors June 24. “The state of the grid is strong. It is reliable. It is as reliable as it has ever been, and it is as ready for the challenges of extreme weather that we have ever experienced. I feel confident that we are ready for this upcoming summer season.” 

Good thing too, as ERCOT is forecasting demand to peak at 87.5 GW this summer in what staff are expecting to be above-normal temperatures. That would replace the current high of 85.5 GW, set in 2023. 

The Texas grid operator’s load peaked at 73.7 GW in 2021. It has added 4,600 MW of large loads since then, with an additional 1,848 MW energized but not yet operational. 

“We’re seeing significant and unpredictable load growth,” Vegas said, referencing data centers, industrial electrification, manufacturing reshoring and population expansion. “The characteristics and the pace of this new load in ERCOT is unlike anything we have seen or managed historically.” 

Fortunately, Texas is the nation’s leader in wind and solar capacity, Vegas said, and it is experiencing “unprecedented growth” in battery storage and distributed energy resources. ERCOT has energized 9,216 MW of solar and battery storage capacity since last summer, accounting for all but 429 MW of new capacity since then. 

Solar and batteries have played a key role in meeting ERCOT’s peak risk hour, which usually comes around 9 p.m. during the summer evenings. As Vegas said, solar energy is “very well suited” to support the air conditioning load during the heat of the afternoon, and batteries are “very well positioned” to help during the evening ramps. 

Solar and batteries “are extremely helpful during the summer seasons,” he told directors. “The risk of emergency events during those periods of time is shrinking, dropping from over 10% a year ago to under 1% this year.” 

At the same time, the grid operator has seen a net loss of 366 MW of gas generation. Much of that comes from the retirement of two gas units at San Antonio’s Braunig power plant, but Vegas said derates and indefinite mothballing at other gas resources also have contributed to the reduction. 

“Even though we’ve seen significant additions and other types of resources to be able to meet the needs of the system in a balanced way going forward across all periods of time and across all weather extremes, we are going to need to see balanced growth in supply,” he said. “That remains a concern and an issue to keep a focus on as we move forward.” 

The immediate focus, of course, is meeting demand this summer. The effort to mitigate the transmission constraint south of San Antonio has picked up steam. The first five of 15 mobile generators necessary to relieve the constraint have arrived in San Antonio from Houston and are expected to be operational by July 4. All 15 mobile units are expected to be interconnected to CPS Energy substations and able to provide 450 MW of capacity by mid-August. 

The mobile units will offer an emergency backup service to help protect the constraint while transmission upgrades are being made, Vegas said. 

The units originally were leased from LifeCycle Power by CenterPoint Energy in Houston. The utility is allowing the units to be dispatched by ERCOT, without compensation, through March 2027. (See ERCOT: Agreement Reached to Use Mobile Generators.) 

Staff have been working on the agreement since February, when they were unable to extend reliability-must-run agreements to two of the three aging Braunig gas units slated for retirement. ERCOT earlier entered into an RMR contract with CPS for Braunig Unit 3, its first since 2016. 

Vegas said CPS found “fairly significant upgrades and maintenance activities” needed to ensure the unit, which dates back to 1970, can continue to operate reliably. ERCOT expects to pay CPS $49 million this year under the RMR contract and a $10 million more in 2026. Together, that’s a $12 million increase from when the RMR contract was executed. 

“We believe that the new costs are well justified within the cost matrix, supporting the cost benefit of keeping this unit running for the foreseeable next couple of years until the transmission solution is developed, completed and ready to allow this unit to retire,” Vegas said. 

He said staff intend to propose a protocol change to allow a timelier recovery of the costs. ERCOT’s current RMR settlement processes do not allow those costs to be reimbursed when they are incurred. 

Chris Coleman, the grid operator’s meteorologist, told the board he expects above-normal temperatures and below-normal precipitation for most of Texas. The past three summers have ranked among the state’s six hottest since 1895. 

“The lean is for summer 2025 to be hotter than 2024,” Coleman said. 

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NYISO Issues Energy Warning as Heat Wave Boils New York

NYISO issued an Energy Warning late June 24 as New York began to finish its third day of intense heat.

The ISO had issued an Energy Watch earlier in the day, signaling that operating reserves were expected to be lower than normal for longer than 60 minutes. As temperatures climbed past 100 degrees Fahrenheit downstate and in New York City, the state’s grid was operating normally but reserves were declining, the ISO said in a statement.

Around 7 p.m., however, NYISO issued the warning, indicating reserves had dropped below 1,965 MW and are not expected to recover for at least 30 minutes. The ISO could begin shedding load if demand isn’t lowered or additional supply cannot be added, it said, asking customers to reduce their consumption if possible.

The ISO will issue an Energy Emergency Alert if reserves drop below 1,310 MW.

At the time of the warning June 24, the marginal cost of energy was nearly $1,400/MWh, with locational-based marginal prices in the Long Island zone at nearly $2,700/MWh.

Utility Actions

To combat high demand, PSEG Long Island activated its Smart Savers Thermostat Program, adjusting the thermostats for approximately 40,000 customers. The program load shifts energy consumption during peak by pre-cooling homes in the afternoon before people return from work and school. PSEG Long Island told RTO Insider that it anticipates shaving 60 MW off the forecasted peak demand.

Elevated temperatures and elevated demand caused roughly 7,000 people to lose power in the Albany area June 23. National Grid said elevated heat had caused a myriad of wire connection and transformer failures.

“Overall, the outages we have seen yesterday and today have been repaired in hours, not days,” National Grid spokesperson Patrick Stella told RTO Insider. “The outages have been limited and scattered across the upstate New York service area.”

Consolidated Edison told RTO Insider that it had restored power to roughly 79,000 customers in New York City since the heat wave had begun, with an average service interruption time of 4.5 hours. These outages were concentrated in Queens and Brooklyn, which is served heavily by an underground system more susceptible to thermal stress caused by prolonged high demand than the overhead system, Con Ed President Matthew Ketschke told local news.

In Central New York, Oneida County experienced tens of thousands of outages during the heat wave, but this was not from the heat itself. An EF1 tornado (86 to 110 mph) struck June 22 and downed more than 120 distribution poles, according to a National Grid press release. While service had been restored to 90,700 of the customers who lost power, more than 10,000 remained without as the heat wave struck. More outages were caused by local heat stress.

National Grid dispatched 2,500 linemen and foresters to repair the damage and is offering public cooling stations to customers affected by the heat. Heat has slowed some recovery efforts.

“We are taking precautions to ensure the health and safety of our crews, such as frequent cooling and hydration breaks,” said Jared Paventi, a National Grid spokesperson. “We’re cognizant of the stress on our customers as they enter their third day without electricity and AC, and we’re doing everything we can to restore power as quickly and safely as possible.”

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Duke Energy Carolinas Authorized to Maximize Generation Amid Heat Wave

The U.S. Department of Energy has issued an emergency order authorizing Duke Energy Carolinas to operate certain generation facilities at maximum output to meet heat-related demand. 

It was the fourth invocation in six weeks of the lightly used Section 202(c) of the Federal Power Act, and it was the first time in nearly two years that high heat prompted such an order. 

Duke requested the order June 23 as humidity and temperatures approaching 100 degrees F were settling over its service area in North and South Carolina. It said it expected a small percentage of its generating units to experience operating difficulties due to the heat and said also that 1,500 MW of capacity is offline or derated. 

Meanwhile, with a heat index in the low 100s, the utility forecast 21,968 MW of load for Duke Energy Carolinas. 

Duke declared an Energy Emergency Alert Level 2 (EEA 2) and told DOE it might not be able to meet the demand and might need to curtail load to preserve grid reliability. 

Early June 24, Energy Secretary Chris Wright signed Order No. 202-25-5. It expires at 10 p.m. June 25, but Duke can request a renewal. 

At 3 p.m. June 24, the National Weather Service reported a temperature of 98 degrees and a heat index of 105 in Duke’s hometown, Charlotte, N.C. It predicted a heat index as high as 110 on June 25 and forecast high temperatures would reach the low to mid 90s over the following few days. 

Also at 3 p.m., Duke’s outage map showed 121 outages totaling just 816 customers without power in the Carolinas. And the U.S. Energy Information Administration’s hourly electric grid monitor was showing Duke Energy Carolinas at 21,306 MW of demand. 

Duke Energy spokesperson Jennifer Garber told RTO Insider: “The grid is performing as expected and we currently have adequate power generation to meet our customers’ needs.” 

The 202(c) order would be used only if needed to preserve reliability, she said, and is narrowly focused on a few facilities: Duke’s Buck Station, Lincoln Combustion Turbine Station, Marshall Steam Plant and Rockingham Station, plus a few units that independent power producers requested be included. 

The request to DOE was a precautionary step as part of Duke’s all-of-the-above preparation for the heat wave, Garber said.

The utility issued conservation appeals for customers in the Carolinas to reduce their energy use, particularly during the peak 3-8 p.m. period. 

The DOE order noted Duke also had curtailed all recallable energy sales and implemented its load management program, including residential demand response and large-load curtailments. Duke also notified wholesale customers to implement in-kind load management programs. These efforts were expected to shave 700 to 1,000 MW off peak demand. 

Meanwhile, the order said, Duke obtained as much external capacity as it could — about1,332 MW. 

Duke told DOE it would exhaust these options before it ran any generation units in a manner that would conflict with local, state or federal regulations and permits. 

The 202(c) order authorizes the generators to operate at maximum capacity only as needed and only as long as Duke has declared an EEA 2 or EEA 3. 

Rare Invocation

Section 202(c) has been used infrequently. On its website, DOE lists just 26 such orders in the past quarter-century. Many of the recent orders were related to extreme weather — heat, hurricanes and the infamous Winter Storm Uri, which hit ERCOT in 2021. 

In the past year, there have been six orders: 

    • Oct. 9, 2024, authorizing Duke Energy to operate certain generating units at low load due to the effects of Hurricane Milton; 
    • May 16, 2025, two orders to the Puerto Rico Electric Power Authority to expand baseload generation and manage vegetation that threatens transmission facilities; 
    • May 23, 2025, blocking the retirement of Consumers Energy’s J.H. Campbell Plant in Michigan to preserve capacity in MISO (See DOE Orders Michigan Coal Plant to Reverse Retirement);  
    • May 30, 2025, blocking retirement of two units at Constellation’s Eddystone Generating Station in Pennsylvania to preserve capacity in PJM (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online); and 
    • June 24, 2025, to help Duke deal with the heat wave. 

Before that, the most recent heat-related 202(c) order authorizing maximum generation output was issued to ERCOT on Sept. 7, 2023, as temperatures in Dallas hit a record 107 degrees. 

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NYISO BIC & OC Briefs: Week of June 16, 2025

Committees Approve Updates to ROFR Implementation

The NYISO Business Issues Committee and Operating Committee approved without objection governing document revisions that would implement transmission owners’ right of first refusal in the ISO’s planning processes at their meetings June 16 and 20, respectively. 

FERC in 2021 ruled that New York TOs have a federal ROFR over transmission upgrades to their facilities and in 2022 approved tariff revisions implementing a ROFR for those that are part of another developer’s public policy transmission project under Order 1000. (See FERC Approves ROFR for NY Transmission Upgrades.) 

But those revisions did not include projects selected by NYISO’s own reliability and economic planning processes that include ROFR-eligible upgrades. The approved proposal would revise tariff attachments P, Y and FF to implement that. 

The proposal now goes to the Management Committee for its June 30 meeting. If approved by the MC and the Board of Directors, NYISO anticipates filing with FERC in July. 

Other BIC Action

The BIC also passed a pair of motions unanimously.  

The committee recommended that the MC approve tariff revisions to support NYISO’s Joint Operating Agreement with PJM in anticipation of the activation of the Dover phased angle regulator. The Dover PAR station is part of the AC Transmission Segment B public policy transmission project, which is intended to reduce transmission congestion between the Albany area and New York City. (See NYISO Board Selects 2 AC Public Policy Tx Projects.) 

Stakeholders also passed a motion to recommend approving changes to the tariff to implement the Market Purchase Hub Transactions project. The market design would allow trading hub energy owners (THEOs) to purchase and sell power on the NYISO day-ahead market to settle imbalances. 

System Impact Studies

The OC also unanimously passed a pair of system impact study reports for two interconnection studies.  

One of these, the POWI Project, would draw 50 MW continuously to the Port of Coeymans to support the port’s upgrades to service the offshore wind industry. (See Siemens Gamesa Plans OSW Nacelle Factory in Upstate NY.) The SIS found there would be no adverse impacts on the local grid. The good-faith cost estimate for the necessary upgrades was found to be $76.48 million. 

The other study was for Beowulf Energy’s Cayuga Compute project, a large data center expansion at the site of a retired coal plant. The project will boost the data center’s load from 50 MW to 138 MW.  

The data center supports artificial intelligence computation. The SIS found that the project could cause thermal and voltage violations but they could be mitigated with operating procedures and several upgrades to the local grid. Combined, the local upgrades would cost about $15 million. 

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N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility

New York’s governor has directed the state power authority to develop an advanced nuclear facility with at least 1 GW of nameplate capacity. 

The move is intended to bolster the state’s lagging clean energy efforts while simultaneously injecting a large quantity of emissions-free baseload power into the grid to facilitate decarbonization and economic development. 

In her announcement June 23, Gov. Kathy Hochul (D) did not elaborate on details about the facility to be built. The New York Power Authority clarified later that no determination has been made on the reactor technology to be used. 

The move places Hochul in an increasingly large group of industry, government and policy leaders hoping to advance a nuclear renaissance in the United States. 

It also places her squarely in the crosshairs of nuclear power’s many remaining opponents, a fact the governor alluded to when she said: “I’m the first Democratic governor in a generation to say to nuclear, ‘I’m embracing this. My state will embrace this.’” 

On cue, opponents raised questions about the plan or attacked it outright, as they have criticized the administration’s increasing willingness over the past few years to consider new nuclear generation. (See N.Y. Takes a Closer Look at Advanced Nuclear.) 

In January 2025, New York joined Constellation Energy in an application to the U.S. Department of Energy for a grant to support co-locating one or more advanced reactors with the two existing reactors at Nine Mile Point on the south shore of Lake Ontario. 

Hochul said this new initiative builds on that collaboration and sets the stage for collaboration with other states and with Ontario — North America’s first small modular reactor is being built in Canada, on the lake’s north shore. (See Ontario Greenlights OPG to Build Small Modular Reactor.) 

The new nuclear project would be built in partnership with the private sector in a community that welcomes it, Hochul said. The state wants to help finance the plant and buy the power it generates, she said, and she is directing the Department of Public Service to work with NYPA to protect ratepayers. 

Important Role

New York’s four operating commercial reactors, all owned by Constellation, receive ratepayer-funded subsidies in recognition of their value in providing 21% of the state’s electricity with zero carbon emissions. 

Nuclear opponents pounce on such subsidies (here and in other states) and point to the fantastically high cost of recent reactor construction projects as proof that nuclear is uneconomical — in addition to being potentially dangerous. 

Levelized cost of energy comparisons do show that new-build nuclear is several times more expensive than new-build solar and wind farms of the type proposed across upstate New York. (See Lazard: Solar and Wind Retain Lowest LCOEs.) 

But the levelized value of electricity is harder to quantify. 

NYISO shows a very low capacity factor for New York solar — 16% for front of the meter and 12.7% for behind the meter for 2023. Onshore wind was much higher in 2023, but still only 22%. 

Extensive backstops would be needed for any whole reliance on photovoltaics and wind turbines to power the Empire State, likely at considerable cost. 

In contrast, the Nine Mile Point reactors, which are 37 and 55 years old, ran at a capacity factor of 92.8% in 2023, and the 50-year-old Fitzpatrick reactor operated at 99.9%. 

Further, New York’s efforts to encourage wind, solar and storage construction are lagging for a host of reasons. The state expects to miss the first milestone in its 2019 climate law — 70% renewable energy by 2030 — perhaps by a wide margin.  

New York stood at just 23.2% renewables in 2023, due in part to the shutdown of the Indian Point nuclear reactors in 2020 and 2021. (See NY Quantifies Slow Progress Toward Renewables.) 

Hochul mentioned this as she spoke June 23 about the new initiative and flagged the shortcomings of wind and solar. 

“It shouldn’t be this hard. But no matter how hard we fight for renewables, solar works when the sun is shining, wind turbines spin when the air is moving,” she said. “We need electricity that’s reliable all day long, regardless of the weather outdoors.” 

That would be fossil fuel or nuclear, and New York is not going to add fossil generation, she said. 

Criticism Lobbed

Hochul’s comments on the state’s clean-energy transition have been more pragmatic than dogmatic, particularly when ratepayers are at risk of bearing higher costs. 

She put on hold the plans for the state’s cap-and-invest system, for example, and she echoed some of President Trump’s speaking points in her June 23 comments, saying the federal nuclear regulatory process was too slow and too cumbersome. (See NY Defers Action on Controversial Cap-and-invest.) 

(Trump moved to speed nuclear power research, development and deployment and ease regulatory oversight with a series of executive orders May 23. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.)) 

State Sen. Liz Krueger (D), chair of the Senate Finance Committee, shared questions about Hochul’s announcement that likely were shared by many nuclear skeptics and opponents: Is it the most cost-effective option? Can it be completed quickly? What will happen to radioactive waste? Are there alternatives? Will local governments be allowed to consent or refuse? 

“I have yet to see any real-world examples of new nuclear development for which all of these questions can be answered in the affirmative,” Krueger posted on X. 

Others took issue with the role to be played by NYPA, which was given expanded authority to develop renewables but debuted with a 3-GW plan that carried a high expected rate of attrition, far short of the robust 15-GW vision advocates had sought. (See NYPA Finalizes Road Map for Renewables Development.) 

“NYPA has the power and mandate to build 15GW of renewables and should not let Trump promises lead New Yorkers away from it,” Public Power NY said. “After appointing a Republican to lead NYPA while remaining silent on its mandate to build wind and solar, Hochul’s decision to step in based on promises from Donald Trump shows just how unserious she is about New Yorker’s energy bills and climate future. NYPA should be laser-focused on rapidly scaling up their buildout of affordable solar and wind, which is the only way to meet the state’s science-based climate goals and lower energy bills.” 

Others were more enthusiastic about Hochul’s announcement, including business and organized labor leaders. Hochul estimated the new advanced nuclear facility would create 1,600 construction jobs and 1,200 permanent jobs. 

The plant would be upstate, much of which is economically stagnant and has been losing population for generations.  

Hochul spoke not far from her childhood home, and noted she was the only one of six siblings who did not leave the state to start her career. A wind farm now stands where her father and grandfather once worked in a steel mill. 

Part of the goal with the nuclear project is to provide the power for new economic development, she added. 

State Sen. George Borello (R) applauded the plan and suggested the former NRG coal-fired plant on the shore of Lake Erie be prioritized as a site. Its shutdown left a gaping hole in the economy and budget of the city of Dunkirk, he said. 

“This would bring back critical revenue, generate well-paying jobs and deliver the long-overdue economic recovery that Dunkirk desperately needs,” he posted on Facebook. 

Constellation also welcomed Hochul’s June 23 announcement with enthusiasm but without specifics on next steps. 

A previous version of this story misstated the number of commercial reactors now in operation in New York.

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Order to Keep Campbell Plant Running Challenged at DOE and FERC

[EDITOR’S NOTE: An earlier version of this story implied that there was an error regarding MISO’s risk in NERC’s Summer Reliability Assessment. It has been corrected to say that the error was in the Long-Term Reliability Assessment.]

Legal challenges to the U.S. Department of Energy’s order to keep the J.H. Campbell power plant in Michigan open mounted with appeals of the initial order and comments at the case in front of FERC on how to pay for it. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.)

Michigan Attorney General Dana Nessel filed a request for rehearing at DOE on June 18 and intervened in the FERC docket (EL25-90) on June 20.

“The closure of this coal-powered electric plant has been planned for years; the utility made all due preparations to maintain our energy load without it; and the closure has been agreed to and cited in settlements affecting customer costs,” Nessel said in a statement. “In particular, if this arbitrary and unlawful order is allowed to stand, the only effect Michiganders will feel will be the pinch in their pockets. The costs of maintaining production at the plant, long since prepared for closure, could be an enormous burden on the ratepaying customers of Consumers Energy.”

The rehearing request her office filed argued the Campbell order “is an unlawful abuse of the department’s emergency authority” that it previously used only in response to natural disasters and requests from grid operators or other governmental bodies. Claims that keeping the plant running this summer responds to an emergency “cannot even bear the mildest scrutiny.”

Nessel also argued that MISO has found it has enough power to meet demand this summer. NERC did place the region under “elevated risk” in its Summer Reliability Assessment, but the attorney general said that was not even its highest level of risk in the report, and MISO has gotten that label regularly in reliability assessments this decade. MISO’s anticipated reserve margin this summer beats its target and is higher than it has been most of this decade, she said.

“The order indicates that the department believes it has the authority to decide which power plants may retire and when, not based on the kind of real emergency that has justified past action, but rather based on its own policy preferences,” Nessel said. “The department appears to want to place its own judgment about operating reserve margins ahead of MISO’s, and its own preference for which resources are employed to maintain resource adequacy ahead of Michigan’s.”

NERC mistakenly labeled MISO at “high risk” in its Long-Term Reliability Assessment based on what it called “mismatched data” from the RTO and said it should be reclassified as “elevated risk” for 2025-2027. The ERO admitted the mistake after criticism from Independent Market Monitor David Patton, who argued the report influenced DOE’s decision to keep Campbell open. (See NERC Responds to MISO IMM’s LTRA Criticism.)

Earthjustice, Sierra Club, the Natural Resources Defense Council, Public Citizen and other groups filed a separate rehearing request at DOE.

“The order is based on a profoundly incorrect understanding of the handful of sources it selectively quotes,” the groups said. “Those sources, and the order itself, do not support the order’s claim of a resource adequacy emergency in any of the various locations at which the order ambiguously gestures.”

Keeping the plant running at this point will be costly because Consumers deliberately minimized investments in it in recent years as it was expected to be retired, they argued. Getting it running could cost tens of millions of dollars, they said.

The same groups made a joint filing at FERC, where the only issue before the commission is who will pay for the power plant. The validity and sufficiency of the order will be addressed through pending requests for rehearing at DOE and, “potentially, litigation thereafter.”

“The commission lacks a basis to determine which, if any, utility ratepayers will materially benefit from the Campbell plant’s operation pursuant to the department’s order,” the groups said. “Ratepayers in Michigan, Iowa, Missouri, Wisconsin and other MISO states have met, and are already paying for, their resource adequacy obligations under MISO’s commission-approved framework for the order’s period.”

They argued consumers in MISO already have secured sufficient resources for this summer, so none of them would be clear beneficiaries of keeping the coal plant open, which means FERC cannot assign costs at this time. The environmental and consumer groups asked FERC to deny the complaint or to hold off ruling on the request for now.

The RTO itself weighed in on the FERC case, saying that while it does not intend to challenge DOE’s order, it has procured enough capacity for this summer’s demand. It has worked with its members, market participants, state regulators and FERC to ensure reliability going forward.

“MISO continues to work with these parties in the context of anticipated growing demand for electricity, planned electric generating facility retirements and an evolving mix of new electric generating resources to refine processes that address the challenges ahead,” it said. “MISO is confident that these collaborative efforts do not require further intervention and will help ensure the region continues to procure sufficient capacity to meet demand.”

But the order is in effect, and MISO lacks any current rules to allocate the costs of keeping the plant running, it said.

Northern Indiana Public Service Co. said that while Campbell is the subject of the proceeding at FERC, DOE already has used its emergency powers in PJM and could use them for other plants. NIPSCO supports Consumers’ request, but DOE’s ongoing use of the authority sheds light on the need for a more universal fix in MISO’s tariff.

FERC should direct MISO to come up with more universal rules on cost recovery so it does not have to deal with future requests in a “piecemeal fashion,” NIPSCO said. “The circumstances that Consumers Energy has found itself in may very well present themselves to other generators in the MISO region, and without an appropriate rate recovery mechanism, MISO’s existing tariff may be unjust and unreasonable.”

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Tenaska Power to Disgorge $28.2M in ERCOT Revenues

Tenaska Power Services and the Texas Public Utility Commission have reached a settlement in which the company will pay a $353,500 penalty and disgorge $28.24 million in excess revenue made in the ERCOT market in violation of agency rules. 

The commission consented to the penalties during its June 20 open meeting (57437). 

The PUC’s Compliance and Enforcement staff recommended the action after investigating Tenaska Power’s assignment of ancillary services (AS) from January 2016 through April 2021. Staff said Tenaska, a qualified scheduling entity (QSE) and ERCOT market participant, assigned the services to unqualified load resources. 

“Tenaska Power was paid to keep capacity available to provide ancillary services during this period but was incapable of providing the ancillary services assigned to unqualified load resources,” staff said. 

The investigation found four separate events where Tenaska Power was at fault: 

In 2018, two separate load resources under common ownership were provisionally authorized to provide AS responsibilities for a 90-day period. After a clerical oversight, Tenaska Power continued to assign the responsibility to the unqualified load resources after their provisional authorizations had lapsed. During the 31 days that followed, the resources were inadvertently assigned AS responsibilities for 5,261 intervals. 

In January 2018, the company telemetered an incorrect resource status code as the QSE for a third party’s generation resource. That led to ERCOT issuing a reliability unit commitment instruction for a unit that was unable to fulfill the request. 

During Winter Storm Uri in February 2021, Tenaska Power received real-time off-line reserve price adder payments for a resource that was on a planned outage when it telemetered incorrect information to ERCOT. 

During the storm, Tenaska Power also telemetered high sustainable limits (HSLs) that incorrectly represented the maximum sustainable energy production capability of resources it represented. The company offered to refund the HSL-related revenues using ERCOT’s alternative dispute resolution process. However, at the time, the process was not an available method to return the excess revenues to the market. 

Staff said Tenaska Power has since taken corrective measures to prevent similar issues in the future.  

Tenaska Power, a subsidiary of Nebraska-based Tenaska, agreed to the administrative fee and the disgorgement. 

Tejas Power Eligible for TEF Bonus

The commission sided with staff’s recommendation to affirm Tejas Power Generation’s eligibility for the Texas Energy Fund’s Completion Bonus Grant program. The generator seeks $17.52 million in performance-dependent grants over a 10-year period for a 146-MW project. 

Staff said Tejas Power’s application was administratively complete and that it completed a review process. The grant is contingent on the resource’s timely interconnection to the grid and meeting annual performance measures, including availability for ERCOT dispatch. 

Tejas Power is the second recipient of the bonus grant program. The PUC in April entered into a grant agreement with the Lower Colorado River Authority, which is seeking $22.5 million in loans to help build the first of two 188-MW gas-fired units at its Timmerman Power Plant. (See “4 Projects Added to TEF,” Texas PUC Approves 765-kV Transmission Option for Permian Basin.) 

LCRA says the unit is scheduled to reach commercial operations in 2025, ahead of its June 1, 2026, deadline to interconnect.  

SWEPCO Resiliency Plan OK’d

The PUC approved Southwestern Electric Power’s system reliability plan, but not before reducing the proposed vegetation-management spend by $5.1 million to $83.7 million (57259). 

Commissioner Courtney Hjaltman suggested the reduction to reflect what she said were “excessive estimates” for the project costs. The commissioners agreed to remove 26 projects with benefit/cost ratios of less than 1.0, considered the industry standard. 

SWEPCO filed the plan consisting of about $183 million of resiliency projects in November 2024. It reached a unanimous agreement with commission staff, the Office of the Public Utility Counsel, Cities Advocating Reasonable Deregulation, Texas Industrial Energy Consumers and Walmart in March. 

The PUC also agreed to intervene in support of MISO’s revised expedited resource addition study before FERC that allows a study of a limited set of interconnection requests on an accelerated timeline. FERC rejected the RTO’s first attempt in May, saying the grid operator failed to limit the number of projects that could apply (ER25-2454). (See MISO Reapplies for Generator Interconnection Fast Lane with FERC.)