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December 19, 2025

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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.) 

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PJM Stakeholders to Examine Rules for Future DOE Emergency Orders

VALLEY FORGE, Pa. — Looking ahead to the possibility of future emergency orders from the U.S. Department of Energy, stakeholders endorsed a PJM issue charge to establish a more permanent set of rules for how to allocate the cost of keeping generation online beyond its desired deactivation date when ordered by the federal government. 

PJM Executive Director of Member Services Jennifer Tribulski told the Markets and Reliability Committee on June 18 that the RTO envisions a new senior task force meeting two to three times a month, with a goal of submitting a filing to FERC in October. 

The issue charge designates the content of future DOE orders and the “operating protocols and parameters agreed to by the resource owner” as out of scope. 

The Members Committee voted to support a proposal to assign all PJM consumers a share of the cost of continuing to operate Constellation Energy’s Eddystone Generating Station. The company was ordered by DOE to keep Eddystone online past its May 31 deactivation date to ensure resource adequacy, but the order did not specify how Constellation should be compensated. (See PJM Stakeholders Propose Cost Allocation Models for DOE Emergency Orders.) 

The package from Gabel Associates received 86% sector-weighted approval in the June 18 vote, making it the only proposal to receive the committee’s support over two proposals from PJM and three from the East Kentucky Power Cooperative (EKPC). The vote results are advisory to inform the PJM Board of Managers’ determination on how to proceed. 

Stakeholders commented on the proposals to the board in a Critical Issue Fast Path (CIFP) meeting, which was closed to media and held after the MRC meeting but just before the MC vote. The CIFP process was conducted on a tight five-day timeline to avoid a gap in billing. 

All of the proposals include the same June 1 implementation date, transparency provisions, billing frequency and cost allocation calculation formula. Where they differ is how to determine which consumers should be allocated a share of the costs and whether the governing document revisions should address possible future DOE emergency orders. 

Gabel’s proposal, PJM Package C and EKPC Package E would allocate the costs to all PJM consumers, while PJM’s Package A would narrow the allocation to specific locational deliverability areas (LDAs) or zones if future emergency orders specified that a resource adequacy issue was geographically isolated. EKPC Packages D and F would allocate the costs to specific LDAs if they clear short of their reliability requirement; otherwise, they would use an RTO-wide allocation. 

Gabel and EKPC Package E both would apply only to the Eddystone order expiring in August, with the other five including differing ways of addressing any future emergency orders to keep generation online. 

Constellation Vice President of Wholesale Market Development Adrien Ford said the company could not support Gabel’s proposal without modifications to allow it to continue to provide cost allocation beyond the Aug. 28 expiration of the DOE order in the event the department requires Eddystone to remain online longer. 

Exelon Director of RTO Relations and Strategy Alex Stern said he supports the Gabel proposal and trusts the board to make any necessary adjustments, such as the applicability to future orders. 

Carl Johnson, representing the PJM Public Power Coalition, said some members supported the Gabel proposal because it would limit the changes to the current Eddystone order, with the belief that there will be more emergency orders issued in the next few weeks and those should be addressed as they come up. 

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PJM MRC/MC Briefs: June. 18, 2025

Dominion Presents Proposal to Change Dual-fuel Definition

VALLEY FORGE, Pa. — Dominion Energy presented the Markets and Reliability Committee with a quick-fix package to expand the definition of dual-fuel generation in the Reliability Assurance Agreement (RAA) to include generation capable of running on a backup fuel type with off-site storage and dedicated delivery.  

The current language restricts the dual-fuel classification to gas combustion turbines or combined cycles capable of starting and operating on an alternative fuel with on-site storage. Dominion’s James Davis said that would exclude an LNG storage facility the company is building in Virginia. Dedicated pipelines would run from storage to two CC generators, a configuration not recognized as dual-fuel under the existing rules, but which Davis said provides a comparable degree of reliability. 

The quick-fix process allows a problem statement, issue charge and proposal to be brought concurrently. The proposal would be effective for the 2028/29 Base Residual Auction (BRA), the schedule of which has fuel-type attestations due in November. 

Calpine’s David “Scarp” Scarpignato said the proposed language could loosen the definition of fuel source to allow configurations that would not deliver the reliability expected from dual-fuel units. When Calpine proposed changes to the dual-fuel definition in 2024, the Independent Market Monitor recommended changes to the proposed language to ensure the backup fuel actually could be used. Scarp gave the example of a generation owner seeking dual-fuel status for a resource with a small on-site storage tank intended to be resupplied by truck as needed. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.) 

Stakeholders Bring Alternative SATA Issue Charges, Endorsement Delayed

The committee deferred voting on an issue charge seeking to establish a ruleset for battery storage to be installed and operated as a transmission asset (SATA) to allow more time to consider two alternatives brought by Constellation and Exelon. 

The PJM issue charge has been discussed at several meetings in recent months, with voting delayed to hold education on how SATA would operate and its implementation in other RTOs.  

Building off PJM’s issue charge, Constellation added several key work activities (KWAs) to identify the use case for SATA, when the batteries would run and more thoroughly consider the market effects storage might have. Stakeholders seeking more consideration of the topic before voting on an issue charge have argued inadequate rules could allow batteries on a regulated rate to displace market-based resources. 

Independent Market Monitor Joe Bowring has said in past meetings there is not a way to meaningfully distinguish between a resource injecting energy for transmission support or market participation. 

Exelon proposed edits to the Constellation language focused on ensuring SATA would be treated and used the same as other transmission solutions. It replaced a Constellation KWA to “identify what the market impacts could be and a commitment to address them” with “ensure a storage device identified as transmission only and not a market resource is treated no differently than any other transmission asset, including with respect to market impacts.” 

1st Read on 3rd Phase of Hybrid Resource Rules

PJM presented revisions to several manuals to conform with FERC’s approval of the third phase of PJM’s hybrid resource rules (ER25-1095). Elements of the manual changes were endorsed by the Planning, Operating and Market Implementation Committees earlier in June. (See “3rd Phase of Hybrid Resource Rules Endorsed,” PJM MIC Briefs: June 2, 2025.)  

Phase 3 expands the hybrid model to include pairings of co-located non-inverter-based generation and battery storage as one market unit. Hybrids with a capacity commitment would fulfill their obligation to offer into the energy market by submitting their forecast output, capped at the inverter capability, while a hybrid with a storage component should offer the “anticipated intermittent and battery output.” 

Revisions to the formula for lost opportunity cost (LOC) credits would make eligible storage and hybrid resources instructed to increase charging to mitigate transmission constraints or reliability issues. Resources instructed to reduce charging would not be eligible. 

The definition of closed- and open-loop batteries also would be revised to allow resource owners to determine how a storage unit should be classified. For instances where storage is capable of charging from the grid, the resource owner would be permitted to choose whether to offer it as open- or closed-loop, allowing for situations where a battery is physically capable of charging but the owner has determined not to operate it in that fashion. 

PJM Presents Capacity Market Manual Revisions

PJM presented a first read on proposed revisions to Manual 18: PJM Capacity Market to conform with several filings the RTO has made in recent months reworking elements of the market (ER25-682, ER25-785, ER24-2995 and ER25-1357). 

The changes include modeling the expected output of some resources operating on reliability-must-run agreements as capacity; implementing a minimum capacity market clearing price and lowering the price maximum; removing the addback for energy efficiency resources; codifying the BRA schedule; maintaining a CT as the reference resource; and setting an RTO-wide capacity performance penalty rate. The revisions also would remove an exemption from the requirement that resources offer into the capacity market for intermittent, storage and hybrid resources. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

Members Committee

Board to Hold Dialogue with Stakeholders at MC Meetings

PJM Board of Managers Chair David Mills told the Members Committee that attending board members will remain at the Conference and Training Center (CTC) for the full meeting to facilitate a dialogue with stakeholders. That includes a commitment to remain in the region overnight to allow discussions to continue after the MC concludes. Mills was joined by board members Paula Conboy and Vickie VanZandt at the CTC, with other members attending virtually. 

“This is an opportunity for us to hear out one another. And all this is against the backdrop of our responsibility as board members …. to hear what you have to say,” Mills said, adding that listening to stakeholders does not mean the board will take sides on issues or compromise its independence. 

At the Annual Meeting on May 12, Mills broached the idea of adding a standing MC agenda item for the board and stakeholders to bring issues they wish to discuss. Several stakeholders cited lacking transparency and access to the board as their reason for voting against re-electing two board members during the meeting. (See PJM Stakeholders Vote Out 2 Board Members.) 

Much of the discussion during the June 18 meeting centered on the format future discussions should take, with the aim to have them begin in earnest at the July 23 MC meeting. Mills said his vision is for the format to be more informal than that of the Liaison Committee (LC), with conversations rather than prepared speeches. That could take the form of moving to group conversations in the lobby or remaining in the conference room. 

PJM Proposes Revisions to Antitrust Language

PJM Assistant General Counsel Eric Scherling presented updated antitrust guidance for stakeholder meetings intended to bolster the RTO’s recommendations for avoiding conduct that could run afoul of antitrust law. He characterized the guidance as a clarification, rather than a change, in the language. 

The changes affect the antitrust language included in meeting agendas, which are referenced by committee and stakeholder group chairs before meetings begin, as well as guidance on the PJM website. Scherling said the change in guidance is not in response to any particular stakeholder behavior, but rather making improvements that PJM has identified. 

While stakeholders can discuss how trends and forecasts may affect market pricing or costs, disclosure of non-public information, such as bidding practices, could violate federal antitrust statutes. The guidance states that “informal, hypothetical or joking references to these topics should be avoided.” 

Scherling said there are a pair of protected areas where market practices or non-public information could be discussed without violating federal law. The Noerr-Pennington doctrine allows for good-faith advocacy for federal agencies to adopt proposals that may reduce the competitiveness, while Parker immunity allows uncompetitive activity so long as it is authorized by state policy. 

Changes to Liaison Committee Registration Discussed

PJM plans to close registration for future LC meetings a few days in advance to ensure staff have time to validate the credentials of attendees ahead of time, Manager of Stakeholder Process and Engagement Michele Greening said. 

For the July 28 meeting, that means registration will close at 5 p.m. July 24, with no late registrations accepted. 

Constellation Vice President of Wholesale Market Development Adrien Ford said prior to the COVID-19 pandemic, the LC meeting was a great opportunity for members to speak with the PJM Board of Managers about pressing matters and network with other attendees afterward. In-person attendance has not returned to pre-pandemic levels, however, and there have been fewer meetings recently, making the committee a less rich experience. 

PJM CEO Manu Asthana said part of why there have been fewer LC meetings is the board has been meeting more regularly to address pressing issues as they arise. 

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MISO Declares Max Gen Emergency in Heat Wave

MISO Midwest entered emergency status June 23 during the RTO’s first serious heat wave of the summer.

MISO declared a maximum generation event for 4-10 p.m. ET, when it estimated that all available resources would be in use. The Step 1 declaration allows the RTO to commit emergency resources and curtail export schedules.

The grid operator said a combination of wide-ranging heat, higher-than-forecasted load, forced outages and restricted transfer capabilities necessitated escalating its earlier emergency warning to an emergency event.

Based on forecasts made in the morning, MISO foresaw the most pressing problem occurring about 7 p.m. ET, when its approximately 121 GW of available capacity would come a few megawatts shy of its load forecast. By afternoon, however, it no longer predicted a deficit.

MISO also issued a maximum generation warning for June 24.

The RTO originally forecast 122.8 GW of demand for June 23. At 1 p.m. ET, its members were serving almost 114 GW of load at a marginal cost of $324.77/MWh. Indianapolis, Detroit and St. Louis were forecasted to hit 95 degrees Fahrenheit or higher June 23. At midday, solar generation was contributing about 12.5 GW and wind 13 GW.

By 6 p.m., MISO was meeting about 119 GW of demand with the help of 5.2 GW of imports priced at about $139/MWh. By then, it had recalibrated its peak demand forecast down to about 120.7 GW.

MISO has been preparing for a sweltering summer. In an outlook issued in May, it estimated it could see a June peak load of nearly 122 GW in a high-demand scenario but expected the peak more likely would top out at 115 GW. The RTO’s July forecast called for a 122.6 GW peak under normal conditions and a high-demand scenario of 129.3 GW. (See MISO Braces for Hot Summer, Potential 130-GW Peak.)

MISO also initiated a capacity advisory for the South region June 21 due to forced generation outages.