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December 19, 2025

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NEPOOL PC Briefs: June 24-26, 2025

Annual State of the Market

HARWICH, Mass. — Amid extreme temperatures and the highest peak demand experienced in years, ISO-NE and stakeholders discussed market performance, capacity auction reforms, the RTO’s 2026 budget and asset condition spending at the summer meeting of the NEPOOL Participants Committee on June 24-26. 

The three-day meeting at a luxury resort on Cape Cod was preceded by the news that CEO Gordon van Welie, who has led the RTO since 2001, will retire by the end of the year. He will be replaced by COO Vamsi Chadalavada. (See ISO-NE CEO Gordon van Welie Announces Retirement.) 

David Patton of Potomac Economics, ISO-NE’s External Market Monitor, presented his annual assessment of the region’s markets, which found they “performed competitively” but concluded that “key improvements will be increasingly important in the coming years.” 

ISO-NE had the highest overall wholesale market costs of all RTOs in 2024 because of high gas costs, Patton said. New England’s reliance on natural gas generation has increased in recent years; according to ISO-NE data, gas generation hit a record high in 2024, accounting for 51% of net energy for load in the region. (See New England Gas Generation Hit a Record High in 2024.) 

Patton added that New England faced inflated capacity costs because of overforecast demand in its Forward Capacity Auctions, which is “slow to correct in the [Forward Capacity Market].” 

The region also continues to have extremely high transmission rates, which were “more than double the average rates in other RTO markets,” Patton said. He noted that the region’s transmission investments have led to low congestion costs. ISO-NE continued to have the lowest congestion costs of all RTOs in 2024, estimated to be “8 to 17% of other RTOs per megawatt-hours of load,” Patton added. 

However, some stakeholders said this calculation of congestion costs does not appear to fully account for transmission constraints in Maine, which have limited the development of renewables and are the target of the first ISO-NE Longer-Term Transmission Planning solicitation. (See ISO-NE Releases Longer-term Transmission Planning RFP.) 

Patton also expressed concern about a lack of liquidity in ISO-NE’s day-ahead market because of “inefficient allocation of costs to virtual transactions.” 

Patton supports ISO-NE’s ongoing efforts to overhaul its capacity market, which are focused on improving resource accreditation, reducing the time between auctions and capacity commitment periods (CCPs), and splitting CCPs into summer and winter seasons. 

He also called for a reduction in ISO-NE’s Pay-for-Performance (PFP) rate, which he said often overstates the value of reserves and could cause the premature retirement of some fossil units. He said the RTO should align PFP charges with the severity of reserve shortages and charge exporters the PFP rate. 

Reflecting on two capacity deficiency events in the summer of 2024, Patton said “extraordinary prices” caused significant charges imposed on steam turbine and combined cycle plants, “most of which were available but not committed in the day-ahead markets.” 

High PFP charges on resources that were not committed in the day-ahead market could cause “lower net revenues that may lead to premature retirements” and “inefficient incentives to self-commit such resources,” Patton said. 

As states look to transition away from fossil generation, Patton concluded that the region is “well positioned to handle the renewable transition” but recommended that the RTO develop a “a look-ahead dispatch model to address ramp needs and [the] optimization of storage resources.” 

Multiyear Road Map

Chadalavada outlined some “key future focus areas” for the RTO over the next few years, including the development of “forward-looking intraday market-clearing and pricing systems,” intended to help optimize storage deployment and meet increasing ramping requirements. 

“To cost-effectively address operational uncertainties in a dynamic power system, costs will need to be incurred now to position the system with sufficient flexibility later,” Chadalavada said. “This will require new real-time, ‘multi-interval’ optimization and pricing algorithms incorporating probabilistic forecasts.” 

Chadalavada said ISO-NE aims to develop probabilistic forecasts for load and renewable production, which should help the RTO manage increasing uncertainty on the system.  

He said ISO-NE is researching methods for multi-interval pricing and probabilistic forecasting, and said the RTO “may recommend a sequence of phased and interdependent market enhancements over the course of this initiative.” 

Other focus areas Chadalavada highlighted include system planning coordination, modeling of inverter-based resources, resource adequacy and cybersecurity.  

2026 Budget

ISO-NE outlined its initial 2026 budget proposal: a revenue requirement of $315.2 million, which would be a $4 million increase over the 2025 requirement. 

This includes a $15.6 million reduction associated with the annual revenue true-up. Without the true-up, the 2026 budget is 1.8% lower than ISO-NE initially projected in 2024. 

“The budget for 2026 represents the ISO’s commitment to supporting the region as it continues to experience an evolving resource mix and changing customer use patterns, ensuring that markets and grid operations are efficient and reliable,” said Kelly Reyngold, director of accounting. 

Notably, the budget “includes ‘placeholder’ funding for asset-condition review work that will only be used for this purpose and, if not needed, will not be reallocated for use elsewhere.” 

Earlier in 2025, ISO-NE announced that it is open to taking on a nonregulatory role in reviewing asset-condition spending, responding to state and consumer advocacy concerns about a lack of transparency and oversight on the projects. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) 

Chadalavada said it likely will take about 18 months to develop in-house asset-condition review capabilities but that ISO-NE hopes to hire a consultant to help review the most important projects in the interim period. He said the RTO is working with transmission owners to establish the criteria for reviewing projects in this interim period and eventually will include all stakeholders in these discussions. 

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PJM Exceeds Forecast Summer Peak Load During June Heat Wave

PJM experienced a preliminary peak load over 160 GW on the afternoon of June 23, surpassing the RTO’s summer forecast of 154 GW and requiring the deployment of pre-emergency demand response. (See PJM Summer Forecast Reports Sufficient Supply.) 

The heat wave blanketing much of the region brought temperatures of around 100 degrees Fahrenheit, leading to an RTO-wide hot weather alert being issued between June 22 and 25, which was extended to include the 26th as well. Several pre-emergency load management reduction actions were taken June 24 across the RTO, while DR also was called for the Mid-Atlantic and Dominion regions June 23 and 25. 

Two maximum generation/load management alerts were issued on June 24 and 25, a notification instructing resource owners to be prepared to operate above their economic parameters if emergency actions are taken. The alerts also put PJM into NERC’s Energy Emergency Alert (EEA) 1 status for their duration. 

PJM spokesperson Daniel Lockwood said the June 23 and 24 peaks are the highest PJM has seen since 2011 and both place in the top five for all-time peak demand. 

PJM also reported that it has dispatched Eddystone Units 3 and 4 throughout the heat wave. The generator is being operated past its requested deactivation date of May 31 under a Department of Energy emergency order expiring Aug. 28. Eddystone Unit 3 ran for 16 hours on June 23 and all day on the 24th, while Unit 4 operated 14 hours on the 23rd and 20 hours the following day. Both units ran all day on June 25. (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online.) 

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CAISO Opens Bidding Process for $900M in Transmission Projects

CAISO is soliciting bids for two transmission projects in the San Francisco Bay Area to prepare the state for more data center load anticipated in the coming decade.  

The projects are part of CAISO’s approved 2024/25 transmission plan, which includes 31 projects. Two of these projects are eligible for a competitive solicitation process — the 230-kV San Jose B-Northern Receiving Station (NRS) line and the 500-kV Metcalf-Manning line — CAISO said at a June 25 transmission planning workshop.  

The Metcalf substation, located in the South Bay Area, is one of the primary supply sources of energy for the San Francisco Bay Area. Load in the area is projected to increase 2.5 GW between 2026 and 2039 — or about 40% of the total load growth over those years. Most of the load growth will be from data centers, CAISO said.  

The Metcalf project includes about 100 miles of new 500-kV AC transmission line between the 500-kV Manning and Metcalf substations. The expected cost of the project is $500 million to $700 million, with a required completion date of June 1, 2034. The project is critical for maintaining reliability in a “major portion of the ISO-controlled grid,” CAISO said in the meeting. 

In the 2024/25 transmission plan, CAISO completed a study of constraints that might have a large impact on the bulk system or the heavily congested areas. The study found that minor congestion was observed on the recommended 500-kV Manning-Metcalf line, which indicates the high use of the 500-kV upgrade, CAISO said. 

The second project — the San Jose B project — is a new, 7-mile transmission line expected to cost $150 million to $200 million, with a planned in-service date of June 1, 2030. 

In less than three years, the load forecast in the San Jose area increased from 2,100 MW in the 2021/22 transmission plan to between 3,400 and 4,200 MW in the 2024/25 transmission plan. The San Jose B project will provide the extra energy. The project also will support two previously approved transmission projects in the area, which have designs that no longer are sufficient because of the increased load forecast. In the future, the San Jose B project will connect to a 115-kV load interconnection switching station owned by Pacific Gas and Electric. 

For this cycle’s bid process, CAISO revised certain parts of its application, including changes to its cost and cost-containment workbook and its project sponsor requirements. If only a single project sponsor is qualified for a project, that sponsor is automatically selected, CAISO said. 

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PJM Board Selects Cost Allocation for Eddystone

The PJM Board of Managers is pursuing an approach that would spread the cost of continuing to operate Constellation Energy’s Eddystone Generating Station to all PJM consumers. (See PJM Stakeholders Propose Cost Allocation Models for DOE Emergency Orders.) 

In a June 26 letter to stakeholders, Chair David Mills said the board selected a proposal sponsored by Gabel Associates through the Critical Issue Fast Path (CIFP) process initiated to determine how Constellation should be paid for keeping Eddystone online under a Department of Energy emergency order. 

Mills noted that the package was the only one to receive a supermajority of sector-weighted support during a June 18 Members Committee (MC) meeting. The board has directed PJM staff to file the proposal at FERC by the end of June. 

Gabel’s proposal was set apart from five other packages sponsored by PJM and the East Kentucky Power Cooperative (EKPC) by its RTO-wide allocation and focus on the current DOE order. Some of the alternatives contemplated how PJM should proceed if more generators are ordered to remain online by the federal government. The cost allocation would expire Aug. 28 along with the conclusion of the emergency order. 

The proposal would determine the charges for each entity by multiplying its share of the RTO monthly unforced capacity (UCAP) obligation by the monthly credit paid to Constellation. The costs to be included in that credit are subject to review by the Independent Market Monitor (IMM). 

A new line item will be included on billing statements showing the cost of that credit, and PJM will post information on its website about the credits and guidance on how they are settled. The proposal carries a June 1 implementation date to capture costs Constellation may have incurred since the DOE order took effect.  

During the MC meeting, Constellation Vice President of Wholesale Market Development Adrien Ford said the company did not vote for the proposal out of concern it would allow cost allocation to lapse if DOE issues subsequent orders to keep Eddystone operational. Some speakers encouraged the board to modify the Gabel proposal to apply to either additional orders on Eddystone or orders that may be announced in coming weeks. 

Carl Johnson, representing the PJM Public Power Coalition, said some of the proposal’s support came from a belief that more orders should be addressed as they arise. 

Mills wrote that the board deliberated on modifying the proposal but opted against making any changes due to mixed feedback it received. He also noted that the Markets and Reliability Committee endorsed a PJM issue charge to consider a long-term cost allocation framework for deactivations delayed under the Federal Power Act (FPA) Section 202(c) orders. 

“Recognizing there may be further DOE 202(c) orders related to generating units in the PJM region in the foreseeable future, the board is encouraged by the fact that the stakeholders have endorsed an issue charge to work on a cost allocation methodology for future DOE 202(c) orders that may require resources to remain operationally available beyond previously anticipated deactivation dates. PJM will announce the commencement of that stakeholder discussion in the near term,” he wrote. 

PJM reported that it has dispatched Eddystone during a heat wave affecting the PJM region on June 23, 24 and 25. Unit 3 ran for 16 hours on June 23 and all day on the 24th, while Unit 4 operated 14 hours on the 23rd and 20 hours the following day. Both units ran all day on June 25. 

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Expert Says Spain Blackout Unlikely in U.S.

Six weeks after a mass outage that stopped electricity for nearly the entire population of Spain and Portugal, along with parts of France, the Spanish government and grid operator Red Electrica have released separate reports detailing the cause of the event and recommendations for future preventive measures.

The outage lasted 18 hours, starting on the afternoon of April 28. In the immediate aftermath of the event, many asked what could have caused such a sudden loss of power. Some speculated that a cyberattack was to blame, while others suggested the disaster occurred because of the high proportion of renewable energy on Spain’s grid at the time, leaving insufficient traditional synchronous generation to provide voltage control. (See NERC Offered to Help with Iberia Outage Investigation, Robb Says.)

Speaking with ERO Insider, Michael Goggin, vice president of Grid Strategies, noted the reports — whose authors he said “did a really good job with the data they [had] available” while producing “solid engineering analysis” — largely laid such ideas to rest. According to Goggin’s analysis of both reports, the blackouts occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from the grid operator’s efforts to control frequency oscillations that were exacerbated by a faulty power plant controller.

At the time of the blackout, 11 thermal generation plants were available for voltage control — four nuclear, one coal-fired and six natural gas-fired — along with an unspecified amount of “hydraulic generation,” as noted in the government report. The plants had trouble managing the grid’s voltage, which experienced swings of about 10% in the hours leading up to the blackout. Some of the worst voltage control performance was at a thermal plant in southern Spain.

To combat the fluctuating voltage, Red Electrica reversed a switch for static reactive devices, which reduced system voltage but left the operator with less flexibility because of the stepwise “all-or-nothing” nature of the devices. The grid operator also ordered two gas combined cycle plants to start up in hopes of dynamically managing voltage; however, the start-up process would have required 1.5 hours at one plant and at least two hours at another. The process was interrupted by the beginning of the blackout 10 minutes later.

Renewables out of Voltage Control Picture

One surprising item in the reports, Goggin said, was the fact that Spain’s electricity regulations do not allow renewable energy resources and battery energy storage systems to provide voltage control. Currently only synchronous generators can provide this function in Spain.

“That was kind of amazing,” Goggin said. “I wasn’t aware that, given the amount of renewables that Spain has, and particularly on this day [when] two-thirds of generation was wind and solar … they’re still not letting those resources regulate voltage. They’re basically keeping the thermal resources online purely to regulate voltage.

“It’s very inefficient,” he continued. “You’re having to pay these … thermal plants to run even though … the generation is not needed or economic.”

Goggin noted in his analysis that battery resources “can start up and begin controlling voltage or frequency almost instantly. Moreover, many modern [inverter-based resources] can be configured so that their power electronics can regulate voltage without even generating real power.”

He further observed that FERC Order 2023’s “strict generator ride-through requirements … ensure IBRs remain online for voltage disturbances of this magnitude in the U.S.”

Goggin also pointed out NERC reliability standard PRC-024-3 (Frequency and voltage protection settings for generating resources) forbids generator protective relays from tripping any type of generator for voltages 10% above normal, while PRC-029-1 (Frequency and voltage ride-through requirements for IBRs), currently awaiting FERC approval, requires IBRs to remain online indefinitely for voltages up to 10% above normal and for one second for voltages 10 to 20% above normal.

These measures are one reason this type of event is unlikely to occur in the U.S., he said. Another is the absence in the U.S. of what the Spanish government referred to as a “Christmas tree” arrangement, in which multiple unaffiliated generators are connected to the grid via a single transformer. This type of setup is common in Spain “for economic and environmental efficiency … and to minimize impact and costs,” but the disconnection of one such transformer caused a significant loss of generation, causing a chain reaction that ultimately led to the blackout.

Goggin said he believed the government and Red Electrica reports will not be the final word on the Iberian outages, particularly in the U.S., where NERC Chief Engineer Mark Lauby is scheduled to present the ERO’s findings on the event at FERC’s open meeting June 26.

The report’s recommendations included several ideas that U.S. regulators may consider. One of these is to retool how generators are compensated for providing reactive power services to counteract voltage fluctuations through a market approach. Another is to examine the role that transmission expansion can play in helping to maintain reliability.

“I think [we] can be doing better at both of those. … The reactive compensation doesn’t really exist here. It’s … something [utilities are] supposed to provide, but if you don’t pay people to provide it, they’re not going to do a very good job of it,” Goggin said.

“Also, as we expand interregional transmission, most of the focus has been on localized shortfalls of generation. But there’s a similar story on the voltage-control capabilities with HVDC lines and how to use that to improve stability,” he added. “I think we can learn the value of those things for preventing a whole host of reliability concerns, including the ones that were the problem here.”

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Constellation Moves Reactor Restart Target Forward to 2027

Constellation Energy said the former Three Mile Island could come back online as the Crane Clean Energy Center a year earlier than initially expected.

PJM approved an early interconnection request, hiring and training are going well, and significant progress has been made on major equipment purchases, the company said June 25 during a celebratory event at the southeast Pennsylvania facility.

When Constellation went public with its plans in September 2024, it targeted a 2028 restart. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

The company now says the facility could come online as soon as 2027.

Crane is roughly two-thirds staffed, with nearly 400 full-time employees hired and 58 more scheduled to start soon. Technical milestones include the successful inspection of the main generator and turbines and other major systems. The new main power transformers are scheduled to be delivered in 2026.

Importantly, the facility was among those fast-tracked in May through PJM’s Reliability Resource Initiative. (See PJM Selects 51 Projects for Expedited Interconnection Studies.)

Constellation CEO Joe Dominguez spoke of the confluence of factors working in favor of the project: PJM’s actions; financial support from Microsoft, which will buy 835 MW of output for its data centers; community backing; and support from Pennsylvania Gov. Josh Shapiro (D), who also spoke at the ceremony.

PJM President Manu Asthana told the crowd about the project’s importance to the region, the nation and the grid, which is wrestling with resource adequacy.

“I’m here to say ‘thank you’ for that,” he said. “PJM understands the importance of bringing this project and other projects like it online quickly, and our engineers are back in the office, working as hard as possible to accelerate that.”

The heat wave did not pause for the ceremony: The temperatures climbed into the 90s under blazing sun at the Crane Clean Energy Center, and public demand for electricity rose with the heat.

Asthana said two days earlier, the PJM control room observed an all-time high peak, 9 GW higher than last summer’s peak.

“Now let me put that in context,” he said. “That is 11 Crane Clean Energy Centers from last year’s peak to this year’s peak. What we’re talking about here is not hypothetical. Our country needs this power.”

Dominguez marveled at the turn of history at one of the best-known nuclear facilities in the world.

“Boy, what an incredible, incredible moment,” he said. “The comeback of this plant, the comeback of the industry. It’s just kind of amazing.”

The partial meltdown of Three Mile Island Unit 2 in 1979 energized popular opposition to commercial nuclear power. Unit 1 was undamaged and came back online several years later, but Constellation’s corporate predecessor, Exelon, shut it down in September 2019 due to uneconomical market and policy conditions. Other reactors nationwide were retired for the same reasons.

Just a few years later, nuclear power is poised for a renaissance, with politicians and industry willing to help subsidize nuclear generation in return for its steady, emissions-free output. Plenty of critics remain, but even some former opponents of nuclear power now offer support.

Unit 1 is among the oldest reactors in the aging U.S. fleet, first licensed in 1974. But the anticipated $1.6 billion cost of the restart project would be a small fraction of the cost of building a comparable facility.

The easiest step forward into Three Mile Island’s next chapter also was the most literal: Constellation renamed it after the late Chris Crane, Exelon’s CEO from 2012 to 2022.

The Nuclear Regulatory Commission approved the change in May.

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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.