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December 16, 2025

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NRECA Legislative Fly-in Focuses on Permitting, Meeting Demand

The National Rural Electric Cooperative Association (NRECA) has flown 2,000 member representatives to D.C. to lobby congressional leaders on key issues for the nation’s co-ops, which this year include passage of permitting legislation and meeting rising energy demand.  

“Our desire, as electric co-ops, is to make sure we have smart energy policies that help us meet this challenge, because it’s a good challenge to me,” NRECA CEO Jim Matheson said on a call with reporters kicking off the April 28-30 Legislative Conference. “I mean, growing electric demand is good news for our country. It shows our economy is growing, and that’s what we want.” 

One of NRECA’s key priorities is to get some changes to federal permitting passed, after a bipartisan effort to do so fell short in the last Congress. (See Lame Duck Permitting Push Fails; Manchin Blames House GOP Leaders.) 

“I think there continues to be an understanding across a large segment of Congress, in a bipartisan way, that our permitting process is not functioning in the most efficient way, and so that’s good,” Matheson said. “On the other hand, we all know that [there’s a] small margin in Congress and getting any type of legislation through can be a challenge.” 

One way the Republican majority is considering to get around the narrow margin is “reconciliation,” since it avoids the Senate filibuster, but it can be used only to pass laws related to funding the government (Democrats used it to pass the Inflation Reduction Act in 2022).  

With so many laws implicated in federal permitting, Matheson said the issue ultimately will require a “multifactor effort from a legislative standpoint” to enact all the needed changes. 

NRECA supports some of President Donald Trump’s regulatory rollbacks at EPA because they will keep needed power plants running in a time of demand growth. But the administration’s trade policies are presenting problems for that effort. 

“The supply chain that serves the electricity sector in this country is a global supply chain. That’s a fact,” Matheson said. “And, so, the answer is, to the extent that the supply chain is disrupted or has additional costs associated with it based on tariffs, yes, that is going to have an impact on the electric sector in general, and on electric co-ops in particular.” 

The tariffs have proved to be moving targets, with President Trump often lowering or delaying them, but any disruptions or higher costs for needed equipment ultimately is going to impact the rural consumers NRECA members serve, he added. 

The industry still is dealing with supply chain disruptions from the COVID-19 pandemic, and now any policy uncertainty is exacerbating the issue, said Keith Brooks, general manager of Douglas Electric Cooperative in Roseburg, Ore. 

“We adjusted our inventory practices during COVID,” Brooks said on the press call. “We’re probably carrying twice as much inventory as we had in the past, just to ride out some of these supply chain ups and downs. But, you know, anything that makes the situation worse is a little scary for us.” 

The tariffs have not been in place long enough to have had a major impact on the power industry’s supply chains yet, he added. 

“We continue to be in a wait-and-see mode for any actual dollar impact to our members that will be the result of any tariffs that come through,” said Annalisa Bloodworth, CEO of Oglethorpe Power, a 38-member co-op in Georgia. “We are starting to receive, from vendors across our supply chain, notices and alerts that their expectations are of increased costs and potential disruption.” 

That comes on top of a supply chain that is under much pressure, not only from the supply side, but from the growing demand for power in the U.S. and around the world, Bloodworth added. 

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Growth of BTM Solar Drives Record-low Demand in ISO-NE

ISO-NE experienced record-low demand on Easter Sunday because of mild temperatures and high behind-the-meter solar output, making 2025 the fourth consecutive year the RTO has set a low-load record.

The 5,318-MW minimum load April 20 was a significant drop from the previous record low of 6,596 MW, set in April 2024. ISO-NE estimates that BTM solar production reduced systemwide demand by about 6,600 MW.

Steven Gould, director of operations at ISO-NE, said the RTO anticipated the low-load conditions days in advance and was able to forecast the minimum load with great accuracy.

“It was a very quiet day because we prepared and we communicated,” Gould said. He added that the impact of declining minimum loads is “something that we are continuously looking at. We’re fine now, but we want to be proactive, and that’s what we’re doing.”

The region’s solar boom has led to an increasing amount of duck curve days, which are defined as days when daytime demand drops below nighttime demand. In 2024, New England experienced 100 duck curve days for the first time in its history.

Steven Gould, ISO-NE | ISO-NE

Largely driven by state policy, the region recently has added about 700 MW of BTM solar capacity per year, Gould said. Solar growth has been strongest in Massachusetts and Connecticut, which are home to about two-thirds of the BTM solar generation in the region.

Gould said the “biggest concern at light loads” is the creation of high-voltage conditions on the transmission system. He said ISO-NE coordinates with the region’s transmission owners ahead of forecasted light-load periods to ensure the system has resources available to reduce the voltage on the system.

Light-load conditions also create the need for significant ramping capabilities as solar production wanes in the evening. On April 20, natural gas generation dropped from over 4,700 MW in the early morning to about 1,800 MW between 10 a.m. and 3 p.m., before increasing in the evening to over 5,000 MW as the systemwide peak grew to about 11,800 MW.

“We have the resources to [ramp back up] at this point in time, and we’re able to do it quite easily,” Gould said.

Power system emissions, which largely are driven by natural gas generation, especially during warmer months, were cut roughly in half during this midday period, before increasing again in the evening.

Nuclear generation, which lacks the ability to quickly increase or decrease production, remained steady at 2,115 MW throughout the day. In the future, Gould said he does not expect low loads to create operational issues for nuclear resources because the region can export power to neighboring regions during extreme low-load conditions.

On April 20, ISO-NE went from importing about 1,500 MW in the morning to exporting power midday to NYISO as New England’s real-time hub LMP dropped to as low as ‑$31.7/MWh. Imports climbed back to about 1,000 MW in the evening.

Looking forward, Gould said he expects the growth of transportation electrification and electric storage to eventually drive up midday demand, helping to mitigate potential low-load concerns.

“We think battery storage and electric transportation and heat pumps will be able to curb the light load, because that will be the lowest energy price for those resources to charge their systems,” Gould said. “If you look at Texas and California, they’re very much ahead of us for battery storage, but that’s what they’re doing.”

Over the next decade, ISO-NE anticipates BTM solar production to nearly double, growing at a rate of about 570 GWh per year. ISO-NE expects this growth to push the system peak load later in the day but does not expect it to have a major impact on peak loads levels. By 2034, ISO-NE expects BTM solar growth to reduce the summer peak by an additional 140 MW and the winter peak by about 400 MW.

However, Gould emphasized the difficulty of forecasting system conditions years in advance, “especially when you go from one [federal] administration to a new administration,” pointing to the struggles and uncertainties surrounding offshore wind development.

“Things are dynamically changing,” Gould said. “We’re doing lots of studies. … We’re taking about light loads; we’re looking at ramping; we’re looking at intermittent resources; we’re looking at forecasting irradiance; we’re looking at forecasting wind and forecasting demographic behavior, and putting it all together to make sure we have adequate resources in our market on a daily basis.”

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ISO-NE’s Final 10-year Demand Forecast Tapers Expectations

ISO-NE has significantly lowered the peak load and net energy estimates in its final 2025 10-year load forecast but still predicts the region’s peak demand will grow by over 2 GW by 2034, the RTO told its Planning Advisory Committee on April 29.  

The reduced demand growth expectations are driven largely by reductions in ISO-NE’s adoption forecasts for heating and transportation electrification. The RTO cut its electrification forecasts in response to data indicating its previous forecasts significantly overestimated the adoption of electric vehicles and heat pumps. (See ISO-NE Scales Back Vehicle, Heating Electrification Forecasts.)  

The final forecast predicts the RTO’s summer peak for an average year will grow from 24,803 MW in 2025 to 26,897 MW in 2034. It expects the winter peak to grow more rapidly — from 20,056 MW in 2025 to 26,020 MW in 2034. Compared with the 2024 10-year forecast, ISO-NE reduced its 2033 summer peak projection by 2.1% and its winter peak projection by 7.1%. 

The RTO expects the winter peak to surpass the summer peak at some point in the 2030s due to heating electrification. The model predicts that average winter and summer peaks will be about equal by 2035, though the winter peak could pass the summer peak earlier under more severe winter weather conditions.  

The projections also reflect major changes to ISO-NE’s base modeling methodology, including the incorporation of hourly data, additional weather scenarios and climate change effects. (See ISO-NE Cuts Winter, Summer Peak Load Forecasts for 2033.)  

Hourly modeling allows ISO-NE to evaluate “a wider variety of system conditions, not just peak loads,” and capture peak loads that occur any time of day, not just in the evening, said Victoria Rojo, supervisor of load forecasting at ISO-NE. Rojo said ISO-NE expects morning winter peaks to become more common as load from heating electrification increases. 

Based on an evaluation using the updated hourly forecasting, Pradip Vijayan, manager of transmission planning at ISO-NE, said the RTO plans to simplify its transmission planning studies to focus on just two scenarios: a midday peak high renewable scenario and an evening peak scenario.  

“For transmission planning high net summer peak load analysis, the ISO proposes modeling 95% of the coincident gross peak load with 0% PV,” Vijayan said, noting that, as the net summer peak load moves to later in the evening in the coming years due to rooftop solar, “this load level should cover both the coincident net peak load conditions in New England and non-coincident net peak loads for most load zones.” 

For the winter, he said ISO-NE plans to continue modeling the peak as “100% of the gross New England winter peak with 0% PV,” noting the “significant variance in PV availability on high winter load days.” 

Updated Interface Limits

Also speaking at the PAC meeting, Alex Rost, ISO-NE’s director of transmission services, said the RTO will increase the Surowiec-South and the Maine-New Hampshire interface transfer limits to 2,200 MW because of network upgrades associated with the New England Clean Energy Connect (NECEC) transmission line. The Surowiec-South limit in Maine now is set at 1,800 MW, while the Maine-New Hampshire limit now is 2,000 MW.  

Rost said the increase of the Surowiec-South interface will allow for the increase in the capacity import capability of the New Brunswick-New England interface from 980 MW to 1,000 MW.  

The updated interface limits will be used in forward capacity market analyses, beginning with the overlapping interconnection impacts analysis for the 2025 interim reconfiguration auction qualification process, which will “determine whether there is sufficient capacity capability to qualify any proposed new capacity resources,” Rost said.

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ERCOT’s TAC Endorses Congestion Management Plan

ERCOT stakeholders have endorsed a protocol change (NPRR1229) that creates a process to compensate market participants when a constrained management plan or ERCOT-directed switching instruction trips a generator that otherwise would have stayed online.

The revision request passed over objections from consumer groups during the Technical Advisory Committee’s April 23 meeting. They said the NPRR shifts costs and deviates from previous market rules for the direct assignment of congestion costs.

“The whole point is that parties are supposed to deal with the direct assignment of congestion costs,” said Lyondell Chemical’s Eric Schubert, one of the Consumer segment’s six members who all voted against the measure. “In other words, you’re supposed to have a backstop in case something comes up online, the generator trips. … It seems to us that this is a problematic NPRR and continues down the path of socializing costs that should be directly assigned.”

The Lower Colorado River Authority’s Blake Holt said the need for compensation will be “extremely rare.”

“When a resource is instructed to operate in a risky condition to benefit the grid reliably and is subsequently tripped offline, we believe it is reasonable to cover the cost of the trip,” he said. “There’s going to be lots of rigor in approving a dispute.”

The proposed change passed 20-8, with one abstention. Electric retailers Rhythm Ops and Demand Control 2 joined the Consumer segment in voting against the measure.

TAC also discussed NPRR1275 but took no action on it. The protocol change, tabled at the Protocol Revision Subcommittee, would expand the qualifying pipeline definition for firm fuel supply service (FFSS) by including contractual natural gas storage in addition to on-site fuel storage.

FFSS was created by the Texas Legislature in 2021 after Winter Storm Uri nearly brought the ERCOT grid to its knees. Renewable resources took much of the blame in Texas, but FERC and NERC found the greatest share of fuel outages during the storm occurred among natural gas facilities. (See FERC, NERC Release Final Texas Storm Report.)

The Public Utility Commission also has a docket (56000) on FFSS. The commission agreed with staff’s recommendation during its April 24 open meeting to delay FFSS’ first procurement until the 2026/27 winter season.

Large Load Working Group OK’d

TAC agreed to sunset the Large Flexible Load Task Force and approved a charter that transitions the body into the Large Load Working Group, reporting to the committee. Members placed the motion on TAC’s combination ballot, which passes for its consent agenda.

The task force’s leadership asked for the changes during the committee’s March meeting. The working group will be responsible for developing and recommending policies to facilitate the “reliable and efficient integration” of large loads into the ERCOT system. (See “Large Load Task Force to Remove ‘Flexible,’” ERCOT Technical Advisory Committee Briefs: March 26, 2025.)

“There’s enough activity going on with all the large loads that we don’t see an end to the task force. There’s a lot of activities that will probably be operations focused,” said ERCOT’s Bill Blevins, who chaired the task force.

Blevins said the group will return to TAC’s May meeting with nominations for its leadership.

The working group is open to ERCOT stakeholders and representatives from the Public Utility Commission, the Independent Market Monitor, the Office of Public Utility Counsel and the grid operator’s staff. It will address interconnection study processes and modeling requirements for large loads (75 MW and above) along with standalone considerations and issues related to co-locating the loads with on-site generation or other resources.

Staff told members that new standalone and co-located projects, as well as several project cancellations, resulted in a net increase of more than 25 GW in the large-load queue, as of March. The queue contains more than 136 GW of study requests, but a little more than 4.5 GW have been energized since 2022.

TAC Endorses $119M Oncor Project

TAC members endorsed a $119 million, 138-kV project in West Texas by placing it on the combo ballot. The Oncor project entails upgrading a 29-mile transmission line and updating other facilities and infrastructure to address reliability issues.

ERCOT’s Regional Planning Group selected the project’s route from among two other alternatives. One option came in at $247 million and the other at $81 million. With the cost exceeding $1 million, the grid operator’s staff must bring the project to the Board of Directors for final approval.

Oncor expects to finish the project by December. As an upgrade, it does not require a certificate of convenience and necessity.

The combo ballot also included the approval of strategic objectives for TAC’s Protocol Revision and Reliability and Operations subcommittees, and an NPRR and a system change request (SCR) that, pending board approval, would:

    • NPRR1271: allow Mexico’s state-owned electric utility, Comision Federal de Electricidad (CFE), to opt out of a requirement to designate a user security administrator and receive digital certificates. CFE is registered with ERCOT as a transmission and/or distribution service provider, a load-serving entity and a resource entity.
    • SCR830: implement a machine-to-machine client credentials authentication flow using OAuth 2.0, allowing for certain read-only endpoints of the GINR Rest Application Programming Interface to be exposed for authorized use.
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PJM MRC/MC Briefs: April 23, 2025

Markets and Reliability Committee

Stakeholders Endorse Changes to Black Start Compensation

The PJM Markets and Reliability Committee endorsed a proposal to rework how resources are compensated for providing black start service the RTO says will provide more predictable revenues for participating market sellers. 

The change was passed with 80% sector-weighted support at the MRC and was endorsed by the Members Committee as part of its April 23 consent agenda.  

The package of changes replaces the zonal net cost of new entry in the base formula rate (BFR) equation — used to determine compensation for most black start resources — with a five-year average of the RTO-wide net CONE. The averaged value will be used for the 2025/26 delivery year and adjusted according to the Handy-Whitman index every year thereafter, with the results to be posted by March 31.  

PJM’s Glen Boyle said the RTO’s goal was not to increase or decrease compensation relative to past years but to keep revenues static to avoid having resources exit the market. When PJM seeks additional black start capability through requests for proposals (RFP), he said the new resources tend to require upgrades to make them capable of providing the service, which results in them being compensated through the capital recovery factor (CRF). That carries potential for significantly higher costs than maintaining resources being compensated through the BFR. 

During the first read of the proposal in March, Boyle said 29 resources have stopped providing black start service since 2019, 26 of which were replaced through RFP. All but two of the new resources required upgrades and initially were compensated through the CRF. (See “PJM Presents 1st Read of Proposal to Rework Black Start Compensation,” PJM MRC/MC Briefs: March 19, 2025.) 

Independent Market Monitor Joe Bowring said PJM should consider carefully whether black start resources are being fairly compensated rather than seek what he called an arbitrary change to the formula. In past meetings, he noted that PJM first broached the subject after it determined the scheduled shift to a combined cycle reference resource would cause the net CONE to fall significantly. PJM since has received FERC approval to continue using a combustion turbine as the reference resource. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

The primary purpose of the reference resource is to select the model resource on which capacity market parameters are based — a structure Boyle said PJM does not believe has any relevance to black start compensation. He said the proposal will break the connection between net CONE and black start. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he agrees with the aims of seeking more transparency and consistency in black start rates, but many advocates are concerned that disentangling net CONE and black start by using the five-year average does not advance those goals. 

“Is there a better way to do this? Make sure it’s fair, and develop a basis to make it fair,” he said. 

PJM Presents Proposal to Add Transparency to ELCC

PJM presented a proposal aiming to provide more transparency in how it determines effective load-carrying capability (ELCC) class ratings and how those values translate in resource accreditation in the capacity market.  

The package received unanimous support from the ELCC Senior Task Force in a March poll. 

It would require PJM to publish an annual report detailing the class ratings development process, the assumptions guiding the process and an explanation of the results. It also would include an analysis of sensitivities PJM deems relevant. A nonbinding schedule also would be developed to show how the accreditation inputs for each auction are used, including dates for releasing class average and unit-specific performance adjustments. 

PJM also would hold stakeholder meetings prior to developing the study to review the assumptions it’s considering using and discuss how changes in the data driving ELCC may affect the outcomes. Similar sessions would be held after the publication to review the results. 

The package also would require PJM to share unit-specific performance data going back to June 2012 with respective generation owners through its Generator Availability Data System. 

The proposal would revise Manual 18: Capacity Market, Manual 20A: Resource Adequacy Analysis and Manual 33: Administrative Services for the PJM Interconnection Operating Agreement. An endorsement vote is planned for the MRC’s meeting May 21. 

Transparency is one of several charges the ELCCSTF was given when it was formed in late 2024, along with the inputs and process PJM uses to determine ELCC values and how investments a generation owner makes in their units can lead to increased accreditation. It also is considering how the shift toward winter risk under the expected unserved energy approach to modeling reliability risks in the ELCC paradigm interacts with the focus on summer peak loads when determining zonal capacity emergency transfer limits. 

First Reads on Manual Revisions

PJM’s Ryan Nice presented a first read on revisions to Manual 1: Control Center and Data Exchange Requirements that includes adding new data requests to the Generation Scheduling Service table. 

The revisions would add the Cold Weather Checklist and Generation Periodic data from the Dispatcher Application and Reporting Tool to the table. They also would align the manual with NERC Standards IRO-010 and TOP-003, both of which are effective July 1 and include a recommendation that changes to transmission owners’ backup functionality operating plans be certified with PJM by Dec. 31, rather than within 60 days. 

PJM’s Suzanne Coyne presented a slate of manual revisions to conform to FERC’s approval of the RTO’s rules for determining clearing prices during a market suspension (ER23-1431). (See “First Reads on Manual Revisions,” PJM MIC Briefs: April 2, 2025.) 

The changes to Manuals 6, 11, 28 and 29 would establish three sets of rules for determining prices based on whether a suspension lasts less than six hours, between six and 24 or longer. Shorter suspensions would use the average real-time prices for each hour prior to and following the outage. For moderate-duration events, day-ahead prices would be used if available; otherwise, real-time prices would be used. For suspensions exceeding a day, an aggregate supply curve would be developed. 

If endorsed by the Market Implementation Committee on May 7, the manual language would be voted on by the MRC on May 21. 

Members Committee

Stakeholders Discuss Posting Board Election Tallies

The Members Committee discussed whether it would be appropriate for PJM to publish the threshold by which candidates for the RTO’s Board of Managers were elected or rejected. Currently PJM states only if a candidate was elected, not exactly how the vote went. 

The subject was raised by Carl Johnson, representing the PJM Public Power Coalition, who said there’s interest in having more public information about board elections given members’ dissatisfaction with decisions the board made on revisions to the Consolidated Transmission Owners Agreement (CTOA) in 2024. The MC rejected endorsement of the proposal to shift filing rights over the Regional Transmission Expansion Plan (RTEP) from membership to the board, after which the board opted to file the changes with the commission later in 2024. FERC ended up rejecting the revisions. (See FERC Rejects PJM and Transmission Owners’ CTOA Proposals.) 

Representing two members of the Other Supplier sector, Bruce Bleiweis, principal of BN Energy Advisor, said transparency is a core pillar of PJM’s responsibilities and having more information about the board vote would support that. 

PJM CEO Manu Asthana said he does not see any reason why the tallies could not be published. The vote is conducted by a third party to ensure the RTO cannot see how individual members voted, and the sector-weighted results are conveyed to staff. Past practice has been that sector-weighted information is not shared with the public or the board. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he’s concerned that releasing information about how each sector voted could put targets on sectors’ backs when elections may be contentious. 

Exelon Director of RTO Relations Alex Stern said he does not want board members or PJM to ever see members’ votes, but it does make sense to have more transparency around board elections. 

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Feds Charge Man with Wash. Substation Attacks

The U.S. Department of Justice has charged a Washington man with damaging five electric substations and attempting to damage another in the state in 2022, according to an indictment unsealed recently by the U.S. District Court for the Western District of Washington.

A federal grand jury on April 9 indicted Zachary Rosenthal, a former resident of Tacoma, Wash., with five counts of destruction of an energy facility, one count of attempted destruction and one count of conspiring to damage energy facilities, the U.S. Attorney’s Office said in a press release. DOJ said Rosenthal was assisted by “others known and unknown” in the attacks.

Rosenthal already had been charged with three counts of damaging an energy facility in Portland, Ore., in November 2022, along with alleged accomplice Nathaniel Adam Cheney of Centralia, Wash. Both men have pleaded not guilty, and the Oregon case is set to go to trial Nov. 3, DOJ’s release said. Rosenthal currently is serving a seven-year sentence in Washington for vehicular assault.

The indictment accused Rosenthal and his co-conspirators of damaging the Toledo, Woodland 1, Woodland 2, Puyallup and Tumwater substations, and attempting to damage the Oakville substation. Attackers used a variety of means to damage the facilities, including firearms, smashing equipment and causing short circuits with heavy chains, DOJ said.

Most of the attacks occurred in November 2022; the Toledo substation attack happened Aug. 5, and the attempt to damage the Oakville substation occurred Dec. 5.

Investigators said the Washington attacks were part of a plan to shut down power to businesses and ATMs in the area to disable alarms and make them easier to rob. Each event, except for the Oakville attack, caused power outages that affected between 1,000 and 6,000 customers, according to DOJ.

Each count of destruction of an energy facility and causing more than $100,000 in damages carries a penalty of up to 20 years in prison and three years’ supervised release. If the damage is between $5,000 and $100,000, the maximum prison time is five years.

The alleged burglary motive is reminiscent of a similar incident that occurred in Washington in December 2022, when two men caused millions of dollars in damages to four electric substations on Christmas Day, leaving more than 15,000 customers without power. (See Feds Charge Two in Wash. Substation Sabotage.)

The defendants in that case, Matthew Greenwood and Jeremy Crahan, admitted in their plea deals they wanted to cut power to rob ATMs and businesses. Crahan was sentenced to 18 months in prison in December 2023; a month later, Greenwood was sentenced to three years of probation, including one year of home confinement.

Although Greenwood and Crahan’s crimes occurred in the same time frame, with similar goals, and even involved one of the same substations as Rosenthal’s alleged attack — the Puyallup facility — DOJ has not indicated that it suspects a connection between the incidents.

No motive has been suggested for the Oregon incidents, but prosecutor Todd Greenberg told local media that investigators have not found any evidence of ties to extremist groups. Law enforcement officials suggested in 2022 that the attacks, and similar events in the Pacific Northwest around the same time, could be related to “racially or ethnically motivated violent extremists” seeking to sow chaos by disrupting critical infrastructure.

While some of the Washington and Oregon cases now appear to have no political motivations, multiple plots to damage the electric grid for racial reasons have been uncovered since then. Around the same time Rosenthal allegedly conducted his attacks, neo-Nazi leader Brandon Russell was developing a plot to destroy electric substations in Baltimore in hopes of sparking a civil war. Russell was convicted in February and faces a maximum sentence of 20 years in prison. (See Neo-Nazi Convicted in Baltimore Grid Attack Conspiracy.)

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After Hitting Milestones, Markets+ Participants Advance on Phase 2

DENVER — Markets+ stakeholders will have little opportunity to ease up in coming months despite a wave of favorable developments for the market.

Those include FERC’s recent approval of the Markets+ tariff, funding agreement and a pair of compliance requests, as well as participants agreeing on most of the market protocols.

SPP has officially set Oct. 1, 2027, as the go-live date for Markets+, its centralized, day-ahead offering in the Western Interconnection. Between now and then, much will happen, with Sept. 1, 2025, emerging as a key date. That is the deadline for balancing authorities to join in time to be a part of the market when it goes live.

“It’s going to be really busy between now and Oct. 1 of 2027,” The Energy Authority’s Laura Trolese, chair of the Markets+ Participant Executive Committee, told RTO Insider on April 23. “The utilities and [independent power producers] within the BAs that are joining in the first tranche are going to need to get ready, register, figure out who their market participants are going to be and figure out a lot of different things to move forward with implementation. When a BA joins, now all the loads and resources within that BA are required to register and participate.”

Before then, SPP will begin designing and building the market’s systems and kicking off network and commercial modeling, while stakeholders will begin training on the RTO’s systems.

And with MPEC’s endorsement, the Markets+ Change User Forum (MCUF) will hold its first monthly meeting as Phase 2 gets serious. SPP staff said the MCUF, based on similar groups in previous market developments, will serve as an implementation forum for the Markets+ protocols.

“This is kind of exciting, because this is where it starts,” said Don Martin, SPP customer relations manager. “It is where you get our people and everybody’s people together. This is where your [energy management systems] team will be talking to these folks. This is where your IT folks will be talking or registering assets.”

The forum is holding its first virtual meeting May 6, five days after Phase 2 starts.

MPEC also endorsed a seams strategy and roadmap paper that lays out focus areas in the future development of polices and governing documents related to seams between Markets+ and neighboring markets and entities. It also documents a “desired end state” for market-to-market relationships with neighboring markets.

Stakeholders unanimously approved the recommendation.

The only motion that received a dissenting vote during the two-day meeting was a recommendation governing meeting attendance and the use of proxies from the Markets+ Interim Governance Task Force (MIGTF). Public interest organizations and other entities with small staffs pushed back against the recommendation that representatives on a working group or task force who miss three straight meetings or appoint a proxy for six straight meetings can be removed from the group by its chair. The MPEC and the Markets+ State Committee (MSC) would be excluded from that provision.

“Those groups that are maybe more capacity resource-constrained tend to rely heavily on proxies in order to maintain effective and consistent participation,” said Renewable Northwest’s Kavya Niranjan, who cast the lone “no” vote. “Our concern with this policy is not that we are not in disagreement with the intention. We feel that, because it can be overly prescriptive, that PIOs that are still trying to engage meaningfully might accidentally or unintentionally get caught up in the overly prescriptive nature of this policy.”

The MIGTF has debated the issue since August 2024, much to the consternation of its chair, Puget Sound Energy’s Jessica Zahnow, who said she just wanted to set clear expectations for attendance and participation.

“When our task force formed eight months ago, I got the list of the six items [to set expectations for recommendations] and I saw attendance policy. I thought, ‘Oh, that’s a slam dunk. That one’s going to be easy. Some of these other things are going to take some work, but this one will be easy,’” she recalled. “It hasn’t been easy, but we have learned a lot.”

Snohomish Public Utility District’s Joe Fina complimented the task force on its effort and their work developing a stakeholder-driven approval process, unlike those of other grid operators.

“I was very impressed with the interactions of the task force, the good faith that I think everyone was working under in trying to resolve the concerns that were issued,” he said. “I’m so glad to see kind of the end product here, after being aware of all of the process. I’m not aware in any of the other markets where they go down as deep into the working groups, and they have a similar thoughtful process, proxies and ability. I think that other markets will be looking at this as kind of the model as to how they deal with the similar issue and the work level.”

GHG, Other Protocols Endorsed

In a series of unanimous votes, MPEC approved more than a dozen-and-a-half chunks of the tariff’s remaining protocol language.

That included sections brought forward by the Markets+ Greenhouse Gas Task Force (MGHGTF), which is dealing with one of the more complex protocol sections. The task force began working on GHG pricing protocols in November 2024 after it completed GHG tracking and reporting protocols and developed an appendix providing guidance on creating and submitting mitigated energy offer calculations.

The MGHGTF plans to draft its final pieces of protocol language — focusing on unspecified-source imports and import interchange transactions — in the months ahead, while also ensuring the market’s implementation is consistent with state regulations.

“There are several things that we are continuing to tackle,” said the Public Generating Pool’s Mary Wiencke, who chairs the group. “I would not want this to be reflected as the GHG Task Force being behind. The GHG Task Force has been working very hard and diligently, but this is a new and novel design, so there are a lot of complex elements to figure out. We still do have some outstanding plan items and action items that we are continuing to work through it.”

She said the Washington State Department of Ecology has an open rulemaking on electricity markets, which has tightened the focus on the group’s work.

“Folks in Washington are very engaged in that process to make sure that what is being developed by the task force is consistent … in terms of the market design reflecting the state regulation and the state regulation reflecting the market design as well,” she said.

The MPEC agreed to reappoint all stakeholder group chairs and vice chairs through its Aug. 12 meeting in Portland. Trolese noted all stakeholder representatives were appointed to two-year terms in April 2023; this will allow a smoother transition when Phase 2 begins with the August meeting, she said.

The MPEC also endorsed three new members for the working groups:

    • Damon Skondin (Tucson Electric Power) for the vacant investor-owned utility seat on the Markets+ Transmission Working Group.
    • Richard Doying (Grid Strategies) and Caitlin Liotiris (Western Power Trading Forum) for the vacant independent seats on the Markets+ Seams Working Group.

Blank on Budget, PSCo Filing

The MSC, composed of regulators from 13 states, is asking for a $428,680 budget for 2025 to fund one full-time equivalent staffer at the Western Interstate Energy Board this year and retain the MSC’s consultants. The MSC said that will enable the regulators to continue engaging in the market’s development.

Eric Blank, chair of the Colorado Public Utilities Commission and previous chair of the MSC, told the MPEC the budget will be submitted to the Interim Markets+ Independent Panel for its approval.

Blank also said the PUC has a pending application from Xcel Energy’s Public Service Company of Colorado seeking cost recovery and other approvals to enter Markets+. PSCo filed its request in February. (See PSCo Seeks to Join SPP’s Markets+.)

“Although I can’t say much about pending litigation, I can say that the Colorado PUC is committed to getting a timely decision made to provide greater certainty to SPP and the Markets+ participants,” he said.

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MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction

MISO’s 2025/26 capacity auction returned $666.50/MW-day prices across all zones in the summer, reinforcing the need for members to build new generation fast, the grid operator said.

While none of MISO’s resource zones experienced a capacity deficit, MISO said it’s inching closer to pervasive shortfalls. The summer’s capacity prices represent a 22-fold increase over summer capacity prices in 2024.

Beyond summer, MISO zones cleared uniformly at $69.88/MW-day in spring and $33.20/MW-day in winter. For fall, MISO Midwest cleared at $91.60 while MISO South cleared at $74.09/MW-day. MISO said the split in fall pricing occurred due to its transfer limits between its Midwest and South regions.

Annualized, MISO’s capacity prices are $217/MW-day for MISO Midwest and $212/MW-day for MISO South.

Prices go into effect June 1, when the planning year begins.

In the 2024/25 capacity auction, Missouri’s Zone 5 cleared at the $719.81/MW-day cost of new entry for generation in spring and fall. All other MISO zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)

The 2025/26 auction was MISO’s first to feature sloped demand curves by season. The grid operator hoped the curves would function as a safety net to have more capacity on hand than strictly necessary to meet planning reserve margin requirements. FERC in 2024 allowed MISO to use them in place of the vertical demand curve it had been using since 2011. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)

MISO said the sloped curves placed an expected higher price on capacity, “reflecting the increased value of accredited capacity beyond the seasonal planning reserve margin target.” The grid operator said the auction cleared 1.9% above its 7.9% summer planning reserve margin (PRM). MISO said, effectively, it’s heading into summer with a 10.1% summer margin at 101.8 GW in MISO Midwest and an 8.7% margin at 35.7 GW in MISO South.

Ahead of the auction, MISO anticipated a 122.66-GW summer coincident peak and required a 7.9% PRM at 135.3 GW for the auction.

In other seasons, MISO cleared a 17.50% PRM in fall compared to its initial 14.90%; a 24.50% PRM in winter compared to the original 18.40%; and a 26.80% PRM in spring compared to the initial 25.30%.

During an April 29 conference call to review results with stakeholders, MISO’s resource adequacy manager Andy Taylor said all offered capacity in MISO Midwest ended up clearing while about 300 MW of capacity in MISO South priced above the summer clearing price was left on the table.

MISO said as with previous auctions, most of its load-serving entities “self-supplied or secured capacity in advance” outside of the voluntary auction and thus are shielded from this year’s pricing. Taylor said more than 90% of load in MISO hedged against “direct exposure to these prices.”

The RTO said while its sloped curves cleared extra capacity, it noticed the footprint’s spare capacity beyond planning reserve margins dwindled 43% this year compared to summer 2024. MISO said the drop occurred despite a slightly lower planning reserve margin aim than summer 2024’s 9% target. The RTO said it oversaw 140.7 GW in summer 2024 offers and 137.8 GW in summer 2025 offers. MISO reported surplus capacity in the summertime has regressed from about 6.5 GW in 2023, to 4.6 GW in 2024, to 2.6 GW in 2025

The 5.1 GW in new capacity, made up mostly of solar generation, and 1.2 GW in capacity accreditation increases added over the last planning year were no match for 4.9 GW in accreditation decreases, 3.3 GW in retirements and suspensions, and a nearly 1-GW loss in external suppliers in the same timeframe, MISO reported.

“New capacity additions did not keep pace with reduced accreditation, suspensions/retirements and slightly reduced imports. The results reinforce the need to increase capacity, as demand is expected to grow with new large load additions,” MISO said in a presentation accompanying auction results.

MISO Vice President of System Planning Aubrey Johnson said clearing prices more accurately reflected the growing value of accredited capacity as MISO’s supply drops closer to its resource adequacy requirements.

During the teleconference, Johnson said the auction “reinforces the challenges of preserving online resources and bringing more resources online as soon as possible.”

Taylor said prices better represent the value of reliability given the “relative risk in each season.” In summer, MISO neared but didn’t hit its preset, approximately $850/MW-day cost of new entry (CONE) for summer. Taylor said although MISO achieved its RA requirements and then some without experiencing any capacity shortages, MISO’s total surplus capacity continues to shrink.

“This has been a trend for many years,” Taylor told stakeholders.

MISO Executive Director of Markets Innovation and Strategy Zak Joundi said prices are “way more reflective of the risk profile we’re operating under.”

But stakeholders questioned whether the surplus is worth the expense.

Sustainable FERC Project’s Natalie McIntire asked how members are supposed to determine how much supplemental capacity MISO might deem appropriate in upcoming years.

“It seems like the PRM is no longer a really firm target,” McIntire said. She asked MISO to be mindful when deciding what volumes are sufficient beyond MISO’s one-year-in-10-years standard, because the surplus comes at a cost to consumers. McIntire requested MISO to balance affordability with reliability.

“It makes everyone feel very comfortable to have large margins, but there is a cost to large margins,” she said.

Taylor responded that MISO’s overall margins are “extremely thin” and acknowledged that MISO would exceed its baseline reliability targets moving forward under the sloped design curve. He MISO’s annual “static” sloped curves — which are calculated annually and use a blend of seasonal, systemwide curves and subregional sloped curves — would determine cleared capacity excesses in upcoming years.

Other stakeholders agreed the added reliability reassurance came at a high cost. Some also questioned whether MISO relied on the correct curves to lock in summertime prices.

Taylor said if not for the sloped curves and additional cleared supply, auction prices could have risen even higher and topped out at CONE under the old vertical curve paradigm. He also said MISO plans to host a more in-depth presentation on auction results at its May 21 Resource Adequacy Subcommittee.

Constellation Energy’s John Orr asked MISO to analyze and share what prices would have been had MISO used its vertical curve. WPPI Energy’s Steve Leovy seconded the request.

Over 2024, MISO and the Organization of MISO States through their joint resource adequacy survey showed that anywhere from a 1.1-GW surplus to a 2.7-GW shortfall could be possible by summer 2025. MISO leadership has been cautioning its stakeholders for more than a year that faster generation additions are a must.

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Plan Lays out Steps for State-led Interregional Transmission in Northeast

The Northeast States Collaborative on Interregional Transmission released a strategic action plan April 28 for creating an interstate planning process for transmission projects that span the seams of their grid operators.

The collaborative comprises nine states — Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island and Vermont — and was formed with the goal of exploring “opportunities for increased interconnectivity” between ISO-NE, NYISO and PJM. (See 10 Northeastern States Sign MOU on Interregional Transmission Planning.) New Hampshire signed the initial memorandum of understanding creating the group but did not sign onto the plan.

The plan, prepared by The Brattle Group, goes further than exploration and into concrete steps for soliciting projects and proposing them to the grid operators. It implicitly criticizes FERC’s planning rules, including the recent Order 1920, for creating barriers to interregional projects.

“No process currently exists for groups of states spanning different transmission planning regions to take the various steps necessary to identify, evaluate, select and agree to share the cost of beneficial interregional transmission projects so they can be developed,” the plan says. “Members of the collaborative have referred to the absence of such a process as ‘the missing middle.’”

Brattle focused on what states can do in the short term — including over the next year — to identify beneficial interregional projects and “make them actionable through existing regional planning processes.” Such projects would help states reach not just their long-term emission-reduction goals but also address their looming resource adequacy concerns.

“New York is pleased to be a part of this strategic partnership so that together with our fellow Northeast states, we can find more effective and affordable solutions to maximizing transmission opportunities that can both provide increased reliability as well as deliver additional clean energy to our grid,” New York State Energy Research and Development Authority President Doreen Harris said in a statement.

Over the next year, the states will attempt to identify “low-hanging fruit” projects through a request for information. Brattle recommends the states ask the three grid operators to take on advisory roles in the process, as any project will need to be integrated into each of their transmission plans. It also suggests including NERC, “given its recent identification of interregional transmission solutions as necessary to ensure a reliable electric grid.” (See NERC Responds to Interregional Transfer Capability Study Comments.)

Simultaneously, Brattle says, the states should consult with the grid operators and FERC on what, if any, tariff changes would be necessary to facilitate the interstate process.

The plan also includes goals for the end of 2027, including the development of HVDC design standards to facilitate an offshore transmission network and joint offshore wind procurements.

“Not having to build new power plants saves Marylanders money,” Maryland Energy Administration Director Paul Pinsky said. “Increased regional transmission capacity can reduce the need for power plants that solely exist to meet peak demand, which are typically fossil fueled. … This collaboration illustrates why state-led climate action is so important to achieving our energy, environmental and economic goals.”

“States across the Northeast share a common priority to ensure an affordable, reliable and sustainable electric grid,” Vermont Department of Public Service Commissioner Kerrick Johnson said. “Transmission is at the heart of securing that energy future.”

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Oxbow Incident: FERC Denies Solar Farm’s Waiver

FERC has denied Oxbow Solar’s waiver request for a 24-month extension of its commercial operation deadline for a planned generating facility in Southwestern Electric Power Co.’s northwestern Louisiana service territory.

In its April 23 order (ER25-1274), the commission said Oxbow Solar had failed to meet FERC’s criteria for waivers of tariff provisions: that the applicant acted in good faith; the waiver is of limited scope; it addresses a concrete problem; and the waiver does not harm third parties or have any other “undesirable consequences.”

FERC found Oxbow Solar failed to show it acted in good faith to diligently advance the solar facility and said it appears “Oxbow Solar’s need for the instant waiver may have been caused, in part, by its own inaction.” The developers did not dispute they failed to meet an amended generator interconnection agreement’s milestone to notify SWEPCO to begin construction or that they met the milestone almost two and a half years late, the commission said.

The planned 73.5-MW generating facility had an initial operating date of Dec. 1, 2023.

FERC also said Oxbow Solar failed to demonstrate that granting the requested waiver would have addressed a concrete problem. It said Oxbow Solar’s only justification is that “the market has corrected for increased project costs.”

“Given the absence of a detailed explanation in the record of how the 24-month extension will allow Oxbow Solar to secure financing and achieve commercial operation, we find that Oxbow Solar has failed to sufficiently demonstrate that its waiver request will remedy a concrete problem,” the commission wrote.

Oxbow Solar had requested the extension, from Nov. 30, 2026, to Nov. 30, 2028, back in February. It said rapid increases in insurance, engineering, procurement, and construction costs and difficulties in securing solar components had hampered its ability to negotiate offtake agreements in time to meet the commercial operation deadline.