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.
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.
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.
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.)
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.
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.
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.
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.”
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.
After nine years of development and dozens of stakeholder meetings, the Independent Electricity System Operator (IESO) is poised to launch its new nodal market May 1, a change it says will save Ontario $700 million over the next decade through reduced out-of-market payments and increased efficiency.
The Market Renewal Program (MPR) is intended to improve the way IESO supplies, schedules and prices power by creating a financially binding day-ahead market (DAM) and creating almost 1,000 locational marginal pricing (LMP) nodes.
The IESO says nodal pricing — which is used in all seven U.S. RTOs and ISOs — is crucial to efficiently dispatching and providing market signals to renewables and new resource types such as distributed energy resources, storage and hybrids.
The current day-ahead commitment process is not financially binding, resulting in uncertainty for generators. The addition of a financially binding day-ahead market gives resources “much more certainty over what they will be paid, and it gives us much more certainty over what’s available and how we can schedule and commit those resources,” said Candice Trickey, director of the MRP, at an April 16 webinar attended by almost 600 people. “So, it gives much, much more clarity, transparency and certainty for both sides.”
Under Ontario’s current two-schedule market design, the initial schedule ignores system constraints and transmission losses to calculate the Hourly Ontario Energy Price. The second schedule incorporates transmission constraints to determine system dispatch, with uplift payments used to address differences between the two schedules.
Candice Trickey, director of IESO’s Market Renewal Program, explains the changes coming with the new nodal market at an April 16 webinar. | IESO
The new market will use a single schedule to dispatch the system and calculate LMPs at more than 970 generation, load and intertie nodes in the day-ahead and real-time markets, a number IESO says may increase as its system grows. The day-ahead market will have hourly pricing while the real-time market will continue to price in five-minute increments.
IESO says the improved price transparency should increase efficiency and lower costs.
The pricing granularity is “really important to sort of underpinning all of the changes that we’re making and giving us the ability to make those cost decisions, and it will also provide longer term signals for resources across the province in terms of where it makes the most sense to locate if you’re looking for future opportunities,” Trickey said. “It will also help better inform consumption decisions for loads that want to be responsive to price.”
Work Began in 2016
Work on the new design began in 2016, when IESO held a series of consultations with stakeholders. “Stakeholders have been a big part of this all along the way [with] literally hundreds of meetings covering all kinds of topics — committees, groups, working groups, you name it,” Trickey said.
The goal? “Making sure that we make the most of Ontario’s electricity supply resources — those that we have today and those that we know are coming in the future,” Trickey said. “It’s really about improving how we schedule the resources and ensuring that we make the most cost-effective scheduling decisions in all hours of the day.”
The IESO’s MRP business case predicted total 10-year benefits of $975 million, including $525 million in market efficiency improvements and $450 million from eliminating unnecessary congestion management settlement credit payments. After implementation costs, the IESO expects $700 million in net financial benefits for Ontario electricity consumers over the first decade.
Accounting for congestion in LMPs will reduce uplift payments. “That’s where a good chunk of the cost reduction comes from,” Trickey said.
Changes for Non-Quick Start Generators
A new Enhanced Real-Time Unit Commitment process will seek to optimize the scheduling of non-quick start gas generators over multiple hours versus the current system, in which dispatch is determined for individual hours.
Most non-quick start (NQS) generators need one to six hours to start up and synchronize with the grid and have limited flexibility because of minimum loading points, maximum daily starts and minimum runtimes.
The IESO will be “looking up to 27 hours ahead to schedule the least cost solution and make sure that we schedule all of the pieces together,” Trickey said.
Ontario’s major transmission interfaces, electrical zones and interties | IESO
IESO also will replace its Real-Time Generator Cost Guarantee (RT-GCG) program with a Generator Offer Guarantee program. The former program provided financial and operational guarantees to NQS generators on days when they may not be able to recover their costs through energy prices. But that allowed them to claim reimbursement for start-up costs greater than what they incurred, the Ontario Energy Board (OEB) concluded in a March 6 ruling dismissing the generators’ challenge to the MRP.
Under the new rules, NQS generators must provide a three-part offer, including energy costs, start-up costs and the cost of remaining connected to the grid while generating net-zero active power.
“The non-competitive nature of the RT-GCG leads to productive inefficiencies in the short run when demand is not met using the lowest cost resources, as offers do not accurately reflect generation costs,” the OEB wrote. “The RT-GCG program also suppresses market prices below efficient levels by removing the incentives for these generators, who are frequently market price-setters, to incorporate fixed start-up costs into their offer prices. The result is a weakened price signal and a reduction of incentives for other market participants to be available at these times.”
An analysis by the generators’ consultant, Power Advisory, found a 600-MW gas generator with a heat rate of 7.5 MMBtu/MWh would have had a net margin of $75.5 million from 2018 to 2023 under the new rules, a reduction of $21 million from the current rules. The analysis also found gas generators set prices in 41% of day-ahead hours and 62% of real-time hours in summer 2021.
Impact on Loads, Resources
Nodal pricing will be applied to dispatchable loads, price-responsive loads and generation, including dispatchable resources, self-scheduling and intermittent suppliers (wind and solar). Non-dispatchable loads will settle on one of 10 hourly zonal prices. Large industrial consumers can continue to pay an hourly Ontario-wide price or choose the LMP for their location.
Dispatchable loads — “a very, very small percentage” of loads, according to Trickey — must be able to respond to IESO instructions and reduce their consumption within five minutes.
2023 energy input (TWh) | IESO
Pricing for non-dispatchable loads will remain uniform across Ontario, but the new Ontario Electricity Market Price will be based on the hourly load-weighted average of all non-dispatchable load DAM LMPs plus a price adjustment to account for the cost of the differences between day-ahead and real-time schedules.
Although the calculations behind them will change, consumer bills will look the same, with an hourly province-wide price for electricity added to the Global Adjustment, which covers the cost of building and maintaining the electric system.
Intertie Transactions
The market will use dynamic settlement pricing on its interties with Quebec, MISO, NYISO and PJM.
IESO imported 4.1 TWh to meet its 137.1 TWh of demand in 2023, while exporting 16.5 TWh.
The real-time intertie border price will be used if there is no congestion in the final pre-dispatch run. For export-congested interties, the sum of the five-minute real-time intertie border prices and the pre-dispatch intertie congestion price will be used. For import-congested interties, the lesser of the pre-dispatch intertie LMP (which includes the intertie border price plus the intertie congestion price) or the five-minute real-time intertie border prices will prevail.
The current day-ahead commitment evaluates import and export legs of wheel-through transactions as linked transactions while pre-dispatch assesses both as separate transactions. In the new market, both the DAM and pre-dispatch will assess import and export legs as linked transactions.
No Virtuals or FTR Markets
With a system-wide price and the lack of a binding day-ahead market, IESO’s current system has no virtuals market for arbitraging between day-ahead and real-time prices.
And while there is a financial transmission rights market for hedging import and export risks, there is no FTR market for hedging internal congestion.
The MRP will create a virtuals market at the zonal level, like those in NYISO and ISO-NE. Market participants will be able to submit hourly bids and offers in any of nine virtual transaction zones in the day-ahead market. The Bruce zone has a low load relative to supply, so it was combined with the Southwest to create a more balanced zone, according to IESO.
MISO and PJM began their virtuals market at the zonal level until they became more established, and SPP’s Markets+ virtuals market also will begin on a zonal basis when it launches, noted Emily Merchant, a director of product at Yes Energy.
Merchant said nodal virtual markets require significant trading activity to ensure prices accurately reflect market conditions. “Given all the changes rolling out with the MRP, the market operator may have wanted to de-risk this new virtuals market by starting off zonal,” Merchant wrote in a Yes Energy blog post on preparing for the nodal market.
The introduction of LMPs also creates the “framework to support FTRs,” said Merchant, although IESO says it has no current plans for such an expansion.
Average weighted hourly Ontario energy price | IESO
“There are no internal nodal transmission rights like there are in some other markets,” said Warren Hill, a senior adviser for market development at IESO. “We are not going in that direction.” (See IESO’s Introduction to Virtual Traders.)
Yes Energy power market analyst Tim Hough said the zonal virtual market may be most attractive to asset operators looking to hedge against volatility.
“Since there’s only nine different nodes you can virtually transact on, there is just a lot less opportunity for traders to find a couple little nodes and a special little weather pattern to make a lot of money on,” he said.
Market Power Mitigation
IESO will change from an ex-post to an ex-ante approach to market monitoring, employing a “conduct and impact” test to mitigate market power before prices and schedules are determined.
If a market participant fails the conduct test — or is found to have made an offer significantly above that expected under competitive conditions — IESO will apply an impact test to determine the difference in market outcome between the higher offer and the reference level offer. If the MP fails both tests, its offer will be replaced with reference levels.
Implementation Plan; Potential for Delays
The MRP will result in about 36 new public reports from IESO and updates to more than a dozen others, while more than 20 will be retired. The MRP also will include a new four-zone demand forecast, “so you’ll be able to see demand in different areas with a more accurate view than what we would provide today,” Trickey said.
IESO will provide updates on the status of the launch beginning the morning of April 30 and continuing through completion of the launch, expected May 2.
“There is always a small chance that something could happen in between now and then that would impact that — likely to be something in terms of system conditions,” Trickey said. “If there was some sort of reliability event — you know, weather event, or something that impacted us — we may need to change that.”
If the launch is delayed, IESO will not go forward until the first of a subsequent month, Trickey said, ruling out a launch on July 1 or Aug. 1 because of holidays. “[We] may not want to necessarily launch in the heat of the summer as well, when system conditions can be more challenging.”
Market participants will need to submit dispatch data into both the legacy and renewed market systems on April 30 because existing bids and offers will not be moved to the new system. There will be no day-ahead market for the May 1 and 2 trade dates as IESO establishes the new real-time market and monitors dispatch results.
“There will be bumps along the way as we transition, because it is a very large and complex change, and one that depends on people from across the sector,” said Trickey. “I know there’s going to be bumps coming, but we’re in a good position to weather through those.”
Although IESO is making the changes to improve operational certainty and reduce system costs, initial market results may not show immediate improvements, said Yes Energy’s Hough. “It’ll be a very big change for a lot of people. So, I would expect some volatility there. If you’re a battery asset operator — which there isn’t much of in Ontario — you will probably be raking it in early on.”
For More Information:
IESO’s Overview of the Transition to the Renewed Market presentation and webcast
Stakeholders and state energy officials continue to raise concerns about a CAISO draft proposal that would adjust how congestion revenues are allocated in its Extended Day-Ahead Market, with the ISO aiming for a vote on the final proposal in the coming weeks.
The draft proposal, released last week, addresses how the EDAM will allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes parallel flows in a neighboring BAA.
CAISO has said the draft proposal will be “transitional” over the next three years, after which time it plans to implement a more permanent design.
The proposal is a product of the past two months of focused work on the subject. In March, CAISO launched an expedited initiative to address stakeholder concerns, and this week, the agency held an all-day meeting to review the proposal with the more than 150 participants who joined the call.
At the April 24 meeting, California Public Utilities Commission regulatory analyst Michele Kito asked if the ISO had a sense of where the major parallel flows currently take place on the system.
“I would imagine that we can look at historical system data,” Kito said. “Do we have any sense of what those [parallel flows] are and what the effects each of these proposals have in terms of revenue allocation?”
“We haven’t looked at specific parallel flow impacts,” George Angelidis, CAISO executive principal, said at the meeting. “There are well-known transmission bottlenecks in the ISO system, like Path 36 and Path 15, but in general, any kind of flow in the system will experience what we define as parallel flow.”
Parallel flow is the impact on the flow gauge of transactions that are external to that BAA, Angelidis said. They can be infinite: Any path will have parallel flows, so CAISO has not looked at potential parallel flow results on specific flow gauges, he said.
Cathleen Colbert, senior director of Western markets policy at Vistra, added, “I will give a little extra support to Michele’s questions. Do we not have any sense of how these parallel flows work on internal constraints? I do think there’s a case for you guys to provide some additional kind of forward-looking information.”
CAISO will study these parallel flow effects over the three-year period of the new design, said Milos Bosanac, ISO regional markets sector manager.
“As entities join the EDAM, we will be modeling transmission constraints on their system that may not necessarily be reflective today,” Bosanac said. “I think it’s difficult to surmise the effects at this point in time of constraints that might not yet be modeled. [However], we will be modeling the new design on PacifiCorp’s system, and as other entities join, we will model those effects [too].”
Middle Approach
Under current EDAM market rules, Open Access Transmission Tariff (OATT) customers in one BAA will end up paying costs for congestion for parallel flows caused by binding transmission constraints in neighboring BAAs. However, under the draft final proposal, parallel flow congestion revenues collected in a BAA that result from a binding constraint in a neighboring area will be allocated first to the BAA in which the overflow congestion occurs and the revenues are collected.
In an example reviewed at the meeting, $135,800 in congestion revenue was collected and distributed to three balancing areas: BAA A, BAA B and BAA C. Under the current design, all $135,800 would be distributed to BAA A. However, under the draft proposal, BAA A would receive $132,800 in revenue, BAA B would receive $1,000, and BAA C would receive $2,000.
The final draft proposal supports EDAM entities’ capacity to provide congestion cost protection for transmission customers exercising firm OATT rights, Bosanac said. The draft also addresses stakeholder concerns about a balancing area being exposed to congestion costs when providing counterflow effects in relation to constraints, he said.
The draft would apply only to the day-ahead market, not to the real-time market. The real-time market retains the congestion revenue allocation in effect today in the WEIM “in order to minimize the impact on the WEIM participants,” Bosanac said.
If approved, CAISO will implement the draft final proposal by collecting data and monitoring the congestion effects over the first one to two years of the transitional approach. CAISO then will prepare a permanent design after the three-year period.
Consumer groups defended their complaint with FERC alleging utilities spend too much on lightly regulated local transmission projects against arguments that such spending is justified (EL25-44).
In a joint answer to protests filed April 24, the 22 groups — including the Industrial Energy Consumers of America, American Forest & Paper Association and R Street Institute — argued that the December 2024 complaint against all FERC-jurisdictional transmission planners should be granted so the commission can address what they called widespread unjust and unreasonable planning practices. (See Utilities Ask FERC to Toss Local Tx Planning Complaint, Others Support It.)
While the transmission lines can be called “local,” those at issue in the complaint are located in the Eastern and Western Interconnections and are part of interstate commerce. That has long been recognized by the courts, the groups said.
“Respondents nevertheless insist that planning of interstate transmission at the individual level remains appropriate because such transmission is ‘local’ and that existing transmission owners have a ‘right’ to plan the interconnected grid of the future simply because they built the grid of yesterday,” they said. “Respondents make no electrical distinction between local and regional transmission.”
The actual difference between “local” and “regional” projects can be arbitrary, the groups argued, noting as an example that American Transmission Co. independently started planning a 345-kV line, which then was selected by MISO for its regional transmission plan, with its costs spread across the footprint.
“ATC argues that ‘the project directly contradicts the “piecemeal planning” allegations contained within the complaint,’ but the project actually proves the point of the complaint, as MISO recognized that the project impacted the entire region, although it was initially individually planned,” the consumer groups said. “The electrical nature of the project did not change through the regional review, and the complaint identified hundreds of similar projects that were individually planned with no substantive regional review.”
A common rebuttal to the complaint was that utilities had to retain their planning role to effectively meet state retail obligations, which leaves it outside of FERC jurisdiction.
“The complaint is based on the simple electrical premise that there is no FERC-jurisdictional ‘local’ transmission and thus there are no ‘local’ transmission planning needs,” the groups responded. “There are localized inputs to determining the holistic needs of the interconnected grid, but electrical facilities at 100 kV and above are not local, except those excluded by the complaint.”
Local projects that solely serve intrastate needs are outside of FERC jurisdiction, and the complaint does not ask FERC to try to regulate them.
Many protesters argued the complaint is too broad, and the commission should take regional differences into account if it decides to grant it.
“Individual or even regional ‘planning challenges’ or differences are irrelevant to the fundamental question under the complaint as to whether it is appropriate to allow individual transmission owners to plan 100-kV and above transmission in interstate commerce based on the ongoing false premise that such transmission planning relates to ‘local transmission,’” the groups answered. “Planning challenges, to the extent they exist, can be incorporated into the required regional planning, just as regional differences are incorporated today in regional planning.” FERC can grant the complaint and facilitate implementation of any necessary region-specific reforms through compliance filings, they argued.
Another common rebuttal was that the complaint had to prove that local planning leads to unjust and unreasonable rates on specific projects. But the groups argued it was aimed at local planning practices and that Section 206 of the Federal Power Act can address broad industry practices.
“Critically, acceptance of respondents’ arguments would also mean that FERC, under a rulemaking pursuant to Section 206, wouldn’t be able to dictate nationwide standards, like in Orders Nos. 890, 1000 [and] 1920,” they said.
Opponents also argued the complaint was a collateral attack on Order 1920, or even earlier transmission planning rules. But the groups said they had put new evidence in front of FERC that it did not have during the proceedings that led to its most recent transmission planning rule.
“The new evidence and changed circumstances consist of new analytical reports and evidence of both individual projects and cumulative regional transmission plans and portfolios across every planning region over several years,” they said.
Other Parties Defend the Complaint
American Municipal Power also filed an answer April 24, arguing FERC should grant the complaint despite a request from PJM and its transmission owners to dismiss it.
The complaint made the case that spending on local projects in PJM has become unjust and unreasonable and should be dealt with in a subsequent show-cause proceeding, AMP said.
Transmission rates in PJM are up 237% from 2011, mainly from local projects with limited oversight, AMP said.
“Forcing local transmission customers to bear the cost of projects that should have been supplanted by more cost-effective regional projects could unduly discriminate against those local customers by unfairly shifting the cost of transmission projects in a manner inconsistent with cost-causation principles,” AMP said. “The harmful effect of these failures would only multiply going forward, as PJM’s load is expected to grow by 70 GW or more in the foreseeable future.”
The Maine Public Utilities Commission similarly rebutted claims about local planning in New England. It said FERC should open another Section 206 show-cause proceeding so it can address the issues around local planning and its lack of oversight in New England.
Projects above $5 million are presented to ISO-NE’s Planning Advisory Committee, but the process has proven inadequate, and the TOs retain all control over asset-condition projects in the region.
The PUC “completely agrees that the ISO-NE tariff and related documents do not provide ISO-NE with a role in local transmission planning sufficient to effectuate all of the remedies sought by complainants, but [it] submits that a Section 206 investigation will allow parties to build a record upon which remedies consistent with Order No. 890 and FERC precedent may be developed specifically for the New England region,” it said.
