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December 8, 2025

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ERCOT Board Approves AS Procurement for 2026

ERCOT’s Board of Directors has approved staff’s recommended methodologies for acquiring minimum ancillary service requirements in 2026, but not before revisiting the same discussions that stakeholders have over conservative operations and target procurement levels. 

The board’s Sept. 23 approval allows ERCOT to use a probabilistic methodology — an analytical approach incorporating randomness and uncertainty by assigning probabilities to outcomes and events — to calculate hourly ERCOT contingency reserve service (ECRS) and non-spinning reserve service quantities. The probabilistic model aligns ECRS and non-spin requirements with the risk profile, where higher risk equals a higher requirement and lower risk equals a lower requirement. 

Staff’s proposal also makes minor changes to regulation service and responsive reserve service (RRS). 

“I appreciate the tension between reliability and efficiency and cost effectiveness,” ERCOT CEO Pablo Vegas said as the hourlong discussion, scheduled for 20 minutes, wound down. “That’s a tension that I think we all deal with in what we do day to day.” 

The Independent Market Monitor again made the case that ERCOT is over-procuring non-spinning reserves and other long-lead-time ancillary services. It offered a compromise that halved the length of staff’s recommended look ahead at forecast errors or forced outages, from six hours to three, saying it would be just as reliable as staff’s proposal but for less cost. 

The Monitor also joined the consumer stakeholder segment in suggesting an end to the grid operator’s conservative operations approach, which stockpiles operating reserves in anticipation of tight conditions. 

“Somebody needs to figure out what the offramp is from conservative operations, so that we’re not just doing this forever,” IMM Director Jeff McDonald said. “I feel for ERCOT having been put in a situation where they have to incorporate that kind of an unwritten policy directive into their actual reliability operations, but there’s got to be an offramp for that.” 

ERCOT Director John Swainson pushed back against the Monitor’s recommendation. He questioned McDonald’s suggestion after ERCOT staff had said they were following the Texas Public Utility Commission’s criteria. In a 2024 report on ancillary services, PUC staff found conservative operations should be maintained to balance system improvements made since the February 2021 winter storm until additional data are available. 

“We have no idea how you calculated or what the hell you’ve done, and you come up with a different answer,” Swainson said. “We just can’t believe you. I mean, your credibility with us as directors is zero.” 

“I’m not really sure how to address that,” McDonald said in response. 

PUC Chair Thomas Gleeson offered McDonald a lifeline, saying the IMM and Potomac Economics’ David Patton have spent “a lot of time with me” on the issue as recently as the prior weekend. 

Texas PUC Chair Thomas Gleeson explains his thoughts on conservative operations. | ERCOT

“I’m in agreement with the IMM that we need to look at all of this,” he said. “I don’t think we should ignore the price formation aspects of the posture that we’ve taken … to ignore the price-formation impacts of the conservative operations posture that we’ve taken would be foolish, at least as I sit here as a commissioner.” 

Gleeson pointed to ERCOT’s Real-time Co-optimization + Batteries (RTC+B) project, to be deployed in December, and reliability standard analysis that will take up much of 2026 as reasons to wait before making further market changes. 

“While I agree that we need to look at this and potentially make some changes in this direction, I think it is more prudent to wait until next year,” he said. “I think this needs more discussion.” 

Adding “real time co optimization + batteries into the market is going to be one of the biggest market changes economically and operationally that we’ve gone through in over a decade,” Vegas said, agreeing with Gleeson that “it’s very prudent to see the impact of that over multiple cycles.” 

In the end, the board agreed with staff and other stakeholders to wait until 2027 to revisit and further examine ancillary service methodologies for potential adjustments. 

RTC+B Completes Major Test

“It feels like if it’s a football game, we’re first down and goal from the 8-yard line,” ERCOT’s Matt Mereness said in briefing the board on the RTC+B project. “There’s still a way to go, but things have been going pretty well.” 

Mereness, senior director of market operations and implementation and the RTC+B project manager, said the initiative is five months into market trials and testing and stabilizing systems. The first of two planned production tests was conducted Sept. 11; ERCOT operators controlled the real-time market and frequency for two hours, and market participants were able to submit accurate telemetry, bids, offers and follow RTC+B dispatch, he said. The RTC+B systems were able to award and dispatch energy and ancillary services in real time every five minutes. 

A second production test is scheduled for Oct. 30. ERCOT’s most significant market redesign since the switch from zonal to nodal in 2010, RTC+B is scheduled to be deployed Dec. 5. 

“We don’t normally take six months to implement something, but when you implement a major redesign of your real-time market and your four-second control of the system, you need to test it,” Mereness said. “It’s not just about ERCOT being successful. It’s about 95 other companies that are batteries, resources and generators that have to move their machines.” 

During the first production test, solar and wind energy dropped by 3,000 MW and two units tripped offline, but “other things” picked up. 

“It wasn’t necessarily an easy-peasy test like some of us thought it would be,” Mereness said. “The good news is that the operators and engineers are now looking at how [our system reacted]. The nice part of actually doing a dress rehearsal is people look at the money; they look at the megawatts; and they see if they can follow.” 

ERCOT plans to publish a market notice Nov. 5 to alert market participants that RTC+B is live and the transition has begun. 

Another ‘Mild’ Texas Summer

Barring an unseasonable warm spell during the fall, ERCOT will go a second straight year without setting a new demand peak, Vegas said during his update to the board. The grid operator recorded a high of 83.68 GW on Aug. 18, less than 2 GW from the all-time peak of 85.51 GW set in August 2023. 

While no new peaks were set during a “mild” summer — the June-July period was only the 43rd-hottest in recorded history — ERCOT’s energy consumption has grown year over year. Vegas said the consumption, which increased 2.53% from 2010 through 2020, has doubled to 5.12% since then. 

“This is a little bit like the proverbial frog that’s boiling slowly in a pot of water … and doesn’t realize that it’s actually boiling,” he said. “This is what’s happening here. Under the surface, we’ve got energy growth growing very rapidly, but because we haven’t had extreme weather events in the last couple of years, we have not seen new peak demands push up that peak demand level any higher. It’s important to not ever be lulled into complacency.” 

Vegas said ERCOT is at an “inflection point of an acceleration of demand growth.” Fortunately for the ISO, staff are analyzing 6,000 MW of new generation that will be synchronized to the grid in the first quarter of 2026. That’s the most ever studied at one time, Vegas said. 

Energy storage resources (3,042 MW) and solar (2,055 MW) account for much of the generation, with four gas projects accounting for the remainder (1,103 MW). Vegas said the first three Texas Energy Fund projects are among the gas projects under study. (See NRG Energy Secures $216M Loan from TEF.) 

“This is a positive trend,” he said. 

Solar and ESRs continue to be the ISO’s workhorses during the critical afternoon hours. Solar set four records during the summer, the last on Sept. 9 (29.83 GW); the 29.34-GW solar peak July 29 broke the grid operator’s mark for wind generation (28.47 GW) for the first time. ESRs also set records this summer, with a high-water mark of 7.51 GW on Sept. 10. 

“The additions of solar and batteries have helped us handle the growth in the summer months, where we’ve seen a lot more consumption,” Vegas said. 

Board Approves Transmission Projects

The directors approved two regional transmission projects that could cost as much as $827 million to build and that have been recommended by ERCOT’s Regional Planning Group and passed the Technical Advisory Committee. (See “$827M in Tx Projects OK’d,” ERCOT Stakeholders Endorse 2026 AS Methodology.) 

CenterPoint Energy’s Baytown Area Load Addition project in the petrochemical industrial region east of Houston is projected to cost $545.3 million for 45 miles of 138-kV lines and additional capacitors. CenterPoint submitted a $141.7 million estimate to address reliability issues caused by proposed new load; ERCOT staff said additional temporary work would be required for all structure replacements, accounting for about 45% of the capital costs, maintenance-outage issues and the expense of rebuilding 138-kV lines among industrial facilities. 

Bryan Texas Utilities’ Texas A&M University System RELLIS Campus project has an estimated capital cost of $282.1 million. The project includes 40 miles of new 345-kV double-circuit lines to the RELLIS campus; constructing or rebuilding about 10 miles of 138-kV lines; and expanding the campus’ existing 138-kV substation. 

Benjamin Barkley, CEO of the Texas Office of Public Utility Counsel, abstained from the vote on the Baytown project. 

The board also approved a price correction for the day-ahead market on its June 27 operating day. ERCOT said a software malfunction related to a generic transmission constraint affected day-ahead prices and wasn’t discovered until after the two-business day deadline for corrections. 

The correction resulted in a maximum absolute value effect of $26,525 to counterparties and $124,385 due to ERCOT. 

Complete Board Seated

Independent Directors Christopher Krummel, Kathleen McAllister and Bill Mohl, fresh off recent selections to the board, participated in their first meetings Sept. 22-23. They have also been appointed to the board’s subcommittees, which are fully rostered for the first time in 2025. (See ERCOT Fills out Board with 2 Final Selections.) 

Consent Agenda Passes

The board’s consent agenda included 10 nodal protocol revision requests (NPRRs), three changes each to the Planning (PGRRs) and Settlement Metering Operating (SMOGRRs) guides, two modifications to the Nodal Operating Guide (NOGRRs), single revisions to the Variable Cost Manual (VCMRR) and Retail Market Guide (RMGRRs), and a system change request (SCR) previously endorsed by TAC that will: 

    • NPRR1265: implement procedures for distributed generation reporting by clarifying DG’s definition and defining the new term, “unregistered distributed generators” (UDGs). The NPRR would establish procedures for UDG reporting to ERCOT and reporting requirements from the ISO. 
    • NPRR1266: specify that a transmission-voltage customer that is a securitization uplift charge opt-out entity may not transfer its status to other entities. The measure adds a requirement that a transmission service provider (TSP) associated with an electric service identifier originally granted opt-out status must compare at least monthly the names of transmission-voltage customers originally granted the status and inform ERCOT of any changes. The TSP requirement excludes those that are securitization uplift charge opt-out entities. 
    • NPRR1277: revise the minimum current exposure and estimate aggregate liability (EAL) formulas, improving the efficacy of existing credit formulas that measure credit exposures in the ERCOT market. The EAL formula revisions include applying the real-time forward adjustment factor against the respective days’ real-time liability estimated (RTLE) and then taking the max over the lookback period; and introducing seasonal variability in the lookback period as it is applied for RTLE. 
    • NPRR1279: enable generation resources to file exceptional fuel costs that include contractual and pipeline-mandated costs and strengthens the process for ERCOT and the Monitor to verify the costs. 
    • NPRR1281: strengthen the relationship between the settlement of firm fuel supply service (FFSS) and operations by clarifying its hourly rolling equivalent availability factor language to ensure the accurate calculation of the FFSS standby fee.  
    • NPRR1283: require that any necessary subsynchronous resonance studies be complete and mitigation be in place before the initial synchronization of an ESR, new generation resource or a settlement-only generator before the initial energization.  
    • NPRR1288: simplify the congestion revenue rights (CRR) auction by removing the ability to transact in multiple month strips that create optimization issues for ERCOT.  
    • NPRR1289: provide an option pricing report that would be posted following each CRR auction. The report will contain shadow prices for all biddable source-sink paths for each month within each time of use for the auction period and establish a minimum CRR bid of 1 MW. 
    • NPRR1290, NOGRR278: address several gaps and clarify protocol language to support the RTC+B initiative’s implementation. 
    • NPRR1291: incorporate the Texas PUC’s substantive rule setting a goal for average total residential load reduction into the protocols, specify data exchange methods and formats, and extend the deadline for posting the annual demand response report. 
    • NOGRR272, PGRR121: establish new advanced-grid support requirements — including model-quality tests and unit validation requirements — for inverter-based ESRs with a standard generation interconnection agreement executed on or after April 1, 2025. 
    • PGRR120: prevent generators from interconnecting to the ERCOT grid if they would be radial to a series capacitor under N-1 conditions. 
    • PGRR129: establish requirements for posting the Grid Reliability and Resiliency assessment and update a list illustrating data sets and classifications. 
    • RMGRR183: incorporate several updates that have been implemented as part of previous project improvements to transmission and/or distribution service providers’ Competitive Retailer Information Portal self-service tool. TDSPs will be able to assign weather moratoriums by county name instead of service territory. 
    • SCR832: discontinue and eventually retire a report not being used by market participants. 
    • SMOGRR032: incorporate the Other Binding Document “TDSP Access to EPS Metering Facility Notification Form” to standardize the approval process. 
    • SMOGRR033: incorporate the Other Binding Document “TDSP Cutover Form for EPS Metering Points” to standardize the approval process. 
    • SMOGRR034: remove obsolete gray-box language associated with NPRR1020 (Allow Some Integrated Energy Storage Designs to Calculate Internal Loads). 
    • VCMRR044: set the variable operations and maintenance cost in the mitigated offer cap for hydro generation resources to the real-time systemwide offer cap and the incremental heat rate value to zero. 
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Stakeholders Press IESO on Governance, Transparency

IESO’s plan to give its staff authority to set market parameters without approval by the Board of Directors has sparked a debate over the ISO’s governance and the role of stakeholders. 

The board has been responsible for setting parameters used in the calculation engines since the ISO’s market launch in 2002. But the changed composition of the board and increasing complexity under the Market Renewal Program (MRP) mean the process is “outdated,” Josh Duru, senior market rules and manuals adviser, said in an engagement session Sept. 16. 

The parameters include the maximum market clearing price (MMCP), maximum operating reserve price (MORP), constraint violation penalties and floor prices for variable generators, and “flexible” nuclear. The MRP added the determination of the settlement floor price to the board’s responsibilities. 

Under the proposed change, the parameters would be set by IESO, “with stakeholder input, in the same way in which most other market rule requirements are established,” the ISO said. The board would “maintain its usual oversight and approval function but should not be required to set technical parameters directly.” 

Changes to the Board of Directors

“At market opening, the board had 15 members, nine of which were stakeholder directors. So, at that point in time, they had the … very technical knowledge in order to set these values,” explained Jo Chung, supervisor of market rules and manuals. “But over the years, that has obviously changed, and we don’t have that stakeholder representation directly on the board.” 

The composition of the board changed as part of the 2015 merger of IESO and the Ontario Power Authority. 

The board, which is appointed by the provincial government, currently includes CEO Lesley Gallinger and five others: 

    • interim board Chair David Collie, former CEO of the Electrical Safety Authority of Ontario and a former executive at Burlington Hydro and Hydro One; 
    • Simon Chapelle, who runs a consulting firm focusing on telecommunications and rural economic development and is former municipal councilor for the city of Kingston; 
    • Frank Fazzari, head of accounting firm Fazzari + Partners; 
    • Tom Mitchell, former CEO of Ontario Power Generation (OPG); and  
    • Robert Wong, principal of executive consulting firm Hesketh Sloane Advisory and former chief information officer at Toronto Hydro-Electric System. 

  • Stakeholder Concerns

The proposal to change how parameters are approved led to a lengthy debate during the webinar about the ISO’s governance and transparency. 

“This seems like a pretty dramatic change, despite the fact that it’s being portrayed as something different,” said Akira Yamamoto, director of regulatory and market policy for TransAlta. 

Yamamoto said other grid operators have an “independent adjudicator” involved in approving changes for essential parameters such as price floors and caps. 

Akira Yamamoto, TransAlta | Independent Power Producers Society of Alberta

“That whole process … in Ontario is a little bit more inside baseball, but there was some process,” Yamamoto said. “And I think the entire elimination of it raises pretty significant concerns about how dramatically the market design could potentially be changed at, ultimately, a staff level.” 

Chung insisted the change is not intended to undermine transparency and noted that the MMCP and MORP have not changed in more than 20 years. 

Role for Technical Panel on Manuals

The discussion also touched on questions over what goes into the market rules, rather than the market manual, and when the ISO should bring such changes to the Technical Panel for public discussion.  

The Technical Panel has authority over changes to market rules but not manuals. (See What to Know About IESO.) 

“That’s always been a debate,” said Julien Wu, director of regulatory affairs at Brookfield Renewable’s Evolugen and a former member of the Technical Panel. 

IESO’s Duru said staff are discussing with the panel when it should review market manuals. 

“I’ll be very pleased if I see this matter actually addressed,” responded OPG’s Vladislav Urukov, who represents market participant generators on the Technical Panel. 

Vladislav Urukov, Ontario Power Generation | IESO

“If you remove the board oversight, and also were somehow able to make changes outside of Technical Panel oversight as well, I think that would be quite concerning. I think that there has to be some means for the participants to object and put counterarguments,” he continued. “And to date, I haven’t found that the baseline change process is robust enough and transparent enough and visible enough [to afford] such feedback. 

“What the ISO hasn’t really done to the extent that it ought to have is present analysis — technical analysis — that supports some of the values. … There has to be very robust, extensive analysis that participants can digest and challenge some of the assumptions … to be able to appreciate why the ISO is picking a value. You know, ‘Why is it 100 and not 125?’” 

Urukov added that he is concerned that “if the discussion of the manuals goes in a way that isn’t helpful, then there’s no guarantee that this would actually go to the Technical Panel. And if it’s only an education session, then there is no ability for participants to vote against or object.” 

IESO’s Chung responded that to change the MMCP, “the ISO would have to go through a very robust stakeholder engagement [and] probably include consultants to provide analysis. 

“We would not just change the value lightly. It would be a pretty big process.” 

Julien Wu, Evolugen | Ontario Waterpower Association

Wu said he agreed the board should not be setting technical parameters. 

But, he said, “there’s a difference between saying that the board itself is not going to set the parameters [and] removing that obligation for the board to have some kind of governance review of the parameters.” 

To “remove any kind of board oversight — that takes away the ability of market participants outside of the consultation process to document any kind of concern or disagreement with the output values,” Wu continued. “So maybe there is a middle way where the board itself doesn’t have the authority to set — or responsibility to set — these values, but there’s still a way, either through the [Technical Panel] or anywhere else, where serious concerns can still be [documented] by the market participants.” 

Less Discretion

Yamamoto said IESO should not expect stakeholders to give the grid operator the level of deference they did during the development of the MRP, saying the ISO should return “to a more robust forum.” 

“Saying, ‘Well, this worked for MRP, and therefore we’re going to design the going-forward processes as if we need all this discretion that we had in MRP’ is a wrong-minded approach,” he said. 

IESO: Goal is to Increase Transparency

James Hunter, IESO’s director of legal services, said the ISO is seeking to increase, not reduce, transparency and opportunities for input. 

He noted that the legacy rules do not require that the parameter values be published in either the rules or the manuals and gives the ISO board power to change them without any stakeholder engagement. 

“MRP introduced the constraint violation penalty values into the manuals for the first time in order to increase transparency around them,” Hunter said. “MMCP and MORP have never been published. We’re proposing to add them to the manuals. And the objective is not to request discretion from stakeholders. What we’re trying to do is bring the establishment of these values into alignment with other technical parameters that are in the market rules. 

James Hunter, IESO | James Hunter

“We want to increase transparency by publishing the manuals. … There’s opportunity for stakeholder feedback that has not been the case historically.” 

But, he acknowledged, “I think what we’ve heard today is — in various forms — the suggestion that maybe there’s a need or an opportunity for even more stakeholder involvement into establishing these values. 

“I think we’ll certainly talk about this [at the October Technical Panel meeting] as an instance of the more general question about how to determine where content is placed and rules and manuals.” 

Next Steps

Following the engagement session, ISO officials extended the deadline for written feedback on the proposal by one week to Sept. 30, as requested by Wu. 

The Technical Panel will discuss the proposal Oct. 7, with a scheduled vote Nov. 11, preceding a board vote Dec. 8. 

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Sturgeon Protection Eased as Empire Wind Makes Up Lost Time

The balance between benefit and harm that some regulators try to maintain has been reset again, this time to the potential detriment of an ancient fish slurping through the seabed off the New York coast. 

The state’s Public Service Commission previously had barred developers of the Empire Wind 1 project from laying their export cable in October and November to limit potential harm to the Atlantic sturgeon and shortnose sturgeon. 

But a 23-day federal stop-work order this spring put the offshore wind project behind schedule, and Empire petitioned July 3 to modify the time-of-year restriction and be allowed to work from Oct. 1 to Nov. 15 (21-T-0366). 

The PSC granted the request Sept. 18, finding that alternative approaches would present serious risks to the project or the endangered sturgeons or both, and risk delaying completion of an emissions-free 810-MW power facility the state is counting on to help meet its decarbonization goals. 

The possibility of harming the local ocean ecosystem in the name of protecting the planet is a rallying cry of offshore wind opponents, particularly the prospect of harm to whales. 

The ancient armor-plated sturgeon probably is not what comes to mind when most people think of the ocean. But its bottom-feeding habits and its migratory patterns may place it in the path of submarine cable installation crews in early autumn in the New York Bight. 

The choice here comes down to more fully protecting the fish vs. cleaner air for New Yorkers and a fractional reduction in the carbon emissions blamed for global climate change. 

The choice can be an uncomfortable question for those trying to save the planet, who likely would prefer to do all of the above. None of the three environmental advocacy organizations asked to comment for this story about striking a balance between harms and benefits offered any response. 

Developer Equinor gave NetZero Insider a list of steps it is taking to avoid impacting sturgeons with the cable installation and to mitigate what impacts do occur, but it offered no opinion on the harm-benefit balance. 

A PSC spokesperson explained in detail how the commission and its staff arm, the Department of Public Service, make these decisions and strike a balance: 

“Staff evaluates any modification applying the same thinking used generally throughout our transmission siting proceedings. Staff assess how these modifications will impact the environment and the public, balancing the need to complete projects in a timely and efficient manner that is consistent with approved construction practices, among other considerations, while also seeking to minimize impacts to the greatest extent practicable. This balancing must also consider whether the facility, or in this instance the requested amendment, will serve the public interest, convenience and necessity. Staff also consults with other agencies, such as [the Department of Environmental Conservation and Department of State], as appropriate to inform its review.” 

In this case, the DEC and DOS advised that continuing the cable installation work through October and November might adversely affect the protected sturgeon species but that pausing the work then resuming it in the winter or in 2026 would impact the sturgeon more significantly. 

The PSC approved the change unanimously as part of the Sept. 18 meeting’s consent agenda, the list of dozens of measures approved with a single vote without discussion. 

Ancient and Modern

The PSC record on the Empire Wind export line — two 230-kV HVAC transmission lines running to the Brooklyn waterfront — is a reminder of how complex the state’s regulatory regime can be. 

Empire Wind’s initial application in June 2021 for permission to build and operate the line was followed by 469 filings before the PSC finally approved the request in December 2023. As of September 2025, the record totals 743 filings, some pertaining to details as obscure as site fencing, dust control and unexpected recovery of human remains. Sturgeon protection constitutes only a tiny portion of the record. 

The sturgeons in question are part of a family estimated to have existed in similar form for more than 100 million years. With their bony armor plates, they are a living fossil of sorts, a throwback to the dinosaur era. 

Until the last 200 years or so, the waters of what is now New York were a good place for them to live. The 150-mile Hudson River estuary offered plenty of space to spawn and long expanses of riverbed muck hiding the small creatures they sniff out, slurp up and swallow whole. 

Thanks to overfishing and other conflicts with human activity, the shortnose and the New York Bight distinct population segment of the Atlantic sturgeon both are classified as endangered. But they still swim in the Hudson and the Bight, and they sometimes get caught by fishers pursuing other species or get smacked by passing vessels. 

The jetting and/or plowing of 15.2 nautical miles of trenches in the seabed is another potentially disruptive or injurious activity for them to cope with. 

To reduce the chance of harm, Empire Offshore Wind LLC said in the Sept. 25 revision of its sturgeon plan that it would: 

    • Monitor for acoustically tagged Atlantic and shortnose sturgeon before each start of construction, and suspend or delay construction if a specimen is within 200 meters of the work area.  
    • Station a dedicated visual observer on a monitoring vessel, watching for sturgeon or other protected species. 
    • Report sturgeon detections to researchers and regulators. 
    • Document and report details of injured or dead sturgeon.
    • Use a cushioned hammer, bubble curtain and silt curtain during pile driving. 

Beyond all this, Empire Wind will increase its contribution of mitigation funds to the Hudson River Foundation to assist with its research activities, which Empire expects will provide a net benefit to the two sturgeon species to offset whatever negative impacts the offshore wind project creates. 

Empire said in another PSC filing that it would use as little of the Oct. 1-Nov. 15 window as possible but that it could not predict a completion date. 

An Equinor spokesperson told NetZero Insider that the $7 billion Empire Wind 1 project is more than 50% complete. 

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FERC Denies IBR Clarification, Adds to OER’s Mandate

In separate orders issued Sept. 25, FERC denied a request for clarification of its order approving NERC’s new inverter-based resources ride-through standards, along with updating how the commission processes certain filings from the ERO. 

FERC approved NERC’s IBR ride-through standards, PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers) and PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) in Order 909, issued July 24.  

PRC-029-1 contained an exemption period that would give owners of legacy IBRs — resources already in operation when the standard goes into effect — 12 months after the effective date of the standard to request an exemption to the ride-through requirements. 

The order dealt with IBRs equipped with choppers, which are used in offshore wind projects to protect converters by dissipating excess power during grid faults. It directed NERC to determine whether those resources have challenges meeting the ride-through standards and account for the difficulty — and to estimate the “lead time between adopting IBR specifications and placing the IBR in service.” NERC must submit its determination, along with any other exemptions it deems appropriate, within 12 months of Aug. 28, 2025, the effective date of the order. 

However, the American Clean Power Association and the Solar Energy Industries Association (acting jointly as “Energy Trades”) then filed a request for clarification of the order Aug. 25 (RM25-3). The organizations expressed concern that, with PRC-029-1 to take effect Oct. 1, 2026, the industry would not have enough time to “make legally effective any proposed modifications submitted by NERC” if the ERO waited until Aug. 28 to make its filing, and claimed this “regulatory uncertainty” could create reliability risks in some regions. 

The Energy Trades asked FERC to clarify that NERC did not have to wait until Aug. 28 to file, and even encouraged NERC to file by May 28, 2026, saying “this would give the commission sufficient time to act on the filing.” But FERC declined to issue this clarification, said it considered the 12 months already given “a reasonable time frame for NERC to … make its decision” and expressed confidence the ERO would not delay its filing unnecessarily. 

FERC also pointed out that NERC has several options to address the Energy Trades’ concerns, such as updating its implementation plan for the modified standard or exercising its enforcement discretion to defer enforcement while registered entities implement the requirements. 

OER to Hear More NERC Cases

The commission’s orders also included a final rule reassigning the handling of certain NERC filings from the commission’s Office of Energy Market Regulation (OEMR) to the Office of Electric Reliability (OER) (RM25-13). 

Under current FERC regulations, the director of OER has the authority to approve uncontested applications from NERC, except applications pursuant to sections 39.8 and 39.10 of the regulations, which are handled by OEMR. Those sections respectively involve: proposals to delegate the ERO’s enforcement power to a regional entity; and proposed organizational rules or rule changes, including any RE rule or rule change. 

The change, which will bring all uncontested NERC applications under the purview of OER, was decided because of the office’s “frequent interactions with the ERO and OER’s applicable expertise,” commissioners said in the order. It will take effect immediately upon the order’s publication in the Federal Register. 

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Stakeholder Forum: Collaboration, Determination and Optionality are Keys to Continued Market Expansion in West

By Chris Robinson and Scott Simms

The future Western markets picture is in sharper focus now: We are progressing toward broad participation in two day-ahead markets. Such widespread participation in expanded market offerings may have seemed doubtful previously — even as recently as 10 years ago at the start of the Western Energy Imbalance Market (WEIM). Collaboration, determination and optionality have been critical to getting us to this pivotal point. 

Utilities and other market participants have recognized the potential benefits of expanded market participation and have worked hard to develop market options that meet their needs — including creative solutions that do not require participation in an RTO, new governance structures, and market designs that are compatible with continued OATT transmission service. Developing such options has facilitated organized market participation to grow, both geographically and in the breadth of services offered. 

Chris Robinson

The passing of AB 825 marks a significant milestone for planned EDAM participants, laying the groundwork for implementing the Pathways “Step 2” proposal. This proposal will establish a new regional organization that will partner with CAISO to implement the Extended Day-Ahead and Western Energy Imbalance markets. At the same time, PacifiCorp and Portland General Electric have had their EDAM tariffs approved by FERC, and all signs indicate a 2026 go-live date. 

Meanwhile, Markets+ also is moving forward with implementation. Nine utilities have made substantial financial commitments to secure the development of the market, with more utilities indicating their intent to join. In addition, many more participants and stakeholders are actively engaged in this final implementation phase. The market go-live is in 2027. 

While we know there is frustration among some parties that a single market could not be achieved, ultimately the region should celebrate the collective progress that these markets represent and respect the decisions that each entity has made regarding its individual participation.   

For entities such as PPC, Tacoma and BPA (as described in their Day-Ahead Market Policy Record of Decision, Appendix B), the risk of participating in a market that continues to have statutory ties to a single state or subset of market participants is untenable. 

Scott Simms

Even under the Pathways governance proposal — which is enabled by California AB 825 — CAISO continues to retain statutory obligations to the people of California and legally must be the operator of EDAM in order for California entities to participate. We respect the decision some entities have made that this level of independence is sufficient for their participation in EDAM, but it continues to be a deal-breaker both for us and for many others.   

It is our hope that after many participants have made their market decisions, both market tariffs have been approved by FERC, governance structures are known, and implementation efforts are under way, we can all turn our attention to good faith efforts to make the soon-to-coexist market approaches in the region as successful as possible. 

Achieving the additional efficiency and access to resources that will be offered by either market will benefit the region much more than having utilities not participating in organized markets — which is a likely outcome without the optionality that has been developed. As long as entities across the West remain committed to continued regional trade, coordination and reciprocal efforts to enable market participation, there can be significant benefits for the region at large. 

We applaud our colleagues whose hard work, determination and collaboration were able to bring AB 825 over the finish line. Our hope is that we collectively can bring that same energy and genuine spirit of collaboration to the hard work needed ahead to successfully implement both markets, including seams negotiations when the time is right. 

Chris Robinson is general manager of Tacoma Power and is the Public Power Council Executive Committee chair. 

Scott Simms is the CEO & executive director of the Public Power Council. 

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Advocates Defend Energy Efficiency Programs in Massachusetts

Climate and consumer advocates are calling on Massachusetts lawmakers to preserve the state’s energy efficiency programs as legislators work to develop an energy affordability bill in response to high gas and electricity costs over the past winter. 

Advocates have expressed concerns that lawmakers may roll back efficiency spending to provide short-term relief to ratepayers. They defended the state’s Mass Save efficiency program at a hearing held by the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) on Sept. 25. 

While Massachusetts’ energy efficiency programs frequently rank among the best in the country — with the state placing second on the American Council for an Energy-Efficient Economy’s (ACEEE’s) 2025 State Energy Efficiency Scorecard — the programs have drawn increased scrutiny over the past year amid increased affordability concerns. 

Over the past winter, sustained lower-than-average temperatures drove high energy prices across New England. In Massachusetts, higher gas supply rates coincided with increased distribution rates, which were driven largely by investments in Mass Save and a state program to replace leaky gas pipes. 

Following public pressure for immediate rate relief, the Massachusetts Department of Public Utilities in late February ordered $500 million in cuts to the Mass Save budget. The utility-administered program is funded through charges on gas and electricity rates, and it offers rebates and incentives for building insulation, efficient appliances and heat pumps.  

While the 2025/27 budget — totaling $4.5 billion after the cut — still is higher than the $4 billion for 2022/24, the reduction drew some criticism from efficiency advocates, who argued it would reduce the long-term benefits of the investment. 

The Massachusetts Department of Energy Resources estimated the original $5 billion investment would return $13.6 billion in overall benefits, including $5.4 billion in direct energy savings. The 2025 ACEEE scorecard estimated that Mass Save investments have returned $3.50 for every dollar invested since 2013. 

Political battles over energy efficiency funding are not limited to Massachusetts; Rhode Island Energy has proposed to cut its program’s funding by 18% in 2026 compared to 2025 levels. 

Meanwhile, the federal One Big Beautiful Bill Act eliminates significant tax credits for HVAC equipment — including heat pumps, electrical upgrades and insulation — at the end of 2025. 

At the TUE Committee hearing Sept. 25, advocates argued that additional efficiency spending must not be put on the chopping block as lawmakers look for near-term rate savings. 

Amy Boyd Rabin, vice president of policy and regulatory affairs at the Environmental League of Massachusetts, advocated for legislation to “create a mechanism to fund energy efficiency and decarbonization efforts beyond our electric and gas bills, taking the burden of Mass Save off of ratepayers’ backs, without hurting the programs or the benefits they can deliver for consumers and the climate.” 

She estimated that Mass Save “has reduced Massachusetts’ energy use by 13.9 billion kWh annually, or 28% of current electricity sales. That’s equivalent to the annual production of all our renewables in ISO-NE each year.” 

Boyd Rabin added that, since its inception, the program has provided “$40.3 billion in benefits” from $11.8 billion in spending, a 3.4-to-1 return on investment. 

“No financial adviser on Earth would urge us to pull out of a fund returning $3.40 for each dollar you put in,” Boyd Rabin said. 

Kyle Murray, director of state program implementation at the Acadia Center, emphasized the regionwide wholesale markets price suppression benefits of these investments. 

He pointed to the ISO-NE capacity scarcity event June 24, when locational marginal prices spiked to $1,110/MWh between 6 and 7 p.m., and highlighted an Acadia analysis estimating that demand reductions associated with behind-the-meter solar saved the region $19.4 million during the day. (See Extreme Heat Triggers Capacity Deficiency in New England and Behind-the-meter Solar Shines in ISO-NE Capacity Deficiency Event.) 

“ISO-NE does not similarly track the impact of energy efficiency. However, make no mistake: But for those critical investments we have made in energy efficiency over the years, those price spikes would have been dramatically worse,” Murray said. 

Responding to public comments, Sen. Mike Barrett (D), TUE co-chair, spoke favorably about energy efficiency investments, noting that, by statute, Mass Save spending is justified only “when it’s the least expensive alternative” to meeting power demand.  

He expressed concern that, while the costs associated with Mass Save are outlined on electricity bills, the savings are not easily apparent to ratepayers, masking the program’s benefits. 

“Mass Save is not Robert Redford; Mass Save is a character actor that gets lost in the scene precisely because they’re effective,” Barrett said. 

Rep. Mark Cusack (D), who is in his first year as the House co-chair of the TUE Committee, largely did not respond in substance to the public comments at the hearing, which were overwhelmingly supportive of preserving or expanding the state’s energy efficiency and building decarbonization programs. 

Rep. Jeffrey Turco (D) appeared more skeptical about efficiency investments, saying that “to the consumer, we keep hearing that we’re saving $3.41 for every dollar invested, but the cost of electricity is going up every year, and it’s by design.” 

Increasing the cost of electricity in the short term in pursuit of long-term benefits causes consumer frustration “because the utility keeps going up, and despite saying, ‘Yes, we’re saving you money,’ the proof is not in the pudding on a monthly basis,” Turco said. 

In response, Murray said, “One of the most difficult challenges of energy efficiency is that it’s difficult to prove a negative.” 

He stressed that while the value of efficiency can be hard to quantify precisely, “if we don’t continue to do this, you’re asking constituents in five, 10, 15, 20 years to bear significantly higher costs.” 

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Pathways to Engage Broad Set of Stakeholders to Select Independent RO Board

The West-Wide Governance Pathways Initiative soon will begin the nomination process to select the initial board of the independent regional organization (RO) that will govern CAISO’s energy markets, staff said during a Sept. 26 meeting a week after the California legislature approved a bill to implement the initiative’s plans.

California Gov. Gavin Newsom signed AB 825 into law on Sept. 19, allowing CAISO and investor-owned utilities to participate in the independent Regional Organization for Western Energy (ROWE), which is being designed by the Pathways Initiative to oversee CAISO’s Western Energy Imbalance Market and soon-to-be-launched Extended Day-Ahead Market. (See Newsom Signs Calif. Pathways Bill into Law.)

One goal is to remove what some see as a barrier to wider participation in CAISO markets by ensuring the markets are not governed solely by California, but rather by stakeholders from all Western states.

During the Sept. 26 meeting, Pathways Launch Committee Co-Chair Kathleen Staks reiterated statements she made earlier in the week that representatives from nine sectors will advise in nominating members to ROWE’s initial board. (See New Challenges Await Pathways After Success in Calif. Legislature and DER Representatives Get a Seat at the Pathways Table.)

The sectors include:

    • EDAM entities
    • WEIM entities
    • ISO participating transmission owners
    • Non-IOU load serving entities serving load from WEIM or EDAM
    • Public interest organizations
    • Independent power producers, independent transmission developers and marketers
    • Consumer advocates
    • Large commercial and industrial customers
    • Distributed energy resources

“The goal is to have that board selection process led by the nominating committee occur over the first six months of 2026, with a goal of seating that initial board in July of 2026,” Staks said.

The initiative’s Formation Committee also is reviewing feedback on ROWE’s proposed bylaws and policies. The committee plans to release revised bylaws in November. (See Pathways Initiative Unveils RO Proposed Name, Bylaws.)

Nine state utility commissioners and energy officials from five different states launched the Pathways Initiative in a July 2023 letter outlining their desire for increased coordination and expansion of electricity markets in the West. (See Regulators Propose New Independent Western RTO.)

In a follow-up letter published Sept. 26, regulators from Arizona, California, New Mexico, Oregon and Washington congratulated the Launch Committee.

“We write once more to appreciate your dedication to the vision we articulated and celebrate the milestones you have achieved,” the regulators wrote. “In particular, we note that pursuant to Pathways Step One, the Western Energy Markets Governing Body now holds primary filing rights for the tariff governing the energy imbalance and day-ahead markets. This approach incorporates customer protections across the market footprint. It also balances the needs of entities across the region to have transparency and certainty when committing to a day-ahead market.”

The regulators also touted the benefits of an independent Western market, saying customers could save over $7 billion.

“We are moving into an era of unprecedented growth in electrical demand, new weather extremes, challenges procuring new generation and cost pressures. Indeed, affordability and reliability are central concerns in all our states,” the regulators wrote. “This legislation provides a critical opportunity for us to address these issues, and we appreciate the time you have invested in realizing this critical milestone.”

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Wright: DOE Working to Stop More Coal Plants from Retiring

U.S. Energy Secretary Chris Wright said his department is working with utilities around the country to keep more coal plants slated for retirement open to help meet rising demand from data centers and other new large loads.

“What we’re doing now is starting dialogues with utilities across the country, and I will tell you, there’s a large amount of them,” Wright said at an event hosted by Reuters during New York Climate Week on Sept. 25. “They’re saying, ‘Thank God.’”

At the time of President Donald Trump’s second inauguration, there were plans to close up to 100 GW of firm generating capacity. Some of those plants — the older, smaller and least efficient — will shut down, but the Department of Energy is committed to keeping others open, Wright said. The interconnection queues contain mostly wind and solar, with plans for just 22 GW of firm capacity to be built to replace the 100 GW at the start of this year.

“We think we need 100 GW more of firm capacity in the next five years,” Wright said. “So, if we got to get up plus 100, we certainly don’t want to dig a hole to minus 78.”

DOE has used its authority under Section 202(c) of the Federal Power Act to keep open two firm power plants in states with Democratic governors: the Campbell coal plant in Michigan, and the dual-fuel Eddystone in Pennsylvania. Its use of that authority broke with tradition as DOE has used the law mainly to keep plants running when needed for reliability and pollution regulations otherwise would limit their output.

Energy Secretary Chris Wright | DOE

Both of those orders were for this summer, and DOE since has extended them. Michigan Attorney General Dana Nessel and environmental nonprofits have challenged the Campbell order in a case that is working its way through the D.C. Circuit Court of Appeals. (See Opponents Take DOE to Court over J.H. Campbell Retirement Delay.)

The Sierra Club, which is one of the groups challenging the Campbell order, responded to Wright’s comments, saying Big Tech companies behind the data centers that are a main contributor to load growth will be complicit in the “plan to take money out of everyday Americans’ pockets and give it to the fossil fuel industry.”

Consumers Energy — which owns the Campbell plant and had procured replacement capacity for it after a ruling from the Michigan Public Service Commission in 2022 to shut it down — said it would cost its customers $29 million in just over a month of operation under the 202(c) order. (See DOE Extension of Michigan Coal Plant Cost $29M in 1st Month.)

“Donald Trump and his fossilized friends have come up with yet another plan to force hardworking Americans to pay off Big Tech’s energy bills to the tune of billions of dollars — all to prop up a few coal executives,” Sierra Club Senior Adviser Jeremy Fisher said in a statement. “Clean solar and wind energy are the cheapest and fastest sources of electricity, and yet this administration is putting its foot on the neck of a huge source of jobs.”

DOE filed a substantive response to requests for rehearing Sept. 8. It noted that 1,575 MW of natural gas and coal-fired capacity already had retired in MISO since summer 2024.

“In the emergency order, the secretary determined that continued operation of the Campbell plant is necessary to best meet the emergency and serve the public interest for purposes of FPA Section 202(c),” DOE said in the rehearing order. “This determination was based on the insufficiency of dispatchable capacity and an anticipated increase in demand during the summer months, resulting in a risk to public health and safety caused by the potential loss of power to homes and local businesses in areas that may be affected by curtailments or outages.”

Opponents argue the department exceeded its authority in the 202(c) order for Campbell, but the department said it was responding to the potential “shortage of electric energy or of facilities for the generation or transmission of electric energy,” which is clearly allowed in the law.

The department also argued it is not required to work with states before it issues such an order, despite language in the DOE Organization Act that it consult with impacted jurisdictions “where practical.” It argued it often is not practical before taking emergency action.

Michigan, other MISO states and the environmental groups all argue that no real emergency existed to warrant the 202(c) action, but the FPA gives the secretary the authority to determine that an emergency exists.

“Section 202(c)(1) delegates a wide degree of latitude for the secretary to determine the existence of an emergency, ‘either upon its own motion or upon complaint, with or without notice, hearing or report,’” DOE said in the rehearing order. “Beyond providing exemplar categories of where an ‘emergency exists,’ the statute is silent on any additional requirements that must be satisfied.”

The Maryland Office of People’s Counsel wants to intervene in the Campbell case, but DOE filed against that motion Sept. 4, arguing it is not an aggrieved party because the emergency order will not cost the state’s ratepayers anything.

The OPC responded Sept. 12 arguing that the interconnections between MISO and PJM mean ratepayers in Maryland will be directly affected by keeping the plant running.

The order requires the continued use of a high-cost resource that will increase prices in both MISO and PJM, the office argued. It is difficult to quantify these costs, but “even a small amount of money is ordinarily an ‘injury,’” the OPC said. “Maryland ratepayers are captive PJM consumers who, because of the order, cannot benefit from more economically efficient power imports and exports between RTOs, despite a planned, lower-cost replacement for the Campbell plant.”

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Bipartisan Transmission Permitting Reform Bill Introduced in House

U.S. Reps. Scott Peters (D-Calif.) and Andy Barr (R-Ky.) have introduced the Streamlining Powerlines Essential to Electric Demand (SPEED) and Reliability Act, which is meant to speed up the siting and permitting of transmission lines. 

“We cannot wait a decade-plus for individual transmission lines to be approved if we don’t want to fall behind China and our adversaries,” Peters said in a Sept. 26 statement. “This bill will lower costs for consumers, improve reliability and help secure America’s energy independence.” 

The bill would alter the National Interest Electric Transmission Corridor (NIETC) program, which allows the Department of Energy and FERC to work together to designate transmission corridors that grant the commission backstop siting authority for lines inside them. The process was created in 2005 and updated during the Biden administration, which led to FERC Order 1977, but not one line has been built using it. 

The SPEED and Reliability Act would remove the ability of the Secretary of Energy to designate corridors and also would centralize environmental reviews at FERC and include additional guardrails to protect customers, benefit local communities and respect state authority. 

FERC could issue construction permits for individual NIETC lines that reduce grid congestion, improve reliability, and offer customers clear economic and reliability benefits. 

The reliability benefits would include facilitating compliance with mandatory reliability standards, cutting the risk of lost load and facilitating compliance with resource adequacy requirements on file with FERC, or offering similar material improvements such as lower outage risks as achieved through increased geographic or resource diversification. 

The bill includes protections for consumers by allocating costs to beneficiaries only. Customers who get no, or just trivial, benefits could not be involuntarily allocated costs from NIETC lines under the bill, though nothing prevents utilities from seeking voluntary agreements with customers on cost allocation. 

The bill specifically pre-empts the siting and cost allocation for lines that go into ERCOT’s territory. It would preserve current law by ensuring states have at least one year to respond to applications before firms can seek approval from FERC. And it would mandate that FERC engage with states, tribes and private property owners throughout the process. 

The bill would apply to any transmission lines at 100 kV or above that would ship power for interstate commerce, including those on the Outer Continental Shelf, or foreign commerce. 

The two congressmen’s offices said the bill would help cut costs for customers through lower congestion and improved reliability/transfer capability during extreme weather events. 

The bill also would help with economic development, as industries like artificial intelligence and microchip manufacturing lead to higher demand, with transmission enabling more development across the country including rural areas, they said. 

“AI data centers and advanced manufacturing are at the core of America’s economic future, but they can’t run without reliable, affordable power,” Barr said in a statement. “The SPEED and Reliability Act cuts red tape and builds the transmission lines we need to lower costs and ensure we stay ahead of China in the race for AI.” 

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DER Representatives Get a Seat at the Pathways Table

As the West-Wide Governance Pathways Initiative dives into its next phases, a wide variety of stakeholders will serve as advisers — including representatives of the distributed energy resource sector.

“Developing the rules for resources participating in the market will … be shaped by that DER sector representative — something that doesn’t exist anywhere else in the country,” said Brian Turner, Western regulatory director for Advanced Energy United. Turner serves on the Pathways Launch Committee.

Turner’s comments came during a Sept. 23 meeting of Nevada’s Regional Transmission Coordination Task Force (RTCTF).

Distributed energy resources include rooftop solar and storage, electric vehicles and smart devices such as thermostats, Turner said. They can be aggregated into virtual power plants (VPPs) that can provide a boost to the grid at critical times.

AEU argued in a 2024 report that VPPs should play a greater role in resource planning in Nevada. (See NV Energy Should Do More to Tap VPP Potential, Report Says.)

Pathways stakeholder committee members from the DER sector “will help represent the interests of what will be hundreds of thousands of devices across Nevada being dispatched into the market,” Turner said.

During its Sept. 23 meeting, the RTCTF heard updates on the Pathways Initiative as well as the Western Resource Adequacy Program and activities at CAISO and SPP.

The group, created through Senate Bill 448 of 2021, advises the governor and state legislature on energy issues, including those related to utilities joining an RTO.

Governance Transition

The Pathways Initiative aims to transition the governance of CAISO’s markets from a board appointed by California’s governor to an independent “regional organization” (RO). One goal is to remove what some see as a barrier to wider participation in CAISO markets, including the Extended Day-Ahead Market (EDAM) expected to launch in 2026. CAISO also runs the real-time Western Energy Imbalance Market (WEIM).

California Gov. Gavin Newsom on Sept. 19 signed Assembly Bill 825, which helps clear the way for the transition to RO governance. (See Newsom Signs Calif. Pathways Bill into Law.)

Kathleen Staks, co-chair of the Pathways Initiative’s Launch Committee and executive director of Western Freedom, told the task force that Pathways is hoping to file incorporation documents with the IRS in January 2026. Once the RO board is seated, it will negotiate with CAISO on a contract to provide market services.

Representatives from nine sectors will participate in the nominating committee that chooses RO board members as well as a stakeholder committee that will identify and prioritize initiatives for the RO, Staks said. Some of the sectors represented will be new for the West, she said. In addition to DER sector representatives, the large industrial and commercial customer sector and the customer advocate sector will be represented.

Other sectors represented on the Stakeholder Representatives Committee include EDAM entities; WEIM entities; CAISO participating transmission owners; and independent power producers, independent transmission developers, and marketers, according to the Launch Committee Step 2 final proposal in November 2024. Some sectors may have more than one representative on the committee.

SPP Responds

Following a presentation from SPP, RTCTF Chair Jennifer Taylor of Enel North America asked what impact the passage of AB 825 would have on SPP. SPP’s Markets+ is competing with CAISO’s EDAM for day-ahead market participants, and SPP has pointed to the governance of Markets+ as one of its advantages.

Jim Gonzalez, SPP’s senior director of seams and Western services, said SPP had been “built on a foundation of independen[t] governance.”

“We’ve had decades of experience administering regional multi-state governance, delivering energy solutions across diverse jurisdictions,” Gonzalez added. “That’s something that’s been a constant throughout not just the RTO but these different contract services.”

With CAISO markets now moving toward independent governance through the Pathways Initiative, some are urging utilities that planned to join Markets+ to rethink their decision.

In Colorado, for example, California-led governance has been a key barrier to the state’s large utilities joining a West-wide market, according to a Sept. 22 news release from Advanced Energy United, Western Resource Advocates and the Environmental Defense Fund. Public Service Company of Colorado received state regulatory approval in July to join Markets+. (See Colo. PUC Approves PSCo’s Markets+ Participation.)

Passage of AB 825 means “the pathway to a bigger, better regional electricity market has opened in the West,” the groups said.

“Colorado decision-makers and utilities should be rethinking prior decisions in light of this development so the state can have the strongest, most reliable, flexible, clean and affordable grid,” Turner of AEU said in a statement.

But some market participants seem unlikely to budge from their Markets+ choice. Bonneville Power Administration previously told RTO Insider that despite the passage of AB 825, it believes Markets+ will provide greater customer benefits. (See New Challenges Await Pathways After Success in Calif. Legislature.)

In Nevada, NV Energy has expressed a preference for participating in EDAM, a step that requires approval from state regulators.