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December 16, 2025

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SPP, Stakeholders Kick off Markets+ Phase 2 Development

PORTLAND, Ore. — Development of SPP’s Markets+ is in full swing. Financing has closed. Work teams and their governance structure have been assembled to implement the design. Various entities are registering for the market.

Further proof of the seriousness of the work ahead came with the new faces sprinkled among attendees for the first in-person Phase 2 meeting of the Markets+ Participant Executive Committee (MPEC). One committed participant sent its entire project team.

Jim Gonzalez, SPP’s director of seams and Western services, said the developments mark a sea change from a 2022 meeting in Phoenix where staff “pitched the idea” of offering market options in the Western Interconnection.

“That was really the first big stakeholder meeting SPP had with some interested parties in the West just describing what we thought we could do, how we’d like to work together to see if there was a way to create a day-ahead and real-time market for the West,” Gonzalez told RTO Insider after the Aug. 12 MPEC meeting. “Seeing the stakeholders really take ownership of their market and being comfortable making decisions has been really exciting to watch.

“It’s exciting for me thinking about not just the governance, but actually implementing the market itself, having the structure in place to be able to move forward to implement and make the necessary changes we need to as we work through that process,” he added.

Joe Taylor, with Xcel Energy’s Public Service Company of Colorado (PSCo), has seen market proposals in the West come and go, including a pair of SPP initiatives in the past decade. This one seems different, he said.

“[We] have a dedicated group of utilities, special interest groups, stakeholders,” he said. “It’s been funded. It’s a real market. We’re moving toward the end goal, and it gets a lot more serious and a lot more engagement as folks start to see what impact these decisions are going to have on what this market looks like.”

PSCo is one of five balancing authorities planning to be part of Markets+ when it goes live in October 2027, joining Arizona Public Service, Powerex, Salt River Project and Tucson Electric Power. The company received permission from the Colorado Public Utilities Commission to join Markets+ in July. (See Colo. PUC Approves PSCo’s Markets+ Participation.)

Pacific Northwest balancing authorities Bonneville Power Administration, Chelan County Public Utility District, Grant County PUD, Puget Sound Energy and Tacoma Power have deferred market participation until at least 2028. The PUDs and Tacoma Power are BPA preference customers dependent on the agency’s transmission system, as are many entities in the region.

The utility BAs, with the exception of PSCo, have all made funding commitments to SPP. PSCo is waiting on an official order from the Colorado commission before agreeing to its portion of Phase 2’s $150 million cost.

Asked about the significance of PSCo joining Markets+, Taylor acknowledged its importance.

“We’re a fairly large utility with respect to this footprint, so I’m thrilled to be able to support my friends and colleagues throughout the West in their commitment,” he said.

Staff said 14 new entities have joined Markets+ during Phase 2, with two dropping out. That leaves 40 active in the phase, having registered— some several times — as various types, with 33 planning on being ready for go-live. The participant categories include:

    • BAs or transmission service providers (5)
    • Load-serving entities (9)
    • Market participants (25)
    • Stakeholders (29)

Participants have until Sept. 1 to register as a BA, Oct. 1 as a transmission service provider and Dec. 1 as a market participant.

Network and commercial modeling has begun in the background. Connectivity testing, the first step before market trials, is scheduled to begin Oct. 1.

‘It All Takes Governance’

The meeting marked the official kickoff for the second phase’s governance. Based on the increased interest from Phase 2 participants, SPP said staff worked with MPEC and the Markets+ Interim Governance Task Force (MIGTF) to expand the task force from the current nine members to as many as 18. The scope change ensures an equal balance among investor-owned utility, public power and independent representatives, accommodating growth as the sector balance allows.

“It all takes governance to actually make this happen,” Gonzalez said.

The task force is responsible for reviewing and recommending changes to governance issues before they go to MPEC during Phase 2. It reports to the committee, along with working groups focused on transmission, market design, seams and reliable operations.

SPP staff will solicit MPEC representatives for public power nominees and send them to the full committee for approval of a balance roster before the next MIGTF meeting.

MPEC approved the rosters for the various working groups and task forces during the meeting, setting their limits at 21 or 24 people. Five of the groups include representation from the Markets+ State Committee (MSC), comprised of regulatory commissioners that are monitoring and providing input into the market’s development.

The implementation timeline for Markets+ | SPP

With several contested seats among the stakeholder bodies, SPP staff again will ask MPEC reps for nominees in underrepresented sectors. They will provide the committee with a list of nominees and bios for each stakeholder group; MPEC will vote on the nominees by email.

“It’s a good problem to have,” MPEC Chair Laura Trolese, with The Energy Authority, said in alluding to the lack of nominees during the first phase.

The committee approved all the roster expansions unanimously, with only four abstentions in all. In most cases, the current stakeholder chairs and vice chairs will continue in their roles until November. New leadership nominees will be placed when MPEC gathers in Tempe, Ariz., Nov. 12-13.

Following the meeting, most staff and stakeholders stayed for an in-person meeting of the Markets+ Change User Forum (MCUF). It will serve as a hub for coordinating participant efforts to implement process or system changes affecting market functions, particularly during market trials.

APS’ Elizabeth Goodman and Powerex’s Derek Russell were seated as the MCUF’s chair and vice chair, respectively.

SPP secured the $150 million Phase 2 funding agreement in June after receiving FERC approval of the tariff earlier in 2025. (See SPP Launches Markets+ Phase 2 With $150M Secured.)

MSC Funded for Phase 2

Arizona Commissioner Nick Myers, the MSC’s chair, told the MPEC that the commissioners have completed a memorandum of understanding with SPP that sets up a fund mechanism for Phase 2. The Western Interstate Energy Board (WIEB), a regulatory organization of 11 Western states and 2 Western Canadian provinces, supported the MSC during Phase 1.

“We’re funded,” Myers said. “WIEB has been supporting the MSC on [its] own since the inception of Markets+, so we’re glad to have that MOU in place. It further solidifies SPP’s support, and all of your support, for the MSC involvement in Markets+.”

Myers said the MSC will ask MPEC to direct the MIGTF to work with the regulators in investigating the election process for the Markets+ Independent Panel that eventually will oversee the market.

“There was a little disconnect there, and we just want to make sure that any holes might be plugged,” he said.

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DOT Issues Guidance to Resume NEVI Funding

An ongoing squabble over a slow-moving EV charger grant program has turned a new page with the Trump administration’s release of new guidance for states to claim funding. 

Transportation Secretary Sean Duffy on Aug. 11 issued interim final guidance for the National Electric Vehicle Infrastructure (NEVI) Formula Program, a Biden administration initiative that allocated $5 billion to states to help build a national network of electric vehicle chargers in hopes of reducing range anxiety and increasing EV adoption by American drivers. 

None of this was a priority for President Donald Trump. The Federal Highway Administration suspended approval of state EV infrastructure deployment plans shortly after he returned to office. 

The Government Accountability Office faulted the move in May and a federal judge issued a preliminary ruling against the Trump administration in late June. 

Seven weeks later, Duffy’s announcement Aug. 11 had a bit of a grudging tone: “Our revised NEVI guidance slashes red tape and makes it easier for states to efficiently build out this infrastructure. While I don’t agree with subsidizing green energy, we will respect Congress’ will and make sure this program uses federal resources efficiently.” 

The Sierra Club, which had joined several other environmental advocacy groups and state attorneys general in the court challenge, called the revised guidance unnecessary and wasteful: “It’s ironic that this guidance was sold as cutting red tape, yet all it has accomplished is more than half a year of needless delay. The guidance only restates requirements already in law, making clear that the real purpose of the Trump administration’s freeze was to try to stall electric vehicle momentum.” 

The administration, it added, “is still illegally withholding billions Congress dedicated to EV charging.” 

NEVI was created in the Infrastructure Investment and Jobs Act of 2021. Its funding authorization is little more than a rounding error in the massive financial commitments made for the clean energy transition during the tenure of President Joe Biden. Also, it was slow to take off. 

Announcements by the Joint Office of Energy and Transportation tended to run in the single digits — the first NEVI-funded charging station had opened in Colorado, three had come online in western Wisconsin, and one was opened in Texas. 

In its final quarterly update, on Nov. 26, 2024, the Joint Office said the number of public charging ports nationwide had doubled during Biden’s tenure to nearly 204,000 — 126 of which were at 31 NEVI-funded stations in nine states. 

But 41 states had released solicitations, the update noted, and 35 of them had issued conditional awards or reached agreements for more than 3,560 fast-charging ports at more than 890 locations. 

On Feb. 6, the Highway Administration suspended approvals of NEVI grants. It issued a spreadsheet showing that as of that date, $526.6 million had been obligated to 46 states, the District of Columbia and Puerto Rico, but they had spent only $44,428,296.71. 

On May 7, the states filed their complaint in U.S. District Court in western Washington (2:25-cv-00848). The advocacy groups later joined as intervenor plaintiffs. 

On May 14, Duffy publicly called out the states for their court challenge, noting that most had not spent even a third of the funds allocated to them. 

On May 22, the GAO issued a determination that the Highway Administration was not authorized to withhold NEVI appropriations, due to provisions of the Impoundment Control Act. 

On June 3, the White House Office of Management and Budget sent a directive to the Department of Transportation attacking the GAO as a partisan entity trying to undermine Trump’s reforms, asserting that GAO’s opinion was wrong on both the facts and the law, and saying that DOT need not change its approach to NEVI. 

On June 24, U.S. District Judge Tana Lin partly granted the states’ motion for a preliminary injunction against the Trump administration withholding NEVI funds as the case continues. 

On Aug. 11, the Sierra Club said it will continue its fight, as well, because the administration “is still illegally withholding billions Congress dedicated to EV charging.” 

Other organizations were more complimentary about the interim final guidance issued on NEVI. 

NATSO, a trade organization representing truck stops and travel centers, and SIGMA, representing fuel marketers and retailers, said the new guidance will help direct funds to sites best suited to deliver reliable, well-maintained charging infrastructure. “Ensuring that charging stations are owned and operated by private entities with a vested interest in the site’s success reduces the risk of stranded assets and minimizes the potential for underutilized or unreliable infrastructure,” they said. 

The Zero Emission Transportation Association said 2025 is projected to the best year yet for charging infrastructure expansion, and said NEVI will help fill in gaps that remain: “The new interim final guidance provides important regulatory certainty for the companies and state departments of transportation that are implementing this program on the ground. NEVI was designed for states to distribute funding based on their specific needs. Finalizing the guidance ensures that this important work will continue.” 

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Trustees: NERC ‘Front and Center’ Addressing Reliability Challenges

CALGARY, Alberta — Opening the Aug. 13-14 meeting of NERC’s Board of Trustees, Chair Suzanne Keenan told attendees that “the visibility of the work we are doing … is off the charts right now … and our work is front and center” in the thinking of U.S. and Canadian policymakers.

Keenan reminded the audience that electric reliability has become a major concern because of the rapid spread of intermittent generation, worries about the grid’s transmission capacity and growing cyber threats from foreign adversaries like China and Russia.

“To keep up is requiring transformational change, such as the Modernization of Standards Processes and Procedures Task Force [MSPPTF]; our work on large loads and the gas-electric interface; rebuilding our compliance program to incorporate abeyance; expanding our registration for small [inverter-based resources]; renovating our approach to reliability assessments; and more,” Keenan said. “Any one of these would be the defining project in most organizations, yet NERC and the regions, with the support and engagement of our members, are tackling them all at once, head-on.”

In his own remarks, Electricity Canada CEO Francis Bradley reflected on the turmoil of the U.S.-Canada relationship since the inauguration of President Donald Trump in January. He praised the ERO for continuing to prioritize collaboration with Canadian regulators and utilities despite the two countries’ trade disagreements.

Electricity Canada CEO Francis Bradley (closest to camera) addresses NERC’s trustees. | © RTO Insider 

“I’m grateful that NERC exists. If it didn’t exist, we would have to create it,” Bradley said. “Electricity may be the example of what an effective cross-border relationship looks like; the stability amid the chaos. But let’s also make sure we don’t become complacent about that relationship and that we continue to look for ways to foster better and better collaboration.”

Board Approves 2026 ERO Budgets

Trustees voted to approve the proposed 2026 Business Plan and Budget for NERC, along with those of the regional entities and the Western Interconnection Regional Advisory Body (WIRAB), the day after their approval by the board’s Finance and Audit Committee (FAC). The budgets will be filed with FERC later this month.

When presenting the budgets to the FAC, CFO Andy Sharp reiterated that NERC is approaching 2026 as a “bridge year” between its current three-year plan, which concludes in 2025, and the next one, which will be developed during 2026 and begin in 2027. (See 2026 to be ‘Bridge Year’ for NERC Budget.) The ERO had planned to create another plan this year but decided to wait, considering the economic and regulatory uncertainty that has grown since Trump returned to the White House.

NERC’s 2026 budget is set to increase $5.3 million over the previous year to $128.3 million, while the assessment is to rise by the same amount to $113.7 million. The remaining budgeted expenses will be covered by NERC’s other funding sources, including fees from the Electricity Information Sharing and Analysis Center’s Cyber Risk Information Sharing Program and vendor affiliate program.

The total ERO budget — including NERC, the REs and WIRAB — is expected to grow $15.9 million to $320.5 million, with the total assessment climbing $18.7 million to $289.6 million. WIRAB plans the smallest increase, with $30,000 — for a total budget of $860,000 — while the Northeast Power Coordinating Council is expecting the largest increase at $2.7 million, for a total of $28.4 million.

Standards Modernization Update

Georgia System Operations CEO Greg Ford, chair of the MSPPTF, said the task force is “confident that we will deliver” recommendations for revamping the ERO’s standards development process by the February 2026 board meeting.

Updating trustees on the task force’s progress since its formation, Ford first noted the issuance of a white paper in July laying out several possible changes applicable to the standard initiation, development and balloting phases. (See NERC Task Force Members Share Standards Modernization Progress.) Proposals include a biannual review process for potential standards projects, centralizing all submissions through NERC’s Reliability and Security Technical Committee and using artificial intelligence for various amounts of work in the drafting process.

NERC is accepting comments on the white paper through Aug. 27. It held a series of webinars after its publication to explain the proposals in more detail and answer questions from industry stakeholders. Ford said nearly 3,200 attendees joined the webinars, showing the level of interest among the industry.

NERC CEO Jim Robb and Georgia System Operations CEO Greg Ford speak before the Member Representatives Committee meeting. | © RTO Insider 

“That tells us a couple of things. It tells us we’re hitting on the right marks; they’re interested; and they’re willing to give us the comments to help us mold the actions that we’re going to bring to the board,” he said.

Ford also discussed the MSPPTF’s work during the Member Representatives Committee meeting prior to the board’s meeting. Asked by MRC Chair John Haarlow if the task force has identified any specific metrics to help measure efficiency improvements in the development process, Ford said that while it has not done so yet, he acknowledged that identifying such metrics would “make us a stronger ERO” and that the task force is working on it.

New Glossary Definitions Adopted

Trustees voted to adopt several new definitions for inclusion in NERC’s Glossary of Terms. They are related to FERC orders on IBRs.

Project 2024-01 (Rules of procedure definitions alignment — generator owner and generator operator) created new definitions for “generator owner” and “generator operator,” while Project 2020-06 (Verifications of models and data for generators) proposed to redefine “model validation” and “model verification.”

The GO and GOP definitions are intended to conform with NERC’s recent creation of new categories for owners of IBRs that previously were not required to register and follow the ERO’s standards. The other definitions arose from FERC Order 901 directing NERC to develop reliability requirements for IBRs and are meant to be used by other standards development teams working on those standards.

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CAISO Monitor Sees ‘Gaming’ Potential in Battery Storage Bid Cost Recovery

CAISO’s Market Monitor is concerned about potential gaming and inefficient bidding behavior in CAISO’s bid cost recovery (BCR) process for battery storage resources. 

The current BCR design creates gaming opportunities for battery storage units, “especially through manipulation of various biddable parameters used to manage [a battery’s] state-of-charge,” CAISO’s Department of Market Monitoring (DMM) said in its annual market performance report, published Aug. 7. 

“Gaming concerns are exacerbated by the fact that bid cost recovery payments are partly driven by submitted bid prices, meaning that inflated bids can cause BCR payments to drastically exceed any economic losses caused by reversal of day-ahead schedules,” DMM said in the report. 

Battery storage capacity in California has grown from 500 MW in 2020 to almost 14,000 MW as of August. An additional 14,000 MW of battery storage capacity is planned to be online by 2030, pushing CAISO’s total to about 28,000 MW by that year. 

In 2024, battery storage facilities received about $18 million in real-time bid cost recovery — about 11% of all bid cost recovery in the year. However, battery storage resources are different from conventional resources: They do not have start-up, shut-down, minimum load or transition costs — the primary drivers of BCR, the report says. 

Historically, BCR has applied to generation facilities as a method to reduce their risk of receiving insufficient revenue to cover start-up and minimum load costs, the report says. As opposed to conventional thermal resources that are incentivized to bid their marginal energy production costs, storage resource bids do not solely represent the costs to discharge or charge energy in a given interval, CAISO said in a November 2024 letter to FERC on the issue. 

“As a result, bid cost recovery payments to storage resources may result in compensation exceeding the resource’s costs,” CAISO said in the letter. 

In its Aug. 7 report, DMM recommended that battery storage resources should be, in general, ineligible for BCR, with a limited number of conditions in which they would be eligible for BCR. The report notes that batteries do have certain limits that can result in BCR payments, specifically state-of-charge constraints that limit a battery storage unit’s charging and discharging behavior. 

But, as a general principle, when batteries are constrained by operational parameters set by unit operators to manage battery operation, “batteries should be ineligible for BCR payments,” the DMM’s report says. 

Additional Revisions

In November 2024, CAISO filed a tariff amendment to address the battery storage BCR gaming concern. The tariff amendment caps battery bids when calculating bid cost recovery payments, which will mostly address the ability of batteries to inflate unwarranted BCR payments, DMM’s report says. 

However, unwarranted BCR payments will continue after the policy change is implemented because batteries with day-ahead schedules will continue to have distorted bidding incentives in real time, DMM’s report says. This is because the largest driver of real-time battery BCR is due to lost revenues of buying or selling back day-ahead schedules, the report says. 

The current BCR design “essentially removes the economic incentive for battery operators to bid in a way that is likely to ensure that batteries are fully charged up at the start of the peak net load hours when prices are highest and batteries are most needed for system reliability,” the report says. 

Responding to questions from RTO Insider, a CAISO spokesperson said the ISO and stakeholders developed market design changes in 2024 to eliminate the potential for strategic bidding that would unduly inflate battery BCR payments. While those changes addressed an important concern, CAISO is working through additional issues related to market efficiency and improving the incentives for batteries to bid in a manner that is cognizant of real-time prices, the spokesperson said. BCR payments to batteries have remained stable even with significant battery fleet growth, they said. 

CAISO is working on additional revisions to the BCR process within the agency’s storage design and modeling initiative that started in 2025. 

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BPA Issues Final Long-term Power Contract, Updates Strategic Plan

The Bonneville Power Administration has finalized the set of policies and records of decision (RODs) underlying its long-term power sales contracts and has taken additional steps to align with President Donald Trump’s priorities, CEO John Hairston said during the agency’s quarterly business review Aug. 14.

The policies and RODs build on the agency’s provider-of-choice policy issued in March 2024 and provide more details about the products and services it offers under the new long-term contracts. The goal is to complete all contract offers by Sept. 30 and for customers to return signed contracts by Dec. 5, allowing BPA to execute them by the end of the year, Hairston said. (See BPA Close to Issuing New Long-term Power Contract.)

“This has been an incredibly iterative and collaborative process,” Hairston noted. “BPA greatly appreciates the time and energy invested by so many people to ensure we establish a foundation for stable, competitively priced and flexible power sales. The long-term certainty provided by these contracts will support regional economic stability and help ensure a more reliable and affordable power supply for customers we serve.”

BPA has updated its strategic plan in accordance with the Trump administration and the Department of Energy’s goal to provide “more secure, reliable, abundant and affordable energy,” Hairston said.

One change, Hairston added, is that the agency has removed objectives related to diversity, equity and inclusion to align with executive orders issued shortly after Trump took office.

“Other minor refinements reflect the department’s focus on energy addition, not subtraction, and strengthening grid reliability and security,” Hairston said.

Hairston highlighted other BPA projects, including a partnership with Energy Northwest to increase the output of the Columbia Generating Station by 162 MW in a $700 million project, and an upgrade to Montana-to-Washington transmission aimed at expanding capacity.

He commented on BPA’s new power and transmission rates for fiscal years 2026 to 2028. Customers’ power rates will increase by about 8 to 9% over the next three years, while transmission rates will jump by an average of nearly 20%. (See BPA Customers to See Increased Power, Transmission Rates.)

“The new rates balance the need to keep rates low and stable while supporting power and transmission system investments to meet customer load growth and connect new generation,” Hairston said. “The rates we adopted are the product of multiple settlements that required hard work and collaboration.”

The administrator noted the June 12 presidential memo directing the federal government to withdraw from a deal the Biden administration signed that eventually could have led to breaching several dams operated by BPA on the Snake River. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.)

“The federal parties provided notice of withdrawal on June 24, which also made clear that the federal government is willing to engage in good faith efforts to seek a satisfactory solution to the pending litigation and concerns of various stakeholders,” Hairston said.

Financial Outlook

BPA’s forecast for net revenue in the third quarter of 2025 is $184 million, a $26 million decrease from the second quarter but higher than the $70 million target.

Power services’ net revenue forecast is $105 million, $27 million above target. Transmission services’ net revenue forecast is $73 million, $80 million above target.

“BPA’s above-targets results are mainly due to higher power and transmission revenues, lower-than-predicted Integrated Program Review expenses and debt-management actions,” according to a news release. “Notably, BPA was able to use liquidity tools to offset its largest power purchases in January and February through a federal debt-management transaction that allowed BPA to realize significant gains.”

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New York PSC Denies NYPA’s Clean Path Transmission Priority Status

The New York Public Service Commission has denied the New York Power Authority’s petition to grant the Clean Path New York transmission project priority status, finding that the utility did not demonstrate it would relieve congestion (20-E-0197).

Instead, the PSC said, NYPA relied “on a recitation of the state’s future needs for renewable generation and the presence of a significant amount of proposed projects in the NYISO interconnection queue to justify designating the project as a” priority transmission project (PTP).

“NYPA does not provide any evidence of existing congestion and does not even meet the standard … for establishing a need to unbottle renewable resources,” the PSC wrote in its Aug. 14 ruling. “This approach overlooks the [PSC’s] emphasis” in its criteria for identifying PTPs “on the need to unbottle existing generation, and therefore misses the mark.”

The PSC noted that recent NYISO studies and the Coordinated Grid Planning Process do not show Clean Path being needed “expeditiously.” It cited the ISO’s 2023-2042 System and Resource Outlook, which found that Clean Path would reach only 47% utilization by 2040.

“Even if we assume the project is technically capable of meeting future needs, designating it as a PTP now would mean charging ratepayers for transmission facilities that will not begin conducting significant amounts of generation until a point in the future that may be two decades away,” the PSC wrote.

Clean Path originally was an $11 billion project that included transmission and renewable generation components. In 2024, NYPA terminated Clean Path’s renewable energy certificate by mutual agreement with the New York State Energy Research and Development Authority. In February 2025, it submitted an updated petition for the transmission portion that came in about $5.2 billion. (See NYPA Argues Clean Path Potential Benefits Outweigh Cost.)

The PSC found that Clean Path could not be justified as a near-term solution to the ongoing reliability issues affecting New York City because NYPA’s petition did not identify any new renewable generation that would be delivered through it.

“The record does not show that the project will deliver significant amounts of generation output to the New York City grid until the 2040s,” the PSC wrote. “If reliability issues arise in the 2030-2035 time frame, the project would not provide a solution.”

The project would have included 178 miles of HVDC line between upstate New York and Queens.

The PSC broadly agreed with NYPA that new transmission is necessary but that projects based on “generation to be built in the future” do not rise to the same urgency as unbottling existing generation. The commission also rejected NYPA’s argument that the existing planning processes take too long to develop a solution to New York’s reliability issues.

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New Report: Consumers Could Pay $3B More Annually if DOE Stay-open Orders Persist

A new Grid Strategies report concludes that if the U.S. Department of Energy continues to supersede retirement decisions for fossil-fueled power plants, it could cost consumers an extra $3 billion annually in a little more than three years.

The report, “The Cost of Federal Mandates to Retain Fossil-Burning Power Plants,” said if the DOE’s trend of stay-open orders persists, it could affect the 34.95 GW of large fossil power plants scheduled to retire between now and the end of 2028.

The Aug. 14 report estimated the cost of DOE mandates on the almost 35 GW of generation could climb to $260 million due monthly by January 2029.

Author and Grid Strategies Vice President Michael Goggin said added costs could surge to nearly $6 billion per year at the end of 2028 if owners of other aging power plants, enticed by revenue guarantees associated with the DOE’s mandates, announce earlier retirement dates.

Environmental nonprofits Earthjustice, Environmental Defense Fund, Natural Resources Defense Council and Sierra Club commissioned the report after the DOE in May issued two mandates to keep Constellation Energy’s Eddystone oil and gas power plant in Pennsylvania and Consumer Energy’s J.H. Campbell coal plant in Michigan operating about three months past their announced retirement dates. (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online and DOE Orders Michigan Coal Plant to Reverse Retirement.)

“Based on the trend to date and indications that DOE has approached the owners of many retiring fossil power plants about potentially mandating their retention, DOE may attempt to mandate the retention of nearly all large fossil power plants slated for retirement between now and the end of 2028,” Goggin wrote.

The report used the 34.95 GW slated for retirement in a low-end estimate and 66.34 GW in a high-end estimate, in which it assumed other plants would announce accelerated retirements.

To arrive at the 66 GW tally, Grid Strategies combined the 35 GW in confirmed announcements with another 31.39 GW of fossil fuel generation across 36 plants that are at least 60 years old.

The nearly 35 GW figure did not include the little more than 8 GW of retiring fossil plants that have at least some replacement fossil capacity planned on site. It also excluded about 310 MW of retiring fossil plants that are smaller than 50 MW.

The report said in all, the DOE could deliver mandates to 90 aging power plants across the country.

Grid Strategies noted that MISO’s median retirement age for its coal plants is around 60 years, while data from the U.S. Energy Information Administration pins the median age of coal plant retirement at 54 years in 2024. Goggin wrote that the 60-year age screen “should provide a conservative estimate of the total fossil capacity that is likely to retire.”

Estimated monthly costs of the DOE keeping about 35 GW of retiring fossil plants online from mid-2025 through 2028 | Grid Strategies

Grid Strategies used an average $89,315/MW-year cost of keeping a plant open, bringing the total annual ratepayer cost by the end of 2028 to $3.121 billion in the low gigawatt estimate and $5.925 billion in the high estimate.

The consulting firm calculated a weighted average cost of recent reliability-must-run (RMR) contracts across the country to come up with the $89,315/MW-year value. It reviewed RMR contracts for Brandon Shores, Wagner and Indian River in PJM; Lakefront Unit 9 and Rush Island in MISO; Braunig Unit 3 in ERCOT; and six units including Midway in CAISO. Contract costs ranged from $49,858/ MW-year for Wagner to $167,619/ MW-year for Lakefront Unit 9.

Goggin said the contract costs should provide a reasonable proxy for ratepayer subsidies paid out under DOE mandates. However, he acknowledged that the first two plants to be kept online are in uncharted territory, with “scant precedent for determining ratepayer subsidy costs for keeping plants open past their scheduled retirement date” due to DOE intervention.

Consumers Energy reported that the J.H. Campbell plant accumulated $29 million in costs after a little more than a month of extended operations. (See DOE Extension of Michigan Coal Plant Cost $29M in 1st Month.) Goggin said if that “cost trend were to persist, that would translate to $279 million in annual cost or $178,559/MW-year, almost exactly twice our estimate.”

The report also noted that the Citizens Utility Board estimates the cost for the Campbell and Eddystone plants at a weighted average annualized cost of $181,200/MW-year, more than twice the report’s estimate.

Grid Strategies determined that California has the most to lose in the low-end estimate, at an annual cost of $389 million by the end of 2028. Texas and Colorado follow at $183 million and $178 million, respectively, per year. Michigan, Louisiana and Illinois — all MISO states — also would register noteworthy costs at $171 million, $164 million and $161 million, respectively.

The report assumed that states that don’t contain plants slated for retirement, including the six New England states, New York, Hawaii, Alaska, Oregon and South Carolina, would be unaffected by DOE stay-open mandates in the low-end scenario. In all, it said ratepayers in 39 states and the District of Columbia stand to incur costs if the DOE doles out mandates to all plants currently counting down to a retirement date.

The analysis assumed plants don’t begin receiving funds to stay open until a month after their scheduled retirement. Goggin noted that the DOE could issue mandates earlier than that.

Grid Strategies said it chose to include potential plants that aren’t yet slated for retirement in the high estimate because the DOE’s actions could create a “perverse incentive” for plants to declare earlier retirements, so they’re paid to remain open.

“This perverse incentive is what economists would call a moral hazard,” Goggin wrote.

Goggin wrote that the report’s eye-popping cost estimates conflict with the April presidential executive order that charged the DOE with issuing mandates, which emphasized rising demand from AI data centers and domestic manufacturing and protecting the “the national and economic security of the American people.” Goggin said it’s “intuitive and inherent” that the DOE keeping plants operating would drive up customer bills.

“Power plants have been slated to retire because their owners and state regulators have determined they are no longer economic or needed. DOE mandates override those well-informed decisions, inflating electric bills for homeowners and businesses and undermining the competitiveness of U.S. factories and data centers,” the report said.

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NERC ‘Leaning into AI’ for Online Assistance

CALGARY, Alberta — NERC staff told a Board of Trustees committee that the ERO’s work on integrating artificial intelligence technology into its operations is “on track” and has produced promising developments.

Speaking to the board’s Technology and Security Committee on Aug. 13, Howard Gugel, NERC’s senior vice president for regulatory oversight, said the ERO Enterprise is “leaning into AI [by] learning, listening and supporting the industry” while engaging with developers on possible uses for the technology in the organization’s business.

Gugel and other speakers characterized the ERO’s approach to AI as “conservative,” acknowledging the need to keep industry data secure and deploy the technology responsibly. NERC and the regional entities have adopted the National Institute of Standards and Technology’s AI Risk Management Framework as a model. NIST’s framework is structured around four core functions:

    • Govern — implement a risk-management culture through policies, processes and accountability mechanisms;
    • Map — identify and document the context, intended uses and potential impacts of AI;
    • Measure — develop metrics for evaluating AI risks, and test and monitor performance regularly; and
    • Manage — prioritize and address identified risks through mitigation strategies, monitoring and improvement.

NIST provided a set of attributes that AI systems should exhibit to demonstrate trustworthiness. These include accuracy and robustness across diverse conditions, protection against failures and outside attacks, accountability and transparency, processes for safeguarding user data and privacy, and fairness.

“There [were] a number of reasons that the NIST AI risk framework was attractive,” said Joseph Younger, chief operating officer at the Texas Reliability Entity. “It’s non-industry-specific; it’s flexible; and it can be tailored to different-size organizations as well as organizations that are at different maturity levels in terms of how they’re implementing AI. … [It] also provides a range of supporting materials, including playbooks, models [and] templates that NERC and the regions could leverage as needed as we start out on these journeys.”

One of the first projects under the ERO’s AI initiative is a chatbot, developed with an outside partner, intended to help users quickly find information from NERC’s website. In the meeting agenda, NERC said such an application “could significantly reduce the time required to … find and apply the knowledge required to perform CMEP [compliance monitoring and enforcement program] tasks.”

The chatbot “can be used as a tool for either somebody that’s a new hire to NERC, or somebody that’s wanting to know more about standards, just to quickly ask a question and get it back,” Gugel said. NERC is developing the chatbot with AI Factory, a product of Microsoft partner company UnifyCloud. An internal pilot is expected to begin in the third quarter.

NERC also is exploring the use of OpenAI’s ChatGPT to help summarize comments submitted for draft reliability standards, which are in the public record and therefore considered a low security risk. In addition, ReliabilityFirst began a test of Microsoft Copilot in January to determine its suitability for the RE’s business. RF has “enabled Copilot for about 35 users, with plans to reach 50 by August 2025,” NERC said. RF has limited the use of Copilot to work teams that are not “primarily focused on core CMEP functions.”

Trustee Sue Kelly noted that in addition to these efforts, NERC’s Modernization of Standards Processes and Procedures Task Force — of which she is a member — is exploring the use of AI in the standards development process. She asked Gugel if such a use case would fall under the governance model.

Gugel assured Kelly that if such an application were created, the personnel involved would be appropriately trained and that the program would “have good guardrails in place [about] what … files can be accessed on the internet, and [which] ones can’t.”

“At this point, my vision would be [that] there’ll always be somebody reviewing that output for a sanity check before it ever goes out for either a public comment or be a document that’s actually used somewhere,” Gugel said.

E-ISAC Notes Growing Threat Sophistication

Matthew Duncan, vice president for security operations and intelligence at the Electricity Information Sharing and Analysis Center, delivered a presentation on the state of the security landscape at the TSC meeting.

Duncan said the environment remained largely “unchanged,” but the E-ISAC has seen “subtle shifts in the techniques and tradecraft being used by all manner of adversaries.” China-linked actors remain an ongoing threat, with an additional rise in malicious activity, including distributed denial of service attacks, from pro-Iran groups following the U.S.’ and Israel’s airstrikes on that country’s nuclear program earlier this year. (See Iran Strikes Likely to Raise Cyber Risk, CISA Warns.)

Between January and June, the E-ISAC made 1,982 direct shares to member and partner organizations, a 79% increase over the same period in 2024. Shares to utility members overall were up 43% year over year, and shares to Canadian members and partners up 13%. Duncan credited the increase to “the efficiency and the automation gains we have made at the E-ISAC.”

Asked by Trustee Jane Allen about reports that AI has fueled an increase in cyberattacks, Duncan acknowledged that “you don’t always know it is AI, or [generative] AI, that’s attacking you.” He said that one possible sign of AI assistance is that “the phishing emails … have all gotten better grammar and better spelling” and seem to be better tailored to their targets.

“The unfortunate truth is [generative] AI makes hacking easier, so even non-sophisticated folks can use these tools to do more effective phishing,” Duncan said. “So I think it behooves us to get ahead of this, to train our people to think about how to respond. If you have a question about whether an email or a text is authentic, find an alternative way to confirm that it is real.”

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Report Urges 5-GW Battery Storage Buildout in SPP

A new report urges SPP to accelerate its interconnection process and reform market rules to allow greater buildout of energy storage.

The report notes that hundreds of battery storage proposals are sitting in the SPP interconnection queue, working through lengthy reviews. Few batteries are deployed in SPP now, but even 5 GW of capacity could boost reliability and reduce costs by a projected $7 billion over the next decade.

Aurora Energy Research issued the report Aug. 12. The American Clean Power Association (ACP), which commissioned it, called for SPP and state policymakers to:

    • accelerate interconnection for the quick-to-deploy technology;
    • reform market rules to generate price signals that incentivize storage development and recognize the reliability contribution of storage;
    • remove ambiguity on when storage must register as a transmission customer and how the associated charges are applied; and
    • streamline and clarify state and local permitting with uniform rules and standards to ensure faster, more certain project execution.

SPP did not return requests for comment for this story.

The RTO recently completed a yearslong effort to streamline and integrate its transmission and generation planning: On Aug. 5, its board of directors approved the Consolidated Planning Process and asked FERC to approve a March 1, 2026, effective date. (See SPP Celebrates Novel Consolidated Planning Process.)

Several statistics provided by Aurora, the Energy Information Administration and SPP itself point to the potential importance of storage:

    • SPP is the second-largest RTO in the nation geographically.
    • It is expecting the largest peak load growth of any RTO, reaching 69 GW in 2035 due to electrification of oil and gas extraction and data center buildout.
    • Thirty-eight percent of its 2024 energy production was from wind turbines.
    • Wind turbines are highly variable sources of power generation — in the past 30 days, hourly output nationwide ranged from 10,352 to 77,765 MWh.
    • The SPP interconnection queue is crowded with proposals for solar generation, which also is intermittent if more predictable.
    • SPP’s 2025 accredited summer battery storage capacity is 172 MW.
    • More than 25 GW of battery capacity proposals entered the SPP interconnection queue in 2024.

Aurora modeled two distinct scenarios in its report: one where restrictions limit 2035 battery capacity to 1.4 GW and the other where 4.7 GW of batteries are deployed, based on economic viability and assuming continuation of various policy reforms such as federal clean energy tax credits and SPP’s Consolidated Planning Process.

In 2035, prices during late-afternoon/early evening summer peak demand periods could be $1,141/MWh under the 1.4-GW scenario, compared with just $153/MWh under the 4.7-GW scenario.

Total system costs could be $7 billion higher in 2035, and electricity prices would climb 10.1% from 2029 to 2035 under the 1.4-GW scenario.

Also over the next decade, the report forecasts growing net hourly load ramps due to expected increases in population and solar generation.

Small ramps will decline in number, the authors say, but large ramps will become more numerous: By 2030, more than 700 hours a year will require a ramp greater than 4 GW, compared with 37 hours in 2020.

A storage fleet larger than 5 GW is critical to grid reliability and cost savings, the report states.

It cites the performance of battery energy storage systems in ERCOT, where 15-minute battery discharges as high as 1.97 GW prevented load shed during several high-stress periods in the late summer of 2023.

“Evening power prices could be 80% lower in SPP if the region can build out the battery storage central states need to ensure reliability,” Noah Roberts, ACP vice president of energy storage, said in a news release. “As power demand surges, battery storage is one of the fastest and most effective ways to strengthen reliability and lower electricity bills. Grid batteries deliver significant cost savings for families and businesses, and provide the reliability needed to power our economy into the future.”

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N.J. Puts on Hold Remaining Pieces of $1.07B OSW Transmission Project

Bringing to a halt two major outstanding elements of New Jersey’s once-aggressive offshore wind plans, the state Board of Public Utilities postponed by 30 months all activities on onshore infrastructure intended to connect the wind farms to the grid. 

The three BPU board members voted unanimously to delay all possible expenditures on the $1.07B project, which was approved in October 2022 and would deliver 6,400 MW of offshore wind generation. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) Two seats on the five-member board are vacant after Commissioner Marian Abdou stepped down in July. 

The project, at its outset, was widely seen as groundbreaking because it was conceived under FERC Order 1000’s State Agreement Approach, which enabled the BPU and PJM to work together to shape the plan. The project included three points of interconnection on Jersey Central Power and Light’s transmission system and included a new substation adjacent to the company’s Larrabee substation. BPU officials said at the time the project would save $900 million over a baseline scenario in which the projects were not coordinated. 

Genevieve DiGiulio, project manager of offshore wind for the BPU, said that once the 30-month hold is over, there is a specific schedule for the projects to move forward. The BPU board at that time, however, will decide what happens next, she said.   

The three commissioners also voted unanimously Aug. 13 to accept a request by Atlantic Shores, the state’s only remaining active wind project, to terminate its Wind Renewable Energy Agreement with the BPU. The project developer in June said it would put the 1.5-GW project on hold because of opposition from the Trump administration. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)   

“Obviously some federal uncertainty has created a situation where we need to make sure that we’re acting in a way that we always do what’s in the best interest of ratepayers,” said BPU President Christine Guhl-Sadovy. “And so this, along with some of the other actions today, are in response to some of those federal decisions around clean energy.” 

The New Jersey League of Conservation Voters, saying the decision was a result of “President Trump’s clean energy ban,” called it a setback that nevertheless will “not stop our fight for a clean energy future in New Jersey.” 

“Offshore wind is critical to our clean energy portfolio and to protecting our health, environment and economy. Every delay forces our residents — especially low-income families and communities of color — to breathe dirty air and bear the brunt of climate change,” said Ed Potosnak, executive director of New Jersey LCV. “Solar and wind are the cheapest forms of energy, and New Jersey deserves clean, affordable, renewable energy, and we will not stop until we achieve it.” 

Solar Project Delays

The board also agreed to extend the development deadline for a series of solar projects in the Community Solar and Competitive Solar Incentive (CSI) programs that have been delayed by difficulties with the interconnection process with utilities. The CSI program is a part of the state’s Successor Solar Incentive (SuSI) program that sets incentive levels through a bid process for grid-scale projects. 

Sawyer Morgan, a project manager in the BPU’s clean energy division, said that out of 451 projects in the community solar pipeline and five others in the CSI pipeline, about 160 submitted a request to the BPU for an administrative extension to project completion deadlines. 

“The large number of projects entering the program simultaneously resulted in lengthy wait times for completion of facilities or engineering studies,” he said. “Stakeholders have reported concerns about the progress of interconnection with EDCs [electric distribution companies] and the opacity and unpredictability of the process.” 

Most of the delays were created by the slowness in developing engineering studies, Morgan said. 

The board agreed to extend the operation deadline for all projects in the two programs by nine months and allowed projects to request an additional six-month extension. The board also agreed to require developers to include a “completed facility study or equivalent feasibility or engineering study” to register a project. 

In a bid to move projects forward more quickly, the board also required EDCs to publish a monthly interconnection queue inventory with data including the locations of projects applying for interconnection progress through the process and other requirements. 

Commissioner Zenon Christodoulou suggested the BPU needs to orient developers to better handle delays. 

“When we talk about unexpected delays, I mean, we’ve known about interconnection issues for years and years and years,” he said. “So these still remain to be issues … but it’s still unexpected? I think the developers should understand and should expect this.”