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December 15, 2025

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Stakeholder Forum: Recent MISO Complaint Undermines Regional Transmission Planning Framework

By Ted Thomas

A new attack on regional transmission planning threatens to unravel a decade of progress toward a more reliable, affordable and interconnected electric grid. 

Ted Thomas

A group of state utility commissioners recently filed a complaint with FERC opposing the cost allocation for a new set of regional transmission projects known as Tranche 2.1 in the MISO region. This 3,631-mile 765-kV backbone portfolio of projects is expected to deliver up to $72 billion in net benefits across the system. 

Their argument? That these projects don’t serve the broader region and should be funded only by the states they physically pass through. It’s an appealing message — no one wants to pay for something they can’t see. But it’s also oversimplified and short-sighted, and it risks undermining the premise of regional planning and cost sharing that keeps the grid reliable and affordable. 

At its core, the complaint misunderstands how regional transmission works. High-voltage transmission lines are not local infrastructure, they are the backbone of the electric grid. They enable power to flow across hundreds of miles, balancing supply and demand in real time and delivering affordable electricity to customers even when local conditions falter. Transmission lines provide shared benefits far beyond state borders. 

This is why MISO — a region with a history of collaboration — created the Multi-Value Project (MVP) framework. When the first round of multi-value transmission projects was approved over a decade ago, they weren’t built just to serve one state or one utility, but to address regional reliability needs, reduce congestion and provide access to low-cost generation across MISO’s 15-state footprint. 

Independent studies later showed those projects will return up to $52.6 billion in benefits over the next 20 to 40 years — benefits that are shared by customers throughout the region and a 20% increase from the original estimate. 

Tranche 2.1 projects follow the same planning logic. Though individual lines may be in specific states, MISO plans them as part of a broader portfolio designed to work together to ease systemwide transmission bottlenecks, enabling cheaper and more reliable electricity to flow across MISO. These projects were approved through a rigorous, transparent regional planning process that evaluated systemwide impacts, not just local needs, and conservatively estimated the benefits of the projects. That’s why MISO’s board agreed these projects should be treated as MVPs and funded accordingly. 

To argue now that these projects should be paid for only by the states in which they’re located is to undermine the premise of regional collaboration. If every state were allowed to pick and choose which projects they want to fund, the grid would be more fragmented and inefficient and less resilient than it already is. Regional transmission planning works only when everyone contributes to — and benefits from — the shared infrastructure we all rely on. 

Moreover, refusing to share costs for regionally beneficial projects will hurt customers in the long run. Without large-scale transmission, we’ll be forced to rely on more expensive local generation, endure greater price volatility and face more frequent reliability challenges as demand grows and extreme weather becomes more common. That’s a cost nobody wants to bear, especially when the alternative is a well-planned, cost-effective solution that has already proved its worth.  

Arkansas is a prime example of how regional planning delivers value. We benefit when low-cost power from elsewhere can flow into Arkansas during times of high demand or generation shortfalls — and vice versa. Regional planning has brought long-term stability to power prices and improved reliability, especially in rural areas that often are more vulnerable to outages and price spikes.  

Despite this, the complaint threatens to erode the regional planning framework, and to do so in the context of a transmission plan that does not even allocate costs to three of the states that filed the complaint, including Arkansas.  

Rather than obstructing new energy infrastructure, we must recognize the urgent need to build for the future and meet demand. FERC should reject this complaint and reaffirm the principles that have made MVPs successful. Tranche 2.1 projects are part of a broader strategy to modernize the grid, reduce costs and ensure a reliable electricity system across the region.  

If we want a grid that works for everyone, we need to keep investing in shared solutions. Transmission isn’t local. Neither are its benefits. Let’s not let short-sighted politics get in the way of smart regional planning. 

Ted Thomas is the founder of Energize Strategies and a former chairman of the Arkansas Public Service Commission. 

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IRS Guidance on Wind and Solar Credits Not as Bad as Feared

The Trump administration is tightening the rules on qualifying for tax credits on new wind and solar construction, but not as much as some feared it would.

IRS Notice 2025-42 released Aug. 15 indicates the Five Percent Safe Harbor provision for the clean energy production and investment credits will be eliminated for new solar facilities larger than 1.5 MW and new wind facilities that start work after Sept. 2, 2025.

It is being replaced with a protocol to establish that significant physical construction has been started before July 5, 2026; proceeded continuously; and was completed within four calendar years to establish eligibility for the tax credits.

This is not as harsh as it could have been, or as some in the clean energy industry had feared — some companies in the sector saw their stock prices soar later Aug. 15 as the guidance was digested.

As the S&P 500 and Nasdaq closed fractionally lower, NextEra Energy closed 4.4% higher, Enphase Energy 8.1%, First Solar 11.1%, Nextracker 12.2% and Sunrun 32.8%.

Research and strategy firm Jefferies called it a win for utility-scale renewables and a huge win for residential solar, saying the guidance was “significantly better than expected.”

The sector’s trade organization, the American Clean Power Association, was critical of the guidance but struck a more measured tone than it has with some of the many setbacks President Donald Trump and his cabinet agencies have dealt to renewable energy in his second term.

CEO Jason Grumet said: “The Treasury Department’s decision to accelerate the phaseout of clean energy tax credits undermines the integrity of our energy grid and our legislative process. In the One Big Beautiful Bill Act, Congress explicitly chose to provide energy companies with one year to phase out tax credits to keep energy prices low while meeting growing power demand.”

But he continued: “We acknowledge and appreciate the hard work of senators who led the effort to elevate pragmatism over partisanship in the legislative process. Their continued advocacy to protect this legislative agreement was instrumental in avoiding greater impediments to energy deployment.”

On July 4, Trump signed the bill, which contained provisions accelerating the phaseout of the Clean Electricity Production Tax Credit and Investment Tax Credit — 45Y and 48E, respectively.

Some Republicans in Congress wanted the credits eliminated immediately, and Trump was widely reported to have won their support for OBBBA and its slower phaseout by promising a firm hand carrying out OBBBA’s provisions.

Trump followed up on July 7 with an executive order directing Treasury to issue new guidance on 45Y and 48E and directing the Department of the Interior to review and revise all policies deemed preferential to wind and solar facilities within 45 days of OBBBA’s enactment. (See U.S. Clean Energy Sector Faces Cuts and Limitations and Trump Executive Order Targets Renewable Energy Tax Credits.)

Interior already has issued a series of policy changes to comply with the order that most observers would characterize as harsh. (See Dept. of Interior Launches Overhaul of OSW Regs and Feds Pile on More Barriers to Wind and Solar.)

Treasury dropped the next shoe on Aug. 15. More is to come, however, including guidance on the safeguards Trump ordered against foreign entities of concern.

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Duke Energy Says Combining Carolina Utilities Would Save Billions

Duke Energy has asked state and federal regulators to combine its two electric utilities that serve the Carolinas in a move it said would result in billions of dollars of customer savings.

Duke Energy Carolinas and Duke Energy Progress have operated as separate utilities since the 2012 merger of Duke and Progress Energy. The two subsidiaries’ combination is legally classified as a merger, but it is more like reorganizing two corporate divisions into one. If approved, the effective date for the combination would be Jan. 1, 2027.

“Combining our two utilities reduces customer costs, simplifies operations, supports economic growth and promotes regulatory efficiencies, all of which will create value for customers in both states,” Duke Energy Carolinas CEO Kodwo Ghartey-Tagoe said in a statement. “There will be no immediate changes to retail customer rates or services. We look forward to sharing more details with our customers on how rates will evolve over time if the combination is approved by regulators.”

Operating as a single utility in the Carolinas would let Duke meet the growing needs for power there at a lower cost due to more efficient planning and an improved ability to avoid redundant investments. The combination would let Duke build fewer assets to meet the combined systems’ needs, and spreading infrastructure across the larger customer base would moderate impact on rates.

The combined utilities would be able to run fewer and less expensive units, use less fuel and cut down on units cycling on and off, thus saving maintenance costs.

The combination needs to be approved by the North Carolina Utilities Commission, the South Carolina PSC and FERC.

The combination is expected to save about $1 billion between 2027 and 2038, which is the close of the planning horizon for the 2023 Carolinas Resource Plan. Retail rates would start changing as the combined firm goes before North Carolina and South Carolina regulators in 2027 and later.

Duke Energy Carolinas owns 20.8 GW of generation and supplies power to 2.9 million customers across 24,000 square miles in the Carolinas. Duke Energy Progress owns 13.8 GW and supplies power to 1.8 million customers across 28,000 square miles.

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MISO States Split on FERC Complaint to Unwind $22B Long-range Tx Plan

Members of the Organization of MISO States are divided on whether the organization should register comments in a FERC complaint that could fundamentally change the way MISO can plan its long-view transmission.

The rift among the states shows how contentious the late July complaint is.

The public service commissions of North Dakota, Montana, Mississippi, Louisiana and Arkansas have sought reclassification of MISO’s $22 billion, mostly 765-kV second long-range transmission portfolio and have contested the RTO’s business case for the lines through a FERC complaint. The complaint could have FERC halting a regional cost-sharing of the lines across MISO Midwest and could upend MISO’s long-range planning process. (See Five Republican States File FERC Complaint to Undercut $22B MISO Long-range Tx Plan.)

FERC has allowed MISO until Sept. 9 to respond to the complaint, 10 days shorter than the monthlong extension MISO originally requested. (See MISO Requests Month to Respond to States’ Long-range Tx Complaint.)

Organization of MISO States Executive Director Tricia DeBleeckere said the complaint positions OMS in a tough spot because five OMS members lodged the complaint in the first place.

DeBleeckere suggested that OMS refrain from filing comments in the docket but said she would defer to what a majority of members want.

OMS President Asks States to Back MISO Planning

Joseph Sullivan, president of the Organization of MISO States and vice chair of the Minnesota Public Utilities Commission, said he’d like to see OMS membership who didn’t bring the complaint file comments defending MISO’s planning process.

“I would like to see if we can get to a majority to file comments in support of the process. Now, there are different ways to do cost-benefit calculations. But this is coming nine months after MISO approved the lines in December 2024 and more than a year and a half after it was clear that this would be the approach,” Sullivan told other regulators at an Aug. 14 OMS Board of Directors meeting.

Sullivan said regulators should remember that the lines are meant to accommodate load growth and economic development while modernizing the MISO system. He said even if the ensuing portfolio isn’t exactly what some states had in mind, MISO states agreed to the MISO process. He added that MISO is an outlier among other RTOs for successfully planning long-range transmission.

“We are the only region that succeeds at this, and that’s because we are working together. [That’s] in no small part because of OMS,” he said.

Sullivan pointed out that OMS in 2019 adopted principles on how MISO should approach long-range transmission planning and followed up in 2021 with a cost-allocation principles document and a filing in support of MISO’s postage-stamp-to-load allocation design. He said MISO’s resulting, second long-range portfolio is “consistent” with the OMS principles.

Sullivan said the five states’ request that MISO going forward submit future long-range transmission business cases to FERC for approval would be “a pretty significant federal takeover of state resource adequacy and utility planning in the modern age.”

“A purist may say ‘not so,’ but in the age of RTOs, that is exactly what this is. We all rely on each other and having the FERC say yes or no is something we should push back vigorously on. Fundamentally, this process is the culmination of the MISO stakeholder process and the aggregation of state and utility resource plans,” he said.

Sullivan said he hoped the remaining OMS members could band together in opposition against the complaint. He said OMS members should all be thinking about the “practical knock-on-effects” should FERC grant the complaint.

The second long-range portfolio already is included in all MISO modeling, Sullivan said, including expedited transmission project review, the 2022 cycle of generator interconnection requests and the interconnection queue fast lane.

“So, there will be major upheavals impacting potentially hundreds of projects, many already approved by our commissions. … Because this filing was so late in the process, it will have massive effects on everything we have already done — much of it to meet the moment on artificial intelligence, data centers, load growth and re-industrialization,” Sullivan warned.

Wisconsin Public Service Commissioner Marcus Hawkins said he would support a majority OMS filing on the complaint, or a filing from a subset of MISO states.

States that brought the complaint forward opposed a majority filing from OMS in the docket.

Barton Norfleet, counsel for the Mississippi Public Service Commission, said he thought OMS should sit this docket out. Noel Darce, counsel for the Louisiana Public Service Commission, also agreed that comments should come from individual states, not the organization itself.

South Dakota Public Utilities Commissioner Chris Nelson said his commission is holding off on communicating a position on the complaint and would weigh making a filing once MISO has responded.

“This is a really divisive issue,” Nelson said.

North Dakota Public Service Commissioner Jill Kringstad said North Dakota has long communicated its disillusionment with the MISO portfolio. She said North Dakota is exercising its right to have FERC take an “objective” view at the long-range transmission.

Sullivan said he thought states and OMS board members should “find the common denominator over the next couple of weeks and develop a set of baseline comments defending the process.”

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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.