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December 8, 2025

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FERC Denies IBR Clarification, Adds to OER’s Mandate

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

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

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

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

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

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

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

OER to Hear More NERC Cases

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

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

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

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

By Chris Robinson and Scott Simms

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

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

Chris Robinson

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

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

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

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

Scott Simms

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

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

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

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

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

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

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Advocates Defend Energy Efficiency Programs in Massachusetts

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The sectors include:

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

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

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

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

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

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

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

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

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Wright: DOE Working to Stop More Coal Plants from Retiring

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

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

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

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

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

Energy Secretary Chris Wright | DOE

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

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

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

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

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

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

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

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

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

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

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

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

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

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Bipartisan Transmission Permitting Reform Bill Introduced in House

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

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

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

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

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

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

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

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

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

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

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

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

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DER Representatives Get a Seat at the Pathways Table

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

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

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

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

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

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

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

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

Governance Transition

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

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

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

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

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

SPP Responds

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

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

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

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

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

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

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

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

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

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Centrus Moves to Expand HALEU Production Facility

Centrus Energy has begun preparing for the massive expansion of its Ohio uranium enrichment plant that it will undertake if it receives federal funding.

The company is pitching the plan as an investment in the U.S. and its energy sector. Many of the advanced nuclear reactor designs being developed would be fueled by high-assay low-enriched uranium (HALEU), which is only produced in commercial volumes in Russia.

Centrus has begun small-scale production of HALEU in the Piketon, Ohio, facility with financial assistance from the U.S. Department of Energy. It is seeking further federal assistance to ramp up HALEU and LEU production there and said it will fabricate the new production equipment entirely in the U.S.

Company leaders joined with Gov. Mike DeWine, state and federal lawmakers, and economic development agencies on Sept. 25 to trumpet what would be a multibillion-dollar investment.

Centrus said the project would support 1,000 construction jobs and add 300 permanent jobs to the 127-strong workforce on site now. It would support hundreds more jobs at Centrus’ Tennessee centrifuge factory and elsewhere in a manufacturing supply chain that spans 13 states.

The company said it has raised $1.2 billion in convertible note transactions and secured utility purchase commitments worth more than $2 billion in the past 12 months as it set the stage for the expansion.

Centrus added a caveat to the announcement: The size and scope of the expansion depend on funding decisions by DOE.

No state grants, loans or tax incentives are planned so far, but the state-authorized nonprofit economic development organization JobsOhio is assisting with workforce development for the facility, which is in a rural region of southern Ohio with significantly higher unemployment and a lower median income than both the state and the U.S.

Centrus said it already has begun hiring in anticipation of the Piketon expansion; the Sept. 25 announcement came at an employment expo in nearby Chillicothe.

“The time has come to restore America’s ability to enrich uranium at scale,” Centrus CEO Amir Vexler said in a news release. “We are planning a historic, multibillion-dollar investment right here in Ohio — supported by a nationwide supply chain to do just that. When it comes to powering our energy future, it’s time to stop relying on foreign, state-owned corporations and start investing in American technology, built by American workers.”

The percentage of U.S.-made uranium concentrate processed into fuel for U.S. nuclear power generation began to decrease around 1980. In 2023, 99.85% of it was imported.

This presents a potentially significant grid security issue, particularly as nuclear generation is pitched for a larger role in the grid. To remedy this, lawmakers and policymakers have been trying to boost domestic fuel production, including through the $2.7 billion funding package Centrus is hoping to tap.

The company has recorded successes, including a national first in late 2023 when it produced 20 kg of HALEU in Phase I of its DOE contract.

It checked off the Phase II requirements of the contract in June when it delivered 900 kg to the department.

Also in June, DOE exercised the first of its three Phase III options with Centrus to continue HALEU production at 900 kg/year.

And in late 2024, Centrus announced the department had awarded it an LEU contract and said it was scaling up its centrifuge manufacturing capacity to meet anticipated demand.

Centrus’ stock price closed 13.1% higher in heavy trading Sept. 25.

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FERC, NERC Praise Low-Risk Violation Handling

In a report filed with FERC on Sept. 23, NERC said the ERO’s Find, Fix, Track and Report (FFT) and Compliance Exception (CE) programs “are meeting the commission’s expectations” and streamlining the handling of lower-risk noncompliance cases by the ERO Enterprise (RC11-6). 

NERC and its regional entities proposed the FFT program in 2011 as an alternative to Notices of Penalty (NOPs) and spreadsheet Notices of Penalty (SNOPs) for processing minimal- and moderate-risk reliability standard violations. Similarly, the CE program, approved by FERC in 2015, allows the processing of minimal-risk violations without penalty; compliance exceptions are also not included in entities’ compliance history for penalty purposes. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.) 

Under both processes, the registered entity must mitigate the noncompliance and make the facts and circumstances of the incident available for review by NERC and appropriate governmental authorities. Instances of noncompliance are tracked and analyzed to identify emerging risks and trends, and entities can object to the use of the process. 

A condition of FERC’s 2012 approval of the FFT program is that NERC submit annual reports on the program’s progress over the previous year. CE program reports were added to this requirement in 2015. 

In this year’s report, NERC staff wrote that both programs have become the preferred means for handling moderate- or minimal-risk violations since their introduction, with 137 of 177 moderate instances handled via FTT in 2024 and 1,371 of 1,483 minimal instances processed as CEs. 

Most minimal-risk violations have been processed as CEs each year since the program began in 2015. Most moderate-risk violations were filed as SNOPs or NOPs until 2019, but in that year, FFTs accounted for the majority of cases and more than half in every year since then. 

“The availability of dispositions not involving settlements or penalties encourages registered entities to conduct their own assessment of their compliance programs … and to report noncompliance found during that assessment knowing that they will not face a settlement or penalty for lower-risk noncompliance,” the report’s authors wrote, adding that “the regional entities’ effective use of FFTs and CEs shows increased consistency in processing and understanding of the risk associated with individual noncompliance across the ERO Enterprise.” 

NERC’s report also discussed the results of a joint review by staff from FERC and the ERO of FFTs and CEs submitted to the commission between October 2023 and September 2024. The review began in October 2024 and ended in August 2025; ERO and commission staff reviewed 32 FFTs and 33 CEs, aiming to determine whether REs were properly implementing the programs. 

FERC staff agreed with REs’ risk determinations for all sample FFTs and CEs, saying that the assessments “clearly identified the factors affecting the risk prior to mitigation,” and that none of the cases “contained any material misrepresentations by the registered entities.” They concluded that the joint review shows “significant alignment across the ERO Enterprise” regarding the processing of individual noncompliance cases. 

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CAISO DMM Concerned About ‘StubHub’ Marketplace in RA Proposal

CAISO’s Market Monitor has cautioned that a new resource adequacy proposal could lead to strategic gaming in the ISO’s market when capacity supplies are tight on the grid. 

The Department of Market Monitoring voiced its concerns in Sept. 19 comments responding to a CAISO proposal that seeks to revise critical portions of the ISO’s resource adequacy requirements and processes to help ensure RA capacity is available under tight conditions. (See CAISO RA Initiative Moves Forward with 3 Proposals.) 

The proposal is part of a CAISO Resource Adequacy Working Group initiative that has prompted some stakeholders — including the DMM — to oppose a few of the potential changes.  

Their concerns centered on two aspects of the Track 2: Outage and Substitution straw proposal released in August.  

One aspect involves a plan for a new energy resource RA pool, while the other deals with an ISO policy requiring load-serving entities to provide substitute capacity during “conditional” resource outages.  

The Track 2 plan attempts to address the fact that the ISO’s current market design incentivizes LSEs to hold back RA capacity from the market in order to avoid potential penalties. This creates artificial tightness in the RA market, which CAISO and stakeholders say could be overcome with changes to outage substitution rules. 

To address the issue, the Track 2 proposal calls for creating a decentralized matching system that would “function like a bulletin board for buyers and sellers to request or provide substitution capacity,” the DMM said. 

This marketplace would be a central clearinghouse to share information for direct bilateral transactions — one that CAISO compared with StubHub, a website that allows users to connect with each other to buy and sell event tickets. The advantage of such a marketplace would be decreased informational friction for scheduling coordinators to find replacement capacity, the ISO has said. 

However, DMM identified potential issues with this new design: Track 2’s proposed marketplace could lead to a “strategic game of pricing” during tight conditions on the grid, it said. 

The problem with the proposed design is too much transparency, DMM contends. The proposed marketplace would reveal supply- and demand-side prices, but not the true reservation — or opportunity — cost and value of capacity for buyers and sellers, it said. 

Instead, DMM proposes an outage substitution pool design based on a reverse second price auction, in which buyers and sellers are incentivized to non-publicly reveal their true reservation prices for substitution capacity, rather than publicly as under the current proposal. 

“DMM suggests that the product purchased in the auction could be analogous to the ISO’s preferred option in the straw proposal, but use the auction mechanism instead,” DMM wrote. “This would require the auction clearing on a unit of capacity per day, just as the proposed marketplace option in the ISO’s currently preferred design. The main difference is the auction would clear resources with the highest marginal value for substitute capacity, and bid prices would not be revealed to market participants.” 

This alternative approach would reduce market power concerns and be designed to disincentivize strategic interactions between market participants, DMM said. 

The DMM’s model would work well if the outage product and capacity available were for a single day of single week, a CAISO spokesperson told RTO Insider in an email. However, this approach becomes much more complex when the duration of outages and durations of supply to cover those outages are mismatched, the spokesperson said. 

DMM’s proposal includes “potential design and implementation challenges when this approach is applied in a manner that reflects scenarios for outage and substitution which often can require multiple days or weeks depending on the participant needs,” the spokesperson said. 

‘Conditional’ Outages Removed

In separate comments to the RA Working Group, other stakeholders shared concerns that the Track 2 proposal no longer includes a provision addressing the concept of “conditional” resource outages — instances when a resource has indicated it will be offline but has not provided substitute capacity. 

CAISO could approve a conditional outage when reliability conditions allow, California Community Choice Association (CalCCA) said in its comments to CAISO. If reliability conditions changed, the ISO could then require the resource to provide substitute capacity, the group said. 

“As a general matter, suppliers should be able to perform short-term maintenance without having to substitute capacity during non-stressed periods,” CalCCA added. “This would allow for more opportunities to perform planned maintenance necessary to support reliable grid operation, minimizing potential maintenance delays and minimizing forced outages.” 

While CAISO would continue to allow off-peak opportunity outages that do not require substitute capacity, off-peak opportunity outages are only allowed during certain hours of the day and cannot extend multiple days, the CalCCA representative said. 

Commenting on behalf of ACP-California, Energy Strategies’ Caitlin Liotiris said the Track 2 proposal “dismisses the concept of conditional outages with little justification.” 

“We continue to believe that conditional outages can be implemented in a manner that fully preserves reliability and reduces costs for ratepayers, while also providing a valuable tool for RA resources to take outages without having to secure substitute capacity,” Liotiris said. 

Allowing conditional outages at least during non-summer, off-peak months would be a reasonable first step, particularly since CAISO used to approve such outages before implementing a full substitution requirement, Liotiris added. 

But a CAISO spokesperson told RTO Insider the “conditional” outages concept was removed “for reliability reasons and challenges.” 

“The California Public Utilities Commission sets monthly RA requirements for LSEs under their jurisdiction to meet the reliability needs, and as such we do not anticipate that under such a construct there would be significant shown RA that could go on planned outage without substitution,” the spokesperson said. 

“In comments received on the issue paper, the CAISO heard many stakeholders disagree with the ‘conditional’ aspect of this approach and a desire for more certainty,” the spokesperson added. “Removing this topic reflected the challenges in providing certainty desired by stakeholders without imposing a reliability risk to the system.” 

CAISO anticipates the Track 2 proposal will be reviewed by its Board of Governors in 2026, the spokesperson said.