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December 8, 2025

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.

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. 

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. 

MISO: More Time Needed to Perform 8-year Resettlement of TOs’ ROE

MISO says it needs more time to finish meting out refunds to transmission customers nearly a dozen years after a complaint was first raised to lower its transmission owners’ base return on equity (EL14-12, et al.).

The RTO and TOs requested an extension until June 30, 2026, of the current Dec. 1 deadline to complete refunds under a FERC-ordered ROE in transmission rates.

In an October 2024 order, FERC set MISO’s base ROE at 9.98%, down from the previous 10.02%. That figure is the latest in a complicated carousel of ROE percentages the commission has set in the last decade.

MISO transmission customers first complained in late 2013 that the 12.38% ROE in use since 2002 was excessive. A second complaint challenging the ROE followed in 2015; that complaint was dismissed as FERC set and reset ROEs from 2016 onward (10.32% beginning in 2016, 9.88% in 2019 and 10.02% in 2020).

In the 2024 ROE order, FERC upheld an original 15-month refund period from Nov. 12, 2013, to Feb. 11, 2015, while prolonging a second refund period from Sept. 28, 2016, through Oct. 17, 2024. The TOs are challenging the eight-year refund period. (See MISO TOs Take ROE Battle to DC Circuit Court Again.)

MISO said more time is necessary to complete the complicated resettlements and accurately disperse refunds with interest for the eight-year period.

The grid operator said, “The number of affected transmission owners, the number of months involved and the number of affected schedules have all increased.” The affected TOs are up to 89, from 75, while the months needing resettlement are up to 181, from 110, it said.

“The tasks have been organized as efficiently as possible but involve ‘thousands of files and communications,’” the RTO told FERC, quoting an attached affidavit from its manager of transmission settlements, Erin Peddicord. “Coordination must take place between MISO and its many TOs, ‘with the exchange of hundreds of files between MISO and its transmission owners for every resettlement year [from] 2013 through Oct. 17, 2024.’”

Peddicord said that although the RTO has been making progress, the base ROE is “fundamental to MISO’s transmission billing.” She said FERC’s changes impacted several revenue schedules and tariff attachments, which are used in part to develop zonal transmission rates, MISO’s systemwide rates and compensation for the 2011 batch of Multi-Value Projects.

She added that transmission formula rates are not standardized in MISO, and TOs have different refund obligation dates, resulting in partial month settlements in some cases. She said the refunds are set to affect all TOs, whether they use historical, forward-looking or hybrid test years to calculate their annual transmission revenue requirements.

Planners Pick $1.5B Underwater HVDC Line for Toronto’s ‘Third Supply’

IESO system planners on Sept. 25 recommended the construction of a $1.5 billion HVDC line to meet Toronto’s growing energy needs, saying it would be more “future proof” than two cheaper options. 

The approximately 40-mile, 900-MW line would run from the Darlington transmission station (TS) in Bowmanville to the Port Lands neighborhood, near Downtown Toronto, via Lake Ontario, requiring expansion of the Hearn switching station in the Port Lands area to add equipment. 

“This option can deliver broader bulk system benefits, as it completely bypasses Cherrywood TS and Leaside TS,” the ISO said in a presentation Sept. 25. 

Toronto’s electricity demand could increase 70% (reference case) to 100% (high electrification) by 2044 because of new housing and commercial development, data centers, and the electrification of heating and transportation. 

As a result, electricity demand is expected to exceed the transmission capacity in 10 to 15 years, creating a “reliability need” by 2038 — or 2034 if the 550-MW gas-fired Portlands Energy Centre (PEC) ceases operations. 

IESO’s draft Integrated Regional Resource Plan (IRRP) recommends battery energy storage systems, upgrades to infrastructure and incremental electricity Demand Side Management (eDSM), including residential solar/storage systems, in addition to new transmission infrastructure. 

“With or without the supply contributions from PEC, meeting the significant need identified for eastern Toronto due to the significant forecasted growth requires a large-scale wires solution,” the ISO said. 

Toronto is currently served by two high-voltage transmission corridors. The underwater line was one of three options planners considered for Toronto’s “Third Supply,” including an overland route from Cherrywood TS (Pickering) to Leaside TS in Toronto estimated at $800 million, and a hybrid of overland and underground segments from Cherrywood TS to the Port Lands, estimated at $900 million. 

In addition to the underwater HVDC line (highlighted in teal) that was recommended, IESO planners also considered an overland route from Cherrywood TS (Pickering) to Leaside TS in Toronto (yellow) and a hybrid overland/underground route from Cherrywood TS to the Port Lands in Toronto (blue). | IESO

“We chose Bowmanville because here we can connect directly to the bulk power system, and it’s conveniently near the lakeshore,” said Steve Norrie, IESO supervisor of transmission planning. “We picked HVDC technology over the more traditional AC technology for its performance and economics over longer distances underwater. This option offers a new supply path that doesn’t rely on Leaside TS, and it doesn’t rely on any of the 230-kV networks at Cherrywood to inject more power downtown, which means that it can deliver broader benefits for the bulk system.” 

While all three options would meet East Toronto’s growth needs into the 2040s, the underwater cable is “the most future-proof option, because it supports the forecasted demand the longest,” Norrie said. “In fact, it will support the demand beyond 2044, so it pushes the need out past the end of the 20-year study in terms of system resilience.” 

Norrie said the HVDC line would help the city respond to “high-impact events,” such as the extreme rainfall and flooding that resulted in the loss of supply in July 2024. 

Toronto has experienced at least three one-in-100-years rainfall events over the last 20 years, and the last two disrupted power to more than 200,000 customers, “which is something that we really looked at this plan as an opportunity to address,” Norrie said. 

The overhead option doesn’t change Toronto’s reliance on the two existing transmission supplies, Norrie said. He said the hybrid would provide some resilience benefit for the downtown core, but the supply to Eastern Toronto would still be reliant on the path coming from Cherrywood. 

“The underwater cable provides a new geographically separate and electrically separate supply path to the downtown. It reduces reliance both on Leaside and Cherrywood, plus it provides a means of backing up the other paths into Toronto in the event of a loss of supply,” he said. “So this would be a significant improvement in system performance.” 

The ISO will consider written comments on the draft IRRP until Oct. 9. 

“We will now be listening to feedback on this draft recommendation, and we will make our final recommendation at the end of October,” IESO spokesman Michael Dodsworth told RTO Insider. 

Escalating Conflict with Utilities Leads to Resignation of Top Conn. Regulator

The forthcoming resignation of Connecticut Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett has created high-stakes questions around the state’s adoption of a comprehensive performance-based regulation (PBR) framework, with three key votes set to occur just two days before Gillett is scheduled to step down.

Gillett, who has frequently drawn the ire of the state’s investor-owned utilities, announced her resignation Sept. 19 after a prolonged pressure campaign by utilities and Connecticut Republicans, writing that “the escalation of disputes into a cycle of lawsuits and press statements pulls attention and resources away from what matters most: keeping rates just and reasonable, improving service and planning a resilient, reliable energy future.”

The disputes have “exacted a real emotional toll both for me personally, as well as my family, and for my team,” Gillett said, adding that “there is only so much that one individual can reasonably endure, or ask of their family, while doing their best to serve our state.”

The day prior, on Sept. 18, Connecticut House Republican Leader Vincent Candelora called for an impeachment inquiry into whether Gillett lied during her February confirmation hearing about the existence of a directive requiring that “staff support for commissioners be directed through her.”

Her resignation, which will take effect Oct. 10, comes as PURA works to finalize a set of major regulatory changes intended to better align utility incentives with customer benefits.

Gillett began her tenure as chair of PURA in 2019, making headlines by presiding over several rulings that significantly limited revenue increases for utilities or ordered revenue decreases.

With Gillett at the helm, PURA decreased the revenue requirements in rate cases for the Aquarion Water Co. and a pair of Avangrid-owned gas utilities, significantly limited a proposed United Illuminating electric rate increase and issued major fines on the state’s electric utilities for poor performance responding to Tropical Storm Isaias in 2020.

According to Gillett’s critics, she fostered an unfavorable investment climate for utilities, hurting their credit ratings and disincentivizing investments in the state’s grid. In recent months, Connecticut Republicans argued she overstepped the limits of her authority, and Eversource Energy and Avangrid alleged in lawsuits that Gillett held a personal bias against the companies.

Following the news of her resignation, Eversource’s stock price spiked by about 8%. Equity analysts at Jefferies Research Services called the news a “clear positive” for the company, writing that Connecticut “has been one of the most challenging U.S. regulatory jurisdictions for the past decade.”

But according to her supporters, Gillett was extremely effective at pushing back against unjustified utility costs and rate increases, making her a target of utility companies.

Reacting to the news, David Pomerantz, executive director of the Energy and Policy Institute (EPI), a utility watchdog nonprofit, called Gillett “possibly the best utility regulator in the country,” saying she “joins the long list of regulators who have attempted to lower rates and confront utility profits, and lost their jobs for it.”

“I think Chair Gillett — more than any other utility regulator in the country, state or federal — was really enacting a reform agenda that could lower rates, and in doing so, was challenging the utilities and their investors on Wall Street to earn their profits in a different way,” Pomerantz said.

Performance-based Regulation

Beyond specific ratemaking proceedings, much of Gillett’s tenure has focused on PBR development in the state. The shift to PBR was initiated by the legislature, which in 2020 directed PURA to develop a comprehensive PBR framework after Tropical Storm Isaias triggered extended power outages.

PURA approved a more general set of goals, considerations and key outcomes for PBR in 2023 (21-05-15) and is nearing final votes on three follow-up dockets to establish specific performance metrics, revenue adjustment mechanisms and integrated distribution system planning requirements.

Throughout the process, utilities have criticized PURA frequently for failing to adequately consider their input, while environmental and consumer groups praised the agency for taking a collaborative approach. (See The Rocky Road to Performance-based Regulation in Connecticut.)

PURA issued draft decisions in each of the three second-phase dockets in July and August (RE01, RE02, RE03). Final decisions for each of the three dockets are scheduled for Oct. 8, two days before Gillett is set to resign.

Noah Berman, utility innovation program manager at the Acadia Center, said he would be “surprised to see a major pivot” in the PBR dockets from the proposed rulings.

“The question is whether the utilities decide to act in good faith on what is being established, or to put aside the years of work that have gone into these frameworks in favor of trying to delay and relitigate under a new chair,” Berman said.

He expressed concern about a “post-resignation inquiry” that Avangrid submitted in the three PBR dockets, which argues Gillett “must have no further involvement” in all open dockets involving the company.

“Chairperson Gillett’s multiple public statements evidencing bias and prejudgment of issues that she is required by law to adjudicate on an impartial basis are well known and are already the subject of pending litigation,” Avangrid wrote. It added that, following the impeachment inquiry and Gillett’s resignation, “if there was any doubt as to whether Chairperson Gillett could fairly adjudicate any of our matters, it is now extinguished.”

Gillett’s involvement in remaining proceedings, including the open PBR dockets, “will not only compound existing legal challenges to PURA’s conduct but will result in new, unnecessary litigation,” Avangrid wrote.

The company added it has “credible concerns about the conduct and bias of other high-ranking PURA personnel,” and asked PURA to explain “what steps the agency will be taking to ensure that PURA staff who are unable to be objective about our matters are not hereafter involved in those matters.”

Both Eversource and Avangrid declined to comment directly on Gillett’s resignation, or the effects it will have on utility regulation in the state. The companies have denied all allegations that they attacked Gillett personally.

Clean energy and utility accountability advocates have been quick to push back on the allegations of impropriety or bias by Gillett and PURA staff.

“Nothing produced from the utility-led [Freedom of Information Act] campaign against Gillett showed anything but a regulator resolute in her commitment to ratepayers,” Pomerantz of EPI argued.

He added that, in 2022, Avangrid’s CEO allegedly offered to provide Gillett with opportunities for “international exposure” in advance of a rate case, while simultaneously threatening to pull investment in the state in the event of an unfavorable decision. Avangrid has denied any wrongdoing.

In an interview, Pomerantz said Gillett’s replacement as chair, along with regulators selected to fill two additional open commissioner seats at PURA, will have a major influence on how PBR is used in the state.

“Performance-based regulation, generally speaking, is really only as good as the regulators that are there to implement it,” Pomerantz said.

While PURA’s PBR framework would be “best-in-class in the country,” if the framework ultimately is approved, it will be “up to a new PURA and a new chair to decide how to implement that new regulatory model over time,” he said.

Lindsay Griffin, Northeast regulatory director for Vote Solar, said the “utilities’ resistance to PBR is entirely predictable,” noting that it would introduce revenue penalties for poor performance, along with bonuses for strong performance.

“With Chair Gillett’s departure, implementing robust performance-based regulation becomes more critical than ever,” Griffin said. “PBR represents the institutional safeguard that can continue protecting ratepayers even when regulatory leadership changes.”

Broader Implications

Griffin also expressed concern about the ripple effects Gillett’s resignation could have on utility regulation throughout the country.

“This resignation sends a chilling message: that sustained legal warfare and public pressure campaigns can drive exceptionally qualified public servants from office when they hold powerful interests accountable,” Griffin said.

She emphasized the importance of “robust regulatory scrutiny,” adding that utilities “should embrace regulatory oversight, not weaponize litigation to silence it.”

Pomerantz offered a similar sentiment, adding that he thinks the “rest of the utility industry will be very happy to attempt to use [Gillett] as an example, to say to any other regulator, or potentially a governor, that ‘we can do that to you too.’”

He said other regulators also appear to have been pushed out of their jobs after clashing with utility companies, citing Michigan Gov. Gretchen Whitmer’s decision to replace Alessandra Carreon on the Michigan Public Service Commission with a political staffer who had worked for a former Michigan House speaker who took large campaign contributions from utility executives.

Instead of feeling intimidated by Gillett’s resignation, Pomerantz expressed his hope that regulators across the country will have the opposite reaction.

“It would be really nice if more of the regulatory community took offense to what the utilities have done here in Connecticut and felt galvanized by it,” Pomerantz said. “I don’t know if that’s happening or not.”

Federal Energy Policy News Roundup: House Bills and DOE Returns $13B

The House Sustainable Energy and Environment Coalition (SEEC) introduced its “Cheap Energy Agenda” on Sept. 24, which it calls a consumer-focused approach to energy policy and includes the Cheap Energy Act. 

The bill, introduced by Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), addresses many issues and proposes big changes for FERC’s authority. 

“For too long, United States energy policy has prioritized the wants of energy producers over the needs of American consumers,” Casten said in a statement. “It’s past time things change. The Cheap Energy Act is a consumer-focused approach to energy policy that is rooted in American values like choice and competition. It will lower the cost of energy for American consumers by ensuring they have access to cheap, reliable and efficient energy.” 

In addition to reinstating the clean energy tax credits Republicans wound down via the One Big Beautiful Bill Act (OBBBA), the bill has a number of policy changes regarding FERC’s authority, some of which Casten (a longtime supporter of the agency) has proposed in the past. 

The bill would have FERC speed up interconnection queues, including promoting the use of automation and standardized study criteria. FERC also would have to change how it allocates costs for lines that are required to reliably bring new generation onto the grid — assigning costs to all beneficiaries and not just the new generator. 

FERC would be required to start up an interregional transmission planning process and allocate the costs of such lines in a way roughly commensurate with benefits. Another idea that comes back up in the bill is that it directs FERC to establish minimum interregional transfer capability between regions — 30% of peak demand for most regions, but just 15% for those that border only one other region. 

FERC would get exclusive siting authority over national interest transmission lines, which are defined as any that cross two or more states and have a capacity that exceeds 1,000 MW. 

Each ISO/RTO would have to set up independent transmission monitors to facilitate the transparent and efficient deployment of new power lines. Another section, modeled after an old Casten bill, includes reforms to the ISO/RTO stakeholder and governance processes, which would start with a technical conference at FERC. 

FERC would be required to establish a shared-savings program under which utilities are rewarded for providing real, independently verified cost savings to consumers. Another proposal would ban companies from trading in energy markets if they manipulate electric or natural gas markets. 

 

The U.S. Department of Energy used Section 202(c) of the Federal Power Act to keep open a pair of fossil plants this summer and fall. The bill would change 202(c) by requiring the department to publish cost estimates for such orders. It also would prohibit DOE from issuing 202(c) orders for any reason that is more than a year in the future.

House Republicans Pass a Couple of FERC-Related Bills out of Committee

The SEEC’s Cheap Energy Act includes a wish list of reforms supported by Democrats, but Republicans have been using their majority to push through legislation in the House and its Energy & Commerce Committee. Before taking a break for the Jewish High Holy Days, the committee passed three bills in a Sept. 19 hearing. 

“Today’s passage of H.R. 3062, H.R. 3015 and H.R. 1047 reflects the House Committee on Energy and Commerce’s relentless work to secure American energy dominance,” Committee Chair Brett Guthrie (R-Ky.) said. “These bills streamline the permitting process for critical cross-border energy projects, restore expert advisory input from the coal industry that the Biden-Harris administration eliminated and ensure that electricity grid operators have the tools they need to secure the reliability of the bulk power system. With rising energy demand and growing threats to grid reliability, House Republicans are ensuring the U.S. has the tools to deliver affordable, abundant and reliable energy.” 

Former North Dakota state regulator and NARUC President, Rep. Julie Fedorchak (R-N.D.) introduced H.R. 3062, the Cross Border Energy Act, which would streamline the permitting process for natural gas and oil pipelines and electric transmission that connects the United States to Canada and Mexico. If the bill is enacted, FERC would review applications for pipelines and DOE for transmission, as opposed to requiring a presidential permit for cross-border energy projects now. 

“The Keystone XL pipeline should have never been canceled. Yet on his first day in office, President Biden used the stroke of a pen to shut it down,” Fedorchak said. “By passing my legislation, the House has taken a critical step to end years of regulatory uncertainty and partisan games that have delayed energy infrastructure projects, crushed good-paying jobs and undermined America’s energy security.”  

The bill would stop future administrations from backtracking on permits that earlier administrations granted to infrastructure crossing borders. 

Rep. Troy Balderson (R-Ohio) introduced H.R. 1047, which seeks to speed up the interconnection queue for “baseload” power plants like those that use natural gas. The bill gives ISOs and RTOs the authority to prioritize energy projects that are ready to bring baseload power on the grid immediately. 

“The interconnection queue is overwhelmed and bogged down, leaving shovel-ready power projects waiting for years while demand continues to climb,” Balderson said in a statement. “The GRID Power Act clears the path for the most critical projects, giving grid operators the tools they need to add more dispatchable baseload power — lowering costs for households and businesses while keeping America’s grid reliable.”  

Expediting resources that advance reliability provides grid operators with additional tools to re-balance the resource mix and keep the lights, while reversing the “legacy effects of the Biden-Harris energy policies that continue to drive prices higher,” the committee said.

DOE Announces $13 Billion in Biden Era Funds are Back in the U.S. Treasury

Speaking of reversing Biden-era policies, DOE announced Sept. 24 that it was returning $13 billion in unobligated funds initially appropriated to advance green energy policies. 

“The American people elected President Trump largely because of the last administration’s reckless spending on climate policies that fed inflation and failed to provide any real benefit to the American people,” U.S. Energy Secretary Chris Wright said. “Thanks to President Trump and Congress, those days are over. By returning these funds to the American taxpayer, the Trump administration is affirming its commitment to advancing more affordable, reliable and secure American energy and being more responsible stewards of taxpayer dollars.” 

The authorization to reverse the tax spending came under OBBBA, which the Trump administration has since rebranded the “Working Families Tax Cut,” and is meant to rein in federal spending and return unobligated funds to the Treasury. Exactly what the money had been earmarked for is unclear, and DOE did not respond to a request to explain that.

Dallas Fed Survey Shows Some Worries about State of Oil and Gas Industry

Meanwhile, the Federal Reserve Bank of Dallas released its regular quarterly survey of oil and gas executives on Sept. 24. The survey includes projections for future fuel prices and some selected quotes on the industry. The survey found expectations for natural gas to cost $3.35/MMBtu in six months and $3.53/MMBtu in a year, which compares to the prompt month closing at $2.853/MMBtu on the NYMEX on Sept. 24. 

The comments are anonymous, and many of them reflect the uncertainty in federal policy and argue that the Trump administration’s actions are working against domestic oil production but are helping natural gas. 

“Because of global circumstances, we think crude oil prices will stay low at the $60 per barrel level,” one respondent said. “Alternatively, because of an increase in the LNG market, we feel that natural gas development and production will increase.” 

Another complained that the Biden administration had vilified shale oil and gas, which led to less investment, but things have not turned around since Trump took office. 

“Guided by a U.S. Department of Energy that tells them what they want to hear instead of hard facts, they operate with little understanding of shale economics,” an anonymous executive told the Fed. “Instead of supporting domestic production, they’ve effectively aligned with OPEC — using supply tactics to push prices below economic thresholds, kneecapping U.S. producers in the process. The collapse of capital availability has fueled consolidation by the majors, pushing out independents and entrepreneurs who once defined the shale revolution. In their place, a handful of giants now dominate, but at the cost of enormous job loss and the destruction of the innovative, risk-taking culture that made the U.S. shale industry great.” 

A third executive worried that aggressive anti-renewable policies from the Trump administration will not be good even for oil and gas in the long term. 

“Day-to-day changes to energy policy is no way for us to win as a country,” they said. “Investors (rightly) avoid investing in energy (of all types, now) because of the volatility of underlying business results as well as the ‘stroke of pen’ risk that the federal government wields as it relates to long duration energy developments. Life is long, and the sword being wielded against the renewables industry right now will likely boomerang back in 3.5 years against traditional energy, which will find itself facing harsher methane penalties, permitting restrictions, crazy environmental reviews and other lawfare tactics.” 

CISA Publishes Cybersecurity Asset Inventory Guide

With operational technology (OT) systems increasingly vulnerable to cyberattacks, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released a guide to help infrastructure owners and operators map their systems and plan their defense strategies.

CISA created the Foundations for OT Cybersecurity: Asset Inventory Guidance for Owners and Operators document through the Joint Cyber Defense Collaborative, an initiative between the private and public sectors that seeks to unify “cyber defense capabilities and actions of government and industry partners.” Entities from the water, oil and electric sectors contributed to the guide, including Duke Energy, Eversource, Pacific Gas & Electric and Southern California Edison.

OT systems have traditionally been separate from entities’ information technology (IT) and business networks. However, in today’s industrial landscape, OT is increasingly integrated with IT for business efficiencies; this creates opportunities for cyber attackers to access OT systems after gaining entry into a company’s IT network.

The guide provides assistance for entities to develop OT asset inventories, which are defined as “organized, regularly updated [lists] of an organization’s OT systems, hardware and software.” Asset inventories are “foundational to designing a modern defensible architecture,” CISA said, because they quickly give organizations insight into their networks to see what might be vulnerable when new threats are revealed.

CISA considers OT asset inventories so important that the agency added them to its list of cybersecurity performance goals, a set of best practices developed in tandem with the National Institute of Standards and Technology that are recommended for all organizations to provide a baseline level of protection.

The guide lays out multiple steps involved in developing an OT asset inventory. First, an organization should define the scope and objectives of the project. This includes defining the authority within the entity that needs the inventory and what positions will be responsible for establishing and maintaining it.

Next, the entity must inspect its system to identify the physical and digital assets and collect asset attributes. Attributes are fields that describe the asset; the guide lists items that entities should prioritize, such as active and supported communication protocols, asset criticality, IP address, manufacturer, physical location and associated user accounts.

A critical step in the process is creating a taxonomy for assets. Organizations must classify assets based on criticality for function; categorize assets and their communication pathways using an existing method or one devised by the entity itself; organize structure and relationships; cross-check and verify accuracy and completeness of the data; and periodically review and update it.

Recognizing that entities in various sectors may have differing needs, the document’s authors provided samples of taxonomies for several industries in the appendices, including electric utilities, based on exercises and discussions with sector representatives. The electric example divides assets into categories by function, such as communications; generation; transmission and distribution; physical and electronic access control or monitoring systems; energy management systems; and distributed energy resources.

Once the inventory is compiled, organizations may use it for several functions. These include cybersecurity and risk management — identifying vulnerabilities and mitigations for OT systems, prioritizing threat factors and strengthening security posture — and maintenance, which can mean assessing the cost of replacing vulnerable systems or analyzing their spare parts inventory to identify any potential gaps. Inventories can also help with performance monitoring and reporting, staff training and informing change management processes.

“More than just a technical manual, this guidance serves as a strategic enabler for cyber defense actions and operational collaboration with CISA and other key stakeholders,” CISA said in a press release. “With a precise understanding of the assets within an operator’s infrastructure, common vulnerabilities and exposures … become significantly more actionable and timely — helping operators reduce risk proactively, before incidents escalate.”

MISO Cuts Renewable Estimates in Tx Planning Scenarios

MISO has slashed earlier renewable energy estimates and boosted natural gas contributions in its transmission planning futures in a rethink brought on by the Trump administration.

Director of Economic and Policy Planning Christina Drake told stakeholders that MISO took a “very hard pivot” to incorporate the One Big Beautiful Bill Act into its four, 20-year futures, which are used to plan long-range transmission.

MISO was on its way to completing the futures and publishing capacity expansion estimates when the bill was passed in July. Staff have added months to the process and expect to deliver final futures sometime in early 2026. (See MISO Seeking Realistic Gen Buildout for Tx Planning Futures.)

“There is quite a bit of reduction in some of the renewable buildout,” Drake said before a Sept. 24 stakeholder teleconference. She also said MISO is reflecting increases in natural gas buildout in its members’ resource planning.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said gas now represents a much higher share of the capacity expansion than when MISO last updated its futures in 2022.

MISO’s preliminary capacity expansion estimates by 2045 now include:

    • For Future 1, a total of 383 GW in installed capacity derived from 28% gas, 25% solar, 25% wind, 11% other, 4% battery, 4% nuclear and 3% coal at 911 TWh of output, with 224 GW built between now and 2045.
    • For Future 2, a total of 403 GW in installed capacity from 25% gas, 25% solar, 30% wind, 11% other, 3% battery, 4% nuclear and 3% coal at 1,075 TWh of output, with 254 GW constructed in 20 years.
    • For Future 3, a total of 446 GW from 19% gas, 31% solar, 29% wind, 10% other, 3% battery, 6% nuclear and 1% coal at 1,253 TWh of output, with 318 GW built between now and 2045.
    • For Future 4, a total of 454 GW from 25% gas, 33% solar, 20% wind, 10% other, 3% battery, 4% nuclear and 4% coal at 1,079 TWh of output, with 281 GW constructed.

MISO’s futures are fashioned through a “fast, faster, fastest” methodology for fleet change and demand in Futures 1-3. Future 4 — new for 2026 — anticipates continued supply chain hindrances and only includes member-announced generation retirements. Unlike the other futures, it doesn’t assume age-based retirements of thermal generators, resulting in about 23 GW of additional thermal generation compared to the other three futures.

MISO’s members have announced intentions to build 171 GW in resources by 2045. MISO’s modeling had to add the most supplemental resources to Future 3, where only 58% of capacity needs would be met using the 171 GW.

The RTO’s fleet prediction in 2022 under Future 2 for 2042 was 471 GW of installed capacity, consisting of 14% gas, 24% solar, 34% wind, 11% other, 9% hybrid resources, 6% standalone batteries, 2% nuclear and 2% coal. That future formed the basis for MISO’s nearly $22 billion long-range transmission plan for MISO Midwest.

MISO said sustainability goals from states and members, not federal incentives, would drive future capacity expansion.

Drake said as it stands across all futures, milestone goals from 2026 to 2028 in Illinois’ Climate and Equitable Jobs Act and New Orleans’ renewable portfolio standard were unattainable. MISO said lead times to build units made the goals infeasible in the near term. Illinois has set out to achieve 100% carbon-free energy by 2050, with interim targets of 40% renewable energy by 2030 and 50% by 2040. New Orleans, on the other hand, is attempting to achieve net carbon neutrality by 2040 and 100% carbon-free electric generation by 2050.

Decarbonization goals across MISO states | MISO

MISO’s Environmental Sector requested a sensitivity study on the futures where natural gas prices rise, prompting an energy storage expansion.

Sustainable FERC Project’s Natalie McIntire said she wondered whether the futures for use in scenario-based planning should be more “diverse” from one another and contemplate a wider range of possibilities. She said MISO should contemplate variables like rising gas prices and falling battery prices, along with the possibility of a reinstatement of tax credits for renewables.

Drake said MISO will check in with stakeholders once futures are more developed. She added that MISO planners have asked themselves the same questions.

“If we get to the end of this process and we don’t have broad bookends, we will revisit,” Drake promised. She stressed that MISO’s numbers aren’t final yet.

Drake said MISO is halfway through the recalibration of its futures. She said initially, removal of tax credits for wind and solar resulted in MISO’s model building a hypothetical 100 GW within a single year to take advantage of the fading perks. Drake said after MISO staff “laughed” at the results, they removed the possibility for renewable production and investment tax credits for generation not already in the queue.

“The rationale for that is if it’s not already in queue … it won’t be in the ground and ready to go by 2028,” she said.

Drake also said MISO must complete generation siting and large load siting for use in its transmission models alongside completing energy adequacy assessments to develop the futures. She said MISO would discuss the locations of large loads in the footprint in November.

MISO Senior Vice President of Planning and Operations Jennifer Curran said members recently have swapped lower accredited renewables for higher accredited dispatchable plants in their plans. She also noted that the U.S. Department of Energy has become “directly involved” in resource retirements, issuing a second extension of Consumers Energy’s J.H. Campbell coal plant in Michigan.

“There has been a lot of activity on the federal front,” Curran acknowledged at a Sept. 17 Advisory Committee meeting in Detroit, part of MISO’s quarterly Board Week.

Curran said it became apparent that a repurposing of futures was necessary in July, when the early expiration of tax incentives became clear.

“We’re putting a lot of eggs in the gas development basket,” Clean Grid Alliance’s Beth Soholt said in response to MISO’s remarks, asking whether the RTO would factor in pipeline capacity issues and fuel availability limits.

Curran said MISO would try to capture the fuel availability associated with “explosion” in gas development and pipeline constraints in the resource’s capacity accreditation.

IESO Ups Capacity Target for Long Lead-Time Resources

IESO has increased the capacity target for its planned solicitation for long lead-time (LLT) resources, even as it acknowledges questions about the need for the procurement. 

The ISO plans to seek 600 to 800 MW of capacity from resources requiring at least five years of lead time, up from its proposed 600 MW, “to recognize the volume of system needs arising in 2035,” officials told stakeholders at an engagement session Sept. 16. The energy target will be up to 1 TWh, unchanged from what the ISO outlined at its June 5 engagement. 

IESO decided to pursue a separate LLT procurement in response to stakeholder feedback that energy storage resources such as compressed air and pumped hydro require longer planning cycles than the four-year lead times for resources offering in the pending Long Term 2 (LT2) procurement. Energy proposals for LT2 are due Oct. 16, and capacity proposals are due Dec. 18. (See IESO Officials Deny Favoring Gas Resources in Upcoming Procurement.) 

The ISO issued a request for information last fall to guide its design of the LLT solicitation and summarized its findings in an Aug. 29 report to the Ministry of Energy and Mines. 

Requirements

To participate in the LLT procurement, resources must require a lead time of five or more years and have an operating life of 40 years, versus 20 years in LT2.  

Technologies for which IESO is less familiar — such as emerging long duration energy storage (LDES) — may need to prove they meet the lead-time requirement with an independent engineer report detailing the project scope, permitting path and supply chain constraints. 

Although the LLT RFP is intended for new resources, IESO is considering including hydropower redevelopment projects — large-scale replacements of existing equipment that IESO said “would be similar in scope to a new build facility.” 

“Following redevelopment, the expected operational life of the facility would be comparable to that of a newly constructed facility,” the ISO said. 

Reservoir hydro projects (those with storage capability that are not pumped hydro) will be eligible to participate in the energy stream only because they would be unable to offer full contract capacity between 7 a.m. and 11 p.m. on business days, as required for capacity resources. 

Pumped storage and other LDES resources will be eligible to submit in the capacity stream only. 

IESO plans an engagement in October to discuss hydro repowering, expansions and upgrades of hydro and other resource types in its procurements. 

Questioning the Need for LLT Procurement

Jonathan Cheszes, president of Compass Greenfield Development, questioned the need for the LLT solicitation, saying the eight- to 12-hour requirement for capacity resources is “functionally consistent” with that in the LT2 capacity procurement.  

“If you need eight to 12 hours of capacity, then why not ask for eight to 12 hours of capacity? … Why limit what technologies can participate?” he asked. 

IESO’s Ben Weir said the LLT RFP is an effort to procure resources with attributes — such as a 40-year life span — that can’t compete in LT2.  

“There’s not much point in signing a 40-year contract with a battery, because it’s not going to last 40 years … the way we intend to use it,” Weir said. 

Cheszes suggested the LLT procurement was premature.  

“If you’re going to get eight to 12 hours out of LT2 … maybe see what the pricing comes in at before” seeking a solicitation for LLT resources, he said. 

“You raise an absolutely valid concern,” responded Dave Barreca, IESO’s supervisor of resource acquisition. “Please believe me that this is top of mind for us. … We are thinking very hard about ratepayer value and prices and how to manage that for this RFP, given that … the field of competition is quite narrow.” 

IESO’s proposed solicitation for long lead-time resources would include long duration energy storage technologies such as compressed air energy storage. | Pacific Northwest National Laboratory

“Forty years [is] a long time,” Cheszes responded. “Just imagine what batteries are going to cost 20 years from now. … And whatever [the] technology [will be, it] won’t be lithium ion, right? It’ll be something totally different. So, you know, locking in 40 years — there’s some pluses, but there’s a bunch of minuses as well.” 

Weir said ISO officials will hold engagements monthly for the rest of 2025 to develop the RFP, with proposals expected in the fourth quarter of 2026 and contract awards in the first half of 2027. The timing of the RFP and the target sizes will be finalized after receiving guidance from the ministry, Weir said. 

Weir said IESO may accept a percentage of all proposals submitted — perhaps 80% — similar to what the ISO did in its second medium-term solicitation (MT2). (See IESO Purchasing 3,000 MW of Energy and Capacity.) 

“This is just a way to maintain competitive tension if the numbers of proposals received are lower than we expect,” he said. 

Rated Criteria

IESO is seeking more information on potential projects in prime agricultural areas (PAAs) to inform how it sets its rated criteria” — non-price factors used to evaluate proposals — for the procurement.  

Some stakeholders said the ISO should not use rated criteria based on locations, such as for proposals located in northern regions or outside of PAAs. 

IESO said its criteria will “be reflective of policy decisions made by the Ministry of Energy and Mines.” 

The ministry also will weigh in on whether IESO should offer price incentives — in addition to rated criteria points — for projects involving Indigenous communities. 

Round Trip Efficiency

IESO is considering minimum round-trip efficiencies (RTEs) — and incentives for exceeding them — because LDES are expected to have lower RTEs than battery storage.  

Barreca said resources considering participating in the LLT RFP have offered a wide range of RTEs with a “middle” of about 60%. That “is quite different than what we’ve seen … in the lithium-ion batteries that we’ve procured” in the first long-term procurement, he said. 

Outages

The ISO plans to use the same rules for planned outages as under LT2. Energy resources should incorporate planned outages into their imputed production factors to avoid non-performance charges. Capacity resources will be permitted a planned outage of up to one month during April, May, October or November. 

Resources will be permitted one long-term outage — a maximum of six months — during the second half of their contracts. 

Environmental Attributes

IESO is considering allowing suppliers to retain the proceeds from sales of “environmental attributes” during the first 20 years of the contract, with the supplier sharing the attributes with IESO in the second 20 years. 

Although suppliers are unlikely to place much value on the attributes for 2051-2070, Barreca said, “there is a good chance that there will be some value there” that could be recovered for ratepayers. 

“We are certainly open to the alternative, which is that you do have forecasts for what those are going to be worth, and you are willing to put those values into your proposal prices,” he added. 

Defining LDES

Open-loop pumped storage hydropower systems connect a reservoir to naturally flowing water via a tunnel, using a pump to move water to higher elevations and a generator to create electricity. | DOE

In addition to inviting participation by compressed air energy storage and pumped hydro storage, IESO will consider emerging technologies such as liquid air energy storage and compressed gas “that are able to demonstrate a sufficient level of technology readiness.” 

Stakeholders told IESO it should clarify its definition of commercially proven LDES technologies and allow participation from LDES technologies with a technology readiness level of eight or higher, indicating it is ready to move from development to commercialization, per the U.S. Department of Energy. 

Although some stakeholders pushed IESO to increase the minimum duration requirement to 10 or 12 hours, the ISO said it expects participating LDES resources “to be in the eight- to 12-hour duration range, which can realize the most reliability benefits at this time.” 

Barreca said IESO’s planning team is conducting research to understand the value of increasing the minimum duration. 

“We’ll need to make a call in terms of whether we think the extra value would be worth the extra price to make that a minimum requirement,” he said. “There is more study required to go to the 24-hour or … multiday storage. That will be a different procurement.” 

Non-performance Charges

The ISO rejected requests that non-performance charges for energy producing resources be based on a five-year rolling average versus the three-year average used in LT2. The three-year average “allows for effective accounting of anomalies that may impact production, such as irregular weather patterns,” IESO said.  

Barreca said the ISO is sticking to a three-year average “primarily because this is a competitive RFP, not a standard offer program, and there are quite a number of variables that a proponent has to work with to find their optimal risk profile.” 

Price Escalation

IESO still is determining how it will escalate prices during the contract term. 

Some potential suppliers said IESO should provide 100% inflation indexing from the contract date to the commercial operation date (COD) — similar to that in the LT2 RFP — and 60% indexing from COD until the contract end date. 

Barreca said the 100% indexing in LT2 “was a direct response to the geopolitical environment at the time.” 

“We have a little bit of runway ahead of us to see what happens there,” he added. “I think we are going to wait just a little bit longer and see how the world evolves between now and then.”