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November 5, 2024

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Appeals Court Upholds FERC on Gas Project Extensions

FERC on March 29 came out on top of litigation over its granting previously approved natural gas projects’ requests for an extension of their deadlines to bring the facilities online (22-1233). 

The Sierra Club challenged two such orders before a three-judge panel of the D.C. Circuit Court of Appeals: National Fuel Gas Supply’s Northern Access Pipeline in Pennsylvania, and New York and Cheniere’s plan to expand its Corpus Christi Liquefaction LNG facility in Texas. Public Citizen joined Sierra in opposing the extension for the LNG facility. 

The New York State Department of Environmental Conservation denied National Fuel’s request for a permit, which set off years of litigation in federal court and caused it to seek two extensions from FERC. The firm won the case and filed its second request with the commission in 2022, which was granted. 

Cheniere’s LNG facility ran into delays because of the economic impacts of the COVID-19 pandemic and filed with FERC to extend its in-service date from later this year to 2027. FERC granted that, agreeing that the firm could not foresee the pandemic’s impacts on the global economy when its initial plans were made. 

FERC has broad discretion to grant the extensions, which is only limited by the “arbitrary and capricious” standard of the Administrative Procedure Act. It does not have to come to the best decision in such cases, with the court’s review limited to whether the commission examined the relevant considerations and articulated a satisfactory explanation for its action that includes a rational connection between the facts and its ruling. 

“In considering the requests for extensions, FERC found that the project sponsors had demonstrated diligence in the continued pursuit of their projects,” the court said. 

The litigation with New York and the pandemic’s impact on supply chains and the economy gave good cause for the extensions, the court said. FERC’s reasoning in both cases was consistent with its earlier decisions granting extensions. 

“FERC has found a wide range of circumstances to support good cause, including legal or litigation-related barriers, as well as impacts from the COVID-19 pandemic,” the court said. 

Sierra Club and Public Citizen argued that FERC’s inquiry was too lax, saying the agency rubber-stamps requests for extensions. 

“Although it is true that FERC has denied very few extension requests, that is not surprising,” the court said. “Project sponsors invest significant time and resources to secure approval of their pipelines and related facilities, and they generally have economic incentives to promptly complete construction.” 

Project sponsors can meet the good-cause standard by demonstrating their diligence and citing factors beyond their control that have slowed their progress, the court said. Developers who would abandon a project likely would never ask for an extension. 

Sierra Club also argued that FERC should have to re-evaluate the findings underlying its original certificate order any time it considers an extension request, but the court disagreed. FERC has broad authority to take whatever actions it finds necessary to amend a certificate. 

While the commission has to account for substantial or significant changes that impact a project’s approval under the National Environmental Policy Act, it is entitled to substantial deference because that call necessarily relies on FERC’s technical expertise, the court said. 

New York passed its Climate Leadership and Community Protection Act while the Northern Access project was being developed; Sierra Club argued that constituted a major change. But FERC found that the law did not impact demand for the pipeline’s gas, which is largely going to serve customers in Canada, where that law has no impact. The court again sided with the commission. 

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FERC Accepts, Sets Hearing on ND Co-op’s Tariff Rates

FERC on March 26 accepted SPP’s proposed tariff revisions modifying Central Power Electric Cooperative’s formula rate template but suspended them for a nominal period subject to refund and established hearing and settlement procedures (ER24-254). 

The commission found the proposed revisions raised issues of material fact that are more appropriately addressed in an administrative hearing. FERC encouraged the proceeding’s parties to reach a settlement before the hearing begins. 

The tariff revisions are suspended for a nominal period, effective Jan. 1, subject to refund. 

SPP filed Central Power’s requested formula rate template with FERC last year. The cooperative asked for a base return on equity of 10.29% and a 50-basis-point adder for its SPP membership. It said incorporating the adder for its initial and continuing RTO membership, previously approved by the commission, resulted in a total ROE of 10.79%. 

The commission said the adder continues to be appropriate given Central Power’s continued SPP membership. However, it found that the ROE, inclusive of the adder, must remain within the zone of reasonableness as determined by hearing and settlement judge proceedings. 

FERC rejected protests by the Western Area Power Administration and Missouri River Energy Services that Central Power should revise the template and the formula rate protocols governing the template’s updates and how the resulting rates will be implemented each year. It said the utilities did not demonstrate how the cooperative’s unchanged template and protocols are “integral to the revisions proposed by Central Power.” 

“We also find that nothing in the interaction between Central Power’s proposed revisions” and the template’s and protocols’ elements “discussed by Missouri River and [WAPA] create an unjust and unreasonable result,” the commission wrote. 

Central Power, headquartered in North Dakota, is a wholesale generation and transmission cooperative interconnected with SPP members WAPA, Basin Electric Power Cooperative and several other utilities. 

While Central Power, a borrower from the Rural Utilities Service, is not a “public utility” under the Federal Power Act, FERC cited precedent and a federal appeals court ruling to find it appropriate to apply the act’s just-and-reasonable standard to the cooperative’s proposed formula rate revisions, which are a component of SPP’s jurisdictional rates. 

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MISO Sets Sights on 2025 Completion for New Market Platform

MISO reported it’s making steady progress on installing a new market platform by the end of next year and will debut a new day-ahead market clearing engine this spring.  

The RTO said it likely will begin using its new, day-ahead market clearing engine exclusively sometime in May. 

At a March 27 customer readiness symposium meant to prepare members for MISO’s technological advances, MISO’s Arijit Bhowmik said the RTO is nearing the completion of parallel operations of the day-ahead clearing engine. MISO has said once it has its new clearing engine up and running smoothly, it can retire the legacy clearing engine from parallel operations. 

The grid operator was forced to push back the launch of the day-ahead market clearing engine to early 2024 instead of late 2023 due to delays. (See “Market Platform Replacement to Spill over into 2025,” MISO Board Week Briefs: Dec. 6-8, 2022.)  

MISO is slated to finish its market platform replacement completely by the end of 2025. It previously had ambitions to wrap up the project by the end of 2024, though it frequently cautioned the timeline could run longer. The RTO began the process of swapping out its outdated market platform for a new, modular platform in 2017. 

In late 2025, MISO will replace its real-time market clearing engine, which the grid operator uses every five minutes to send dispatch instructions. It also will go live in early 2025 with a new look-ahead commitment tool for generators.  

MISO completed factory acceptance testing and took delivery of its new real-time engine in 2023.  

Bhowmik said he hopes the introduction of the more nimble, modular platform can allow MISO to scale back the support hours it spends with members on the vintage platform.  

MISO has said it expects to spend $152 million on the market platform replacement, including about $14 million this year. It estimated program benefits remain steady at about $430 million. The grid operator began the market platform project with a $130 million budget and a $30 million contingency.  

Last year, MISO Director Theresa Wise said though the project now is “at the edge of” MISO’s budget plus contingencies, MISO expects the new platform to save at least a few hundred million dollars. 

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New England States’ OSW Procurement Receives 5,454 MW in Bids

The coordinated offshore wind procurements of Connecticut, Massachusetts and Rhode Island received 5,454 MW in bids from four developers, falling short of the 6,000-MW solicitation cap.  

The window for bids closed March 27 in the first-of-its-kind coordinated procurement. The states are hoping that joint solicitations will reduce costs by enabling larger-scale projects and better utilizing regional supply chains. Projects could be submitted both as single-state and multistate offers to two or three of the states. 

The procurement comes on the heels of a turbulent period for offshore wind in New England. Avangrid Renewables and SouthCoast Wind both backed out of power purchase agreements with Massachusetts in 2023, while Rhode Island Energy canceled the PPA for a joint Eversource- Ørsted project, citing cost concerns. 

The bids included multiple recently canceled projects from Avangrid Renewables and SouthCoast, along with new proposals. Avangrid, Ørsted, SouthCoast and Vineyard Offshore all submitted bids for the procurement. 

Avangrid

The largest proposal came from Avangrid, which offered an approximately 1,870-MW combined bid of two projects, including its canceled Commonwealth Wind project. The projects, dubbed New England Wind 1 and New England Wind 2, would connect to the grid in Barnstable, Mass. 

Avangrid touted the 791-MW New England Wind 1 as a “shovel-ready project” that could reach commercial operations by 2029. It was offered as both a standalone project and a combined proposal with New England Wind 2. 

“With nearly all local, state and federal permits in hand, all interconnection rights secured and a project labor agreement signed with a skilled, local, union workforce, Avangrid is ready to go,” CEO Pedro Azagra Blazquez said. 

The 1,080-MW New England Wind 2 project, essentially a rebranding of the canceled Commonwealth project, was only offered as part of the combined proposal “to capture important economics of scale and support significant grid upgrades,” the company wrote. 

The company also announced memorandums of understanding for power purchases with the city of Boston and the Massachusetts Municipal Wholesale Electric Co. Boston’s MOU will enable it to purchase up to 15 MW of power from New England Wind. 

“This partnership advances our climate goals while bringing thousands of green jobs to our region, creating a pathway for generations to come,” said Mayor Michelle Wu. 

Vineyard

Vineyard — funded by Copenhagen Infrastructure Partners, Avangrid’s partner on the Vineyard Wind 1 project — proposed a 1,200-MW project dubbed Vineyard Wind 2 to all three states. The project would be south of Nantucket, reaching the shore in New London, Conn., and connecting to the grid in Montville.   

“By making effective use of ports, facilities and interconnection points throughout the region, Vineyard Wind 2 offers the most economic project configuration possible while delivering economic benefits for all three states,” said CEO Alicia Barton.  

The company also highlighted a recently signed tribal benefit agreement with the Mashpee Wampanoag Tribe for the proposal. According to the bid, the agreement would create a fund to “support education, environmental and natural resources, cultural resources and historic preservation efforts by the tribe.” 

SouthCoast

Following the cancellation of its PPA in 2023, SouthCoast resubmitted a 1,200-MW proposal to the states for the coordinated solicitation. The company said it could begin construction in 2025 and reach commercial operations by 2030. 

“The punishing inflation of 2020-2023 profoundly impacted infrastructure costs, upending the economics of projects that had fixed revenues but still needed to fix their costs,” the company wrote. “The clear lesson is that a quick turn from award to construction is critical to de-risk a macroeconomic environment that no one can control.” 

The project has “crucial manufacturing slots and supply chain reservations secured and [a] federal permit Record of Decision expected this year,” the bid noted. 

Ørsted

Ørsted submitted standalone and multistate bids in Rhode Island and Connecticut for its 1,184-MW Starboard Wind project. 

Ørsted and Eversource are constructing Revolution Wind, a 704-MW project that will provide power to Rhode Island and Connecticut. Ørsted and Eversource’s bid for Revolution Wind 2, a proposed 884-MW project, was rejected by Rhode Island Energy in 2023. 

“While the project name Starboard Wind is new, our work on the project itself is not,” Ørsted wrote. “We’ve been developing the offshore project site for nearly a decade, giving us extensive site data and a deep understanding of how to construct our proposed offshore wind farm successfully.” 

The three states now have until Aug. 7 to evaluate and make decisions on the bids.  

“The Healey-Driscoll Administration will review bids over the coming months and coordinate with Connecticut and Rhode Island to evaluate multistate projects that would increase benefits for the region,” said Elizabeth Mahony, commissioner of the Massachusetts Department of Energy Resources. “Massachusetts is committed to growing its offshore wind industry, which will spur our clean energy transition and provide renewable, affordable power to our homes and businesses.” 

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NEPOOL TC Approves Process for States’ Transmission Needs

The NEPOOL Transmission Committee voted on March 27 to create a planning process for long-term transmission needs identified by states to meet their clean energy goals.

The new process — Extended-term/Longer-term Transmission Planning Phase 2 — was developed by ISO-NE and the New England States Committee on Electricity (NESCOE) in response to concerns from the states about transmission needs that extend beyond the typical planning horizon.

The proposal builds on the first phase of the transmission planning project — which created a process to study long-term transmission needs and was approved by FERC in 2022 — by creating a process for states to act on needs identified in those studies. 

“This effort, Phase 2, establishes the rules that enable the states to achieve their policies through the development of transmission to address anticipated system concerns and the associated cost allocation method,” said Brent Oberlin, ISO-NE director of transmission planning. 

In the new process, states can direct ISO-NE to issue a request for proposals for projects addressing long-term transmission needs. After soliciting bids from transmission developers, the RTO will quantify projected costs and benefits for each bid, with the benefits required to outweigh the costs to be eligible to be selected. ISO-NE will then select a preferred solution, with NESCOE then given the option to proceed or cancel the project. 

By default, the costs associated with these projects will be regionalized, although NESCOE can also submit an alternative cost allocation method for any project.  

The TC approved a supplemental process for when no projects pass the cost-benefit threshold. The costs commensurate with the benefits would be regionalized, while individual states can voluntarily cover any remaining costs in order to proceed with a project. 

The committee also approved an amendment to the proposal introduced by Avangrid that directs ISO-NE to conduct an independent cost assessment of bids submitted by transmission developers. 

Alan Trotta of Avangrid said different bidders may have different methodologies for calculating their project costs and that “a consistent cost estimating methodology by one entity will put bids on a level playing field.” 

Ensuring an independent assessment, either by ISO-NE or a third party commissioned by the RTO, would prevent aggressive cost estimations or differences in project scope from unfairly influencing the results of the project selection process, Trotta said. 

ISO-NE indicated that it will incorporate this amendment into the proposal it brings to a vote at the NEPOOL Participants Committee in April.

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FERC Waives Nearly $2M in CAISO Data Reporting Penalties

FERC on March 27 granted complaints by five utilities against CAISO, nullifying nearly $2 million in penalties for incorrect meter data reporting. 

Idaho Power (EL23-94), Tucson Electric Power (TEP) (EL24-15), Direct Energy Business (EL24-11), Tacoma Power (EL23-103) and the city of Corona, Calif. (EL23-99), all submitted complaints last year challenging the application of CAISO tariff section 37, which spells out the ISO’s rules of conduct. 

Under the section, if a scheduling coordinator fails to submit meter data 52 days after the trading date, the submission is considered late. Failure to submit revised meter data 214 days after the trading day for the resettlement statement that CAISO issues is considered an inaccurate submission. Either violation subjects a scheduling coordinator to a $1,000 penalty for each trading day after deadlines are missed. 

Each of the complainants told FERC that CAISO was applying the provision too strictly for “minor, inadvertent” errors and that the errors had practically no effect on the markets, making the penalties unjust and unreasonable. 

The commission agreed “that the penalties assessed are not commensurate with any potential damage caused by the inadvertent errors, which were properly reported upon discovery, promptly fixed and had a de minimis effect” on the markets. 

The ISO also supported all the complaints, saying that until the rule is changed, it “supports relief for parties that receive excessive penalties under the existing tariff rules.” In May 2023, it opened the Rules of Conduct Enhancements stakeholder initiative to address issues including the potential for excessive penalties in certain circumstances. 

Several of the complaints noted that the tariff provision does not allow CAISO discretion in waiving or reducing penalties. 

Idaho Power had appealed $639,000 in penalties for incorrect data associated with the Arrowrock Hydroelectric Project. In July 2022, the utility discovered that transmission line losses were being double counted in the meter data being provided to CAISO, leading to under-reporting of energy produced by Arrowrock. Idaho Power argued that because the quantity did not affect LMPs or market runs in the Western Energy Imbalance Market (WEIM), the penalties should be waived. 

Tacoma’s reporting errors stemmed from setting its transmission system loss factor of 1.87%, which resulted in it under-reporting load by an hourly average of the same amount. It said the error occurred because of a misunderstanding in the treatment of line losses that occurred when it joined the WEIM. Upon noticing the error, it immediately reported it to CAISO and corrected it the next day. 

Both Corona and Direct Energy challenged their respective $342,000 and $825,000 penalties for errors resulting from Southern California Edison changing its billing system, saying it acted in good faith by notifying CAISO of the error upon discovery.  

Like Tacoma, TEP appealed penalties related to an inadvertent miscalculation during its integration into the WEIM. However, the utility did not submit settlement statements with its complaint; rather, it submitted nine CAISO notices of review, issued over the course of 2023, for periods of trading days in 2022.  

FERC agreed to only waive the penalties — $191,000 — described in the last notice, issued Oct. 31, 2023; TEP filed its complaint in November. The other eight “do not provide sufficient information for us to determine whether the instant complaint was filed with the commission within 22 business days from the date of issuance of any of the corresponding settlement statements,” as required by the tariff, the commission said. It set the other penalties for paper hearing, ordering TEP to file evidence that it submitted its complaint in a timely manner. 

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GCPA Tabs Clemenhagen as New Exec Director

The nonprofit Gulf Coast Power Association has selected Barbara Clemenhagen as its next executive director. 

Clemenhagen, vice president of market intelligence at Customized Energy Solutions (CES) and a member of the GCPA Board of Directors, will succeed Kim Casey, who is retiring in June. 

Board President Beth Garza said March 28 the board conducted a “thorough search process” to replace Casey, who announced her retirement last year. She and Clemenhagen will work together during a short transition. 

Clemenhagen has more than 30 years of executive experience in the U.S. and Canadian utility industries. She joined CES from Topaz Power, where she was vice president of commercial and external relations, and previously was a regulatory commissioner at the British Columbia Utilities Commission. 

She has served on ERCOT’s board, the ISO’s Technical Advisory Committee and as chair of the Wholesale Market Subcommittee. Clemenhagen was president of the Texas Competitive Power Advocates trade organization from 2009 to 2013. 

Clemenhagen said she is honored to serve as the GCPA’s next executive director and plans to guide the organization to its 50th anniversary in 2036. 

“GCPA is a leader in providing best-in-class networking and education conferences in the ERCOT, MISO and SPP footprints, and I look forward to continuing to provide excellent programming and advancing the GCPA to new heights,” she said. 

Garza said the GCPA is “thrilled” to have Clemenhagen on board. “She has a distinguished career in the electric power business and has been involved with GCPA for a number of years,” Garza said. 

Clemenhagen will be the GCPA’s fifth executive director since the organization was created in 1986, following David Olver (1989-2003), John Stauffacher (2004-2012), Tom Foreman (2013-2018) and Casey (2018-2024). 

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Stakeholder Soapbox — There and Back Again: D.C. Circuit Again Considers NYISO’s Approach to Zero-Emission Mandate

Dozens of states have adopted emission-reduction targets aimed at fighting climate change. But how should RTOs account for those initiatives when their effects are delayed, uncertain, expensive for consumers or all of the above? 

In New York State Public Service Commission v. FERC (No. 23-1192), the D.C. Circuit is poised to address that question — with potentially significant implications for climate-change laws, energy markets, and the approval process for RTO and ISO tariff amendments going forward. 

New York’s Climate Act Spurs NYISO Action

In 2019, New York’s Climate Leadership and Community Protection Act (Climate Act) set a target date of 2040 to eliminate all greenhouse-gas emissions from the state’s energy grid. The act ordered the New York Public Service Commission (NYPSC) to promulgate regulations implementing that target date, but it also authorized NYPSC to create exceptions if necessary for reliability. To date, NYPSC has not promulgated any implementing regulations. 

In response to the new law, NYISO proposed a revision to the Net Cost of New Entry (“Net CONE”) figure used in its capacity market. Net CONE is an annualized estimate of new-entry costs, calculated by dividing a hypothetical new gas-fired power plant’s lifetime expenses by an “amortization period,” i.e., the number of years in the plant’s viable economic life. NYISO historically has used a 20-year amortization period, but given uncertainty that gas-fired plants would be viable after 2040, NYISO proposed shortening the amortization period to 17 years.   

That proposal comes with a cost. To incentivize market entry in the event of a supply shortfall, NYISO factors Net CONE into its capacity demand curve. Shortening the amortization period (and thereby increasing Net CONE) also would thus increase capacity clearing prices, to the tune of more than $100 million annually. 

FERC Approves NYISO’s Proposal — on Take Three

For nearly four years, NYISO’s proposal has been tied up in proceedings before FERC and the D.C. Circuit, generating multiple FERC orders and a D.C. Circuit opinion in between. In FERC’s most recent, third order (the one now before the D.C. Circuit), FERC approved the amendment.   

Opponents of the proposal, including NYPSC itself, have made two main arguments. First, they have argued that NYISO made an impermissibly speculative assumption that gas-fired plants must close by 2040 when it relied on the Climate Act’s target date to justify its proposal. They have contended that NYPSC can create exceptions to the act, or new retrofitting technology might enable plants to operate past 2040. Second, opponents have argued the nine-figure spike in capacity costs (and, ultimately, an increase in consumer prices) means the amendment is not just and reasonable. 

Jennifer Fischell | MoloLamken

Although FERC initially adopted those arguments, the D.C. Circuit expressed skepticism in the case’s first trip to the appellate court. See Independent Power Producers of New York, Inc. v. FERC, No. 21-1166, 2022 WL 3210362 (D.C. Cir. Aug. 9, 2022). On remand, FERC now has fully rejected the challenges to NYISO’s proposal. N.Y. Independent System Operator, Inc., 185 FERC ¶ 61,010 (Oct. 4, 2023). The amendment, FERC found in its most recent order, is a reasonable response to the Climate Act and is not impermissibly speculative, since the only law on the books all but requires zero emissions after 2040. The proposal’s opponents, in FERC’s view, are speculating about yet-unknown regulatory and technological developments.   

FERC also found the increase in capacity prices effectively irrelevant. The amendment was limited to changing the Net CONE amortization period (which FERC found reasonable); it did not change the broader capacity-auction structure that incorporated Net CONE into capacity prices (which FERC previously approved as reasonable). Prices resulting from a reasonable rate design using reasonable components, FERC concluded, are necessarily reasonable too.  

The D.C. Circuit Petition for Review Raises Issues of Nationwide Significance

FERC’s order now is before the D.C. Circuit on NYPSC’s petition for review. Chief Judge Srinivasan and Judges Randolph and Childs heard argument Feb. 20, 2024 — and the judges’ questioning suggests a pro-FERC majority. Srinivasan and Randolph signaled strong agreement with FERC’s view that relying on the Climate Act’s target is not speculative, while Childs seemed more skeptical, pressing FERC’s counsel to defend the agency’s treatment of the proposal’s effect on prices. If oral argument is a guide, the court could be poised to deny the petition and approve FERC’s reasoning.   

Jackson Myers | MoloLamken

Whatever the outcome, the ruling could have nationwide consequences. New York is not the only state with an emissions mandate, and NYISO is not the only RTO trying to account for those laws. And even beyond the climate-change context, the court’s ruling on the “speculation” question will send a signal to FERC and to RTOs about how to deal with regulatory uncertainty more broadly.   

How the D.C. Circuit treats FERC’s dismissal of NYPSC’s cost concerns could be even more significant. FERC has argued that price increases caused by a proposed amendment’s interaction with a broader, FERC-approved rate design need not be considered in the just-and-reasonable inquiry. Instead, in FERC’s view, challenges based on resulting price changes must be made using Section 206 of the Federal Power Act. If the court agrees, Section 206 complaints could become routine when stakeholders oppose a tariff amendment because they contend its relationship with existing tariff elements could lead to unjust and unreasonable prices. If the court disagrees, the case likely will return, once again, to FERC. And from there, it might come back again. 

Jennifer Fischell is a partner at MoloLamken with a practice focusing on energy and administrative law, appeals and other complex civil litigation. She has clerked for judges at all levels of the federal judiciary, most recently for Justice Elena Kagan of the U.S. Supreme Court. 

Jackson Myers is an attorney at MoloLamken with a practice focusing on appeals, complex civil litigation and white-collar matters. Prior to joining MoloLamken, he clerked for Judge Dennis Jacobs of the U.S Court of Appeals for the Second Circuit and Judge John Bates of the U.S. District Court for the District of Columbia. 

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LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant

Michigan’s 800-MW Palisades nuclear power plant, which was decommissioned in 2022, could become the first nuclear plant in the U.S. to be restarted, helped by a $1.52 billion loan from the federal Department of Energy’s Loan Programs Office (LPO). 

The agency’s conditional commitment for the loan to Florida-based Holtec International would also be the first offered under the Energy Infrastructure Reinvestment program, which is funded by the Inflation Reduction Act, according to the March 27 announcement. The program aims to “finance projects that retool, repower, repurpose or replace energy infrastructure that has ceased operation,” LPO said. 

Once restarted, the plant would protect “600 good-paying, high-skill jobs and clean, reliable power for 800,000 homes,” Michigan Gov. Gretchen Whitmer said in a statement. “Palisades will be the first successfully restarted nuclear power plant in American history, driving $363 million of regional economic impact and helping Michigan lead the future of clean energy.” 

Whitmer has been pushing for the Palisades restart, and the Michigan Legislature last year provided $150 million in state funding for the project. 

Holtec also intends to build two small modular reactors on the site, according to LPO. 

Holtec CEO Kris Singh called the loan “a triumph for the United States in our collective pursuit of a clean and dependable energy future. … The repowering of Palisades will restore safe, around-the-clock generation to hundreds of thousands of households, businesses and manufacturers.” 

LPO expects the project to avoid close to 4.5 million tons of carbon dioxide emissions per year and 111 million tons of CO2 in 25 years of operation — the equivalent of taking 970,000 gasoline-powered cars off the road per year. 

Holtec has signed two long-term power purchase agreements with two electric cooperatives for the plant’s output. Wolverine Power Cooperative provides electricity for five co-ops in Michigan, and Hoosier Energy, an alliance of 18 co-ops, serves customers in Indiana and Illinois. 

Speaking at an industry conference last year, Wolverine COO Zach Anderson said the Palisades PPA met all the co-op’s top priorities for new power. “It’s a long-term, stable, 100% carbon-free, 24/7 power supply, so it’s decarbonized and reliable,” as well as cost competitive, Anderson said. 

Reactions

Doug True, senior vice president and chief nuclear officer at the Nuclear Energy Institute, said the loan signals the Biden administration’s “willingness to explore opportunities to preserve our existing nuclear fleet,” as well as support for “the pivotal role nuclear energy plays in our nation’s clean energy future.” 

Patrick White, research director at the Nuclear Innovation Alliance, sees the loan as an indication of LPO’s willingness to fund more nuclear projects going forward. The office previously helped fund the long-delayed and costly Vogtle Units 3 and 4 in Georgia with $12 billion in loans. 

But White cautioned that the restart likely will be a one-off project, rather than the first of many. Repowering Palisades is not “something that’s generally applicable to plants that have been decommissioned,” White said in an interview with RTO Insider. 

“I believe when Palisades was being kind of shut down and moving from its previous life in operation into decommissioning, there was an idea that the plant [might] be restarted,” he said. “So, the owner took a lot of steps to make sure the plant was kept in essentially ready-to-go condition.” 

In a statement provided by the American Nuclear Society, Keith Drudy, a Michigan native and nuclear engineer who worked on Vogtle 3 and 4, said, “Restarting Palisades from its current state is really no more complicated than returning from a significant maintenance outage ― something that nuclear plants do every 18 to 24 months. The nuclear industry knows how to do maintenance, implement upgrades and enhancements, and … keep these plants running for 60 years and beyond. 

“The unique challenge here is that, until now, there has been no regulatory process or precedent for declaring that a licensee intends to cease operations of a plant and then return that plant back to operating status from a regulatory perspective,” Drudy said. “That process is now being developed, and I have no doubt that the [Nuclear Regulatory Commission] and other impacted regulatory agencies can and will ensure the restart of these units meets all standards and requirements.” 

Holtec began the relicensing process for Palisades with the NRC in October 2023 and is targeting a final decision by the end of 2025, according to Patrick O’Brien, the company’s director of government affairs and communication.  

Anderson said Wolverine expects to start receiving power from the plant by 2027. 

Holtec’s History

Located on the southeast shore of Lake Michigan, the Palisades nuclear plant began operation in 1971. It was originally owned by CMS Energy and its primary utility, Consumers Energy, and was acquired by Entergy in 2007. 

Consumers continued to buy power from the plant, but changing market conditions led to Entergy’s decision to close Palisades in 2022, citing the availability of cheaper power from renewables and natural gas. Power from the plant could cost 57% more than other generation, according to a report by Bridge Michigan. 

Even before the plant ceased operation in May 2022 and was sold to Holtec for decommissioning, Michigan officials began looking at options for restarting it. Holtec made an unsuccessful application for funding from DOE’s Civil Nuclear Credit Program, which received $6 billion in funding from the Infrastructure Investment and Jobs Act to help plants at risk of closure. 

The company began its application process with LPO in 2023. The announcement of the conditional commitment begins a negotiation process under which Holtec will have to reach specific technical and financial milestones before the loan is finalized. 

But the decision could prove controversial for a number of reasons, first and foremost the company’s history of financial missteps. In January, Holtec agreed to a $5 million settlement with New Jersey to avoid criminal prosecution over allegations that it provided inaccurate information to obtain $1 million in state tax credits in 2018. While accepting the settlement, the company denied any wrongdoing. 

Holtec has a large campus in Camden. As part of the settlement, it agreed to hire a state-approved independent reviewer to monitor any future applications it makes for New Jersey state benefits. 

The company was also barred from doing business with the Tennessee Valley Authority for 60 days in 2010, after it was implicated in a scandal involving kickbacks to a TVA official from a Holtec contractor, according to a report from InsiderNJ. 

Another concern is that Holtec’s business is focused on decommissioning nuclear plants; it has never actually operated one. 

O’Brien acknowledged that the company’s lack of operational experience is “generally true. … But with the decommissioning, we retained qualified staff, including operators, maintenance, radiation protection and other craft [workers] that have years of experience in plant operations. The Palisades team is comprised of a hard-working team that safely operated the facility for over 50 years. In addition, we will be partnering with a licensed operator for restart.”