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February 12, 2025

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FERC Proposes Talks with DOJ on Southern Co. Plant Purchase

FERC on Feb. 10 took the rare step of issuing a Notice of Proposed Communication with the U.S. Department of Justice over Southern Co.’s application to purchase a power plant in Alabama (EC25-27). 

Southern affiliate Alabama Power is trying to buy Tenaska’s Lindsay Hill Generating Station, an 895-MW natural gas- and oil-fired power plant, which is currently under a tolling agreement with Mercuria Energy Group through April 30, 2027. Once that lapses, the utility would control its entire output, according to the application filed in early December. 

Energy Alabama, Public Citizen and Gasp protested the application Feb. 7, arguing that the company did not address any market power concerns. 

FERC works with DOJ’s Antitrust Division often, as they have overlapping jurisdiction on mergers, but the notice is unusual. It simply informed parties to the case notice that FERC staff want to communicate with DOJ officials on the proposed purchase and invited them to raise any objections to such communications. If none are filed, they will go ahead with the communications. 

“As a part of the overall regulatory review process for the proposed acquisition of the Lindsay Hill Generating Station, Alabama Power is seeking approval from FERC, and the transaction is subject to review under the Hart-Scott-Rodino Act (as administered by the Department of Justice and the Federal Trade Commission),” Alabama Power spokesperson Anthony Cook said in a statement. “This generating facility is necessary in order to help meet Alabama’s growing energy load. We are reviewing the recent comments filed in the FERC proceeding and will respond appropriately.” 

Alabama Power and Tenaska told FERC that the deal is consistent with its merger policies and has no impact on competition, rates or regulation, nor will it result in any cross-subsidization. Once the tolling agreement ends, the plant’s output would be sold under Alabama Power’s market-based rate tariff, but the companies argued in the application that no market power issues will occur because of the agreement. 

“When the effect of the Mercuria tolling agreement is taken into account, there is no overlap between the combining entities — Alabama Power and its affiliates on the one hand, and TAP on the other hand — and the proposed transaction results in no change in market concentration,” they said. 

In their joint protest, Energy Alabama, Public Citizen and Gasp argued that FERC needs to anticipate what the market power situation will be in May 2027. 

“The joint applicants’ failure to analyze this preordained outcome — which is the stated purpose of the proposed transaction — prevents the commission from evaluating whether the proposed transaction is consistent with the public interest, let alone whether existing mitigation measures remain sufficiently protective,” the groups said. “The application further obscures this deficiency by designating the affidavit discussing the horizonal competitive analysis screen privileged and confidential.” 

It is atypical to keep horizontal market screens confidential in FERC proceedings, and the groups noted that Southern and Tenaska have filed them publicly in other cases. Parties to the case had access to the horizontal market power screen, but any relevant comments in the public version had to be blacked out to abide by confidentiality rules. 

The transaction would be the fifth FERC has approved for Alabama Power since 2020, with the commission having already approved 2,500 MW of generation purchases by the utility. 

“Acquiring the Lindsay Hill facility would bring that number to over 3,400 MW,” the groups said. “When compared to the 12,942 MW of generating capacity that Alabama Power currently owns or controls, this figure cannot be ignored.” 

The first of those four previous deals involved Alabama Power buying another plant from Tenaska that was under a tolling agreement, and they initially failed to file a market power screen. FERC found that deficient and required them to calculate the impact on market power once the tolling agreement expired. 

In the case pending now, the tolling agreement expires a year earlier, meaning the screens will be less speculative, and unlike that earlier Tenaska plant purchase, Alabama Power is not already using the generation for itself. The companies have not asserted that the plant is currently dispatched in Southern’s internal power pool, but once the tolling agreement is done, it will add 895 MW to the dominant supplier in that market. 

“Alabama Power’s systematic acquisition of large generating facilities — and by extension, Southern Co.’s consolidation of generating capacity in the region — is especially concerning given the size of” the company’s balancing authority area, which has about 61 GW of capacity, the groups said. 

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US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth

A new study from Duke University says the existing power system could handle 126 GW of new demand with no additional generation if artificial intelligence data centers can be persuaded to cut their energy use by as little as 1% during times of peak demand.

The “Rethinking Load Growth” report looks at 22 balancing authorities — RTOs, ISOs and large investor-owned utilities — representing 95% of the country’s peak load and finds that each could add varying amounts of new load without exceeding its maximum capacity “provided the new load can be temporarily curtailed as needed.”

The report defines system curtailment, or flexibility, as a data center’s ability to temporarily reduce its power consumption “by using onsite generators, shifting workload to other facilities or reducing operations,” thus creating “curtailment-enabled headroom” to add new load.

For example, the study estimates PJM could integrate more than 23 GW of new load with curtailment-enabled headroom based on 1% curtailment. ERCOT could add 14.7 GW, and Southern Co. could add 9.3 GW.

Lower curtailment rates still could provide significant headroom, the study says, with PJM opening up 17.8 GW at 0.5% curtailment and 13.3 GW at 0.25% curtailment.

The length of curtailment periods also would vary, with a 1% curtailment lasting no more than 2.5 hours, while a 0.25% curtailment rate would last only 1.7 hours.

“These results suggest that the U.S. power system’s existing headroom … is sufficient to accommodate significant constant new loads, provided such loads can be safely scaled back during some hours of the year,” the report says, framing flexibility as a win-win for all stakeholders.

The U.S. still will need to build new generation and transmission to meet anticipated demand growth, the report says. “[But] flexible load strategies can help tap existing headroom to more quickly integrate new loads, reduce the cost of capacity expansion and enable greater focus on the highest-value investments in the electric power system.”

“The immensity of the challenge underscores the importance of deploying every available tool, especially those that can more swiftly, affordably and sustainably integrate large loads,” the report says. “The unique profile of AI data centers can facilitate more flexible operations, supported by ongoing advancements in distributed energy resources.”

Data Centers and DR

Authored by researchers at Duke’s Nicholas Institute for Energy, Environment and Sustainability, the study grounds its argument for flexibility in the current flashpoints for demand growth. Data centers often have aggressive schedules for going online but may face yearslong interconnection and supply chain delays.

Lead times for ordering transformers have gone from less than a year to two to five years, with prices rising 80%, according to June 2024 figures from the president’s National Infrastructure Advisory Council, the report says. Wood Mackenzie has reported that lead times for high-voltage circuit breakers were nearing three years at the end of 2023.

The report notes the growing interest in co-locating data centers with existing or new generation, but says it is not likely to be “a long-term, systemwide solution.”

The fact the U.S. grid is designed with headroom to accommodate relatively short periods of peak demand and often is underused provides a further rationale for leveraging this built-in flexibility, the report says. Better use of the system can reduce costs for consumers by “lowering the per-unit cost of electricity — and [reducing] the likelihood that expensive new peaking plants or network expansions may be needed.”

The report notes that some grid operators and utilities already are experimenting with flexible interconnection strategies, such as ERCOT’s interim treatment of new large loads as “controllable” resources, allowing them to go online in less than two years.

Still another argument for flexibility is the recent release of DeepSeek, the Chinese AI platform that claims to use significantly less energy than U.S. AI. Here, the report says, system flexibility could serve as a hedge for potential demand uncertainty.

But getting data centers to participate in traditional demand response programs — which have long provided system flexibility — has been difficult due to centers’ often inflexible, 24/7 demand profiles. Further, traditional DR programs have been designed for “traditional industrial consumers … with different incentives and operational specifications.” The report suggests new programs should be developed to align with data centers’ needs, including “streamlined participation structures, tailored incentives, and metrics that reflect the scale and responsiveness of data centers.”

New AI data centers, with “evolving computational loads … are more amenable to load flexibility,” the report says. The “training” of AI databases allows for flexible timing and the distribution of workloads across different data centers. An EPRI report cited by the Duke researchers found that “optimizing data center computation and geographic location … to capitalize on lower electric rates during off-peak hours” could provide cost savings of 15% and reduce strain on the grid during high-demand hours.

The report points to three trends that could “create further opportunities for load flexibility now than in the past.” First is the construction and interconnection delays that increase costs and timelines for getting new centers online, followed by the growth of clean, distributed technologies that offer lower-cost, behind-the-meter generation.

The third is the growth of hyperscale data centers and their computational loads, “which is lending scale and specialization to more sophisticated data center operators,” the report says. “These operators, seeking speed to market, may be more likely to adopt flexibility in return for faster interconnection.”

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BPA Halts Some Tx Planning Processes Amid Surge of Service Requests

The Bonneville Power Administration has temporarily paused certain transmission planning processes to consider new “reforms” in light of “exponential growth” of transmission service requests, BPA staff told stakeholders during a workshop Feb. 11. 

BPA’s 2025 transmission cluster study includes over 65 GW of transmission service requests (TSRs), compared with 5.9 GW in the 2021 study. The requests exceed the total regional load projected for the Pacific Northwest in 2034, Richard Shaheen, BPA’s senior vice president of transmission services, said during the workshop. 

“There’s been just an exponential growth in the area of transmission service requests,” Shaheen said. 

“That level of demand has basically strained our existing processes that weren’t designed to handle that level of volume, so they literally just crippled under the weight of all of that amount of requests for study,” Shaheen added.  

BPA first announced the pause in a Feb. 5 email. Specifically, the areas impacted by the pause include the: 

    • 2025 TSR study and expansion process cluster study; 
    • TSR evaluation process (for any new TSRs requesting new or modified capacity); 
    • TSR data exhibit evaluation process; 
    • Network Integration Transmission Service load and resource forecast evaluation and closeout process. 

TSRs requiring network capacity above existing commitments that submitted requests on or after noon Aug. 15, 2024 — the deadline to submit TSRs for consideration in the 2025 cluster study — will see limited impact as BPA assesses the need for planning reforms, according to a staff presentation. 

The pause won’t impact initiatives deemed critical, like BPA’s “evolving grid projects,” the Portland area reinforcement study, system assessment and other projects, according to Jeffrey Cook, BPA vice president of transmission asset management and planning. 

“This is really just focused on the transmission service request piece that we have in the study,” Cook said. He added that “we have to do something different in order to take the next step forward” to deal with the 65 GW of TSRs. 

Abbey Nulph, BPA analyst, reiterated that point, saying the pause is a chance for the agency “to not just live with our existing processes and try to find some way to help them limp along through this process, but to take a big step back [to] be able to design the process with the current world and market activity in mind.” 

When BPA designed the studies, the industry had yet to experience the impact of data center growth or current levels of competitive resource development, Nulph said. 

A December report published by WECC forecast “staggering” growth in electricity demand in the Western Interconnection over the next decade. 

WECC predicted annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and double the 9.6% growth forecast in 2022 resource plans. 

Similarly, the Pacific Northwest Utilities Conference Committee’s Northwest regional forecast for 2024 found that electricity demand will increase from about 23,700 average MW in 2024 to about 31,100 aMW in 2033, an increase of more than 30% in the next 10 years. 

Following stakeholder input, BPA said the plan is to issue a staff proposal in November aimed at improving the processes impacted by the pause. 

The pause also comes amid recent actions taken by President Donald Trump aimed toward the energy industry at large. Trump recently paused a 10% tariff on “energy resources from Canada,” along with 25% tariffs on other imports from Canada and from Mexico, for 30 days after last-minute negotiations with the two countries’ leaders.  

Additionally, Trump, on Feb. 10, imposed a 25% steel tariff on all steel and aluminum imports. 

Meanwhile, BPA workers, similar to millions of other federal workers, received the buyout offer from the Trump administration in a message titled “Fork in the Road.” The administration offered a “deferred resignation” arrangement, promising to provide workers who accepted the offer with a severance package consisting of eight months’ pay and benefits through Sept. 30, the end of the federal fiscal year. The offer has been challenged in court. 

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Incumbent Utilities Make Case for ROFR Laws in New Report

A band of incumbent utilities has collected case studies that they say demonstrate the need to instate or maintain right-of-first-refusal laws for the good of grid expansion.

The Developers Advocating Transmission Advancements (DATA) — comprising Ameren, Eversource Energy, Exelon, ITC Holdings, National Grid USA and Xcel Energy — released a white paper Feb. 5 faulting FERC’s Order 1000 and solicitation processes for hindering more effective grid expansion.

Competitive bidding “isn’t compatible with what’s needed now,” ITC Director of Federal Affairs Devin McMackin said in an interview with RTO Insider. “We think it’s well established now that the cost benefits of competitive bidding haven’t materialized. It creates more litigation than it does transmission.”

On the other hand, McMackin said the ROFR is “a model that we know works.”

The report, “Recent Experience with Competitive Transmission Projects and Solicitations,” emphasizes four recent project scenarios from MISO, PJM, CAISO and New England that DATA says put the flaws of competitive processes on display.

The group said a competitive bidding and selection process can fail to take full projects costs into account; fail to “right-size” projects; fail to consider the feasibility of siting and routing proposals; and can come equipped with “illusory” cost caps.

“Order No. 1000 policy has created the incentive for developers to relentlessly argue over the right to build projects, fostering uncertainty that is to the detriment of actual infrastructure development,” DATA wrote. It argued that competitive solicitations have not resulted in benefits, instead contributing to a development environment rife with “litigation and administrative challenges, protracted solicitation processes and re-scoping of projects” — all without “demonstrated countervailing benefit to consumers.”

“There remains no evidence that FERC’s competitive transmission policy has improved the process of developing needed transmission infrastructure. Instead, there is an ever growing body of evidence that reform is needed,” the group said.

MISO

In MISO, DATA said ongoing uncertainty over Iowa’s ROFR law placed 447 miles of planned 345-kV circuits at a temporary standstill. The $2.1 billion worth of lines originate from the RTO’s first long-range transmission plan (LRTP) approved in 2022.

At first, MISO automatically assigned the lines to ITC Midwest and MidAmerican Energy, but in late 2023, a state court struck down the law in a case brought by competitive developer LS Power. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.) Appeals from the incumbents and the Iowa attorney general are pending. After conducting a variance analysis, MISO reaffirmed the lines should continue to be developed by ITC and MidAmerican.

DATA said litigation over Iowa’s ROFR could have an “adverse, cascading effect” on MISO’s first LRTP projects and delay economic and reliability benefits. Rather than lower costs, Order 1000 has “created the incentive for competitive developers to fight a constant and multifront battle for the opportunity to develop transmission projects, even if the result is to the detriment of actual infrastructure development,” it said.

LS Power has also filed a complaint with FERC against MISO for effectively ignoring a preliminary injunction against Indiana’s ROFR law. The company argued it is being denied the opportunity to bid on about $1 billion in LRTP projects. (See LS Power Files Complaint Against MISO over Indiana ROFR.)

McMackin said once grid planners go through the “arduous” process of assembling a transmission portfolio, the last thing anyone wants is to spend years deciding which developer should build it.

McMackin said the certainty ROFRs deliver is evident in MISO, where long-range transmission projects in states with such laws move straight to development, while projects in non-ROFR states are ushered through yearslong solicitation processes.

“States without ROFRs won’t even get bids out for two years,” McMackin said, adding that DATA’s “core contention is that ROFR is pro-transmission policy.”

PJM

Competitive processes, DATA said, can have planners selecting projects that are not the best in the long term or the most cost-effective.

DATA singled out the $513 million, 500-kV MidAtlantic Resiliency Link (MARL), which PJM awarded to NextEra Energy in Window 3 of its 2022 Regional Transmission Expansion Plan. NextEra was tasked with routing the project through the notoriously difficult-to-site Loudoun County, Va., in the Dominion zone. The company initially used Google Maps to chart an ultimately infeasible corridor and skipped deeper routing analyses. Eventually, Exelon and FirstEnergy assisted with an alternative route and construction on their existing rights of way, and NextEra and PJM agreed to cancel a portion of the project in favor of incumbent utilities building sections. PJM’s Board of Managers approved the changes to the project in 2024, at a net increase in costs.

DATA said NextEra’s bid on MARL shows how developers can submit “unsophisticated and incomplete proposals” to an “artificially constrained assessment.” It said competitive bidders don’t instinctively reach out to other utilities for the type of collaboration that might come naturally to incumbent developers.

“Challenges with siting transmission … along the initial MARL route should not have been a surprise to NextEra, or to PJM,” DATA wrote. “We will never know if a project collaboratively developed by incumbent utilities in the first instance would have avoided the increased cost or identified a superior, more holistic, more robust solution.”

New England

DATA also pointed to the $2.78 billion, 345-kV Aroostook Renewable Gateway project in Northern Maine that the Public Utilities Commission awarded in 2022 and subsequently withdrew because selected developer LS Power announced it would exceed its original fixed-price bid.

The PUC has since initiated a new docket to contemplate an alternative project and developer.

DATA said hard cost caps are ill suited for the “development challenges and commercial realities of electric transmission,” which include long lead times, high capital costs and regulatory hurdles, among other cost pressures.

CAISO

Finally, DATA called out two HVDC transmission projects in the San Francisco South Bay region — Newark-to-Northern Receiving Station and Metcalf-to-San Jose B — from CAISO’s 2021-2022 transmission plan, also awarded to LS Power.

According to the report, when significant load growth entered the picture and brought hypothetical overloads with the original design, CAISO was forced to modify the Newark project into a 230-kV switchyard and a 230-kV AC circuit. CAISO said it will set apart a San Jose B substation expansion as part of the project for incumbent Pacific Gas and Electric instead of allowing LS Power to build a new station to avoid building duplicative substations on scarce land.

CAISO also must include a new Northern Receiving Station-to-San Jose B circuit that is set to be awarded through bidding later this year.

DATA said CAISO’s twisty rescoping and involvement of new developers on the project shows how competitive processes can “lead to fractured and inferior planning outcomes that fail to make project selections accounting for the full costs that will be borne by customers and do not maximize or ‘right-size’ the value of solutions to meet immediate and future needs.”

‘Unintended Consequences’

What the case studies “collectively demonstrate is … a full range of unintended consequences,” McMackin said. Competitive developers may make “routing choices that might not be compatible with the project with the expectation that it can all be renegotiated later.”

As of press time, LS Power did not respond to RTO Insider’s request for comment on whether it believes the shift in projects can be construed as misfires, or whether it views its litigation as postponing transmission construction.

The Electricity Transmission Competition Coalition (ETCC) has recently renewed its argument that monopoly incumbents continue to price gouge. It noted that according to the U.S. Bureau of Labor Statistics’ Consumer Price Index Summary for January, annual electricity price inflation climbed at four times the rate of the average U.S. grocery bill.

ETCC maintains that MISO ratepayers could save several million if all projects in its second, nearly $22 billion LRTP portfolio are competitively bid.

Two months ago, MISO was compelled to conduct a variance analysis on one of the LRTP projects from its first portfolio following a cost increase of more than 2.5 in the project under incumbent Northern Indiana Public Service Co. The planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana climbed from an estimated $261 million to $675 million. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)

‘Meeting the Moment’

McMackin characterized DATA’s members as investor-owned utilities that are supportive of regional transmission. They are “deeply engaged” in building the grids that can “meet the moment” of demand growth from artificial intelligence, electrification and decarbonization.

“Right now, what’s best for customers is getting transmission built,” McMackin said.

He acknowledged that it is natural that incumbent utilities would want project opportunities.

“I think that’s a fair question that goes to motivation,” he said. But he said ROFRs have “strong track records of working,” having been the default before Order 1000. He argued ROFRs are needed to “reestablish certainty to get infrastructure built expeditiously.”

McMackin recognized that getting transmission built is complicated and challenging.

“We do not make the claim that incumbent developers don’t encounter the same challenges that non-incumbent developers do, because developing large-scale transmission is hard. And it’s hard across the board,” McMackin said. However, he said non-incumbent development of projects more routinely results in “cost escalations beyond what’s expected.”

“Non-incumbent development has a host of issues,” he said, adding that he expects the issues to escalate with FERC’s Order 1920. “To the extent that there’s not ROFR certainty from FERC, there will be more examples.”

DATA would like to see FERC reopen the ROFR topic so the group can share the “data we now have about how this process is working,” McMackin said. “We need more federal certainty on the issue.”

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NYISO Liaison Subcommittee Briefs: Feb. 11, 2025

ISO Still Working on Trump Tariff Clarity

NYISO is still working on getting clarification on President Donald Trump’s pending 10% tariff on energy imports, Mark Seibert, manager of ISO member relations, told the Liaison Subcommittee.  

The Board of Directors “has authorized [NYISO] to seek any tariff authority necessary to comply with legal obligations that may be imposed on it,” Seibert said. “Management is working through these issues internally and with members of the ISO/RTO community,” and with FERC. (See NYISO Assessing Impact of Trump’s Canada Tariff on Electricity Market.) 

Seibert said the ISO would address the issue in detail with stakeholders Feb. 25. 

He also said the ISO had not yet received any guidance from “anyone down in D.C,” as Kevin Lang, representing New York City, put it. 

Clean Path

Seibert told the subcommittee that the board had approved the changes to the 2025 Project Grant Plan, specifically approving the removal of its initiative to develop market participation rules for internal controllable lines. 

This was done because of the New York Power Authority’s proposed changes to the Clean Path NY transmission project. (See NYPA Files Petition with New York PSC to Save Clean Path Project.) 

“We remain ready to support the project in the future once updated details and plans are available,” Seibert said.  

A representative from NYPA thanked the ISO for its continued support of the project.  

Cybersecurity Updates

Seibert said NYISO had successfully completed its triennial critical infrastructure audit by the Northeast Power Coordinating Council. The ISO scored “excellent,” and there were no areas of concern. 

NYISO is also continuing to monitor cybersecurity developments with respect to “nation-state threat actors and global attack campaigns.” The ISO is implementing “three micro segmentation enforcement environments” within its networks to prevent persistent threats. Seibert said this was a key element of the “zero trust” cybersecurity strategy the ISO was implementing. 

The subcommittee receiving a classified briefing late in 2024 on Volt Typhoon, a Chinese state-sponsored hacking group. The Cybersecurity and Infrastructure Security Agency has continually issued warnings that China has been sponsoring persistent intrusions into critical infrastructure. (See CISA Leader Reiterates China Cyber Warnings.) 

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Pathways ‘Step 2’ Plan Elicits Praise, Concerns — and Advice

A recent workshop on the West-Wide Governance Pathways Initiative has sparked praise for the proposal as well as concerns, including uneasiness over plans to share staffing between CAISO and a new regional organization that would govern Western electricity markets. 

“Shared staffing could lead to undue influence over governance decisions and compromise the impartiality needed for effective oversight and market rule promulgation and implementation,” Rob Creager, executive director of the Wyoming Energy Authority, said in a letter to the California Energy Commission.  

Even if the arrangement is temporary as part of Pathways Step 2, it could have long-term impacts and “create a precedent for the market operation moving forward,” Creager wrote.  

The letter was one of several submitted as a follow-up to a CEC workshop Jan. 24 on regional electricity markets and coordination, including the Pathways Initiative. (See CEC Workshop to Focus on Impact of Pathways Initiative; Ariz. Commissioner Questions Utility Decisions to Join SPP’s Markets+.) 

Pathways proposes to create a new independent “regional organization” (RO) to govern rules for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).  

The move could alleviate concerns of potential participants who are uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. 

Pathways backers are now waiting for a bill to be introduced in the California legislature that would allow a change to CAISO’s governance with the introduction of the RO. 

The International Brotherhood of Electrical Workers, which opposed previous efforts to “regionalize” CAISO, plans to sponsor the bill, an IBEW representative said in October. The deadline for introducing bills this session is Feb. 21. (See California Labor, (Possibly) Public Power to Sponsor Pathways Legislation.) 

While the potential legislation has garnered support, including from some past opponents, Creager pointed out it’s typical for bills to be revised as they move through the legislature. He recommended that stakeholders clearly state what they want in the bill — as well as what they don’t want — “to ensure true political independence of the RO is established and to ensure any market designs and market rules are fair and transparent.” 

WEA was formed in 2020 when the Wyoming State Energy Office merged with the Wyoming Infrastructure Authority and the Wyoming Pipeline Authority. Creager noted that Wyoming was the largest electricity exporter in the Western Interconnection as of 2023. 

EDAM vs. Markets+

While acknowledging the competition between CAISO’s Extended Day Ahead Market and SPP’s Markets+, Creager said WEA realizes that “with PacifiCorp’s long-term participation in the WEIM and first-mover to commit to the EDAM, combined with Black Hills Energy’s (dba Cheyenne Light, Fuel & Power) decision to join the WEIM, Wyoming’s attention will be more focused on the evolution of CAISO’s market offerings with the potential to expand to a RO.” 

In August, two Black Hills Energy subsidiaries serving parts of Montana, Wyoming and South Dakota announced their move from SPP’s Western Energy Imbalance Service (WEIS) to CAISO’s WEIM. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.) 

Other stakeholders who submitted comment letters to the CEC commended the Pathways Initiative. 

Leanne Bober, director of regulatory affairs for the California Community Choice Association, said CalCCA supports Pathways because of its potential to “capture reliability, affordability and environmental benefits of regional coordination.”  

Pathways continues the incremental approach to regional coordination that has been working well for the region so far, Bober wrote, pointing to CAISO’s WEIM and soon-to-be-implemented EDAM as examples. 

Shifting energy market governance to an RO with board members from across the West “will promote trust across Western entities, attract a diverse range of potential regional market participants and maximize the potential benefits of a regional market,” Bober said. 

Adam Smith, director of regulatory relations at Southern California Edison, also wrote in support of Pathways. 

“Independent governance is crucial for greater regional market integration,” Smith wrote. The Pathways Initiative “has now provided a clear proposal for implementing such governance.” 

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NEPOOL Markets Committee Briefs: Feb. 11, 2025

Resource Retirement Changes

ISO-NE continued discussions with stakeholders on its capacity auction reform project at the NEPOOL Markets Committee (MC) meeting Feb. 11, providing more information on planned changes to the resource retirement process.

The RTO plans to decouple the retirement process from its capacity market as it works to reduce the time between auctions and capacity commitment periods (CCPs). Under current procedures, resources signal their plans to retire through the forward capacity auction process, about four years before their actual retirement.

ISO-NE proposes to require resources to give a two-year advance notification of their plans to retire for a given CCP. The reduced timeline is intended to give resources more clarity around the economics that motivate retirement decisions, while still providing enough time to conduct market power and reliability analyses, deploy transmission solutions if needed and enable market participants to respond. (See ISO-NE Introduces Proposed Resource Retirement Changes.)

While the two-year notification timeline would not provide enough time to develop long lead-time resources, some resources, including batteries and demand response, likely could be developed in this period, said Kevin Coopey, principal analyst at ISO-NE.

“If a market response takes longer than two years, the notification lead time will reduce the gap between when the deactivation occurs and when the market responds,” Coopey said.

ISO-NE plans for retirement submissions — including retirement dates — to be binding. This is intended to preserve the market signal sent by retirements and prevent resources from “fishing” for reliability retention contracts, Coopey said. He added that allowing withdrawals could unintentionally create “incentives for resources to ‘test’ if they can get away with exercising market power with limited repercussions.”

The RTO plans to discuss reliability reviews for deactivation requests at the MC in March.

FERC Order 904

ISO-NE opted to delay a planned vote on compliance with FERC Order 904, which prohibits transmission providers from compensating generators for reactive power within the standard power factor range.

The standard power factor range is defined as “the power factor range set forth in the generating facility’s interconnection agreement when the unit is online and synchronized to the transmission system,” FERC wrote in the order.

Prior to the order, the RTO unsuccessfully argued the commission should let it maintain its procedures for compensating reactive resources.

To comply with the order, ISO-NE proposes to eliminate its volt ampere reactive capacity cost compensation program. The compliance proposal would not change compensation for resources following ISO-NE dispatch instructions, the RTO noted.

Multiple stakeholders expressed concern that the compliance proposal is too broad and argued the RTO should continue compensating resources for reactive power outside of the standard range. Responding to the concerns, ISO-NE delayed the vote until Feb. 27, when it will hold a joint meeting of the MC and the Transmission Committee.

The compliance filing is due on March 27; ISO-NE proposes for the changes to take effect on June 1.

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Type One, TVA to Cooperate on Fusion Plant

Another target is set for commercial nuclear fusion power: The Tennessee Valley Authority and Type One Energy have a cooperative agreement for a potential commercial plant. 

TVA and Type One announced Feb. 11 that the project could go online as early as the mid-2030s. 

This would put it slightly behind another effort — Commonwealth Fusion Systems’ collaboration with Dominion Energy, which aims to get the world’s first commercial fusion reactor online by the early 2030s in Virginia. (See Oklo, Commonwealth Fusion Unveil Ambitious Nuclear Plans.) 

The commercially viable fusion reactor is a goal that has eluded researchers for decades but that still is being pursued closely: The analytics firm ABI Research recently calculated third-quarter 2024 investment in fusion at a record $7 billion. 

Type One’s agreement with TVA calls for “Infinity Two,” a 350-MWe pilot fusion plant, to provide base load generation for the Tennessee Valley region, potentially repurposing retired TVA fossil-burning power plant infrastructure. 

It expands on Project Infinity, which was announced in early 2024 and calls for a prototype “Infinity One” reactor to be placed at the site of TVA’s Bull Run Fossil Plant, an 865-MW coal-fired facility retired in late 2023. 

Type One and TVA said in a news release they will collaborate on siting studies, environmental reviews, licensing and financing for Infinity Two. 

Also, TVA’s Power Service Shops in Alabama will assist Type One as it shapes its supply chain and develops modular manufacturing and assembly techniques. TVA in turn will “benefit from the subsequent scaling of fusion energy on a global basis, following the successful deployment of Infinity Two.” 

Type One CEO Christofer Mowry said the agreement allows his company to use TVA’s existing infrastructure and expertise rather than duplicating it as it goes through phases of research and development. 

“Instead, we can focus on completing the design of Infinity Two and testing it with the Infinity One prototype in TVA’s Bull Run plant. The ability for us to focus on developing and delivering the core stellarator technology materially derisks our path to fusion power plant commercialization.” 

Also Feb. 11, Commonwealth Fusion and Type One announced a licensing agreement for Type One to use Commonwealth Fusion’s high-temperature superconducting cable technology in development of its fusion magnets. 

Both companies have first-to-market aspirations, but with different reactors. Commonwealth Fusion is developing a tokamak reactor, and Type One is going with the more complex stellarator design. 

They said in a news release their agreement has benefits beyond the Infinity Two project: It gives Commonwealth Fusion a new market for its cable technology and gives Type One access to demonstrated background technologies and capabilities. 

As with the TVA agreement, the deal saves Type One the time, risk and expense of re-creating what Commonwealth Fusion already has. 

Commonwealth Fusion CEO Bob Mumgaard said this would accelerate Type One’s development efforts. 

“At CFS, we are confident in our approach using magnetic confinement in tokamaks, but we also want to support companies pursuing other promising magnetic confinement applications given the scale necessary to address the urgent transition to fusion energy and the transformative nature of high-field magnets,” he added. 

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Company Briefs

EDF Renewables Brings 300-MW Solar Farm Online

EDF Renewables announced its 300-MW Desert Quartzite solar-plus-storage project in California is now operational. 

The project, which was approved by the BLM in January 2020, also boasts 600 MW of storage. 

The project was initially developed by First Solar in 2019, but the company sold its interest in the project to EDF in 2020. 

More: pv magazine 

Meta, Enel Agree to PPA for Wind Farm

Meta and Enel North America have signed a power purchase agreement for a wind farm in Oklahoma. 

The 25-year PPA is for a 115-MW portion of the Rockhaven wind farm. It marks the third collaboration between the two companies. 

More: Power Technology 

Enel Powers On Solar-plus-Storage Facility

Enel North America last week announced its solar-plus-storage facility in Texas is now operational. 

The project combines 202 MW of solar capacity with a 104-MW battery storage system. 

Enel is among the largest renewable operators in Texas, having around 5 GW of installed wind and solar capacity, along with 1.3 GW of installed battery storage. 

More: Renewables Now 

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State Briefs

CALIFORNIA 

Lawsuit Filed Against Vistra, PG&E over Moss Landing Fire

Community members last week filed a lawsuit against Vistra, PG&E and other defendants over the Moss Landing battery storage facility fire that occurred Jan. 16. 

The civil complaint alleges the burning of lithium-ion batteries caused “the release of massive plumes of smoke, ash and toxic chemicals into the surrounding communities.” The defendants are accused of negligence, reckless, intentional, and/or abnormally dangerous actions and inactions that created conditions to exist that were harmful to health. It also says they failed to implement adequate safety measures despite previous incidents in 2021, 2022 and 2023. 

More: KSBW; The San Francisco Standard 

Tesla Sales Decline 12% in 2024

Tesla’s sales in the state fell almost 8% in the fourth quarter and 12% for the year, according to data sourced by the California New Car Dealers Association. 

The company also registered fewer cars in all four quarters of 2024, as sales of its second-most important model — the Model 3 — plunged 36% for the year. 

Tesla did manage to maintain most of the state’s zero-emission vehicle registrations last year, although its share dropped to 52.5% from 60.1%. 

More: The Mercury News 

CONNECTICUT 

Lamont Gives up on Effort to Phase out Gas Vehicles

After being forced to retreat last year from an effort to phase out sales of new gas-powered cars, Gov. Ned Lamont said he has little desire to resume the fight under the Trump administration. 

“I said a year ago, whatever it was, we’re going to follow the federal standards,” Lamont said. “I’m sorry that there probably are no federal standards now.” 

Lamont was referring to the fact that the state automatically reverted to federal emissions standards on the sale of new vehicles after lawmakers balked at the idea of following California’s timeline requiring manufacturers to offer only electric and other zero-emission vehicles by 2035. 

More: CT Mirror 

Utilities Oppose Bill that Would Consolidate Power at PURA

Avangrid and Eversource last week voiced their displeasures with a bill that would shrink the Public Utilities Regulatory Authority to a three-person panel and give it the ability to place cases in the hands of a single commissioner. 

The public comments come a week after the utilities filed a lawsuit contending that PURA Chair Marissa Gillett had usurped the power of fellow commissioners by placing herself in charge of hundreds of cases and issuing decisions without a full vote. 

The legislation was introduced by Sen. Norm Needleman (D), who said the bill mirrored the language of the law prior to the expansion of PURA’s board from three to five members in 2019.  

More: CT Mirror 

MAINE 

PUC Approves Rules Restricting Utilities from Passing Lobbying Costs to Customers

The Public Utilities Commission last week voted 3-0 to restrict utilities from passing costs related to political activities, advertising and education initiatives onto customers. 

The regulation requires utilities to file annual reports describing their political activities, charitable contributions, educational spending and other similar activities. Utilities also must detail expenses associated with these activities, and the regulation prohibits any utility from providing promotional allowances without first getting PUC approval. 

The regulation is based on a law enacted in 2023 by the Legislature and Gov. Janet Mills requiring greater transparency in utilities’ spending on advertising. 

More: Portland Press Herald 

MARYLAND 

BGE Waives Late Fees, Suspends Disconnections

Baltimore Gas and Electric announced it is waiving certain fees and suspending service disconnections for nonpayment amid high winter energy bills. 

The company said it will pause service disconnections in February and waive late payment fees incurred since Jan. 1. 

BGE said extremely cold weather combined with higher supply costs contributed to increased energy costs. 

More: WBAL 

MASSACHUSETTS 

National Grid Pulls Plug on Geothermal Pilot Program

National Grid has canceled plans for a project that may have brought geothermal energy to communities in Lowell, citing higher-than-anticipated costs. 

The program was one of three pilots across the state testing whether geothermal energy could displace fossil fuels in heating, air conditioning and gas appliances. All three programs were placed in environmental justice communities. 

The project’s estimated cost was $15.6 million over five years. National Grid declined to specify how much more the project would have cost. 

More: CommonWealth Beacon 

NEW JERSEY

State’s Climate Change Lawsuit Dismissed

State Superior Court Judge Douglas Hurd last week dismissed the state’s lawsuit that claimed deceptive actions by oil companies encouraged the unchecked burning of fossil fuels and worsened climate change. 

Hurd wrote in his opinion that only federal law can govern the claims made by the state, agreeing with arguments made by the oil companies’ lawyers. 

More: NJ Spotlight News 

NEW MEXICO

Santa Fe County Planning Commission Approves Solar Project

The Santa Fe County Planning Commission last week voted 6-1 to approve a conditional use permit for the Rancho Viejo Solar project. 

The commercial solar-plus-storage facility was proposed by AES Clean Energy Development. 

More: KSFR 

OHIO 

3 FirstEnergy Subsidiaries File Electric Security Plan with PUC

Ohio Edison, The Illuminating Company and Toledo Edison — three FirstEnergy companies — have filed a proposed electric security plan (ESP) with the Public Utilities Commission. 

The companies said the ESP supports their commitment to investing in and maintaining the grid while providing customer assistance programs and energy efficiency initiatives. Specifically, this sixth ESP preserves customers’ ability to select their own energy supplier and maintains an auction process to determine the pricing and supply. 

If approved, the average residential customer could see an increase of $3.40 (2.7%) on their monthly bill. 

More: Daily Energy Insider 

OREGON 

Jury Awards $50M to 2020 Wildfire Survivors

A jury last week awarded nearly $50 million in damages to seven survivors of the 2020 Labor Day wildfires. 

In financial filings, PacifiCorp executives have estimated that the 2020 and 2022 wildfires have cost the company nearly $2.7 billion. It’s the fourth jury verdict against PacifiCorp. At least eight more trials are scheduled. 

More: OPB 

SOUTH DAKOTA

PUC Approves Permit for Portion of Big Stone South to Alexandria Tx Line

The Public Utilities Commission has approved a facility permit for the state’s portion of the Big Stone South to Alexandria 345-kV transmission line. 

Otter Tail Power Co. and Western Minnesota Municipal Power Agency will co-own the 100-mile line. The companies have also filed a route permit application with the Minnesota Public Utilities Commission for that portion of the project. That decision is expected in mid-2026 with the companies targeting an in-service date by the end of 2030. 

More: T&D World