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February 23, 2025

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E-ISAC: Foreign Actors Continue to Target Grid

MIAMI — The world is becoming “a scary place” for those defending the electric grid against cyber and physical security threats, representatives of the Electricity Information Sharing and Analysis Center (E-ISAC) told the NERC Board of Trustees’ Technology and Security Committee at its meeting Feb. 12. 

Matt Duncan, the E-ISAC’s vice president for security operations and intelligence, said “the watch order for the E-ISAC going forward is ‘be ready’” in the face of continuing threats from international adversaries like China, Russia, Iran and North Korea. In particular, he noted that suspicious activity from China “has continued unabated” amid the country’s stated plans to have the capability to invade Taiwan by 2027, potentially sparking armed conflict with the U.S. 

“The naming and shaming defenses that we’ve put in have not stopped the persistent cyber espionage and possible prepositioning in critical infrastructure networks in North American and allied countries” by Chinese operatives, Duncan said. He mentioned the Salt Typhoon group, which was recently found to have breached the networks of multiple telecommunications firms, along with the Volt Typhoon group accused of infiltrating U.S. infrastructure organizations for at least five years. (See CISA Leader Reiterates China Cyber Warnings.) 

“While there is no credible, specific and imminent threat to the grid, this [malicious] activity is continuing, which suggests that preparedness and investment in our cyber defenses, as well as increased information sharing, [are] essential to keeping the lights on,” Duncan added. 

The cyber attackers targeting the grid tend to use similar tools and techniques, he said, with probes on identity access management, unpatched firewalls and open ports, and the use of social engineering tools supported by artificial intelligence to trick human grid operators. Duncan stressed that “the best defense is the training of the humans that are on the network,” rather than investments in technology. 

One tool for this training is the E-ISAC’s direct share program, Duncan observed, through which the organization researches cyber and physical security gaps on behalf of the industry and shares them proactively with members and partners from other industries. 

Last year the number of direct shares to electricity industry asset owner or operator member organizations grew by 2.3% to 748, Duncan said; conversely, the number of shares sent to independent partners of the E-ISAC — organizations in other critical industry sectors or the government — declined by 6.5% to 2,790. The E-ISAC attributed these shifts to “a renewed focus on the electricity and gas industries and their equipment, and improved email security.” 

Media Frenzy Fed Drone Sightings

Duncan also discussed the unusually high number of drone sightings reported in December. Numerous citizens on social media described seeing unexplained unmanned craft in the sky that month, and the FBI said it had received more than 5,000 reports of drone sightings through its tiplines.  

The Federal Aviation Administration temporarily restricted drone flights over 22 cities, though investigators later determined that there was nothing suspicious about the reports and that the sightings were all either of lawful drones from hobbyists and law enforcement, or planes, helicopters and stars mistaken for drones. 

Duncan acknowledged that the E-ISAC also received a large number of reports of drones flying near critical infrastructure equipment in December, which were described in accompanying material (page 29) as being equal to about half the number of reports normally received in a two-year period. However, he emphasized that the E-ISAC determined there was no threat to grid reliability. The uptick in reports was driven largely by the media attention given to drones in general, he said. 

Drones can be used to attack grid facilities, as in the case of a Tennessee man charged with planning to rig an unmanned aerial vehicle with explosives and fly it into an electric substation. (See Feds Accuse Tenn. Man of Substation Attack Plot.) While Duncan pointed out that drones do have legitimate uses for electric utilities, he said the E-ISAC must continue to work with partners to address their potential dangers. 

“The challenge, of course, [is that] there’s not a lot that can be done in the mitigation front yet, but we’re working with the [Federal Aviation Administration, the Cybersecurity and Infrastructure Security Agency] and industry to make them aware of the potential impact and request additional support,” Duncan said. 

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Eversource to Boost Grid Investments by $1.9B After Exiting Wind, Water

Eversource Energy executives announced during the company’s year-end earnings call Feb. 12 its plan to increase investments in its “core electric and natural gas operations” by $1.9 billion in 2025-2028 in the wake of its exit from the offshore wind business and finalizing the sale of its water utility.

“The $1.9 billion increase is primarily driven by higher electric transmission and higher electric distribution investments in Massachusetts,” CFO John Moreira said.

The company took a net after-tax loss of $524 million from the sale of its offshore wind business in 2024, which came in the wake of a $1.95 billion loss from offshore wind in 2023. Its pending sale of Aquarion Water to a new Connecticut-owned water authority, announced in late January, brought an additional loss of $298 million.

“Proceeds from the [Aquarion] sale will be used to reduce debt, allowing us to reinvest capital into our regulated utilities” in Massachusetts, Connecticut and New Hampshire, Eversource CEO Joe Nolan said.

Between 2025 and 2029, the company plans to invest a total of $24.2 billion across its gas and electric businesses, which includes “only those projects that we have clear line of sight on from a regulatory approval perspective,” Moreira said. This includes nearly $7 billion in transmission investments, focused on projects to replace aging infrastructure, increase extreme weather resilience and interconnect renewables.

The plan also features more than $10 billion for electric distribution upgrades, focused on reliability and resilience. This includes $850 million to deploy advanced metering infrastructure (AMI) in Massachusetts, which will “allow customers to increasingly participate in the transformation of energy usage,” Moreira said. Eversource’s goal is to achieve full AMI deployment by 2029.

Moreira said the company could invest an additional $2 billion in investment over the five-year period, highlighting the deployment of AMI and electric vehicle infrastructure in Connecticut, large-scale solar generation in New Hampshire and upgrades at its LNG facilities.

“The biggest component of that incremental investment opportunity is Connecticut AMI,” Nolan said.

The company and the state have struggled to agree on how to fund the deployment of meters for 1.3 million customers, which is expected to cost $766 million. Eversource and Avangrid, which both own utilities in Connecticut, have frequently decried the regulatory climate in the state under the leadership of Public Utilities Regulatory Authority Chair Marissa Gillett. In January, the companies filed a lawsuit alleging that Gillett has abused her authority as the head of the agency.

“PURA’s use of unlawful procedures to vest unchecked decision-making authority in a single individual has resulted in an environment of opaque, unpredictable and arbitrary regulatory outcomes,” Eversource wrote in a cease-and-desist letter to the agency on Jan. 14.

“We continue to await PURA’s action as they consider the final decision” on the AMI meters, Nolan said.

Gov. Ned Lamont (D) has stood by Gillett, who is up for reappointment. He has disputed the utilities’ claims that the authority has unlawfully made decisions without holding votes between all three commissioners.

“Stop litigating this in the press,” Lamont said in a January news conference. “If you don’t like a decision, you can appeal it. I think that is the best way to handle this.”

Regarding Massachusetts, Nolan highlighted Eversource’s recent acquisition of part of the retired Mystic Generating Station from Constellation Energy.

“Purchasing this site will allow us to transform it into a premier energy interconnection hub that enhances reliability and energy supply diversity for the entire New England region,” Nolan said. He noted that the company is still evaluating investment opportunities at the site.

Asked about potential additional delays to Revolution Wind after Ørsted appeared to push the offshore wind project’s timeline back at its earnings call earlier in the month, Nolan said that “nothing has changed on Revolution; we continue to make great progress.”

While the company sold its stake in the project to Global Infrastructure Partners, it remains on the hook for price adjustments if the project’s pre-tax, equity internal rate of return falls below 13%. These adjustments would be applied upon the project’s commercial operations date. Eversource also shares partial responsibility for construction cost overruns on the project.

“The 20th turbine is being loaded now at New London. … We feel very good about executing there,” Nolan said.

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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 currently is 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 the company did not address any market power concerns. 

FERC often works with DOJ’s Antitrust Division, as they have overlapping jurisdiction on mergers, but the notice is unusual. It simply informed parties to the case 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 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 [Tenaska] 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 currently is 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 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 because of 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 at 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 reduce 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 also has 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 since has 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 2021/22 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 convoluted 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 publication 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) 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 MISO ratepayers could save several million dollars 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 more than 2.5 times cost increase 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 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 still is looking for clarification on President Donald Trump’s pending 10% tariff on energy imports, Joe Oates, chairman of NYISO’s Board of Directors, 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,” Oates 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.) 

Oates 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

Oates told the subcommittee the board 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,” Oates said.  

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

Cybersecurity Updates

Oates said NYISO 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 also continues 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. Oates 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 warned that China has sponsored 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 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 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 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.