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February 28, 2025

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Feds Pause $1M Pathways Initiative Funding, Group Leader Says

The federal government has put on hold nearly $1 million in funding toward the development of a new independent Western “regional organization” (RO) to oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the West-Wide Governance Pathways Initiative’s Launch Committee said Feb. 27.

The funding status is unknown because of a communication pause from the U.S. Department of Energy, according to a committee presentation.

“Given some of the cuts and uncertainty with the federal government, that funding is currently on hold,” Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, said during the stakeholder meeting.

However, the Launch Committee does not expect the uncertainty of federal funding to slow down its work significantly. The current political environment has impacted some partners of the Pathways Initiative, “and we are sensitive to that. But directly for the work that we’re doing, we think we’re going to be able to continue to move forward,” Staks said.

Pathways received nearly $1 million from the DOE under former President Joe Biden’s administration in November to underwrite the committee’s efforts to establish an RO to oversee CAISO’s WEIM and EDAM.

The award was issued through the Pathways Initiative’s philanthropy adviser Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.

President Donald Trump’s administration on Jan. 27 paused all federal grants and loans, according to a memo issued by the White House’s Office and Management and Budget.

“With or without that DOE funding, the RO is going to need additional funding,” Staks noted.

Setting up an independent RO comes with several costs, including legal review of various documents, seating a board and ongoing facilitation costs, among other things, she said.

Staks said the committee hopes to have a draft budget to share with stakeholders by spring. She recognized that “all of our work thus far has been funded by a variety of stakeholders, and we are extremely grateful for that support and commitment.”

The Launch Committee’s success also hinges on the California bill to implement the Pathways “Step 2” plan to transform CAISO’s governance. Lawmakers introduced the bill in the state Legislature on Feb. 20. The proposed legislation sets conditions under which CAISO and California investor-owned utilities can participate in energy markets governed by an independent RO.

The Launch Committee is also working to finalize corporate documents, including registering as a nonprofit organization and refining the nominating committee process used to seat the RO board. The entire process to establish the RO will be marked by an extensive stakeholder process and negotiations between various parties, Staks noted.

The Pathways bill states that CAISO can join the RO-governed market on or after Jan. 1, 2027, which the Launch Committee believes “will not be too early,” according to Staks.

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SouthCoast Wind to Take $278M Impairment as Delay Appears Likely

Another mature offshore wind project is facing financial write-downs and a potential yearslong delay in the wake of the Trump administration’s moves to shut the sector down. 

The partners behind SouthCoast Wind said they would take a $278 million impairment on their planned wind farm off the Massachusetts coast and place development on hold for as many as four years because of the uncertainty created by President Donald Trump’s Day 1 executive order targeting wind power. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

SouthCoast is at a late stage of development compared with many of the other proposals in U.S. waters. On Dec. 20, the Bureau of Ocean Energy Management issued a Record of Decision in its favor. It was the 11th offshore wind project greenlit, all of them during the Biden administration, and it seems likely to be the last for years to come. 

BOEM subsequently approved SouthCoast’s construction and operations plan on Jan. 17 — the last business day before Trump was inaugurated and issued an executive order casting new uncertainty upon what once was a rapidly growing renewable energy sector. 

EDP Renewables and Engie are 50/50 partners in Ocean Winds, which is developing SouthCoast. They cited the U.S. market uncertainty Feb. 26 and 27, respectively, as they discussed the possible delay and resulting impairment with financial analysts. 

EDP CEO Miguel Stilwell d’Andrade said during an investor call that in the wake of the executive order, “We’ve decided to just be more prudent around the timing. … If we get a better scenario, then that would be great. We could have taken a two-year delay, but we took a four-year one.” 

“We feel that there’s probably going to be delay in development. [SouthCoast] is quite advanced. It’s a great project. So if we pause it, it’s OK; you know, let’s see what happens in four years,” Engie CEO Catherine MacGregor said. 

Ocean Winds North America CEO Michael Brown later said via email: “The impairment decision is a precautionary measure based on a scenario of potential delays in its projects. Ocean Winds strongly believes in the potential of offshore wind to generate significant economic activity and provide abundant, domestic energy to meet rapidly growing demand in the U.S. and remains confident in finding a path forward in coordination with all relevant authorities in the upcoming months.” 

This is the narrative adopted by the U.S. renewables industry after Election Day: The country needs the electricity and the economic benefits of renewable energy development. But there is no indication so far that the argument has swayed the president. 

SouthCoast in September was selected in an innovative joint solicitation by the three southern New England states to provide 1,087 MW to Massachusetts and 200 MW to Rhode Island. 

But nearly six months later, the parties are still negotiating power purchase agreements. The terms have not been disclosed, but they are likely to be expensive: D’Andrade hinted that EDP’s bid was higher than $150/MWh. 

Massachusetts officials were not able to provide an update at press time, and Rhode Island officials did not return a request for comment. 

This is the second go-round for SouthCoast Wind, which was selected in an earlier Massachusetts solicitation under the name Mayflower Wind. Like most other wind projects contracted off the Northeast coast, it could not proceed to construction amid the soaring costs and supply chain constraints of 2022/23 under terms of PPAs negotiated years earlier. After negotiations, SouthCoast canceled the original PPAs and rebid its project. 

The reset may prove costly, as U.S. leadership has since passed from an ardent wind power supporter to an adamant foe. 

Trump’s executive order immediately halts only future wind energy leasing, but it directs a review and potential revocation of existing lessees’ permits — an implied but dire threat to an industry that already was struggling before he was elected. 

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Texas RE Hears About Reliability Benefits of New Nuclear Reactor Designs

A new generation of nuclear reactors has the potential to provide needed reliability services, speakers said at a webinar hosted by the Texas Reliability Entity on Feb. 27. 

However, they added, harnessing these technologies will require helping regulators, policymakers and consumers overcome longstanding concerns about nuclear power. 

Derek Haas, an associate professor at the University of Texas at Austin whose areas of research include advanced nuclear reactor design and licensing, joined Andrew Harmon, vice president of operations and business development at Natura Resources, for the regional entity’s regular Talk with Texas RE event. 

Haas observed that traditional nuclear reactors produced relatively large amounts of power but required a reliable electric supply from the grid to pump coolant even after shutdown. By contrast, newer reactor designs such as molten salt reactors, which produce energy at higher temperatures and higher efficiency but lower pressure, are built to “walk away safe” standards so they can shut down safely without melting down even if grid power is lost. 

The new designs can even support the grid in the case of an emergency, Haas said, noting that “you might have an on-site diesel generator, and with that, the reactors even provide an additional level of reliability where they could provide black start capability to the grid.”  

In addition, he observed that although “folks think of nuclear as not load-following … reactors can load follow, really, faster than coal, but not quite as fast as gas. It’s just that for such a capital-intensive project [as a traditional reactor], it doesn’t really make sense to load follow.” By contrast, he said, advanced reactors could be constructed at a smaller size and a lower cost to make them more responsive to load. 

Proponents of advanced reactors have attracted criticism for presenting an overly rosy picture of the state of the technology. For example, last year a nuclear energy expert from George Washington University argued that the presence of these reactors on power grids “is largely fictional,” and the reactors that have been built present significant risks of terrorism and nuclear proliferation. (See Report: Small Nuclear Reactors not the Answer.) 

However, Harmon, whose company is preparing to build the MSR-100 molten salt reactor at Texas A&M University, emphasized that such concerns have been considered and incorporated into the design of the new reactors. Natura touts the MSR-100 as the first molten salt reactor ever licensed by the U.S. Nuclear Regulatory Commission, and Harmon pointed out that the new reactors reduce or eliminate many of the dangers associated by the public with traditional reactor designs. 

“Molten salt reactors do not produce spent nuclear fuel, and so we have the ability to … achieve 20 times the amount of fuel utilization [of] traditional light water reactors,” Harmon said. “Basically, as long as gravity works, we’re able to drain our salt and our fuel into a drain tank below our reactor core … thus causing the fission process to stop, and keeping it under low-pressure operation. So there’s nothing that we have to actively do for that system to be able to walk away and safely shut down operations.” 

Both speakers acknowledged that nuclear proponents will need to overcome longstanding fears based on accidents like those at the Chernobyl and Fukushima nuclear plants. Haas observed that the U.S. nuclear industry also needs investment; the Nuclear Energy Institute’s 2023 Workforce Strategic Plan found that a significant portion of the nuclear workforce is approaching retirement age, particularly in the radiation protection field. 

Haas emphasized that while the cultural bias against nuclear power is understandable given their presentation in the media, “the risks are already extraordinarily low with existing [nuclear] technology,” and new designs will only increase that safety. 

“The reality about even [Chernobyl, Fukushima and Three Mile Island is] the number of people harmed was still extraordinarily low for industrial accidents,” Haas said. “I would be perfectly happy to live near a nuclear reactor, and the last place I lived was just within sight of a nuclear power plant. So [I’m] not just saying that; I’ve done it before.” 

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Legal Experts Chart Future of Agency Deference After Loper Bright

WASHINGTON — Before President Donald Trump’s executive orders started raising questions about the authority of FERC and other agencies, courts had already started to chip away at longstanding precedents such as the Chevron deference, experts said during a panel at NARUC’s Winter Policy Summit.

“Chevron has been on the ropes for many, many years,” Jonathan Ellis, a partner with McGuireWoods, said during the Feb. 24 panel. “Justice [Antonin] Scalia was once an ardent supporter, and then toward the end of his career soured on the doctrine.” (See Supreme Court Ends Chevron Deference to Administrative Agencies.)

Before Scalia started to change his tune on the precedent, Ellis clerked for Chief Justice John Roberts, who Ellis said was never a big fan of the doctrine, in which courts usually deferred to decisions by regulatory agencies on issues of their expertise.

In many cases preceding Loper Bright Enterprises v. Raimondo, the court had worked around Chevron, but the petition for certiorari in that case already asked the court to rule against it or find it did not apply, Ellis said.

“There will always be, I think, out of necessity, some role or deference to regulatory agencies and expertise that they represent,” he added.

Georgetown University law professor Howard Shelanski agreed that the tea leaves had not augured well for Chevron for quite some time, but noted the issues in the case went to the heart of the constitutionality of Congress delegating authority to agencies.

“For a long time, it was taken as a given by the court that concerns over delegation had been asked and answered,” Shelanski said. “And so long as there was some kind of articulable principle that limited the agency — even a very vague one, even a very general one — they had to allow that Congress had the authority to give the agency some scope for interpretation. And that led to the view, if a statute is silent on something, the agency should be able to step in.”

‘Ambiguous Phrasing’

Overruling Chevron means precedent has reverted back to the 1970s, when courts could second guess agency decisions on appeal as a matter of statutory interpretation, he said.

FERC Solicitor Robert Solomon said in his 30-year career he has probably cited the Chevron doctrine as much as any lawyer, but over the past 10 years the Supreme Court and lower courts have increasingly avoided using it.

“Courts have gone out of their way to find the absence of ambiguity and no need to defer formally under Chevron to the agency,” he added.

The Energy Policy Act of 2005 contained what Solomon called “some of the most ambiguous phrasing” he could imagine around when FERC’s backstop transmission siting authority kicked in, but the U.S. 4th Circuit Court of Appeals still declined to follow Chevron in Piedmont Environmental Council v. FERC and sided against the agency, effectively gutting that statute for a decade until Congress passed another law.

“In the Supreme Court demand response case, FERC v. EPSA — the greatest case ever decided, the majority found that the FERC’s authority to essentially regulate demand response, because it has a direct effect on wholesale prices, was clear and unambiguous,” Solomon said, making a joking reference to a case he argued.

But in a dissent in that case, Scalia argued the statute was “clear and unambiguous” against FERC because the agency “was effectively regulating retail sales within the ambit of state authorities,” Solomon said.

Even before Chevron was struck down, it had proved difficult to determine when courts would apply it, and now FERC’s legal team is getting around the issue by using the term “respect” rather than “deference,” he said, adding that he’s concerned by some of the language courts use when they invoke their authority under Article 3 of the Constitution to resolve all questions of law.

Regardless of court actions, Solomon said FERC still has a responsibility to make well-reasoned decisions based on the record before it. Loper Bright will have an impact on interpreting federal law and when it comes to issues where FERC’s authority clashes with that of states, the trend has been to let jurisdictions overlap, he said.

“From my perspective, the bigger concern right now isn’t whether Chevron deference or respect continues to live for our interpretation of federal statutes,” Solomon said. “… Rather, the current issue is whether we will continue to get Chevron-like deference, not when we are interpreting the federal statute, but rather when we are interpreting a federally approved tariff or a contract that similarly involves interpretation by Article 3 courts.”

Courts have expertise in interpreting the law, but FERC has continued to argue in court that it has special expertise when it comes to the rates and tariffs that make up the bulk of its work, Solomon contended. And the agency is waiting for a case that will determine whether the courts will defer to its expertise on jurisdictional contracts and tariffs, he added.

“In the eight months or so since [Loper Bright] was decided, the courts continue to go out of their way to explain whether or not the decision would have been any different if Chevron still applied,” Solomon said. “It’s actually been quite satisfactory to us. There have been a couple of recent decisions where the court has said not just simply that the agency’s interpretation was reasonable or permissible, but rather it was the best or the correct interpretation.”

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Eversource Outlines Billions in New Boston-area Asset-condition Needs

Presenting to the ISO-NE Planning Advisory Committee on Feb. 26, Eversource Energy introduced a new set of asset-condition projects that could cost the region billions over multiple decades. 

The company is proposing the staged replacement of its aging network of underground high-pressure fluid-filled (HPFF) transmission lines in Eastern Massachusetts. The company’s HPFF lines are reaching the end of their expected lifespan, and leaks from the lines have become larger and more frequent as the lines have aged, Eversource’s Chris Soderman said. 

“Failures can lead to monthslong outages due to the difficulty of repairs,” he said, adding that the company is still working on the environmental cleanup for a leak that occurred Dec. 24, 2023. Most of the 6,000 gallons of dielectric fluid that leaked from the line during the incident flowed into the Charles River, he said. 

Eversource outlined its plans to gradually replace its HPFF lines with cross-linked polyethylene (XLPE) technology, which it described as the “preferred technology for new underground transmission line construction.” 

Soderman said the supply chain for HPFF technology is fragile, and the only remaining HPFF manufacturing plant in the world has signaled its intent to exit the market in the long term. 

“If HPFF cable manufacturing were discontinued today, Eversource estimates that spare inventory would be sufficient to maintain existing HPFF lines during the conversion to XLPE — but not over the long term,” Soderman said. “The most responsible solution to ensure long-term reliability for customers and protection of the environment is to transition away from HPFF cables as the assets reach [their] end of usable life.” 

He said the company plans for roughly three to four phases of work to replace its HPFF network, which includes “approximately 179 miles of [pool transmission facility] HPFF circuits.” 

The company expects the replacements to continue into the 2040s, with the first phase aiming to construct about 35 miles of double-circuit underground ductbank, which will likely cost “somewhere between $1.5 [billion] and $2 billion,” Soderman said. He added that it is too early to make reliable cost projections for later phases of the replacements. 

In recent years, the New England states have raised alarm about the rapidly increasing costs of asset-condition projects in the region, prompting some changes to the process of reviewing the projects at the PAC. However, asset-condition projects are under FERC jurisdiction, and the states have limited power to regulate the projects. 

The asset-condition project forecast database published by the New England Transmission Owners — created at the request of the states in 2024 — outlines $5.8 billion in spending for projects expected to come online between 2024 and 2030. This includes only projects with full cost estimates, and the total cost will increase as additional projects move out of the conceptual stages. 

Beyond the cost estimate, Eversource did not provide an official cost estimate for the HPFF replacement program. Soderman said the first phase of replacements will be broken into 11 individual projects with in-service dates from 2028 to 2033. Eversource plans to provide cost estimates to the PAC in the summer, he said. 

Also at the PAC, Joe Dobiac of National Grid detailed a nearly $9 million cost increase for a transmission upgrade project in Massachusetts. He attributed the increase to permitting delays, which have pushed the expected in-service date from December 2025 to December 2026. 

Rafael Panos of National Grid presented a nearly $12 million asset-condition project in Eastern Massachusetts, driven by worn shieldwire assemblies, deteriorated insulation, damaged shieldwire and cracks in a river crossing tower foundation. 

Joshua Cefaratti of Avangrid provided an update on the final cost of a project to build a flood wall protecting a substation in Connecticut. The project was completed in August 2024 at a cost of $53.9 million, a significant increase over the initial estimate of $16.5 million in 2016. He attributed the price increase to permitting and construction delays and increased labor and materials costs. 

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PJM Board Approves $6B in Grid Upgrades

The PJM Board of Managers on Feb. 26 approved a $6 billion package of grid upgrades that includes expanding the 765-kV backbone east to meet rising demand, particularly in Northern Virginia’s Data Center Alley. 

PJM’s recommended slate of projects includes Window 1 of the 2024 Regional Transmission Expansion Plan, as well as a doubling of the cost estimate for grid reinforcements needed to allow the deactivation of Talen Energy’s Brandon Shore generator outside Baltimore from $738.83 million to $1.5 billion. (See “RTEP Changes Include Doubling of Tx Costs for Brandon Shores Deactivation,” PJM TEAC Briefs: Feb. 4, 2025.) 

“A strong, efficient transmission system enables economic growth and ensures reliability for consumers across the PJM region,” PJM’s Executive Vice President of Operations, Planning and Security Aftab Khan said in an announcement of the approval. “These projects are especially critical to reliably meet the increasing demand for electricity and leverage new generation resources.” 

The expansion of the 765-kV network, which accounts for the bulk of the cost, would proceed in two regions: one to the north running from the John Amos substation in West Virginia to the Doubs substation in Maryland, and a second to the south linking the existing network looped into Joshua Falls in Amherst, Va., to a new substation, named Yeat, in Fauquier County to the north. 

The northern corridor would use a mix of greenfield and existing rights of way between Joshua Falls and the Welton Spring substation, which would be upgraded with a new 765-kV switchyard, four 250-MVAR shunt reactors and a 500-MVAR synchronous compensator (STATCOM). The line would continue to Doubs mainly following existing ROW and then to a new Rocky Point substation sited nearby. The new facility would be looped into the 500-kV Doubs-Goose Creek, Doubs-Aspen and Woodside-Goose Creek lines and would feature 765- and 500-kV yards; two 765/500-kV transformers; two 765-kV and two 500-kV, 250-MVAR capacitor banks; and a 500-MVAR STATCOM. Upgrades would also be made to the Joshua Falls, Doubs and Black Oak substations. 

PJM’s analysis report accompanying the recommended projects states that the proposals to upgrade the corridor between John Amos and Rocky Point to 765 kV was selected to provide scalability and flexibility to address load growths and changes in the resource mix beyond the RTEP horizon. A newly implemented 15-year analysis found anticipated violations that would be resolved by the proposal. The work was assigned to American Electric Power, FirstEnergy and Trans-Allegheny Interstate Line Co. (TrAILCo), the latter of which is a FirstEnergy subsidiary. It is expected to cost $1.9 billion, with a required in-service date in June 2029 and projected in-service date in December 2029. 

The southern Joshua Falls-Yeat line would mainly follow existing ROW, with some greenfield components. Yeat would be cut into the 500-kV Bristers-Ox, 500-kV Meadowbrook-Vint Hill and 230-kV Vint Hill-Elk Run lines. The component is estimated to cost $1.1 billion and go into service in June 2029. 

The work between Joshua Falls and Yeat also includes the proposed 500-kV “Kraken Loop” branching off the North Anna substation to a new Kraken facility to the northeast and turning back northwest to Yeat. Existing lines between North Anna and the Ladysmith substation would be upgraded to 500 kV, and new lines mainly following existing ROW would be built to Kraken, which would be outfitted with two 1,440-MVA, 500/230-kV transformers. The corridor would continue to Yeat with a mix of greenfield and existing ROW. Upgrades would be made to the North Anna, Ladysmith and Elmont substations. 

The RTEP report states that the loop will address load growth expected to the east of North Anna, while also resolving stability and operational constraints. Ties to the 230-kV network around Kraken would be deferred until they are needed and likely pursued through the supplemental planning process. The loop was assigned to Dominion Energy at an estimated cost of $704 million and an in-service date in June 2029. 

Several additional project components across the PJM region were included in the RTEP window. An additional $672 million Transource project was selected to upgrade 230-kV and 115-kV infrastructure across the Dominion’s footprint, which was assigned the construction as the incumbent transmission owner. The package includes a new 230-kV Elmont-Ladysmith line using existing structures between the two substations; a new 230-kV Raines-Cloud line; and rebuilding two 230-kV lines between the Marsh Run and Remington CT substations.  

A $217 million package was approved in the ATSI region to rebuild the 32-mile, 138-kV Greenfield-Beaver line and sections of the Hayes-Avery, Avery-Shinrock and 138-kV Greenfield-Lakeview lines. A $262 million project would reconfigure the 765-kV Maliszewski substation and reconductor the 10.2 miles of the 345-kV Maliszewski-Corridor line and 4.75 miles of the 345-kV Bokes Creek-Marysville line. 

Advanced Energy United Policy Director Jon Gordon said the RTEP process fails to consider regional impacts and alternatives to transmission for solving needs identified. He also argued that projects submitted by TOs are planned in isolation and not competitively bid. 

“PJM continues with its business-as-usual buildout of local transmission ‘reliability’ projects that are not part of any kind of comprehensive regional infrastructure planning process. The PJM board just approved $6.7 billion of these transmission projects for this year, up from $5.1 billion in 2024. The five-year cost for these projects is approaching $40 billion,” Gordon said. “These costs are passed through directly to ratepayers and are part of the ever-escalating retail electric rate problem that PJM seems to have little concern for.” 

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Stakeholders Want More from MISO on Tx Project Cost Containment

CARMEL, Ind. — MISO doesn’t think it needs to step up cost monitoring on its ever-larger transmission projects even as some stakeholders call for tighter measures.

Speaking at a Feb. 25 cost allocation working group meeting, MISO’s Jeremiah Doner said the RTO doesn’t see a need to upend its current variance analysis process, the mechanism it uses to investigate projects that incur cost overruns or other difficulties.

“We think that the current process is designed to sufficiently monitor and track projects,” Doner told stakeholders.

MISO’s End-Use Customer sector in December asked the RTO and stakeholders to discuss transmission cost containment measures. The request coincided with MISO announcing it would investigate one long-range transmission project from its first portfolio, which experienced a 2.5-times increase in costs. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)

MISO staff perform variance analyses on regionally cost-shared transmission projects that encounter schedule delays, permitting challenges, significant design changes or experience at least a 25% cost increase from original estimates. The studies are also triggered when developers find themselves unable to complete the project or if they default on the terms of their selected developer agreement.

After completing the analysis, MISO can either let a project stand, develop a mitigation plan for it, cancel it or assign it to different developers if possible. A committee of MISO employees selected by RTO executives makes calls on how to deal with such projects.

The End-Use Customer sector and the Coalition of MISO Transmission Customers have said that MISO’s 25% trigger is too high.

Some stakeholders have suggested MISO lower the current 25% cost-increase limit to around 10%. They have also said the RTO should consult with state regulators to review the cost mitigation measures it prescribes to some developers.

MISO settled on the 25% threshold 10 years ago, Doner said.

“There were stakeholders who wanted the value to be higher, there were stakeholders who wanted the value to be lower,” he said.

Zachary Callen, an economic analyst at the Illinois Commerce Commission, asked if MISO has considered notifying stakeholders about projects with up to a 24% cost overrun that might run the risk of a variance analysis.

Doner said MISO thus far hasn’t encountered too many projects that have cost overruns that come close to the 25% limit.

“There still is room for some modest enhancements,” argued attorney Ken Stark, representing MISO end-use customers. He added that the End-Use Customer sector is willing to come before the working group in April to propose some stiffer requirements to “layer on” to the existing process.

“The world has changed. The portfolios that are coming in aren’t exactly cheap,” said consultant Kavita Maini, representing MISO industrial customers. She said for a billion dollar transmission project, costs could spill over by $250,000 before MISO commits to examining them.

“That’s a lot of money. … It seems like this threshold should be much lower,” Maini said. She said she believes there’s more to do to make the variance analysis more transparent and ensure proper monitoring of projects.

Doner maintained that the process is sufficiently transparent. He said MISO staff uses the publicly available reporting that developers submit to MISO to review projects. However, he acknowledged the RTO can’t always share confidential project information.

“We think that the tools are there. We’ve been able to track costs with projects and make changes, if need be,” he said.

Although MISO so far doesn’t seem receptive to increased variance analysis activations, Doner said it plans to more clearly provide notice to stakeholders through its public planning committees when it finishes a variance analysis and develops an action plan.

MISO has completed nine variance analyses to date. For most studied projects, the RTO has either drawn up mitigation plans or let projects stand. While the grid operator has never reassigned a project developer through the analysis, it has canceled one 500-kV project due to a new right of first refusal law in Texas. (See FERC Rejects Last-ditch Effort to Save Tx Project.)

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Dragos: Attacks on ICS Increased in 2024

The barrier to entry for malicious cyber actors to target operational technology and industrial control systems (ICS) continued to drop in 2024, paving the way for new adversaries to target electric utilities and other critical infrastructure providers, cybersecurity firm Dragos claimed in its annual Year In Review report released Feb. 25. 

At the same time, cyber defenders made “incremental but uneven” progress adapting to the new pressures on them, Dragos said, with electric utilities and other regulated industries demonstrating “higher maturity levels” than peers in other sectors, including water utilities and manufacturers. The firm said that “visibility into OT environments lags behind adversary tactics in many cases.” 

“Organizations with strong incident response capabilities, defensible architectures, secure remote access protocols and robust network monitoring are far better positioned to reduce the risk of a successful attack on the enterprise OT even in this increasingly complex environment,” Dragos said. 

Dragos publishes its Year in Review each year to alert cybersecurity professionals to trends in cyberattacks, as well as specific threat groups that were active during the previous year. The firm said nine of the 23 threat groups that it tracks were active in 2024. 

New Adversaries with Stage 2 Capabilities

Two of these groups — Graphite and Bauxite — were identified last year for the first time, although Graphite is now known to have been active since at least 2022, and Bauxite since 2023. 

Graphite has conducted spear-phishing campaigns — in which an emailer attempts to gain confidential information by impersonating trusted senders — against natural gas pipeline operators and hydroelectric facilities in West Asia and Eastern Europe, along with energy and government entities in Poland, Ukraine and the Middle East. 

While Dragos does not link attack groups with specific nation-states in its report, the firm did note that “Graphite focuses on organizations with relevance to the military situation in Ukraine.” 

According to the report, Graphite’s activities have not yet risen past Stage 1 of the ICS kill chain, a model of ICS attacks adapted from Lockheed Martin’s cyber kill chain framework. SANS Institute defines Stage 1 as “espionage or an intelligence operation.” But the other newly identified group, Bauxite, has demonstrated the ability to reach Stage 2 of the kill chain, Dragos said, meaning “a capability that can meaningfully attack the ICS.” 

Bauxite’s first campaign affected nearly 100 organizations globally and involved compromises of programmable logic controllers connected to the internet. This gave the attackers the ability to launch a denial-of-service attack against the victims’ ICS. The group went on to target devices manufactured by Sophos, leading to “enterprise impact on chemical, food and beverage, and water and wastewater industries.” 

Dragos noted that Sophos devices are also found in North American electric and oil and natural gas utilities, though these were not identified as having been affected by the attack. The firm said that Bauxite “shares substantial technical overlaps, based on capabilities and network infrastructure, with the pro-Iranian hacktivist persona CyberAv3ngers.” 

Three other active threat groups demonstrated ICS cyber kill chain Stage 2 capability: Chernovite, developers of the ICS attack framework Pipedream; Electrum, previously involved in attacks against Ukraine’s electric grid in 2016; and Voltzite, a group with “extensive technical overlaps with” the China-connected Volt Typhoon group. Volt Typhoon has been accused of embedding itself in the information technology networks of U.S. critical infrastructure organizations for at least five years. (See CISA Leader Reiterates China Cyber Warnings.) 

Dragos called Voltzite “arguably the most crucial threat group to track in critical infrastructure, [with a] dedicated focus on OT data.” The firm said it has observed Voltzite stealing “data that contains critical information about the spatial layout of energy systems” and expects the group to continue operating against critical infrastructure both in the U.S. and “Western-aligned nations” in 2025. 

Dragos Urges Ransomware Preparedness

Ransomware remained a serious threat across industries in 2024, with Dragos saying the number of ransomware attacks against industrial organizations has doubled year over year since 2022. 

Last year, the firm observed ransomware groups posting sensitive data of 1,693 industrial organizations on their dedicated leak sites; 984 incidents, more than half the total, were observed in North America, with 419 in Europe and 137 in Asia. Fewer than 100 incidents each were observed in South America, Africa, the Middle East, and Australia and New Zealand. 

Companies in the electricity industry constituted a relatively small portion of the ransomware attacks, with only 30 incidents in 2024. The vast majority of incidents affected the manufacturing sector, which Dragos attributed to the knowledge that “even brief disruptions can cause significant financial and logistical fallout” for manufacturers. However, the firm warned that other sectors, including energy, transportation and ICS vendors, “remain high on the list as ransomware groups refine their tactics to maximize pressure and impact.” 

“With these threats showing no sign of slowing, organizations must prioritize resilience, proactive defenses and incident response readiness,” Dragos said. 

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NARUC Winter Summit Tackles Uncertainty Around Demand Growth

WASHINGTON — Demand growth coupled with an ongoing changeover in supply has dominated the power industry’s attention, and it was a major theme at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit, held Feb. 23-26. 

Those trends have pushed up prices, notably in PJM and its recent capacity auction, but FERC Commissioner David Rosner said all of the RTOs save billions of dollars annually by wringing efficiencies out of the grid. 

“The advantage of markets really is their ability to attract capital and attract the lowest-cost resources,” Rosner said. 

It gets complicated because markets also have to recognize that different resources provide different reliability benefits, and figuring out how to design to markets to address that fact has proven to be a long, iterative process. 

“The commission has approved different ways to ‘accredit’ capacity; that’s a fancy word for saying, ‘We are compensating resources for their actual contribution towards reliability,’” Rosner said. “And that evolves as the system evolves, and the more smart policies like that that we can have in place that pay for service provided, that just makes sense.” 

Markets have improved resource performance, and they have placed the risk for bad bets away from customers and toward investors, NYISO CEO Rich Dewey said. But the fleet has changed significantly in the quarter-century since ISOs and RTOs started running parts of the grid. 

“You’ve got to think about valuing the attribute of what these resources bring, and getting that right, so the investment that’s necessary matches the value and the performance that you get out of that attribute,” Dewey said. “So, markets are in a continuous evolution. You can’t just stand it up and then sit back and collect the rewards of harnessing that spirit of competition. We need to continue to work at it.” 

New York has a goal of getting to net-zero emissions by 2050, but the markets were not set up to address that issue initially, Dewey said. So a big part of the ISO’s work has been to get the rules place that attract the kinds of investment that will realize the policy. 

“The challenges, however, seem to be getting bigger,” Electric Power Supply Association CEO Todd Snitchler said. “We’re going through what I think is a second round of an important opportunity for new investment into restructured markets. But it’s not unique to restructured markets. You’re seeing this in vertically integrated portions around the country as well, where load growth is growing, and growing meaningfully for the first time in a generation.” 

All the change is happening at a time with real challenges from the political side, as states that stood up markets in the 1990s now have very different policies, Snitchler said. The focus used to be on least-cost dispatch, which is what the markets were designed for, and now many states want carbon reductions, or other policies that do not always line up with others in the same market. 

“It’s not an absolute degree of certainty that’s needed, but it’s a reasonable degree of certainty that’s needed,” Snitchler said. “And we find ourselves in very uncertain situations presently, which makes investment very difficult at the very time we need investment to be flowing fairly dramatically.” 

These issues recently came to a head in PJM when its last capacity auction cleared the rest of the market at $270/MW-day after years of lower pricing, a signal for needed new supply, Snitchler said. 

“There already is market behavior that is responding to just one price signal,” he added. “Now we do have to be thoughtful and understand that a number [of], or several more, high auction clears are probably not politically palatable.” 

Pennsylvania Gov. Josh Shapiro (D) and PJM have agreed to a deal that will cap prices for the next couple of auctions as the RTO considers additional changes in the capacity market. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

All of the changes to markets make it riskier to commit the capital needed to get new generation built, Shell Energy North America CEO Carolyn Comer said. 

“The more markets continue to get tweaked, the more uncertainty we see, the harder it is for me to compete for that capital, quite frankly, and that’s a problem,” Comer said. 

Shell has started to invest directly in power plants, so it is watching those rules for its own purposes, she said. It also offers risk-management services for smaller market players. In the past, hedges were commonly offered to such customers for 15 to 20 years, but the pace of change makes that less feasible. 

“I do believe it’s important to take risk off consumers and move it to the product; that’s the whole point of creation of competitive markets,” Comer said. “Then I also have to think about making a return on the risk that I’m actually taking. And in order to be able to calculate that return on risk, I need a certain amount of policy certainty.” 

The changes have led to a number of policies at PJM, especially including price caps and temporary queue jumping, but the ultimate solution to higher prices is to get more resources onto the grid, and that should involve all kinds of generation, American Clean Power Association Vice President Carrie Zalewski said. 

“The obvious answer is, let’s interconnect stuff,” Zalewski said. “Waiting in an interconnection queue is one thing, but not knowing how long you’re going to wait, there’s a whole other level of uncertainty that creates more issues with supply chain.” 

Developers can spend so much time waiting for a generator interconnection agreement (GIA) that permits already approved expire. Order 2023 from FERC will help once implemented, but more can be done both before the GIA and after, she added. 

Uncertainty on the Demand Side

While suppliers face uncertainty, the issue is increasingly important on the demand side as the grid faces load growth not seen in decades from data centers, reshoring manufacturing and the early days of electrification. 

Artificial intelligence is a major source of demand for data centers now, and despite some recent improvements in efficiency from Chinese firm DeepSeek, that is expected to continue to grow, Electric Power Research Institute CEO Arshad Mansoor said. 

“There’s Jevon’s paradox that says things that get more efficient are used more, and that’s really what’s going to happen,” Mansoor said. 

The large language models that have dominated AI so far can only train on the information that is on the public internet, which is only about 5 to 6% of the total data in the world. Industries, including energy, are going to start training AIs on their proprietary data to help out in their operations, and that is going to lead to huge new computing demands regardless of how efficient the code is, Mansoor said. 

All that growth represents a huge economic opportunity for the country, and meeting it is going to require getting the load forecasts right, PJM Senior Vice President Asim Haque said. 

PJM is working closely with its member utilities and increasingly the data centers themselves, while focusing on the areas in its footprint with the highest demand, like Northern Virginia and Columbus, Ohio. 

The new load growth is going to require more transmission and generation, but some of the data center customers are focused on speed to market. 

“They’ve got to get to market to a particular point in time,” Haque said. “That’s why you’re seeing some more adventurous efforts outside of directly connecting to the grid — this concept of co-location.” 

While many data centers are focused on getting to the grid quick, Meta’s Etta Lockey said her firm was not interested in shifting costs to other customers and ultimately looks at data center expansion as a net positive. 

“We sit at a really generational, hopefully once-in-a-career opportunity to think about some economic growth in this country that could be unprecedented,” Lockey said. “And that’s the future state that I really want to [home] in on and force us all to kind of think about what that can really look like.” 

While rates have been on the rise, if the load growth from data centers is handled right, it will lead to more infrastructure, and the overall costs of the system will be spread across a bigger base. 

“The end goal should be downward pressure on rates, let’s be honest,” Southern Co. Vice President of System Planning Clay Rikard said. “This new load is the opportunity to put downward pressure on rates, if we do it right.” 

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NYISO Preparing to Collect Duties on Canadian Electricity Imports

NYISO presented the Installed Capacity Working Group with two proposals it plans to file with FERC to give itself the means to collect duties in case President Donald Trump’s tariff on Canadian energy imports applies to electricity.

Trump had announced a 10% tariff on “energy resources from Canada” but paused it on Feb. 3. While NYISO’s current position is that import the tariff does not appear to legally apply to electricity — and it is not necessarily its job to collect the duties if it does — it wants to be prepared on Day 1. (See NYISO Assessing Impact of Trump’s Canada Tariff on Electricity Market.)

“The goal is to have effective March 4 the tariff infrastructure in order to comply with whatever the government may impose,” NYISO General Counsel Robert Fernandez said.

“It seems to me that what we think about whether or not they apply is not relevant because ultimately, it will the wannabe king and his minions who tell us whether it applies or not, and I don’t get the impression they’re going to consult with you,” said Mark Younger of Hudson Energy Economics.

NYISO’s primary proposal would allow it to collect duties from real-time scheduled imports originating from “Duty Eligible Proxy” buses that represent interties between New York and Canada. It would create a new Rate Schedule 21 for duty recovery that would be paid to a relevant federal authority and charged to the “financially responsible party” for each subject transaction.

Under this proposal, NYISO would use day-ahead location-based marginal prices to calculate duties. NYISO said that using this method will allow both day-ahead and real-time transactions to reflect the cost of duties in their offers. Using real-time prices would make it impossible for duties to be calculated on day-ahead transactions.

“The day-ahead LBMP represents a financially binding price for electricity sales at the relevant tie and location,” said Nathaniel Gilbraith, manager of energy market design for NYISO. “Using real-time prices alone to calculate duties would create a duty cost risk that the day-ahead transactions could not reflect in their offers.”

Until NYISO develops software to automate calculating, collecting and paying duties, the process would be manual. The ISO would not collect duties on Canadian energy wheeling in from other control areas.

NYISO’s alternate proposal defines subject transactions the same way but would collect the required duties from withdrawals on a ratio-share basis. This is being done to create a duty mechanism that would apply to load in order to maximize the likelihood that NYISO has the legal authority to collect.

“My understanding is that the importer of record pays the collection that pays the tariff and ultimately passes it on to the consumer,” Fernandez said. “And that’s analogous to what we’re saying could happen under the load-ratio-share approach.”

Fernandez said this was not the favored approach because it was not as economically efficient. The alternative, which the ISO calls a “backstop,” was being filed out of an abundance of caution, he explained.

Younger said he appreciated the steps NYISO was taking to protect the market and added that it should ensure that capacity was also covered by any language filed with FERC.

Ted Murphy, a lawyer for NYISO from law firm Hunton Andrews Kurth, explained that there was historical precedent against import duties being levied against electricity. He said federal customs and tariff enforcement agents did not know how applicable tariffs were to electricity.

“One thing that gives me comfort is that one line in the trade tariffs suggest that intangible things are not subject to tax,” Murphy said. “There are cases saying electricity is intangible. In my mind, capacity as one level of abstraction out from actual electrons crossing the border makes me think that the focus is going to be on energy, not capacity or other products. But nobody knows.”

Chris Casey, with the Natural Resources Defense Council, said that filing a request with FERC to enable compliance with potential import duties made him nervous because no formal ruling on electricity had been made by any relevant authority. Fernandez replied that the ISO had considered going through a more formal process of getting a declared ruling, but the problem was lack of time.

“In a perfect world, these rules would have been developed through the normal shared governance process,” Fernandez said. “But March 4 is next week, and we’ve been looking at this for a couple weeks now, and we simply do not have time to get that ruling.”

Fernandez said that if Customs and Border Protection or the Treasury Department did not give NYISO a definitive ruling by March 4, the import duties would not be collected or remitted to the government. They would set up the accounting necessary to do so only when ordered.

“Dollars will not flow, will not be collected or remitted until we know that we actually have a legal obligation to do that,” Fernandez said. NYISO staff and counsel would consider whether to add capacity to the proposals in a pre-filing conference, he said.

Fernandez went on to say that he expected ISO-NE to file a similar request by the end of the week with FERC but that he did not know where the other ISOs or RTOs stood on this issue. A stakeholder said that he was worried that NYISO’s filing would “raise awareness” and cause reinterpretation of existing law.

“Are we making this a self-fulfilling prophecy?” Fernandez reflected. “I don’t know, but I read the newspapers. It’s not like we can stick our heads in the sand and act like ostriches on this and hope it doesn’t happen. On March 4, NYISO needs rules in place so we can comply with the law if it eventually comes to pass.”

When NYISO staff were asked by other stakeholders how much money was at stake for the federal government, they said that forecasting that figure was complicated and that they didn’t want to go on record with a dollar figure.