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March 12, 2025

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PJM Stakeholders Approve SIS Manual Language

VALLEY FORGE, Pa. — The PJM Planning Committee on March 4 endorsed by acclamation revisions to Manual 14H to conform with changes to the RTO’s surplus interconnection service (SIS) process FERC approved in February (ER25-778).  

The committee discussed the specifics of how PJM would implement the changes during its meeting before approving the language. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

SIS allows developers to add new resources to an existing point of interconnection that is not fully used; for example, if an existing resource does not operate at all times of day. Injection is capped at the capacity interconnection rights in the original resource’s interconnection service agreement, and surplus interconnection requests do not trigger the need for new network upgrades. 

The new manual language would eliminate categorical prohibition on storage eligibility for SIS; change how PJM models proposed resources alongside projects in the generation interconnection queue; expand eligibility to allow SIS applications when the host resource is still in development; and allow projects that consume transmission headroom but do not require network upgrades. It would also allow projects that require additional interconnection facilities for the service while still prohibiting new network upgrades. 

PJM’s Ed Franks said SIS applications would be studied using the most recent cluster phase 3 model to be commenced, which he said would strike a balance that allows projects to proceed without being disrupted if others in that cluster drop out. Franks said it is less likely for projects later in the queue to withdraw, reducing the risk of cluster analyses having to be retooled in a manner that impacts the potential for SIS projects to be assigned network upgrades. 

“This would only be exponentially more complicated if we were using an earlier model,” he said. 

Responding to stakeholder questions on what battery storage configurations would be allowable, Franks said both open- and closed-loop storage would be permitted so long as network upgrades are not triggered. 

Ken Foladare, director of RTO and regulatory affairs for Tangibl Group, said the change would allow existing renewable resources to increase their reliability contribution by adding storage, transforming a non-dispatchable resource into semi-dispatchable. 

Jason Connell, PJM | © RTO Insider LLC

“This is a good opportunity for PJM to be able to add megawatts, especially if you’re adding battery storage to standalone wind, standalone storage and contribute to resource adequacy,” he said. 

Stakeholders questioned whether there would be a cure process for cases in which network upgrades are identified and allow for developers to change the scope of their projects to mitigate those violations. PJM Vice President of Planning Jason Connell said the tariff is clear in that if the SIS request causes a need for network upgrades, it would be denied. 

PJM Director of Interconnection Planning Donnie Bielak said developers could submit a new application with changes that could avoid triggering the upgrades that led to rejection. He said the RTO wants to avoid taking on the role of a design consultant engaging with a back-and-forth with the developer on what can be done to avoid network upgrades. 

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Petition Asks FERC to Potentially Claim Jurisdiction over Puerto Rico

Puerto Rican company Pluvia filed a petition with FERC in February asking the commission to find that its proposal to link the territory to the continental U.S. via grid-scale batteries on cargo ships could trigger its jurisdiction over the island (EL25-57). 

The batteries being shipped back and forth would be storage-as-transmission-only assets (SATOA), and similar projects have been proposed using railcars. The mobile storage also could ship power the other way. The firm’s filing says the technology could be used for day-to-day shipping and under emergency conditions. 

The firm filed its petition in early February, and FERC noticed it a couple of weeks later. It largely has flown under the radar, with only Public Citizen filing a “doc-less” motion to intervene before the comment period closed March 3. 

Pluvia describes itself only as “a domestic limited liability company wholly owned by citizens of the United States and organized under the laws of the commonwealth of Puerto Rico, inter alia, to produce, transmit and sell electric energy at wholesale.” Exactly who is behind the firm is unclear: Its petition was filed by one lawyer, and its incorporation documents with Puerto Rican authorities only list another lawyer. 

The state-owned Puerto Rico Electric Power Authority (PREPA) entered into contracts with Luma Energy (a subsidiary of Canadian utility Atco and Quantas Services) to run its grid in 2021, and with Genera PR (a subsidiary of the LNG firm New Fortress Energy) to run its generation in 2023. Pluvia told FERC that those deals have kept a monopoly in place, which is overall detrimental to the island’s population. 

“Public electricity monopolies have been effectively managed by other states, which have cooperated to lower costs and improve service to customers by implementing federal electric competition policy under the” Federal Power Act, Pluvia said. “The government of Puerto Rico’s administration, however, has been unsuccessful. The damage Puerto Rico’s electricity monopoly has caused is considered a human-made disaster with appalling humanitarian and economic impacts in Puerto Rico that also impact United States taxpayers.” 

The island infamously was impacted by Hurricane Maria, which in 2017 destroyed the island’s power grid and kept some of its residents without power for four weeks. 

“It’s really not done well since the hurricanes; the reliability of the system is probably about 10 times worse in terms of safety and safety metrics than the U.S. average,” Cathy Kunkel, energy consultant for the Institute for Energy Economics and Financial Analysis, said in an interview. “And the reliability has actually declined over the last year or so.” 

PREPA’s system was contracted to Luma and Genera after the hurricane, with Kunkel saying it was not sold outright because that would have put at risk federal disaster relief funds being used to shore up the grid. 

High costs and an unreliable power system have been impairments to economic growth on the island and its ability to stop people from moving to the mainland, Pluvia said in its petition. 

On top of still running a creaky grid before and after Maria ravaged PREPA’s system, the public utility has been bankrupt, which has hampered its ability to attract needed investment, Pluvia said 

“PREPA’s lack of credit creates a barrier to normal project financing for energy projects, as financing sources hesitate to bet on PREPA’s performance of its long-term contractual obligations to buy electricity in quantities and at prices stated in” power purchase agreements, Pluvia said. 

The combination of public monopoly and insolvency leads consumers and investors to a dead end, while creating the misleading appearance of an energy transition through multiple phases of bids and awards that produce contracts needing affordable financing, it added. 

While Pluvia and its backers might have run into trouble with securing contacts, Kunkel noted that major deals have been struck recently. 

“There’s definitely been long-term contracts that have been signed in the last several years,” Kunkel said. “There’s been a number of new renewable energy contracts and some battery storage contracts and a new natural gas plant contract that was signed in December.” 

Another trend since Maria has been end-use consumers’ increasing adoption of distributed solar and storage, which Kunkel said makes up about 9% of Puerto Rico’s electricity consumption. 

The issue of FERC jurisdiction over Puerto Rico’s grid has come up before, such as when Alternative Transmission filed a petition in 2023 seeking a finding from the commission that its proposed undersea cable would not trigger commission jurisdiction (EL23-14). The project and its details were a little too vague for FERC to give a firm answer, but it did discuss the jurisdictional issues and said it could forswear oversight of Puerto Rico’s grid as it has in similar cases involving ERCOT. (See FERC Weighs in on Jurisdictional Questions over Puerto Rico Project.) 

The Alternative Transmission case came up in Pluvia’s petition as it seeks to clarify that its proposal of shipping batteries back and forth by sea could trigger FERC jurisdiction over the island’s power system, which the commission said could happen with an undersea cable. 

The petition does not ask FERC to claim jurisdiction immediately, but Pluvia said it may request that in future proceedings, and it expressly reserved the right to do so. 

Puerto Rico has a version of a state regulator already called the Energy Bureau, which was set up about a decade ago to oversee PREPA. IEEFA’s Kunkel said it has helped bring some normality to the island’s regulatory structure. 

“One of the problems with PREPA … was that it really had just kind of become a very politically driven entity and was not making decisions based on best-practice, sound utility planning,” Kunkel said. “For example, it had not had a base rate case since the 1980s. One of the first things that the Energy [Bureau] did was to have a base rate case.” 

As for bringing RTO-style markets to the island, it is unclear how much benefit they would bring: Puerto Rico’s system is far smaller than any of the continental organized markets, meaning it would lack the benefits that come from centrally dispatching large amounts of generation across a wide footprint, Kunkel said. 

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Offshore Wind Development Rebound Expected — Outside US

With one notable exception, the offshore wind industry is on track for a global rebound, Rystad Energy predicts in its 2025 outlook, released March 2.

The energy research and intelligence company expects capacity additions to reach 19 GW — substantially more than the roughly 8 GW and 10 GW seen in 2024 and 2023, respectively — and expects investment to reach $80 billion.

Mainland China, the world’s largest offshore wind market, will account for more than 12 GW of the total. With South Korea and Taiwan added in, Rystad projects 74% of 2025 offshore generation capacity additions will be in Asian waters. The U.K., Germany, France and Netherlands account for the remaining 26%.

The world’s largest economy, which until very recently offered robust policy support for offshore wind development, is zeroed out in Rystad’s 2025 forecast of capacity additions.

“U.S. federal policy is creating significant global ripple effects, hindering offshore wind development, especially where a large portion of auctioned capacity lies,” Petra Manuel, Rystad’s senior offshore wind analyst, said in announcing the outlook. “President Donald Trump’s January memorandum halting new leasing and approvals on the Outer Continental Shelf, citing environmental and safety concerns, could last throughout his term, pausing new developments and creating continued uncertainty for ongoing projects.”

One U.S. offshore wind project now under construction, the 800-MW Vineyard Wind 1, could potentially have a 2025 commercial operation date, but it has experienced repeated delays.

Four other projects are in the works: Offshore and onshore construction are underway on Revolution Wind and Coastal Virginia Offshore Wind, while onshore work has begun for Sunrise Wind and Empire Wind 1.

None of the four are scheduled to be completed this year.

Trump’s Jan. 20 memorandum suspended new offshore wind leasing and directed “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases,” injecting a new degree of risk and uncertainty into an industry already struggling to build momentum in the U.S.

While China will dominate construction completion in 2025, Rystad expects that European projects will represent the bulk of final investment decisions (FIDs) made in 2025 for future construction starts — 9.5 GW in total, with Poland, Germany and the U.K. accounting for 6.9 GW. Worldwide, 2025 FIDs are expected to be about equal to those of 2024.

Another barometer of future planning is site leasing. Rystad notes that seabed areas holding a record 55 GW of potential capacity were offered at auction in 2025 outside China. But not all of that capacity found a buyer, particularly in the U.S., where two of four auctions were called off before being held and a third drew bids for only half the lease areas offered.

Rystad expects significantly less capacity to be offered at auction in 2025 — about 30 to 40 GW worldwide, which would be in line with activity seen in 2021 and 2022.

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Ontario Threatens 25% Tariff on Electricity to US

Ontario Premier Doug Ford announced March 4 that the province will enact a retaliatory 25% tariff on its electricity exports to the U.S. — or even halt them — if President Donald Trump doesn’t stand down in a burgeoning trade war. 

“Today, I am writing to every senator, every congressman and woman and the governors from New York state, Michigan and Minnesota, telling them that [if] these tariffs persist, if the Trump administration follows through on any more tariffs, we will immediately apply a 25% surcharge on the electricity we export,” Ford said from a podium emblazoned with “Canada is not for sale.” 

“We will not hesitate to shut off their power as well,” Ford told reporters at the press conference. 

According to a draft public notice of tariff  rules  posted March 3, a 25% tariff on nearly all goods from Mexico and Canada and a 10% tariff on Canadian energy went into effect at 12:01 a.m. March 4.  

Ford’s announcement was part of an unfolding Canadian response. He said it was a “tough day” for both the U.S. and Canada. 

“Canada and Ontario did not start this fight. We want to work with our American friends and allies, not against them. We said we’d never start a trade and tariff war with the U.S. But you’d better believe we’re ready to win one,” he said. 

Ford added that the U.S. leaders he has spoken to agree that Trump’s tariffs on Canada are a “massive mistake” that stand to hurt both countries. He said the two could have worked together to economically sustain one another.  

“We have no choice. We have to respond … tariff for tariff, dollar for dollar,” he said. Ford said Canadians should be prepared for a long fight and escalations, including “surcharges or outright restrictions” on the critical minerals and electricity Canada supplies to the U.S. Ford said Ontario’s tariffs would be used to help the workers affected. 

Canadian power exports to the U.S. fluctuate year to year, though the U.S. is consistently a net importer of power. In 2023, the U.S. took in 15 TWh compared to 42 TWh in 2022, according to the U.S. Energy Information Administration. The decline was brought on by an ongoing drought affecting Canadian hydropower and lower natural gas prices in the U.S.  

Ontario exports power through New York, Michigan and Minnesota. The province powers about 1.5 million homes across those states. 

During a separate and routine press conference March 4, New York Gov. Kathy Hochul said she does not think her state has a “target on our backs from Canada.”  

“Fortunately for our state, I’m good at developing positive relationships with our allies, not embarrassing them,” Hochul said. She said the western part of the state and Canada share an “incredible synergy” and that she had previous assurances from Ford that he would not harm the state.  

“Now, whether that means he can help the flow of energy that we’re already counting on to keep coming here … I’m happy to have additional conversations with him on how we can support each other during this crisis,” she said. 

In response to RTO Insider, MISO said it had more to do to understand how the U.S.’ tariffs work and did not address the prospect of Ontario’s retaliation. The MISO footprint includes Michigan and Minnesota. 

“This is a fluid situation, and it is unclear whether the U.S. import tariffs apply to imports of electricity from Canada, and it is uncertain whether or when this will be resolved. MISO has received no confirmation from federal agencies regarding the duties’ applicability to electricity or who will be responsible for paying or collecting them,” spokesperson Brandon Morris told RTO Insider. 

However, MISO noted that less than 1% of its total energy in 2024 was supplied via Canadian imports, with less than half of that hailing from Ontario. 

“For context, that amount is equivalent to approximately one power plant. MISO manages the loss of power plants like this every day to ensure reliability across our footprint,” Morris said. 

Stacey LaRouche, press secretary for Michigan Gov. Gretchen Whitmer, said the governor and her team are monitoring the situation. Whitmer has previously warned that tariffs would put jobs on both sides of the border at risk and stand to further slow supply chains and raise consumer costs. 

Minnesota Gov. Tim Walz called the tariff back-and-forth “totally avoidable.”  

“And if I had some advice on this one: President Trump can just claim victory. We’ll create an award here and award it [to] him that he won the trade war. Good for you,” Walz said during a March 4 press conference before the agricultural community of Cannon Falls, Minn. “But let us get back to the work of real economics; the growing of food; making sure that we’re innovating for the future.”   

Ford said he was encouraging his fellow premiers to follow suit with reciprocal surcharges. If any make similar announcements, ISO-NE could be included in Canada’s counteroffensive. 

“New England’s power system is connected to Quebec and New Brunswick, not Ontario, and the region’s grid is operating reliably today,” ISO-NE said in an email to RTO Insider. 

Vincent Gabrielle and Jon Lamson contributed to this report. 

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Former BPA Leaders Again Protest Workforce Cuts

IRVING, Texas — Former Bonneville Power Administration heads Randy Hardy (1991-1997) and Stephen Wright (2000-2013) have again collaborated on a public letter distributed in the Pacific Northwest about the “tremendous risk being created” in the region by workforce reductions at the federal agency.

In a letter made public March 3, which followed a previous letter in February, Hardy and Wright argued that the reductions will not realize taxpayer savings, as all BPA expenses are funded through electricity rates charged to its utility customers and passed on to retail consumers. They noted that the federal power marketing administration has already lost 14% of its workforce and a fifth of its power dispatchers, endangering the entire Northwest power grid.

“There has been no strategy to the workforce reductions such as targeting less important positions, or fencing off positions critical to ensuring public health and safety such as power dispatchers and lineworkers,” the former administrators wrote. “While BPA management is strictly limiting communication, from our experience we can presume that management is now attempting to plug round pegs into square holes and in many cases not having anywhere near enough pegs.”

“The implications of those people dropping out of the workforce without a plan just leads one to question: ‘What are the impacts going to be?’” Wright, a member of SPP’s Board of Directors, told RTO Insider as the letter was being released. “When you have people that are everything from duty schedulers, hydro schedulers to linemen, it just leaves you with a bunch of questions about, well, how are they going to manage through this? And then what implications are there for others that are impacted by their operations? They’re so interconnected, there’s a chance that that could be widespread.”

The administrators added three concerns to those expressed in their previous letter:

    • The reductions will increase outage repair times across BPA’s six-state region.
    • Employee safety will be compromised with crews stretched thin and likely requiring more overtime.
    • Geopolitical tension translates to risk of cybersecurity intrusions.

“We reemphasize that we strongly support seeking efficiency gains especially through the adoption of new technology,” Hardy and Wright wrote. “But electricity delivery, unlike many other businesses, is a function where the public reasonably expects — and public health and safety demands — round-the-clock, uninterrupted service.”

They closed their missive by asking for relief from the Department of Energy, urging a total exemption from pending reductions, lifting an existing hiring freeze, rehiring the 100 or so probationary employees already laid off, and exempting the U.S. Army Corp of Engineers and Bureau of Reclamation staff who are funded by BPA revenues.

BPA is part of DOE and provides about 28% of the Northwestern U.S.’ electricity, managing a 15,000-mile transmission network. It is one of the key potential participants in SPP’s Markets+, a day-ahead service offering. Wright serves as chair of the Interim Markets+ Independent Panel and is one of three SPP directors serving on it.

The letter was written for those in the Northwest and distributed by the Public Power Council and others. Hardy took the message to The Seattle Times.

Wright said he and Hardy are simply doing what others can’t.

“We’re putting information out right for people to be aware of,” he said. “The problem is, it’s difficult for the agencies to talk about this, and so, to some extent, we have to surmise some things. But between Randy and me, we just have enough years having been at Bonneville; we can put pieces together that it might not be easy for other people to put together.”

Wright was speaking during a break in SPP’s Energy Synergy Summit. In a separate meeting earlier that day, he asked SPP legal staff about staff reductions at FERC and the potential effect on the grid operator’s “specific issues.”

“I was asking the question because I don’t know what’s going on, but the way [job reductions] landed at Bonneville, I don’t know why it would be significantly different: … the relatively random nature in which people are choosing to resign, or the implications of probationary employees,” he said. “And by the way, ‘probationary employee’ doesn’t mean that they’re new.”

According to the U.S. government, probationary federal workers are new or reassigned employees under evaluation during a trial period, which generally lasts a year. A federal employee can become probationary with a transfer or new job within the same department.

When it was pointed out to Wright during the meeting that he is helping to raise awareness of the layoffs and their potential effect on the Northwest, he said, “This is a very active conversation in the Northwest.”

“The thing that really is bothersome about this is that it doesn’t do anything for the federal deficit,” he said.

In the letter, Wright and Hardy wrote, “Reducing BPA staff does not save U.S. taxpayers one dime.”

The former administrators are not alone in expressing their concerns over the BPA job reductions. Wright reeled off a list of several other public figures who are also speaking up: All but one of Washington state’s Democratic U.S. representatives, who wrote a letter to Energy Secretary Chris Wright (Rep. Marie Gluesenkamp Perez was the lone holdout); Energy and Commerce Committee member Rep. Kim Schrier (D-Wash.), who made a speech on the House floor; and Oregon’s U.S. senators, Ron Wyden (D) and Jeff Merkley (D), who wrote a letter to President Donald Trump. (See Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA.)

Wright said the only Pacific Northwest Republican who has spoken about the issue is U.S. Rep. Dan Newhouse (Wash.). “He did it in a newsletter to his constituents, just saying he’s concerned about the impacts on the energy and research issues. He also has a National Lab in his district,” Wright said.

Asked if the outreach to the government and stakeholders is working, Wright said, “It’s definitely getting attention. I mean, a fair amount of attention.”

Fred Heutte, senior policy associate with the Northwest Energy Coalition, agreed with the sentiments in the letter. He told RTO Insider that though NWEC disagrees with BPA on many issues, “we are absolutely committed to the idea that Bonneville must have the staff to operate the system day-to-day.”

The staffing crisis “is a direct threat to reliability,” Heutte said. He added that regional entities, such as WECC, “have a role in standing up and saying that their main focus under the [Energy Policy Act of 2005] is reliability.”

Heutte sits on WECC’s Member Advisory Committee. The organization oversees compliance with reliability standards. It also conducts resource assessments and planning functions for the Western Interconnection.

Approximately 90 million people are served in the Western Interconnection. Heutte said that WECC speaking up would send a “very important signal.”

“We want people to say, ‘If I flip the switch, the lights will go on.’ That’s a good thing, but there’s an enormous amount of work and enormous amount of vulnerability now to not having the staff sufficient to make that happen. So I hope at the appropriate time that WECC will speak up.”

When asked to comment on the letter, BPA spokesperson Doug Johnson told RTO Insider in an email that “there is nothing in the letter we feel the need to correct or expand upon.”

“WECC is aware of the personnel impacts at Bonneville Power Administration and other federal entities in the West,” Kris Raper, vice president of strategic engagement and external affairs at WECC, told RTO Insider in an email. “We will continue to monitor the situation as it develops, including collaborating and coordinating with BPA and other electric industry owners and operators in support of their role in serving customers with the essential power that they need.”

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FERC Grants Palisades Extra Time to Get Online

FERC has given the Palisades Nuclear Plant special permission to exceed MISO’s 36-month limit on generator suspensions as owner Holtec International works through the plant’s reopening. 

The commission decided Feb. 28 that Holtec can use a 22-month extension on top of the RTO’s three-year limit to bring Palisades back online (ER25-1083). 

The MISO tariff limits generation suspensions to a cumulative 36-month maximum over a five-year span. After reaching the limit, generators are expected to return to service or risk termination of interconnection service. 

Holtec told FERC that its plan to return Palisades to service was not crystalized until April 2024. Previous owner Entergy placed Palisades in suspension status with MISO in 2022. 

FERC’s leeway means Holtec now has until March 1, 2027 — instead of May 20, 2025 — to start the reactor under MISO’s rules. Holtec is navigating a recommissioning process with the Nuclear Regulatory Commission and hopes to have the plant online in October at the earliest. (See Anti-nuclear Groups Challenge Palisades Reopening.) 

Holtec argued that if it was not granted the extra time and lost its interconnection rights with MISO member Michigan Electric Transmission Co., it could result in “substantial delays or potential loss of baseload generation critically needed to support resource adequacy in the MISO region.”  

The Michigan Public Service Commission filed comments in support of the waiver. 

Holtec also said it is preparing a new generator interconnection agreement to file with MISO that will lay out expectations and associated deadlines on the path to reactivating the partly decommissioned nuclear plant. 

FERC said Holtec seemed to act in good faith and that a continuation of the Palisades suspension without terminating interconnection service would not harm any third parties. On the other hand, the commission said that disconnecting Palisades from the MISO system would “jeopardize the recommissioning timeline.”

The commission noted that, according to Holtec, Palisades’ reopen will not require network upgrades. It also said it had Holtec’s word that MISO verified the 22-month waiver would not present “reliability concerns or interconnection queue management issues.” 

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Seattle City Light, Others Urge BPA to Pause Day-ahead Decision

The Bonneville Power Administration should remain in CAISO’s Western Energy Imbalance Market (WEIM) and hold off on joining a day-ahead market, Seattle City Light and other Northwest parties urged in a letter sent to BPA CEO John Hairston days before the agency is expected to issue its draft day-ahead market decision. 

In the March 3 letter, City Light, Portland General Electric (PGE), PacifiCorp and three labor groups praised BPA for pushing for independent market governance in the West, saying the agency’s involvement in developing day-ahead markets by SPP and CAISO has resulted in important market governance reforms. 

With BPA slated to release its draft day-ahead market decision March 6, the signatories argued the “DAM decision presents a critical opportunity for BPA to acknowledge the results of its leadership on governance reform, the desire for additional progress, and the need for additional information to provide the strongest business case for a decision to join a DAM that delivers the greatest economic and reliability benefits to BPA customers.” 

The letter contended that BPA has three options: 

    • Joining SPP’s Markets+, which has independent governance but a smaller footprint with a higher risk of market seams and “great efficiency challenges for itself and the region.”
    • Participating in CAISO’s Extended Day Ahead Market (EDAM), “a market within CAISO governance but with a larger footprint and momentum and progress towards independent governance.”
    • Joining neither market and continuing to participate in the WEIM. 

When asked to comment on the letter, BPA spokesperson Doug Johnson told RTO Insider in an email that the agency “has no plans to alter its current timetable for the day-ahead market decision.” 

BPA staff previously recommended Markets+ largely because of the market option’s independent governance design. Dawn Lindell, CEO of City Light, argued in a November letter that BPA’s Markets+ leaning was “alarming,” saying the agency ignored studies showing the economic benefits of EDAM. (See Rising Tensions Evident at BPA Day-ahead Markets Workshop and Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.) 

A municipal utility, City Light is the largest entity in BPA’s “preference” customer base of publicly owned utilities.  

In January, Hairston tamped down expectations that BPA is all in on SPP’s Markets+. (See In Letter to Senators, BPA Tempers Markets+ Leaning.) 

In the March 3 letter, City Light and the other signatories again pointed to the studies to argue that EDAM could provide significant benefits and that joining Markets+ would be costly. 

Additionally, “BPA’s own analysis through the Western Markets Exploratory Group (WMEG) shows double the benefits for BPA when choosing to remain in the WEIM with current market commitments compared to participation in Markets+ ($398 million v. $203 million),” the letter stated. 

BPA’s March 6 deadline also ignores recent steps taken to create a new independent regional organization that will assume governance over CAISO’s markets, according to the letter. 

California state lawmakers on Feb. 20 introduced a bill that sets the conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent regional organization. (See Pathways ‘Step 2’ Bill Introduced in Calif. Legislature.) 

In asking BPA to postpone its day-ahead market decision, the letter also took note of the need for more information and recent staffing challenges brought by the Trump administration. (See 2 Top BPA Execs to Depart; Army Corps of Engineers also Faces Massive Cutbacks) 

“[W]e ask that BPA choose to remain in the WEIM for the foreseeable future and not commit to join a day-ahead market at this time,” the letter stated. “This would allow BPA to explore mechanisms to better monetize its participation in WEIM, while continuing to lead on governance reform as it considers future DAM opportunities. Additionally, it would delay the creation of an unavoidable, not easily managed or reversible, seam and maintain the coordination in the West that is critical to keep the lights on and costs down.” 

Another notable aspect of the letter: It was signed by three International Brotherhood of Electrical Workers locals representing workers at City Light, BPA and Tacoma Power, marking the first time any of those unions have taken a position on the day-ahead markets issue. IBEW 125 in Portland, Ore., represents workers at PGE and PacifiCorp, in addition to BPA. 

Tacoma Power last month became the second Northwest entity to commit to joining Markets+. (See Tacoma Power to Join SPP’s Markets+.) 

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ISO-NE Braces for Tariffs on Canadian Electricity

In preparation for potential fees on electricity imports from Canada, ISO-NE requested authorization from FERC on Feb. 28 to collect import duties while simultaneously arguing that the RTO “is not the appropriate entity” to do so (ER25-1445).

The Trump administration’s monthlong pause of the tariffs on Canadian goods, which include a 10% fee on energy imports, expires March 4.

Vague language in the original executive order, coupled with limited communication from the administration, has created significant uncertainty regarding what is included in the energy carveout, how the tariffs will be applied and whether the tariffs apply to electricity. (See Uncertainty Remains Around Energy Tariffs amid Last-minute Deals.)

Along with the 10% energy tariff, President Donald Trump on Feb. 1 imposed tariffs of 25% on all other imports from Canada, as well as those from Mexico.

At a press conference March 3, Trump said the tariffs will proceed, with “no room left for Mexico or for Canada” to avoid them.

ISO-NE has argued that the tariffs “do not appear to apply to electricity and that, even if they do, ISO New England would not be responsible implementing them.”

The RTO noted that the definition referenced by the February order on Canadian imports does not explicitly include electricity. It defines energy or energy resources as “crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water and critical minerals.”

ISO-NE also pointed to statements from the U.S. International Trade Commission indicating that electricity is exempt from U.S. tariff laws.

The RTO’s proposal is intended to protect it if the administration does in fact determine it is responsible for the tariffs, which would pose a “significant financial risk to the ISO” if it does not have the means to collect the fees, it said.

It noted that the “failure to have a cost-recovery mechanism in place prior to the effective date of a Canadian import tariff would place the ISO at risk of noncompliance with a federal obligation and, in a worst-case scenario, could force the ISO to seek bankruptcy protection.”

If it is unable to pay the duties, the federal government could direct the RTO to suspend imports, which could create “precipitous, adverse consequences” for grid reliability, ISO-NE wrote.

It estimated that a 10% tariff on electricity imports would cost the region about $66 million annually, while a 25% tariff would cost the region about $165 million annually. The RTO noted that Canadian imports have covered about 11% of the region’s load over the past five years.

Imports are poised to increase when the New England Clean Energy Connect (NECEC) transmission line comes online, likely by early 2026. The NECEC project includes a long-term contract for the supply of baseload power from Québec to Massachusetts. Hydro-Québec has said it is monitoring the potential effects of the tariffs on its long-term contracts.

To prevent potential fallout for the New England market, ISO-NE proposes a “temporary mechanism” enabling it to collect the tariffs. In the absence of direction from the administration regarding which entities ISO-NE should collect the duties from, the RTO would charge the fees “to the entities selling the assessed electricity into the ISO-administered market.”

If the federal government provides more specific information around the responsible entities, ISO-NE would alert its market participants and adopt the requirements, the RTO noted.

The proposal will only take effect if the Trump administration determines ISO-NE is responsible for the tariffs. If the temporary mechanism does take effect, the RTO said it would work with stakeholders to create a “cost-collection mechanism that is specific to the terms and conditions of the import tariff and resulting imposed import duties.” The RTO would be required to file the final mechanism within 120 days of the date the temporary mechanism takes effect.

ISO-NE said its proposal is intended to apply to any other future import duties imposed by the federal government on electricity. The Trump administration has said it may increase the tariffs if Canada retaliates with its own duties on U.S. goods.

Ontario Premier Doug Ford on March 3 said he is prepared to cut off electricity exports to the U.S. “with a smile on my face” if the tariffs go into effect.

“They rely on our energy. They need to feel the pain. They want to come at us hard; we’re going to come back twice as hard,” Ford said.

The RTO requested an expedited review of its order, asking FERC to rule on its filing by the end of March and accept a March 1 effective date for the proposal. It also asked for a shortened comment period ending March 10.

ISO-NE’s filing mirrored a proposal submitted by NYISO on the same date. NYISO also argued that the executive order does not appear to apply to electricity but asked FERC to authorize it to collect tariffs if required to do so by the administration. (See NYISO Preparing to Collect Duties on Canadian Electricity Imports.)

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ACORE Panel: Did Loper Bright Really Overturn Chevron?

WASHINGTON ― The headlines in the wake of the U.S. Supreme Court decision in Loper Bright Enterprises vs. Raimondo were unequivocal: The Chevon doctrine had been overturned, ending court deference to federal agency expertise in interpreting vague or ambiguous legal statutes. 

Well, maybe not, according to David Hill, executive vice president for energy at the Bipartisan Policy Center. “It’s absolutely true, Chevron was overruled,” Hill said during a panel on the changing legal landscape under the Trump administration during the second day of the American Council on Renewable Energy’s Policy Forum on Feb. 27. “But it’s worth actually thinking about what was the Chevron decision, and what were the courts and the agencies actually doing … and what did the court in Loper Bright … actually say?” 

Hill and others on the panel spent an hour trying to untangle the legalities, or lack thereof, in the onslaught of executive orders and actions unleashed in the six weeks since President Donald Trump was inaugurated, along with the impact of major court decisions like Loper Bright. 

Going back to the original Chevron doctrine, Hill said, the decision to defer to agency expertise in interpreting a statute was supposed to be a two-step process in which the courts first had to determine whether a statute was ambiguous or “clear on its face.” Part of the problem with Chevron was how it was applied, he said. 

“The courts would be all over the board with it. There were judges in individual cases that would disagree about whether or not a statute was clear or ambiguous,” Hill said, which complicated the second step of deciding whether an agency’s interpretation should be deferred to.  

Once again, the courts decided if an agency’s interpretation was permissible and reasonable. Under Loper Bright, courts no longer can give “binding deference” to agencies, he said. What they can do is “give the agency very great respect, due respect. They can consider it highly persuasive, especially informative, [give it] most respectful consideration, great weight. So, what’s the difference between that and some pretty great amounts of deference?” 

As the lower courts ruled on how to apply deference under Chevron, they also likely will “decide how much Loper Bright actually changed the real law,” Hill said. “Now they can’t say … ‘we’re just stuck with what the agency said,’ but they can give a lot of weight to what the agencies did, and I think they will on some of the really technical, statutory interpretations.” 

Cary Coglianese, director of the Penn Program on Regulation at the University of Pennsylvania’s Carey Law School, generally agreed with Hill’s interpretation of Loper Bright, but said the ruling likely would have symbolic impacts. Beyond the court overturning a 40-year-old precedent, “you have to also think about Loper Bright in the context of a larger Supreme Court that’s deeply skeptical of administrative power,” he said. 

Coglianese pointed to other recent cases, such as West Virginia vs. EPA, which raised the “major question doctrine demanding greater clarity whenever agencies are to use statutes to do something important, like regulating to protect against climate change.” 

Future cases may be “a little less about how Loper Bright is actually written and what it says, but more [about] what it actually means to be part of a larger, shifting legal landscape,” he said. “And quite frankly, we can’t discount at all the administrative and political landscape that’s shifting as well.” 

Is the Endangerment Finding Safe?

Speaking from the legislative side, Ana Unruh Cohen, Democratic staff director for the House Natural Resources Committee, said individual lawmakers “always aspire to write a very clear and direct … piece of legislation, and then things get negotiated; things change.”  

Certainly, as representatives move new bills, they are focused on ensuring their language is clear, Unruh Cohen said. Similarly, Hill said, agency staff writing regulations will have to think carefully about building a well-argued paper trail to validate their interpretation of statutes without relying on Chevron.  

Could Loper Bright also be used to advance further deregulation, such as a rollback of EPA’s 2009 endangerment finding, which allowed the agency to regulate greenhouse gas emissions under the Clean Air Act? 

Unruh Cohen noted that the Supreme Court has not overturned the endangerment finding in the past, even when it had the opportunity to do so, but Coglianese again pointed to the shifting legal and administrative landscape. “Maybe this current Supreme Court would be willing,” he said. “If they’re willing to go back and overrule Chevron, if they’re willing to go back and overrule Roe v. Wade,” is the endangerment finding really safe? 

“Maybe they would be happy to say, yeah … we now accept that EPA under the Trump administration has a better reading of the Clean Air Act that says it never authorized regulating greenhouse gas emissions.” 

Coglianese and Unruh Cohen both expect that any approach to overturning the endangerment finding would have to be done on statutory grounds rather than a full-on attack on climate science. Congressional Republicans have shifted their approach from one that questions climate science itself to one that asks which policies can best address the issue, Unruh Cohen said. 

Coming at it from a statutory perspective starts from the “question of whether we have the statutory authority in the first place to do this,” Coglianese said. “Then, quite frankly, none of that technical information really matters.” 

Coglianese also laid out the statutory and constitutional issues related to Trump’s funding pause. “One has to ask the people who are issuing these directives, do they have statutory authority? Second, are they acting in a manner that is not arbitrary? … 

“Then there’s these constitutional questions about whether it’s consistent with our separation of powers. Whether it’s consistent with the spending clause of the United States Constitution for the executive branch on its own to simply decide what we want to spend money on or not, even though Congress has approved and told the administration to carry out the spending.” 

The catch, he said, is the pacing and timing problem: “Those who control the computers are able to block funding, and there’s not a lot of transparency around that. The courts are being much more deliberative and trying to figure out what’s going on.” 

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FERC Approves $420K in Penalties for RF Utilities

FERC has approved a $380,000 penalty leveled against American Electric Power (AEP) by ReliabilityFirst for violating NERC’s reliability standards for relay trip limits, along with a separate $40,000 penalty against the Lansing Board of Water and Light (BWL) for infringing on NERC’s facility rating standard. 

The commission announced in a Feb. 28 filing that it would not further review the settlements between RF and the two utilities, filed by NERC on Jan. 30. FERC also indicated it would approve two other settlements involving violations of NERC’s Critical Infrastructure Protection standards. Details of these infractions, including the utilities and regional entities involved, were not made public in keeping with commission policy on CIP violations. 

According to the AEP settlement, the utility notified RF of its violation in June 2021 via a self-report (NP25-7). AEP told the RE that it had identified a potential noncompliance with PRC-023-4 (Transmission relay loadability) involving a relay on the Nagel-Phipps Bend 500-kV circuit. 

Requirement R1 of the standard lays out the criteria that utilities must use to ensure its circuit terminals do not “prevent [their] phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the” grid.  

Entities may choose one of 13 criteria to implement. Criterion 1 requires entities to “set transmission line relays so that they do not operate at or below 150% of the circuit’s highest seasonal facility rating” for a defined loading duration as close as possible to four hours.  

The relay in question went into service Dec. 27, 2019. RF said AEP didn’t know at the time that an engineer had listed the phase time overcurrent (TOC) setting for the relay in AEP’s settings workbook incorrectly, the result of the worker misreading an “engineering template default setting [that] limited the loadability of the line.” During a “storm and period of high load” on Feb. 16, 2021, the relay tripped and caused a misoperation on the Nagel-Phipps Bend circuit. 

RF said the values communicated to AEP’s transmission planning personnel for the relay’s summer normal and emergency ratings were 3,609 MVA, while the communicated winter normal and emergency ratings were 4,473 MVA. However, the actual ratings in all cases were 396 MVA. AEP performed an extent of condition review and did not discover any further PRC-023-4 noncompliance. 

The RE said the root cause of the noncompliance was the engineer placing the wrong settings into service. This error itself was due to confusion created by the relay-setting software. The software created a new folder every time a setting was changed, while keeping the original, unaltered settings in a separate folder called the working folder. The engineer used the settings from the working folder instead of the new folder. 

RF noted that AEP also lacked sufficient internal controls for validating relay settings. While the utility performs a peer review before settings are placed in service, and the correct settings were reviewed in this case, the problem arose after the review when the engineer mistakenly input the settings from the wrong folder. 

The RE assessed the risk posed by the violation as “serious and substantial,” observing that “improperly setting relays for transmission system components can prematurely trip these components out of service, limiting system operator flexibility and their ability to take controlled actions,” and “the worst-case scenario (a tripped relay that caused a misoperation) actually occurred during a storm and period of high load.” 

AEP’s mitigating actions — which the utility completed on Sept. 23, 2021 — include: 

    • Correcting the relay settings the day of the misoperation. 
    • Working with the settings software vendor to improve the confusing folder setup. 
    • Reviewing all relays with default settings enabled for the relevant areas. 
    • Introducing an automated relay settings tool to minimize human error when calculating settings. 
    • Checking similar protective relay settings for other instances in which the phase TOC was enabled incorrectly. 

Lansing BWL Settles for Ratings Errors

BWL’s settlement with RF stemmed from violations of FAC-008-3 (Facility ratings). It was the only settlement submitted in NERC’s monthly spreadsheet notice of penalty (NP25-8). Unlike AEP’s infringement, this violation was discovered by the RE during a compliance audit Dec. 11, 2020. 

RF determined that BWL had failed to “establish facility ratings consistent with its facility ratings methodology (FRM),” as required by requirement R6 of the standard — and requirement R1 of FAC-009-1 (Establish and communicate facility ratings), the standard in effect when the violation began.  

Under BWL’s FRM, all transmission lines and their vertical clearance should be capable of operating safely at 160 degrees Celsius. However, BWL only could demonstrate a safe operating temperature of 100 degrees C. RF attributed this discrepancy to a software issue. 

BWL updated its FRM to reflect the lower safe operating temperature and to “more clearly account for sag limited ratings.” After these changes, the utility still had to remediate thermal rating inconsistencies at two transmission lines, which it did by assigning both lines a higher sag limited rating. 

RF said the root cause of the issues was “multifaceted”; the incorrect software setting was due to inadequate verification controls, while the derates related to the thermal violations occurred because BWL’s procedures did not account for the “particular attributes” of field conditions around the two lines. Violations dated back to 2011, when the utility registered as a transmission owner and was required to comply with FAC-009-1, and ended on March 8, 2024, when BWL updated its FRM and completed remediation on the last line. 

The RE said the violation posed a moderate risk to grid reliability, due in part to the duration of the violation and the size of the derates on the two lines (39% and 83%). But RF also called the risk not serious because the company never operated the affected lines within 10% of the corrected facility ratings and no harm is known to have occurred.