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February 11, 2025

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Georgia Power Proposes Nuclear Uprate, Delay in Fossil Retirement

Georgia Power’s 2025 Integrated Resource Plan proposes to uprate four of its nuclear reactors, upgrade a natural gas plant and push back some coal and gas retirements. 

Georgia’s largest electric utility said the moves are driven by anticipated demand. It expects 8.2 GW of load growth through the end of 2030 — 2.2 GW more than it projected in its 2023 IRP Update. 

Environmental advocates were disappointed by some aspects of the plan, particularly the operating extensions of what Georgia Power called some of the most advanced coal-fired units in the world. 

In its Public Service Commission filing (Docket 56002), Georgia Power proposes to address both power demand and supply in its new IRP. It also lays out a 10-year plan to upgrade more than 1,000 miles of transmission lines. 

Nuclear is one of the smaller components on the supply side of the strategy. 

Georgia Power proposes to increase the thermal output of its Hatch 1 and 2 and Vogtle 1 and 2 reactors to extract a 112-MW increase in capacity from them as soon as late 2028 or early 2029. The four units began commercial operation 36 to 49 years ago. 

Proposed upgrades to 10 gas units at Plant McIntosh are projected to yield 268 MW of incremental capacity as early as late 2027. 

Investments in nine existing hydroelectric facilities would preserve 665 MW of capacity. 

The 2025 IRP also proposes keeping three coal-fired units at Plant Scherer; an oil-burning unit at Plant Gaston; and four gas units with coal-fired backup at Plant Gaston in operation through 2034 to 2038. This would preserve 1 GW of capacity and is a change from the 2022 IRP, which called for their retirement in 2027 and 2028.  

Georgia has seen an uptick in manufacturing development in the past four years, and the Census Bureau estimates its population jumped 4.4% from 2020 to 2024, compared with 2.6% nationwide. 

Georgia Power CEO Kim Greene alluded to this in a Jan. 31 news release: “The 2025 IRP provides a comprehensive plan to support Georgia’s continued economic growth and serve Georgians with clean, safe, reliable and affordable energy well into the future.” 

Some of that economic growth has been in the clean energy sector, boosted by funding during the Biden administration. Environmental activists saw irony in Georgia Power’s proposal to burn more fossil fuel to power these new facilities. 

“We’re the number one state to do business and one of the U.S.’s fastest-growing tech hubs. Are we really going to power progress with gas and coal?” Southern Environmental Law Center attorney Jennifer Whitfield asked in a news release. “Coal hasn’t been economic for years, and paying for even more methane gas is incompatible with the future Georgians want and businesses are demanding.” 

At the two-year anniversary of the Inflation Reduction Act, nonpartisan business group E2 calculated that Georgia had fared second-best among the states under the IRA: 28 major clean energy or clean vehicle projects carrying an estimated $15.3 billion investment that would create an estimated 15,723 jobs. 

Georgia Power predicts the largest components of its summer 2025 generation capacity mix will be 44% gas, 16% coal, 14% solar/storage and 12% nuclear. Its actual energy mix for 2024 was 40% gas, 29% nuclear, 16% coal and 6% solar. In total, 38% of the energy was carbon-free. 

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LS Power Files Complaint Against MISO over Indiana ROFR

Competitive transmission developer LS Power has lodged a complaint against MISO for treating Indiana’s right of first refusal law as if it’s in effect when it’s under a preliminary injunction, arguing it’s being denied the chance to bid on a share of more than $1 billion in proposed transmission.

LS Power alleged in a Feb. 4 complaint that MISO is violating its tariff by playing by the state’s ROFR law even though the U.S. District Court for the Southern District of Indiana has temporarily forbidden its enforcement (EL25-55).

LS Power said MISO erroneously considers a preliminary injunction of the ROFR to not affect the law’s status but agrees a permanent ban would render the law irrelevant. The company said MISO’s interpretation of its tariff defies established law that “a preliminary injunction has all of the force of a permanent injunction during its period of effectiveness.”

LS Power asked FERC to act quickly to force MISO to respect injunctions regardless of whether they’re preliminary or permanent.

“MISO’s position that only a permanent injunction — not a preliminary injunction — renders a law ‘[ina]pplicable’ is flatly wrong and would cause chaos if applied across all tariff references to ‘applicable laws,’” the developer argued.

In December, a federal judge for the Southern District of Indiana blocked Indiana’s right of first refusal law, benefiting incumbent utilities, which had been in effect for roughly a year and a half. (See New Law Expands Indiana ROFR Law for Transmission Buildout.) LS Power sued the Indiana Utility Regulatory Commission, arguing the state violated the Commerce Clause by treating in-state developers differently than out-of-state developers.

At the time, Chief Judge Tanya Walton Pratt agreed the ROFR “erects a barrier to the interstate electric transmission market by limiting who can compete for new construction projects in Indiana.”

The decision immobilized Indiana’s ROFR law five days before MISO approved its $21.8 billion long-range transmission plan (LRTP) for MISO Midwest. (See “Indiana ROFR Reversal Complicates Project Assignment,” MISO Board Endorses $21.8B Long-range Transmission Plan.)

The 7th U.S. Circuit Court of Appeals on Jan. 12 continued the lower court’s injunction after a monthlong stay; the court has yet to issue a final ruling on whether the district court was correct to issue the injunction. Meanwhile, district court litigation continues.

MISO on Jan. 31 issued the LRTP portfolio’s first request for proposals, soliciting bids for the Kentucky portion of a 345-kV transmission line that crosses the Ohio River into Indiana. The RTO excluded the Indiana portion of the project from competition.

In its complaint, LS Power said MISO withholding the second half of the project from competition denies ratepayers the “potential efficiencies of a single developer addressing the entire set of new 345-kV facilities.”

“Incumbent transmission owners have indicated that they plan to move quickly to advance the projects excluded from competition, which will result in spending ratepayer money while confusing landowners and others in the path of these largely greenfield additions if the projects are ultimately declared competitive,” LS Power said.

LS Power said it and its subsidiaries are “directly and substantially harmed by MISO’s tariff violation because MISO relied on its view that it could ignore the preliminary injunction to exclude over $1 billion in proposed transmission additions in Indiana from the tariff’s required competitive transmission process.”

LS Power said from what it can tell, MISO has not assigned Indiana projects from the second LRTP yet. The company said if MISO designates projects while the preliminary injunction is in place, those assignments would be invalid.

MISO previously estimated that about $7 billion of the $21.8 billion portfolio will be opened to competitive bidding. That figure does not account for the injunction against Indiana’s right of first refusal law.

At a Feb. 5 Advisory Committee meeting, MISO counsel Jacob Krause said MISO is aware of LS Power’s complaint over its interpretation of the law. He did not elaborate on MISO’s stance.

“The Indiana ROFR law is not in effect today,” LS Power’s Sharon Segner told MISO membership at the meeting. “If a preliminary injunction is in effect, it means the Indiana law is not in effect.”

LS Power added that it was not looking for FERC to wade into arguments concerning the legitimacy of ROFR laws or Commerce Clause issues. It said it simply was requesting that FERC weigh MISO’s obligation to comply with applicable laws and regulations, per its tariff. LS Power warned that MISO’s view that a law remains in force even when it’s subjected to preliminary injunction could create “chaos” in other areas, like MISO’s generator interconnection procedures.

“After all, consistency of tariff application requires that MISO approach the impact of preliminary injunctions the same across all tariff references to applicable laws and regulations, not solely state incumbent preference laws,” LS Power wrote. However, LS Power added that a FERC resolution of MISO’s tariff interpretation may impact the 7th Circuit and the district court’s proceedings.

MISO planners previously said in public meetings that the RTO is indifferent as to which companies build LRTP lines but wants them finished in a timely manner.

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Arizona Electric Utilities Team Up to Pursue Nuclear

Arizona’s three largest electric utilities are jointly exploring the possibility of adding nuclear generation. 

Arizona Public Service (APS), Salt River Project (SRP) and Tucson Electric Power (TEP) announced Feb. 5 they are starting the process now because the time frame to develop such projects would be lengthy. 

The utilities could use the small modular reactor technology that is advancing along multiple development pathways, or they could use larger-scale reactors. Potential sites could include coal-burning plants that will be retired. 

The utilities are seeking a grant through the U.S. Department of Energy’s Generation III+ Small Modular Reactor Program, a Biden-era funding stream that promised up to $900 million to support initial construction of next-generation nuclear technologies. 

The application window closed Jan. 17, three days before the inauguration of a president who promised a close review of and sweeping changes to his predecessor’s spending priorities. 

As of Feb. 5, a webpage for the grant program (which was launched by DOE’s Office of Clean Energy Demonstrations and the Office of Nuclear Energy) was still live on DOE’s website. 

APS, SRP and TEP said the grant would support a three-year site selection process and, possibly, preparation of an early site plan application to the U.S. Nuclear Regulatory Commission. 

The three utilities called the grant application an initial step in a larger collaborative effort to explore new nuclear generation in Arizona. 

They said a preferred site would not be identified until the late 2020s, at the earliest, and if additional nuclear capacity was developed, it might be expected to come online in the early 2040s. 

APS operates the only nuclear plant in Arizona — the three-reactor Palo Verde Generating Station. The 4-GW facility claimed the title of largest nameplate capacity in the nation for a quarter century but was surpassed by Georgia Power’s Plant Vogtle in 2024, when its fourth unit entered commercial operation. 

APS President Ted Geisler said in a news release that the timeline for nuclear expansion stretches well into the future. 

“Energy demand in Arizona is increasing rapidly,” he said. “To ensure a reliable and affordable electric supply for our customers, we are committed to maintaining a diverse energy mix. While new nuclear generation would take more than a decade to develop, the planning and exploration of options must begin now. We are partnering with neighboring utilities to assess the feasibility of new nuclear generation, alongside other resources, to meet the state’s growing energy needs.”

The Energy Information Administration notes that Arizona has among the lowest per-capita rates of energy use among the U.S. states, thanks to its mild winters and percentage of seasonal residences. But it also is among the fastest-growing states, with its population increasing 11.9% between the 2010 and 2020 Census counts. 

EIA reports that in 2023, natural gas was the dominant resource for in-state electricity generation in Arizona, at 46%. Nuclear was second at 27%, followed by coal and solar (10% each), hydro (5%) and wind (1%). 

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Wash. Governor Orders Study to Explore Data Center Impact

Washington Gov. Bob Ferguson (D) signed an executive order Feb. 3 to explore the impact of data center growth on the Evergreen State, in a move that comes as the Northwest grapples with the mounting challenges and opportunities the centers could bring.

The order specifically establishes a workgroup that will publish a report by Dec. 1, 2025, to “recommend policies and actions for addressing energy use and impacts on the economy and job market,” according to a news release.

The group will include representatives from Washington’s Department of Commerce, the Utilities and Transportation Commission, the Department of Ecology, electric utilities, environmental advocacy groups, labor organizations and industry stakeholders, according to the release.

“We must ensure Washington remains a leader in technology and sustainability — these experts will help us do that,” Ferguson said in a statement. “This group will help us balance industry growth, tax revenue needs, energy constraints and sustainability.”

Fred Heutte, a senior policy analyst at the Northwest Energy Coalition, welcomed Ferguson’s initiative, telling RTO Insider that other Northwest states should launch their own studies in collaboration with their neighbors.

“The new data center development is already posing major and rapid increases in our local, state and regional electricity use,” Heutte said.

Ferguson’s order follows a report published by WECC forecasting “staggering” growth in electricity demand in the Western Interconnection over the next decade.

Washington Gov. Bob Ferguson | Washington state government

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

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

Heutte said it’s important the Washington workgroup get input from local communities and tribes that have data centers nearby. The question of cost allocation is similarly crucial, he said, especially if data centers don’t fully cover costs related to their use or if utilities will not pay for new equipment and energy supplies.

“There is a risk that significant cost shifting could happen for all other power customers at a time when a lot of people are having … trouble with high bills, energy burden, struggling to pay their bills,” Heutte said.

Heutte also argued the workgroup should focus on grid flexibility and ensuring that companies behind the data centers work with the community.

“We want them to be good community partners, continue to support and expand clean energy, reliability and affordable energy costs for everyone,” Heutte said.

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Neo-Nazi Convicted in Baltimore Grid Attack Conspiracy

A federal jury has convicted neo-Nazi leader Brandon Russell of planning to attack electric substations in Baltimore in hopes of sparking a cascading failure that would “completely destroy [the] whole city.” 

Russell was found guilty of conspiracy to damage an energy facility after a six-day trial. The jury’s verdict form was filed Feb. 4, according to court records, although a statement from the U.S. Department of Justice said the verdict was returned Feb. 3.  

Russell was charged in February 2023 along with his accomplice, Sarah Beth Clendaniel. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)  

Clendaniel pleaded guilty to the conspiracy charge and being a felon in possession of a firearm in September 2024 and was sentenced to concurrently serve 18 years for conspiracy and 15 years for the firearm charge, plus three years of supervised release for the latter charge. The conspiracy conviction also includes a lifetime of supervised release for Clendaniel after her prison term. 

Brandon Russell | Pinellas County Sheriff’s Office

Russell — the founder of Atomwaffen Division, which DOJ considers a “racially or ethnically motivated violent extremist” group inspired by Nazi beliefs — first became acquainted with Clendaniel in 2018 while both were incarcerated at separate facilities, according to the criminal complaint. Russell, a resident of Orlando, Fla., was in prison for possessing explosive material that he intended to use to attack electric infrastructure in his home state. 

Prosecutors said the two began actively conspiring no later than November 2022, working with a third person who was an informant for the FBI. Clendaniel identified five substations she planned to target, all operated by Baltimore Gas and Electric, a subsidiary of Exelon.  

She and Russell hoped to cause “a significant interruption and impairment of the … regional power grid,” DOJ said. The department calculated that the monetary loss from their planned attacks “would have exceeded $75 million.” 

Russell compared the planned attack to the rifle attacks in Moore County, N.C., when unknown perpetrators damaged two Duke Energy substations and caused more than 54,000 customers to lose power, DOJ said. (See Duke Completes Power Restoration After NC Substation Attack.) Clendaniel hoped that the cascading failure resulting from the destruction of the substations “would be legendary” and “completely destroy” Baltimore. 

“Today’s verdict reinforces [that] there is no tolerance for those who seek to harm our communities and use violence to further hate-filled beliefs,” FBI Special Agent William DelBagno said in the DOJ statement. “I am proud of the tremendous work by FBI Baltimore’s Joint Terrorism Task Force which led this investigation.” 

Russell’s sentencing date has not been scheduled. He faces a maximum sentence of 20 years in prison. 

Electric utilities have become increasingly concerned about defending their facilities from violence as the incidence of attacks has risen in recent years. 

A common thread is politically motivated assaults on power stations. FBI agents arrested a 24-year-old from Tennessee in November 2024 for plotting to rig a drone with explosives and fly it into a substation near Nashville to disrupt power, cause civil unrest and spark a civil war; the defendant in that case also claimed ties to Atomwaffen. (See Feds Accuse Tenn. Man of Substation Attack Plot.)  

Similarly, three men with neo-Nazi associations pleaded guilty in 2022 to conspiring to damage substations with rifles after being arrested in Ohio. The men admitted they planned to damage the grid in order to cause racial unrest and were sentenced to 12, 60 and 92 months in prison. 

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North American Trade War Averted as Canada, Mexico Strike Deals

President Donald Trump has, at least temporarily, pulled back from starting a trade war with Canada and Mexico, issuing updated executive orders delaying the imposition of tariffs on both until March so additional talks on fentanyl, immigration and other trade issues can continue. 

Trump had threatened over the weekend to impose 25% tariffs on most imports from the two countries and a 10% tariff on energy imports from Canada. (See Uncertainty Remains Around Energy Tariffs amid Last-minute Deals.) 

“The challenges at our southern border are foremost in the public consciousness, but our northern border is not exempt from these issues,” Trump said in an executive order. “Criminal networks are implicated in human trafficking and smuggling operations, enabling unvetted illegal migration across our northern border. There is also a growing presence of Mexican cartels operating fentanyl and nitazene synthesis labs in Canada.” 

Both Canadian Prime Minister Justin Trudeau and Mexican President Claudia Sheinbaum Pardo struck deals with Trump on Feb. 3 that averted the tariffs for another month at least, with another pair of executive orders issued delaying them until March 4. 

“I firmly believe that collaboration is what makes this continent great, and it is what will enable our conversation to move from one about tariffs, which in my mind is a lose-lose conversation, to one about prosperity and security, which offers a win-win,” Canadian Energy and Natural Resources Minister Jonathan Wilkinson said in remarks to the Atlantic Council on Feb. 4. 

Wilkinson is a member of the current governing Liberal Party. Trudeau announced plans to step down in early January, which likely will lead to a new election in the coming months. According to the average of polls from the Canadian Broadcasting Corp., the Conservative Party is likely to return to power for the first time in 12 years. 

While Wilkinson discussed the longstanding partnership the U.S. and Canada have had, he noted that Trump’s tariff threats generated a patriotic response. 

“When all of a sudden Canada is treated more like an adversary than a partner, it did shake every Canadian, and I think you saw that in some of the patriotic expressions that came out in the aftermath of the decision to impose tariffs,” Wilkinson said. 

The movement of drugs and illegal immigration are smaller issues along the Canadian border than that of Mexico, but Wilkinson said his government is just as opposed to illegal smuggling and border crossings as the U.S. government. Canada recently announced an investment of $1 billion in border security, and Trudeau said he would appoint a “fentanyl czar” and list drug cartels as terrorists to work with the Trump administration, Wilkinson said. 

“Our respective economies are so integrated that I would say the partnership is effectively hard-wired,” Wilkinson said. “Nearly $2.7 billion worth of goods and services cross the border each day in 2023. Thirty-six U.S. states rely on Canada as their No. 1 export market. Canadian consumers and businesses purchased more goods from the United States than China, Japan and Germany combined.” 

The two economies are so intertwined that in the auto industry, parts will go back and forth across the border half a dozen times or more before a product is completed, he added. 

“But there is no area where the integrated nature of our economies is clearer than in energy and key resources, such as critical minerals,” Wilkinson said. “For example, Canada supplies significant quantities of low-cost hydroelectricity to several U.S. states via fixed transmission lines. Canadian electricity powers the equivalent of 6 million American homes.” 

In general, Canadian provinces are more economically linked, with energy and other sectors, to their neighboring U.S. states than they are to each other, Brattle Group Principal Johannes Pfeifenberger said in an interview. 

“British Columbia and Quebec, in particular, have vast amount of hydropower and hydro storage,” Pfeifenberger said. “So, in some ways, British Columbia would be the ideal battery for the West, and Quebec would be the ideal battery for the Northeast.” 

Excess renewables from the U.S. could be shipped up to Canada when that makes sense, and then the Canadian firms would sell it back south when American power demand is higher, he added. 

Wilkinson ran off other beneficial trading arrangements, from U.S. farmers importing potash, to the two countries working together on uranium supply so that the next generation of small modular reactors does not need to rely on supplies from more antagonistic countries like Russia. 

“I am suggesting that we should instead build upon current success by developing a U.S.-Canada alliance in energy and minerals,” he said. “Such an alliance would enable the United States and Canada to achieve our shared vision for affordable energy bills for families, strong and secure economies and North America as the world’s dominant energy supplier.” 

Electricity trading is a bigger deal between Canada and the U.S. than is trade with Mexico, where a few connections with Arizona, California and Texas are smaller and used less often, Pfefeinberger said. 

Kinetic Movement of Flowing Water

It is unclear whether trades in electricity will be covered by the laws that Trump’s executive orders cite, but he did single out electric generation and its fuels, including “the kinetic movement of flowing water,” in the order declaring a National Energy Emergency. The order imposing a 10% tariff on Canadian energy cited the energy emergency order. (See What is and isn’t in Trump’s National Energy Emergency Order.) 

Energy economist Robert McCullough, who has worked around hydroelectricity issues for decades, has an archive with 150 million files from the industry. None of them referenced the “kinetic movement of flowing water,” he said. A Google search of the phrase returns an “Energy 101” explainer video that the Department of Energy posted almost two years ago. 

“I think what we’re seeing is a bluff, and that this will fade away,” McCullough said. “But we do know that if it’s serious, they certainly didn’t prepare the paperwork seriously. The kindest word for it is that it’s ‘muddled.’ Now we are going to see a Federal Register notice, and hopefully that’ll be more operational.” 

If the talks for the next month or more between Canada and the U.S. are serious, there is plenty on electricity markets that the two sides could work to improve, he added. 

The Columbia River Treaty, which has been in effect since the 1960s, could benefit from some updates, McCullough said. While British Columbia, Ontario and Quebec are well plugged into the U.S. grid, other provinces are not. 

“Manitoba Hydro has always been isolated and confused and has never actually had the involvement in the energy markets that BC Hydro has,” McCullough said. 

On the East Coast, Newfoundland effectively has been blocked from shipping its hydropower to the U.S. by Hydro-Quebec. McCullough said that even FERC could weigh in there. Hydro-Quebec had to agree to FERC regulations, such as Order 888, when it entered into the U.S. markets. 

“Theoretically, Hydro-Quebec has signed on to 888 and has to open it up for open access, but practically, that never happens,” McCullough said. “And obviously they could go to FERC and demand that FERC penalize Hydro-Quebec and Canada for violating 888, but that apparently has never been seriously considered.” 

Normally it would be a hard case to make that a foreign, provincially owned corporation could be dinged for not following FERC’s rules on its Canadian grid, he added. But with Trump in the White House, who knows? 

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PJM Network Upgrades Boost Cost of Dominion OSW Project 9%

Dominion Energy reported that its Coastal Virginia Offshore Wind project will cost 9% more than initially expected, thanks to higher-than-expected PJM network upgrade costs.

In an update issued Feb. 3, the utility said the largest offshore wind project in the U.S. otherwise is roughly in line with the budget submitted 39 months ago. It is 50% complete and still on track to be commissioned in late 2026.

The project is in a very different situation than most other wind projects off the Northeast coast, which have suffered a litany of delays, cost increases, offtake contract cancellations, pauses on development or even outright cancellations in the past two years.

And as a fully permitted project already under construction, Coastal Virginia Offshore Wind (CVOW) also is not immediately affected by the freeze on offshore wind leasing ordered by President Trump.

In its update, Dominion indicated there were decreases in offshore construction and equipment costs because of currency hedging as well as some increases such as unexploded ordnance removal, undersea cable protection enhancements and transportation fuel.

But these were far eclipsed by the onshore network upgrades and electrical interconnection cost increases.

In its quarterly report submitted Feb. 3 to the Virginia State Corporation Commission (PUR-2024-0026), Dominion said the increase stemmed from the Phase II Study results for Transition Cycle 1 that PJM published in late December.

Based on its conversations with PJM, Dominion expects the network and interconnection costs to be $882 million higher than in the original budget estimate submitted to the SCC in November 2021. The offshore adjustments are expected to raise the price tag by $30 million.

That boosts CVOW’s anticipated total cost from $9.8 billion to $10.7 billion. Part of this will be borne by ratepayers, and part by Dominion and its partner, Stonepeak.

The levelized cost of energy now is projected to be $62/MWh, once $29/MWh in renewable energy credits are factored in. That translates to an expected net impact over project lifetime of $1.01/month for a residential customer using 1,000 kWh/month.

This compares with an average all-in development cost of $150/MWh and a residential ratepayer impact of $2.02/month for Empire Wind and Sunrise Wind, the two mature projects awarded contracts by New York state in 2024.

Empire and Sunrise are among the few offshore wind projects on the East Coast still on track; most others have been canceled, paused or are far off in the future.

Transition pieces for the Coastal Virginia Offshore Wind project are loaded on the MS Sunrise in January in Aalborg Port in Denmark. | CS Wind Offshore

What makes CVOW different beyond its sheer size — 2.6 GW, which is 50% more than Empire and Sunrise combined — is that it is being developed by a regulated utility with a regulated return on its investment.

Importantly, Dominion locked in its costs for components and contractors before supply chain constraints, inflation and interest rate hikes wreaked havoc on an industry just starting to gain momentum in the U.S. market.

Dominion is optimistic CVOW’s value proposition will carry it through the latest challenge: election of a president with a longstanding antipathy toward wind turbines, particularly the 800-foot ocean variety.

Trump’s Day 1 executive order freezing new leases does not immediately affect projects that already hold leases — except by creating an uncertainty that can scare away investors who already were looking at a long and uncertain path for cost recovery during the supportive years of the Biden administration.

The order directed “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases, identifying any legal bases for such removal.”

Dominion told RTO Insider in late 2024 that CVOW has enjoyed bipartisan support through multiple state and federal administrations in its yearslong progression from concept to plan to two-turbine pilot project to full-scale steel in the water.

“Bipartisan leaders agree it has been an economic boom for Virginia, creating thousands of jobs and stimulating billions in economic growth, while providing consumers with reliable and affordable energy,” a spokesperson said in December. “Leaders from both parties also agree on the importance of American energy dominance, maintaining our technological superiority and creating good-paying jobs for Americans.”

In its Feb. 3 update, Dominion repeated this message and noted CVOW will advance one of Trump’s stated priorities — dominance in artificial intelligence — by helping power the world’s largest concentration of data centers.

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Senate Wildfire Bills Address Tx Corridor Clearing, Other Measures

A bipartisan bill in the U.S. Senate would make it easier for utilities to clear trees around power lines on U.S. Forest Service land by not requiring a timber sale for the cut-down material. 

Senate Bill 349, also known as the Fire-Safe Electrical Corridors Act, is one in a package of three bipartisan fire-safety bills that Sen. Alex Padilla (D-Calif.) announced Feb. 3.  

Another bill in the package is the wide-ranging Wildfire Emergency Act, or SB 350. Among its provisions are creating a prescribed fire training center in the West and speeding up the installation of wildfire detection equipment on the ground and in space. 

The third bill, SB 336, would give homeowners a tax exemption on money they receive through state programs to protect their homes from natural disasters. 

The bills come as the Los Angeles area starts to recover from last month’s severe wildfires that have been called the worst natural disaster in the city’s history.  

But California is not alone in facing wildfire threats. Wildfires burned 8.8 million acres across the U.S. last year, with about 1 million acres of that land in California. 

“Montanans see firsthand the effects that catastrophic wildfires have on our communities,” Sen. Steve Daines (R-Mont.) said in a statement. Daines and Padilla are cosponsors of the Wildfire Emergency Act and the Fire-Safe Electrical Corridors Act. 

Among the 11 sponsors of SB 336, the Disaster Mitigation and Tax Parity Act, are Padilla and Sens. Adam Schiff (D-Calif.), Thom Tillis (R-N.C.) and Bill Cassidy (R-La.). California, North Carolina and Louisiana are states that offer grants to homeowners to take steps such as removing fire-prone vegetation around their homes or strengthening roofs or foundations. 

“Homeowners should not face additional taxes for wanting to protect their homes,” Schiff said in a statement. 

All three bills were introduced Jan. 30 and referred to committee. 

Tree Removal Targeted

Under SB 349, the Forest Service could give electric utilities standing permission to remove hazardous trees near power lines within existing rights-of-way. A timber sale would not be required as part of the tree removal. But if a utility opts to sell the cut-down trees, the proceeds — minus transportation costs — must be given to the Forest Service. 

Although the USFS now allows utilities to cut down and trim trees in utility corridors, some forest managers view the law as forbidding removal of the material, Padilla’s office said in a release. As a result, dry fuels can build up beneath utility lines. 

“This bill would help reduce the risk of wildfires on forest lands by ensuring the clearing of existing corridors and give certainty to utilities,” Padilla’s office said. 

Three of California’s largest or most destructive fires were started by electrical equipment, the release noted. Those include the 2021 Dixie Fire, which burned 963,309 acres, making it the second-largest wildfire in state history. The blaze started when a tree fell onto a PG&E distribution line. 

Powerlines also were blamed for the 2017 Thomas Fire, which charred 281,893 acres, and the 2018 Camp Fire, which destroyed 18,804 buildings and killed 85 people, according to California Department of Forestry and Fire Protection (Cal Fire) statistics. 

The wildfire crisis “demands more proactive responses from the federal government,” Padilla’s office said in a fact sheet on SB 350. 

The Wildfire Emergency Act would create an energy resilience program at the Department of Energy to ensure that critical facilities, such as hospitals, schools, utility stations and police stations, can keep operating during wildfires. The bill would authorize $100 million for retrofits. 

The bill would expand a Department of Energy weatherization grant program to give low-income households up to $13,000 for wildfire-hardening measures, such as ember resistant roofs or gutters. 

The bill also would allow the Forest Service to pilot the use of private financing to restore wildfire-damaged forests. And the bill would allow the expansion of up to 20 existing collaborative forest restoration projects. 

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FERC Approves ISO-NE Capacity Market Collateral Requirements

FERC has accepted ISO-NE’s proposal to increase collateral requirements for generators participating in its capacity market, rejecting the New England Power Generators Association’s (NEPGA’s) arguments the changes violate the filed rate doctrine. 

The changes to the RTO’s financial assurance policy (FAP) are intended to reduce the risks of generators defaulting on pay-for-performance charges incurred during capacity scarcity events (ER24-3071). 

The commission ruled Jan. 31 that the updates “will better protect the market against the risks of socialized defaults and failure to pay non-performance penalties resulting from capacity sellers with insufficient corporate liquidity.” 

The policy revisions will create a corporate liquidity assessment, which will evaluate each generator’s “ability to pay potential penalty payment obligations associated with its CSO [capacity supply obligation] within the applicable Capacity Commitment Period (CCP), over a forward-looking rolling six months.” 

This assessment will categorize participants as low, medium and high risk, and the categories will be used to determine the generators’ collateral requirements. 

The changes took effect Feb. 1, 2025, and will impact CSOs beginning June 1, the start of 2025/26 CCP, which corresponds to Forward Capacity Auction 16.  

The implementation of the revisions will coincide with a major increase in non-performance penalty rates, which also take effect the same date. The penalty rate, which increased from $3,500/MWh to $5,455/MWh for the 2024/2025 CCP, will increase to $9,337/MWh on June 1, 2025. 

Pay-for-performance penalties can pose significant risks to resources with CSOs. Non-performance charges totaled $62.7 million across two scarcity events during summer 2024. Oil resources and non-combined-cycle dual-fuel resources took large penalties during these events, while imports took in nearly $29 million in performance credits. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.) 

ISO-NE estimated the new collateral requirements will increase the total financial assurance obligations for CSOs in the 2025/26 CCP by about $72 million to $90 million. Generators that meet the “low risk” classification will not be subject to the higher collateral requirements. 

“By requiring CSO holders deemed as medium risk and high risk to provide increased collateral, the FAP Revisions can reduce the risk of socialized defaults,” FERC ruled. 

‘Post Hoc Tinkering’

In its protest of ISO-NE’s proposal, NEPGA argued that applying the updated requirements to existing CSOs would violate FERC’s filed rate doctrine, which prohibits retroactive changes to rates. 

“The FAP changes, if applied to CSOs beginning with the FCA 16 Capacity Commitment Period, would change the financial assurance requirements (the legal consequences) of assuming a CSO in FCAs 16-18 held in 2022 – 2024,” NEPGA wrote. 

“The doctrine forbids ‘post hoc tinkering’ to correct or otherwise alter prior rates, terms and conditions, such as the CSO obligations and entitlements offered and agreed to in FCAs 16-18,” the association added. 

NEPGA alsoargued that, even if the revisions do not violate the filed rate doctrine, increasing the collateral requirements for existing CSOs could decrease investor confidence in market stability, potentially accelerating retirements and reducing system reliability.  

FERC rejected NEPGA’s argument regarding the filed rate doctrine, noting the commission “previously found that the terms and conditions of performance and other obligations that are a part of forward capacity markets may be revised, even after a forward auction for a future delivery year is completed, if the changes are made prospectively and after notice.” 

The commission added that the financial assurance requirements for the upcoming CCP “have not been calculated or posted,” and the changes to the policy accepted by FERC “will only alter future data inputs to these formulas.” 

Responding to NEPGA’s concerns that the revisions still would have negative effects on the market even in the absence of a filed rate violation, FERC wrote that “capacity suppliers had no reasonable expectation that the FAP provisions would remain unchanged, and to the extent that NEPGA members considered existing FAP provisions in formulating their offers, they did so at their own financial risk.” 

NEPGA expressed disappointment with FERC’s ruling, saying in a statement that the changes will impose “new, higher costs on generators well after they assumed a Capacity Supply Obligation, and, therefore, have no way of reflecting these increases in market offers.” 

The group added that it is reviewing the order and “assessing potential next steps.” 

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FERC Sets Missouri Co-op’s Tx Rate for Hearing

FERC has ordered hearing and settlement proceedings over a Missouri electric distribution cooperative’s effort to split from the Wabash Valley Power Association and earn rates on its own as a transmission owner in MISO.

Citizens Electric Corp., currently a member of the Wabash Valley Power Association, is striking out on its own and has purchased two planned transmission assets from the association while still taking service as a third-party customer through mid-2028. Citizens hopes to exit Wabash by June.

But FERC in a Jan. 31 order said the rates Citizens proposed might not be just and reasonable, singling out a proposed depreciation rate and one of the lines for not being proven to be beneficial (ER25-324). While FERC gave the go-ahead for rates to become effective Feb. 1, it subjected them to refund.

Citizens is member-owned and borrows from the U.S. Department of Agriculture’s Rural Utilities Service. While not a public utility and exempted from FERC regulation, the cooperative agreed to a commission review of rate recovery. The MISO Board of Directors on Jan. 23 approved Citizens as a transmission owner.

Citizens bought a $117.5 million portion of the jointly planned, 138-kV Grand Tower Project line and substation rebuild, a baseline reliability project approved under MISO’s 2023 Transmission Expansion Plan (MTEP 23). It also purchased the Salem Bulk Project, a new 69-kV line approved as an “other” reliability project in MTEP 23.

FERC decided one of the transmission projects didn’t meet the threshold for rate incentives.

FERC said Citizens did not prove that Salem Bulk Project ensures reliability or reduces congestion costs because of its status as an “other” project under MTEP. In MISO, “other” reliability projects aren’t held to the same level of review as baseline reliability projects, which are built to meet NERC criteria. FERC said the project lacks “a fair and open regional transmission planning process that considers and evaluates projects for reliability or congestion.”

FERC also said it wasn’t convinced Citizens’ proposed 2.75% depreciation rate in the formula is fair. The Rural Utilities Service uses a 2.75% depreciation rate, and Citizens borrowed it, explaining it didn’t conduct its own depreciation study.

Citizens agreed ahead of FERC’s decision that its rate formula would be subject to refund with interest.

Otherwise, FERC granted Citizens’ request for the Construction Work in Progress (CWIP) Incentive and Abandoned Plant Incentive on the Grand Tower Project. FERC agreed the project presents a “cash flow risk” that the CWIP can alleviate while helping avoid rate shocks to Citizens’ transmission customers. Finally, the commission allowed Citizens’ proposed return on equity of 9.98% and the 50-basis-point adder for RTO participation.

Christie Faults ‘Check-the-box’ Tx Incentives

As he has with past orders on rate incentives, Chairman Mark Christie dissented in part from the order, blasting FERC’s incentives approval as a “check-the-box” exercise.

Christie took issue with approval of the CWIP and Abandoned Plant incentives, saying the commission eschewed a “fact-specific, careful evaluation of balancing the needs of consumers and the benefits to investors based on the nature of the transmission projects at issue.” He added that “every transmission developer seems to cite the same” financial and regulatory risks for projects.

Christie also said the RTO participation adder “increases the transmission owner’s ROE above the market cost of equity capital” and is “an involuntary gift from consumers.”

“There has been and continues to be something really wrong with this picture,” he said, calling again to limit the adder to the three years following initial RTO membership.

Christie also pointed out that FERC approved incentives for a transmission project that doesn’t yet have state approval for construction.

“No state CPCN [certificate of public convenience and necessity] proceeding has been conducted reviewing both need and prudence, yet the commission grants the incentive anyway,” he wrote. “Although the regional transmission planning process is only one rebuttable presumption … allowing qualification for incentive rate treatment, reliance on regional transmission planning in lieu of state approval to construct is one of the major problems with FERC’s policy. This practice is indefensible and always has been.”

He said MISO’s transmission planning is “not remotely the equivalent of a serious, litigated” CPCN.

Christie repeated concerns that the CWIP Incentive “effectively makes consumers the bank for transmission developers,” and the Abandoned Plant Incentive “effectively makes them the insurer of last resort” — all without the benefits of interest or premiums.

Christie said the case “graphically illustrates the fundamental unfairness of the commission’s practices regarding incentives” and demanded a revisit of FERC Order 679, which makes any transmission project designed to increase reliability or reduce congestion eligible for incentive ratemaking.