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January 3, 2025

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Pennsylvania Seeks Lower PJM Capacity Price Cap in FERC Complaint

Pennsylvania Gov. Josh Shapiro on Dec. 30 filed a complaint with FERC on behalf of the state asking the commission to revise how the maximum clearing price in PJM’s capacity auction is determined, arguing that the current design could result in consumers overpaying by as much as $20 billion (EL25-46).

The state seeks to lower the price cap to 1.5 times the net cost of new entry (CONE) on the grounds that the status quo approach of using the greater of gross CONE or 1.75 times net CONE could result in high prices without any corresponding reliability benefit. It argued that 1.5 times net CONE is the theoretical price point to ensure that the reference capacity resource can remain in business on top of any energy and ancillary service (EAS) revenues, and that any price above that would be excessive.

It asked that the change be effective for the 2026/27 Base Residual Auction (BRA) and the following two auctions while stakeholders consider the market design more holistically through the Quadrennial Review process, which has been expedited by a year and is in the initial phases of the PJM stakeholder process with the Market Implementation Committee.

“The public interest simply cannot tolerate up to $20.4 billion in unreasonably high rates dictated by a steep demand curve that was designed for an entirely different environment,” Pennsylvania said. “To prevent an unjustly high auction price and to reflect current market conditions, PJM should be directed to return the price cap to 1.5 times net CONE until a new demand curve is established by the ongoing sixth Quadrennial Review.”

Under normal circumstances, the state said, a higher clearing price could create a stronger incentive for development of new resources. But PJM’s backlogged interconnection queue prevents the construction of any projects not already in line. Paired with several delays to the auction schedule that have compressed the three-year advance timeline to 11 months, it said that any developers seeking to respond to a high price signal would not be able to do so until the delivery year has passed.

“It is difficult to escape the conclusion that PJM’s capacity market is currently failing,” Pennsylvania said. “This is not one isolated failure: Respected analysts have ranked PJM’s interconnection queue process the worst in the nation. PJM has also habitually failed to run its capacity auctions on time — earning the distinction of being the only grid operator in the nation with a forward auction design that is effectively being held as a prompt auction.”

In a statement responding to the complaint, PJM said there is an imbalance between supply and demand creating an increasing risk of capacity shortages, in part because of state and federal policies that are causing generators to prematurely deactivate. It said it has proposed rule changes to FERC that would reduce the price cap and allow new generation to come online quicker.

The RTO has also implemented changes to its interconnection process to study projects faster, allowing about 50 GW to come out of the queue and move on to the next steps of development, it said. Many have run into roadblocks that PJM said are outside of its control, such as permitting, financing and supply chain challenges.

“We remain open to additional solutions to this generational challenge, as long as they support keeping the lights on. Service interruptions, brownouts and blackouts cannot be an option,” PJM said. “We have had productive engagement with the Shapiro administration and all of our states to date, and we appreciate their active engagement and advocacy. It will take all of us working together to help create the conditions for increased investment in new generation that is needed for long-term price stability as well as grid reliability for customers.”

Pennsylvania acknowledged the proposed revisions to aspects of the capacity market and how new resources can progress through the interconnection process, but it said the prospect that the 2026/27 auction will clear at an unreasonably high cap remains, and construction timelines make it unlikely that new resources could be online in time to add supply.

“Even PJM’s proposed ‘fast track’ Reliability Resource Initiative (RRI) — which Pennsylvania generally supports — is not projected to allow new resources to come online before the 2029/2030 delivery year [ER25-712]. These obstacles mean most new projects are unable to even get in line to join the PJM grid for the foreseeable future, and none can realistically expect to be delivering power within 11 months,” the state said, referencing the RTO’s proposal to allow 50 resources to be added to the Transition Cycle 2 queue based on their expected in-service date and deliverable capacity.

The state also argued that PJM’s proposal to undo a change to make the reference resource a combined cycle unit and revert back to a combustion turbine would resolve the concerns that led it to increasing the net CONE multiplier in the 2022 Quadrennial Review prices (ER25-682). Because CCs tend to rely on the energy market for a larger share of their revenues, there was a concern that high prices in that market could suppress capacity clearing prices even when new resources are expected to be needed. The 2026/27 BRA would be the first to use a CC as the reference resource, but PJM requested that FERC allow it to continue using a CT unit when it determined that net CONE would fall to zero in some zones.

A net CONE of zero would result in a substantially steeper variable resource requirement (VRR) curve that could swing capacity prices with relatively small changes in the amount of capacity offers, in addition to knock-on effects for other market constructs that use net CONE as an input. (See FERC Approves PJM Quadrennial Review.)

Pennsylvania said there is no theoretical basis for including gross CONE when defining the price cap, and it was added in the 2011 Quadrennial Review to address possible inaccuracies in the EAS offset, which it says have been resolved by the shift to forward-looking estimates of energy prices rather than historical data.

Even with the higher capacity prices that using gross CONE could lead to, Kris Aksomitis, director of commercial power development and strategy for consultancy Power Advisory, said in an affidavit that resources capable of coming online quickly are unlikely to be further incentivized to do so. Owners of mothballed assets would likely be wary of continued market volatility, and there is no evidence that demand response requires “scarcity-level pricing” to increase participation, he said. Projects already in the queue are also unlikely to receive interconnection service agreements in time to offer into the market.

“Setting the price cap at gross CONE is likely to increase capacity prices for the 2026/2027 BRA by as much as 50% relative to prices under a lower price cap, with no reasonable expectation of an incremental market response sufficient to justify the cost,” Aksomitis said. “This represents an unjustified wealth transfer, as the incremental capacity and reliability benefit are shown to be minimal and come at cost orders of magnitude greater than any reasonable estimate of the” value of lost load.

Pennsylvania acknowledged that load growth will push demand and prices higher, a process it said is already happening as designed with a surge in clearing prices in the 2025/26 auction to $269.92/MW-day, up from $28.92/MW-day in the prior auction. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

“Indeed, record load growth is making it plainly evident that new capacity is needed in the marketplace, and the capacity market is responding as designed with a strong build signal,” it said. “Under these conditions, net CONE is functioning as intended and recently produced an all-time high RTO-wide capacity price in response to increasing supply-demand imbalance in July 2024.”

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PSEG’s Piedmont Transmission Project Faces Opposition in Maryland

The Maryland Public Service Commission on Dec. 31 received an application from PSEG Renewable Transmission for the company’s Maryland Piedmont Reliability Project, a 67-mile, 500-kV transmission line that could be vital to power reliability in the state but has already sparked opposition. 

The proposed line would run from a connection with a Baltimore Gas and Electric transmission line in northern Baltimore County, through Carroll County and end at a substation in Frederick County, near the state’s border with Pennsylvania. With a 150-foot-wide right of way, the project would cover approximately 1,221 acres, according to details in the application. 

The 500-kV line would be built on “303 H-frame structures, consisting of two vertical tubular poles with an average height of 145 feet (varying from 85 to 195 feet) and an anticipated foundation diameter of 6 to 14 feet,” the application says. The distance between the pylons would vary from 800 to 1,400 feet, with an average of 1,200 feet.  

PJM has warned the state repeatedly that new transmission is needed to meet growing demand from data centers and avoid potential power loss as existing fossil fuel plants are closed. 

But Joanne Frederick, board president of Stop MPRP, a grassroots, nonpartisan group opposing the project, isn’t buying that argument. 

“They have maintained all along that this was the only solution that would work, and we don’t believe them,” Frederick said in a Jan. 2 interview with RTO Insider. “This project, as proposed, is catastrophic to farmlands. It’s catastrophic to property values. It’s catastrophic to farming businesses. It’s catastrophic to several agri-tourism businesses. … We plan to argue against this project; against each of those broad negative impacts it would bring.” 

Frederick is one of several individuals and groups that have raised concerns about the project, from individual farmers to Gov. Wes Moore (D), who has questioned how the new transmission line would benefit the state and its residents. 

Opponents argue that MPRP was designed to bring power from Pennsylvania to data centers in Northern Virginia, but Maryland residents could end up paying a major part of the project’s $424 million price tag. 

PSEG has laid out a schedule for MPRP that includes PSC approval of a certificate of public convenience and necessity by the end of 2025, with construction beginning in 2026 and the project going online in 2027. 

The PSC soon will announce the date for a pre-hearing conference to set an administrative schedule and consider petitions from individuals and groups seeking to intervene in the case, according to Communications Director Tori Leonard. The commission also will schedule public hearings on the project in Baltimore, Carroll and Frederick counties, she said. 

Reliability and Economic Benefits

The MPRP was approved by PJM as part of its Regional Transmission Expansion Plan in December 2023. (See PJM Board Approves $5 Billion Transmission Expansion.) 

“PJM has determined that the bulk 500-kV electric transmission system serving large parts of Maryland is forecasted to experience serious reliability violations including thermal overloads and voltage collapse violations (blackout) in 2027,” PSEG said in its application. “If these serious reliability violations are not addressed, it could compromise overall system reliability in the PJM region, including for Maryland customers, and could lead to widespread and extreme conditions, including system collapse and blackouts.” 

Maryland imports about 40% of its power from the regional grid, and PJM has said the threats to reliability are so severe that upgrades to increase capacity on existing lines, by installing advanced conductors or other grid-enhancing technologies, would not be sufficient, the company said. 

PSEG also has said its proposed route was chosen out of 10 alternatives because it “impacted fewer conservation easements, had fewer residences and community facilities in close proximity to the right of way, and it was shorter and had fewer hard turns, which reduces cost and complexity.” 

The route also avoids Civil War battlefields and state parks, PSEG said in the application. 

Responding to community requests that the line be run along existing rights of ways, PSEG said doing so “would require removing over 90 residential homes and community buildings.” However, the proposed route would require easements on private land. 

According to PSEG’s website for the project, the company has started reaching out to landowners on the proposed route to talk with them about the project and answer questions. The company will seek temporary right-of-entry agreements “to conduct surveys and other studies needed to assess the suitability of the property for the MPRP and to gather information needed for the CPCN evaluation.” 

PSEG counters concerns about who will pay for MPRP by noting that as a PJM project, the cost will be allocated to customers across the RTO’s service territory, which includes 13 states and D.C. It also estimates $306 million in project benefits for Maryland, including “direct, indirect and induced positive economic impacts over an assumed 30 years of operations” and 1,709 full-time jobs during construction. 

Possible Legislation

The company first released a map of its 10 alternative routes in July 2024, followed by the announcement of the preferred route in October. PSEG held three public meetings, one in each of the affected counties, in November. 

Project opponents argue the rollout schedule did not leave enough time for individuals and communities to study the proposed route and provide informed feedback. 

PSEG’s public meetings were a step in the right direction but not sufficient, said Kim Coble, executive director of the Maryland League of Conservation Voters. 

“There needs to be more conversations,” Coble said in a Jan. 2 interview with RTO Insider. “You can fill a room with a bunch of people and a PowerPoint [presentation], and that does not equate into meaningful engagement of the communities that are impacted. There’re conversations; there’s listening; there’s [asking], ‘What are your concerns, and how can we help address them?’” 

In a Nov. 22 statement, Gov. Moore laid out his own “grave concerns about how the study area for this project was determined, the lack of community involvement in the planning process and the lack of effective communication about the impacts of this project.” 

Maryland lawmakers plan to introduce legislation that could slow the approval process for PSEG and the MPRP.

Del. Jesse Pippy (R), minority whip in the House of Delegates, is working on a bill that could require PSEG to provide more documentation of the alternative routes the company considered.  

PSEG “kept their cards very close to their chest,” Pippy told WBAL. “So, what we want to ensure is that when the Maryland Public Service Commission is making decisions, they are requiring these applicants to consider alternative routes.” 

Senate Minority Leader Justin Ready (R) may propose a bill to ensure that farmers displaced by the project receive a 350% premium for any of their land taken by eminent domain, according to WBAL. 

Stop MPRP’s Frederick also wants further study of alternatives to the project, such as combining system upgrades with grid-enhancing technologies and a new natural gas plant. 

“What’s the [difference] between … the negative environmental impact of a new, clean natural gas power plant versus the negative environmental impact of wiping out 473 acres of old-growth forest, of doing that kind of environmental damage to wetlands, woodlands across Maryland?” she said. “We owe it to ourselves to understand the facts; to clearly articulate the choices we should be making and not just ignore them.” 

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Offshore Wind Industry Girds for 2025, Trump Presidency

The U.S. offshore wind industry will find out soon where election rhetoric turns into action or turns into hollow words.

Donald Trump’s pledges and threats on the campaign trail suggest he will attempt many transformational changes. But few targets have been identified so clearly and firmly as when Trump said he would end offshore wind on Day 1 of his second term as president.

It was a classic campaign rally message: bold and decisive but devoid of details, delivered to a friendly crowd on a beach in New Jersey, an epicenter of offshore wind opposition.

But given Trump’s longstanding antipathy toward offshore wind, it may have been more than a soundbite.

The industry has attracted tens of billions of dollars in investment and put thousands of Americans to work as it attempts to build a new U.S. power sector.

That would seem to check a lot of Trump’s favorite boxes, many advocates note — if it did not entail thousands of giant wind turbines along the nation’s coastlines.

Path of Most Resistance

Analysts, advocates and industry members speaking to RTO Insider or to public and private audiences in late 2024 see a variety of ways President Trump could thwart offshore wind development.

There is the executive order — bold and decisive but subject to court challenge.

Indirect measures would be harder to fight and could net similar results:

    • Refusing to defend specific projects against litigation.
    • Slow-walking permit reviews.
    • Not holding auctions.
    • Moving to reduce or eliminate tax credits.
    • Limiting the funding and staffing for regulatory agencies.
    • Jacking up tariffs on the expensive (and still almost entirely foreign) components of offshore wind farms.
    • Creating a level of uncertainty that scares off the investors needed to build factories, ships, ports, workforce and other parts of an industrial ecosystem.

Given Trump’s deliberately unpredictable leadership style, it is hard to guess what he will do. Even the more predictable presidents have been known to say one thing and then do another.

An all-of-the-above energy portfolio with both fossil and renewable energy is backed by many Republicans, including former North Dakota Gov. Doug Burgum, whom Trump has chosen to head the Department of the Interior, lead agency on offshore wind regulation.

During Burgum’s eight-year tenure, North Dakota doubled its installed onshore wind generation capacity to more than 4 GW.

Offshore wind advocates have their hopes. But analysts and observers whose comments were reviewed for this report expect U.S. offshore wind development to be at least somewhat stunted during Trump 2.0 — not a full-on implosion but probably well short of the robust growth of the Biden years.

Headwinds

In a mid-December update to clients, ClearView Energy Partners said it sees two scenarios for Trump to deal with offshore wind: Retaliate against one of Biden’s prized initiatives by actively moving to thwart it, or merely refocus resources elsewhere, letting it sputter along without support.

One can envision reasons for both scenarios, ClearView wrote, but Trump’s past attacks on renewables are not necessarily the best indicator: “Campaigning is one thing, and governing is another. Trump has demonstrated a mercurial willingness to reverse or modify his prior stated positions.”

Killing permitted offshore wind projects on principle also would run counter to Trump’s goal of energy dominance and be counterproductive in a time of growing concerns about resource adequacy, Clearview wrote.

Three South Fork Wind turbines are shown off the New York coast in early 2024. | South Fork Wind

Wood Mackenzie said the impact of the Trump administration’s decisions could vary considerably. Restricting permitting and leases would not have much effect on the 10-year outlook, it said, given that nearly 25 GW of projects are far along in the permitting process or have completed it. Limiting finances, on the other hand, would have a greater effect.

“If the administration chooses to not issue guidance on the domestic content bonus credit for offshore wind, or pares back the 45X advanced manufacturing tax credit, investments in a domestic supply chain could be significantly delayed,” Wood Mackenzie analyst Stephen Maldonado said in mid-November. “While Wood Mackenzie’s base case outlook expects 27 GW of cumulative installed capacity by 2033, the compound effects of these constraints could lead to a 30% decrease over the same time frame.”

In a subsequent update in mid-December, Wood Mackenzie said change already was underway, with some early stage U.S. projects mothballed or paused. It said: “The segment’s longer lead times may limit the immediate impact on 2025 budgets, but offshore wind is set to slide down the investment priority list for many diversified renewables developers next year.”

During an American Offshore Wind Academy webcast in mid-December, Boston Consulting Group Managing Director Jeremy Merz said Trump could pull many levers, ranging from financial disincentives to executive orders to a permitting slowdown.

He expects a mid-range approach with mid-range effects on the industry. Individual projects would sustain greater or lesser impacts depending on where they are in their timeline — those that are fully permitted with offtake agreements and a clear path to construction are at much less risk than those that merely have secured a lease and are in early planning.

“I don’t believe it will actually lead to death of offshore wind in the U.S. I think that’s a very, very unrealistic scenario,” Merz said.

But he added: “Given the increased uncertainty that we have at the moment, investors, developers will probably shift some of their capital to offshore wind outside of the U.S., or to other energy sources in the U.S.”

Yvan Gelbart, lead analyst at Spinergie, wrote in mid-November that Trump’s potential actions all could create short-term headwinds for the industry — even a 10% increase in capital costs due to tariffs would render many projects unviable.

He noted, however, that the election cycle brought no significant changes to the leadership of the states that are helping to drive offshore wind development.

Gelbart wrote: “State-level support and approved project pipelines will help mitigate some of the federal-level challenges. While progress may slow, it’s unlikely to come to a complete halt. … The coming years will be trying, but with careful navigation, the industry may weather this storm.”

For a different perspective, look at GE Vernova, a giant among power equipment manufacturers.

It has not taken an offshore wind turbine order in more than three years. Its decision to halt development of an 18-MW model was blamed for the collapse of an entire offshore wind solicitation totaling more than 4 GW in New York in early 2024.

But it has expanded its gas turbine manufacturing capacity.

Consider two paths to 9 GW of generation capacity: In 2019, New York set a 9 GW offshore wind goal and gave itself 16 years to reach it. Shortly after Trump was reelected in 2024, GE Vernova needed just 30 days to book reservations for 9 GW of new gas-fired turbines.

CEO Scott Strazik said during an investor update in mid-December that the company will not chase bad offshore wind deals. Two days later in an interview with Bloomberg News, he doubled down: “The reality is, the economics of this industry don’t make sense.”

GE Vernova will need to start from scratch to assess the finances of offshore turbines, Strazik told Bloomberg, with pricing more analogous to nuclear power than to onshore wind or solar.

Strazik’s comments touch on a larger problem: Whatever effect Trump may have on U.S. offshore wind in 2025, the industry was not swimming along smoothly in 2023 and 2024. It sustained significant setbacks in both years, even as it logged significant progress.

History May Not Repeat

It is probably unwise to predict how offshore wind will fare during Trump 2.0 based on what happened during Trump 1.0. First, the U.S. industry of the mid-2020s is far advanced from the late-2010s industry. More important, President Trump is “mercurial.”

But consider a December 2018 Department of the Interior news release on a Massachusetts wind lease auction titled: “BIDDING BONANZA! Trump Administration Smashes Record for Offshore Wind Auction with $405 Million in Winning Bids.”

Then-Interior Secretary Ryan Zinke goes on to say: “To anyone who doubted that our ambitious vision for energy dominance would not include renewables, today we put that rumor to rest. With bold leadership, faster, streamlined environmental reviews, and a lot of hard work with our states and fishermen, we’ve given the wind industry the confidence to think and bid big.”

Walter Cruickshank, then-acting director of the Bureau of Ocean Energy Management, added: “This auction will further the Administration’s comprehensive effort to secure the nation’s energy future.”

The first monopile for Equinox’s Empire Wind 1 project off the coast of New York is completed Nov. 28 at Sif’s facilities in the Netherlands. | Sif Group

So the Trump administration presented at least the appearance of an all-of-the-above approach to energy development.

One also could count the number of announcements Interior has made about offshore wind. There have been 215 under Biden as of late December 2024; 131 during the last five years that Barack Obama was president; and just 43 during Trump’s four years in office.

Or one could ask James Bennett, who was BOEM’s manager of renewable energy programs during the Trump administration and parts of the Obama and Biden administrations.

During an early-November webcast staged by the American Offshore Wind Academy, Bennett suggested the effusive news release about the Massachusetts auction was disingenuous.

“By then, some of the policies had taken hold, and there were some slowdowns, if you will, in the latter part of the Trump administration, which, of course, changed quite a bit with the incoming Biden administration. And it’s been going very, very aggressively since then.”

Bennett also reminded viewers that offshore wind was little more than a paper industry in the United States in 2016. It is now a multibillion-dollar endeavor — and those are much harder to shut down with the flick of a switch.

Pushing Forward

The day after Trump won reelection, Oceantic Network reminded him of the economic value of offshore wind, and of his earlier role in building it.

Several weeks later, Senior Vice President Stephanie Francoeur told NetZero Insider that this remains the strategy. Wind farms totaling 4 GW of capacity are under construction in U.S. waters, dozens more gigawatts of capacity are moving closer to construction, $41 billion in investments have created thousands of jobs and the supply chain spans 40 states.

All this began during the first Trump administration, she added.

“This new administration is signaling a seriousness with expanding domestic energy production, and we really believe that offshore wind energy is going to be a critical part of that future energy mix,” Francoeur said.

Nick Guariglia, outreach manager for the New York Offshore Wind Alliance, said rolling with changes in administration is an indispensable part of offshore wind development — no project can get done in four years.

New York’s South Fork Wind started development under Obama, continued during Trump and became the first completed utility-scale wind farm in U.S. waters during the last year of the Biden presidency.

“There were always going to be changes in Washington,” Guariglia said flatly.

His membership is neither optimistic nor pessimistic about Trump’s return. The industry is fine-tuning its message to emphasize priorities it shares with Trump and continuing with its business, he said.

“We have produced jobs. We’ve spurred economic development. We are literally creating new tax revenues for local municipalities.”

Kelt Wilska, offshore wind director at the Environmental League of Massachusetts, said he was excited to see Massachusetts Gov. Maura Healey redouble her state’s commitment to offshore wind.

Union ironworkers who are building components for the Sunrise Wind project applaud a milestone announcement at a fabrication shop in Coeymans, N.Y., in September. | © RTO Insider LLC 

He said states can counter federal headwinds facing the offshore wind industry by offering their own support through aggressive procurements and through supply chain development, both of which the Bay State has done.

It sends an important message of confidence to the industry and to other states, Wilska said.

“This is a national industry,” he said. “It’s taking off everywhere. I give examples of New England, because that’s where I work, but this truly is a regional and also a national industry that is vulnerable.”

That speaks to a key part of the strategy for the offshore wind industry and the larger renewables industry as it attempts to move forward through the Trump years.

The Inflation Reduction Act passed with not a single Republican vote, yet its economic benefits are flowing to Republican-controlled areas.

At the two-year anniversary of the signing of the IRA, the energy and environment advocacy group E2 tallied 334 major announced clean energy/clean vehicle projects. Of these, 278 offered estimates of job creation (total: 109,278) and/or private capital investment ($126 billion).

E2 calculated that 60% of the 334 announcements were in Republican congressional districts, and that they represented 68% of the new jobs and 85% of the investments.

Clean energy advocates hope enough legislators in the slim Republican majorities in both houses of Congress will want to protect those gains that they can temper Trump’s harshest moves.

U.S. Rep. Salud Carbajal (D-Calif.), co-chair of the Congressional Offshore Wind Caucus, said via email that attempts at persuasion already have begun:

“The bipartisan Offshore Wind Caucus has been committed to educating members of Congress about the economic benefits of this burgeoning industry and working across the aisle to support the renewable energy job creation happening in communities across America. I’m confident that it will continue doing that work in the next Congress and will look to engage with the incoming administration to help them see the support this homegrown American energy source has throughout the country.”

Dominion Energy, which is building the nation’s largest offshore wind project to date, expects to finish on time and on budget regardless of partisan politics. It has important advantages over other developers: It is a regulated utility with itself as the offtaker, and it locked in cost certainty on the project before macroeconomic factors began to shake the offshore wind industry.

Spokesperson Jeremy Slayton said via email: “Virginia’s clean energy transition and our ‘all of the above’ strategy, including Coastal Virginia Offshore Wind, have been underway for several years under multiple state and federal administrations and with bipartisan support from policymakers at every level.

“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. Leaders from both parties also agree on the importance of American energy dominance, maintaining our technological superiority and creating good-paying jobs for Americans.”

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Feds Boost Constellation Nuclear Plans with $840M PPA

A first-of-its-kind power purchase agreement will send more than 10 million MWh of power to federal buildings and help Constellation Energy increase the output from its nuclear fleet. 

Constellation and the U.S. General Services Administration announced the contract Jan. 2. The 10-year deal is valued at $840 million and is accompanied by a $172 million contract for Constellation to provide energy savings and conservation upgrades at five GSA facilities in the D.C. region. 

In its news release, GSA framed the announcement with the multipronged benefits of boosting U.S. nuclear generation capacity, protecting taxpayers from price hikes and helping 14 government entities transition to 100% carbon-free electricity by 2030. 

Constellation operates the largest U.S. reactor fleet. The contract will help it meet the costs of extending licenses for its existing nuclear plants and installing upgrades that will increase their output by a combined 135 MW. It covers 80 federal facilities in five states within PJM territory and will begin in April. 

GSA called the contract historic and said it was modeled on long-term corporate carbon-free procurements. 

Not all of the power supplied under the deal will be carbon-free. Neither side specified the anticipated percentage, but GSA said that over the next decade, it would purchase 2.4 million MWh of Constellation’s newly expanded nuclear output, as well as the associated energy attribute certificates. 

For Constellation, the agreement is another step toward the market certainty it needs to invest in nuclear power. For example, the company announced its 2024 request to renew the license for its Dresden nuclear facility with the caveat that it needed “adequate market or policy support.” 

Corporate predecessor Exelon had planned to retire Dresden and another Illinois facility early, then kept them open when the state implemented policy changes in 2021. Constellation is now planning to restart a reactor at the former Three Mile Island facility to supply electricity to Microsoft data centers. 

In Constellation’s news release Jan. 2, CEO Joseph Dominguez spoke of the value proposition his company’s “clean energy centers” present. 

“For many decades, Constellation’s nuclear fleet has provided carbon-free, reliable, American-made energy to millions of families and institutions,” he said. “Frustratingly, however, nuclear energy was excluded from many corporate and government sustainable energy procurements. Not anymore. This agreement is another powerful example of how things have changed.” 

He said the GSA agreement, like the previous agreements with Microsoft and other entities, “will allow Constellation to relicense and extend the lives of these critical assets.” 

The energy will be supplied to the Architect of the Capitol, the GSA, the Social Security Administration, the Army Corps of Engineers, the Department of Veterans’ Affairs, the Department of Transportation, the U.S. Mint, the U.S. Railroad Retirement Board, the National Archives and Records Administration, the Federal Bureau of Prisons, the Federal Reserve System, the National Park Service, the National Oceanic and Atmospheric Administration, and the Washington Metropolitan Area Transit Authority in locations the agencies own or operate in Illinois, Maryland, New Jersey, Pennsylvania and Ohio. 

The energy savings performance contract awarded to Constellation includes lighting, weatherization, HVAC and building control upgrades to increase energy efficiency, decrease emissions and lower energy costs. 

Work will start shortly and continue for 42 months. The centerpiece is the conversion of four D.C.-area buildings from steam to electric boilers and heat pumps. Constellation also will provide preventive maintenance services and train GSA personnel. 

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NERC Pushes Cold Weather Prep as ‘Trough’ Approaches

NERC has urged power grid operators to take action to “ensure the highest levels of reliability” ahead of a wave of extreme winter weather predicted to blanket much of North America in the first weeks of January. 

“The reliability of the North American electric grid is the key priority for NERC — we know 400 million North Americans are counting on an uninterrupted supply of electricity to support our way of life,” NERC said. 

NERC noted in its release the issue of a hazards outlook by the National Weather Service forecasting “extremely low temperatures, damaging winds, snow and freezing rain” across the U.S. East Coast, Southeast and Midwest that could lead to “a series of successive events that could create challenges for those reliant on inventoried fuels.” The ERO said it’s particularly concerned about the supply of natural gas, which is used for electric generation and home heating.  

NWS’s most recent outlook, covering the week of Jan. 10-16, is consistent with these warnings, forecasting a combination of low pressure in the eastern U.S. and high pressure in the West and Greenland that likely create a “deep trough” to “funnel Arctic air into the Lower 48 east of the Rockies.” The outlook said there is a greater than 60% chance of “much below-normal temperatures” for much of the Southeastern U.S. on Jan. 9-11, meaning daily minimum temperatures that are less than the 15th percentile and near or below freezing. 

Even Florida faces the potential of a hard freeze, NWS said. Low pressure conditions also could lead to “widespread breezy conditions and very low wind chills,” with at least a 20% chance of wind speeds passing the 85th percentile over the Northern and Central Plains Jan. 10-14. 

Heavy snow also is possible across the central and eastern Continental U.S. in the middle of the covered week, and even in the Southeast — along with other precipitation types — due to moisture from the Gulf of Mexico. NWS noted that earlier outlooks predicted moderate risks of heavy snow between Jan. 9 and 15, but this has been changed to a slight risk. The change is due partly to lower predicted snowfall totals, but also because models indicate “some of the anticipated heavy snow” shifting into the preceding week. 

In a video statement, NERC CEO Jim Robb said the coming cold weather could represent a “major” challenge to grid reliability and reiterated the ERO’s call for action from the industry. 

“While forecasts are forecasts and undoubtedly contain error, these systems do seem to have the potential to bring a prolonged period of very cold weather — as cold as single digit temperatures in the U.S. South,” Robb said. “As a result, I’m asking everyone in the electricity supply chain … to take all appropriate actions to ensure that we can maintain an uninterrupted supply of electricity to customers. … The actions you take now may very well help us avoid the consequences of events such as we saw in Texas in 2021 and the Mid-Atlantic in 2022.” 

Winter weather has been a growing source of concern for NERC and the rest of the ERO, with the organization warning in this year’s Winter Reliability Assessment that all or part of multiple regions face elevated risk of energy shortfalls from extreme winter conditions. NERC said rising demand and retirements of thermal generation capacity contribute to slimmer reserve margins across the continent. (See NERC Sees ‘Reasons for Optimism’ as Winter Approaches.) 

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MISO Angles for More Generation, RA Requirements in 2025

MISO will waste no time in 2025 trying to blunt the threat of a shortage that could arrive in the summer months by encouraging new generation and enacting more resource adequacy measures.

MISO leadership spent 2024 reiterating that the grid operator is on a collision course with a supply deficit unless members get more projects built, it supercharges transmission planning and it can persuade members to stave off generation retirements.

During MISO’s Board Week Dec. 10-12, MISO executives said they would pursue large-scale load shedding drills among the membership, indicating the RTO anticipates blackouts.

However, MISO CEO John Bear said he feels that MISO has accomplished more in terms of resource adequacy in the past “three years versus the last 10.”

“I do feel like we’re at a little bit of inflection point though,” Bear said at a Dec. 12 MISO Board of Directors meeting. He said though MISO is cleared to roll out a sloped demand curve in its seasonal-based capacity auctions this spring, a new capacity accreditation by 2028 and has attained board permission for its newest long-range transmission plan, it still faces a resource gap as soon as summer.

“Now we need members to revise their plans and really roll up their sleeves. … We’ve got to get resources added to the system,” Bear said. He added that even before the surge in data center growth projection, MISO and the Organization of MISO States’ (OMS) resource adequacy survey indicated reserve margin deficits could occur within months.

In September, MISO Independent Market Monitor David Patton agreed MISO is implementing resource adequacy improvements at a “remarkable” clip — a good thing for the sake of future reliability.

“The seasonal capacity auctions and reliability-based demand curve are being implemented in a third of the time it takes other RTOs,” Patton said.

“Pressures on resource adequacy from fleet transition and projected large spot load additions continue and will increase unless MISO and members take mitigating action,” Durgesh Manjure added during MISO’s mid-September Board Week.

“We are losing megawatts faster than we can replace them,” he emphasized.

MISO CEO John Bear listens to reports at December Board Week in The Woodlands, Texas. | © RTO Insider LLC 

Manjure also said the generator interconnection queue isn’t the source of guaranteed resource additions that it used to be. He said approximately 57 GW of new resources have attained interconnection agreements but remain unfinished largely due to straggling supply chains. Manjure said projects could face anywhere from three to seven years of delay before megawatts materialize on the system after signing their interconnection agreements.

The true conversion rate of the interconnection queue “is becoming more and more nebulous,” Manjure said. “It’s becoming harder to predict what’s going to come online.”

However, he said there’s “no dearth” of projects in the queue. Staff often point out that MISO’s 312-GW interconnection queue alone is more than twice the RTO’s peak load.

MISO in late 2024 concluded its members need to add projects at an “unprecedented” 17 GW/year clip to achieve resource adequacy while decarbonizing the grid. That’s triple the rate members have added per year over the past few years. (See MISO Assessment Calls for 17 GW in New Resources Annually.)

The Need for Queue Speed

To get more new generators churning out energy sooner, MISO is fashioning an express lane in its interconnection queue for projects that bolster resource adequacy. The idea — which is set for more workshopping with stakeholders in the coming months — would have select generation developers entering a fast lane devoted to projects with authorization from their state authorities. MISO would perform individual, rather than batch, studies on the projects and funnel them to interconnection agreements quicker. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must.)

MISO’s emphasis on needing more generation expeditiously appears incompatible with its call in late 2024 to officially skip acceptance of a 2024 cycle of queue projects for study. But the RTO insists it has good reason to take a step back — it’s working with a tech startup to create a more automated queue that turns out studies faster. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.)

If MISO gets its way, it will process smaller queues this year and into the foreseeable future. The grid operator has filed with FERC to impose a 50% peak demand cap on the project submittals it will accept into its interconnection queue annually. The 2025 cycle of queue projects is tentatively scheduled to kick off in the third quarter, since MISO intends to have the cap in place before it formally accepts a new cycle. MISO has said smaller queue classes will make interconnection studies workable and realistic.

Sloped Curves to Net More Capacity

MISO’s springtime capacity auctions for the 2025/26 planning year will be the first to feature a sloped demand curve. The grid operator hopes to use the curves as a safety net to have more capacity on hand than strictly necessary to meet planning reserve margin requirements. FERC allowed MISO to use them in place of the vertical demand curve it had been using since 2011. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)

Amid talk of heightened operating risks, MISO filed to increase its current $3,500/MWh value of lost load to $10,000/MWh. The plan is pending before FERC.

MISO, OMS to Outline Possible New Resource Adequacy Standard

Further, MISO has promised to work with state regulators in 2025 to come up with a potential new direction on its resource adequacy standard.

MISO has said it might draw on a combination of measurements gaining attention across the industry, including:

    • Its existing loss of load expectation to capture frequency of events.
    • Expected unserved energy to capture the size of events.
    • Loss of load hours to capture event duration.
    • Value at Risk or Conditional Value at Risk to measure the magnitude of the aftermath of worst-case events.

MISO Director of Strategic Initiatives and Assessments Jordan Bakke told attendees at a November Resource Adequacy Subcommittee that “more investigation is needed” to figure out how risk will play out as its system evolves. MISO has suggested its current loss of load expectation criterion could in the future lead to “materially higher risk” by underestimating system vulnerability.

Bakke said MISO’s one-day-in-10-years loss of load resource adequacy standard “has a number of limitations.” But he also said MISO believes it has some time on its side because the new risks the industry is trying to steel itself against will arise from a “highly evolved” system that is a few years down the road. Bakke pointed out that MISO’s Regional Resource Assessment shows that within 20 years, risk will swing from summer to winter, with emergency events expected to grow in size and be longer lived.

OMS has advised MISO to tread carefully and be mindful of state jurisdiction when crafting a new resource adequacy standard. (See MISO Dips Toes into Potential New Resource Adequacy Standard; States Demand Key Role.)

OMS is standing up a devoted resource adequacy committee to work with MISO. Bakke said the RTO will collaborate with OMS throughout 2025 to develop a recommendation on preferred changes to resource adequacy criteria at the end of the year.

Bakke added “it’s too soon to know” when MISO might be able to employ new criteria. He said it’s MISO’s goal to “illuminate the topic” by providing risk assessments while OMS holds deciding power.

Executive Director of Market and Grid Strategy Zak Joundi has said “we were fortunate in the past” to operate the system reliably simply by preparing for summer peak load.

“That’s no longer the case,” he told attendees at the March MISO Board Week.

Futures to Become Bolder

The grid operator will take a break from long-range transmission planning over 2025 to refurbish its three 20-year futures scenarios, which form the foundation of MISO’s long-term transmission planning. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.) The RTO has promised to come back in 2026 with another portfolio of long-range transmission projects for its Midwest region.

Bear said the changing world means it’s time for MISO to revisit its 20-year transmission planning futures and contemplate more load growth, more electrification and a resource transition in overdrive.

MISO’s projected resource portfolio from its 2024 Regional Resource Assessment. The RTO predicts a 56% share of renewables in 2030 and an 87% share by 2043. | MISO

Meanwhile, regulatory work will begin on MISO’s second, nearly $22 billion LRTP portfolio, approved in December. MISO staff have vowed to appear before state commissions to vouch for the transmission’s importance in its members’ resource planning. (See MISO Board Endorses $21.8B Long-range Transmission Plan.)

Director of Cost Allocation and Competitive Transmission Jeremiah Doner called the second LRTP portfolio a “step forward for the system in the 765-kV transmission,” pointing out that swaths of MISO Midwest lack a 765-kV backbone.

Load Growth Looms

Bear said while MISO has accomplished more resource adequacy initiatives than ever before through the stakeholder process in 2024, he joked that the “bad news” is MISO and stakeholders must consider several more in the coming months.

“My concern is that all the things we’re seeing, our neighbors our seeing. Our reserve margins are getting tighter, and we’re seeing load growth … not seen since the ‘60s and ‘70s,” Bear said during the September board meeting.

“When you start adding load additions the size of small cities, you really have to step back,” he said.

“MISO folks need to stay ahead of the curve,” Board Chair Todd Raba agreed at the time.

MISO executives expect load to grow by about 60% by 2040. That will be paired with an anticipated 87% renewable energy output from the RTO’s fleet. By 2030, the RTO expects more than 50% renewable energy output.

MISO expects a 10%-14% increase in load over the next few years, fueled primarily by the rise of data centers.

“There’s not a state in our footprint that doesn’t want to see that economic development,” MISO’s Bob Kuzman said at Infocast’s inaugural Midcontinent Clean Energy conference in late August.

However, Kuzman warned that data centers need dispatchable, at-the-ready resources. He warned that the replacement generation coming online needs to have the same reliability attributes that departing thermal generators were able to furnish.

“These large AI and data centers need power 24/7/365. … They are not interruptible,” he said.

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Equinor Closes on $3B in Financing for Empire Wind 1

Equinor has closed on the finances for Empire Wind 1, a major milestone for a New York project expected to accrue $5 billion in capital costs over the next few years. 

The company announced the development Jan. 2, less than three weeks before the inauguration of a president openly hostile to offshore wind power.  

But early stage proposals in U.S. waters may be more vulnerable to this hostility than a project such as Empire Wind 1, which already has secured federal approvals and a state offtake contract, has begun onshore construction, and projects a 2027 commercial operation date. 

Molly Morris, Equinor’s senior vice president of Renewables Americas, addressed the federal political landscape at a late-October offshore wind industry conference, saying support from states — particularly New York and other East Coast states — is what has been driving the industry’s growth. (See Equinor Exec Gives Insight on Empire Wind.) 

In a Jan. 2 news release, Morris emphasized offshore wind’s value to national interests: “Today’s financial close maintains our momentum toward bringing a significant source of power to the grid. Empire Wind 1 will strengthen U.S. energy security, build economic growth and fuel a new American supply chain.” 

Equinor said it made its final investment decision on Empire Wind 1 in late 2024 and was able to secure competitive terms for the more-than-$3 billion package thanks to strong interest from lenders. 

Total capital investment — including the offshore wind hub now under construction in New York City and factoring in future investment tax credits — is expected to run in the $5 billion range. 

The history of Empire Wind reflects the bumpy road the offshore wind industry has traversed in the past decade while establishing itself in the United States. 

Equinor acquired wind energy lease areas off the Northeast coast as it leveraged its offshore engineering experience for a move into renewable energy. 

The Norwegian state-owned oil major teamed up with oil super major bp on Empire Wind and Beacon Wind to win contracts with New York, then saw those contracts become untenable in 2022 and 2023 due to soaring prices. 

Equinor and bp dissolved their partnership, with bp taking sole ownership of the Beacon portfolio and Equinor taking Empire. 

In 2024, Equinor won a new state contract for the 810-MW Empire Wind 1 at a much higher strike price: $155/MWh.  

Empire Wind 2 — potentially much larger, at 1,200 MW or more — was paused. 

Equinor said Jan. 2 it still is looking to farm out ownership in Empire Wind 1 to a new partner to enhance value and reduce exposure. 

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How Much of the IRA Can be Saved in 2025?

It has been a year of turbulence and dramatic contrasts in federal energy policy.

The U.S. clean energy transition gained substantial economic momentum from the tax credits, grants and other incentives in the signature legislation of President Joe Biden’s administration, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.

In her last major public speech at the Department of Energy’s Deploy 2024 Conference on Dec. 5, Energy Secretary Jennifer Granholm pointed to the more than 900 cleantech factories and projects announced since the passage of the laws. Every dollar of federal funds spent supporting these facilities has drawn in $6 of private investment, she claimed.

The clean energy transition has become inevitable, inexorable and built to last, Granholm said.

But an increasingly pressing question loomed over each new announcement of IIJA and IRA grant and loan awards: Would the federal dollars and programs continue if former President Donald Trump were to be elected and Republicans gain control of both houses of Congress?

Trump campaigned on pledges to claw back all unspent funds from the IRA and to “drill, baby, drill” to restore the dominance of fossil fuels in U.S. energy policy.

Certainly, energy industry leaders started laying out various scenarios about the fate of clean energy policy in a second Trump administration more than a year before the president-elect and Republican lawmakers will take control of Washington again.

At RTO Insider, our first article appeared on Aug. 2, 2023, with former FERC Commissioner Bernard McNamee discussing what has become an extreme-reorientation scenario, as detailed in the Heritage Foundation’s 920-page Mandate for Leadership, commonly referred to as “Project 2025,” which itself was published in April 2023. (See Plan for GOP President: Cut Climate Programs, ‘Re-examine’ RTOs.)

McNamee authored Project 2025’s chapter on the Department of Energy and related commissions, in which he called for DOE to be renamed the Department of Energy Security and Advanced Science and to be downsized, returning the agency to the core pillars of the 1977 legislation under which it was created:

    • engaging in basic and fundamental science and research through the 17 National Laboratories;
    • cleaning up nuclear waste and weapons sites from World War II’s Manhattan Project and the Cold War;
    • developing storage sites for nuclear waste produced by “civilian” nuclear reactors; and
    • developing new nuclear weapons and naval reactors, led by the department’s National Nuclear Security Administration.

McNamee urged for a full repeal of the IRA and IIJA and called for the defunding or closure of DOE offices that have played a major role in implementing the laws, including the Office of Clean Energy Demonstrations, the Grid Deployment Office and the Loan Programs Office.

The Economics Scenario

More optimistic scenarios emerged early in 2024, with panel discussions at successive industry conferences advancing variations on what has become a dominant post-election narrative: About 80% of the federal dollars from the IRA and IIJA have gone to Republican-led states and districts, a lopsided distribution that is expected to prevent a full repeal.

Speaking at the American Council on Renewable Energy’s Policy Forum in March, Melissa Burnison, vice president of federal legislative affairs at Berkshire Hathaway Energy, said, “Bipartisan benefits from the IRA, from tax policy [are] something that ― even from the most conservative congressional members, we’ve heard ― we’re not going to see a wholesale repeal of the IRA.

“First of all, it’s probably not possible, and second of all, it doesn’t make sense for their constituents.”

A similar talking point for many clean energy advocates has been the Aug. 6 letter that 18 House members sent to Speaker Mike Johnson (R-La.), arguing against repeal of the IRA’s clean energy tax credits.

Before the election, Johnson replied that any rollbacks to the IRA would be made with a scalpel rather than a sledgehammer.

The business case for the IRA continued to spark optimism among the attendees at Deploy 2024, where the industry turned out “in force,” said Aram Shumavon, CEO of Kevala, a grid data analytics firm. “The transition has built enough momentum that the economics of it just make sense. …

“Even in the face of or the prospect of very significant swings associated with some tariffs and things along those lines, and potential significant challenges to some of the programs that create subsidies right now, the economics of zero-marginal-cost fuels and a bunch of technologies that support the evolution of the grid are undeniable,” Shumavon said in a post-conference interview with RTO Insider.

According to LPO Director Jigar Shah, his office still is receiving about one new loan application per week.

The Political Scenario

As they prepare to leave office, Shah and other Biden administration officials have remained advocates for the economic argument for the IIJA, IRA and the clean energy transition in general. The investments made and jobs created are in and of themselves irreversible, they say, and any claw-back attempt might create bad press for Republicans.

Getting money out the door ― which DOE has been doing at breakneck speed since the election ― also has been seen as an effective way to “Trump-proof” those funds. DOE officials have stressed that once the department signs a contract with an organization selected to receive federal dollars ― including companies with conditional loan commitments from the LPO ― that money cannot be clawed back.

Shah has noted that all DOE contracts were honored during the first Trump administration.

But a range of industry analysts and D.C. insiders have warned that the clean energy industry and its advocates should take Trump and congressional Republicans at their word and prepare for shifting priorities, ongoing uncertainty, and some major roadblocks and rollbacks.

A top priority for the new Congress will be extending the 2017 tax cuts, passed during Trump’s first administration, which are set to expire at the end of 2025. The IRA could be “cannibalized” to help pay for those cuts, which could cost an estimated $4 trillion to $5 trillion. According to Alex McDonough, a partner at policy consultancy Pioneer Public Affairs, House Republicans could have a budget reconciliation package to extend the Tax Cuts and Jobs Act (H.R. 1) ready to introduce in the first full week of January.

With narrow majorities in both Houses, even Republicans who favor keeping at least some IRA tax credits may have little wiggle room to negotiate, McDonough warned at the 2024 Solar Focus conference in Baltimore on Nov. 19.

“If we get to a point where there’s a tax bill on the floor that extends the 2017 tax cuts and includes all the IRA provisions in there, cutting them in any which way, they will vote for it,” he said. “They will have to vote for that bill for political reasons; because if that bill fails, they will be responsible for an income tax hike for every American.”

The IRA’s $7,500 rebates for electric vehicles are one of the most frequently mentioned rollback targets. Phasing out the investment and production tax credits for clean technologies also could be pushed up from the law’s 10-year time frame to five years.

Beth Viola, a senior policy adviser at Holland & Knight, expects Trump to issue a post-inauguration hold on further awards of IIJA and IRA funds, including grants or loans with signed contracts.

“It may be that they just slow everything down so that nobody gets those dollars or sees those dollars for a very long time, if ever,” Viola said at the National Clean Energy Week Policymakers’ Symposium on Sept. 25.

Policies and People

While Trump has distanced himself from Project 2025, his calls for “U.S. energy dominance” and rejection of clean energy policies echo former Commissioner McNamee’s rhetoric in the plan.

But, as noted at pre- and post-election industry conferences, the success of such policies could depend on the people who shape and implement them. The potential leaders for energy policy in the Trump administration often say they favor an all-of-the-above approach to energy policy but primarily lean toward fossil fuels.

That description fits both North Dakota Gov. Doug Burgum (R) and Chris Wright, CEO of Liberty Energy, a natural gas company, Trump’s picks to head the Interior and Energy departments, respectively.

Burgum has supported wind energy, which provides more than a third of North Dakota’s electric power but was one of the organizers behind a much publicized campaign dinner at which Trump asked oil and gas company executives for $1 billion in donations, pledging to repeal a range of environmental regulations in return.

Wright has no prior government experience. He has published several online videos in which he has proselytized for the benefits of “hydrocarbons,” and downplayed the existence of climate change and the clean energy transition.

Trump has also selected Burgum to lead a newly formed National Energy Council, of which Wright will also be a member. Trump has said the cross-agency body will focus on “cutting red tape, enhancing private-sector investments across all sectors of the economy and [promoting] innovation over longstanding, but totally unnecessary, regulation.”

Since Trump’s announcement of his selections, both presumptive nominees have remained mum on their plans for their respective departments. If confirmed, early actions might include accelerating Interior’s permitting of energy infrastructure on federal lands, including oil and gas drilling and pipelines, and rolling back regulations that seek to limit fossil fuel use, such as DOE’s final rule raising efficiency standards for gas stoves.

Policies and programs with bipartisan support have the best chance of survival, such as DOE’s regional clean hydrogen hubs and direct air capture hubs, both of which have funding from the IIJA and strong support from fossil fuel companies.

The wild card is the significant growth of artificial intelligence and data centers and the resulting power demand. Trump’s energy policy objectives ― more baseload plants, lower electric bills ― could collide with the plans of some tech giants to power their operations with clean, dispatchable power.

The buzz at most industry conferences since the election is that between Trump’s promised tariffs and new fossil fuel plants, electricity bills aren’t going anywhere but up.

In other words, no one can predict exactly how Trump’s energy policies will play out or the mix of economics, politics and people that could determine what happens next.

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Utilities Seek Rehearing of Order 1920-A’s Accommodations for States

Transmission owners filed requests for rehearing of Order 1920-A with FERC over the holiday break, saying the commission went too far in giving state regulators a role over cost allocation (RM21-17). 

“This decision compels utilities to include, in compliance filings, cost allocation proposals they may neither sponsor nor support as well as consult with relevant state entities in specific circumstances,” Edison Electric Institute said in its filing. “In addition to the legal infirmities, these are not necessary to achieve the commission’s stated goal of meaningful state involvement, a goal EEI supports.” 

EEI said it is seeking rehearing on limited issues “to ensure the statutory rights of transmission providers are not eroded and that Order 1920 is legally durable.” 

Order 1920 required transmission planners to let state regulators in their footprint work on a cost allocation scheme, but Order 1920-A went further in requiring transmission planners to file that even if they disagree with what the states come up with. 

“The commission declares that it will not be required to adopt the transmission provider’s proposal on compliance, ‘even if that proposal complies with the final rule’s requirements,’” EEI said. “Rather, the commission states that it need only select a replacement rate that complies with the final rule and that is adequately supported in the record.” 

EEI also opposes Order 1920-A’s requirement that transmission providers consult with state regulators when they want to change cost allocation methods in the future after they already have complied with the rule. 

The investor-owned utility trade group argued that by requiring transmission planners to file state-backed cost allocation methods under the Federal Power Act’s Section 206, Order 1920-A encroaches on their Section 205 rights as public utilities. The requirement to consult on future changes also encroaches on utilities’ rights under Section 205, EEI said. 

EEI said the decision in Atlantic City Electric Co. v. FERC from 2002 effectively bars FERC from forcing utilities to file states’ cost allocation methods, or consulting with them on future changes. 

“By requiring the public utilities to file the relevant state entities’ proposals, the commission is requiring those public utilities to cede their statutory rights to make filings under the FPA to the relevant state entities and to provide those entities with statutory rights that Congress did not intend them to have,” EEI said. 

The authority to establish a replacement rate does not authorize FERC to provide state regulators with statutory authority reserved solely for public utilities, nor does it authorize FERC to require public utilities to cede those rights to state regulators, it added. 

WIRES Group also filed a request for rehearing on the more state-friendly changes in Order 1920-A, saying the changes exceed FERC’s authority. 

“The commission has no ratemaking or rate setting authority under FPA section 205,” WIRES said. “Section 205 simply vests the commission with the power to review such rates as made by public utilities and to modify them upon a finding of unlawfulness. The power to initiate rate changes rests with the public utility alone, and the commission cannot limit or prohibit public utilities from filing changes in the first instance.” 

The intent of the law was to let public utilities act quickly without obstacles. Courts have recognized that a public utility’s Section 205 filing rights cannot be restricted by requiring negotiations or consultations. 

The National Rural Electric Cooperative Association filed rehearing on the issue but takes a different angle in noting that state regulators often do not oversee its members or public power utilities. 

“Under the laws of many states, the democratically elected boards of directors of electric cooperatives establish the cooperative’s rates independently of a state utility commission,” NRECA said. 

Unlike its investor-owned counterparts, NRECA would not oppose states’ greater roles, but the definition of “relevant state entities” needs to be expanded. Co-ops are mostly regulated by elected boards of directors. 

“The commission should clarify or modify the Order No. 1920‑A to require that all electric consumers in a state are comparably represented,” NRECA said. “Arbitrarily excluding, or allowing a planning region to exclude, the representatives of some electric consumers from the more robust process created by Order No. 1920‑A is clearly unreasonable, and the commission provides no reasonable justification for it given the stated purpose of Order No. 1920‑A’s modifications to the Final Rule.” 

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NV Energy’s Greenlink West Poised for Progress in 2025

With approvals falling into place for NV Energy’s Greenlink West project, construction of the 472-mile transmission line is expected to ramp up in 2025. 

The Public Utilities Commission of Nevada (PUCN) on Dec. 20 approved a construction permit for Greenlink West, a 525-kV line that will run along the west side of the state from the Las Vegas region to Yerington in Northern Nevada. The project also includes three 345-kV lines from Yerington to the Reno/Sparks area. 

And on Dec. 31, the PUCN approved a construction permit for a related project: a 10-mile, 345-kV line between the Comstock Meadows and West Tracy substations in Northern Nevada. 

In its application, NV Energy said the Comstock Meadows to West Tracy line must be in service before Greenlink West is finished. The new line will prevent an overload of 120-kV lines when a Greenlink component — a 345-kV line from Fort Churchill to Comstock Meadows — is completed. 

In addition, NV Energy said the line is needed “based on the total load growth in the Tahoe Reno Industrial Center.” The TRI Center is home to Tesla Gigafactory 1, Google, data center company Switch and other businesses. 

NV Energy’s Greenlink Nevada project consists of Greenlink West along with Greenlink North, a planned 235-mile east-west line across the north side of the state. The two Greenlink lines will connect with NV Energy’s existing One Nevada Line, a north-south line along the eastern side of the state, forming a transmission triangle around Nevada. 

Greenlink is seen as a way to improve reliability and promote development of renewable resources in the state. 

The Bureau of Land Management issued a record of decision approving Greenlink West in September. (See BLM OKs NV Energy’s Greenlink West Line.) 

Greenlink West construction is expected to start in the first quarter of 2025 with a targeted in-service date of May 2027.  

For Greenlink North, a comment period for the draft environmental impact statement (EIS) ended Dec. 11. BLM has set target dates of April 11 for publishing the final EIS and July 31 for issuing a record of decision on the project. 

NV Energy expects Greenlink North to be in service by December 2028. 

In 2024, NV Energy bought land next to its Fort Churchill Power Plant near Yerington to build the Walker River substation. The Greenlink West and North lines will meet at Fort Churchill, and NV Energy calls the Walker River substation the “hub” of the Greenlink project. Clearance and grading of the site began in September, NV Energy said on its website. The utility expects the substation to be completed in 2025. 

‘Continued Approval’ Sought

In a separate action Dec. 20, the PUCN declined NV Energy’s request for “continued approval” of the Greenlink project and approval of a $4.128 billion cost estimate, which doesn’t include one of the project’s 345-kV segments.  

Greenlink’s projected cost has ballooned since a cost estimate of $2.484 billion in 2020. NV Energy has blamed inflation, environmental mitigation and other factors for the increase. (See NV Energy IRP Describes $1.76B Cost Jump for Greenlink Projects.) 

The request for “continued approval” was made as part of the utility’s integrated resource plan filed in May. 

In an order approving parts of the IRP, the commission noted it had already approved all the components of the Greenlink project. There’s nothing in Nevada statute that requires “continued approval” of a project that’s being developed, the commission said in its order. 

“‘Continued approval’ implies a presumption of prudence,” the commission said in its order. “The commission does not find it reasonable or in the public interest to grant a request that equates to a prudency approval for unvetted costs.” 

Instead, the Greenlink costs will undergo a prudency review during a general rate case, the commission said. 

The commission did grant NV Energy’s request for critical facility designation for Greenlink West, a designation that was previously granted for Greenlink North. 

Greenlink is needed to protect reliability, is critical to the development of renewable energy resources and will allow energy transfers between northern and southern Nevada, the commission said. 

But the commission said the utility’s request for a construction work in progress (CWIP) incentive should be addressed in a general rate case rather than in the IRP.