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January 15, 2025

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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 to 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. 

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ERCOT Finds Little Interest in MRAs for San Antonio Units

ERCOT’s request for must-run alternatives (MRAs) for cost-effective solutions to the congestion problems in San Antonio did not receive any responses by a Dec. 30 deadline, putting the solicitation in serious doubt. 

The Texas grid operator said Dec. 31 that given the absence of questions about its request for proposals, it will not post answers or further amendments to the solicitation or other related documents by the Jan. 8 deadline. It will issue a market notice on that date if it determines an amended request is necessary. 

A previous solicitation for an MRA to the Braunig units resulted in one response: a 200-MW, multihour energy storage resource. 

ERCOT is seeking a more cost-effective option than entering into an agreement to use the mobile generators CenterPoint Energy has offered or committing CPS Energy’s Braunig Units 1 and 2 under a reliability-must-run (RMR) contract. (See “ERCOT to Pursue Braunig MRAs,” Texas PUC Shelves PCM Design Over Lack of Benefits.) 

Staff are pursuing an RMR contract, ERCOT’s first since 2016, with Braunig’s largest gas resource, Unit 3. The resource has a 412-MW maximum summer rating. Units 1 and 2 have a combined summer rating of 392 MW. 

CPS, San Antonio’s municipal utility, told ERCOT last year that it planned to retire the three gas units, which date back to the 1960s, in March 2025. However, the grid operator said the plant’s units were needed for reliability. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

ERCOT says the RMR units will be important in addressing the South Texas export interconnection reliability operating limits (IROLs) staff established last year. Staff’s analysis revealed that under certain conditions, such as when high system demand coincides with an outage of a major transmission line or one or more generation units, lines that deliver power from South Texas into San Antonio could be overloaded and possibly lead to cascading outages. 

ERCOT has been in discussions with CPS, CenterPoint and Life Cycle Power over moving 15 large generators and their 450 MW of capacity from Houston to distribution sites in the San Antonio area. The generators, which range between 27 and 32 MW, would provide a less expensive alternative to the $56 million that CPS says it will take to overhaul and continue running Braunig’s other two units. 

PUC Opens Application for Completion Bonuses

The Texas Public Utility Commission began accepting applications on Jan. 1 for completion bonuses of dispatchable, or thermal, energy under the Texas Energy Fund (TEF). 

The fund’s Completion Bonus Grant Program provides performance-based grants to qualifying projects for the construction of new dispatchable generating facilities in ERCOT or the addition of new dispatchable units at existing facilities in the grid operator’s territory. Qualifying projects will add at least 100 MW of new dispatchable generation capacity to the ERCOT grid, the PUC said. 

The TEF’s In-ERCOT Generation Loan Program has received 18 applications for 9.72 GW of potential new generation seeking $5.34 billion in loans. The Texas legislature has allocated $5 billion to the fund. 

The fund was established by state law and approved by voters in 2023. It offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable generation, alongside three other separate programs. 

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EDAM Won’t Eliminate WEIM-only Option, CAISO CEO Says

CAISO’s launch of the Extended Day-Ahead Market (EDAM) will not spell the end of a Western real-time-only offering from the ISO, according to CEO Elliot Mainzer. 

“Participation in the EDAM is voluntary, allowing an entity participating in the Western Energy Imbalance Market (WEIM) to extend its participation to EDAM, to remain only in the WEIM, or to exit one or both markets for any reason,” Mainzer wrote in a Dec. 23 letter addressed to the Bonneville Power Administration.  

“While participation in EDAM necessarily requires that an entity also participate in the WEIM, we remain fully committed to maintaining support for the WEIM indefinitely,” he wrote. 

Mainzer’s letter comes in response to a statement BPA Administrator John Hairston made in his own Dec. 13 letter to Seattle City Light CEO Dawn Lindell, which defended the federal power agency’s continued preference for joining SPP’s Markets+ despite the findings of a BPA-commissioned study showing the agency would realize greater financial benefits from participating in EDAM. (See BPA Touts Markets+ in Response to Seattle City Light Opposition.) 

The production cost study by Environmental and Energy Economics (E3) examined a variety of market scenarios, including a “business as usual” case in which Western entities continue to trade day-ahead electricity in the bilateral market while remaining in their existing real-time markets (either the WEIM or SPP’s Western Energy Imbalance Service) — a scenario in which BPA would realize an estimated $138 million in annual benefits.  

But Hairston’s letter to Lindell noted that BPA expects the existing benefits of the real-time WEIM — in which BPA is a participant — to “erode” as many of its members begin to participate in either of the organized day-ahead markets. 

“As EIM entities move to the Extended Day-Ahead Market (EDAM) proposed by … CAISO, there is no guarantee WEIM will continue to be offered as a standalone program, which is a risk to the potential benefits and long-term viability of a WEIM-only scenario for Bonneville,” Hairston wrote. 

Mainzer’s letter looks to be intended to counter that assertion. 

“We fully expect that some balancing authorities in the West will choose to remain in WEIM without joining EDAM,” he wrote,” he wrote. “These entities would continue to submit base schedules in WEIM as they do today and would be optimized across the entire real-time market footprint, including both entities participating only in WEIM and those participating in EDAM after it launches.” 

The Dec. 19 letter also provided a platform to Mainzer to contrast CAISO’s “incremental” approach to market participation with that of Markets+, which will require its members to participate in both a real-time and day-ahead market and join the Western Power Pool’s Western Resource Adequacy Program (WRAP).  

BPA and most of its “preference” customer base of publicly owned utilities have pointed to the WRAP requirement as a key factor in their assessments favoring Markets+.   

But Mainzer said CAISO has designed its markets in part to factor in the “diversity” of the West and allow its participants to make the decisions that work best for them and their customers.” 

“For example, just as we do not require entities to migrate from WEIM to EDAM, there is also no mandate for market participants to join a particular resource planning or resource adequacy program. Instead, the Western energy markets have been specifically designed to accommodate the decisions of our partners that work best for their unique circumstances.” 

Mainzer’s letter marks the first time CAISO has weighed in formally on BPA’s day-ahead market decision process since the agency initiated the effort in July 2023. BPA staff expect to issue a draft market decision in March followed by a final decision in June. 

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PJM MRC/MC Briefs: Dec. 18, 2024

MARKETS AND RELIABILITY COMMITTEE

Stakeholders Endorse Changes to Accounting of Demand Response in Load Forecasts

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation a quick fix proposal to account for errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast. (See “First Read on Quick Fix for Revising Load Drop Estimate Inputs,” PJM MRC/MC Briefs: Nov. 21, 2024.) 

PJM’s Andrew Gledhill explained that when PJM incorporates hourly load data in the forecast, it produces estimated load drops that intend to determine what load would have been if not for load management deployments. In some instances, however, emergency conditions may be initiated at times when consumers participating in DR programs already have reduced demand. 

He gave the example of the December 2022 Winter Storm Elliott, which saw several blocks of performance assessment intervals (PAIs) declared around Christmas — including during night-time hours — when industrial and commercial DR customers were operating at reduced capacity independent of grid conditions. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

The revisions to Manual 19: Load Forecasting and Analysis, modify two paragraphs to grant PJM flexibility in identifying when the standard load drop estimates may be inaccurate and to apply alternatives. The language also would clarify how the estimates are used in producing the annual forecasts. 

Several stakeholders argued the language was overly broad and more detail would be needed on what methodologies PJM would use and transparency for stakeholders on when they are invoked. Gledhill said there is no one-size-fits-all and PJM prefers to keep its options open-ended. 

Calpine’s David “Scarp” Scarpignato and Gabel’s Rebecca Stadelmeyer offered amendments to the language that would direct PJM to present stakeholders with information should it use the discretion the revisions would offer. Gledhill accepted such an amendment.

Vote on Site Control Requirements Deferred

Stakeholders voted to delay action on revisions to Manual 14H: New Service Requests Cycle Process, which would codify PJM’s interpretation of the site control rules for planned resources in the interconnection queue. Several developers have called PJM’s interpretation overly strict and argued it would require them to retain unnecessary land. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

EDF Renewables Director of Transmission Policy Emma Nix said delaying would allow manual revisions to be informed by a complaint filed by the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United, which argues PJM’s interpretation of the site control rules in the tariff do not conform to its language and would present unnecessary development costs (EL25-22). Nix motioned to have the item removed from the MRC’s consent agenda. 

PJM’s Jason Shoemaker said the application window for Transition Cycle 2 closed Dec. 17 and staff seeks to implement the language quickly to provide developers with clarity on the rules. He added that the vote would not be an end to the RTO’s ongoing conversations with developers on site control requirements. 

“These developers need to have some understanding of how their projects are going to be moved through the process,” he said. “We’d like to see the vote go forward today because it does impact our developers today.” 

The revisions would allow parcels to be removed from a project so long as it continues to meet the minimum acreage and energy output listed in the project application. Land could be added to a project at Decision Point 1 so long as either it is adjacent to the site, or evidence of easements is provided. If the energy output is reduced, the land requirements also correspondingly would go down. 

The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 to specify that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels can be added similarly to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle. 

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement (NSA) to determine permissibility. 

The revisions also would correct Exhibit 10 in the manual, which inadvertently used a diagram from another exhibit when describing how generators interconnect to existing transmission substations.

Discussions on CETL Shifted to ELCC Task Force

The committee endorsed a change to an issue charge to charge the newly formed Effective Load Carrying Capability Senior Task Force (ELCC STF) with addressing a “disconnect” between PJM’s winter-focused accreditation and the use of summer peaks when calculating zonal capacity emergency transfer limits (CETL). (See “Stakeholders Endorse LS Power Issue Charge on CETL,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

Endorsed by the Planning Committee on Nov. 6, the issue charge originally assigned the work to the PC. But ELCC STF Chair Michele Greening said PJM staff found there is a lot of synergy between the CETL discussions and the other two topics the task force is addressing, both on substance and timelines. 

The task force also is in the early phases of working on issue charges addressing the transparency of the ELCC model and how it is used to determine resource accreditation. Both were approved by the MRC during its Oct. 30 meeting. 

The revisions to the CETL issue charge also extended the work timeline to target a FERC filing in May 2025, rather than the first quarter of 2024. 

First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation

PJM’s Chantal Hendrzak presented a first read on proposed changes to PJM’s rules for deactivating resources, extending the notification they must provide PJM before they can go offline, increasing the amount of data that is posted publicly and revamping the compensation for units that enter reliability-must-run (RMR) agreements. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.) 

The tariff revisions would require generation owners to provide 12 months’ notice ahead of their desired deactivation date, in addition to the existing must-offer exception deadlines on units that would not participate in the capacity market. PJM would publish publicly the estimated RMR revenue allocation zonal rate for zones that would be affected by an RMR agreement; postings also would be expanded to include Independent Market Monitor determinations on market power, deactivation response letters and RMR agreement notifications. 

The $2 million cap on project investments that can be included in the deactivation avoidable cost rate (DACR) would be eliminated and the scaling element of the yearly adder on investments would be shifted to a static 10%. A provision that replaces the DACR with the daily deficiency rate if the DACR and multiplier are greater than the deficiency rate also would be removed. 

The proposal is one of three the Deactivation Enhancement Senior Task Force (DESTF) voted on in October, carrying 69% support and winning out over a second PJM-sponsored package with fewer changes to compensation and a proposal from the Monitor that would have limited RMR agreements to five years and required stakeholder notification of agreements at least a year in advance.

Several Manual Revisions Endorsed

PJM’s Ryan Nice presented a slate of revisions to Manual 1: Control Center and Data Exchange Requirements, expanding its backup and emergency communication modes, as well as changes drafted through the document’s periodic review. The committee is set to vote on endorsement at its Jan. 23 meeting.  

He said the AltSCADA communication process allows inter-control center communications (ICCP) links to be transmitted between PJM and transmission owners using simple spreadsheet files in the event that default SCADA software is offline, such as through a cyberattack. The changes also include an expansion of the RTO’s read-only mode that prevents ICCP data from being edited during planned maintenance windows where the risk of incorrect data being submitted is increased. 

The periodic review changes include updating definitions to be clearer and more consistent with other manuals. 

PJM’s Liem Hoang presented a set of revisions to Manual 38: Operations Planning, to include information about the Operational Planning Analysis used in the Day-ahead Market and specify that CEII access is necessary to review the analysis. The language is set to be considered by the Operating Committee on Jan. 9 and the MRC on Jan. 23, with immediate implementation if approved.  

PJM’s Susan Kenney presented a set of revisions to Manuals 27 and 29 to remove outdated references, make grammatical corrections and add a description of how the non-zone network load responsibility is assigned to network customers in Manual 27. The MRC is set to vote on the changes Jan. 23. 

MEMBERS COMMITTEE

Sector Representatives and MC Vice Chair Elected

The Members Committee voted to elect representatives to serve on the Finance Committee for its 2025 term, sector whips and named Steve Kirk of NextEra Energy Marketing to serve as MC vice chair. American Municipal Power’s Lynn Horning will be chair of the committee. 

The new sector representatives on the Finance Committee will be: Susan Bruce, of the PJM Industrial Customers Coalition, representing end use customers; Jeff Whitehead, of Eastern Generation, representing generation owners; Steve Kirk, representing other suppliers; and Laura Yovanovich, of PPL Utilities, representing transmission owners. 

The sector whips for 2025 will be: 

    • John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), for the electric distributor sector. 
    • Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), for the end use customer sector. 
    • David “Scarp” Scarpignato, of Calpine, for the generation owner sector. 
    • Sean Chang, of Shell Energy North America, for the other supplier sector. 
    • Jim Davis, of Virginia Electric & Power Co., for the transmission owner sector. 

PJM Presents Manual Language Detailing Process After FERC Rejection of Stakeholder Packages

PJM presented a first read on a proposal to revise Manual 34: PJM Stakeholder Process to establish a standardized path for PJM to follow when FERC rejects a stakeholder-endorsed proposal. The language is set to be voted on during the committee’s Jan. 23 meeting, with AMP and the Delaware Division of the Public Advocate intending to move and second the motion. 

Acting on its own accord or stakeholder request, PJM could hold a presentation within 90 days of the order on the commission’s rejection and recommend how to proceed. The proceeding discussion would include all possible stakeholder options, such as restarting the stakeholder process, identifying changes that could be made, new proposals or any other decision decided the senior standing committee agrees on. 

Greening said the manual is currently silent on how PJM and stakeholders should proceed after the commission rejects a proposal, leading to instances where there was disagreement on next steps. One such instance followed FERC denying a proposal to implement multi-schedule modeling by using a formula to select energy market offers to be entered into the Market Clearing Engine. The original proposal was rejected by the commission in March, and PJM opted to bring the alternative that received the second-highest vote count for endorsement. (See “Monitor, PJM Present Processes to Enable Multi-schedule Modeling,” PJM MRC/MC Briefs: June 27, 2024.)