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January 7, 2025

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Data Centers and Demand Growth Top 2025 Agenda

Apart from the November election, the issue that has been utterly inescapable is data centers and their insatiable appetite for power. 

From conferences to utility earnings calls to state and federal regulatory meetings to a growing library of reports and research papers, the electric power industry has debated, discussed and wrestled with how to provide the gigawatts of demand from the data centers that are sprouting like mushrooms across the country.  

These increasingly mammoth facilities used for new artificial intelligence services are disrupting traditional utility and regulatory planning models and could accelerate the pace of change across the industry. 

Former FERC Chair Neil Chatterjee noted that winning the AI race with China has become a national security imperative. Consequently, demand growth from data centers is “going to totally upend energy policy and the conventional wisdom that Republicans are for fossil fuels and Democrats are for green energy,” Chatterjee said Dec. 5 at the U.S. Department of Energy’s Deploy 2024 conference. 

“We’re going to need every available electron and … every available megawatt,” he said. “We’re going to figure out energy efficiency, demand response, virtual power plants. How can we get grid-enhancing technologies [online]? How can we get greater optimization for our current grid? All of this will be essential to winning the AI race while simultaneously bringing down the cost of electricity for consumers.”  

The data center dilemma centers first on a familiar mismatch of timescales. Utilities and their regulators tend to plan based on the small, incremental demand growth that has been the norm over the past two decades at least. Planning, approving and building new generation can take three to five years or more. New transmission can take a decade.  

But data center development moves at ever-increasing digital speed, with tech giants like Google, Amazon and Microsoft planning and building new “hyperscale” facilities in two years or less. These companies also have committed to powering their operations with clean energy and have started looking for carbon-free electricity outside established business and regulatory models. 

Google has been on the cutting edge, with recent announcements of a new “clean transition tariff” in partnership with NV Energy, bringing major amounts of previously untapped geothermal power to Nevada’s grid. The company also rolled out a first-ever power purchase agreement for nuclear power from small modular reactors being developed by Kairos Power. 

Microsoft made headlines with its agreement with Constellation Energy to reopen a reactor at the shuttered Three Mile Island nuclear plant in Pennsylvania and its plan to buy 500,000 metric tons of carbon dioxide removal credits over six years from 1PointFive, a carbon removal developer. 

Just how much power will be needed is a moving target. A much-cited figure, traceable to a May 2024 analysis from Goldman Sachs, is that a ChatGPT query can consume nearly 10 times as much electricity as a standard Google search. Also released in May, a report from the Electric Power Research Institute estimated data centers would consume 9% of U.S. power by 2030.

More recent figures from the Lawrence Berkeley National Laboratory show that data centers, which accounted for 76 TWh, or 1.9%, of U.S. energy demand in 2018, hit 176 TWh, or 4.4% in 2023. LBNL predicts future growth ranging from 325 to 580 TWh by 2028, or 6.7 to 12% of total U.S. energy demand.  

The numbers for individual utilities are equally dramatic. As part of a new “Silicon Prairie” region attracting hyperscale development, the Omaha Public Power District put 1 GW of additional capacity online in 2024 and expects to almost double its generation capacity, from 3.6 GW to 6.8 GW, in the next five years, according to CEO Javier Fernandez.  

Georgia Power estimates a threefold increase in power demand from data centers and other economic development by mid-2030, from its current 12.2 GW to 36.5 GW. In April, the utility won approval from state regulators to update its 2022 Integrated Resource Plan, adding three new methane gas- and oil-burning power plants, totaling 1.4 GW of capacity, while also importing 750 MW of coal-fired power from Mississippi and pledging to add 10 GW of renewables by 2035.  

Pivoting the Message

Georgia Power’s IRP update represents what has become a typical response to the data center dilemma: delaying the previously planned closures of coal-fired and nuclear plants and adding new natural gas-fired plants to short-term expansion plans, along with renewables. 

PJM stirred controversy with its proposed Resource Reliability Initiative to meet demand growth by allowing new resources with 24/7 power to jump its historically clogged interconnection queue, a strategy that likely would favor fossil fuel plants over renewable projects that have been waiting in line for years.  

The industry argument for such fast and familiar solutions is simply that SMRs, enhanced geothermal and other emerging clean technologies supported by the tech giants are not yet at scale and may not be for five or 10 years. In the interim, new, dispatchable power will be needed, and existing generation ― including coal, natural gas and nuclear plants ― should be kept online, or in the case of the Three Mile Island and the Palisades nuclear power plant in Michigan, brought back online after a previous closure. 

But the clean energy industry is framing demand growth as a major opportunity to provide new solutions that build on its strengths, such as flexibility and innovation, and to use demand management strategies to reposition data centers as grid assets. 

Since the election, a range of industry leaders have shifted their messaging to align with President-elect Donald Trump’s priority of U.S. energy dominance, and big tech CEOs, including Jeff Bezos of Amazon and Sundar Pichai of Google, have made million-dollar contributions for Trump’s inauguration.  

The takeaway here is that while concerns with climate change may not lessen over the next four years, they likely will not appear in companies’ and trade associations’ public statements and policies.  

Speaking at Deploy 2024, Heather Reams, president of the right-leaning Citizens for Responsible Energy Solutions, said, “You’re not changing your business but pivoting the words you use.” She advised the industry to come with solutions to demand growth and talk with the White House and lawmakers on both sides of the aisle in Congress. 

The Solar Energy Industries Association set the tone Dec. 12 with its 10 policy priorities for the new administration, beginning with an “all-of-the-above” approach to U.S. energy dominance that includes solar and storage. Nos. 2 and 3 on the list are eliminating U.S. dependence on China for a range of clean energy technologies, including solar, and “surging” U.S. manufacturing. 

With the tech giants seeking clean energy, SEIA’s list also promotes solar as a key to unlocking the new power needed to meet data center and AI demand. 

The EPRI report recommends that data centers optimize their computational load by moving certain operations to off-peak hours, to reduce strain on the grid and their own electricity bills.  

Such strategies “could evolve to incorporate real-time energy market dynamics enabling data centers to not only adjust their operations based on grid demands but also actively participate in energy markets to optimize their benefits and support grid stability,” the report says. 

Permitting and Transmission

After AI and data centers, permitting and transmission planning were the other top issues for the clean energy industry in 2024 and will be a critical part of any solutions to demand growth going forward. 

But whether Trump and the Republican-controlled Congress can advance the bipartisan problem-solving needed is an open question. 

Certainly, Trump and North Dakota Gov. Doug Burgum (R), nominated as secretary of the Interior, are expected to come into office prioritizing the rollback of a range of environmental regulations. 

For example, the Biden administration has placed a strong emphasis on community engagement as an essential part of environmental reviews and permitting, to prevent ongoing legal challenges to new projects. Will such requirements be maintained, weakened or dropped in rollback and reform efforts? 

The bipartisan Energy Permitting Reform Act (S. 4753), authored by outgoing Sen. Joe Manchin (I-W.Va.) and Sen. John Barrasso, incoming Senate Republican whip, fell victim to post-election politics during the lame duck session of Congress. Both parties agree that energy infrastructure permitting needs to be streamlined and accelerated, but sticking points include the extent to which any new law should change environmental reviews under the National Environmental Policy Act and whether reform should include transmission. 

For Republicans, permitting reform could be targeted primarily at increasing drilling on federal lands and building out more natural gas pipelines. A new permitting bill could prioritize allowing companies to pay for expedited NEPA reviews, while cutting the time frame for legal challenges to final permitting decisions from its current six years to six months or less. Such changes likely would meet fierce opposition and legal challenges from environmental groups.  

Many Republicans also link action to increase interstate transmission as supporting the deployment of renewable energy, specifically the 2,600 GW of solar, wind and storage sitting in RTO and ISO interconnection queues across the country. 

With Barrasso as Republican whip, EPRA could be used as a starting point for a permitting reform bill that Republicans could try to pass via budget reconciliation, which would require only a simple majority vote. Democrats are countering that this approach would not pass parliamentary muster since budget reconciliation measures, by law, must be related to the federal budget.  

While Congress debates, however, the tech industry continues to move much faster than lawmakers, utilities or regulators and has shown itself adept at circumventing politics. The new buzzword in data center development is “co-location,” meaning that data centers are planned with their own supplies of clean energy, if not behind the meter, then inside the fence. 

A critical question is whether the hyperscalers ― like Google, Amazon and Microsoft ― will backtrack on their clean energy commitments as they continue aggressive expansion of their data centers, and whether others, including cities and states, will follow suit. 

Will Microsoft’s purchase of carbon removal credits be used to offset or rationalize continued fossil fuel use at some of their facilities? Maryland boasts one of the most aggressive emission reduction goals in the U.S. ― 60% below 2006 levels by 2031. But the state passed a law (S.B. 474)  in 2024 allowing data centers to use fossil fuels to power backup generators without going through a standard regulatory approval process, a policy strongly supported by Gov. Wes Moore (D). 

As competition grows between states to attract hyperscalers and their data centers, will such workarounds become a new norm or just one of many possible solutions that will emerge as the demand growth landscape continues to evolve in 2025? 

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Measured Praise for Clean Hydrogen Tax Credit Rules

The IRS has issued final clean hydrogen tax credit rules that balance the contentious and complicated matter well enough that industry and environmental advocates alike can find something positive in the details. 

But the Jan. 3 announcement — more than two years in the making — landed less than three weeks before the inauguration of a president whose policies and priorities may reshuffle the landscape for the U.S. clean hydrogen industry. 

The Fuel Cell and Hydrogen Energy Association hailed policy changes incorporated in the final rules but described its issuance as a milestone rather than the destination in an “extremely complex” matter. 

“There are also multiple areas where implementation and timing will be up to the incoming Trump-Vance administration,” CEO Frank Wolak said in a prepared statement. 

The section 45V Clean Hydrogen Production Tax Credit was authorized in the Inflation Reduction Act, which was signed into law in August 2022. The proposed guidance for 45V was not issued until late December 2023. Final guidance took an additional year to land, as 30,000 public comments were submitted, and multiple federal agencies collaborated intensively. 

Building up a clean hydrogen industry in the United States was among President Biden’s signature initiatives, but progress was slow during the two-year wait for the final rules and the key clarifications they provide on what qualifies as “clean.” 

Producers will need to wait a few more weeks for the Department of Energy to issue its updated 45VH2-GREET model so they can calculate the section 45V tax credit. (GREET is the Greenhouse gases, Regulated Emissions and Energy Use in Technologies life cycle analysis suite developed by the Department of Energy’s Argonne National Laboratory.) 

Hydrogen holds promise as a fuel that does not generate carbon emissions, but it is expensive to produce. The Biden administration’s push is to lower the price of producing clean hydrogen while also lowering carbon emissions associated with its production. 

Environmental advocates pressed for tight rules on the emissions-free energy used to generate clean hydrogen and industry representatives pressed for looser controls that would help make green hydrogen more economical. 

In their Jan. 3 news release, the U.S. Department of the Treasury and Internal Revenue Service promise clarity, safeguards and flexibility in the rules, which drill down to grid regions, hourly accounting, upstream methane leakage, carbon sequestration, fugitive methane use and temporal matching of electricity generation and hydrogen production. 

The guidance stretches 379 pages. Wolak noted that it is extremely complex, “and will require intense evaluation by project developers to understand all the nuances and how they will apply to their specific facilities.” 

It is scheduled to be published Jan. 10 in the Federal Register. 

John Podesta, senior adviser to the president for international climate policy, said in the news release: “The extensive revisions we’ve made in [these] final rules provide the certainty that hydrogen producers need to keep their projects moving forward and make the United States a global leader in truly green hydrogen.” 

Wolak said the final rules are not the final word: “This issuance of final rules closes a long chapter, and now the industry can look forward to conversations with the new Congress and new administration regarding how federal tax and energy policy can most effectively advance the development of hydrogen in the U.S.” 

Other organizations had mixed reactions, but most had something good to say about the rules, even if they also offered some criticism. 

Clean Air Task Force senior U.S. director Conrad Schneider said: “We appreciate Treasury moving toward better hydrogen policy in its final rule for clean hydrogen production. … We hoped to see stricter guardrails around the use of existing clean electricity to make hydrogen, but we are glad the final guidance includes criteria for determining the incrementality of existing clean electricity, especially existing nuclear energy, that accounts for the unique circumstances of each plant. We are, however, disappointed in Treasury’s decision to push hourly matching from 2028 to 2030, and we worry that this could cause at least some increase in emissions in the short term.” 

Constellation Energy Corp., the nation’s largest nuclear reactor operator, applauded a change from the tentative rules that will allow existing nuclear plants to claim tax credits for powering clean hydrogen production. But the company stopped short of any commitment. “Constellation is carefully reviewing the impact of the final rules as well as newly proposed electric transmission charges on the feasibility of its proposed clean hydrogen project at the LaSalle Clean Energy Center and Constellation’s role in the MachH2 Hub,” the company stated in a news release. 

CEO Joe Dominguez added: “While any incrementality limit is incompatible with the conclusion that clean hydrogen customers should be able to use reliable nuclear energy from America’s fleet of plants, the final rule is an important step in the right direction.” 

Investment firm Jefferies said Jan. 3 that it does not expect operators of existing U.S. nuclear plants to pursue the clean hydrogen market because data center contracts are more lucrative and less risky. 

Business Council for Sustainable Energy President Lisa Jacobson said: “The release of the final rules will allow project developers and investors to better assess credit eligibility and open investment opportunities in the U.S. hydrogen industry. The rule provides clarity and flexibility in several areas but will also require continued engagement with the Trump administration and Congress on a number of critical open implementation issues.” 

The Environmental Defense Fund said 45V presents an opportunity to reduce pollution while building new markets. “Clean hydrogen can help clean up parts of the economy that are hard to decarbonize any other way, but only if we do it right,” said Beth Trask, EDF vice president for global energy transition. “Proper implementation of the production tax credit could help catalyze private investment, lower costs and drive global demand for American-made hydrogen. But risks remain that public incentives for clean hydrogen could go toward fossil fuel-based projects that offer no real climate benefit and undermine the integrity of the U.S. hydrogen market.” 

The National Resources Defense Council took a similar stance. “The final guidance is an important step towards a truly clean hydrogen industry. The rule provides much needed certainty for the industry and positions U.S. producers to be competitive in the global market,” NRDC hydrogen advocate Erik Kamrath said. “The extra flexibilities granted to the green hydrogen industry are not perfect from a climate perspective. But the rule maintains key protections that minimize dangerous air and climate pollution from electrolytic hydrogen production while also protecting U.S. taxpayers and electricity consumers.” 

Earthjustice was less complimentary. “The Biden administration’s tax guidance supports clean hydrogen projects that by and large do not worsen climate and health-harming pollution, but more protections are needed,” legislative director for climate and energy Chris Espinosa said. “The administration included several significant loopholes for dirty hydrogen producers to enjoy the benefits of this important climate program.” 

CNX Resources, an independent company extracting natural gas from shale in the Appalachian basin, said the 45V rules do not work for its purposes: “The Department of Treasury’s recognition of captured waste coal mine methane (CMM) as a feedstock for hydrogen production is validation of its inherent environmental and economic benefits and an important step in continuing to monetize the value of this unique asset. However, we believe that the final 45V implementation rules are overly restrictive across a range of feedstocks and do not currently appear to create sufficient economic incentives for the company to expand its CMM capture operations for hydrogen end use.” 

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Nickell: SPP’s Culture Paves Way for its 2025 Success

In the waning hours of his first full day as SPP’s CEO-in-waiting, Lanny Nickell was deep into a phone conversation with a reporter and laying out his plans for 2025.

He said his success, and that of SPP, will be based on its stakeholder driven approach with its members — in other words, its corporate culture.

“Culture is our secret sauce. That’s what’s allowed us to be successful, and that’s what’s going to allow us to be successful in the future,” Nickell said. “To me, our culture is the foundation upon which I plan to build pillars of ambitious strategy, high visibility and operational excellence.”

Told that sounded like an answer from his interview for the CEO’s job, Nickell said, “It was.”

Having nailed the interview, he now prepares to take over the reins full-time following a three-month transition period with his predecessor, Barbara Sugg, before facing the “enormity of the task ahead.” (See SPP Names COO Nickell to Replace Sugg as CEO.)

“I think we can do it in a way that presents a tremendous opportunity to provide a lot of value,” he said. “Continuing to work on this ‘grid of the future’ is a big goal for me. That goal includes enabling quicker connection of more generation and helping our members interconnect large loads that are seeking service in our footprint. We have to do this in a way that’s very quick and reliable, continuing the progress we’ve already made on improving resource adequacy.”

With its Grid of the Future initiative, SPP looks beyond normal planning horizons to determine what the future holds for the grid operator and its stakeholders, region and industry. An addendum to the RTO’s 2023 Grid of the Future report includes recommendations to address artificial intelligence, grid-enhancing technologies and the load of the future that will be incorporated into various working group plans in 2025 and beyond.

“The future of the electric grid is vitally important to our stakeholders, and this research sets the stage for the many discussions that will occur among stakeholders to prepare SPP to meet the needs of its members,” Sugg told stakeholders in December.

The author of both documents, the Future Grid Strategy Advisory Group, said the addendum is intended to capture the grid’s future needs as they continue to “evolve at a rapid pace.” The advisory group is collaborating with the Resource and Energy Adequacy Leadership (REAL) Team to host a Load of the Future Symposium March 3-4.

The REAL Team has been charged with assessing SPP’s current resource adequacy (RA) construct and “anticipated challenges resulting from resource mix changes, extreme weather impacts, increased demand and evolving consumer behaviors.” It plans to work with several stakeholder groups and state regulators in providing feedback on 2025’s loss-of-load expectation study and effective load-carrying capability, seasonal RA requirements analysis and the future resource mix/expected unserved energy study.

Nickell made it apparent he places a lot of importance on the REAL Team’s work when he told its members in December that “this is the right committee … resolving those challenges, because that’s where the majority of our challenges are.” (See “Nickell Looks Forward as CEO,” SPP Briefs: Week of Dec. 16, 2024.)

“We’ve done a lot of work in that regard. We have more to do, and we want to make sure that that we continue that focus,” Nickell told RTO Insider.

The challenges are daunting. SPP says excess generating capacity in its footprint is shrinking to “dangerously” low levels and it increasingly is dependent on more variable resources — including the nation’s largest wind generation fleet with more than 33 GW of installed capacity — as thermal generators retire. With large loads and electrification continuing to increase, the RTO says demand could increase by 25% before 2030.

Despite its members building $12.4 billion in transmission upgrades between 2006 and 2023 and another $3.5 billion of additional upgrades in progress, the grid operator says it still needs significant amounts of new generation and transmission.

Having streamlined the current generator interconnection queue — average study time has been reduced from seven years to four — SPP staff is reinventing it as an integrated part of the annual transmission planning process. SPP says that will result in a fairer sharing of upgrade costs, more financial certainty for developers, better transmission solutions, and more reliable and affordable energy sources.

Nickell called the consolidated planning process “a big deal” and said he wants to move it forward.

SPP also will move forward with its development of a new approach to allocating GI costs. It says requiring all GI customers to pay a fee contributing to the overall system transmission buildout will bring regional planning and interconnection studies together, making both processes more efficient and leading to a better system expansion.

That has bolstered SPP’s case for expanding its RTO footprint and standing up a day-ahead market offering in the Western Interconnection.

SPP’s service offerings and proposed markets in the Western Interconnection | SPP

“Continuing our growth of SPP’s services and footprint is another high priority,” Nickell said. “Just to continue that progress in a way that’s as beneficial to current and future members.”

The expansion of its RTO footprint into the Rockies is proceeding in the background, as did the previous additions of Nebraska public power districts in 2009 and the Integrated System in 2015. A strike team of the seven western organizations interested in SPP membership is working with staff on joint operating agreements with the western RTO’s neighbors; a final version is expected by the end of 2025.

Potential Markets+ participants will open the year in January in Tempe, Ariz., where they will consider the remaining protocols that need to be approved as Phase 2 of the market’s development begins in earnest. SPP lists nearly three dozen entities participating in the work, many of which must agree to funding agreements for the second phase.

“There are many utilities in the West that really appreciate how we do what we do,” Nickell said. “They love our governance model and having a voice in the stakeholder process. They’re going to love the immense benefits they can get out of leveraging a diverse set of resources available in the Pacific Northwest, Desert Southwest and the current SPP market, as will our members.”

The Bonneville Power Administration, the big dog in the Pacific Northwest, has said that is the reason it is following through on its $25 million funding commitment to Markets+’ development, despite several studies that claim CAISO’s competing Extended Day-Ahead Market offers more benefits. BPA says it is following the wishes of its customers and preserving a choice between the two markets, literally mirroring remarks by SPP staffers who say they just want Western utilities to have a choice. (See BPA: Funding Markets+ Phase 2 Preserves Choice.)

The Pacific Northwest’s congressional delegation twice has sent letters to BPA saying the agency has failed to make a financial case for joining Markets+. (See BPA Has not Made ‘Business Case’ for Markets+, NW Senators Say.)

BPA plans to issue a draft decision on which market it will join in early March. That will open a public comment period, after which the agency will make its final decision in early May.

SPP also is waiting on word from FERC over its response to the commission’s deficiency letter. The grid operator filed its response in September, asking for an answer by Nov. 20. Arizona Corporation Commissioner Nick Myers told several of his fellow Western commissioners during a Dec. 20 conference call that after recent discussions with FERC staff, he believed a decision is imminent.

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How FERC Under Trump Might Advance Energy Affordability in 2025

The direction FERC takes under President-elect Donald Trump’s second term is up in the air, but between his campaign promises and a major complaint filed just before the holidays, the commission may spend some of its time on cutting costs to consumers. 

During an election year in which the cost of living was a major theme, Trump promised to halve energy bills — including electricity, gas and transportation — within one year of his second term by expanding domestic resources and infrastructure.  

Then in late November, consumer groups filed a complaint seeking greater oversight of local transmission planning, which they claim has contributed to higher bills consumers have faced in recent years. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.) The complaint and a recent RMI report claim that local transmission lines can fall into a gap, with RTOs more focused on regional plans and many states assuming the RTOs and FERC will oversee them. 

Transmission is the fastest-growing part of customers’ bills, with the Energy Information Administration reporting in November that spending on distribution and transmission has been responsible for overall higher industry spending in recent decades.

In an interview with RTO Insider, FERC Commissioner Mark Christie pointed to J.D. Power & Associates’ most recent survey of residential customers, which reported the highest average bills in the survey’s history at $182/month and a fourth straight year of declining customer satisfaction.  

FERC gives transmission developers a presumption of prudence when they file for cost recovery under its formula rate rules, meaning opponents have a higher burden of proving any overspending. “It’s another part of many things that FERC does that have contributed to this rapidly rising cost of transmission,” Christie said. 

Curtailing that presumption, as well as transmission incentives for lines that do not go through a “credible” certificate of public convenience and necessity process, would lead to states starting to review transmission more often, as it would align the utilities they oversee with that goal, he argued. 

“What’s happened over the last 20 years with the advent of RTOs is that the various states have either removed or taken away or restricted the ability of their state utility commissions to vet these local projects as well as regional projects,” Christie said. 

Some states like Virginia, where Christie was a regulator, kept their transmission oversight. PJM, meanwhile, does a good job on planning regional transmission lines, he said. 

“Where they do not do [a good] job is on the local projects, which in PJM are called supplementals, and … about 80% now of the transmission costs in PJM are coming from these local projects,” Christie said. (See Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros.) 

The best place to review local projects, which are by definition only inside the territory of one utility and often involve more basic grid upkeep like replacing old infrastructure, is at the state level. 

“FERC cannot change state laws, obviously, but what FERC can do is stop giving a presumption of prudence for projects that are coming out of states where they’ve not been given a thorough vetting,” Christie said. 

WIRES Weighs in

WIRES Executive Director Larry Gasteiger pushed back against the consumer groups’ complaint and defended local transmission planning generally in an interview. 

“This complaint is a distraction from all the work that really needs to get done on getting transmission that we need today built more efficiently and faster,” Gasteiger said. “It’s going to be a distraction from compliance with Order 2023. It’s going to be a distraction for compliance with [Order] 1920 because it’s going to pull on resources from the commission; from the transmission developers; from all the stakeholders to deal with an issue that’s, frankly, unnecessary.” 

Local transmission planning already is adequately overseen, with stakeholders given a chance to review plans in detail, Gasteiger argued. While the issue has been brought up repeatedly over the years, Gasteiger said none of the critics can point to specific projects in which the industry overbuilt transmission because of a lack of oversight. 

“There’s been a longstanding openness towards reasonable transparency and reasonable access to information,” Gasteiger said. “I think my sense is that transmission owners are generally open to that. But that’s not what this is about. This is really about adding a lot more process, a lot more requirements now around local transmission, further burdening it. It’s only going to make it take longer. It’s only going to make it become more costly, and it’s only going to make projects riskier for transmission developers to get done.” 

Local transmission development is a necessary process, WIRES argued in a report in 2021. 

“What we don’t want to see is jeopardizing success stories where you have been able to get transmission developed like in local transmission,” Gasteiger said. “It’s not an either-or. The fact of the matter is, if you want to have more regional transmission development, it’s only going to create requirements for more local transmission development.” 

It’s not All Local

With FERC issuing Order 1920-A, which won more support from states as it gave their regulators a larger role in regional planning, opinions are split on whether it will save money if it survives legal review. 

Christie filed a dissent against the initial Order 1920 but supported the move to give state regulators a more formal role. However, he still feels that 1920-A has its shortcomings, including a failure to do anything about local transmission. 

“It’s not going to do anything to lower costs. It’s a bizarre argument,” Christie said. “It’s going to actually increase costs because the whole goal of 1920 was to increase transmission spending by $3 [trillion] or $4 trillion. … How can that lower costs?” 

Joshua Macey — associate professor at Yale Law School, where he teaches energy law — said the answer to Christie’s question is by increasing competition. 

“When you look at the history of electricity regulation in the last 30 years, there’s overwhelming evidence that competition has driven down costs,” Macey said. “There’s been countless studies showing that transmission constraints reduce competition, increase generator market power and lead to congestion that drives costs.” 

The political discussion around transmission expansion has focused on expanding access to renewable energy, which is tied to liberal states’ energy policies, he added. More transmission would help expand renewables, as well as make the grid more reliable and increase competition. 

“I think creating barriers to transmission would not be consistent with the Trump administration’s goal of reducing prices, though it might be consistent with the goal of protecting fossil resources,” Macey said. 

The Energy Markets

Increasing competition in the power markets also could help lower prices, with Macey suggesting an auction-based approach to radically reduce interconnection queues. 

“You would auction off positions in the queue to the highest bidder,” Macey said. “You would fix resource adequacy markets, which … includes raising offer caps in the energy market; having meaningful nonperformance penalties in capacity markets; and then essentially requiring that when conducting a regional transmission plan, you also assess the benefits of increasing regional transfer capability.” 

A major factor on electricity prices is the price of natural gas, which EIA reported has gone from an average of just over $2/MMBtu in November to well over $3/MMBtu by the end of year, with the agency expecting it to average that latter price the rest of the heating season. 

Impacts on natural gas prices were the main reason the Rhodium Group forecast price increases if the Trump administration rolls back the Inflation Reduction Act, which has been a goal of many in the Republican Party. Rhodium estimates full repeal would lead to higher energy bills of $489 annually for the average customer by 2035. 

The law is “transitioning a major source of natural gas demand, the power sector, away from natural gas,” Rhodium Associate Director Ben King said in an interview. “That has the impact of reducing the price of gas, so it just makes things a little bit cheaper.” 

Getting new supplies of generation onto the grid also can help the power industry hedge against the huge price spikes from abnormal events in the natural gas market, such as February 2021’s Winter Storm Uri, or Russia’s invasion of Ukraine and the subsequent scrambling of global natural gas supplies, he added. 

Increasing natural gas demand in the power sector has impacts that go much further afield than higher electricity prices. It also means higher prices for industries that use gas as fuel and end-use customers who rely on it for heating, King said. 

One can find the opposite argument from conservative groups, with a letter to Congress on the IRA’s two-year anniversary signed by Competitive Enterprise Institute, Americans for Prosperity and more than 50 conservative groups arguing its full repeal would save money. 

“The cost of these subsidies may reach $1 trillion or more, but the tax dollars squandered are only part of the burden,” the groups said. By favoring renewables over “conventional and reliable resources,” the “unavoidable result is costlier energy bills — the last thing the American people need.”

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FERC to Weigh in on Cost Recovery of Oak Creek’s Early Retirement

FERC has opened hearing and settlement procedures into the more than half-billion dollars We Energies is asking customers to foot for the early retirement of the coal-fired Oak Creek Power Plant in Wisconsin.

We Energies requested to recover $510.5 million of unamortized investment for the Wisconsin coal plant through its wholesale rates (ER25-316). The company said it will retire the remaining two of Oak Creek’s four units — first started up in the mid-1960s — at the end of 2025, leaving an estimated remaining expected composite life of about 17 years and $698.7 million in unamortized plant balance. The company said it has a retirement reserve of approximately $188.2 million to offset the amount.

We Energies said that even with the ratemaking treatment, wholesale rates are set to decline about 2.7% with the coal plant’s retirement and estimated overall savings between $817 million and $1.7 billion for its customers. The utility said it “no longer expects [Oak Creek] to provide net economic benefits to its customers due to the current regulatory climate.”

The utility told FERC its decision to retire the plant early and seek cost recovery is on par with the commission’s 1996 Yankee Atomic decision, in which it allowed the owners of the Massachusetts nuclear plant full recovery of unamortized investments and operations and maintenance expenses even though it shut down prematurely. We Energies said Oak Creek has operated “safely and reliably for nearly 70 years prior to retirement, and that it has performed consistently and at a reasonable cost compared to other coal plants” in the U.S.

However, Cloverland Electric Cooperative argued We Energies’ estimated savings exclude the cost of new generation the utility will need to replace Oak Creek’s output. The cooperative also said We Energies’ assessment of Oak Creek’s remaining useful life is overblown because it relied on “stale data” from a 2012 depreciation study.

The commission said We Energies’ accounting request might be unreasonable but that it could not make a determination based on the filing and protests alone. It placed the rates into effect subject to refund and conditioned on the hearing and settlement outcome.

We Energies requested an effective date of Dec. 31, 2024, for recovery on Oak Creek Units 5 and 6, which were retired in mid-2024, and a Jan. 1, 2026, effective date to begin the amortization period for Units 7 and 8, which are planned to operate through the end of the year.

Units 1 to 4 were retired in the 1980s.

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How Much are Batteries Displacing Natural Gas on CAISO’s Grid?

More than 11,000 MW of battery storage resources are now deployed across CAISO’s grid — with much more on the way.

But how much are California’s batteries really displacing gas-fired generation?

Answering that question isn’t easy, according to CAISO staff and other electric industry experts, who say that while batteries are having a notable impact, several factors — including weather conditions and the behavior of storage resources — complicate the narrative that they are displacing gas on the grid.

“You can confidently say that batteries are displacing the need for natural gas energy production, but — and this is a large ‘but’ — batteries are not displacing the need for natural gas capacity just yet,” Carrie Bentley, CEO and co-founder of Gridwell Consulting, told RTO Insider.

Battery buildout has coincided with the need for additional capacity to ensure reliability, especially as 2024 saw another record-breaking year for high temperatures. Reliability modeling indicates that most, if not all, of the gas fleet is still needed, as well as all the current and planned batteries for the next decade, Bentley added.

“This is not as bleak for the environment as it sounds because batteries are displacing the gas fleet energy production and therefore lowering natural gas emissions,” Bentley said.

No ‘One-for-one Displacement’

Energy storage capacity on the CAISO grid grew from under 500 MW in the summer of 2020 to 11,200 MW as of June 2024, representing a “significant” pace of deployment, Sergio Dueñas Melendez, the ISO’s battery storage sector manager, said in an interview with RTO Insider.

CAISO’s Western Energy Imbalance Market includes an additional 3,500 MW of battery capacity, according to a June 2024 report from the ISO’s Department of Market Monitoring.

While Dueñas Melendez noted that the ISO does not currently have a metric to determine whether batteries have displaced the need for gas on California’s grid, the addition of energy storage has had an obvious impact.

“Now that we have way more batteries, we definitely are seeing that batteries are charging in periods of high solar radiation and discharging as the sun starts to set into the afternoon peak and the peak hours,” Dueñas Melendez said. “Earlier this year, the ISO broke a record of peak battery discharge, with over 7,000 MW in a given five-minute interval of battery discharge.”

Pointing to data from the DMM showing the change in hourly generation by fuel type between 2022 and 2023, “you can see how gas, on average, especially in certain hours, has reduced its output, and batteries have increased their output,” CAISO COO Mark Rothleder told RTO Insider.

But the behavior of batteries complicates making an exact calculation of the level of displacement.

“You will not see a one-for-one displacement because a four-hour battery is not going to perfectly displace a dispatchable gas resource over the day,” Rothleder said. “The capability of the batteries over four hours versus being able to ramp day-over-day and intraday of the gas fleet doesn’t allow you, at this point, to fully replace the gas fleet with batteries. But there is certainly energy displacement.”

Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, added that a one-to-one replacement of gas with storage supply cannot be assumed because of the dozens of storage and gas resources with varying costs and locations. He also noted that, given the level of storage in the system, those resources can also be displacing of other types of supply, not just gas — the exact value of which is also unclear.

“Since the market determines the optimal dispatch of all resources based on their bid costs and attributes, it can’t precisely track in isolation the specific volumes of gas supply displaced by storage resources compared to other supply types,” Bautista Alderete said in an email. “Changes in the level of gas supply dispatched at any given time depend on various factors, including the relative bid costs of different technologies, demand levels, hydro conditions, renewable production, resource availability, gas prices, seasonal conditions, transmission congestion and broader supply/demand conditions in the WEIM that influence the level of transfers.”

Weather Impacts

The degree to which batteries displace gas can also depend on prevailing weather conditions.

A May 2024 blog post from energy data provider Grid Status contended that battery storage was the “standout performer” in CAISO last spring, saying that “batteries are displacing natural gas when solar generation is ramping up and down each day in CAISO.”

But the report only cited data from April, which does not show the full picture, according to Bentley.

“April is not indicative of the annual trend, because what’s happening in April is you have very low demand, but it’s starting to get sunny,” she said. “This is basically the perfect time for batteries.”

California successively broke records for summer heat in 2023 and 2024, which drove high — although not record —peak loads. While natural gas usage remained high, it decreased as batteries grew, even as peak demand increased.

According to CAISO data, the ISO’s 2023 peak demand occurred on Aug. 16 at 44,534 MW. In the early evening hours, as solar ramped down, natural gas peaked at 26,490 MW, with batteries dispatching at 927 MW. As the evening progressed, batteries ramped up, peaking at nearly 3,000 MW, while natural gas ramped down to just over 25,000 MW.

The 2024 peak of 48,353 MW occurred on Sept. 5. As solar ramped down in the early evening hours, both gas and batteries ramped up well into the night. Despite the increased net demand and record-breaking heat compared with the prior year, the natural gas peak topped out at just over 23,000 MW, while battery output rose to over 6,000 MW — reflecting a seasonal pattern that resulted in an “uneventful” summer despite periods of extreme heat, according to CAISO. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.)

When considering different periods and associated trends, all system conditions must be considered, Bautista Alderete added.

“The supply mix will inherently be lower across various technologies to meet the demand on a spring day with a peak of 30,000 MW, compared to a much higher supply mix needed to meet the demand on a summer day with a peak of 50,000 MW,” Bautista Alderete said. “Naturally, a higher level of supply is required to meet peak demand during the summer.”

The growth of battery energy storage in tandem with the decrease of natural gas is expected to continue. The California Energy Commission projected the need for 52,000 MW of battery energy storage by 2045, a goal that CAISO’s Dueñas Melendez said the state is on track to meet.

“We have more in the queue than that,” Dueñas Melendez said. “The real challenge — across the different agencies, for developers and for the ISO — is to be able to manage that influx in an orderly way to get to that goal.”

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CAISO Leaders Look Ahead to 2025 with Confidence

CAISO, California and other parts of the Western Interconnection are moving into 2025 with a heavy load of priorities: implementing a day-ahead market, developing the transmission and other infrastructure needed to meet ambitious climate goals, and moving forward with new and continuing initiatives to address some of the ISO’s biggest challenges.  

But the ISO is no stranger to ambitious workloads.  

“We’ve been in a heavy lift for several years, and we’ve already been anticipating this, and so we’ve been preparing,” CAISO COO Mark Rothleder said in an interview with RTO Insider.

Key among CAISO’s priorities: continuing the steadfast work required to implement the Extended Day-Ahead Market (EDAM) in time for the 2026 launch date.  

“2025 is going to be a major, major focus on implementation of EDAM,” CAISO CEO Elliot Mainzer said at a Dec. 18 joint meeting of the ISO Board of Governors and Western Energy Markets Governing Body.  

Several entities have committed formally to joining EDAM over SPP’s Markets+, including PacifiCorp, Portland General Electric, Los Angeles Department of Water and Power, and the Balancing Authority of Northern California. Others have indicated a leaning toward joining in the year ahead, including Idaho Power, NV Energy, Berkshire Hathaway Montana, and Public Service Company of New Mexico. 

Others, including the Western Area Power Administration’s Desert Southwest Region, along with Arizona G&T Cooperatives, have indicated strong interest. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.) 

PacifiCorp’s “go-live” date is scheduled for the spring of 2026, and PGE’s is slated for that fall.  

“We’re going to be doing a lot of work this year to keep both of those entities on track for implementation,” Mainzer said. “I’m very confident that we’re going to continue making progress there.”  

But this won’t come without challenges. PacifiCorp, the first Western entity to begin taking steps to join EDAM, already faces scrutiny over its implementation process.  

During the Dec. 18 meeting, Carrie Bentley, a consultant representing the Western Power Trading Forum (WPTF), told the ISO board and Governing Body of WPTF’s intent to file a FERC protest in January over PacifiCorp’s proposed tariff changes to implement EDAM.  

“WPTF has significant concerns with this filing, specifically that PacifiCorp proposes to allocate virtually all congestion revenues it receives from … CAISO to measured demand,” Bentley said in the Dec. 18 meeting. “At the most basic level, PacifiCorp’s filing goes against a foundational aspect of the EDAM market design — that fundamentally, EDAM is a day-ahead market overlaid on OATT transmission rights, and it’s not a full ISO or RTO that includes congestion management instruments.”  

PacifiCorp’s filing, Bentley added, “hands opponents of EDAM a valuable weapon to undermine it, which is completely unwarranted,” and was not part of the EDAM design agreement.  

Mainzer validated Bentley’s concerns.  

“We are very aware of the nature of your concerns,” Mainzer said. “I think we share your optimism and hopefulness that this matter can be resolved in a mutually acceptable manner, and we will continue to work with PacifiCorp and others to support what they need to bring it to a satisfactory resolution.”  

‘In Good Shape’

In 2025, reliability will be — and always is — “job number one,” Mainzer said, emphasizing that the ISO already has begun planning for winter.  

CAISO’s forecast team expects above-normal temperatures across California and in the Desert Southwest (DSW) from December through February, with the highest likelihood of above normal temperatures in the southern region. In contrast, there’s a greater potential for below-normal temperatures in the Pacific Northwest.   

Northern California saw above-normal rainfall through early December, Mainzer noted, which then “dissipated a bit” as the month progressed. Between December and February, there is a projected risk of below-normal precipitation for the Desert Southwest and a higher likelihood of above-normal precipitation in the Pacific Northwest.  

Current reservoir conditions across California and the West are at about half-capacity, so the expected precipitation in the Northwest could help the region recover some of its hydro storage, with the Desert Southwest expected to remain at greater risk of low water conditions, Dede Subakti, the ISO’s vice president of system operations, wrote in a Dec. 20 posting on the ISO’s Energy Matters blog. 

“We’re going to be keeping a close eye on the forecast, temperature and precipitation,” Mainzer said. “Fortunately, given this outlook, our operations team is reporting that all major transmission paths are expected to be fully available to support transfers across the region, allowing market participants in balancing areas to move energy across the system as needed.”  

Resource adequacy is “looking good,” Mainzer added, showing sufficient supply to meet firm demand through the winter.  

CAISO has intensified its winter readiness planning, with more time and resources being spent on forecasting, coordination and preparation around cold weather events, Subatki wrote in his post.  

That comes partly in response to the January 2024 cold snap that pushed multiple Pacific Northwest balancing authorities to the brink of rolling blackouts and provoked an extended debate about how the ISO managed power flows — and its markets — during the event. (See NW Cold Snap Dispute Reflects Divisions over Western Markets and CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap.) 

“The ISO is prepared and has been working hard to make sure all the customers and market entities we serve in California and the broader West are ready for winter,” Subakti wrote. “Mother Nature often has her own plans and weather predictions are never 100 percent accurate, regardless of what season we’re in. But with all of the work and preparation, we are going into the winter of 2024-2025 in good shape.”  

New and Continued Initiatives

CAISO is moving into 2025 with 10 active stakeholder initiatives, and several include sub-working groups dealing with some aspect of EDAM implementation.  

In the Greenhouse Gas Coordination Working Group, ISO staff and stakeholders are in the process of developing a process for accounting for GHG emissions in EDAM for states that don’t price carbon but have other policies to reduce emissions. (See Western Market Developers Compare Approaches to GHGs.) The ISO is expected to develop a policy in the first quarter of 2025 and make a decision in the second.  

In the Price Formation Enhancements Initiative, staff and stakeholders are, among other things, considering whether to include fast-start pricing in the EDAM design. (See CAISO Considering Fast-start Pricing for Extended Day-Ahead Market.) A straw proposal for this initiative is expected in Q2, with policy development in Q3.  

Other efforts, such as the Storage Design and Modeling Initiative, are new, but piggybacking on the work of prior working groups. This effort will continue to tackle an array of challenges related to the market participation of storage resources, including further addressing bid cost recovery issues and developing a default energy bid formula specifically for batteries. (See CAISO Launches New Initiative for Storage Resource Design.) 

‘We’ve Got to Push Through’

Rothleder reflected on the past four years, highlighting that since 2020, when the ISO faced challenges meeting demand, the state has stepped up to increase the amount of capacity being brought on, and that pace of development has increased.

Going into 2025, the pace must be sustained, Rothleder emphasized, to maintain reliability and meet the state’s climate goals.  

“Taking your foot off the gas pedal is not going to be helpful at this point,” Rothleder said. “We’ve got to push through, continue the development, continue the transmission and continue the collaboration across the region because the lack of not doing so will be both costly and create more operational challenges for not coordinating and collaborating across the greater West.” 

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MISO Stakeholders Debate Usefulness of MW Queue Cap Pending Before FERC

Protests and endorsements have turned up in response to MISO’s second attempt with FERC to annually cap project submittals to its interconnection queue based on a megawatt value.

MISO filed its intentions with FERC in late November to impose a yearly cap of 50% of the non-coincident peak per study region in its interconnection queue (ER25-507). RTO staff have said repeatedly that a cap would make their interconnection studies manageable. MISO first filed for a cap in late 2023 but was rebuffed by FERC. (See MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects.)

Multiple stakeholders weighed in with FERC over the revamped proposal, with some claiming the cap would introduce a discriminatory process that would inject more uncertainty into the queue.

“Rather than help MISO manage its rapidly growing queue, this proposal would add uncertainty and create a rush of projects seeking to be included in the next available capped queue cycle,” the American Clean Power Association, Advanced Energy United, the Solar Energy Industries Association, the Southern Renewable Energy Association and Clean Grid Alliance said in a joint protest. The groups said MISO’s cap filing didn’t contain any elements that would speed up queue processing, like offering more schedule certainty or providing network upgrade cost estimates earlier.

“Instead of addressing these underlying issues, MISO has simply opted to prioritize shrinking the queue size over boosting queue throughput without any evidence that smaller clusters will be processed faster than larger clusters,” they argued, adding that it’s a “false assumption” to assume that a more modest queue equals a more accurate and faster queue.

Shell Energy and its subsidiaries said the cap “misses the mark” because just a few interconnection customers are responsible for the overwhelming number of requests in recent years.

“Given this fact, it is unjust, unreasonable and unduly discriminatory to impose sweeping restrictions on the majority of interconnection customers not contributing to the problem,” Shell argued. The company suggested MISO craft queue caps by corporate family, which would have the same effect on queue size without punishing all developers “for the behavior of a few.”

On the other hand, the Organization of MISO States called the cap a “necessary mechanism — at least in the near-term — to ensure MISO can efficiently manage” an oversaturated interconnection queue.

OMS pointed out that the 171 GW of interconnection requests MISO received in 2022 and the 124 GW that followed in 2023 aren’t sustainable and aren’t conducive to realistic study results.

“The sheer size of MISO’s interconnection queue has resulted in unreliable, outdated and inaccurate network upgrades identified early in the study process. It is simply infeasible to study clusters of resources that when combined exceed MISO’s all-time peak load,” OMS wrote.

However, the Mississippi Public Service Commission and Louisiana Public Service Commission objected to MISO’s cap plans because MISO didn’t include a cap exemption for projects that further states’ resource adequacy targets. MISO’s first, failed attempt to instate a queue cap featured an exemption for regulators’ pet generation projects. The grid operator since has morphed the promise of a cap exemption for critical projects into the creation an exclusive express lane for projects that preserve resource adequacy. (See MISO Outlines Plan on Fast-track Queue for Resource Adequacy.)

But the two state commissions said exclusion of the exemption this time around “usurps the exclusive authority of state retail regulators and their jurisdictional utilities to plan for adequate generation resources needed to provide resource adequacy within the jurisdictional footprint.”

Mississippi and Louisiana regulators said FERC should reject the cap or direct MISO to reintegrate the exemption into its plan. They said without a cap, MISO’s queue could limit or purge dispatchable resources like natural gas and nuclear units that will keep resource adequacy from degrading.

Despite the MISO South states’ opposition, Entergy and Cleco lent support to the cap. The two said MISO’s interconnection models are too bogged down to produce accurate study results for interconnection customers.

Duke Energy likewise supported the cap and said many of the recent rounds of submittals likely are “speculative projects with high withdrawal rates.”

Alliant Energy didn’t outright oppose the cap but said it harbored concerns that “serious risk” would remain on load-serving entities’ ability to interconnect projects in a timely manner. It asked FERC to hold off on a final decision on the cap until it also could weigh MISO’s upcoming expedited queue lane for resource adequacy projects. MISO plans to file the proposal for fast-track queue processing with FERC sometime in the first quarter of 2025.

MISO chimed in to remind stakeholders that the prior regulator exemption was part of a “previously rejected process that is not currently before the commission and not relevant for any purpose here.” MISO said it was being unfairly forced to defend its current filing based on the rejected one.

The RTO also said references to and making the cap contingent on its upcoming filing to fashion an RA expedited queue process are misplaced because the “budding” plan remains under development in the stakeholder process.

“MISO should neither be required to defend proposals previously rejected by the Commission in other dockets, nor should it be required to expand upon a … process that is still in development between MISO and stakeholders,” MISO said.

MISO said the cap proposal at its core merely asks FERC to “simplify a math problem — MISO’s study process — by limiting the number of variables — interconnection requests — it must solve for in each queue cycle.”

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FERC Sides with New England Developers on Interconnection Complaint

New England transmission owners no longer can require interconnection customers to pay operations and maintenance (O&M) costs for required system upgrades, FERC ruled Dec. 19 (EL23-16-00). The ruling could help reduce costs associated with interconnection in the region, potentially shifting some O&M expenses into transmission rates.  

The decision responds to a 2022 complaint by trade organization RENEW Northeast, which was supported by major clean energy associations including the New England Power Generators Association and Advanced Energy United. 

RENEW argued that the O&M requirement “can be a substantial burden on interconnection customers and can cause an unfair shifting of O&M costs from transmission customers to interconnection customers,” discouraging new development.   

The association noted that New England is the only region in the country that requires interconnection customers to pay the O&M costs associated with interconnection upgrades.  

“Because the O&M costs can be assessed for the 20- to 30-year duration of the [large generator interconnection agreement], the interconnection customer could pay O&M costs that exceed the capital costs of the network upgrades themselves,” RENEW wrote.  

ISO-NE declined to take a position on the merits of RENEW’s complaint, writing that it has no financial interest in the matter. It asked to be dismissed as a party to the proceeding, arguing that the disputed parts of the RTO’s Open Access Transmission Tariff “are within the exclusive right” of the region’s transmission owners. 

FERC denied the RTO’s request, writing that “retaining ISO-NE as a party to this proceeding will ensure that all parties required to make tariff changes pursuant to this order are parties to this proceeding.” 

Meanwhile, the New England Participating Transmission Owners (PTOs), the New England States Committee on Electricity (NESCOE), the Massachusetts Attorney General’s Office and a group of consumer-owned utilities argued that RENEW did not meet the burden of proof to show that the O&M requirement is unjust.  

“RENEW seeks to replace long-settled rules that put development risks and costs on interconnection customers with a one-sided bargain that shifts 100% of those costs to consumers,” NESCOE wrote. 

The transmission owners argued that “the current allocation of interconnection costs … is the result of a grand compromise of many interrelated rights and obligations among generation owners, transmission owners, public power and end-use customers that was determined to be just and reasonable by the commission and should not be casually tossed aside by modification of a single component.” 

FERC sided with RENEW, directing ISO-NE and the region’s transmission owners to submit a compliance filing within 60 days “removing from the tariff any language that provides for the assignment of network upgrade O&M costs to interconnection customers.” 

FERC noted that Order 2003 allows transmission providers to assign “but for” costs — which FERC defines as costs that would not exist without the interconnecting project — to interconnection customers. However, FERC determined the O&M requirements are not covered by this provision. 

“RENEW has provided substantial evidence that the network upgrade O&M costs that are being assigned to interconnection customers … do not reflect the actual but for network upgrade O&M costs that each interconnection customer’s interconnection request causes to be incurred,” FERC wrote. 

FERC also accepted RENEW’s request to require the transmission owners to widen the definition of an “interested party” within the transmission formula rate protocols. RENEW and similar trade groups are not included in the existing definition of an interested party. 

FERC wrote that the current definition “limits interested parties to a specific enumerated group and does not provide for sufficiently broad participation.” 

RENEW applauded FERC’s order, writing in a statement that the ruling “will eliminate the risks and uncertainties for interconnecting power generators that increase costs to consumers for energy and potentially delay the transition to a cleaner energy grid.” 

Joe LaRusso, manager of the Clean Grid Program at the Acadia Center, wrote on social media that “FERC has broomed away a significant obstacle to interconnection that was unique to New England.” 

A representative of ISO-NE said the RTO is assessing the order to determine its next steps. 

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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.”