In an attempt to stimulate the deployment of artificial intelligence and related infrastructure, the Trump administration has released an action plan and announced the development of data centers on federal land.
The U.S. Department of Energy has chosen four sites around the country to host data centers and related energy infrastructure: the Idaho National Laboratory; Oak Ridge Reservation; Paducah Gaseous Diffusion Plant; and the Savannah River Site.
“By leveraging DOE land assets for the deployment of AI and energy infrastructure, we are taking a bold step to accelerate the next Manhattan Project — ensuring U.S. AI and energy leadership,” Energy Secretary Chris Wright said in a July 24 statement. “These sites are uniquely positioned to host data centers as well as power generation to bolster grid reliability, strengthen our national security and reduce energy costs.”
DOE said it plans to work with data center developers, energy companies and the public in consultation with states, local governments and federally recognized tribes to advance the initiative. Solicitations for proposals to develop the sites will be released in the coming months, and DOE could pick winning proposals by the end of 2025. The department is considering other federal sites for data center developments as well.
The idea to use federal lands for data centers was included in the White House’s AI Action Plan, which was released on July 23. It also contains some broad recommendations for updates in electricity policy.
“The power grid is the lifeblood of the modern economy and a cornerstone of national security, but it is facing a confluence of challenges that demand strategic foresight and decisive action,” the plan said. “Escalating demand driven by electrification and the technological advancements of AI are increasing pressures on the grid. The United States must develop a comprehensive strategy to enhance and expand the power grid designed not just to weather these challenges, but to ensure the grid’s continued strength and capacity for future growth.”
The plan calls for stabilizing “the grid of today as much as possible,” or stopping premature power plant retirements. The existing power grid also can be optimized.
“The United States must explore solutions like advanced grid management technologies and upgrades to power lines that can increase the amount of electricity transmitted along existing routes,” the plan said. “Furthermore, the United States should investigate new and novel ways for large power consumers to manage their power consumption during critical grid periods to enhance reliability and unlock additional power on the system.”
New, reliable, dispatchable power plants need to be connected, the plan said. And the industry should roll out next-generation technologies such as enhanced geothermal, nuclear fission and nuclear fusion.
The plan calls for reforming “power markets to align financial incentives with the goal of grid stability, ensuring that investment in power generation reflects the system’s needs.”
The WATT Coalition and AMP Coalition released a joint statement saying that advanced transmission technologies and grid-enhancing technologies can help in the effort to connect data centers to the grid.
“The Department of Energy found that these technologies together could unlock capacity for more than 100 GW of new power, enough to meet a significant portion of the new load projected over the next 5-8 years,” they said. “These advanced transmission technologies represent a critical near-term pillar for modernizing the grid and meeting the growing power needs of the U.S. while new large-scale transmission lines are built.”
National Electrical Manufacturers Association CEO Debra Phillips called the action plan a welcome development for the industry it represents.
“The plan underscores the criticality of a modernized and resilient power grid, determining that the United States must explore solutions like advanced grid management technologies,” Phillips said. “Electrical manufacturers are at the forefront of this transformation — deploying reconductoring solutions, digital substations and data center strategies that optimize grid capacity and enhance reliability.”
In the wake of the New York Public Service Commission’s decision to cease planning its offshore wind underwater transmission network, NYISO has followed suit, tossing two years of planning studies. (See NY Steps Back From OSW, Halts Offshore Tx Planning Process.)
At the Transmission Planning Advisory Subcommittee’s meeting July 23, NYISO’s Jason Frasier thanked developers, ISO staff and stakeholders for their work and participation in the Public Policy Transmission Need process, initiated by the Department of Public Service in June 2023. NYISO revealed the bids in its solicitation in June 2024 and was targeting a selection by the Board of Directors in the second quarter of this year. (See NYISO Reveals Bids in NYC Offshore Transmission Solicitation.)
Frasier said that the ISO will now solicit feedback from stakeholders on the PPTN process for potential improvements.
Howard Fromer of Bayonne Energy Center asked whether developers would be reimbursed or compensated for their participation. Frasier said there was no mechanism in the tariff for developers to get compensated for a PPTN that was not finished.
Other stakeholders asked whether projects in the interconnection queue that were being built with the assumption of the PPTN would also be canceled automatically. Frasier indicated that those developers would need to withdraw or revise their projects. Absent a withdrawal notice, they would remain active.
A representative from Earthjustice asked whether any of NYISO’s studies of the benefits of offshore transmission would be retained or released. Frasier said that no benefit evaluation would be completed or released beyond what the ISO had already done.
U.S. investor-owned electric companies invested $178 billion in 2024 and are projected to invest more than $1.1 trillion through 2029, their trade organization reported.
The Edison Electric Institute said July 23 in its annual Financial Review that this level of capital expenditure exceeds every other U.S. business sector and places electric companies at the forefront of a transformational time for the economy.
2024 was the 13th straight record-setting year for investment, EEI said. In just the past decade, annual capital outlay has jumped from $104 billion to $178.2 billion. The largest single jump was from $147.7 billion in 2022 to $168 billion in 2023.
The 2024 financials indicate the scale of the industry. The report shows that collectively, U.S. investor-owned electric companies had:
$403.5 billion in 2024 operating income, down 0.1% from 2023;
$54.6 billion in net income, up 4.5%;
$34 billion in dividends paid on common stock, up 5.8%;
$1.57 trillion in property, facilities and equipment, up 5.5 %; and
$2.18 trillion in total assets, up 5.1%.
The industry’s average credit rating remained at BBB+ for the 11th year in a row, EIA said, and 94% of EEI Index companies increased their dividend. At 62.2%, the dividend payout ratio is the highest of any U.S. business sector, EEI said.
On the regulatory front, 81 rate reviews were filed in 2024 and 78 decided; average awarded return on equity was 9.73%, up from 9.58% a year earlier. The 2024 ROE broke down to 9.84% for vertically integrated companies and 9.53% for distribution-only companies.
The data covers 38 investor-owned electric companies whose stock is publicly traded on major U.S. stock exchanges, plus five companies that provide regulated electric service in the United States but are not listed on the U.S. exchanges.
Stock prices for the 38 EEI Index companies ended 2024 19.1% higher, placing them well ahead of the Dow Jones Industrial Average, well short of the S&P 500, and far short of the Nasdaq. Interest rate changes in the fourth quarter stunted the EEI Index’s full-year performance.
The index companies had a combined $1.02 trillion market capitalization at the end of 2024, with NextEra Energy the leader at $147.2 billion, Southern Co. a distant second at $90.3 billion and Unitil bringing up the rear at $900 million.
In a news release, EEI President Drew Maloney looked beyond the numbers to the significance of the financials: “America’s electric companies are leading in this unique and critical moment for our nation. As demand for electricity continues to grow, we remain committed to making the investments needed to strengthen America’s energy security while ensuring that our customers receive reliable, affordable energy.”
EEI said these companies support more than 7 million jobs nationwide and account for 5% of the U.S. GDP.
FERC has approved a set of amendments to the Northeast Power Coordinating Council’s bylaws that aim to broaden the regional entity’s purpose, modify membership eligibility and voting rights of members and the Board of Directors, and update its organizational structure.
NERC and NPCC filed the amendments in February, asserting they raised no reliability issues and “continue to satisfy the five governance criteria” for NPCC’s bylaws in the RE’s delegation agreement. Those criteria are that the RE:
be governed by an independent or hybrid board;
assure independence in its rules from power system owners and operators;
let its membership be open with no more than a nominal fee;
ensure no sector exercises dominance over its actions; and
provide the public with reasonable notice and opportunity for comment.
FERC approved the changes in a July 21 filing (RR25-2).
The amendments apply throughout the RE’s bylaws, starting with Article II, where the requirement that NPCC’s principal office be located in Manhattan has been removed; now the office may be located anywhere within the NPCC geographic region. Additional language will allow the principal office to remain in its established location if that area is removed from the NPCC footprint.
In Article III, the language detailing NPCC’s purpose has been updated to widen the type of agreements the RE can enter with Canadian provincial authorities. Previously it included only memoranda of understanding. The article now also says NPCC may use any “lawful activity necessary or appropriate to achieve” its electric reliability mission.
Article IV has been updated to remove “the ability of a natural person to be an NPCC member” and require member applicants to “have a material interest in the reliable operation of the Northeastern” electric grid. NERC and NPCC said these changes would improve the handling of sensitive information discussed at member meetings by ensuring that anyone present at such meetings is a member of an organization with its own governance and accountability policies.
In addition, single end use customers no longer can be members of NPCC, in line with the requirement that a member not be a natural person, and other REs also cannot be members because “it is not necessary.” NERC said none of these changes will affect any existing members “because there are no natural persons, single end use customers or [REs] that are currently members of NPCC.”
The organizational changes in Article V specify that NPCC’s president also is the CEO and clarify the duties of the office. Language also has been modified in Article V to allow board vacancies to be filled by a simple majority vote of directors present at a meeting. This change ties into the modifications in Article VI that permit up to five independent directors, including the board chair; previously, two of the 16 directors were required to be independent, in addition to the chair. The chair’s term also has been lengthened from two to five years, with a maximum of two terms.
NPCC simplified the board’s quorum requirements to allow a quorum to exist with at least 50% of the directors present, including at least two independent directors. Previously, attaining quorum required at least one independent director and at least half of stakeholder directors in each of at least 60% of the sectors, meaning that quorum could be reached with as few as six directors present or denied with up to 10 directors present, depending on their sectors. The change will eliminate this ambiguity.
Voting requirements also have been changed to allow motions to pass based on a majority vote of directors present at a meeting, rather than the previous two-thirds sector-weighted majority. This update also is meant to simplify voting, particularly in light of the planned expansion of independent directors.
Similarly, members’ voting rights have been updated to allow a quorum with at least 50% of members present instead of half of members in at least 60% of stakeholder voting sectors. Motions also may pass based on a majority vote of members present, rather than a two-thirds sector-weighted majority.
The amendments also will change the names of three board committees. The Corporate Governance and Nominating Committee will become the Governance and Nominating Committee, the Management Development and Compensation Committee will become the Compensation Committee, and the Pension Committee will become the Retirement Plan Investment Committee.
Finally, NPCC added new provisions to Article XVIII, which covers dissolution of the RE, to state that a two-thirds affirmative majority vote of members is required to terminate NPCC as a corporation. The distribution of assets upon dissolution has been modified to reflect NPCC’s new status as a 501(c)(3) organization.
SPP’s Strategic Planning Committee unanimously endorsed RTO staff’s comprehensive approach to accelerate transmission capability, directing them and SPP’s working groups to prioritize the development of policies for all short-, mid- and long-term initiatives.
Time is running short, Casey Cathey, SPP vice president of engineering, said during the July 17 meeting. Staff are producing solutions for the 2025 Integrated Transmission Planning assessment, which will be shared with stakeholders in October.
The ITP portfolio is expected to be another large one, possibly double that of the record 2024 assessment. That one produced 89 projects expected to cost $7.65 billion. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)
“We still have some work to do to solidify and optimize that total final portfolio, but we’re still looking at a multibillion-dollar portfolio,” Cathey told the SPC. “It may be in the realm of $15 billion. And so there is a notion that anything that we can do between now and November, we should probably do, recognizing that expedited revision requests and all of the things moving so fast this year has been problematic.”
Noted teen philosopher Ferris Bueller said, “Life moves pretty fast. If you don’t stop and look around once in a while, you could miss it.”
But Cathey can’t afford to stop and look around.
“We have to accelerate everything. We need to accelerate load. We need to accelerate generation. And so today’s topic is accelerating all things transmission,” he said.
Cathey said while SPP has added about $1 billion in transmission annually over the last decade, the evolving generation mix and growing reliability needs demand a faster and more targeted response.
Staff have proposed a multiphase strategy that speeds up transmission capability by: accelerating issuance of notifications to construct and timelines for selecting transmission owners under the competitive process; increasing deployment of near-term solutions; improving the efficiency of project completions; and addressing a diverse range of stakeholder perspectives.
Gaining and obtaining the SPC’s endorsement and guidance was the first step.
Christy Walsh, with the Natural Resources Defense Council, said she loved the focus on capacity.
“We need to build more transmission. We need more. We need to upgrade the biggest existing system as much as we can,” she said. “We keep hearing it’s going to take three to five years to build transmission. But we’re also hearing we need capacity now for the new loads and whatnot. If we can squeeze more capacity out of the existing system … we should be doing that now while we’re waiting the optimistic three to five years for the new transmission, and that’s three to five years on top of the planning process.”
Cathey agreed, saying staff are evaluating internal procedural barriers and coordinating with state and federal agencies to streamline permitting and construction efforts. The upcoming work will incorporate the strategies into long-range planning efforts and potentially shape future policy proposals.
Forecasting Mitigation Process OK’d
The committee unanimously endorsed its Load Forecasting Task Force’s proposed strategy to mitigate forecast risk in the SPP footprint and its impact on system planning.
The team has proposed improving consistency between forecasts used for resource adequacy and transmission planning purposes to address growing concern about under-forecasting load due to rapid economic growth, electrification trends and data center expansions. It says traditional forecasting methods may not fully capture emerging demand risks.
Oklahoma Gas & Electric’s Brad Cochran, the task force’s chair, said the group has been meeting for a year. During that time, it had several conversations with other grid operators about their practices.
“What we were finding through discussions is there’s variability and timing of when entities are completing their forecasts and when they’re updating them,” he said. “We’ve talked extensively … about large loads and how fast they’re coming. Those forecasts change and those numbers change often, so aligning those two so you have similar information in both of these planning processes is a big deal.”
The team recommended continuing to use separate load-responsible entity forecasts for RA and Integrated Transmission Planning (ITP) but require an update to the ITP forecast during the RA submittal window. It also advocated that SPP assess whether to develop in-house forecasting expertise, but not conduct forecasts for individual LREs.
“Because of the diverse footprint of SPP and the diverse membership at this time, the task force didn’t think that it makes sense for SPP to develop these forecasts for all 60-plus LREs,” Cochran said.
He suggested SPP have some level of expertise and knowledge to give it “the ability to kind of build and evolve over time and look at these forecasts and communication.”
STRP Task Force Created
The SPC agreed to form a task force to help develop guidelines and a framework for reforming the process for considering short-term reliability projects (STRPs).
Irene Dimitry, an independent member of SPP’s Board of Directors, will chair the task force, which will report to the SPC. The effort comes after several attempts by staff resulted in a framework that she said was “too prescriptive.”
“Given our role as independent board members, we need the ability to each apply our own judgment in making decisions about what’s best for SPP and its members and all the customers that we serve,” she said.
SPP CEO Lanny Nickell said the focus for the task force should be, “How do we make it faster?” It has a January 2026 deadline for delivering meaningful plans to the SPC.
“Ultimately, we need to do whatever is needed to produce reliability upgrades, to produce economic value and optimize all of that to consumers in the region,” he said. “We just need to make sure we recognize the fact that speed is of the essence, particularly if there’s a reliability need that’s been addressed by any upgrade.”
SPP’s tariff defines STRPs as upgrades that meet the criteria for competitive projects but are needed in three years or less to address “identified reliability violations.” In that case, STRPs are not considered competitive upgrades under the tariff and are awarded to the incumbent transmission owner.
SPC Increases Membership
The Corporate Governance Committee approved 11 nominations to the SPC, raising the committee’s sector membership to match that of the 23-person Members Committee. The nominations result from an April change to the bylaws. The SPP board will vote on the nominations during its August meeting.
The new members are:
Nick Abraham, ITC Great Plains; Rebecca Atkins, Missouri Joint Municipal EUC; Jarred Cooley, SPS/Xcel Energy; Mark Foreman, Tenaska Power Services; Steve Gaw, Advanced Power Alliance; Christopher Matos, Google; Kevin Noblet, Kansas Electric Power Cooperative; Robert Pick, Nebraska Public Power District; Sarah Ruen, Tri-State Generation & Transmission; Emily Shuart, OG&E; Christy Walsh, Natural Resources Defense Council.
The return of electricity demand growth is a reality embraced by both political parties, but a Senate Energy and Natural Resources Committee hearing on July 23 highlighted their differences on how to address it.
“Here’s the real problem: We have spent much of the last 20 years shutting down the generation that can actually meet that demand,” committee Chair Mike Lee (R-Utah) said. “Coal plants retire, nuclear blocked, natural gas tied up in endless litigation; and we replaced a lot of that capacity with wind, solar and batteries, resources that by design don’t work all the time.”
The growth being driven by artificial intelligence and data centers, electrification and resurging domestic manufacturing will require changes to how energy infrastructure is permitted and built, Ranking Member Martin Heinrich (D-N.M.) said.
“No single business or technical workaround can substitute for a coordinated, modern, responsive grid,” Heinrich said. “Fortunately, we sit on the committee that can help make that happen. The urgency isn’t just about maintaining our edge in AI innovation; it’s about affordability.”
The recently passed reconciliation bill cut tax credits for the kind of energy resources that can be most quickly deployed — solar and wind, which Heinrich said would raise nationwide annual energy costs by $16 billion by 2030 and $33 billion by 2035.
“And the president’s tariffs are driving up equipment costs, raising the cost of all energy generation resources — all of them,” he added. “This is leading directly to Americans spending more on their utility bills.”
Lee pushed back on criticism about Republicans using reconciliation and relying on party-line votes to cut renewables subsidies in the recently passed “One Big Beautiful Bill Act,” reversing policies Democrats had enacted three years earlier using the same legislative tactic.
“The Inflation Reduction Act turbocharged subsidies for wind and solar,” Lee said. “And those subsidies are distorting energy investment, because the subsidies can offset more than 50% of the project’s costs — a significant amount that ends up being borne by the U.S. government and the U.S. taxpayer.”
On top of that, he added, those intermittent resources need to be balanced with energy storage or natural gas peaker plants, which add to the costs.
Huntsman Corp. CEO Peter Huntsman agreed, pinning the blame for the decline in its chemical industry on its net-zero policies.
“I’ve experienced this firsthand as our company has laid off thousands of employees in Europe,” Huntsman said. “Facilities that were globally competitive just a few years ago have been closed and are no longer operating due to ruinous and unrealistic net-zero and decarbonization policies and the failed ideas that you can power a modern economy without developing oil and gas resources.”
No AI Leadership Without Power
Jeff Tench, executive vice president at Vantage Data Centers, offered the perspective of his industry, saying that, just five years ago, a data center with 30 MW of power demand would’ve been considered “large.” Now, 100 MW is a starting point, and some customers are asking for 1 GW or more for data centers used to support artificial intelligence, he said.
“We cannot get the amount of electricity we need in the time frame to build our data centers,” Tench said. “Without electrical power, it is not possible to build digital infrastructure — the infrastructure that supports AI data centers. Transmission lines and generation facilities must scale rapidly if the U.S. is to remain the global leader in AI innovation. We are asking for your leadership to drive a more modernized policy framework that reflects today’s growth, aligns with investment timelines and ensures that the power system is ready when and where it is needed.”
Interconnection timelines for new generation and new large loads are too slow, the transmission grid needs to be upgraded to support the new demands, and permitting must be improved to ensure the U.S. can lead in AI development, he added.
“The United States is looking at an AI era that is not coming, but is here,” Tench said. “We have the capital, we have the customers and the talent, but we will not lead if we cannot power it.”
Power demand growth is sudden and challenging to meet, and it is contributing to affordability issues around the country, said Rob Gramlich, president of Grid Strategies. While acknowledging the need for more generation, Gramlich focused on transmission first because the federal government has more authority over its development.
“It has the highest impact,” Gramlich said. “It’s the great integrator of all resources. It may seem like it’s a renewable energy piece of infrastructure, but that’s just because over the last five years, that’s all anybody was trying to connect to the grid.
“Right now, we’re seeing a lot of other things trying to connect to the grid, including Jeff’s data centers and data centers around the country, other large loads, manufacturing and other types of generation. And whether it’s nuclear, [carbon capture and sequestration], other types of generation — guess what? It’s going to face that same constrained grid.”
Building new lines can take time, but grid-enhancing technologies and advanced conductors can be deployed more rapidly to get more out of existing infrastructure, Gramlich said. The industry also should keep considering building larger 765-kV lines, which are cheaper compared with building multiple lines to meet the same need, Gramlich said.
“We do need firm power to meet peak loads,” Gramlich said. “Resources provide varying levels of contributions to meeting peak loads. Nuclear has the highest contribution at 95%, but we’re not able to get much more very soon. Gas CTs, at least according to PJM, are around 60% in terms of their ability to serve peak loads. Combined cycle is a little higher in the 70s. Offshore wind is actually 69%.
“And so none of these resources are perfect, but the point is, when you put them all together on the integrated grid, that’s how you get nearly 100% reliability of the power system.”
As it updates its energy plan to reflect new challenges to decarbonization, New York is contemplating what until recently seemed improbable, or even unthinkable: new fossil-fired generation.
The state Energy Planning Board voted July 23 to publish the draft 2025 update of the state Energy Plan after 10 months of deliberations. A series of hearings across the state is scheduled to gather input on the draft.
Further updates and revisions to the draft are expected as it approaches finalization toward the end of this year and the effects of federal policy changes become clear.
The board’s chair — Doreen Harris, CEO of the New York State Energy Research and Development Authority — told RTO Insider that the huge shifts in federal policy over the past six months created uncertainty to a degree that required the board to present a range of scenarios in the draft. She said federal actions over just the past few weeks may have rendered some of those scenarios overly optimistic.
The Trump administration is actively moving to thwart energy efficiency and clean energy initiatives such as those New York has worked more than a decade to build. Meanwhile, the recently enacted reconciliation bill, the One Big Beautiful Bill Act, eliminates federal subsidies that states were counting on to incentivize renewables development and shifts billions of dollars in federal spending obligations to state governments, thus limiting whatever inclination states had to subsidize renewables on their own.
As such, New York is contemplating strategy shifts on multiple fronts with the draft update.
Ambition vs. Results
New York has had mixed results in expanding its renewables portfolio and shrinking its carbon footprint.
The Climate Leadership and Community Protection Act — New York’s landmark 2019 climate law — mandates 70% renewable energy and a 40% reduction in greenhouse gas emissions, as well as 100% zero-emission energy by 2040.
But officials have acknowledged the state is likely to miss the two 2030 goals, possibly by a wide margin: GHG emissions were down only 9.3% as of 2022, and renewables accounted for only 27% in 2023.
The draft update acknowledges the challenges facing the 2040 zero-emissions energy goal as well. Given the 23% increase in peak demand and 26% increase in annual demand expected by 2040, the draft emphasizes the importance of not falling further behind on generation capacity.
One scenario envisions current-day nuclear and hydro assets continuing to play a key role in the state grid in 2040, joined by 35 GW of solar; 9 GW each of storage, onshore wind and offshore wind; and 16 GW of green hydrogen combustion.
Any of those targets could be a challenge in the current environment, but hydrogen stands out as a leap of faith.
The draft immediately acknowledges the technical challenges of generating huge quantities of hydrogen in an ecologically and economically sound manner. And it acknowledges that hydrogen or other “clean firm” technologies critical to this planning process are not yet scalable.
So the draft looks at fossil fuel as indispensable for some time to come. Natural gas and petroleum will be diminished but still important energy resources in New York in 2040, the draft says, and fossil generation will remain essential to grid reliability.
But a quarter of the state’s combustion generation capacity will be at retirement age as soon as 2028, so the state will need to be strategic about the pace of combustion unit retirements, the draft warns, and will need to consider whether new or repowered fossil-fuel generation is necessary.
Harris said the state’s energy planning process has been faced with moving variables since President Donald Trump began his second term, and she said some of the scenarios laid out in the draft plan are based on factors and assumptions that recently became outdated.
New York is working to meet rising electricity demand presented by new large loads and decarbonization efforts. | New York state Energy Planning Board
“If anything, the reconciliation bill may have rendered even that planning case a bit optimistic from the perspective of renewable deployment in particular,” she said.
NYSERDA’s senior vice president for policy, analysis and research, Carl Mas, said the language in the draft about new fossil generation is intentionally broad because there is such a broad range of possible outcomes as New York navigates state and federal economic and policy factors.
But there are scenarios under which the state — which had sought to phase out fossil fuel generation in the 2030s —would instead seek construction of new fossil generation or retrofits to make older facilities cleaner and more efficient.
“With the load growth that we’re seeing, we feel like we have to remain flexible,” Mas said. “There’s extreme amounts of uncertainty, but we have a very old fleet, and we have a growing load and substantial new headwinds that we didn’t have five or six years ago.”
This does not alter the state’s commitment to renewables and decarbonization, Harris and Mas said. It recognizes that the plan for carrying out that commitment may need to be modified to maintain reliability.
Tough Decisions
New York has a number of hard choices to make with its energy portfolio, and the draft update of the plan lays out some of the potential decision-making pathways in a rapidly evolving landscape. But it will not make the decisions easier.
Renewables advocates have been unhappy about the state ratcheting back initiatives that have become untenable or expensive, and about the slow pace at which the New York Power Authority is starting its role as a renewables developer. Any move to authorize major new fossil infrastructure is likely to go over just as badly.
Meanwhile, New York must decide whether to continue to subsidize the nuclear power plants that supply 22% of the state’s total electricity and 42% of its emissions-free electricity. Over the past seven fiscal years, this zero-emission credit program has consumed $3.73 billion gathered from surcharges on electric bills.
The draft plan highlights the importance of the ZEC program, but it also states bluntly that “it is not feasible to continue increasing the number and scale of programs that electric ratepayers need to fund.”
Another challenge: New York’s renewable energy pipeline — partly rebuilt after mass cancellations in 2023 — faces a new round of cancellations because of the impending end of federal tax credits under the reconciliation bill.
“We have literally seen the federal government’s action result in tens of billions of dollars of impact on New Yorkers with respect to clean energy deployment costs,” Harris said.
There is a wave of collateral damage beyond the tax credits, she said, as the industries and workforce that were growing in the clean energy sector retract and retreat.
Harris added, though, that renewable energy is not expected to halt; the question is how much it will slow.
“So this energy plan is taking into account the realities of having those tools impacted,” Harris said.
Simultaneous Goals
The draft plan’s summary alone stretches 80 pages and reminds the reader why governmental processes sometimes move so slowly: It is filled with parallel and secondary goals that rope in a massive cast of stakeholders and competing interests.
The draft suggests that as New York is reducing its carbon footprint and keeping its grid reliable, it should upgrade one of the oldest housing stocks in the U.S.; move to 100% zero-emission vehicle sales; reduce negative impacts on disadvantaged communities and actively steer positive impacts toward them; bolster organized labor; help poorer New Yorkers cut their energy costs; craft a more cohesive energy planning process; support research and development; build at least 1 GW of nuclear capacity; develop the energy workforce; lead the country in battery energy storage safety; maintain reliable gas transmission networks that can meet peak demand; consider wholesale electricity market reforms; and integrate renewables into the land-planning practices of often oppositional local governments.
And it wants to do all of this affordably.
“These are all goals that the state can meet without sacrificing one for another,” the draft says.
It estimates that some of the scenarios would raise energy costs more than 35% by 2040. That is expected to be offset to some extent by lower health care costs and other societal benefits, but it would be a lot of money on top of already high rates. Heavy investment is needed under any scenario because of the age of existing transmission and generation infrastructure and the increased demands expected to be placed on them.
But any embrace of new or rebuilt natural gas-fired generation would be a bitter pill to swallow for clean energy advocates.
Marguerite Wells, executive director of the Alliance for Clean Energy New York, avoided the words “natural gas” in a statement but made the trade group’s priority clear: “Electric demand is rising, and legacy generating sources are aging. It’s patently obvious that renewable sources are going to be the fastest and lowest-cost method of bringing new power onto the grid.”
ACE NY looks forward to commenting on the draft, she said, and working with the state to identify the inefficiencies and road blocks that are delaying renewables.
State policy not long ago favored natural gas as the preferred alternative to coal and oil.
The 2015 update of the State Energy Plan discussed New York’s ambitions for, and early steps with, renewables. But it also said, “Economic, operational and environmental advantages make natural gas the current fuel of choice for new and replacement generation in New York.”
The 2019 climate law canceled that line of thought. But there was always going to be an off-ramp in case the vision did not come together as hoped.
In the 2022 Scoping Plan it prepared for the law, the state Climate Action Council said, “The effectiveness of programs and policies should be continually evaluated and changed if renewable energy is not being deployed at the pace necessary to achieve the requirements on time.”
The July 23 vote to publish the draft set in advance the process for such a potential change.
Jackie Bray, commissioner of the Division of Homeland Security and Emergency Services and a member of the Energy Planning Board, said she was glad alternate scenarios were included in the draft in case the preferred scenario becomes impossible.
There can be a tendency in this type of planning process, she said, for well-meaning leaders to continually add objectives to a blueprint on the assumption that there is time over the next decade to figure out how to reach those objectives.
“Make sure that we are being realistic about what we can deliver and what we must deliver,” Bray urged listeners.
The nation’s largest renewable energy developer continues to present renewables as a bridge to the grid of the future and fashion itself as an “all-of-the-above” company in an optimal position to build that bridge.
But NextEra Energy’s July 23 financial report came on the heels of potentially major roadblocks for wind and solar development being erected by the federal government.
The company’s stock price took a hit in trading later in the day, despite solid second-quarter financials with year-over-year growth in revenue, earnings and order backlog.
Component company NextEra Energy Resources added more than 1 GW of commitments from hyperscalers to its backlog during the quarter, raising its total existing and planned service for data center and technology customers to more than 10.5 GW.
Its overall backlog is nearly 30 GW, the majority of it wind and solar generation, which is in a race to start or finish construction in time to qualify for sunsetting federal tax credits.
Tariffs, executive orders and agency rulemaking add uncertainty to the company’s strategizing, NextEra CEO John Ketchum said during a conference call with financial analysts.
“While there are risks to be managed, we believe there also are significant opportunities, given the steps we’ve taken to prepare for this moment, as we expect a natural pull forward of demand,” he said. “We are in a constant state of construction.”
No company is immune to all risks, Ketchum said, but NextEra has proved repeatedly it can navigate challenges.
He repeated a variation of the message that the renewables sector began broadcasting the day after Election Day 2024: America needs us.
That message seems not to have resonated with enough decision makers, given the details of the One Big Beautiful Bill Act that target wind and solar development.
But the company views OBBBA as a rule change, not a sunset or a cliff. “Tough, but constructive,” Ketchum called it.
“We are firmly aligned with the administration’s goal to unleash American energy dominance, and to do so, we need all of the electrons we can get on the grid. There’s truly no time to wait,” Ketchum said.
“As I’ve said many times, we’re going to need all forms of energy to meet this moment. New gas and nuclear are on the way and will be critical to meeting demand over the long term. Renewables and storage can bridge the gap and will play an important role in an all-of-the-above future.”
Ketchum said the leadership believes NextEra has begun construction of enough projects to reach its development expectations through 2029. They cannot, however, make any guarantees.
He added that if smaller companies not as well prepared as NextEra are unable to move forward in this environment, there would be opportunity for NextEra to pick up their projects and move them to completion.
Turning to the Duane Arnold nuclear plant in Iowa, Ketchum said engineering studies and site reviews are progressing favorably, and there are conversations with customers about offtake of the power it would produce if restarted.
NextEra Energy reported second-quarter 2025 earnings per share of $1.05 on revenue of $6.7 billion and net income of $2.03 billion, up from 96 cents, $6.07 billion and $1.62 billion in the same period of 2024.
Its stock price dropped 6.1% in trading July 23 to close at $72.82, near the middle of its 52-week range.
FERC approved Constellation Energy’s $26.6 billion purchase of Calpine, creating an IPP with nearly 60 GW of generation around the country (EC25-43).
In an order issued after the markets closed July 23, the commission found the deal, with divestment commitments and a settlement on bidding behavior with PJM’s Independent Market Monitor, is in the public interest.
While Constellation is the surviving firm in the deal, Calpine’s main owners — ECP and AI Holdings — each still will control less than 10% of the new firm, which is below FERC’s standard for a controlling interest in a utility.
The mitigation plan includes selling off 3,546 MW of generation, all of it located in PJM, that comes from the 1,134-MW natural gas combined cycle Bethlehem Energy Center, the 569-MW dual-fuel combined cycle York Energy Center Unit 1, the 1,136-MW dual-fuel combined cycle Hay Road Energy Center and the 707-MW simple cycle gas-fired Edge Moor Energy Center.
The two firms have overlapping generation in ISO/RTOs around the country, but PJM is their biggest shared market, where, after consummation, Constellation will control 26.4 GW, or 14.9%, of its installed capacity. In some submarkets to the RTO, absent the mitigation plan, the merger would have given Constellation enough market power to fail standard screens, FERC said.
Constellation and the IMM signed a deal July 3 where the firm agreed to some post-merger behavioral commitments to deal with the monitor’s concerns over its impact on market power. The deal is based on one that Constellation entered into with the IMM before the merger and extends behavioral commitments on its generation out to the 2035/36 capacity delivery year.
The deal prevents the firm from selling any of 3,546 MW of generation to be divested to Dominion Energy and American Electric Power, or their subsidiaries. The IMM could disagree on other deals, including seeking restrictions at FERC, but Constellation would be able to oppose those arguments.
The IMM settlement includes commitments for Constellation to bid into the capacity and energy markets at specific prices and requires notice for retirements. It also limits Constellation’s ability to enter into co-location deals with large loads such as data centers.
“For a period of one year from the execution of this settlement agreement, Constellation agrees not to enter into any co-location arrangements under which the capacity serving the load delists, until and only if the commission issues an order, regulations or policy statement subsequent to the date of this agreement authorizing such a configuration,” it said. “For the avoidance of doubt, nothing in this agreement restricts the ability of Constellation or the [PJM] IMM to advocate for any particular co-location configuration or restriction on such configurations.”
FERC found the mitigation plan appropriately addresses market power concerns brought up by Constellation’s acquisition of Calpine.
“We accept Constellation Energy’s commitment to abide by the terms of the Constellation-PJM IMM agreements, and we condition our authorization of the proposed transaction on that commitment,” FERC said.
The deal addresses market power concerns that the IMM and other intervenors made in the case, extending bidding rules Constellation already must follow in PJM to its newly acquired units and for an additional four years from the previous deal. Any changes to that deal before May 2036 would have to come before FERC to get approved, as the regulator is basing the deal’s approval on the commitments made there.
Pennsylvania’s Consumer Advocate asked FERC to weigh the impact of the merger on the state’s competitive market and the default service auctions for customers who stay with the utility. FERC has said it would examine retail market impacts, but only if a state commission asks it to do so, and the PUC did not in this case.
FERC also was unpersuaded by protesters’ arguments that it needed to examine the impact of ECP continuing to own less than 10% of the firm after the merger. Staying below that mark creates a rebuttable presumption that an entity lacks control.
“ECP and AI Holdings will each hold less than 10% of the voting equity interests in Constellation and will not have any right to appoint a board member to the boards of Constellation or any of its subsidiaries,” FERC said. “Furthermore, applicants represent that there is no contract that gives ECP influence on the decision-making of Constellation or its public utility subsidiaries after consummation of the proposed transaction.”
California’s fastest-growing energy resource — battery storage — is earning less net revenue per unit with each passing year, while capacity is expected to continue to boom in the Golden State.
Battery storage net revenue dropped from an average of $102/kW-year in 2022 to $78/kW-year in 2023, to $53/kW-year in 2024, indicating a “trend,” CAISO’s Department of Market Monitoring (DMM) said in a July 15 memo, which was included in reports provided to the July 22 general session of the Western Energy Markets Governing Body.
Lower peak energy prices are the primary cause of the revenue decline, and revenue from ancillary services also has continued to decrease significantly as the volume of battery capacity has increased, the DMM said.
Even so, an additional 14,000 MW of battery storage capacity is planned to be online by 2030, pushing CAISO’s total to about 28,000 MW by that year. Battery storage capacity has gone from 500 MW in 2020 to close to 14,000 MW as of June.
Nearby states also are going bonkers over batteries: Arizona plans to install more than 5,000 MW of additional battery storage capacity by 2028, while Nevada is looking to add about 2,500 MW by that year. In total, more than 19,000 MW is planned to be installed in Western Energy Imbalance Market (WEIM) states by 2028, DMM Executive Director Eric Hildebrandt said in the memo. Much of the battery capacity in other WEIM states is being installed to meet the renewable energy requirements of load-serving entities in California, Hildebrandt said.
The DMM recommended CAISO revise its bid cost recovery rules for batteries because the current rules “significantly decrease the incentive for batteries to bid in a manner that ensures their capacity is usually fully available during the most critical peak net load hours,” Hildebrandt said in the memo.
“In addition to increasing bid cost recovery payments and related gaming opportunities, this can result in batteries being discharged prior to the peak net load hours, when battery capacity is needed most,” Hildebrandt said.
In 2024, battery storage facilities in CAISO’s region received about $18 million in real-time bid cost recovery payments, representing 11% of total bid cost recovery payments and 4% of batteries’ total net market revenues.
Batteries tend to contract less than their maximum power capacity for resource adequacy purposes. This means batteries theoretically could provide more power than their RA value, Hildebrandt added.
During the five highest load days of 2024, battery storage resources provided significant RA capacity. However, RA storage capacity can drop in the later peak net load hours — when batteries are critical for system reliability — due to insufficient state-of-charge, Hildebrandt said.
In 2024, batteries supplied about 9% of CAISO’s energy during peak net load hours, while battery charging represented about 15% of CAISO’s load during mid-day hours, according to the memo. Battery charging helped reduce the need to curtail or export surplus solar energy at very low prices, the memo said.
CAISO will rely heavily on battery storage facilities to meet peak demand this summer, state energy officials said in May. A surplus of at least 5,500 MW is projected to be available to California during peak demand under normal conditions and 1,368 MW under extreme conditions, the officials said.
