Constellation Energy turned in better-than-projected financials for 2024 as it continued to meet the demand for emissions-free energy with the nation’s largest nuclear fleet.
The Baltimore-based energy company said it has the lowest CO2 emissions rate among the top 20 private investor-owned U.S. power producers and that it once again was the nation’s largest producer of emissions-free energy in 2024.
The capacity factor of its nuclear plants inched up from 94.4% in 2023 to 94.6% in 2024, which it said is about four percentage points higher than the industry average.
Constellation CEO Joe Dominguez has spoken about U.S. energy trends presenting opportunities for the company, and he repeated the message Feb. 18 as he announced the fourth-quarter and year-end financials: “There has never been a more exciting time for our country and for the energy industry. We are privileged to be at the heart of it all.”
Demand for electricity is such that Constellation is working to restart a 51-year-old retired reactor at Three Mile Island in Pennsylvania, which it has renamed the Crane Clean Energy Center, to supply Microsoft for 20 years.
Constellation is also in the process of acquiring Calpine Corp., the nation’s largest operator of geothermal and natural gas power generation, a deal it said would create a leading retail supplier of power to meet growing demand. (See Constellation to Acquire Calpine for $29.1B.)
Constellation’s stock price has been on a mostly steady and often sharp rise since the company spun off from Exelon in early 2022. That likely is based in part on the widespread (but not universal) expectation that data centers for power-intensive artificial intelligence applications will create huge demands for additional electricity — Constellation stock jumped 25% in a single day when the Calpine deal was announced.
The price per share hit an all-time high Jan. 24, then plummeted 21% the next trading day on news that DeepSeek had developed an artificial intelligence model that needs only a fraction of the electricity that other models consume. The stock price has recovered much of that loss, however.
In its annual 10-K filing, also released Feb. 18, Constellation said energy-intensive data centers would be a potential driver of market demand for its reliable, carbon-free electricity, as would policy support for nuclear energy and consumer preference for clean energy.
Constellation reported 2024 GAAP net income of $3.75 billion, or $11.89 per share. This compares with $1.62 billion and $5.01 per share for 2023.
Adjusted (non-GAAP) income was $2.74 billion, or $8.67 per share in 2024. During the year, Constellation twice bumped its full-year guidance for adjusted earnings higher, but results still exceeded the final $8-$8.40 guidance the company set.
“Backstopped by our strong balance sheet and industry-leading generation and commercial businesses, we’re affirming our 2025 adjusted operating earnings guidance range at $8.90-$9.60 per share,” CFO Dan Eggers said in the news release.
Constellation closed 2024 with 31,676 MW of nameplate generation capacity — 22,068 MW of nuclear, 7,045 MW of natural gas and oil, and 2,563 MW of renewables.
2024 sales totaled 269,417 GWh, approximately the same as 2023 sales. That broke down to 67.4% nuclear; 9.9% gas, oil and renewables; and 22.6% purchased power.
FERC approved a set of wide-ranging changes to PJM’s capacity market, including setting a new reference resource, recognizing the resource adequacy contribution of reliability must-run (RMR) units and establishing an RTO-wide non-performance charge rate (ER25-682).
The rule changes came after the capacity prices spiked in the 2025/26 base residual auctions last year, due to the tightening supply and demand balance in the RTO. It also comes as the capacity auctions have been delayed so new generation can be built in time to participate.
Two major fossil fuel power plants outside of Baltimore — the 1,289-MW Brandon Shores coal plant and the 843-MW H.A. Wagner oil-fired plant — are slated to retire but have entered into RMR deals with PJM to stay open until the grid is reinforced. Both of those RMR deals are pending at FERC.
PJM proposed reflecting the resource adequacy contributions of any RMR deals in its next capacity auction for 2026/27 that is set for July 2025, and the one after that for 2027/28. They will bid $0 into the auction, effectively serving as price takers and giving the RTO more time to develop a fulsome proposal.
Brandon Shores and H.A. Wagner are the only two plants that could qualify for the temporary rule, but Brandon Shores might require an emergency order from the U.S. Department of Energy under the Federal Power Act’s Section 202 (c).
FERC found the proposal to reflect RMR units in the capacity auction just and reasonable, which includes crediting back the load paying for the RMR deal with any capacity revenues.
“We agree with PJM that taking into consideration the resource adequacy contributions of RMR resources that meet certain criteria, such that they can be reasonably expected to perform, similar to capacity resources, will reflect the actual availability of resources in the PJM region for the 2026/2027 and 2027/2028 delivery years and avoid the risk that load will pay twice for the same capacity,” the order said.
Requiring them to be price takers in the auction is in line with rules in New York and New England and will avoid customers paying for the same megawatts twice, FERC said.
Previously, PJM was set to use a combined cycle natural gas unit for the 2026/27 auction. Given the realities of the auction, that would have led to a too-steep demand curve that left the auction price too sensitive to small changes in supply and demand. Instead, the auction will be run with a curve based on a combustion turbine natural gas plant, which will help ease the rate impacts of tight market conditions while maintaining reliability.
PJM reviews such basic inputs to its capacity market every four years, but the market conditions have changed so much since 2022 moving to a combined cycle reference unit no longer makes sense for the next auctions, FERC said.
Another major change is setting up a marketwide non-performance rate because some of the local delivery areas (LDA) have market conditions with a near-zero net cost of new entry (CONE), which means the non-performance penalties also were near zero. Keeping the non-performance rates above zero everywhere will help the RTO maintain reliability in an emergency.
“We agree with PJM that its proposed uniform Non-Performance Charge rate recognizes the fact that capacity emergencies often extend beyond a single LDA, particularly given PJM’s recently revised definition of Emergency Action, which is structured such that PAIs [performance assessment intervals] are triggered across an entire Reserve Zone or Reserve Sub-zone,” FERC said.
PJM also proposed a clarification that even if resources get out of a must-offer requirement, that does not provide a defense against market power abuse, like withholding capacity. That led to protests from market participants that the change would lead to them having the burden of proving their decisions to bid into the market are legitimate.
FERC noted that it’s impossible to write rules that explicitly ban every kind of fraudulent behavior because “the methods and techniques of manipulation are limited only by the ingenuity of man.”
“PJM’s proposal accurately states that an exception or exemption does not provide a defense to potential claims of withholding, market manipulation, or the exercise of market power,” FERC said. “PJM’s proposed language does not prohibit or limit an entity from providing evidence of the facts and circumstances relevant to defending against market power claims.”
$3B Natural Gas Pipeline Expansion Planned for Southeast
Kinder Morgan and Southern Natural Gas last week announced their proposed $3 billion natural gas expansion project called the South System Expansion 4 Project.
The project, which would deliver over a billion cubic feet of natural gas daily, would stretch nearly 300 miles across Georgia, Alabama and Mississippi. The companies are splitting the cost.
Edison International Faces Shareholder Lawsuit over LA Wildfires
Edison International, the parent company of Southern California Edison, has been sued for allegedly defrauding shareholders before the recent Los Angeles-area wildfires by assuring them it could shut down power lines to reduce the risk of catastrophic damage.
Shareholders said Edison made materially false and misleading statements for nearly four years before the fire by assuring its utility unit used a power shutoff program to “proactively de-energize power lines” to reduce wildfire risks during “extreme weather events.” The shareholders said reports claim Edison had not de-energized the lines, while lawsuits blamed the company’s equipment for starting the Eaton fire.
The lawsuit seeks unspecified damages for shareholders.
Lawmaker Proposes Law to Limit Rate Increases for Investor-owned Utilities
Sen. Aisha Wahab last week introduced a bill that would prohibit investor-owned utilities from proposing more than one rate increase per year.
The bill would also cap any rate increase to no more than the Consumer Price Index, which is a measure of the average change over time in the prices consumers generally pay for goods and services.
The Public Utilities Commission approved six rate increases for PG&E in 2024, which later announced it made a record $2.47 billion in profits.
Former House Speaker Michael Madigan was convicted last week on 10 counts relating to a nearly decadelong bribery conspiracy involving ComEd.
The jury also convicted Madigan of a plot to install ex-Ald. Danny Solis on a state board in exchange for Solis’ help securing private business for Madigan’s law firm. However, the jury acquitted Madigan of attempted extortion and other crimes involving Solis and an apartment project, as well as failing to agree on finding Madigan guilty of a broad racketeering conspiracy.
The most serious counts carry a maximum of 20 years in prison for the 82-year-old. No sentencing hearing has been set.
A House subcommittee last week advanced bills aimed at curtailing carbon sequestration pipelines.
One bill would allow landowners to seek declaratory judgment, or a legally binding explanation of their rights, from a district court if their property were subject to an eminent domain claim in an application before the Utilities Commission. Another bill would limit permits to liquified CO2 pipelines to 25 years and prohibit the UC from renewing those permits.
Constellation to Upgrade Calvert Cliffs Nuclear Plant
Constellation Energy last week said it will spend $100 million to upgrade equipment and electrical systems at its Calvert Cliffs nuclear power plant.
The company is upgrading the plant with the hopes of renewing its operating licenses. The current licenses for its two reactors expire in 2034 and 2036. The upgrades are expected to increase production by 10%.
The Public Utilities Commission last week approved an 8.17% rate increase for Xcel Energy natural gas customers, effective July 1.
The PUC approved the deal between Xcel and officials, which was down from an original request of 9.6%. The increase will add about $4.20/month to the average household.
The state Senate has passed a bill that would pull the state out of the Regional Greenhouse Gas Initiative.
The bill formally repeals Pennsylvania’s participation in RGGI, ensuring that any decision to impose electricity taxes or emissions programs must go through the legislative process rather than being enacted unilaterally by the executive branch.
The bill now moves to the House of Representatives.
The Santee Cooper Board of Directors last week unanimously approved a settlement that will enable the company to raise rates for the second time this year to recover $550 million in costs it incurred during a nearly five-year freeze on its electric rates.
The increase is expected to start at about 3% ($5/month) for the average household and gradually decline to less than 2%. The collection period will last 14½ years starting in July.
The resolution follows years of negotiations with Central Electric Power Cooperative and lawyers who filed a class-action lawsuit on behalf of ratepayers in 2017. The litigation followed the utility’s decision to abandon the expansion of the V.C. Summer nuclear plant after sinking billions of dollars into the doomed project.
The International Energy Agency last week raised its predictions for the world’s rising electricity demand, pegging the growth at almost 4% a year until 2027, up from its previous forecast of 3.4% a year.
The consuming of more electricity will be led by China, where demand grew by 7% last year and could grow by 6% a year over the next three years. Rising demand in the U.S. is expected to add the equivalent of California’s current power consumption to the national total by 2027.
Mark Uyeda, the acting chair of the Securities and Exchange Commission, last week announced he was directing the commission’s legal team to inform a federal appellate court that the regulator was pausing a rule that requires publicly traded companies to provide investors with information about the impact of their businesses on climate and the environment.
The decision to tell the U.S. Court of Appeals for the Eighth Circuit to pause any further proceedings in the matter is an indication the regulator may eventually move to rescind the rule or modify it.
The Tennessee Valley Authority is offering a voluntary buyout program that will give qualifying employees five days of pay for every full year of service to reduce the utility’s workforce and cut costs.
The offer was announced internally last year and applies across the company, TVA spokesperson Scott Brooks said. It is unrelated to the buyout offered to federal employees by the Trump administration.
TVA had 11,312 employees in 2024, up from 10,901 the year before, according to its latest annual financial report.
Energy Transfer, CloudBurst Sign Natural Gas Supply Agreement
U.S. pipeline operator Energy Transfer announced it has entered into a long-term natural gas supply agreement with CloudBurst Data Centers for its development in Central Texas.
Energy Transfer will provide up to 450,000 MMBtu/day of natural gas through its Oasis Pipeline to CloudBurst’s campus outside of San Marcos, Texas. The supply will generate up to nearly 1.2 GW of power for at least 10 years.
Toyota EV Battery Factory Ready to Begin Production
Toyota announced that Toyota Battery Manufacturing North Carolina, the automaker’s first in-house battery manufacturing plant outside Japan, is ready to begin production and will start shipping batteries for North American EVs in April.
The nearly $14 billion battery facility will produce batteries for hybrid electric vehicles, plug-in hybrid electric vehicles and battery electric vehicles. Production will be increased in phases, with line launches planned through 2030.
The Pipeline and Hazardous Materials Safety Administration has proposed a $2.4 million fine against pipeline company Denbury and its contractor, Republic Testing Laboratories, for taunting, pushing and blocking inspectors from doing their jobs while examining a carbon dioxide pipeline in Texas.
PHMSA’s report details six incidents from Aug. 30 to Dec. 7, 2023, that it says violated federal law at the facility. The report also says Denbury refused to provide data and prevented inspectors from photographing readings on equipment.
Syzygy Plasmonics said it would slash more than half of its staff by the end of March.
The company, which has raised more than $100 million in funding and received backing from Mitsubishi Heavy Industries America, notified the state of Texas that it plans to lay off 68 employees beginning March 31. The layoffs are “a result of the company’s current financial outlook,” CEO Trevor Best said.
Syzygy develops photoreactors that use light rather than combustion to power chemical reactions.
To build a reliable, affordable and clean electric power system that can meet the challenges of unprecedented demand growth, the U.S. energy industry and the customers it serves will need to shift their thinking about what a reliable system looks like, according to a new study from nonprofit think tank Energy Innovation Policy & Technology.
“Grid operators, reliability authorities and utilities are ringing reliability alarm bells, and outdated views on grid reliability are colliding with slow-moving institutions,” the report says. New concepts of reliability are needed so that “utilities and grid operators can build new generation faster and more efficiently, while simultaneously deploying strategic demand-side solutions at scale.”
In opposition to President Donald Trump’s call to ensure reliability by building new fossil fuel-fired plants, Energy Innovation argues that “reliability is a characteristic of the whole electric system, to which individual resources contribute. Every source of electricity has different characteristics that should complement each other in a balanced portfolio.”
Examples include the increasing number of grids around the world that provide reliable service with major amounts of solar, wind and storage online, it says.
“For instance, large grids in the Midwest, Texas and California regularly operate using more than 70% renewable energy, and … Iowa and South Dakota generated roughly 60% of all their electricity in 2023 from wind power,” the report says. “In Hawaii, South Australia and Denmark, grids are already operating using 100% renewable power for days at a time.
“Notably, though, these jurisdictions have adjusted their planning and operating practices to integrate higher penetrations of renewable energy and battery storage without compromising reliability.”
The Energy Innovation report is intended to be a primer for U.S. regulators and policymakers to demystify the often-daunting technical details of “grounding reliability discussions in meaningful solutions … while also discussing the challenges in achieving a 100% clean electricity grid.”
Caught between the high speed of data center buildout and the much slower regulatory speed of project permitting and interconnection, the industry is at “an inflection point where the pressures are growing,” Sara Baldwin, Energy Innovation’s senior director of electrification policy and co-author of the report, said in an interview with RTO Insider. “So, the lag that is created in slow decision-making is actually exacerbating the challenges. It’s creating more of an energy emergency. … Excuses are standing in the way.
“We’re actually not confronting technical challenges as much as we’re confronting human challenges,” Baldwin said. “And in some ways, human challenges are harder because human beings want to have full control over all the decision-making that falls underneath their jurisdiction and in their purview.”
An example is the traditional thinking about the need for system inertia, provided by spinning turbines and typically powered by fossil fuels or hydropower, often cited by industry leaders arguing for more baseload power.
Specifically, they say, inertia can help to keep frequency levels on the grid stable in the event of stress on the system or disturbances caused by extreme weather.
Report co-author Michelle Solomon, Energy Innovation’s manager for electricity policy, countered that “traditional inertia isn’t actually something that you need to run the grid. Traditional inertia is part of this broader frequency response set of services, and actually, in many cases, inverter-based resources can respond faster … and provide what’s called synthetic inertia.”
Grid services provided by inverter-based and synchronous resources | Milligan Grid Solutions
The report notes that “while inertia slows frequency decline, it is not capable of restoring frequency back to its nominal level. Instead, services like fast frequency response, which can both slow the rate of frequency decline and help restore frequency are needed. …
“Inverter-based resources (IBRs) can ramp up and down much more quickly than a conventional power plant, making them more responsive to changing grid conditions,” the report says. “IBRs can provide nearly instantaneous fast frequency response.”
Can IBRs Deliver?
But the report also acknowledges that a significant gap exists between what IBRs are technically capable of doing and industry confidence in their ability to deliver when needed in real-life situations.
“Developers must be disciplined to program their resources to ride through a voltage event [even] if such a setting should compromise their asset or their operating revenues,” the report says. Similarly, utilities and grid operators need to “quantify and understand how IBRs respond during a grid emergency” and ensure appropriate compensation in cases where they “provide a superior response.”
For Mark Lauby, senior vice president and chief engineer at NERC, such recommendations contain a lot of “ifs” and potential threats to reliability. While he agreed that the future of the U.S. grid lies in a portfolio of diverse resources, including IBRs, “they haven’t been proven. We haven’t got a lot of them on the system.”
New and traditional technologies have “got to work together, not against each other,” Lauby said in an interview with RTO Insider.
“Batteries can move very quickly as long as they are charged … and inverter-based resources can mimic some of the things like inertia on the system, but they have got to be able to run on the battery,” he said. “The battery better be charged, and if you have long-term events, where you’ve kind of exhausted your battery storage, now you don’t have energy and, by the way, you don’t have essential livelihood services.”
Lauby also said that while management of demand-side resources can be effective for shaving peak demand, which can be predicted and prepared for, stress on the grid is now coming at less predictable times and locations.
IBRs could build more uncertainty into electric systems, on top of the essential variability of wind and solar, he said. For example, a dayslong drop in wind could take thousands of megawatts off the grid.
NERC is working on a range of standards intended to build industry confidence in the reliability of IBRs and other new technologies, he said.
Natural Gas Won’t
The Energy Innovation report comes at a pivotal moment in industry and public debates over the most effective short-term strategies for meeting data centers’ ravenous appetite for electricity, which could make up 12% of U.S. energy demand by 2028. (See Berkeley Lab: Data Centers Could Need 12% of US Power by 2028.)
The Trump administration and congressional Republicans are advocating for regulatory changes to allow faster permitting, interconnection and construction of natural gas plants, which they are promoting as baseload power that will keep the lights on and cut consumers’ bills.
For example, in a speech on the House floor Feb. 13, Rep. Julie Fedorchak (R-N.D.) announced her plans to form an AI and Energy Working Group that would target increasing baseload power on the grid.
“The rapid, forced transition to intermittent power sources — paired with the retirement of reliable baseload generators — has left our electric grid increasingly vulnerable to outages,” Fedorchak said.
On Feb. 11, FERC approved PJM’s Reliability Resource Initiative, a one-time measure aimed at adding extra capacity to the RTO’s system by allowing generation that meets certain criteria to essentially jump its notoriously backlogged interconnection queue. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)
Renewable developers opposed the initiative, saying it is designed to allow large natural gas plants to get online ahead of the approximately 286 GW of projects, mostly wind, solar and storage, that have been waiting for years for PJM to work through its queue backlog.
An illustrative example of grid services working together to stabilize frequency | Milligan Grid Solutions
On the other side, the Solar Energy Industries Association has been attempting to pivot the public dialogue on demand growth to include solar, storage and other renewables as “the fastest technologies to develop and deploy. Not only are they much simpler to engineer, their supply chains are more robust than natural gas (which currently faces a bottleneck in gas turbine blades),” SEIA said in a Feb. 4 blog post. Natural gas plants can also be 2.5 times more expensive to build, it said.
The Energy Innovation report joins a recent study from Duke University in arguing for aggressive deployment of demand-side resources that can open up capacity on the grid versus inherently slow and costly fossil fuel generation. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)
“While strategic new generation and transmission solutions are needed to meet growing demand, these large investments will show up on customers’ electric bills for decades to come and could increase emissions without helping affordability or sufficiently improving reliability,” the report says.
“But aggressive investments in demand-side solutions are a cost-effective, least-regrets way to manage growth in the near term, while unlocking their full potential over the long term.” Similarly, getting solar, wind and storage online quickly will buy time for the development of dispatchable, zero-carbon generation that could replace fossil fuels, the report says.
Pointing to the 2,600 GW of mostly renewable projects in RTO and ISO interconnection queues, Solomon said, “Because wind and solar and batteries are already in the process of being built, [they] can come online in a matter of a year and a half. … The gas plants they are looking at building are not coming online until 2030. Natural gas isn’t the solution that’s going to deliver.”
Oregon Sens. Jeff Merkley and Ron Wyden have demanded the Trump administration explain and justify recent actions that could drastically cut staff at the Bonneville Power Administration and compromise the federal power agency’s ability to maintain grid reliability in the Pacific Northwest.
In a letter dated Feb. 14, the state’s two Democratic U.S. senators warned President Donald Trump that moves by his newly created Department of Government Efficiency (DOGE) could result in the “imminent departure” of 20% of BPA’s workforce and pose “a direct and immediate threat to the reliability of the electrical grid that serves millions of American families and businesses” in the region.
The 20% figure appears to have its origin in a Feb. 13 Oregon Public Broadcasting article that said BPA could see the firing of an additional 350 to 400 “probationary” employees on top of the 200 staffers who agreed to accept DOGE’s “deferred resignation” buyout offer made to the entire federal workforce last month. (See BPA Committed to Trump’s Energy Goals, Hairston Says.)
BPA staff were offered the buyout despite the fact that its operations are self-funded through its power sales, made primarily to the Northwest’s large number of publicly owned utilities that rely on the agency for low-cost power generated by the region’s extensive network of federally owned hydroelectric dams.
BPA also has rescinded 90 job offers following the federal hiring freeze Trump imposed after his inauguration Jan. 20.
“Employees on the ground are already warning that these actions will make it nearly impossible to strengthen and expand the grid as needed,” Merkley and Wyden wrote. “Instead, BPA will be forced into ‘damage control’ mode, struggling just to ‘keep the lights on.’ This is not speculation; it is the reality voiced by those who operate our energy infrastructure every day.”
The senators called the cuts “reckless” and “financially ludicrous,” particularly in light BPA’s status as a self-funding entity.
“If the administration’s goal is truly to ensure reliable, secure, and affordable energy, then why are you actively dismantling the most effective and self-sustaining power system in the country?” they wrote.
The senators’ letter also demanded Trump answer a series of “critical” questions by Feb. 28, including:
How the administration can justify the cuts given BPA’s self-funding status.
How it plans to address operational and safety risks “posed by the loss of experienced linemen, engineers, and dispatchers” and avoid grid failures in the face of the expected growth in electricity demand stemming from new data centers.
Whether the administration will commit to lifting the hiring freeze on “mission-critical” positions at BPA that would prevent “de-stabilization” of the Northwest grid.
The letter also asks Trump to explain the role of DOGE in BPA’s staffing decisions and describe its “qualifications in managing complex energy infrastructure.”
Some of the senators’ questions overlap with those RTO Insider asked the U.S. Department of Energy last month upon learning that BPA staff had been among the federal workers offered buyouts. DOE has not responded to or acknowledged those questions. (See BPA Employees Confront Trump’s ‘Fork in the Road’.)
Politico on Feb. 17 reported that 30 “Department of Energy” employees who work on grid maintenance for BPA had been asked to return to their jobs after having been terminated.
BPA confirmed to RTO Insider that those employees are in fact BPA staff.
New York’s Public Service Commission has approved an implementation plan to push for installation of 200 MW of residential energy storage and 1,500 MW of retail storage (18-E-0130).
These will make up part of the state’s 2030 goal of 6 GW of storage, which is equal to about 20% of the state’s present-day peak load. The remaining 4,300 MW is to come from bulk storage; the PSC continues to review the proposed bulk implementation plan.
The state has a way to go. As of April 2024, there was only about 400 MW of storage operational in New York. Nearly 600 MW was under contract but not yet online, and 300 MW was procured but not under contract. Construction of wind and utility-scale solar also is progressing slowly in New York.
Gov. Kathy Hochul (D) in January 2022 doubled the state’s 2030 storage target from 3 GW to 6 GW. The PSC approved the roadmap for reaching 6 GW in June 2024; the implementation plans will guide procurement efforts and set the stage for financial incentives to be allocated. (See NY Sets Strategy to Reach 6 GW of Energy Storage.)
The implementation plans are living documents, however.
They were prepared by the New York State Energy Research and Development Authority based on the June 2024 roadmap. In its approval Feb. 13, the PSC directed NYSERDA to make some modifications based on stakeholder feedback. Continued refinement may be necessary, the PSC noted, due to changes in market conditions, technology or other factors specific to retail and residential storage.
Fire safety is among those moving targets.
Battery energy storage system (BESS) fires are rare, but those that do occur have been very well publicized, with a noticeable effect on public opinion. This can become a significant hurdle to BESS development in a home-rule state like New York, where local governments have the ability to pause or block development of some energy infrastructure development.
After three unrelated BESS fires in rapid succession in 2023, New York state put together a task force that issued a series of recommendations to limit the likelihood of BESS fires. (See NY Fire Code Updates Recommended for BESS Facilities.) Those recommendations have been forwarded for consideration in the 2025 update of the New York State Uniform Fire Prevention and Building Code.
The PSC wrote in the order: “The commission directs NYSERDA to implement new fire safety requirements as necessary based on updates to the building code for fire safety, regarding energy storage systems.”
A significant buildout of energy storage is necessary if the state is to increase its reliance on intermittent renewables and decrease its use of fossil-fired energy generation, as it hopes.
PSC Chair Rory Christian noted this in a Feb. 13 news release, saying: “Energy storage is crucial as New York works to decarbonize our electric grid, manage increased energy loads, and optimize the integration and use of clean, renewable energy. Today’s decision moves forward our landmark energy storage program.”
The cost to ratepayers is unknown, again because of unknowable future energy market fluctuations.
An analysis performed as the roadmap was prepared in 2024 estimated the cost of subsidies for the 6 GW buildout at $1.3 billion to $2 billion; $200 million already had been allocated as of April 2024.
The analysis further estimated that $2 billion worth of grid upgrades could be avoided if 6 GW of storage capacity were online, and that additional benefits would accrue to society through such things as cleaner air and reduced health care costs.
New York claims its storage goal is the nation’s most ambitious, but that distinction is diminished by the fact that California and Texas already are far beyond the 6 GW the Empire State hopes to achieve by 2030. S&P Global reports that as of the second quarter of 2024, California had 10.3 GW online and Texas had 7.7 GW.
The deadline to submit bills for California’s 2025 session is looming, and backers of the West-Wide Governance Pathways Initiative expect legislation without unnecessary fluff that will change CAISO’s governance structure and allow a new regional organization (RO) to oversee the ISO’s Western energy markets.
California backers of the Pathways Initiative’s Step 2 plan have until Feb. 21 to submit a bill for the state legislature’s 2025 session. Under Step 2, which requires statutory changes, Pathways would create a new independent RO to govern rules for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market (EDAM).
The Western Energy Markets (WEM) Governing Body and ISO Board of Governors approved Step 1 in August, elevating the Governing Body’s authority over CAISO energy markets. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)
The anticipated Step 2 legislation comes as entities weigh whether to join SPP’s Markets+ or EDAM. The two markets have yet to go online, but both are competing for participants.
EDAM’s governance structure has been a concern for stakeholders uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. (See Pathways Step 2 Not Good Enough, Markets+ Backers Say.)
Pathways Launch Committee member Brian Turner, director of Advanced Energy United’s regulatory engagement in the West, expects the Step 2 legislation to address those concerns by preserving states’ policy authority. (See Pathways ‘Step 2’ Plan Elicits Praise, Concerns — and Advice.)
“California’s clean energy policies, greenhouse gas goals, etc., are preserved and not imposed on other states,” Turner told RTO Insider. “Other states can make their own decisions and have them be respected under the governance framework that we outlined.”
Turner added that states participating in EDAM are “not being asked to give up any of its authority or autonomy on its resource and clean energy policy and other public policy goals.”
Ben Otto, energy consultant with NW Energy Coalition, shared Turner’s sentiment, saying that a key innovation of the Pathways proposal “is that moving forward with regional governance for EDAM does not depend on California legislation. Rather, the legislation will enable California entities to participate in the regional market and CAISO to contract as an operator.”
Otto said he expects the bill to be short and enable CAISO to participate in a regional day-ahead market under certain conditions.
“The conditions match the governance structures, public interest protections, and other elements of the Pathways Initiative proposal,” Otto said.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association (IEP) and former board chair at CAISO, similarly said he expects “the legislation to be short and to the point.”
“I expect some language on protecting the public interests and respect for the energy polices of the various states. Hard stop,” Smutny-Jones said. “This is not a new energy policy, but a bill authorizing how the Western transmission system can be more efficiently operated to the benefit of California and Western ratepayers.”
A potential hurdle in the process could be if stakeholders add unrelated energy policies to the bill, said Sara Fitzsimon, policy director at IEP.
“This bill needs to only focus on authorizing the CAISO’s participation in an independent RO. Any other language outside achieving that goal should not be included, as it could cause delays in getting this critical language through the legislature,” Fitzsimon said.
The anticipated bill also comes as California grapples with wildfires and affordability issues, which could potentially cause delays, according to Leah Rubin Shen, managing director of Advanced Energy United’s legislative, political and regulatory engagement in the West.
Though the bill should only enable Step 2, Rubin Shen hopes the conversation around markets doesn’t end with the bill but rather spurs parties in the West to continue to discuss how to “evolve beyond a day-ahead market” by, for example, building an RTO.
“So, to the extent that this is a step forward, we are hopeful that it is a step that is good in its own right, and also a step that maybe has further steps down the road,” Rubin Shen said.
After a two-month delay, ERCOT on Feb. 13 released its semiannual Capacity, Demand and Reserves report, which provides potential future planning reserve margins five years into the future during the high-demand periods of the winter and summer seasons.
According to the report’s most dire scenarios, the Texas grid operator may not have enough power to meet that peak demand during next year’s summer. However, ERCOT said in a statement that the CDR report is a “snapshot of potential supply resource availability and demand” and is not intended to represent expected real-time operations scenarios.
The report was delayed so that revisions to its parameters could be made to “better represent the performance of grid resources and the dynamic nature of the ERCOT grid,” the grid operator said.
ERCOT CEO Pablo Vegas appeared before the Texas Public Utility Commission to roll out the report. He told the commissioners that the state’s “fast-growing” environment, with large loads able to quickly connect to the grid before the infrastructure is ready, has placed “downward pressure on planning reserves.”
“We see that trend continuing in this CDR as well,” Vegas said. “Some of the changes that we’ve made have accelerated or changed the view of those planning reserve margins shrinking, but … the overall trend of a rapidly growing economy, rapidly growing demand as a result of that … the energy economy is working to keep up with that.”
The CDR projects PRMs, currently 18.9% for peak load and 10.5% for net peak load (when solar generation drops during the early evening hours when loads are still high), will fall to 8.3% and 21%, respectively, during summer 2027. The 2027/28 winter PRMs also drop into negative territory.
ERCOT last year projected demand would reach 150 GW by 2030, fueled by data centers, industrial and petroleum production facilities, and cryptocurrency miners. The CDR projects demand to peak at 140 GW in 2029. The grid operator’s current peak is 85.5 GW, set in August 2023.
“It’s important to note that all scenarios in this report have a certain level of uncertainty that can alter the long-term resource adequacy outcomes, and these forecasts will change over time based on a variety of factors,” ERCOT said in releasing the report.
Skepticism
The release was met with skepticism by several industry insiders.
Stoic Energy’s founder, Doug Lewin, jumped on a comment made by Vegas to the PUC that the CDR “doesn’t model what the market would typically do.”
“Exactly,” Lewin said as he moderated a discussion on his Substack feed. “I think this report is largely worthless. Might be worse than worthless because people panic for no good reason.”
Pointing to an ERCOT slide with PRMs between 32.4 and 21%, Lewin said it “looks scary, but it’s in no way reflective of the reality of the market. So, what’s the point?”
The “Texas CDR report is far less important fundamentally than in the past years and is more a political signal in 2025,” Julien Dumoulin-Smith, a financial analyst with investment banking and capital markets firm Jefferies, said in an email to his audience.
“The optics of … -2 to -33% reserve margins likely leads to a political response,” he said, saying those optics likely will lead to efforts to subsidize generation and potentially less support for data centers.
Dumoulin-Smith said that draft legislation (Senate Bill 6) could be “adverse” for power companies. The bill would require a “minimum transmission fee” based on large users’ peak load; require disclosure of backup generation; require PUC approval for any data center to buy existing thermal generation’s output; and establish a new ancillary service similar to ERCOT’s current emergency response service to “competitively procure demand reductions from large load customers” with 24-hour notice.
The changes to the CDR include new load forecasts, as directed by House Bill 5066, that come directly from transmission and distribution utilities’ projections of new loads. Previously, ERCOT staff only counted loads with signed connection agreements.
It now will use effective load-carrying capabilities (ELCCs) to measure renewable resources’ and battery storage’s reliability contributions. The ELCC metric is used in most capacity markets, but ERCOT operates an energy-only construct.
The CDR also will illustrate both peak and peak net reserve margins and include demand-side resources such as demand response programs. ERCOT said the potential 9.72 GW of thermal generation in the Texas Energy Fund (TEF) did not meet the rules for inclusion in the base CDR scenario. It said additional scenarios did include the full TEF generation portfolio’s potential effect on reserve margins.
“The new parameters and scenarios in the CDR better represent the performance of grid resources and the dynamic nature of the ERCOT grid,” ERCOT said.
“The methodology changed significantly and … is extremely suspect. ELCC is a massively flawed metric,” Lewin said, noting “centrally planned, administratively determined capacity values” are necessary in capacity markets, but not in an energy-only market.
“That’s part of the point of an energy-only market. Markets are far better at determining which resources can meet demand,” Lewin said. “Very hard to get good enough data to determine these things administratively. You’ll always be behind.”
The CDR, originally released at 9:33 a.m. Feb. 13 in a market notice, was revised twice to reflect corrections to formulas in the “load-resource scenarios” tab that affected TEF scenarios.
Dumoulin-Smith said “significant math errors” overstated projected supply in 2029 by about 28 GW, a “substantial delta” on an approximate 100-GW base. The initial report had one reserve margin of 22% that was corrected to 3.9% in the second report and uses a “stale” load forecast from summer 2024, he said.
The analyst said he is “doubtful” many of the TEF projects will be completed without further support. Texas Lt. Gov. Dan Patrick (R), as president of the state Senate, has said he might seek $5 billion in state funds as incentives to build more natural gas power plants; the TEF’s In-ERCOT Generation Loan Program already has been allocated $5 billion for low-interest loans, but the current portfolio will require $5.34 billion in loaned funds.
ERCOT says future economic growth will provide opportunities to improve PRMs. It says potential short-term solutions include expanding DR capabilities and broadening the firm-fuel supply service program. It also says it could further improve energy storage optimization and work with large loads on flexibility capabilities.
“ERCOT looks forward to working on short- and long-term solutions with the Texas Legislature, PUC and stakeholders to continue to strengthen the reliability and resiliency of the Texas power grid,” CEO Vegas said.
