MIAMI — For Dan Beans, CEO of Roseville Electric Utility in California, the disruptions brought by the COVID-19 pandemic taught some hard truths about the resiliency of the global supply chains on which companies like his rely for essential materials.
“We have learned several lessons. One of them is: No one’s coming to save you,” Beans said during a panel on supply chain issues at NERC’s quarterly technical session during the Board of Trustees and Member Representatives Committee meetings in Miami.
“And what I mean by that is mutual aid. We’ve always done a really good job with that, but when it comes down to what do I have to hold back from my customers during the supply chain crisis, and what can I give to [neighbors], it makes it hard. So mutual aid is definitely at risk with a supply chain situation as dire as this,” he said.
Beans said the pandemic-induced supply issues caused Roseville Electric’s inventory practices and project timelines to go “out the window” and that even after switching from a one-year procurement cycle to three years, the utility still has not been able to rebuild its inventory of spare parts, with more than 200 transformers on order since 2022. The city’s growing population has added to the pressure by creating demand for housing.
Roseville Electric has been able to address the transformer shortage by finding a supplier based in South Korea, which Beans said has provided good equipment. But he worried that trade tensions might create new problems for his utility and others.
“I don’t know that the policymakers understand this,” Beans said. “Transformers aren’t toilet paper; this is not going to be at Costco next week. This is going to take a lot of time, [and there are] a lot of different knobs to turn. We need some immediate action, and some long-term action.”
The electric sector is not the only industry experiencing supply chain issues in recent years, according to Betsy Soehren Jones, executive director of the Critical Infrastructure Security Consortium, which works on behalf of electric, gas, oil, transportation, water asset owners and business organizations to protect supply chains and suppliers from cybersecurity and other risks.
Focusing on the challenge of software provenance and cyber vulnerabilities, she suggested utilities could learn from the experiences of peers in the automotive industry.
“What they did was, they pulled all of their major suppliers into a room, and they sat down and said, ‘These are our expectations, these are the threats, these are the risks that we see as an industry,’” Soehren Jones said. “‘We need to figure out a better way, between all of us, to get the software bill of materials standardized. … We need to know what’s inside of things. We need to understand where are you sourcing your materials? … Because at the end of the day, we are the ones that are responsible for selling that product to the market.’”
Soehren Jones said manufacturers and their suppliers set up a “standardized library of information” that allowed suppliers to continue innovating in their products while manufacturers could stay abreast of major updates, and suggested that a similar approach could keep utilities from stifling innovation among their vendors.
She added that the U.S. Defense Department’s Defense Innovation Unit (DIU) could serve as a model for the electric industry. DIUs were created in 2015 to help technology startups enter the DOD market and adapt to the department’s procurement regulations.
Jeremy Rand, vice president of procurement at Arevon Energy, joked that product sourcing has given him his “first five gray hairs” over the past three years. He admitted that utilities “don’t understand … where our products are sourced from” as well as they should.
Rand said the silver lining of the pandemic and other trade disruptions was that it forced the industry to take a hard look at these issues and start to identify areas for improvement. However, he emphasized that utilities are still in the process of fully understanding the problems they face.
“We definitely are learning much more in depth, and there is much better communication with those vendors than there ever has been to get down to those suppliers and understand how [they] are affected [by] tariffs [and other] disruptions … and how that synergy between all of them comes together so we can understand the risk profile of our projects,” Rand said.
With West Virginia lawmakers looking on, U.S. EPA Administrator Lee Zeldin on Feb. 18 signed an approval granting the state primary authority for permitting carbon dioxide injection wells in the state, which could be used in carbon capture and sequestration projects.
Under the approval, West Virginia will have “primacy” for permitting the wells — called Class VI wells — that are supposed to permanently sequester carbon dioxide in deep underground caverns, while also ensuring no CO2 leakage or other negative impacts affecting drinking water.
Zeldin hailed the approval as an example of “the spirit of cooperative federalism that is alive and well in the Trump administration. … We here at EPA respect the talent that’s out there [in] the states, the understanding of how to do it better and faster.”
Interior Secretary Doug Burgum spoke of North Dakota’s experience when he was governor, after it because the first state to be granted primacy for Class VI permitting in 2018, during the first Trump administration.
“We’ve permitted some of the largest CO2 storage areas in the country. We’ve done all that in time frames that have been as short as six months from the beginning of the permit application, and we’ve done that without any risk to the environment,” Burgum said. Permitting primacy also drew “a record amount of capital investment coming into our state,” used in part for the development of low-carbon fuels such as ethanol.
West Virginia is the fourth state to be granted primacy, following North Dakota in 2018, Wyoming in 2020 and Louisiana in 2023. The approval will go into effect 30 days after it is published in the Federal Register, according to the EPA announcement.
Sen. Shelley Moore Capito (R-W.Va.), chair of the Senate Environment and Public Works Committee, cited the state’s long history of energy production and ongoing work on carbon sequestration at the National Energy Technology Laboratory in Morgantown, W.Va.
“EPA [should] be the overarching responsible agent to give us guidelines and give us expertise and make sure we’re within the guidelines,” Moore Capito said. “But really, let us work together to make sure that we get not just the best results, the quickest results [but] probably the most economic results and probably the most long-lasting results.”
Under the Safe Drinking Water Act, EPA has jurisdiction over six classes of injection wells, from Class I, used to “inject hazardous and non-hazardous wastes into deep, underground rock formations,” to Class VI, used for long-term storage or sequestration of CO2 in “subsurface rock formations.”
Many states have primacy for Class II wells, which are used to sequester fluids used in oil and gas production. Only six states ― Arizona, Iowa, Minnesota, New York, Pennsylvania and Virginia ― and the District of Columbia still are under federal jurisdiction for all classes, according to an EPA map.
Class VI permitting requires the injections wells to be designed “in a manner that will prevent any CO2 or formation fluids from leaking outside of the injection zone.” Well construction will depend on “site-specific conditions,” and materials used should be “corrosion resistant and compatible with the conditions and fluids to which they may be exposed.”
Corrosion monitoring must continue for the life of the project.
According to EPA’s Class VI permit tracker, the agency has 161 applications under review and targets completing individual reviews within 24 months of receiving an application. West Virginia appears to have two projects in the queue, one received in April 2024, and one received in September 2024.
Two energy companies, citing equipment procurement constraints, have withdrawn projects from the Texas Energy Fund’s (TEF) In-ERCOT Load Program. The withdrawals leave 16 projects that have advanced to a due diligence phase (56896).
ENGIE Flexible Generation NA filed Feb. 17 at the PUC to withdraw its Perseus project, a 930-MW peaking facility, from consideration. The company said it has “become evident” supply chain issues would delay the project’s schedule, making it impossible to meet a December 2025 deadline for statutorily mandated initial loan disbursements.
ENGIE also withdrew its Spenser project from further consideration. The project, a 483-MW peaker, did not advance to the due diligence phase.
In January, Howard Energy Partners withdrew its co-generation facility at its Javelina processing plant in Corpus Christi, attributing it to similar “equipment procurement constraints.” The company said the delays would prevent it from meeting the same December timelines as ENGIE.
The Javelina facility, consisting of a 134-MW combined cycle facility and a 192-MW simple cycle unit, would make 271 MW available for dispatch.
PUC spokesperson Ellie Breed said the PUC anticipates proposing an additional project or projects for advancement to due diligence to replace the ENGIE project.
The withdrawals leave at least 16 projects in the TEF portfolio, accounting for about 8.5 GW of capacity. Loan information is confidential.
PUC Approves Non-ERCOT Program
The PUC established another TEF program when it approved a rule during its Feb. 13 open meeting that creates a program for grants to utilities and power generators outside the ERCOT region.
The rule sets up the Outside of ERCOT Grant Program as one of four programs under the TEF, which Texans approved by constitutional amendment in 2023. The grants can be used to finance modernization, weatherization, reliability and resiliency improvements, and vegetation management (57004).
“Every corner of our state faces unique weather threats and challenges,” PUC Chair Thomas Gleeson said in a statement. “The rule approved today will ensure that the TEF improves electric reliability for all Texans, whether inside or outside the ERCOT region.”
The ERCOT region covers about 75% of Texas, except for portions of East Texas, West Texas and El Paso.
ADER Project Moved to ERCOT
The commission endorsed staff’s recommendation to move the aggregated distributed energy resources (ADER) pilot project into ERCOT’s stakeholder process to determine the best way to move the initiative forward (53911).
The action will dissolve the ADER Task Force, which was created in July 2022. Its work has resulted in three virtual power plants, or ADERs, participating in the wholesale energy market and providing certain ancillary services. The ADERs can provide 25.5 MW of energy, 111 MW of non-spin reserve service, and 8.7 MW of ERCOT contingency reserve service.
“The pilot can only benefit from the larger stakeholder group at ERCOT, and that will facilitate its coordinated growth, along with other projects within the ERCOT market system,” PUC staffer Ramya Ramaswamy told the commission. She also recommended the grid operator file progress reports every six months.
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, 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/share. This compares with $1.62 billion and $5.01/share for 2023.
Adjusted (non-GAAP) income was $2.74 billion, or $8.67/share in 2024. During the year, Constellation twice bumped its full-year guidance for adjusted earnings higher, but results still exceeded the final $8 to $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 to $9.60/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.”
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.
$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.
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 of 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.
