- NERC issues a rare Level 3 alert, warning of grid oscillations that threaten the reliability of the bulk power system.
- FERC sees summer power challenges from increased demand as well as extreme weather, drought and more.
- A U.S. Court of Appeals panel hears arguments as Michigan sues to block the Energy Department’s orders to keep coal plants open beyond scheduled retirement dates.
- As elected officials worry about affordability, California – like other blue states – is backpedaling from policies that raise electric rates to meet emissions targets.
- FERC Chair Swett expresses concern that grid operator PJM may have grown too big to function. Commissioner Chang disagrees.
- Commissioner LaCerte confirmed for another five years at FERC.
Grid Reliability Regulator Issues a Rare ‘Level 3’ Alert, Citing ‘Unprecedented Challenges’
The North American Electric Reliability Corp. (NERC), a non-profit regulator whose mission is ensuring the security of the electric grid, issued a rare Level 3 alert – NERC’s highest level – on May 4. The alert occurred as “the grid faces unprecedented challenges from a surge in large power consumers,” mainly data centers, said a NERC press release, which continued:
The Level 3 Alert was issued as NERC observed customer-initiated large load reductions and significant oscillations that occur in seconds, leaving little or no room for real-time responses, threatening BPS [bulk power system] reliability
In a piece headlined, “A major watchdog says data centers are wreaking havoc on North America’s power grid,” Business Insider explained, “The constant, rapid fluctuations between extremely high and extremely low power use levels can put entire electric grids at risk of going offline.”
The alert requires grid entities to take seven actions to “address immediate risks posed by computational loads” because these entities “generally did not have sufficient processes, procedures, or methods to address emerging computational loads.”
According to Utility Dive, “Transmission planners and operators, system planners and balancing authorities are among the entities that must act. The required actions address the modeling, study, operation, protection and control of computational loads, including artificial intelligence training and cryptocurrency mining.”
NERC is worried that large loads are being added so quickly that they are making the grid unstable at a time when the institutions that manage the grid don’t yet have good reliability systems in place to cope with the change.
Some of the requirements in the alert seem utterly basic. For example, in a separate document headed “Essential Action to Industry,” NERC states, “TPs [transmission planners] and PCs [planning coordinators] should develop a detailed list of modeling data, settings, and parameters needed from computational loads and distribute this to TOs [transmission owners] in their footprint. TOs should reflect this in their facility interconnection requirements.”
The loads are so new and so large that the whole process is going to take longer than anticipated, Andrew Webber, CEO of Digital Power Optimization, a firm that builds and manages data centers, told Utility Dive.
“It will take years of coordinated effort in the drafting of new regulations,” said Webber, who pointed to the need for understanding limitations and opportunities related to physical equipment and software and control systems and the “re-prioritizing various loads all throughout society.”
At CERAWeek, the Houston energy conference in March, Laura Swett, chair of the Federal Energy Regulatory Commission (FERC), complained about a lack of communication between data centers and regulators. Webber said that both FERC and NERC are facing challenges “in getting genuine buy-in and wholehearted acceptance by the data center industry as it pertains to grid reliability.”
NERC said in a statement. “The grid faces unprecedented challenges from a surge in large power consumers.” Summer peak demand across the bulk power system is expected to rise 24% in the next 10 years, with data centers accounting for most of the increase, the organization said in its most recent Long Term Reliability Assessment, published in January.
FERC Sees Challenges This Summer as Heat, Drought, Low Snowpack and Wildfires Exacerbate the Strain of Higher Demand
“Forecasted higher-than-average summer temperatures and uncertainty from extreme weather events are expected to challenge the electric grid this summer,” concluded the staff of FERC in its annual Summer Energy Market and Reliability Assessment.
Addressing these challenges may be difficult, said the report, because “several weather conditions build off each other, namely low snowpack, continued drought, and wildfires. The resulting low water levels are also expected to restrict hydropower generation in key regions.”
In addition, said the report, “electricity consumption is expected to be higher in summer 2026 than in each of the previous five summers,” with natural gas demand rising. The graphic below (Figure 13 from the report) shows how over the previous five years, consumption was fairly flat, but this year it is expected to rise significantly, especially in August.
FERC expects the highest wholesale electricity prices will be registered in the Mid-Atlantic region, where the regional transmission organization (RTO) is PJM Interconnection (see below), and in New York and New England. “Compared to last summer, natural gas prices are also expected to increase at major eastern trading hub but decrease at most western and midcontinent trading hubs.”
The good news in the report is that of the 16 grid regions in the U.S., only a few face “a higher likelihood of tight supply and reliability issues during extreme conditions”: New England, the Northwest and the western part of the territory covered by ERCOT, the Electric Reliability Council of Texas.
FERC notes that major capacity additions are helping meet demand in Texas, where a total of 25.6 gigawatts (GW) of new generation is coming online between October 2025 and September 2026; about half is from natural gas and half from solar. The Western Electricity Coordinating Council (WECC) will add a total of 12.6 GW, along similar proportions as Texas, and MISO (the Midcontinent Independent System Operator) will add 10.8 GW, mostly solar. Unfortunately, PJM, the largest grid operator, covering all or part of 13 states and the District of Columbia, will add just 4.8 GW.
Also troubling are retirements. MISO will lose 3.2 GW of coal generation; WECC, 2.3 GW, mainly natural gas; and PJM, 1.8 GW of coal.
Those retirements will affect resource adequacy in the years ahead. NERC projects that summer peak demand across North America will grow by about 224 GW over
the next decade. That is a 69% increase over the previous year’s ten-year forecast and roughly a 24% increase from 2025 peak demand. Most of the new load, says NERC, will come from data centers.
The NERC summer report drills down on natural gas. It cites a forecast by the U.S. Energy Information Administration (EIA) that gas production in the U.S. will rise to 109.3 bill cubic feet per day (Bcfd) this summer, up from 108.2 Bcfd last year and 94.9 Bcfd in 2021. But exports are rising as well, in part because the war in Iran has limited shipments from Gulf states. Liquefied natural gas (LNG) exports from the U.S. will jump to 15.8 Bcfd. Natural gas storage inventories, however, are strong.
A worrisome element this summer is snow – not enough of it. States the report:
Snowpack is important for summer electric system reliability, serving as a natural energy reservoir that gradually releases water during spring and summer and fuels hydropower generation when electricity demand increases with rising temperatures. But across the West this summer, there is record low snowpack. This could curb production of hydropower throughout the West, where over half of all U.S. utility-scale hydropower generation capacity is concentrated.
Drought conditions prevail over about half the nation, including the area fed by the Colorado River, which provides power for the Glen Canyon (1.3 GW) and Hoover (2 GW) Dams. Drought also heightens the chance of wildfires, which can destroy transmission and distribution infrastructure. The National Interagency Coordination Center predicts significant wildfire potential in August across the West, Southern Plains, and the Southeast regions.
States Object to Energy Department Orders That Keep Old Coal Plants to Keep Operating
We reported in Newsletter No. 49 and several other times about orders from the U.S. Department of Energy (DOE) to keep coal plants operating beyond their scheduled retirement dates.
For example, a year ago, DOE Secretary Chris Wright issued an emergency order directing MISO, in coordination with Consumers Energy, to ensure that the 1,560 megawatt (MW) J.H. Campbell coal-fired power plant in West Olive, Mich., “remains available for operation, minimizing any potential capacity shortfall that could lead to unnecessary power outages.” Campbell, which went into operation into service in 1962, was scheduled to shut down on May 31, 2025.
Said Wright, “This administration will not sit back and allow dangerous energy subtraction policies threaten the resiliency of our grid and raise electricity prices on American families.”
While the orders were originally aimed at increasing reliability during the summer, when air conditioning boosts demand for electricity in heat waves, Wright credited the policy with preventing catastrophe when Winter Storm Fern struck a wide swath of the U.S. in late January.
“Beautiful, clean coal was the MVP of the huge cold snap we’re in right now,” said Wright in a DOE press release on Feb. 6.” I can say with some confidence, hundreds of American lives have been saved because of President Trump’s actions saving America’s coal industry.”
DOE stated that “more than 17 gigawatts of coal-powered electricity generation were saved ahead of Winter Storm Fern,” and of the five coal plants that were kept operating, three, including Campbell, were in the impacted storm region. “All three provided essential power during the storm.”
As we reported in Newsletter No. 58, however, in his written testimony at a hearing of the House Energy & Commerce Committee’s energy panel on March 17, Michael Goggin, executive vice president of the research firm Grid Strategies, stated that, “Coal units that have received Department of Energy (DOE) mandates to continue operating performed particularly poorly during Winter Storm Fern, as documented by DOE’s own data.” The three plants, including Campbell, achieved, on average, only about one-third of their nameplate output. Goggin added:
This poor performance is to be expected for coal plants that were slated for retirement because their equipment has reached the end of its useful life. In many cases their owners have also deferred maintenance and capital expenditures in anticipation of their retirement, further exacerbating their performance.
Still, even if they operated at just one-third of capacity, the coal plants provided power in an emergency. They aren’t a long-term solution to electricity constraints, but, says DOE, an emergency measure.
Wayne Winegarden, a senior fellow at Pacific Research Institute, which sponsors this newsletter, wrote in a RealClear Energy piece on April 7:
Coal played a central role in keeping the lights on. During the week of the storm, coal accounted for 21% of electricity generation in the Lower 48 states, up from 17% the previous week. In regions such as the Midwest and Mid-Atlantic, where natural gas infrastructure can face constraints and freezing risks during extreme cold, coal generation provided critical backup. Within the PJM Interconnection territory, wind and solar supplied about 5% of electricity during the storm, while coal provided roughly 24%.
Since last May, Wright has extended the order to keep the Campbell plant open five times, most recently on May 18. The next expiration date is Aug. 16. In justifying the latest extension, DOE stated that removing Campbell from service could lead to “the loss of power to homes and local businesses in the areas affected by curtailments or outages, presenting a risk to public health and safety.”
The extension came just three days after a U.S. Court of Appeals panel in Washington heard oral arguments in a challenge filed by the state of Michigan to overturn the DOE orders. The court will have to decide the winner of a classic battle pitting state and federal claims of authority.
“By arbitrarily declaring a false emergency, the Trump administration is forcing Michigan residents to foot the bill for an aging, expensive coal plant that was slated for responsible, cost-saving retirement,” Michigan Attorney General Dana Nessel said in a press release .
Consumers Energy said in its most recent earnings statement that the additional cost of keeping the J.H. Campbell plant open reached $180 million as of March.
Expenses are mounting for utilities in other states that have been required to keep their coal plants open. Claire Brown of the New York Times reported on May 14 that “TransAlta’s facility in Centralia, Wash., hasn’t burned a single lump of coal since an emergency order forced it to stay open in December. But it is seeking $20 million in reimbursements for three months of expenses, and the numbers will climb if it ever produces energy.”
The state of Washington – in an action similar to Michigan’s – sued earlier this year to reject DOE’s 2025 order to revive the Centralia coal plant. Brown wrote that TransAlta spent $4.6 million to acquire the coal to use under the order. But it may never be needed. So, she wrote, “What happens when the emergency order eventually expires?”
The plant could then “be left with a pile of coal it has no way to use. According to [an] affidavit, the plant has not found any buyers for leftover coal. The company is asking for $7 million to get rid of the coal pile and dispose of it in a landfill near the Oregon border.” The article also listed such costs as $4.5 million in salaries, $1 million for tools and $354,000 for insurance. And, again, these expenses don’t include actual operating costs because the plant remains on standby.
Costs at other plants, including those set for retirement that were ordered to stay open in Indiana, Colorado and Pennsylvania, are likely to be much higher. An opinion piece in the Indiana Capital Chronicle on May 22, following a legislative hearing, stated:
We found out at the hearing that it’s costing more than $1 million each day to keep two ancient, crumbling coal plants running even though the utilities were preparing to shut them down because the plants were not cost effective…. The White House ordered these zombie facilities back online, a move that one utility estimated could cost more than $100 million.
The Michigan case, said a Utility Dive report, “is the first among the legal challenges to DOE orders keeping fossil-fueled power plants from retiring to reach oral arguments. A court decision expected later this year could set a precedent for the other pending cases.”
Speaking for the states of Michigan, Illinois and Minnesota as well as several environmental groups, Michigan Assistant Attorney General Lucas Wollenzien told the appeals court panel that DOE’s “claim of authority here is unprecedented and unchecked, which transformed the structure of power for regulating resource planning as it has been commonly understood for decades.”
Wollenzien argued “that, under President Donald Trump, the Department of Energy has swept aside the procedures and safeguards of the 91-year-old Federal Power Act (FPA). That’s the law spelling out that utilities, states and regional planning authorities decide whether electricity resources are adequate, with input from the public.”
DOE, however, said that the Michigan order – as well as those involving the other plants — was authorized by Section 202(c) of the FPA and is in accordance with a national energy emergency that President Donald Trump announced on Jan. 20, 2025.
“The Secretary of Energy is not required to wait for a blackout to happen before invoking” the law’s emergency powers, said Robert Stander, deputy assistant attorney general for the Department of Justice. “Congress delegated sole discretion to the secretary to determine how much risk is too much risk, how much of a shortage is too short.”
The plaintiffs say that deciding whether a plant stays open is a state, not federal, prerogative. But the lines of authority between federal and state authority under the FPA have been blurry for decades, say legal experts, and have become even blurrier with the growth of distributed energy resources (DERs, such as battery storage) and of large loads.
California, Like Other States, Is Retreating From Policies That Raise Utility Bills in the Quest for Emissions Targets
The retreat continues from energy policies driven by state emissions goals. We have reported on how Rhode Island, Pennsylvania, New York, New Jersey and Connecticut have all made adjustments to goals in order to reduce the burden of higher costs on their residents.
Now, the biggest state is backpedaling as well. The California Air Resources Board (CARB) is holding a public hearing on May 28 on proposed amendments to the cap on greenhouse gas emissions and to the state’s “market-based compliance mechanisms regulation,” another term for the cap-and-trade, or cap-and-invest, rules that Northeast states are also modifying.
California’s system, writes Jeff St. John of Canary Media, “was put in place in 2006, becoming the country’s first economy-wide emissions-trading mechanism for refineries, factories, power plants, and other major industrial sites. Together, these sources account for about 80% of California’s greenhouse gas emissions.”
The aim was to reduce carbon emissions 40% below 1990 levels by 2030. But the program, reported the Associated Press on April 16, “costs Californians an extra 24 cents a gallon at the pump and slightly more on their utility bills.” At a time when voters are concerned about affordability, it’s a burden that has attracted the attention of elected officials and regulators.
CARB’s new plan is to “grant 118 million metric tons of extra emissions allowances to oil refineries and other industries, in exchange for a promise to invest in decarbonization projects in the future.” The result, wrote St. John, is that carbon dioxide levels “will blow past the state’s 2030 targets.”
The plan means that cap-and-trade revenues will fall by as much as $4 billion over the next four years, two University of California at Santa Barbara researchers have calculated. The bulk of these revenues ultimately come from California consumers and businesses themselves, and the funds the state collects go to various environmental programs. The state now says it won’t have enough to fully fund its earlier commitments to forestry and fire protection and to encouragements to adopt electric vehicles.
CARB realized earlier this year that, as St. John wrote, “the state’s previous accounting had undercounted how many million tons of emissions it needed to eliminate between 2007 and 2030 to hit California’s decarbonization targets.”
So CARB proposed in January to remove allowances for that 118-million-ton shortfall entirely. But industry objected, warning “that such a move would drive up consumer costs and push jobs and investment out of the state.”
California Republicans, along with some moderate Democrats and CARB officials, agreed. Hence, the new proposal, the Manufacturing Decarbonization Initiative, that is coming to a vote later this month.
Environmental activists and a group of state lawmakers are trying to get CARB to revise the revised plan “because this proposal undermines the integrity of the program so substantially,” says Chloe Ames, a policy adviser at NextGen California, one of 45 organizations that signed a letter to CARB Chair Lauren Sanchez and Gov. Gavin Newsom (D) calling for the plan to be abandoned.
It’s unlikely that CARB and Newsom, who has expressed concerns about high electric bills for the past two years, will back down. In our Newsletter No. 40, we quoted a Politico piece stating that Newsom’s ” decisions to postpone the closure of its last nuclear plant and to extend the life of some natural gas-fired facilities highlight what officials and experts say is the fact that the state with the most ambitious energy goals is far from achieving them.”
The story may sound complicated, but the gist is easy to understand. Like elected officials in other states, those in California recognize that their climate-change programs have been too aggressive and threaten to harm families and the economy at a time when “affordability” is the most important political issue, so they are making changes.
Responding to Troubles at PJM, the FERC Chair Says It May Simply Be ‘Too Big to Function’
There’s growing discontent over the nation’s largest grid operator, and now the chair of FERC, Laura Swett, a Republican appointee, is going public with concerns that PJM Interconnection has grown too large to function effectively in a time of surging demand and structural challenges.
At PJM’s annual meeting in Baltimore on May 12, Swett said in a speech:
We still expect PJM to run markets that are fair and efficient for everyone, to plan transmission across diverse jurisdictions, and to maintain reliability through extreme weather, shifting fuel mixes, and rapid technological change. If this can’t be landed given PJM’s huge and diverse footprint, perhaps it simply has grown too big to function.
But in an interview with Utility Dive on May 19, FERC Commissioner Judy Chang, a Democratic appointee, disagreed. “I am not thinking about [PJM] breaking up…. I’m interested in the successful continued operation of PJM, but definitely I want to help them get through this period and continue to meet the needs of the market.”
PJM was “what every market wanted to be” a few years ago, Chang said, but has been “really hurt” by challenges with supply chains, interconnection and a lack of transmission capability. She added:
When the market was working, people were not saying it’s too big to work, right? When people think prices are too high, then folks are uneasy and want change.… I think of it as, okay, if the market was not designed to meet this particular moment, then what does the market need to evolve into for the future?
PJM covers all or part of some of the most heavily populated and industrialized states in the country, including Ohio, Pennsylvania, New Jersey, North Carolina and Virginia, which is the largest site of data centers in the world. The grid operator serves 67 million Americans.
“PJM’s story began in 1927 when three utilities came together to form what would become the world’s first power pool,” said Swett. It was a new concept guided by the principle that “collective problem solving can produce benefits greater than any one of them could achieve alone.”
Today, however, “we face historically unprecedented demand—with potentially historically unprecedented catastrophic failure. PJM is the tip of the spear—the laboratory of national and economic security on which our country may rise or fall,” Swett said.
In a pointed allusion to PJM’s long line of projects waiting to get on the grid, she continued “We need NEW—not already planned or queued—generation and we need it NOW. There’s no excuse for failure—companies are ready and willing to pay for more than their fair share of getting the power they require…. This is not a time for weak leadership or to be crippled by fear. This is a time for difficult, history-making decisions.”
Swett announced that FERC will be convening a conference on July 23 “focused on identifying flaws and solutions related to PJM’s stakeholder process and governance.” She added, “Under my leadership, FERC will not shy away from taking action if necessary.”
In January, the White House National Energy Dominance Council and the 13 governors whose states the grid operator covers, plus the Mayor of Washington, DC, issued an unprecedented joint statement calling for PJM to provide “15-year certainty for new capacity resources” by holding a “Reliability Backstop Auction” no later than September.
The statement also asked PJM to ensure long-term viability and reduce costs – not necessarily an easy mandate in the face of rising demand and plant retirements.
PJM is grappling with the same problem that vexes other energy stakeholders. As the Pennsylvania Capital-Star put it on May 6:
The growing demand from data centers and broader electrification of the economy is exacerbated by tightening supply as older, dirtier power plants retire and supply chain and permitting issues make new plants harder to build fast enough.
Still, PJM has become a target, and the news is not good on costs that have to be borne by ratepayers. On May 15, E&E News reported that “power prices in the nation’s largest grid market” – that is, PJM – “jumped almost 76 percent in the first quarter year-over-year.”
Monitoring Analytics, the independent monitor for PJM, said that the findings highlight the inflationary pressures facing residents of multiple battleground states heading into midterm elections, wrote E&E’s Christa Marshall.
“The price impacts on customers have been very large and are not reversible,” the market monitor said. “The price impacts will be even larger in the near term unless the issues associated with data center load are addressed in a timely manner.”
PJM spokesperson Jeff Shields responded that the rising prices outlined in the report “are an accurate indication of the tightening supply and demand condition in the wholesale markets and the markets are functioning correctly by appropriately reflecting these conditions.”
In its report, Monitoring Analytics called for requiring data centers in PJM to bring their own generation. That idea echoes the “ratepayer protection pledge” backed by the White House and large technology companies earlier this year. “The preferred solution would include creating a queue for the addition of large new data center loads, which would not be interconnected until there is adequate capacity to serve them,” the report said.
PJM has been responding. In a letter to stakeholders on May 19, the grid operator said it will move up a planned backstop reliability auction to address demand from data centers to September 2026, in accordance with the January statement by the White House and governors. The auction had previously been set for March 2027.
The stakeholder letter followed a May 5 letter from PJM’s CEO, David Mills, to the 13 governors and DC Mayor Muriel Bowser, reminding them “that when PJM runs this backstop procurement, if states have not established frameworks to appropriately allocate costs to new data center loads, it is unclear to which customers those costs would be assigned. Absent appropriate safeguards, it appears possible to PJM that these costs will be allocated to other consumers in your state based upon your existing state’s framework.”
In other words, PJM made it clear that the states have responsibility – through their own public utility commissions — for deciding how to apportion retail costs around data center loads, and if the states don’t act, they can’t blame PJM.
Then on May 20, Reuters reported that “power plants on the largest U.S. electric grid [that is, PJM] received a record payout of nearly $1 billion to cover their losses in the first quarter, when fuel costs surged during a winter cold snap.” Tim McLaughlin of Reuters wrote:
Those huge payments will ultimately be shouldered by ratepayers through their power bills and reflect growing instability on an aging system already struggling to keep up with rising demand from data centers feeding the AI boom.
McLaughlin added, “While the record payouts were linked to an unusual deep freeze, analysts anticipate more big outlays in the future, too. That’s because the buffer against blackouts for PJM, which manages the supply of electricity…is nearly 40% below the target set by the regional grid system.”
The reporter quoted David Lapp, the head of Maryland’s Office ofPeople’s Counsel, a state agency that advocates for residential utility consumers, as saying, “The payments to these old, uneconomic power plants is really a telltale signal of the problems on the PJM system. And it’s a lot of money going to what is not ultimately a long-term solution.”
The week before Swett’s speech, PJM issued a report on capacity market design and investment incentives – “in recognition that the conditions that made the market work for nearly two decades have changed, and that the stress now visible in prices, reserve margins and investment pipelines reflects something more fundamental than a design that needs recalibration.”
The report states that PJM is trying to manage “a transition from an era of managing surplus to an era of managing scarcity — one that is anticipated to persist for some time based on current projections.”
But instead of prescribing one plan, the report offered three distinct “paths forward,” based on answers to three structural questions:
- Should we preserve the concept of resource adequacy as a common good that is shared by all, also known as the “shared reliability compact” – and if so, who is responsible for making it financially durable?…
- Should we decide that reliability, in a period of scarcity, must be explicitly rationed?…
- In either case, should the primary long-term hedging instrument be the capacity product, or do we make a deliberate shift of revenues supporting resource adequacy to the energy market with long-term contracting of the energy product?
PJM’s critics, who include governors of states in its operating region such as Democrats Josh Shapiro of Pennsylvania (who threatened to pull out of PJM) and Wes Moore of Maryland, say it just isn’t moving fast enough and is causing constituents’ rates to rise too sharply.
On May 7, Maryland filed a complaint at FERC, charging that PJM’s “rules for assigning regional transmission costs driven by data centers violate the Federal Power Act and will unfairly inflate Marylanders’ electric bills.” The complaint states:
Of $22 billion in transmission project costs advanced over the last three years through PJM’s competitive regional transmission procurement windows, PJM’s rules for allocating these costs have unlawfully assigned Maryland customers responsibility for $2 billion in capital expenditures — costs that will be recovered in rates for decades and that will drive up Maryland customer bills by $1.6 billion over the next ten years alone.
Maryland challenged PJM’s hybrid transmission cost allocation methodology, which makes states pay for capital investment in part based on the proportion of demand the project has within the entire system.
PJM reacted forcefully, and at the PJM meeting on May 12, Moore “pushed back on PJM’s assertion that state policies have undermined its markets, instead arguing the RTO [regional transmission organization] has created a credibility gap by not working with elected representatives and regulators.”
LaCerte Confirmed as FERC Commissioner Through 2031
The Senate on May 18 confirmed David LaCerte for a second term as a FERC Commissioner. In a press release, FERC stated:
During his initial term, Commissioner LaCerte’s focus has been on advancing and modernizing long overdue energy infrastructure projects, strengthening grid reliability, and keeping energy affordable for American households and industry. He has been actively engaged in modernizing the Commission’s permitting processes, supporting reforms to reduce regulatory delays and providing certainty to accelerate the projects needed to meet rising energy demand.
LaCerte, a Republican from Louisiana, was originally sworn in on Oct. 27, 2025, to serve the remainder of a term expiring next month. His new term ends on June 30, 2031. He is an attorney with extensive Clean Air Act litigation experience. He previously served as a senior advisor at the Office of Personnel Management and as acting director of the U.S. Chemical Safety Board.
LaCerte was widely praised on the extended appointment. The Edison Electric Institute, which represents large utilities, said, “We look forward to continuing our work with Commissioner LaCerte and the full Commission to strengthen the nation’s energy grid and support the infrastructure needed to power our economy and communities.”
Todd Snitchler, CEO of the Electric Power Supply Association (EPSA), which represents competitive power providers, said he looks forward to working with LaCerte and the entire commission. Snitchler said in a press release:
Getting power to all customers quickly and cost-effectively means taking practical action and setting clear, legally durable rules so that competitive power markets can continue their long track record of success. That’s how we keep the grid strong and protect consumers.
Snitchler added that, with the right framework, competitive power suppliers “will continue to deliver reliable, affordable power that supports jobs, economic growth, and U.S. leadership in AI—without driving unnecessary costs onto households.”
The American Clean Power Association congratulated LaCerte and said “his leadership and thoughtful engagement on critical energy issues will continue to be important as the nation’s energy landscape evolves.