The European Network of Transmission System Operators’ (ENTSO-E) final report on the Iberian Peninsula blackout of April 2025 lays out the root causes and chain of events that led to the collapse of the grid, providing critiques of the numerous points of failure.
Much of 472-page document, released March 20, consists of the organization’s factual report, released in October 2025, but it also includes a detailed root-cause analysis and recommendations for preventing future outages, as well as additional data that were not previously available. (See European Regulator Issues ‘Factual Report’ on Iberian Outages.)
The report’s findings largely align with those of the Spanish government and grid operator, which concluded the blackout occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from frequency oscillations, exacerbated by a faulty power plant controller.
ENTSO-E stresses throughout the report that no single factor led to the collapse and that any one of the factors by itself would not have been a problem. Instead, it created a large root-cause tree displaying the multiple factors that led to a very fast voltage increase (page 332).
The roots of the tree include:
no explicit criteria concerning dynamic behavior for conventional generators’ reactive power;
no economic consequences for generators if their voltage-control requirements were not met;
renewable resources operate in fixed power factor mode; and
the design of voltage control of local generation networks not aligned with system needs.
The report separates its recommendations based on whether they are related to the root causes and gives each a priority label. ENTSO-E said generators should operate in voltage-control mode whenever possible and that transmission system operators (TSOs) should ensure there are enough voltage-control and monitoring equipment on the grid.
It also said TSOs need to enforce Europe’s harmonized voltage operating range: Spain allows its grid to operate up to 435 kV, while the rest of the continent allows up to 420 kV.
Finally, ENTSO-E said a common procedure should be established to create a snapshot after a significant event, allowing for accurate simulations of the system under similar conditions to those of the event. It noted that it had to rely on incomplete data, particularly from Spanish TSOs.
“This blackout highlights how developments at the local level can have systemwide implications and underlines the importance of maintaining strong links between local and European system behavior and coordination, while ensuring that market mechanisms, regulatory frameworks and energy policies remain aligned with the physical limits of the system,” ENTSO-E said.
HOUSTON — FERC Chair Laura Swett treaded carefully when discussing the commission’s Advance Notice of Proposed Rulemaking to accelerate the massive wave of large loads that virtually everyone in the industry agrees is coming, whether the grid is ready or not.
The commission faces an April 30 deadline to release the rules. Given that the docket is still open, Swett is simply trying to avoid ex parte rule violations.
Speaking at CERAWeek 2026 by S&P Global on March 26, Swett was asked by conference chair Daniel Yergin about the commission’s role in matching supply with, in Swett’s own words, the “exponential, explosive demand.”
“We have to ensure that there are clear and efficient rules for large loads and generation to get online as quickly as possible, and I’m being a little bit careful here,” she said, “because we have a live docket from the secretary of energy that gets to this matter.”
When she was again asked to comment on the ANOPR during a press briefing after her onstage appearance, Swett said, “The question you asked me is squarely within that docket, so I won’t speak to any specifics.”
Speaking generally, she said that federal jurisdiction is very clear.
Federal and state jurisdiction “has been that way for hundreds of years, and as a regulator, I take those lines very seriously,” Swett said. “That is part of the way that the commission is thinking, but we still have quite a bit of time before we have to opine on that docket.”
Speaking elsewhere during the conference, Commissioner Judy Chang echoed Swett by saying she has “convictions” that FERC has “some amount of jurisdiction” over large loads interconnecting to the grid.
Wright’s directive included a proposed rulemaking designed to ensure the timely and orderly interconnection of large loads, and laid out four legal justifications:
Large load interconnections are a critical component of open-access transmission service that requires minimum terms and conditions to ensure non-discriminatory service.
Interconnecting large loads is a practice that directly affects FERC-jurisdictional rates, and the Federal Power Act has vested the agency with exclusive authority to ensure wholesale rates are just and reasonable.
The ANOPR will not impinge on state authority over retail sales. FERC will not exert jurisdiction over any retail sales to large loads, and the states retain authority over expansion or siting of generation facilities.
Any contrary view of the proposed changes conflicts with the FPA’s core purpose of granting FERC exclusive jurisdiction over transmission in interstate commerce and interconnecting large loads to the grid to obtain service benefits.
Wright recommended the ANOPR apply to loads 20 MW or greater and that it include standardized financial and readiness requirements. Loads that agreed to be curtailed during tight grid conditions would be expedited and also responsible for 100% of network upgrade costs.
FERC may be building on several interconnection proposals that the country’s grid operators have made. MISO and SPP have instituted expedited studies to interconnect “shovel-ready” projects that received commission approval in 2025. SPP also received approval for 90-day study processes that review interconnection requests from “high-impact” large loads seeking to interconnect to its system. (See MISO, SPP Collaborate on Their ERAS Proposals and FERC Approves SPP Large Load Interconnection Process.)
“There are several markets across the country that have come to FERC with proposals,” Swett said. “Under our authorizing statutes, we are in a receptive posture, but we also have tools to be a little bit more aggressive in directing markets to do something.”
She said the country’s electric markets have “very different” characteristics and differing transmission systems. Market members and state policies also have different “progressions” for solving the problem, Swett said.
“As we have received proposals across the country, we look at them and try to accept them or refine them as quickly as we can to get the markets the feedback and the approvals that they need to then solve the problem themselves,” she said.
Peter Lake, senior director of power for the White House’s National Energy Dominance Council, said FERC has done a “tremendous job” on the rulemaking and that if implemented, it would change the interconnection and energizing timeline to 60 days.
“I really hope that they get where we hope they’re going, but to give you a sense of context, a lot of these hyperscalers who are writing $100 million checks are frustrated with a five-, six-, seven-year timeline,” he said. “It would be an extraordinary game changer in both accelerating interconnected data centers and accelerating this country’s ability to compute.
“It should be an extraordinary change, an extraordinary paradigm shift, in how this country develops and how this country competes in the global AI arms race and how our generation fleet operates,” Lake added.
“That is remarkable,” said moderator Douglas Giuffre, with S&P Global. “Sixty days. It would be amazing.”
It may also be unlikely. The industry requires stability models and assessments when interconnecting and energizing loads. To maintain reliability in interconnecting the loads, stability — the critical-path item — is a priority.
“There’s a lot of details,” Lake said, “and FERC is doing a great job of working through that, as they should.”
A delay in the repair of Unit 3 of Xcel Energy’s coal-fired Comanche Generating Station has sparked questions among Colorado regulators about the utility’s ability to meet summer peak demand in 2026.
Public Service Company of Colorado, an Xcel subsidiary, told the Colorado Public Utilities Commission in a March 2 filing that Comanche Unit 3 would return to service “around August 2026.” In previous filings, PSCo listed the unit’s expected return-to-service date as June 15, 2026.
The Unit 3 outage began Aug. 12, 2025, prompting a petition from PSCo and Gov. Jared Polis’ administration to postpone the retirement of Comanche Unit 2 to help make up for the outage. The PUC granted the petition in December, delaying Unit 2’s retirement one year to the end of 2026. (See Colorado PUC Approves Extension for Comanche Coal Plant.)
A PSCo forecast that assumed Unit 3 would be back online in June showed a summer peak capacity need of 7,534 MW and a total accredited capacity of 7,457 MW, for a 77-MW deficit. But without a return to service of Unit 3, which has an accredited capacity of 415 MW to the PSCo system, the shortfall potentially grows to 492 MW.
The delayed return of Unit 3, coupled with an early spring heat wave throughout the West, elicited concern from commissioners during a March 25 PUC meeting.
“We have a real problem with Comanche 3,” Commissioner Tom Plant said. “I’m not convinced they’re going to be able to meet summer peak, particularly when we’ve got 85-degree temperatures in March.”
As part of its approval of the Unit 2 extension in December, the commission directed PSCo to file by March 1 a status report on Comanche 3 and the company’s plans to address resource needs. A second report is due by June 1.
But during their March 25 meeting, commissioners said summer 2026 resource needs should be addressed quickly. They asked the company to file a report by April 15.
Commission Chair Eric Blank wants the company to run a test of its demand response programs in April or May to see how much demand is reduced. Commissioners said they’re prepared to fast-track increased incentives for demand response programs to increase participation this summer.
Commissioners asked PSCo to work with its wholesale customers on demand response. Another idea was to focus on customer-side energy storage programs, which could help during peak demand and public safety power shutoffs.
The delay in Comanche Unit 3 repairs was one of “two very bad pieces of news” from PSCo’s March 2 filing, Blank said. The second disappointment is that the utility is now “wavering on its longstanding commitment” to coal plant retirements, he said.
“Near-term, the most likely capacity solutions are continued extensions of existing units — namely, Comanche Unit 2 and, to a lesser extent, the Hayden units,” PSCo said in the filing.
Hayden Station, whose two units have a combined capacity of 446 MW, is scheduled to retire by 2028.
The company acknowledged that additional investments — and potentially regulatory changes — would be needed to keep the coal-fired units running beyond their retirement dates. Coal extensions also “may create challenges with continuing the pace of the company’s clean energy transition,” PSCo said. Xcel plans to exit from coal by 2030.
In addition to a summer peak capacity shortfall in 2026, PSCo forecasts show a 445-MW shortfall in summer 2027. In 2028 to 2030, a summer peak capacity surplus is predicted.
Capacity shortfalls are also forecast for winter peaks: 96 MW in 2027 and 424 MW in 2028, both assuming Comanche 3 is back in service.
PSCo said it has been looking at other ways to plug its capacity shortfalls. Market purchases will help improve the capacity position in 2026. But the availability of short-term market purchases “is increasingly constrained,” the company said, “due to high demand across the West, limited transmission availability and the impending implementation of SPP’s Western expansion.”
Other potential strategies for increased capacity are extending power purchase agreements, implementing demand response programs and acquiring more resources through a commission-approved near-term procurement process. (See Colo. PUC Approves 3.2-GW PSCo Resource Package.)
Comanche 3 Repairs
Comanche Unit 3 is undergoing both offsite and onsite repairs, PSCo said in its filing. Mitsubishi is conducting the offsite work but has been hindered by supply chain delays, the filing said. General Electric is performing onsite work and will restore the unit to service.
Preliminary results of a root cause analysis point to fabrication and design issues with Unit 3, the filing said, noting that Public Service ran the unit “within the relevant thermal parameters.”
The public version of the filing redacts the name of the Unit 3 component that was shipped out for repair, as well as the cost of repairs.
Comanche Unit 3 has been plagued with outages since it first went online in 2010. PUC commissioners have questioned whether it makes sense to keep fixing it.
But for now, PSCo said, “there are no reasonable alternatives to returning Comanche Unit 3 to service.”
“The timelines to develop and in-service new fixed generation are, at best, in 2029 and will cost billions of dollars to address the 415 MW accredited capacity of Comanche Unit 3,” the company said.
Data center load growth in California could turn out to be “lumpy,” with sudden, large increases in specific regions of the state, rather than smooth growth over time.
Standard forecasting models assume smooth and diversified load growth, such as a 1.5% increase per year, GridLab Senior Program Manager Casey Baker said in a letter to the stakeholder working group managing CAISO’s large loads initiative. But data center load growth often jumps 50 to 100 MW almost instantly in specific locations, he said.
California’s data center demand is expected to increase by 1.8 GW by 2030 and 4.9 GW by 2040, but utility interconnection queues in the Silicon Valley area suggest the 4.9-GW demand could occur by 2030, Baker added.
To address sudden demand growth, CAISO should complete a high load-growth sensitivity case as part of its 2026/27 transmission planning process (TPP), he said. This study would show the risks of underbuilding the CAISO system compared to the risks and costs of overbuilding and would be particularly critical for the South Bay Area and other load pockets where growth is concentrated.
Major transmission infrastructure requires eight to 10 years to plan, permit and construct, but modern data centers can be energized in two or three years. If CAISO’s TPP relies on the base case forecast but a high load-growth future occurs, the grid faces a physical deficit in the early 2030s that “cannot be remedied in time,” Baker said.
“The transmission owners simply will not be able to build wires fast enough to catch up to the demand,” he said.
A high load sensitivity case would include specific hot zones where loads develop at a higher rate than is currently forecast, Baker said.
“This is the only way to reveal where voltage instability and thermal overloads might occur that the base case forecast averages away,” Baker said.
GridLab cited a Silicon Valley Power (SVP) study that showed SVP’s capital construction plan far exceeds the state’s base assumptions. Load in Santa Clara will double from about 720 MW to about 1,300 MW by 2035, with most of it happening in the next five years.
It is important for CAISO to clarify how it will review large load interconnection requests, particularly when significant network upgrades are identified as needed, SVP representatives said in comments to CAISO on the initiative. These network upgrades could occur in utility-led load interconnection studies that are not fully reflected in the CAISO’s annual TPP, the representatives said.
SVP found that several 230- and 115-kV facilities could become overloaded based on proposed large load additions in SVP’s region, according to the letter.
CAISO does not presently have a threshold for what constitutes a large load, Danielle Mills, CAISO infrastructure policy development principal, said during a February CAISO workshop. (See CAISO Examines ‘Pulsating’ Data Center Loads.) The ISO is taking comments on this threshold and may develop a definition over the next several months.
Utilities are responsible for large load interconnections, but CAISO is monitoring developments at the federal level regarding whether RTOs and ISOs can or should be more heavily involved in the process, the ISO said in a Jan. 30 Large Load Considerations issue paper.
Large loads include more than data centers: Loads from EV charging stations and electric agricultural and industrial equipment, which also fall into the category, are expected to increase significantly over the coming years too.
SPP Model Should be Considered, Some Stakeholders Say
NextEra Energy representatives said CAISO should model SPP’s recent proposal for large loads that was approved by FERC. SPP’s proposal includes a 90-day study process for interconnecting large loads that will be paired with new local generation.
SPP’s model is “just and reasonable and not unduly discriminatory” and allows large load customers “to interconnect to the transmission system in a timely manner and increase the speed of interconnection queue processing,” NextEra said. CAISO could develop a similar model to meet the California Energy Commission’s large load forecast in a timely manner, it said.
CAISO could also develop a new way to study large load proposals in its interconnection queue, specifically those that include co-located generation, NextEra said.
Currently, large loads with co-located generators or energy storage facilities are part of two interconnection processes — the transmission owner’s load interconnection process and CAISO’s generator interconnection process. A more closely coordinated process is needed to ensure that large loads are quickly interconnected while recognizing the effects at the point of interconnection, NextEra said.
ALBANY, N.Y. — Generation industry representatives and their allies united behind a call to loosen New York’s climate law to allow the repowering of old fossil fuel plants with new natural gas turbines at the Independent Power Producers of New York’s 40th annual Spring Conference on March 24.
“I personally love Gov. [Kathy] Hochul’s all-of-the-above energy strategy,” Richard Barlette, IPPNY chair and director of state government affairs for Constellation Energy, said during his opening remarks. Intermittent resources need “firm” support as they continue to grow. “We must remain laser-focused on reliability while continuing to scale clean technologies. Wind, solar, nuclear, storage, natural gas and hydrogen must all be a part of the conversation.”
NYISO CEO Rich Dewey reinforced these points in his keynote address. While he didn’t express specific policy positions, he painted an all-too-familiar picture of New York’s aged generation fleet, thinning margins and the intense balancing act the ISO had to run during June 2025’s heat wave and the late January winter storm. Keeping the grid going in the winter, Dewey said, was harder than in a summer heat wave primarily because of fuel constraints and reliance on older units. (See NYISO Details Late June Heat Wave for Reliability Council and NYISO Provides System Data During Winter Storm Fern.)
“[What] keeps me up most at night [is] the aging generation fleet. Twenty-five percent of capacity is more than 50 years old,” Dewey said. “But on hot days, on cold days, we can’t maintain a reliable system without these resources and increasingly depend on their participation more and more.”
NYISO planning studies have typically assumed that these generators would be online for the foreseeable future, but this is becoming “less and less responsible” when examining the grid, he said.
Since the enactment of the New York Climate Leadership and Community Protection Act, “we’ve deactivated 4,200 MW of primarily dispatchable resources,” Dewey said. Of the 2,274 MW interconnected since then, “almost all of that is renewable intermittent resources. When you think about that, that’s a significant margin.”
Large loads come online much faster than generation as well, he said. A data center has an average build time of about 18 months; generation of all types takes years to get on the grid under the best circumstances.
Ruben Diaz Jr., Natural Allies | IPPNY / Tim Raab
“There is a recognition through the State Energy Plan that we are going to need to have progress made on some of these repowering proposals,” Dewey said in response to an audience question about lowering energy prices. “Those repowering proposals will yield a generation source that is more efficient, cleaner and more cost-effective in the long run.”
In another keynote address that ended the conference, former Bronx Borough President Ruben Diaz Jr. spoke on behalf of Natural Allies, an industry group trying to make the case for natural gas generation as compatible with environmental justice.
“Energy policy is not theoretical. It shows up on the kitchen table. It shows up in utility bills. It shows up in the cost of groceries. It shows up in the cost of rent,” Diaz said. He said his past environmental justice positions were not at odds with wanting to upgrade old fossil plants. “New York is among the highest electric bills in America, and that is … experienced by working families every single month. When energy policies undermine reliability, it is not the wealthy who feel the pinch.”
Diaz said environmental justice means reducing emissions and that the current law makes it impossible to replace old, dirty plants with cleaner ones. This has knock-on effects, forcing more emissions in poor neighborhoods as reliability margins thin.
‘How to Keep the Damn Lights on’
After Dewey’s keynote, a panel convened to discuss “How to Keep the Damn Lights on.” The panel was moderated by longtime industry analyst John Reese of Morningsidenergy and included Matt Schwall of Alpha Generation; Pallas LeeVanSchaick of Potomac Economics, the NYISO Market Monitoring Unit; Derek Hagaman of Gabel Associates; and Bryan Sixberry of GE Vernova.
Reese opened with a breakdown of federal Energy Information Administration data showing that 50% of generation in New York City was over 50 years old. Roughly 6% of units in the city were 70 years old, around six times the national average of 1.3%. He said that the mechanical wear on a fossil fuel unit made living to 80 almost impossible. The oldest units will either be offline in the next few years because they cannot be maintained affordably or because they “decide not to wake up one day.”
From left: Pallas LeeVanSchaick, Potomac Economics; Bryan Sixberry, GE Vernova; Matt Schwall, AlphaGen; Derek Hagaman, Gabel Associates; and moderator John Reese, Morningsidenergy | IPPNY / Tim Raab
“The data is scary, and we need to do something,” Reese said.
Hagaman said running the old peaker plants was “not the most affordable option”. He said it was hard to sell the idea for repowering because any investment on the system is going to cost money.
“Frankly it’s a matter of making it more affordable than the alternative,” Hagaman said. He pointed to Arizona and Colorado as states that were embracing repowering as elements of an all-of-the-above strategy.
Schwall said replacing old, inefficient natural gas plants with new units that could also burn alternative fuels was compatible with an environmental justice message. He pointed to his childhood growing up on Staten Island, where it took over 25 years for the Fresh Kills Landfill to be remediated.
Matt Schwall, AlphaGen | IPPNY / Tim Raab
“Environmental progress does not happen overnight. … Environmental progress is not always perfect,” he said. Using natural gas generators is not a perfect solution in the context of our environmental goals, but in the near and medium term, especially in New York City it is a necessary solution for the environment and for reliability.”
Sixberry said the main stopping blocks for getting a generator on the grid were transformer and breaker backlogs. Repowering projects could take advantage of transformers and breakers that are already in place, effectively swapping out an old generator for another.
In response to a question about local communities not wanting repowering projects because of emissions, Schwall said that while repowering is “not a perfect solution,” it is very difficult to get enough renewables on the grid to maintain reliability.
“Installing technology that is cleaner, that is capable of running on zero-emissions fuel … it’s not a zero-sum game,” he said. “It does not mean that the state should not be pursuing solar energy or storage.”
Fighting the Headwinds
In another panel, renewable energy advocates discussed how local government could help in the face of unprecedented federal interference in state climate policy.
Most of the panelists said New York needed to reduce permitting time and expedite construction. Longer lag times for permits create uncertainty for project financing, which can lead to canceled projects.
“The biggest issue we’ve been facing prior to this administration, and writ large, has been that it takes too long to develop. It takes way too long to do anything, not just renewable energy,” said Alicia Gené Artessa, director of the New York Offshore Wind Alliance. “When you have a set contract price and it takes 10 years to build a project, the price doesn’t match up anymore.”
Jeffrey Escobar, a partner at Sheppard Mullin, concurred, saying that he has had clients drop out of the development cycle in New York after buying up build sites because it was too difficult to build.
Other panelists said the state needs to make contracts with renewable energy developers more flexible so they could withstand supply issues or federal policy shocks while also making development smoother.
Ryan Stanton, executive director of the Long Island Federation of Labor, said more effort has to be put into communicating with local communities and local stakeholders when developing renewables. He cited Citizens United as a major contributor to enflaming local discourse.
“They have a ton of money to back doing nothing,” Stanton said. “It’s a lot harder to communicate effectively, to have an honest conversation about making policy decisions for the long term.”
He pointed to the success of renewable development in the Republican-controlled town of Brookhaven, on Long Island. He said the town is on track to link 900 MW of offshore wind to the town because the labor movement, local government and community leaders had coordinated and communicated effectively.
Artessa agreed, saying communication is the “backbone” of their industries. She said she hoped the state would work with local governments to make it clear to developers where they were welcome, and to coordinate planning across municipalities.
NEW ORLEANS — FERC Commissioner David LaCerte encouraged MISO players to bring their boldest ideas forward that could help return the electric industry to a more humdrum reliability baseline.
LaCerte addressed MISO’s March 25 Advisory Committee meeting ahead of a possible second Senate confirmation, this time for a full, five-year term. (See LaCerte: FERC Focused on Winning AI Race.)
He commended MISO on its initiatives to stand up more infrastructure in record time, including its interregional planning with SPP on the $1.65 billion Joint Targeted Interconnection Queue transmission portfolio.
“Interregional cooperation is not easy,” said LaCerte, adding that single-minded goals must be set aside to improve the larger grid. “The infrastructure will serve real customers, so I applaud you for that.”
LaCerte also called MISO’s temporary, fast-tracked interconnection queue lane a “focused, practical” tool to bring generation online faster.
He said if reconfirmed by the Senate, he would focus on making sure that “every action we’re taking is in furtherance of reliability and affordability.” He said both must be lifted equally and that he doesn’t prioritize one over the other.
LaCerte said he doesn’t like that the nation’s risk maps look like “McDonald’s drive-through menus” with all the vibrant, warm colors.
He repeatedly encouraged MISO, stakeholders and states to “be bold” and bring their best ideas forward to tackle grid expansion reliably. “The best ideas come from the states … not necessarily the bureaucrats in D.C.,” he said.
He said his goal is to help the industry “get back to more boring, more business as usual” so residential ratepayers are neither worried they’ll flip a light switch in vain nor nervous about how they’ll cover energy bills.
However, LaCerte told attendees that “large loads cannot be wished away.” He said “living in an era where we’re all uncomfortable” will be the standard for a while and the country must strive to be a premier environment for AI growth. “Second place is not the place you want to be in in this landscape,” he said.
He also said MISO made “smart, disciplined decisions under pressure” during the late January 2026 winter storm and that MISO deserves more recognition for steering operations during the cold snap. (See MISO: Gen Performance Lacking During January Winter Storm.)
He noted that many gas generators performed well below their capacity accreditation during the emergency.
“That’s not a coincidence; that is a pattern,” LaCerte said. He said he plans to focus on coordination of pipeline availability and electricity demand should he return to FERC for a full term.
During a later talk on what impediments the MISO footprint could soon face, multiple MISO members said gas-electric coordination will become more consequential as gas generation becomes more of a load-bearing column of the grid.
Michelle Bloodworth, of coal lobby America’s Power, said MISO should be aware of the risk of inadequate fuel supply as MISO heads toward a fuel mix shared by natural gas, wind and solar generation. She said with natural gas as the backstop, firm pipeline transportation and storage for just-in-time service becomes more essential.
Bloodworth said members are going to have to “evaluate a price tag” that comes with replacing coal with natural gas, as onsite coal piles don’t experience the dramatic price spikes that natural gas supply does during high demand.
Pelican Power’s Tia Elliott said gas generators “need firm contracts,” but added that’s a matter the states oversee.
Meanwhile, the Union of Concerned Scientists’ Sam Gomberg chimed in that MISO should formally name climate change as an operational risk.
“I think we need to be more proactive about responding to those trends,” Gomberg said. He said simultaneous intense heat waves and droughts will test the grid by driving up demand while drying up cooling water for generation.
Gomberg asked MISO to prepare a “full assessment” of what operating conditions might look like a decade down the road with a warmer planet featuring more volatile weather.
The spring quarterly meeting of the ISO-NE Consumer Liaison Group revolved around the growing risks of extreme climate-driven weather events in Vermont and New England.
As extreme weather events increase, speakers at the meeting said hardening the grid, investing in efficiency and adding distributed resources will become increasingly important.
The state experienced dramatic flooding in the summers of 2023 and 2024 that caused widespread damage, along with more limited flooding in 2025. Catastrophic flooding is not a new phenomenon in the state — a massive flood in 1927 killed 84 people, including the lieutenant governor, and flooding during Tropical Storm Irene in 2011 killed seven people and caused nearly $750 million in damage.
But scientists warn that man-made climate change is increasing the likelihood of extreme precipitation in the Northeast.
At the CLG meeting on March 25 in Randolph, Vt., residents and activists stressed the importance of planning to protect infrastructure from future extreme weather events and decarbonization to avoid exacerbating those events.
“Climate change disasters are coming for us in New England,” said Shawna Trader, a community organizer who was heavily involved in the response to the 2023 flood. “This is not the time to rest. … This is the time to innovate.”
Discussions about climate change no longer center around hypothetical effects on future generations, said Ben Edgerly Walsh, climate and energy program director at the Vermont Public Interest Research Group.
For Vermonters, “the climate crisis is something that they have shoveled out of their neighbor’s or their church’s basement. It’s something that’s washed away their home,” he said.
Following the 2023 flood, Efficiency Vermont was able to access leftover federal funds from the American Rescue Plan Act to pair home rebuilds with home weatherization and efficiency upgrades for low-income residents.
Dave Westman of VEIC, administrator of the Efficiency Vermont program, said home rebuilds pair well with weatherization. But continuing this approach over the long term will require lawmakers and state officials to find a new source of funding, he said.
“We know that Vermont isn’t going to be immune from future climate risks,” he said.
Edgerly Walsh highlighted a 2024 state law requiring major fossil fuel companies to compensate the state for greenhouse gas emissions to help fund climate resilience and recovery efforts.
“Vermonters deserve to have a chance to not foot the whole bill — they can’t afford to,” he said.
“As a result of these investments, we could see really significant benefits to the electric grid,” he added, noting that money collected from fossil fuel companies could help harden the grid, develop microgrids and lower storm charges on electric bills.
But the law has an uncertain future. It faces legal challenges from the Trump administration, the U.S. Chamber of Commerce and the American Petroleum Institute, which argue the state’s attempt to penalize global companies for emissions dating back to 1995 violates the U.S. Constitution.
New York has passed a similar “climate superfund” act, which the Trump administration has challenged. The outcomes of these legal battles could have major implications for climate resilience and recovery in Vermont and throughout the country.
PacifiCorp is preparing to bring online enough long-term clean energy resources to help the utility meet Washington’s strict 2030 greenhouse gas targets.
Specifically, PacifiCorp has selected a shortlist of resources from a Washington-specific request for proposals for supply-side resources with an expected commercial online date before the end of 2029. The company issued the RFP to comply with Washington’s Clean Energy Transformation Act (CETA), Rohini Ghosh, PacifiCorp’s director of clean energy planning, told the Washington Utilities and Transportation Commission (UTC) on March 24.
CETA requires all electric utilities in the state to become greenhouse gas-neutral by 2030 (allowing for use of offsets and other programs) on the way to generating all power from emissions-free resources by 2045. It also prohibits utilities from serving their Washington customers with any coal-fired generation after 2025. (See Washington Agencies Adopt New Rules to Implement CETA.)
PacifiCorp’s shortlist includes 853 MW of solar resources and 200 MW of batteries. The utility has begun executing the contracts, Ghosh said. She added that the new resources alone are enough to meet 80% of PacifiCorp’s CETA targets.
The resources fall under power purchase agreements, Ghosh noted. Although potential federal tax credits would not flow directly to the company, “it should be reflected in the prices we have received,” she said.
“Another specific action the company will take is to continue to evaluate potential cost-effective short-term products to make additional progress towards the clean energy targets,” Ghosh said. “While we have identified a healthy number of resources from this RFP, I will note that they largely come online in 2028 and by the end of 2029. So, we’re on a firm target for 2030, but there is still some room to potentially evaluate short-term options between now and then.”
Zachary Rogala, staff attorney at PacifiCorp, noted that the company’s service territory in Washington is “much smaller” than that of other utilities operating in the state.
“Given the size of our service territory, these are realistic targets, and we’re excited to share that news today,” Rogala said.
The costs associated with the procurement of the new resources “will be reviewed in the context of CETA’s cost-containment provisions and associated commission rules,” Drew Marine, PacifiCorp spokesperson, told RTO Insider in an email.
“Additional information about the costs of these resources will be provided in a subsequent filing in this same docket, based on the conditions of approval adopted by the commission,” Marine added. “PacifiCorp recognizes affordability concerns and is committed to helping mitigate customer cost pressures driven by Washington’s policies.”
The announcement came during a UTC meeting on PacifiCorp’s 2025 clean energy implementation plan, which is filed on a four-year cycle. PacifiCorp filed the plan in October 2025 for the UTC’s approval.
Since 2021, PacifiCorp has brought online or contracted for 3.3 GW of new renewable or storage resources, according to the utility’s presentation slides.
Over the next two decades, PacifiCorp says it needs over 2.5 GW of new renewable and storage resources to serve Washington customers and remain compliant with CETA. The company estimates it will need over $1.7 billion in transmission investments to connect the resources.
In the near term, PacifiCorp found that Washington customers will require 1.4 GW of new renewable resources by 2030, including 709 MW of wind and 735 of solar, supported by 462 MW of batteries, to generate CETA-compliant energy.
PacifiCorp anticipates $25.39 million in CETA compliance costs between 2026 and 2029. Compliance costs over the next 21 years could reach $1.4 billion, or a $72 million annual revenue increase, according to presentation slides.
In February, PacifiCorp agreed to sell most of its Washington utility operations to Portland General Electric for $1.9 billion. That deal is expected to close by early 2027, pending regulatory approvals. (See PGE to Acquire PacifiCorp’s Wash. Operations for $1.9B.)
NEW ORLEANS — In a case of déjà vu, MISO announced that NERC is poised to issue a follow-up to its Long-Term Reliability Assessment that stands to lower the RTO’s reliability vulnerability from “high risk” to “elevated.”
MISO Vice President of System Planning Aubrey Johnson said NERC would issue the updated findings in early May.
Speaking at a March 24 meeting of the System Planning Committee of the MISO Board of Directors, Johnson said this time around, NERC would factor in MISO’s interconnection queue fast lane, which boosts supply adequacy.
A NERC representative confirmed the agency would issue a special assessment in April.
MISO’s separate, expedited interconnection queue has attracted 27 GW worth of proposals across 53 generation projects, 72% of which is natural gas, 16% storage, 7% solar and 5% wind. So far, MISO is ready to clear or has cleared 11 GW of nameplate capacity to connect and is studying an additional 8 GW for interconnection. (See MISO’s 3rd Expedited Queue: 8 GW of Gas and Batteries.)
MISO Director Nancy Lange said NERC’s initial decision to ignore contributions from the expedited queue in its assessment is “puzzling.” NERC officials have said the organization enforces a cutoff date for information that informs the assessment.
Director Mark Johnson said even the improved standing to “elevated risk” is “still a discount to what’s being done” by MISO and its members to address reliability.
MISO Independent Market Monitor (IMM) David Patton told the RTO’s board, executives and stakeholders he continues to believe NERC was off base to designate MISO a high-risk area.
Patton said “probably the most significant” consequence of NERC’s LTRA is the U.S. Department of Energy issuing several 90-day retirement delays for coal plants in MISO’s territory. He said the orders are racking up extraordinary costs.
The U.S. Department of Energy reupped stay-open orders March 24 for NIPSCO’s R.M. Schahfer Generating Station and Centerpoint’s F.B. Culley Generating Station through June 21, 2026.
“It’s pretty easy to come the conclusion that none of these orders are actually needed,” Patton said at a March 24 meeting of the Markets Committee of the MISO Board of Directors.
Patton quipped that “nobody reads the report” and instead focuses on the vibrant colors on NERC’s indicative map.
Multiple state regulators belonging to the Organization of MISO States sent a letter in February to challenge NERC’s results and the omission of MISO’s fast-tracked interconnection process. (See MISO States Dispute ‘High Risk’ Designation from NERC.)
But at a March 25 Advisory Committee meeting, Clean Grid Alliance Executive Director Beth Soholt criticized MISO’s efforts to bring more supply online for translating overwhelmingly into new gas generation.
“I’m wondering where the balance is in this ‘all of the above’ approach,” Soholt said.
NERC similarly downgraded MISO’s alert level in the LTRA in 2025 through an after-the-fact supplement. In that case, the IMM criticized NERC’s original conclusion and pointed out an error: NERC used unforced capacity values for MISO when calculating a margin that it ultimately compared to an installed capacity requirement.
In February, MISO Senior Manager of Market Design Neil Shah told the Entergy Regional State Committee the RTO was in contact with NERC to hopefully improve assumptions used in the latest LTRA.
Shah said including the generator interconnection express lane would likely “close the gap” in the NERC report. However, he said uncertainty remains due to the potential for additional large loads claiming spots on the grid.
MISO expects the first projects from its expedited generator queue to come online in 2028. Beyond that, Shah said, “MISO is projecting higher rate of new resource additions in 2026” than have historically come online annually from 2022 to 2025.
Large Loads, Uptick in Supply Additions
NERC’s revised findings are set to arrive as large loads continue to ratchet up in MISO and the RTO sets sights on record-setting capacity additions.
MISO’s Advisory Committee at its March 25 meeting voted to create a Large Load Working Group, which would discuss ever-larger load integrations and report to the Advisory Committee. The new stakeholder group doesn’t yet have a charter or management plan, but it will likely help develop ideas to better integrate demand.
MISO has indicated it will introduce reliability requirements for large loads at the time of interconnection and could file a proposal with FERC in late 2026.
During Board Week, MISO said its recent load estimates and its members’ load forecasting show it could have more than 145 GW in load by 2030 and about 155 GW in 2035.
MISO and members’ load projections through 2035 | MISO
MISO expects to add about 15 GW of capacity by the end of 2026. If realized, it would be a record for the RTO.
“The systems are responding. The work we’re doing is really coming to fruition,” Aubrey Johnson said of MISO’s interconnection process.
MISO’s legacy interconnection queue contains 192 GW, but the RTO expects that number to continue declining as federal tax credits are phased out. The grid operator faced a more-than-300-GW queue at one point in 2025.
MISO has recently issued $60 million in refunds to withdrawing interconnection customers, a figure significant enough to be featured in the RTO’s financial updates.
Relatedly, the grid operator now has 76 GW in generation with approved interconnection agreements but has yet to be built.
“We predict that we will have close to 100 GW … by the end of the year,” Johnson said at the System Planning Committee meeting.
Of the 76 GW, MISO reported that 42 GW are delayed three years or more beyond their stated commercial operation dates. Johnson said developers remain dogged by permitting hurdles, supply chain issues and, in some cases, the lack of an off-taker for their planned projects.
However, Johnson said MISO was able to process the first study phase of the regular 2025 cycle of interconnection projects in just 54 business days.
“And that’s going to be the slowest we ever do it,” Johnson said. “Going forward, we expect to only have one open queue cycle per year.”
However, Soholt said she’s heard that some interconnection customers don’t trust the results Pearl Street’s SUGAR software (which MISO is using to automate studies) is producing, noting interconnection customers are having difficulty replicating the study results they receive.
The volatility of supply and demand straining the U.S. bulk power system is generally accepted as the Senate Energy and Natural Resources Committee continues to work on permitting legislation. How to address that imbalance drew varied testimony in a March 25 hearing.
“This hearing is one of the series on the importance of permitting reform to inform our committee’s deliberations on the challenges facing the nation’s bulk power system and what Congress should do to address them,” Chair Mike Lee (R-Utah) said to open the hearing.
The imbalance is the result of power plant retirements made when demand growth was flat. Demand has surged because of the addition of large loads like data centers.
“These are structural changes in our economy that require really large amounts of electricity around the clock,” Lee said. “Our grid was designed to meet peaks most of the time. It operates with excess capacity, but that cushion is shrinking. In some regions, the margin is already gone.”
Ranking Member Martin Heinrich (D-N.M.) agreed the grid is straining due to rising demand but argued some Trump administration policies are not helping.
“This imbalance has led to electricity bills rising by as much as 13% since President Trump took office,” Heinrich said. “These rising costs made worse by the administration’s fossil-only agenda, which includes propping up uneconomic coal plants, stalling 116 GW of new capacity from coming online, canceling clean energy projects and starting a war with Iran that is driving up oil and gas prices.”
Demand is rising, but exactly when and where the new large customers will show up is far from certain, said Todd Snitchler, CEO of the Electric Power Supply Association.
“This uncertainty is perhaps the greatest risk for both reliability and affordability for electric consumers because of the danger of either over- or under-producing capacity during a time of volatile demand projections,” he added.
That risk can be minimized by using competitive wholesale energy markets, encouraging bilateral or co-located agreements, improving load forecasting, passing a permitting law and recognizing that much of the recent increase in prices is due to state policies and regulations, Snitchler said.
“When competitive power suppliers, like our members, invest in generation assets, they do so without guarantees for cost recovery and an approved rate of return,” Snitchler said. “The risk of investing in those generation resources remains on the developers and owners of the plants and not the ratepayer.”
Travis Fisher, Cato Institute director of energy and environmental policy studies, said Congress should embrace competition, arguing that federal policy has fallen well short of that.
“I very much agree with a 2002 book by Cato that referred to the mandatory open access model of transmission, which is basically what we’re dealing with now, which is the restructuring — I wouldn’t call it deregulation — restructuring from the late 1990s, referred to that as ‘infrastructure socialism,’” Fisher said. “Now that is, I think, a fair way to characterize the public grid. That’s why I’ve been advocating today for a new parallel path to allow private grids.”
The growth in artificial intelligence data centers and advanced manufacturing is a sign of an expanding economy, but the grid cannot keep up. Consumer-regulated electricity can meet that demand quickly without overburdening other consumers, Fisher said. (See GOP Senator Introduces Bill to Let Large Loads Set up Consumer Regulated Utilities.)
“The idea is straightforward: allow new large-scale customers, like data centers, to develop off-grid power systems under voluntary contracts,” he said. “These systems would be physically separate from the existing grid. That means no interconnection delays, no reliance on congested transmission networks, and importantly, no shifting of costs or risks onto existing ratepayers.”
The best way the committee can help the grid meet rising demand is by expanding the power grid, said Liza Reid, Niskanen Center director of climate and energy policy.
“We are building a more diverse set of energy resources at the same time: gas, nuclear, wind, solar, geothermal and storage,” Reid said. “But no single resource is sufficient on its own. Reliability depends on how these resources work together, and transmission is what allows that coordination to happen and ensures that every American has access to that affordable power.”
The bulk power system is made up of regional grids, with limited transfer capability between them, which has been illustrated in recent winter storms when one region is facing tight conditions while its neighbor operates normally.
“Interregional transmission lines are in the national public interest because of these affordability and reliability benefits that they provide, yet they face much higher siting and permitting barriers than other energy infrastructure, because the authority to prove approve interstate projects still rests largely with the states or even sometimes counties,” Reid said.
A shortage of grid capacity is the primary barrier to AI in the country, and without a dominant grid, the technology will develop faster elsewhere, she said. Congress can help deliver that grid with permitting legislation, she added.
