The U.S. Nuclear Regulatory Commission has issued a 20-year license renewal for the Diablo Canyon Power Plant, a nuclear facility seen as key to California grid reliability as the state transitions to clean energy.
The renewed licenses for Diablo Canyon Units 1 and 2 run through 2044 and 2045, respectively, though extending operations past 2030 would require action from the California Legislature. The NRC issued the renewed licenses and a record of decision April 2.
Diablo Canyon, a 2,200-MW facility owned and operated by Pacific Gas and Electric, supplied about 10% of the state’s total electricity in 2024, including 16% of its zero-carbon electricity. It is the state’s last operating nuclear power plant.
PG&E CEO Sumeet Singh called the Diablo Canyon license renewal “an important milestone for California’s energy future.”
“Diablo Canyon is the state’s largest source of clean energy and a cornerstone of reliability,” Singh said in a statement.
In 2016, PG&E agreed to retire Diablo Canyon Units 1 and 2 when their operating licenses expired in November 2024 August 2025, respectively.
But rolling blackouts in California during a 2020 heat wave and close calls in subsequent summers prompted state officials, including Gov. Gavin Newsom (D), to reassess Diablo’s future.
In September 2022, Newsom signed Senate Bill 846, authorizing a five-year extension of Diablo Canyon.
A statement from Newsom’s office following the license renewal said Diablo Canyon will provide around-the-clock, carbon-free electricity “as California navigates growing electricity demand and hotter summers, while continuing investments in grid reliability and additional clean energy resources.”
Newsom noted that Diablo Canyon’s electricity isn’t subject to the fluctuation of fossil fuel-based power resources.
SB 846 authorized a loan from the state’s general fund and directed PG&E to apply for a grant from the U.S. Department of Energy’s Civil Nuclear Credit Program. In January 2024, the DOE awarded PG&E $1.1 billion to keep Diablo Canyon running. (See Diablo Canyon Secures $1.1B DOE Award to Support Operations.)
The NRC granted an exemption to allow PG&E to keep running the units past their license expiration dates, a move that a federal appellate court upheld. (See 9th Circuit Upholds NRC Decision on Diablo Canyon.)
The California Public Utilities Commission approved a five-year extension for Diablo Canyon in December 2023. (See California PUC Votes to Extend Diablo Canyon Nuclear Plant 5 Years.) In December 2025, CPUC approved PG&E’s request to recover about $382 million from ratepayers to keep running Diablo Canyon.
PG&E said it has received approvals from the State Lands Commission, the California Coastal Commission and the Central Coast Regional Water Quality Control Board to extend Diablo Canyon operations.
Jeremy Groom, acting director of the NRC’s Office of Nuclear Reactor Regulation, said during a signing ceremony that Diablo Canyon is “a stabilizing force for California’s electric grid.” He said the license renewal is the NRC’s 100th renewed operating license for U.S. power plants.
And more renewals likely are on the way. In March, Arizona Public Service notified the NRC that it plans to seek operating license renewals for all three units at the Palo Verde Generating Station, potentially extending operations through the mid-2060s. (See APS to Seek Palo Verde Extension through 2067.)
Power prices were higher in most states in 2025 compared to a year earlier. A study from Lawrence Berkeley National Laboratory found that was due to multiple factors, which varied by state.
The study is an update of an earlier iteration and adds prices from 2025 to the initial study’s dataset from 2019 to 2024, Brattle Group Principal and study co-author Ryan Hledik said in an interview. (See LBNL Study Examines Drivers Behind Higher Power Prices in Some States.)
“The drivers of changes in electricity prices are nuanced,” Hledik said. “There is often, I think, a tendency to want to point to one single factor that is leading to increasing electricity prices. And this analysis supported the work that we did previously and showed that it’s more complicated than that. There are a number of factors that can push rates either up or down depending on which market you’re in and where you’re located.”
The report will be updated regularly, as this release and the initial version from October 2025 have proven valuable to those interested in the electric industry, he added.
Electricity prices rose, on average, about 3% in 2025 from a year earlier, which is a departure from 2019 to 2024.
“It’s only one year, but it does give you the sense that we could be observing the beginning of this inflection point where rates go from declining at a modest rate in inflation-adjusted terms to increasing in inflation-adjusted terms,” Hledik said.
Data centers often are blamed by the public as a primary culprit for rising prices. So far, new supply in PJM, for example, hasn’t kept up with the demand driven by data centers. That has led to higher capacity prices, which in turn contribute to higher retail prices.
“That’s not the only driver of rate changes in PJM states,” Hledik said. “And then, you know, PJM is not the only market in the United States. There’s a lot happening that looks different than that in other parts of the country.”
Natural gas prices increased between 2024 and 2025, and that was a significant driver of higher electricity prices.
“Load growth can be a contributor. We saw that in PJM, but if natural gas prices swing upward during that period, those are going to drive an increase in electricity prices as well, and that was observed pretty broadly, given the country’s dependence on natural gas as a fuel source for generation,” Hledik said.
A graph from the report showing the close relationship between natural gas prices and power prices. | Lawrence Berkeley National Laboratory
The LBNL study did not look into secondary effects of data centers like whether their demand has influenced the cost of components. Wood Mackenzie released a report April 1 finding the cost of gas turbines was expected to hit $600/kW by the end of 2027 — a 195% increase from 2019 — due to higher demand, “especially” from data centers.
The reasons for rising equipment costs in recent years are broader than just data centers, Hledik said.
“The cost of equipment on the distribution system has increased significantly over the last six years, and data centers are not typically distribution-connected loads. They’re plugging directly into the transmission system,” Hledik said. “The reason we’ve seen equipment costs increasing at the distribution level is because of post-pandemic supply chain constraints that still haven’t been resolved.”
State policies play a role, Hledik said. They are one of the top three or four drivers for power prices, with renewable portfolio standards that require utilities to buy generation at above-market rates as one example, he said.
“In a market like Texas that has great access to wind and solar generation, you don’t see rates going up because the market has concluded that those are economically competitive resource types,” Hledik said. “Where we’ve seen there potentially being some upward pressure is if you have a state that has clean energy goals and is asking their utility to go out and buy stuff out of market that is more expensive than they would procure otherwise.”
The policy calculation there is that climate change will lead to costs through extreme weather, wildfires and other issues. So, some states have opted to address that by investing in renewables now, he added.
Situations beyond the control of state policymakers have a big influence on prices, such as the availability of cheap power or the kind of geography on which utilities need to build the grid.
“If it’s a utility that has physical topography that is easier to build power lines across, than one that is harder to develop, that can drive up costs as well,” Hledik said. “If you’re in the West and dealing with drought conditions that can increase the risk of wildfires, and then you’re recovering the cost of wildfire risk mitigation through your retail electricity rates — that can drive up costs.”
Another issue with retail power prices is how they are spread around to different customer classes. Residential customers pay higher rates at a national average in 2025 of 17.3 cents/kWh in 2025, which compares to 13.4 cents/kWh for commercial customers and 8.6 cents/kWh for industrial customers, the paper said.
Residential prices from 2019 to 2025 rose 33%, while commercial and industrial customers saw increases of 26% and 27%, respectively. However, between 2024 and 2025, residential customers saw prices rise 5%, compared to 5.2% for commercial customers and 6% for industrial customers, the paper said.
“Residential customers are located all the way at the end of the distribution system, whereas larger industrial customers or data centers might not be using the distribution system at all,” Hledik said. “They might be plugging directly into the transmission system. And, so, when rates are being set for each of these customer classes, they’re being set roughly based on the costs that each of those classes are contributing to the overall cost.”
That leads to some of the disparity, but policy and politics can get involved as larger customers can intervene in legislative or regulatory proceedings to get lower rates for themselves, he added.
The data center industry, utilities, regulators and politicians all talk about ensuring the new class of hyperscale customers pay for the costs of serving their new load. But given the realities of the retail setting, getting that 100% perfect will not be possible, Hledik said.
“If we conclude that ultimately the best we can do from an accounting standpoint is ensure that about 90% of the costs that are being introduced by very large customers are being recovered from those customers, you might also see accompanying policies,” he added.
Regulators could make up the difference by having data centers pay into funds to offset costs for low-income consumers, or low-income weatherization programs. Low-income customers have a higher energy burden than others.
“If you look back over the last couple of decades, on average, the cost of electricity as a percent of total household expenditures has actually decreased,” Hledik said. “But if you look specifically at certain vulnerable customer segments, like lower-income customers, their energy affordability challenges have actually increased over the last five to six years.”
Texas Gov. Greg Abbott has opened applications for $350 million in grants through the Texas Advanced Nuclear Development Fund (TANDF) to support the nuclear energy industry, its supply chain and its manufacturing capacity in the state.
“To power the Texas of tomorrow, we must boost our state’s advanced nuclear capacity,” Abbott said in a statement.
The TANDF, the largest nuclear investment in the country according to Texas, was created by state law in 2025 to aid the development and commercialization of the advanced nuclear sector. The same law also created the state’s Texas Advanced Nuclear Energy Office (TANEO), which will administer the funds.
“Through TANEO and the [TANDF], Texas is streamlining the nuclear regulatory environment and making investments to spur a flourishing nuclear energy ecosystem for generations to come,” Abbott said.
Reed Clay, president of the Texas Nuclear Alliance, welcomed the news. He applauded Abbott and the TANEO for “establishing the programs that will lead directly to more nuclear power and more nuclear jobs in the state of Texas.”
“It is clear that the governor urgently understands two things,” Clay said in an email: “the immense national security and energy security implications of regaining our status as the world’s leading exporter of nuclear technology, and the exponential opportunity to bring high-paying jobs to Texas as the nuclear industry re-establishes itself.”
The alliance, formed in 2022, is dedicated to the advancement of nuclear technology in Texas. Clay said some of its more than 70 member companies played an “instrumental” role in passing the bill that created the TANDF.
The fund comprises two programs: Project Development and Supply Chain Reimbursement, and Advanced Nuclear Construction Reimbursement. Grant applications for the programs are open to projects that build advanced reactors, strengthen the nuclear manufacturing capacity and build a domestic fuel cycle supply chain in Texas.
The development program holds $70 million, capped at $12.5 million per award. The construction program holds $280 million, capped at $120 million per award. State law allows the TANEO to only sign agreements with projects that have a license or permit application from the U.S. Nuclear Regulatory Commission.
Only two projects are currently eligible. X-energy’s 80-MW collaboration with Dow at the latter’s Seadrift facility on the Gulf Coast has entered an 18-month construction-permit review by the NRC. Fermi America has an advanced nuclear application pending before the commission for its four-unit AP1000 plant, part of Project Matador in the Texas Panhandle.
Applicants must submit a notice of intent to apply by April 23 and submit formal applications by May 14.
The TANDF is modeled after the $10 billion Texas Energy Fund, which provides grants and loans to finance the construction, maintenance and modernization of the state’s electric facilities.
Thomas Gleeson, chair of the Public Utility Commission, said during a state Senate hearing April 1 that the PUC has executed six loans for 3.5 GW of gas-fired generation, with an additional 5 GW of projects going through due diligence. That nears the TEF’s goal of 10 GW of dispatchable generation.
The commission has also selected 29 projects that strengthen electric reliability and facility weatherization for the 919,000 customers served outside the ERCOT region, Gleeson said.
SPP says it has become the first grid operator to manage markets in both the Eastern and Western interconnections with its formal expansion into the West.
The RTO increased its footprint to 17 states at midnight (CT) April 1, expanding its reliability coordination, wholesale market and other services into the Western Interconnection on schedule.
The DC ties between the eastern and western interconnections. | NREL
The expansion adds three states to SPP’s current RTO coverage: Arizona, Colorado and Utah. The RTO Expansion members affirmed their support to go live April 1 with a unanimous vote of support in March. (See SPP RTO Expansion Members Affirm April 1 Go-live.)
“We’re working closely with our utility partners, neighboring systems and others to closely monitor grid conditions,” SPP spokesperson Derek Wingfield said. “So far, all indications suggest that we’ve completed a smooth transition.”
ROUND ROCK, Texas — A slew of “pent-up” interconnection requests from large load customers submitted by Oncor Electric Delivery has pushed the ERCOT queue for interested data centers and crypto miners to over 410 GW.
The large load interconnection queue stood at 238 GW in early March. However, ERCOT staff said they have received 137 new interconnection submissions since then totaling about 140 GW of new large loads by 2036. Oncor submitted about 130 GW of those requests, almost as much as the grid’s current nameplate generation capacity of about 150 GW.
“It looks like there were some pent-up projects that had not yet gotten into the queue,” ERCOT CEO Pablo Vegas said while meeting with reporters March 31 during ERCOT’s annual Innovation Summit. “They all kind of landed in a one-week period.”
Vegas delivered the same news to the Texas Senate Business and Commerce Committee April 1 during its first interim hearing before the 2027 legislative session begins in January. Committee members were unfazed.
“Import the sun directly to Texas. Hook it up to our grid,” cracked committee Chair Charles Schwertner (R).
ERCOT CEO Pablo Vegas | Texas Senate
Load projections are submitted to ERCOT by transmission companies, who work directly with the interested customers and have “varying approaches to complying” with state law, Vegas told senators.
“ERCOT is continuing to work through new processes to study large loads in a coordinated manner as part of transmission system planning,” Oncor told RTO Insider in an email. “Oncor periodically formally requests new study assignments for large loads seeking interconnection to our system. To ensure ERCOT has appropriate visibility during this process development, we recently provided an extended scope of our requests. Oncor will continue to provide updated interconnection requests as appropriate.”
The Public Utility Commission has filed a proposed rule change that would establish interconnection standards for large load customers. The rule would require those customers to execute an intermediate agreement that makes certain disclosures before their projects’ inclusion in an interconnection study and to post $50,000/MW in financial security. Within 30 days of the completion of the study, the customers would have to execute an interconnection agreement that updates their disclosures and pay a nonrefundable $50,000/MW interconnection fee (58481). (See Texas PUC Proposes Large Load Interconnection Standards.)
“Those same requirements could be used to effectively filter down the load forecast to a realistic number,” Vegas said.
Asked how long the “gold rush” of large loads flocking to Texas will last, PUC Chair Thomas Gleeson told the committee: “This is something that will definitely be here for the foreseeable future. I really believe, from the companies I’ve talked to, that … it may not be this upward trend. It’s such a high slope. But I do think we’re going to continue to see data centers look to locate here and get power from us for at least five to seven years.”
“This cycle is about a five-year cycle we’re going to see develop,” Vegas said, “and then we’ll have to evaluate what’s ahead.”
In the meantime, the Texas grid will be in the Legislature’s crosshairs. Lt. Gov. Dan Patrick has issued eight interim charges for senators to study in preparation for the 2027 session. The first four all relate to ERCOT and the grid, including:
assessing the state of the grid;
managing the effect on 765-kV transmission lines on landowners’ rights;
modernizing transmission and improving affordability; and
managing data center growth.
The House of Representatives’ interim charges focus on similar issues.
“These interim charges reflect issues Texans have asked the Senate to study,” Patrick said in a statement. “When the 90th regular legislative session begins … the Texas Senate will move quickly to address these priorities and many more.”
The Bonneville Power Administration could end up revising its rates to tackle the financial fallout of a federal judge in Oregon ordering increased spill levels at eight dams on the Columbia and Snake rivers.
In the wake of the court-ordered injunction, BPA staff hosted a workshop March 30 to discuss proposed revisions to the 2026-2028 power general rate schedule provisions.
Before the injunction, the agency expected to end fiscal year 2028 with $397 million in financial reserves. But with the court order, if it were to take no action, the agency anticipates ending 2028 with $196 million in reserves, according to Daniel Fisher, BPA’s power rates manager.
“That’s a big number. There’s just no way around that,” Fisher said.
The agency said the court order changes how it operates its system and the inventory levels from what it had anticipated when it set rates for the FY26-28 period (BP-26).
To tackle the issue, staff presented several solutions, each of which assumes the agency is $85 million worse off in each year of the three-year rate period relative to the rates set under BP-26, according to their presentation.
Staff prefer a solution that includes collecting $125 million in expected costs upfront in fiscal years 2027 and 2028. The solution includes an end-of-year true-up provision that would return a portion or all $125 million if BPA’s financial reserves attributable to power are higher than 90 days’ cash at the end of each year.
Under the solution, called Conditional PNRR, BPA expects to end fiscal year 2028 with $392 million in financial reserves, $5 million lower than the pre-injunction results. Staff said they favor the approach because its last true-up occurs at the end of 2028 rather than at the end of 2027.
“This increases the chance that BPA will start the new contract with financial reserves at a level similar to that had BPA known about the court-ordered operations when it first set BP-26 rates,” according to the presentation.
Another solution would entail a new surcharge capped at $125 million. The surcharge “would trigger if fiscal years 2026 and 2027 ended below 90 days’ cash and would collect the difference up to the cap of $125 million in the next fiscal year,” it says.
Utility representatives voiced support for BPA’s efforts to address the financial impact of the court order.
Garrison Marr, senior manager of power supply at Snohomish County Public Utility District, said BPA moving quickly on the rate case process “helps us for transparency for utility planning; helps with risk reduction … and cost certainty in the context of the spill injunction.”
Marr said Snohomish leans in favor of the Conditional PNRR solution.
Chris Roden, director of energy resources at Clatskanie People’s Utility District, said he appreciates BPA addressing potential impacts early.
“It’s helpful for a utility that does concurrent ratemaking that’s largely driven by Bonneville to have a certain amount of certainty in our planning assumption, so that when we go through our own processes, we know what to bake in,” Roden said.
He added that staff have done a “good job” of not “getting stuck in the muck of politics, administrative outcomes. … Just sticking to the guns of good, prudent financial policy.”
BPA aims to issue an initial proposal in early May with testimony and supporting documents.
Court Injunction
The issue stems from a Feb. 25 court order in which U.S. District Judge Michael H. Simon granted a preliminary injunction sought by the states of Oregon and Washington, tribes and environmental groups. The order requires the U.S. Army Corps of Engineers and the Bureau of Reclamation to spill large amounts of water over the eight dams instead of running it through turbines to protect migrating salmon and steelhead in the Columbia and Snake rivers. (See Judge Orders Spill at Northwest Dams to Aid Salmon, Despite Energy Concerns.)
The long-running case now concerns an environmental impact statement and a biological opinion from 2020 that the court ordered the federal agencies to prepare for the Federal Columbia River Power System.
In challenging the analysis, the plaintiffs alleged the Army Corps’ plan failed to adequately protect salmon.
The case was stayed under a deal plaintiffs struck with President Joe Biden, which included, among other things, $1 billion toward salmon restoration. President Donald Trump upended the deal in June 2025. The Trump administration said it would have several negative impacts on energy production, shipping channels and water supply for local farmers. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.)
When the case resumed, plaintiffs asked for injunctive relief beginning March 1, urging the court to require federal defendants to increase spill levels, lower reservoir levels and implement emergency conservation measures for the salmon.
In granting the request, Simon said the injunction includes a provision for the federal agencies to adjust spill for emergency power generation and transportation needs. However, he rejected arguments that increasing spill levels could impact power generation, saying the granted relief is “narrowly tailored and essentially maintains the status quo.”
Talen Energy’s proposal to buy more than 2.5 GW of generation from Energy Capital Partners will lead to a more concentrated PJM market and more market power for the fourth-largest generator in the RTO, the PJM’s Independent Market Monitor said in comments filed with FERC on March 31 (EC26-59).
The deal for the Cornerstone Generation portfolio does not fail FERC’s Herfindahl-Hirschman Index (HHI) thresholds in a delivered price test Talen included in its application to buy the three power plants from ECP, which in turn bought them from ArcLight and Blackstone in 2025. The additional generation would increase Talen’s PJM generation portfolio from 13,139 MW to 15,684 MW.
While the deal does not break any HHI thresholds, Monitoring Analytics said the pivotal supplier test shows Talen already has market power and the deal would increase it.
“There are gaps in the market power mitigation rules for the PJM energy, capacity and ancillary services markets,” the IMM said. “The existence of pivotal suppliers in the PJM markets, along with insufficient market power mitigation, means that all increases in structural market power undermine the competitiveness of the PJM markets.”
The IMM said the deal should be approved only if Talen agrees to behavioral commitments, which would not burden the applicants because they only ensure competitive behavior. FERC should reject the initial application and require it be refiled with commitments, otherwise it would not be consistent with the public interest, the Monitor said.
“The broader question for the commission’s merger policy is whether any transactions that result in incremental increases in market power in the PJM capacity market, or any PJM market, without clear behavioral conditions should be approved as consistent with the public interest given the fact that the PJM capacity market is already characterized by endemic market power,” the IMM said.
The current need for new generation in PJM is an opportunity for increased competition and new entry, but generation ownership is instead being consolidated in a small group of owners, it contended.
“Talen has been one of the largest owners of generation in PJM since its creation in 2015,” the IMM said. “Talen is one of the top five owners of PJM capacity and recently acquired two large gas fired combined cycle resources, the Moxie Freedom and Guernsey plants, in 2025. Other owners in the top five also have recent and/or pending transactions: Constellation, Vistra and ArcLight. The market power created by this ownership consolidation creates the potential for additional upward pressure on PJM energy and capacity prices, at a time when data center load growth is already resulting in noncompetitive prices.”
FERC needs to consider the consolidation trend in every merger application for assets in PJM that comes before the agency, the Monitor added.
‘Even Greater Risk’
The commission has been relying on HHI tests as its primary market power screen for decades. HHI is the sum of the squared market shares of all market participants, and even a supplier that passes the screen can still raise market prices above a competitive level.
The market power mitigation rules for the energy market rely on the assumption that enough competitive sellers exist so that if anyone tried to raise prices, another would underbid it at a competitive price.
“This assumption requires that the total demand for energy can be met without the supply from any individual supplier or without the supply from a small group of suppliers,” the IMM said. “This assumption is not correct when there are pivotal suppliers in the energy market. In 2025, there were pivotal suppliers in the aggregate energy market on 95.3 percent of days.”
The capacity market is extremely tight, and that is expected to continue for the foreseeable future, leading to prices above historical norms that only increase the impact of market power.
As far as specific behavioral requirements for Talen, the IMM said the firm should commit to keeping existing capacity in the market, instead of withdrawing it to serve data centers via colocation. Removing existing capacity would make the market less competitive and lead to higher rates for consumers.
“The fact that PJM is already short of its reliability target and that PJM faces very significant levels of forecast data center load makes this reliability impact an even greater risk,” the IMM said. “Allowing the removal of capacity to serve data center load shifts the costs and risks of data centers from data centers to all other PJM customers.”
The IMM also suggested several ways Talen should be limited in its market bids and a commitment to retire units only when they are uneconomic.
NEW ORLEANS — A sitting state commissioner and two former regulators have asked MISO to publicly share any information it might gather on its Independent Market Monitor’s possible involvement in a five-state complaint against the RTO’s long-range transmission planning.
The regulators emphasized the need for transparency after emails surfaced pertaining to the drafting of the complaint.
Their requests come after Manifest Energy, a new group focused on ratepayer interests and industry transparency, in late March published a trove of emails from 2025 that circulated among state regulatory staff, outside counsel and consultants working on the complaint against MISO’s second, $22 billion long-range transmission plan (LRTP) portfolio approved in late 2024.
State utility commissions from Arkansas, Louisiana, Mississippi, North Dakota and Montana filed their complaint in July 2025, asking FERC to order MISO to revoke the classification of its second, $22 billion LRTP portfolio and nullify the portfolio’s load-ratio share cost allocation.
The states contend MISO and its board erred by advancing transmission projects that will cost more than the value they can provide and said FERC should scrutinize all the RTO’s future business cases supporting LRTPs (EL25-109).
Around the same time as the emails’ release, MISO board members authorized a third-party review of IMM best practices. In a statement to RTO Insider, MISO said the “emails and information ‘Manifest American Energy’ released were not part of the decision to conduct an independent, best practices review of the IMM function.”
At a March 26 meeting of MISO’s Board of Directors, Director Theresa Wise said the best practices review is sensible given that the RTO subjects other vendors to such a standard.
Patton has said his involvement with the parties who authored the complaint was limited to explaining his own transmission cost-benefit analysis that the complaint relied upon. He said he neither strategized with the complainants nor helped them draft the complaint.
Norris: MISO ‘Well Within’ Scope to Prod
Speaking for the Natural Resources Defense Council, John Norris, a former FERC commissioner, Iowa Utilities Board member and president of the Organization of MISO States, said he is concerned about the “genesis and construction” of the LRTP complaint.
During the March 26 meeting, Norris urged the MISO board to be open about what they discover.
“That notion of secrecy and surprise … don’t devolve into that. There’s nothing to be gained from the element of surprise.”
Norris said MISO is “well within its scope” to ask for a complete report from the IMM that outlines when the engagement began and how long it lasted, the nature of the engagement, and “what input was provided on the construction and drafting of the complaint.” The RTO is “entitled to know” those details, he added.
MISO should “take the initiative” to uncover those details while the LRTP complaint remains outstanding, Norris said.
“I would encourage you to act on this right away. Transparency is critical to public trust in our process. Any divergence from that … should not be permissible,” he said. “As best I can tell in talking to folks, MISO wasn’t aware. That concerns me.”
Norris said if he were still a FERC commissioner, he’d be interested in what transpires.
“How do you give an independent assessment when there was at least some level of engagement that impacts your ability to provide an independent assessment?” he asked.
Norris said based on “what I’ve seen so far of the documentation provided … something does not add up.” He noted the engagement between Patton and those authoring the complaint seemed to span months based on email chains.
“It’s just, ‘Come clean,’” Norris said later in an interview with RTO Insider.
Speaking before the MISO board, Norris said the process behind the complaint “diverted from” what he remembered as a culture of mutual respect and openness while involved with OMS. He lamented that a majority of OMS members “this time weren’t a part of the conversation.”
“Transparency is essential for continuity of investment and for public trust,” he said. “That’s what troubled me about both the process and the complaint — is that all MISO states have been open with each other and shared positions and unequivocally accepted dissent, so what was the need for the secrecy around the action of six OMS members?”
Norris contended that MISO South’s aversion to transmission planning now stands to affect MISO Midwest’s transmission planning successes.
“The genesis of this complaint comes from MISO South, and it’s the same set of stall tactics that have prevented long-range transmission from ever getting off the ground in 13 years,” Norris said.
Entergy and others joined MISO in 2013, creating MISO South. Norris was one of the FERC regulators to approve the utility’s membership, but he has since criticized a lack of regional transmission planning in the South and has said given what he knows now, he would not have cast a vote for Entergy to join MISO.
Norris said one thought struck him while meeting with young members of MISO’s Environmental Sector during the RTO’s Board Week: “You’ll probably be middle-aged before a long-term transmission project is built in MISO South.”
Norris told the board he’s a “longtime believer of long-range transmission planning and building for the future.”
“Planning is critical. We owe it to the next generation to get this done,” Norris said.
Differing Views
On the other hand, former FERC Chair Mark Christie, now director of the Center for Energy Law and Policy, supported Patton on social media.
Christie said both the PJM and MISO monitors are “frequently attacked by interest groups who don’t like it when the IMMs do their jobs.”
“Their job is to put out the facts with independent analysis, regardless of which interests don’t like it,” Christie said, calling Patton an “invaluable neutral analyst.”
“Patton correctly understands that transmission planning, which costs consumers literally trillions of dollars, should be subject to the same scrutiny as markets,” Christie wrote in a March 31 LinkedIn post.
But Energize Strategies’ Ted Thomas, former chair of the Arkansas Public Service Commission, seconded the call for transparency.
“When you’re dealing with decisions of this scale, transparency is what gives the process credibility,” Thomas said in an email to RTO Insider. “If discussions involving the Independent Market Monitor occurred before FERC had issued an order clarifying its authority under the tariff to weigh in on transmission matters, that timing raises reasonable questions about role clarity and process.”
“Stakeholders deserve transparency on that point,” Thomas said. “At the same time, we shouldn’t lose sight of the bigger picture — a reliable, well-planned transmission system is essential to keeping costs down. The goal should be disciplined governance and continued investment, not uncertainty that ultimately puts ratepayers at risk.”
Ham: ‘Clear’ the Perception
Minnesota Public Utilities Commissioner Hwikwon Ham said if MISO’s review delves into the extent of communications between the IMM and states regarding the LRTP complaint, then the RTO should present public findings to its stakeholder community. He said trust relies on public information.
Ham said it’s “too soon to tell if trust has been violated” regarding the IMM.
“I don’t think the IMM office’s intention is anticompetitive behavior. … But we need to make sure we have trust in the IMM’s office. At least if there’s some perception in the community, I think we need to clear that perception,” Ham told RTO Insider. “[Possibly] being associated with that kind of activity makes his office less credible — that’s my concern.”
Ham said the perception that the IMM could have “potentially taken a side” and engaged with testimony while later intervening in the complaint “makes me uncomfortable.” He added that he had no direct knowledge of the communications until the release of the emails.
Ham said he’s engaged the IMM for his advice many times over the years, particularly in regard to understanding the effect a sloped demand curve would have on MISO’s capacity market.
Ham said what appears unusual about this instance is that it involves parties protesting an adopted MISO stakeholder agreement. He said personally, he’s never heard of the IMM becoming involved in a protest of MISO processes.
Ham stressed that he and the Minnesota PUC “strongly support a market monitoring function at the RTO.”
Above all, the complaint is about allocating the cost of MISO’s long-range transmission lines, Ham said. He said the discord could mean it’s time for stakeholders to revisit MISO’s cost allocation methodologies.
“Hopefully people are more focused on doing it than fighting over this. That is my wish,” Ham said. “Hopefully, MISO and OMS can regroup and talk about long-range cost allocation. Hopefully, everybody can focus on the core issue, and everyone can agree on a solution to this. Because the nation needs those transmission lines.”
Ham said it’s not a problem that OMS contains differing views across the states.
“Overall, I think OMS is not a consensus organization,” he said, adding that he’s there to protect Minnesota’s best interests while other states act in their best interests.
Ham recounted that when he worked previously as a PUC staff member, he and now fellow Commissioner Joseph Sullivan spent about three years starting in 2020 trying to create cost allocation solutions that would work across the MISO footprint.
“I strongly believed we could do that,” Ham said. “That’s why it’s very painful for me to see this secondary legal challenge rather than solutions through the OMS process.”
A draft order from the Public Utilities Commission of Nevada signals that the commission is likely to approve NV Energy’s participation in CAISO’s Extended Day-Ahead Market, but with conditions to address stakeholder concerns.
The draft order, released March 31, would grant NV Energy’s request to join EDAM in fall 2028. The commission is to vote on the order April 3.
In potentially granting NV Energy’s request to join EDAM, the draft order noted the company’s positive experience with CAISO’s Western Energy Imbalance Market. And being a WEIM participant is expected to reduce implementation costs for joining EDAM, the draft order stated.
The draft order also pointed to NV Energy’s “numerous, significant interties” with other expected EDAM participants. Those include eight direct interconnections with CAISO and connections with Idaho Power, Los Angeles Department of Water and Power, and PacifiCorp.
Diverse energy resources available through EDAM was another factor in the draft decision.
NV Energy filed its request to join EDAM on Oct. 22 as an amendment to its 2025-2027 Energy Supply Plan. (See NV Energy Files Request to Join EDAM.)
The application cited a Brattle Group study that projected the company would save $93.1 million a year by joining EDAM relative to participating in WEIM alone. In contrast, joining SPP’s competing day-ahead market, Markets+, would increase annual costs by an estimated $7.3 million.
Some parties argued that the benefits to NV Energy of joining EDAM are uncertain because they’re based on assumptions in a production cost model. They said the commission should wait until EDAM is in operation in 2026 and 2027 before finding it’s prudent for the company to join. (See Caution Urged as Regulators Consider NV Energy’s Request to Join EDAM.)
The draft order said that “while the commission finds and agrees that there will be benefits [from joining EDAM], the commission cannot find that $93.1 million is a precise estimate of projected benefits.”
The draft order would require NV Energy to come up with a way to measure annual adjusted production cost savings from EDAM participation.
“The commission finds that NV Energy’s potential APC savings are seasonal and highly dependent on NV Energy’s ability to acquire excess California solar energy at very low, zero, or negative cost during limited hours of the day in the spring,” the draft order said.
The draft order also addressed surcharges to EDAM participants who don’t meet a daily resource sufficiency evaluation (RSE). NV Energy argued that it has enough resources to pass the RSE and doesn’t expect to pay any surcharges. The draft order says if there are RSE surcharges, company shareholders will be responsible for paying them.
Another stakeholder concern was that NV Energy has not yet revised its Open Access Transmission Tariff. The commission’s draft order includes a requirement for the company to file reports on the progress of its OATT stakeholder process, with drafts, comments and responses posted to its Open Access Same-time Information System (OASIS).
In comments filed to FERC, NERC opposes a proposal that would require the ERO and utilities to harden the grid against space radiation and electromagnetic pulse (EMP) attacks, claiming the proponents offers “no new compelling facts” to support their recommendations (EL26-49).
The proposal by the Center for Security Policy (CSP) and the Secure the Grid Coalition (STG) drew support from a range of commenters, including scientists, engineers, lawmakers and lobbying groups. In comments filed March 30, they described the risks raised by CSP and STG as “not speculative” and NERC’s relevant reliability standard TPL-007-4 (Transmission system planned performance for geomagnetic disturbance events) as “a false assurance” that is inadequate to protect the grid.
CSP and STG’s complaint, filed March 9, called for FERC to direct NERC to study electric utilities’ risk exposure to disruption by ground-induced current (GIC) from solar weather and EMPs, and for the commission to incentivize utilities to harden their systems through rate recovery.
‘Catastrophic’ Threat from GICs
The threat from GICs is “both inevitable and catastrophic,” the groups argued, citing testimony to Congress in 2019 in which Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security, warned that such events “pose substantial risk to equipment and operation of the nation’s electric grid.” GIC-related damages to the U.S. power grid cause almost $7 billion in economic losses each year, they continued, referring to a study published in the journal Space Weather, and are likely to grow as the construction of data centers accelerates.
Publications from the U.S. Department of Energy and a U.S. Senate commission on EMPs, as well as the International Electrotechnical Commission’s (IEC) EMP protection standard, support hardening the electrical system to withstand GIC events with a field strength of 85 V/km, the groups observed. But, they continued, TPL-007-4 “does not protect against [GICs] … which routinely damage equipment in the” electric grid.
In fact, the model used to create the standard “purposely excluded” a 1921 solar storm that produced a strength of 20 V/km, the groups alleged, criticizing NERC’s consensus-based standards development process as designed to produce “the lowest common denominator to achieve sufficient votes by the regulated industry.”
To address the GIC threat, the groups asked that FERC direct NERC to survey all registered entities by requiring a “technical assessment of all covered equipment to determine vulnerability to GICs.” They requested the assessment require:
Modeling behavior of equipment under peak magnetic field strength of 20,000 nanoteslas or peak electric field strength of 85 V/km, using waveforms in the IEC EMP standard.
Assuming GIC exposure with transformers fully loaded.
Modeling transformer age and condition according to standards of the American National Standards Institute and the Institute of Electrical and Electronic Engineers.
Determining vulnerability to “half-cycle saturation, GIC-induced harmonics, reactive power consumption, hot spot generation and insulation degradation.”
They also requested that the commission “provide cost recovery for assessment and GIC protection to 85 V/km.”
NERC Claims No Basis for Complaint
NERC’s March 30 response asked that FERC deny the complaint, claiming it “fails to set forth the basis in fact and law for the positions taken and fails to demonstrate the existence of any action or inaction that is inconsistent with applicable laws.”
The ERO wrote that the groups’ objection to TPL-007-4 “appears to rest on an inaccurate understanding” of the standard, which was developed to address the risk of geomagnetic disturbances from solar storms rather than EMP attacks. NERC reminded the commission that “extensive rulemaking proceedings” and studies preceded the adoption of the original TPL-007-1 standard, and that FERC found it and all of its successors to be just, reasonable and in the public interest.
The ERO pointed out that its analysis of a GMD event that occurred in May 2024 showed the electric grid “experienced few … impacts” during the storm. This was the first major GMD event since TPL-007-1 took effect, NERC wrote, indicating that TPL-007-4 and other GMD-related standards “are operating as intended to protect the grid during severe solar storms.” NERC said the complainants’ call for a study, and their focus on the threshold of 85 V/km, was “a collateral attack on matters settled long ago.”
The ERO also asked whether STG and CSP wished to move toward a “technology mandated” approach that prescribes specific remedies, citing a section of the complaint in which the groups called GIC-blocking devices “proven and validated” and suggested requiring it on U.S. grid transformers.
NERC wrote that GIC blockers “are an important tool in mitigating potential GIC risks,” but warned that deploying them at scale requires considerable analysis and potentially increases risks to grid reliability “due to potential issues with installation and misoperation.” The ERO reminded FERC that such factors are why NERC prefers a “technology-neutral” approach that allows registered entities the flexibility to choose their own best solutions.
Most Comments Support Original Complaint
Despite NERC’s defense of TPL-007-4, additional comments filed in the docket overwhelmingly supported the original complaint, indicating widespread concern about the risk of grid disturbances from GIC events.
Individual respondents included Tennessee state Sen. Janice Bowling (R), who wrote that she has “observed a major reluctance of utilities … to address the GIC threat with hardware protection because they are afforded no financial incentives from FERC to do so.” She requested the commission “thoroughly investigate” the issue and make the findings available to the state Senate, where a bill sponsored by Bowling to require investigation of GICs’ impacts on the grid is under consideration.
Similarly, Texas state Sen. Bob Hall (R) wrote that despite “numerous forms of legislation,” the Texas grid remains vulnerable to GICs, for which he blamed a lack of “financial incentives for utilities to take aggressive action.” He also called on FERC to investigate the complaint and “create proper financial incentives” that will allow Texas regulators “to do the same for the utilities under their jurisdiction.”
The Foundation for Infrastructure Resilience (FIR), a nonprofit focused on preparing the U.S. for extended widespread grid failures caused by natural disasters, EMPs or physical and cyberattacks, wrote that “the GIC threat is not speculative” and the “regulatory and financial framework” to support needed resilience measures is not in place. Like NERC, FIR wrote that it prefers technology-neutral solutions and suggested the commission “frame any resulting reliability standard or order in terms of performance outcomes and engineering thresholds.”
Andrew Scott, a geologist affiliated with FIR, observed in a separate comment that geological evidence indicates the Earth has experienced multiple solar storms with field strengths of over 200 V/km. He compared NERC’s current approach to GICs to “placing fire sprinklers in one room of a house rather than across the entire structure, and then claiming the house is fully protected from fire.”
“Much money is saved by installing only one sprinkler, and everything looks great until a fire occurs. But to assume or claim the structure is fully protected and safe is misleading at best, deceptive at worst, and most likely fatal to those trapped inside the structure,” Scott wrote. “The unrealistic NERC TPL-007-4 GMD values must be increased upwards to 85+ V/km to address realistic threats to the power grid.”
