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April 3, 2026

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CIP Specialists Warn Compliance not Enough for Security

Speaking at the Texas Reliability Entity’s Spring Standards, Security and Reliability Workshop, NERC compliance expert Brent Castagnetto told utilities security breaches are inevitable if they do not “elevate” their focus on the ERO’s Critical Infrastructure Protection standards beyond the regular audit cycle.

Castagnetto is co-founder of NovaSync, a provider of compliance tools focused on the CIP standards, who joined the workshop to discuss what he called the “CIP drip” phenomenon. He said the name came from a conversation a year earlier with Nick Santora, NovaSync’s vice president of growth and his co-presenter at the workshop.

“We were lamenting the fact that we both own homes, and homes often come with unique sets of problems depending on where you live,” Castagnetto said. “They could be external [or] internal; they could be the fact that you bought a crappy old house like I did and then fixed it up, or you could have challenges with buying a new home and shoddy craftsmanship. Whether you rent or own, it is likely that you’ve experienced a challenging issue, or a drip or a leak with your own home.”

Castagnetto said he and his company have seen the same kind of problem in many organizations’ CIP compliance programs. These processes usually are set up with good intentions, he said, but it’s impossible to anticipate every shortcoming ahead of time, and entities must actively check to see if issues are developing that need to be addressed.

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“If we leave [these drips] unattended, and we have a leak that’s going through our foundation, that can lead to all kinds of problems, right? If we don’t address issues with our roof, we’re likely going to see some risk exposure there,” Castagnetto said. “The same thing applies when we look at audits that happen on a periodic basis, whether you’re on a three- or six-year cycle. … Is that good enough? No, you’re likely experiencing drips along the way that you have to address in a more meaningful and practical way.”

Castagnetto and Santora discussed some of the problems they have discovered that were developing without their clients’ knowledge. These fell into several categories, the first of which was issues having to do with employees, whom Santora quipped are likely to remain “a pretty big problem to solve … until the robots take over.”

Santora observed that any registered entity contains many people involved in CIP compliance, and keeping their understanding of the standards and their responsibilities up to date is an urgent requirement. He described the best training programs as a “two-way street, a push and a pull,” in which — rather than providing training and ordering employees to complete it — leadership engages with employees to learn what they are unsure about and what processes need updating.

The discussion of CIP training prompted Castagnetto to turn to the next topic, processes, which he called “critically important” but misunderstood by utilities who design their compliance processes as “calendar events and reminders that cue to do an activity or perform something.” He said this approach is less effective than one that focuses on “connecting the dots from the technology that we’re using to the people that are working in the process.”

“If you’re stuck in this mode where you’re using Outlook and calendar reminders to ensure that the … steps [are] undertaken to accomplish a specific task, it’s not going to work long-term for you,” he said. “Heaven forbid Outlook goes down … or that [responsible] person leaves, and now we’re just moving the calendar to somebody else. We’re passing the buck. You don’t want to find yourself in that situation.”

Entities also must understand that CIP compliance by itself is not enough to ensure the organization’s safety in the face of determined security threats, Castagnetto warned. He cited the case of Christina Chapman, an Arizona woman sentenced in 2025 to 8.5 years in federal prison for helping North Korean information technology workers obtain remote positions at more than 300 U.S. companies.

Chapman operated what authorities called a “laptop farm” at her home, storing more than 90 computers from the companies she fooled, as well as shipping devices to overseas locations. The North Korean employees used the “stolen or borrowed” identities of actual U.S. individuals to fool the IRS. While authorities eventually caught up with the scheme, it still generated more than $17 million in revenue for Chapman and North Korea. Castagnetto said the story shows that utilities cannot count on CIP compliance alone to protect them.

“There’s nothing in [the CIP standards] that says you have to go and verify these people, but we have to figure out a solution to it, because it can happen to us, and we don’t want to have that,” Castagnetto said.

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California Snowpack Near Record Lows as Summer Approaches

Despite a few large storms in January and February, snowpack levels in California are approaching record lows due to a heat dome that settled over the state in March.

The California Department of Water Resources (DWR) on April 1 found nothing when it measured the snowpack at Phillips Station in El Dorado County.

“We measured today, but there was actually no measurable snow … so we are calling today’s measurement 0 [inches],” Andy Reising, manager of snow surveys and water supply forecasting at DWR, said during a press conference held from the station on April 1.

In an average year, the snowpack depth at Phillips Station measures about five feet, with about three feet of snow and two feet of water below the snow. The zero-inch measurement represents the second-lowest April 1 measurement at the station in DWR’s history, Reising said, given that there was a trace amount of snow on the ground.

Snowpack levels typically peak around April 1, but the heat dome in March caused large snowmelt to start about two months early.

DWR Director Karla Nemeth called the measurements “one of the quickest snow surveys we’ve had and maybe one where people could actually use an umbrella.”

“That’s just the reality that we’re living in,” she said.

Most of the state’s precipitation in 2026 has come as rain, Nemeth said. The combination of rain, limited snow and warmer weather in March is “setting us up for what will be a challenging year for water management in the state,” she said.

Snowpack across the state is just 18% of average for April 1, DWR said in a news release. The snowpack fulfills about 30% of California’s water usage and is sometimes called the state’s “frozen reservoir,” DWR said.

However, there is fortunate news: California’s reservoirs are nearly full, Nemeth said.

“But what we have in our reservoirs is what we have. We have to manage that really for the next six months or so until we hit October,” she added.

Rivers in California are running higher than average due to the early snowmelt. Much of the snow runoff cannot be stored, however, because reservoirs are full and must keep some room to protect communities from flooding in the event of late spring rains. The state lacks the right infrastructure to convey early-season runoff into underground aquifers, DWR said.

CAISO relies on hydropower supplied by DWR’s State Water Project (SWP). The SWP has five hydroelectric generating plants and four hybrid plants, which generate about 6 billion kWh/year.

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Utilities, Lawmakers Push for ‘Bold’ Leader to Guide BPA Through Tx Challenges

Utilities and lawmakers in the Northwest agree the Bonneville Power Administration’s next administrator must focus on building transmission and take risks to make that happen.

BPA is searching for its next leader after outgoing Administrator John Hairston announced he is leaving the agency to head up the Eugene Water & Electric Board. (See Hairston to Retire from BPA, Poised to Join EWEB.)

Whoever takes over would oversee an agency that controls about 75% of the Northwest’s high-voltage transmission system. And this system “faces serious challenges,” Melanie Coon, Puget Sound Energy’s spokesperson, told RTO Insider in an email.

“Years of underinvestment have left the aging system at full capacity, limiting its ability to handle power flows within the Northwest and to neighboring regions,” Coon said. “PSE believes the incoming BPA administrator must prioritize transmission development as a critical focus area and be open to innovative partnerships that can accelerate transmission development across the region.”

PSE was one of the signatories to a Feb. 18 letter that a group of investor-owned utilities sent to U.S. Secretary of Energy Chris Wright. The other utilities include Avista Corp., Idaho Power, NorthWestern Energy, PacifiCorp and Portland General Electric.

The utilities said BPA’s mission is to ensure the Federal Columbia River Power System and Federal Columbia River Transmission System benefit all the agency’s customers, not just “select parts of the region or customers of any specific classification of electric utility.”

“For the region’s IOUs, BPA’s actions to carry out that mission have been deficient for some time, and BPA’s lack of transmission development in the region is the most visible example of this deficiency,” the letter stated.

A study by Energy and Environmental Economics predicts that accelerated load growth and aging power plant retirements will create a resource gap in the Northwest starting at about 1.3 GW in 2026 and expanding to almost 9 GW by 2030. That is approximately the load of the state of Oregon.

With the region facing “unprecedented load growth,” BPA needs a “bold leader” who prioritizes transmission investments, market structures that benefit all customers and is open to new public-private partnerships to speed up transmission development, the IOUs argued.

The IOUs noted that BPA has identified critical projects to help new resources and new large load developments come online. But without “the push of a new administrator, projects will linger without timely completion,” according to the letter.

John Haarlow, Snohomish County PUD’s CEO, echoed the IOUs’ concerns.

“What we’re hoping to see in the next administrator is someone who can move the agency from planning into action on transmission, generation and the infrastructure investments the Northwest requires to keep up with growing demand and pressing resource adequacy concerns,” Haarlow told RTO Insider.

Haarlow added that the next leader should be experienced in running a “complex organization” and be able to build relationships “across a diverse set of stakeholders, including utilities, tribes, states and Congress.”

Given BPA’s importance in the region, “It will take an innovative and results-oriented leader with a clear vision to lead across all of it,” he said.

A group of seven Republican lawmakers from Washington, Oregon, Idaho, Montana and Nevada sent a separate letter to Wright on March 18. The lawmakers similarly contended the next administrator must “act much more quickly” on transmission.

Citing conversations with stakeholders, the lawmakers said the agency needs “A disrupter. A risk taker.” The agency needs someone with “the ability to recognize the need for new ideas and new approaches to long-standing problems facing the agency,” including transmission, the lawmakers argued.

Sen. Ron Wyden (D-Ore.) told RTO Insider in an email that the next administrator should strive to keep energy bills low “while also expanding responsible transmission that will allow increased renewable energy on the grid.”

‘Transmission, Transmission, Transmission’

Under Hairston, who assumed the role of administrator in January 2021, BPA has secured $773.8 million in transmission capital for 2025 with the goal of doubling transmission capital execution by 2028. It plans to issue awards to contractors that will cover a 10-year period with a maximum value of $25 billion to build and modify lines.

BPA also launched its $5 billion Grid Expansion and Reinforcement Portfolio (GERP) initiative in 2023 with the aim of building 23 new transmission lines and substation projects. (See BPA Provides More Details on $5B Tx Projects.)

Siobhan Doherty, Seattle City Light’s power supply officer, said the utility is happy BPA’s GERP initiative is moving forward. But “there’s still a lot of work to do in order to make transmission available for the region,” Doherty added.

BPA paused certain planning processes in 2025 to consider how to address nearly 61 GW of transmission service requests. The agency has presented proposals to reduce the queue and has held several stakeholder meetings on the issue. (See Northwest Lawmakers Explore Building Transmission Without BPA’s Help.)

SCL has advocated for BPA to make changes in its transmission tariff to build new lines faster and to make conditional transmission available earlier in the interconnection process, Doherty noted.

“We’ve seen multiple regional studies showing a need for resource adequacy, or that the region will not be resource adequate in the next five or 10 years,” Doherty said. “Since Bonneville is the backbone of the transmission system in the Northwest, we really think they need to focus a lot on moving transmission forward quickly.”

Transmission is not the only initiative on BPA’s agenda. For example, the agency is preparing to join SPP’s Markets+ day-ahead market. BPA also recently executed long-term wholesale electric power contracts with more than 130 public utility customers and is considering revising its rates following a court order to increase spills at eight dams on the Columbia and Snake rivers. (See BPA Releases Draft Decision Solidifying Markets+ Choice and BPA Explores Rate Alternatives Following Order to Increase Dam Spills.)

Still, “transmission, transmission, transmission,” former BPA Administrator Randy Hardy said. “Transmission construction and interconnection challenges dwarf everything else.”

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Data Center Interest, Opposition on the Rise in New England

While the data center boom has yet to have a major impact on the New England grid, increased interest from data center developers is fueling concern about potential effects on energy affordability and long-term resource adequacy.

The region already faces potential supply challenges in the 2030s due to electrification-driven load growth, potential resource retirements and the struggles of building offshore wind. ISO-NE forecasts its reserve margin will decline from about 17% in 2026 to 8% in 2034.

Accurately forecasting the scale of data center development in New England is a daunting task due to the speculative nature of many interconnection inquiries and the speed-to-market sought by most developers. But multiple major utilities have reported they have gigawatts of new load under study because of a sharp uptick in interconnection requests starting in early 2024.

If the high-end outcomes for electrification and data center development materialize, New England could face a rapidly tightening balance of supply and demand. This could exacerbate energy affordability issues and threaten decarbonization efforts.

In a power system with about a 26-GW peak, the possibility of gigawatt-scale data centers means these issues could materialize quickly and with limited warning.

Forecasting Uncertainty

Prior to 2024, developers of large data centers showed very little interest in New England, in part because of the region’s high energy costs and siting limitations.

“The number literally was zero in terms of large, hyperscale data centers anywhere on Eversource’s service territory,” said Jacob Lucas, vice president of transmission planning at Eversource Energy, which owns the largest transmission footprint in New England.

Since 2024, “we’ve had anywhere between about a gigawatt-and-a-half to 7 GW simultaneously under study,” he said, noting that the total amount of demand under study can fluctuate significantly based on projects entering or dropping out of the process.

He added that “every single request we’ve ever gotten has essentially been for a 24/7/365 max load.”

The cost and duration of initial large load interconnection studies vary depending on the level of granularity sought by developers. The studies tend to last between six and 12 months and cost from $100,000 to $500,000, Lucas said. To interconnect, large loads must undergo an additional, more extensive study process, coordinated with ISO-NE, to evaluate system impacts and determine the need for interconnection upgrades.

So far, no large load projects in Eversource’s queue have reached a final interconnection agreement since interest spiked in 2024, though one recent project reached the point of negotiating a construction agreement before the developers walked away, Lucas noted.

National Grid, the third-largest transmission owner in the region, has seen a relatively steady queue of around 2.5 GW since the start of 2024. Avangrid, the region’s second-largest transmission company, declined to comment.

While New England is just starting to grapple with the potential effects of hyperscale data centers, policymakers and officials have prepared for years for load growth associated with electrification and decarbonization.

In ISO-NE’s landmark 2050 Transmission Study, published in 2023, the RTO forecast New England’s peak load to roughly double over the next 25 years, with a cost of up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

Although electrification has proceeded at a slower pace than ISO-NE projected in 2023, the RTO still forecasts substantial electrification over the long term and expects heating electrification to shift the region from a summer- to winter-peaking system in the mid-2030s.

ISO-NE is working to incorporate large loads into its 10-year demand forecast for the first time in 2026. The RTO plans to incorporate prospective large loads that are greater than 20 MW and under formal study. It proposes to derate the proposed nameplate capacity of these projects based on their stage of development and expected utilization rate.

The RTO’s 2026 draft forecast includes only about 110 MW of additional large load demand by 2035.

“Prospective large loads in New England remain limited in number and scale,” Victoria Rojo, supervisor of load forecasting for ISO-NE, noted at a February NEPOOL meeting. “Recent data collected from TOs suggests that there are a couple hundred megawatts of large loads in the formal study phase.”

But accurately predicting data center development 10 years out is extremely challenging. Just one large-scale project could dramatically change the outlook for the region, while the fate of individual projects may depend on the ebb and flow of global economics.

According to Lucas, large load projects studied by Eversource have ranged in size from about 100 to 1,000 MW. Uncertainty around which projects actually will materialize is “one of the big issues” in planning for data center development, he said.

Significantly overestimating demand could distort the market by creating a false appearance of resource adequacy issues, he said. But if a project on the higher end of the range is among the first to commit to development, ISO-NE’s estimate could be too low by a factor of five, he added.

Ultimately, ISO-NE’s introduction of large load demand into its forecast is a step in the right direction, he said, adding that the demand is “not going to be zero.”

ISO-NE has noted it has “limited visibility into detailed project information,” and data sharing “can be sensitive and is not ubiquitous across entities.”

To help address these issues, it has developed a quarterly survey for utilities to submit information on large loads, which should help the RTO “proactively characterize and incorporate large loads into the long-term load forecast.”

ISO-NE’s ongoing capacity market overhaul also may reduce some of the risk associated with forecasting uncertainty. FERC recently approved ISO-NE’s proposal to transition to a prompt capacity auction, cutting the time between auctions and commitment periods by about three years (ER26-925). (See FERC Approves ISO-NE Prompt Capacity Market.)

Prompt auctions will be held about a month before each yearlong commitment period, enabling the RTO to rely on more up-to-date information on supply and demand.

Increased demand forecasting accuracy “will be especially important when accounting for data centers and other large load proposals, which are often highly uncertain in terms of proposal attrition rates, relative construction time and electric demand characteristics,” the RTO told FERC.

But these changes would not address the fundamental issues that could occur if new demand significantly outpaces new supply in the region.

Energy Affordability

Affordability concerns have dominated energy policy discussions in New England since consumers were hit with price spikes in the winter of 2024/25. Costs remained high over the past winter, which was the most expensive winter in the history of ISO-NE’s wholesale markets. (See 2025/26 Most Expensive Winter in History of ISO-NE Markets.)

“Everybody is acutely aware that we are already in this affordability crunch,” said Noah Berman, senior policy advocate at the Acadia Center. With the potential for data center demand on the horizon, “legislators are thinking about this … and are trying to get out ahead of it.”

In PJM, the data center boom has contributed to a rapid increase in forecast demand and skyrocketing capacity prices in recent capacity auctions. (See PJM Capacity Prices Hit $329/MW-day Price Cap.) Nationally, data center demand also drove increased coal-fired generation and overall power sector emissions in 2025.

“People are seeing what’s happening in PJM … in PJM [data centers] are absolutely causing price spikes,” Berman said.

Even without new data centers, New England could face power supply issues starting in the mid-2030s.

“We are, as a region, really struggling to build new generation,” said Lucas of Eversource. “The looming issue New England has … is capacity shortage.”

Adding a few large data centers to this equation is “just going to make that worse,” he said.

To prevent negative impacts on consumers and the climate, some advocates argue regulators must require data center developers to procure enough new carbon-free generation to meet their demand.

But the data center industry has opposed these mandates. Lucas Fykes, director of energy policy at the Data Center Coalition, said data centers should not be required to bring their own supply. He stressed the importance of developing accurate demand forecasts and said it should be up to states and utilities to figure out how best to ensure resource adequacy.

Interconnecting large data centers also could require significant upgrades to the region’s transmission system. Drew Landry, Maine deputy public advocate, said the region must work to ensure data center developers are accountable for all costs of the system upgrades required to interconnect their facilities.

He said the data center boom appears to be “a bit of a gold rush situation,” with developers scrambling to advance projects which ultimately may fail. The potential for stranded projects, he said, “raises the potential for stranded costs.”

To protect against this risk, ISO-NE and utilities should collect as much money upfront as possible to fund the upgrades, he said.

Across New England, the transmission and energy supply concerns are starting to translate into legislation.

A bill (H.5175) passed by the Massachusetts House of Representatives in late February would require data centers with load larger than 20 MW to procure at least 80% renewable energy. The bill also would direct electric utilities to establish specific data center tariffs designed to “ensure that non-data center ratepayers are protected from any increased costs that result from increased electricity demand.”

In late March, the Vermont House of Representatives passed a bill (H.727) similarly creating a separate ratepayer class for data centers over 20 MW. In the siting process, data centers would have to prove to the Vermont Public Utility Commission that development “will promote the general good of the state” and will not adversely affect other ratepayers.

Democrats in Rhode Island also have introduced legislation (S.2427) to create a new retail customer class for data centers intended to protect against cost shifts.

Blowback

The data center boom also has been met with growing grassroots backlash, with opponents successfully blocking or delaying projects throughout the country. New England is no exception.

For opponents, data centers can represent a physical embodiment of unconstrained capitalism, Big Tech, inequality, environmental degradation and AI slop.

“There is a real extractive relationship between data centers and local communities,” said Dana Colihan, co-executive director of Slingshot, an environmental justice nonprofit. “These facilities are primarily benefiting wealthy corporations, not everyday folks.”

At a March meeting of the ISO-NE Consumer Liaison Group — one of the region’s few forums that convenes grassroots activists, ISO-NE officials and state and industry representatives — Vermont-based activists sent a blunt message to any data center developers eyeing the state.

“If anyone tries to build data centers here, we will drive them out,” one speaker said.

Data center opponents have scored several wins in local battles in recent months.

In Lewiston, Maine, city councilors voted to kill a data center development plan after intense local opposition.

In Wiscasset, Maine, the selectboard voted to pause early-stage discussions about the development of a data center on town-owned land amid backlash from the community.

And in Lowell, Mass., the city council passed a one-year moratorium on data center development or expansion amid the Markley Group’s efforts to expand an existing data center in a residential neighborhood. Local residents have complained about noise and air pollution from the facility and have legally challenged an air permit approval allowing Markley to add eight backup diesel generators to the facility.

Public debates over the moratorium pitted union electrical workers against environmentalists and neighbors. One city councilor compared her decision on the moratorium vote to choosing a favorite child.

“I think community engagement is often key to determining if projects move forward and move forward well, and ensuring mitigation measures are put in place,” said Anxhela Mile, staff attorney for the Conservation Law Foundation.

Data center proponents argue development is essential to maintaining U.S. economic competitiveness. They point to increased tax revenue and job creation benefiting local communities.

Data centers can bring millions of dollars in tax benefits while maintaining the “small-town feel” of rural areas, Fykes said. “Many of our members are focused on being good stewards of the community.”

A 2024 economic development law passed in Massachusetts included significant sales tax exemptions for data centers. The state finalized the tax breaks on March 27, authorizing a sales tax exemption for equipment, software, electricity use and construction costs for data center facilities.

To qualify, the law requires data centers to employ at least 100 full-time workers in the state, but the regulations do not include substantial ratepayer or environmental protections.

“If you’re going to incentivize these companies to come here, make sure you’re doing it correctly,” Mile said, noting that CLF was one of a handful of groups to voice concern about the lack of consumer and environmental protections during the legislative process.

“I think a lot of groups were caught off guard with it,” she said. “It just seemed like it just kind of slipped through.”

But the political climate has shifted since the passage of the law, with energy affordability taking precedence and local groups mobilizing against data center development. Future legislation may prove to be far more controversial.

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NRC Renews Diablo Canyon License for 20 Years

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.)

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LBNL Study Finds Power Prices Rose in 2025 Due to Multiple Factors

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.”

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Texas Offers $350M in Grants for Advanced Nuclear Projects

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 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.

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SPP Successfully Completes Western RTO Expansion

SPP has expanded its service territory into the Western Interconnection, making it the first RTO with services spanning two interconnections.

One of the more recent significant structural changes in U.S. energy markets was completed at 12 a.m. CT April 1, when the RTO began offering reliability coordination, a wholesale market and other services on schedule and without a hitch into the West. The cutover followed months of testing, simulation and joint operational coordination with dozens of participating utilities.

“We’re working closely with our utility partners, neighboring systems and others to closely monitor grid conditions,” SPP spokesperson Derek Wingfield said April 2. “So far, all indications suggest that we’ve completed a smooth transition.”

The RTO Expansion (RTOE) was led by nine load-serving utilities. They affirmed their support to proceed with the expansion with a unanimous vote of support in March. (See SPP RTO Expansion Members Affirm April 1 Go-live.)

To submit a commentary on this topic, email forum@rtoinsider.com.

The expansion extends the RTO footprint into seven states, some of which already have legacy SPP members: Arizona, Colorado, Montana, Nebraska, New Mexico, Utah and Wyoming. Arizona, Colorado and Utah increase SPP’s involvement into 17 states; it now serves a 732,000-square-mile region home to 20 million people.

SPP said 25 Western entities are now enjoying the same advantages its legacy members have enjoyed under its Integrated Marketplace since 2014, including improved reliability, lower wholesale energy costs through regional dispatch, stakeholder-driven and independent grid governance, and efficient planning that supports economic growth.

The RTO said that operating as a coordinated system will strengthen real‑time situational awareness across a wider geography and enable the region to maximize diverse generating resources, navigate weather events and other threats to grid integrity, and optimize the use and planning of the region’s transmission network.

Yes Energy says the expansion represents more than a geographic shift: It introduces new pricing nodes, additional trading opportunities and changes to how SPP’s Integrated Marketplace publishes data.

“SPP’s Western expansion is a landmark milestone for our organization, our new members and the broader energy industry,” CEO Lanny Nickell said in a statement. “This is one of many bold steps we’re taking to deliver long-term value to more consumers.”

Some of the new members expressed their appreciation and excitement in statements provided by SPP.

“This is about preparing [us] for the future,” Delta-Montrose Electric Association CEO Jack Johnston said. “The electric grid is becoming more complex, and cooperatives that are connected to larger, coordinated systems are better positioned to adapt.”

The DC ties between the Eastern and Western interconnections | NREL

Platte River Power Authority CEO Jason Frisbie said participating in a “fully organized” energy market is the most significant element of its Resource Diversification Policy.

“We recognized early on that we could not achieve the noncarbon energy future our owner communities are asking for on our own,” he said. “Joining the SPP RTO provides access to a much broader footprint of renewable resources while helping us maintain the reliability and affordability that our communities and their customers expect.”

La Plata Electric Association CEO Chris Hansen said that after having been involved in bringing an RTO to Colorado for more than 10 years, he found the moment “incredibly meaningful.” He noted that the West has operated as 37 separate grid areas, which he said has driven higher costs, lower reliability and increased emissions.

“A more integrated grid changes that,” he said. “It improves all three and is one of the most impactful steps we can take to reduce pollution and show real leadership.”

The Sierra Club also praised the RTOE, saying it supports organized markets “for their creation of more efficient and cost-effective energy markets that are better able to utilize resources like wind and solar across the grid.”

RTOs “like SPP allow states and regions to share power, increasing electric grid reliability and giving electric providers the opportunity to purchase more affordable wholesale energy on open markets,” it said in an email to RTO Insider.

“We cannot understate how momentous this moment is if utilities and independent power producers are able to take advantage of the opportunity,” policy adviser Jessi Eidbo added. “A larger system footprint means greater resilience, greater access to a diversity of low-cost renewable energy resources and significant opportunities for system efficiencies that can drive down consumer electricity costs.”

The expanded market will operate as two balancing authority areas: SPP East and SPP West. The regions will be connected by three DC ties (Miles City, Stegall and Sidney) that allow power to flow between BAAs and be optimized by SPP.

The West BAA adds several entities that participate in SPP’s Western Energy Imbalance Service (WEIS). It will provide a day-ahead market, reliability coordination and other RTO services, building upon WEIS’ real-time imbalance service. RTOE will also introduce a new reference bus and a western trading hub, enabling LMPs to form independently while being integrated into the broader SPP market.

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ERCOT Large Load Interconnection Queue Hits 410 GW

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.”

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BPA Explores Rate Alternatives Following Order to Increase Dam Spills

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.

BPA’s financial reserves policy aims to maintain sufficient financial reserves and promote long-term rate stability. (See BPA Triggers $40M Surcharge Following Low Water Years.)

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.”