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March 4, 2026

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MISO Opens 3rd Tx Project Review as Data Center Plans Conflict with Long-range Tx Timeline

MISO has opened a third review of a long-range transmission project, this time because three substations are needed more than five years ahead of schedule to accommodate new data center load.

MISO’s third variance analysis focuses on the South Fond du Lac–Rockdale–Big Bend–Sugar Creek–Kitty Hawk Long-Range Transmission Project in southeastern Wisconsin that was approved under a $22 billion portfolio at the end of 2024.

At the beginning of 2026, MISO awarded Chicago-based Viridon Midcontinent some of the project build — 106 miles of 345-kV lines and four, 345-kV substations at $350 million, nicknamed the Wisconsin Southeast (WISE) project. (See MISO Picks AEP, Berkshire’s Joint Venture to Build $1.2B 765-kV Line.)

Now, MISO said Viridon “is unlikely to secure required regulatory approvals in time to meet the recently accelerated Dec. 1, 2027, in‑service date” for the Sheboygan River, Mullet River Junction and Cedar Creek Junction substations, part of the WISE project.

MISO originally projected the project would be in service by mid-2033.

MISO said the project is bumping up against a separate, expedited transmission project in east-central Wisconsin from American Transmission Co. designed to address anticipated data center load.

The expedited project, which ATC submitted to MISO in September 2025, relies on the trio of substations. MISO said it approved the expedited Ozaukee County Distribution Project in late February “in light of the urgency of the anticipated data center load.”

Viridon’s regulatory snags include “acquiring public utility status and receiving appropriate certification(s) required to construct the three referenced substations,” according to MISO.

Viridon was founded in 2023 and is owned by Blackstone Energy Transition Partners, one of Blackstone’s private equity funds.

“As the Sheboygan River, Mullet River Junction and Cedar Creek Junction substations are already included in the WISE competitive transmission project, Viridon maintains the responsible entity for the construction, implementation, ownership and operation of said substations,” MISO said in a late February notice for the variance analysis.

MISO included footnotes in its selected developer agreement with Viridon that timelines for the three substations were subject to change pending the outcome of ATC’s Ozaukee County Distribution Interconnection Project.

The Ozaukee project involves rebuilding and upgrading existing 345-kV lines and construction of up to five new substations at a cost of $1.36 billion to $1.64 billion. The Wisconsin Public Service Commission said it likely has until December 2026 to approve, modify or deny the project (137-CE-221).

“This process will review the likelihood of being able to meet the accelerated timeline, assess potential impacts, and determine next steps to resolve the issue,” MISO said of its variance analysis in a statement to RTO Insider.

MISO conducts variance analyses on regionally cost-shared transmission projects when they encounter schedule delays, permitting challenges, significant design changes or experience at least a 25% cost increase from original estimates. The reevaluation studies are also triggered when developers find themselves unable to complete the project or if they default on the terms of their selected developer agreement.

After completing the analysis, MISO can either let projects stand, develop a mitigation plan for them, cancel projects or assign them to different developers if possible. A committee of MISO employees selected by RTO executives make calls on how to deal with projects.

“Viridon is committed to delivering the WISE Project, including the three substations, and will meet MISO’s requirements with respect to timeline and all other requirements,” the developer said in a statement to RTO Insider.

Viridon said it “can’t speculate” on PSC actions, including why the commission is unlikely to grant approvals in the near term.

“Viridon will follow the PSC’s defined process, which will allow for completion of the substations on the timeline required,” it said.

Neither Viridon nor MISO would comment on whether there’s a possibility ATC could take over some of the substation work because of data center development.

MISO didn’t respond to RTO Insider’s question on whether it’s anticipating other instances where timelines on long-range transmission projects will need to be accelerated to meet demand for new transmission capacity to accommodate other data centers.

Viridon said it “is committed to the best outcome for all customers in Wisconsin and across MISO.”

In its selection report at the beginning of 2026, MISO said it was concerned Viridon may have underestimated the capital costs of the project in its bid. Three other bidders estimated the project would cost anywhere from $471 million to $481 million; MISO itself estimated the project would cost $662 million to complete.

However, MISO said its confidence in its selected developer was buoyed by the fact Viridon already executed an agreement with an experienced general contractor and strong cost containment measures.

MISO is conducting two other variance analyses on long-range transmission projects — for cost overruns instead of schedule and regulatory hitches. Two transmission projects in Minnesota and Illinois/Indiana have crossed MISO’s 25% overrun threshold from an original cost estimate. (See MISO Launches 2nd Review of Long-range Tx Project for Cost Overruns; Stakeholders Suggest Cost Overruns Ubiquitous as MISO Reviews Long-range Tx Project.)

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FERC’s LaCerte Clears Committee Vote on Nomination for a Full Term

The Senate Energy and Natural Resources Committee advanced FERC Commissioner David LaCerte’s nomination for a new, full five-year term by a vote of 12-8.

The vote largely was along party lines, though LaCerte did win backing from Sen. Angus King (I-Maine), who caucuses with the Democrats. That gave him a slightly larger margin than the two nominees he was paired with; Stevan Pearce for director of the Bureau of Land Management and Kyle Haustveit to be under secretary of energy both cleared the committee on 11-9 votes as King voted against them.

The March 4 votes came more than a week after the committee took testimony from the three nominees. (See: LaCerte: FERC Focused on Winning the AI Race.)

“At last week’s hearing, each of the nominees demonstrated that they’re committed to ensuring the United States can meet rising electricity demand, prepared to advance reliable, affordable energy by backing domestic production, ready to exercise disciplined regulatory judgment over transmission, wholesale markets and natural gas infrastructure,” said committee Chair Mike Lee (R-Utah).

Lee added that he looks forward to supporting each of the nominees when they are being considered by the full Senate.

Ranking Member Martin Heinrich (D-N.M.) softened his tone on LaCerte compared to his previous confirmation hearing, when he argued the nominee lacked experience in economic regulation. That has changed with on-the-job experience.

“I was encouraged by his strong commitment to ratepayer protection, affordability, reliability, resource neutrality and commission independence at his confirmation hearing,” Heinrich said. “I also acknowledge that he has faithfully served on the commission for the past five months. But as I said when I voted against Laura Swett’s nomination last fall: These are not normal times.”

The Trump administration is “creating a grid crisis,” killing union jobs, and raising electricity prices with its back-to-the-past energy policies, he added.

“Until this administration respects the will of Congress, I cannot in good conscience support its nominees,” Heinrich said.

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IESO Delays 2nd Window of LT2; Lays out Reqs for Repowered Facilities

IESO officials have delayed the second window of the grid operator’s second long-term (LT2) resource procurement to the second quarter of 2027 and postponed the required milestone commercial operation date to 2032, in response to stakeholder feedback.

In a stakeholder engagement webinar Feb. 24, officials said they agreed with the majority of stakeholders that it would make sense to delay the second window to next year, considering that awards for the first window and the Long-Lead Time procurement will be awarded this year and would affect transmission availability. (See IESO Expands Hydro Eligibility in Long Lead-Time Procurement.)

Officials also noted that Ontario municipalities will hold elections in October, which could affect certain projects obtaining the necessary municipal support resolutions.

LT2 is targeting 14 TWh/year of new energy and 1.6 GW of new capacity by the mid-2030s. The ISO’s first long-term procurement focused on resources that could be online more quickly, by mid-2028. Both award 20-year contracts, as opposed to the medium-term (MT) procurements, which award five-year contracts.

The February engagement was intended to lay out IESO’s proposed requirements for repowered facilities to participate in LT2, the most significant of which is the completion of an MT contract before beginning the 20-year term. The ISO is considering allowing MT contracts for up to 10 years, but it needs to discuss that with the provincial government. Regardless, the minimum term would be five years.

“While we don’t want to get into a technical analysis about how much useful life a facility has in it, at this point we feel everyone should have another five-year term in them,” said Dave Barreca, IESO’s supervisor of resource acquisition.

Eligibility for the MT will be based on how close a facility is to the end of its existing contract. The facility would have to demonstrate an extension of its useful life through the replacement of its generating equipment and be able to have completed both its original 20-year contract and its MT contract by May 1, 2032.

IESO would not institute technical requirements on what constitutes repowering; a facility would need only an independent engineer’s certification that it complies with the performance obligations of all LT2 resources.

Bruce Kolesnik, of Sunspring Energy Consulting, said he agreed existing facilities should have at least another five years of useful life to participate in LT2, but he questioned why they will need to complete an MT first. “That basically implies that repowering can’t participate in LT2 window 2 and presumably not LT2 window 3,” he said. “Why not just allow them to participate in LT2 for another 20-year contract? It basically still uses up their five years of useful life.”

Barreca said that based on previous MT procurements, “those five years of useful life would come at a lower rate than a new build certainly and [most likely] a repowered facility. … There is a desire to see maximal ratepayer value.” He also noted there are facilities procured in MT2, which was concluded in June 2025, that would be eligible shortly.

Repowered facilities would compete directly against new builds, despite some stakeholders arguing that they should compete against each other in a separate pool. “The IESO believes that having new builds compete with repowered facilities will result in the most cost-effective outcomes for ratepayers,” Barreca said. But he noted it is considering including a specific new build target and a cap on repowered facilities in the procurement.

Stakeholder feedback on the proposed requirements is due March 13.

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Report: GridEx VIII Highlighted Areas for Improvement

NERC’s GridEx VIII security exercise highlighted multiple areas for improvement for grid reliability, including better communication within and outside the electric industry, heightened security around drones and reduced reliance on data centers, according to the after-action report from the Electricity Information Sharing and Analysis Center.

The E-ISAC hosted the biennial exercise Nov. 18-20, 2025, and included a distributed play portion and an executive tabletop. In the distributed play, held the first two days, participants from 378 organizations worked individualized exercises based on a core scenario developed by the E-ISAC.

The tabletop, held Nov. 20, brought together leaders from 84 organizations, including industry executives, senior government officials and other “entities impacted by the scenario.”

Scenarios for the tabletop and distributed play involved a conflict between two fictional nations in which adversary “Crimsonia” invaded ally “Beryllia” and launched cyber and physical attacks against U.S. and Canadian infrastructure to delay and degrade their response.

The tabletop occurred in summer 2028 across three acts. In Act 1, Crimsonia imposed a naval and air blockade on Beryllia, while electric utilities noticed spikes in cyber probes and forced oscillations across the Eastern and Western Interconnections.

Act 2 occurred several weeks later and involved steps by Crimsonia to deter intervention by rendering GPS services “essentially unavailable,” causing power outages at “U.S. and Canadian facilities with military missions,” and attacking Microsoft identity and authentication services. Act 3 involved physical sabotage against water systems, drone attacks on a nuclear power plant and a ransomware attack on a pipeline.

The distributed play took place in 2026 against the backdrop of preparations for a global sporting event dubbed the “World Chalice.” Play comprised five moves occurring over the course of two weeks.

    • Move 0 (before play began) — Utilities suffer vandalism and theft in the lead-up to the games, while the E-ISAC reports a new strain of malware being used on electric infrastructure overseas.
    • Move 1 — A small-scale cyberattack against corporate computers distracts information technology personnel, leading to a major attack on electric and gas utilities that disrupts monitoring and control systems.
    • Move 2 ­— Large-scale attacks are carried out against multiple substations with drones and firearms. An electrician is held hostage at one facility. Additional attacks affect defense-critical infrastructure (DCI) as Crimsonia invades Beryllia.
    • Move 3 — A heat dome causes failures at multiple data centers, affecting digital infrastructure including cloud services. Adversaries cut telecommunication lines to control rooms, insider attacks occur at utilities and vendors, and utility staff receive faked messages from leadership.
    • Move 4 — Players discuss the long-term recovery efforts from the perspective of a week after the last move.

With 378 organizations participating, the distributed play portion of GridEx VIII was the biggest since GridEx V in 2019 and the third largest since the first exercise in 2011. NERC explained the attendance shifts since GridEx V — 293 organizations participated in GridEx VI and 252 in GridEx VII — as likely due to registration policy changes. Since GridEx V, only E-ISAC members and partners have been able to register for the exercise, but in GridEx VIII asset owners and operators could vouch for non-members for the first time.

Most participants were based in North America, with additional involvement from entities in Australia, Germany, Portugal and New Zealand. 63 participants were based in the footprint of SERC Reliability, more than any other regional entity and 15 more than in GridEx VII; WECC had the second-most participants at 60, four fewer than in GridEx VII when it was the leader.

Recommendations

The tabletop and executive play sessions generated a list of recommendations to improve reliability and resilience.

Recommendations from the tabletop included that U.S. and Canadian defense facilities work with industry to develop “collective understanding of the electric reliability requirements for DCI and associated risks to” defense-critical electric infrastructure. Participants also urged government entities to improve information sharing with industry and promote laws like the Cybersecurity Information Sharing Act of 2015 and programs like the E-ISAC’s Cybersecurity Risk Information Sharing Program.

The drone-related incidents prompted a recommendation that the U.S. and Canadian governments work with industry on responses to drone threats and “clarify available government support.” Participants also suggested that industry and government discuss how to shield utilities from liability for following government directives affecting their operations or energy and resource allocation.

Distributed play participants urged that industry continue to coordinate with government and emergency management partners on exercise and response planning, and encouraged entities to continue testing their various communication methods for potential failure modes. Contributors also suggested that entities practice their internal coordination and communication along with strengthening their external relationships.

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Ontario PMU Expansion Raises Cost Concerns

IESO’s plan to require synchrophasor data from storage resources prompted cost concerns during an educational session at the ISO’s Technical Panel meeting March 3.

IESO announced in 2025 it will require phasor measurement units (PMUs) at all grid-connected storage units rated at least 20 MVA, including aggregations. PMUs, which collect data including voltage, current and frequency, already are required for generators of 100 MVA and larger. The new requirement also would apply to any size storage or generation facility that can impact a NERC interconnection reliability operating limit.

As part of the changes, the ISO will move its PMU requirements to the market rules from the market manual, and the minimum reporting rate will increase from 30 to 60 samples/second.

IESO’s supervisory control and data acquisition (SCADA) system, which collects data from grid-connected facilities every two to 10 seconds, cannot provide real-time monitoring for the “oscillation phenomena” that can be caused by the growing number of inverter-based storage facilities.

“Going to 60 samples a second allows us to be able to see any oscillations that might occur between zero to 15 hertz in the field,” said Dame Jankuloski, lead power system engineer in IESO’s Performance Validation and Modeling unit. “We’re just trying to be a little bit proactive here and go with a higher sampling rate because that’s what other jurisdictions in North America have done.”

IESO, which currently has 86 PMUs at 36 facilities, expects that to increase to 240 PMUs at 111 facilities in the next five years.

Jankuloski said written comments submitted following an engagement session in December “raised no material concerns” with the new requirements. (See IESO Seeks Comment on Revised Monitoring Requirements.)

But stakeholders expressed concern over costs during Jankuloski’s presentation.

“I don’t have any idea what the [cost] is here. … Is it a million bucks or is it 100 million?” asked Dave Forsyth of AMPCO, which represents industrial power users. “Who’s going to pay for this and how much [is it] going to cost? And are we asking for a Rolls Royce when we only need a Chevy?”

Robert Reinmuller, of transmission and distribution utility Hydro One, said most of the PMUs in IESO’s system today were installed by his company. Many of the future installations will be for facilities that win upcoming IESO procurements, he said.

He said the utility will file rate requests for 2028 to 2032 within a couple of months. “And if I don’t have, say 150 PMUs accounted for … for this change that you’re proposing, we’re going to have a hard time finding that money after the fact,” he said.

Reinmuller said Hydro One spent tens of millions of dollars installing the existing PMUs. “The PMU itself is not an expensive device. … But the infrastructure to collect the data … behind the scenes is not trivial.”

Jankuloski acknowledged that doubling the sampling from 30 to 60 readings/second will require more data storage capacity but said Hydro One officials had not expressed “any major concerns” in their discussions with the ISO.

IESO sized its system to handle 60 samples/second for up to 400 PMUs, he said.

“So, we left a little bit of spare [room],” he said. “Right now, we are sort of at the half[way] point in terms of requirements that we have proposed to date.”

Jankuloski said “it is a bit of a challenge to put a [cost] number” on the new requirements. “But from a reliability perspective, we don’t want an outage, right? And so, if an oscillation were to cause an outage [without] having this data, we would not be able to first prevent it, or even just see it and see what kind of actions we need to take.”

The Technical Panel is expected to vote on recommending the changes at its May 12 meeting, teeing up an IESO board vote on June 11. The tentative effective date is Dec. 2.

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Data Centers Don’t Cause Rate Increases but Would Still be Wise to Supply Own Power

By Kristen Walker

In a notable move at the State of the Union, President Trump announced, “We’re telling the major tech companies that they have the obligation to provide for their own power needs.”

Several Big Tech players incidentally will meet at the White House this week to sign an agreement to build their own electricity supply. Data centers have become the whipping boy of high electric bills; consumers believe they are paying higher rates because of these power-hungry server farms.

However, it is not that simple. Plenty of other variables factor into electricity rates, making it difficult to point the finger directly at data centers. If anything, data suggests otherwise.

Take Virginia and Texas, which lead the pack and together account for one-fourth of all U.S. data centers, at 663 and 405, respectively. According to the U.S. Energy Information Agency, the average residential electricity rate in Virginia is 15.94 cents/kilowatt hour (kWh) and Texas is 16.04 cents, both of which are below the national average of 17.24 cents/kWh.

Kristen Walker

Loudoun County, Va., — considered the Mecca of data centers — has experienced a modest rate increase recently, but Dominion Energy asserts the cost is “largely attributed to inflationary pressure, not the demand of data centers.” Labor, equipment and materials prices have increased. The county’s 14.25 cents/kWh is still well below the national average.

On the flip side, California’s average 34.71 cents/kWh consistently ranks as the highest electricity prices in the continental U.S. Their number of data centers is roughly half of Virginia’s: 320.

Most Northeast states also consistently rank in the top 10 for electricity rates. Yet their data center counts pale in comparison to the top dogs: Connecticut (61), Maine (eight), Massachusetts (49), New Hampshire (10), New York (142), Rhode Island (seven) and Vermont (three).

Why do all these states suffer not only from soaring electricity costs but rates that have increased much faster than the national average?

State Policies Contribute to Higher Prices

State policies and decisions have much more to do with electricity prices than simply load growth. Most states referenced above have ambitious standards that eventually require 100% power generation from renewable energy. The Northeast states participate in the Regional Greenhouse Gas Initiative, which regulates energy sources, as well as have policymakers who block natural gas pipeline infrastructure. These actions contribute to higher electricity prices for consumers.

The math doesn’t exactly compute for a correlation between data centers and electricity prices. So far.

A Virginia state-commissioned report that found residential ratepayers were not subsidizing costs for larger users also says that scenario could change unless mitigated. It asserts that significant new generation and transmissions will need to be built, energy demand will outpace supply and heavier reliance on imported power is susceptible to spikes in energy market prices.

But all that remains to be seen, especially in the other 49 states. After all, Virginia is home to an impressive 663 data centers (and counting) and has yet to experience rate increases because of them.

It does not, however, negate the reality that communities continue to worry about paying for data centers’ energy use. Data center operators no doubt hope to mitigate some of the public’s concerns by building off-grid.

As more state legislation designed to pause, slow or deter data center construction increasingly materializes throughout the country, Big Tech must proactively secure sufficient power for these warehouses. Moratoriums and delays would be a death sentence for the AI race. And it is unfair to sideline the industry. Needing to get on-line sooner rather than later, data centers don’t have time for politics or the ever-growing interconnection queues.

Many hyperscalers are past waiting; they’ve already begun producing their own electricity.

Operators Seeking Alternative Energy Supply

Operators increasingly are using natural gas, solar, batteries and fuel cells to supply their power, with the latter constituting the fastest‑growing off‑grid option. The 90-day installation and nearly 100% reliability are enticing one in three data centers to go off-grid by 2030.

Modular natural‑gas turbines and reciprocating engines also are growing in popularity. Resembling small power plants collocated with the data center, these systems can be deployed within weeks or months.

Multiple Big Tech companies even announced plans to go nuclear, through either revitalizing nuclear plants or incorporating small modular reactors.

With today’s political climate, regulatory barriers, time constraints and affordability concerns, in-house energy generation makes sense. Data centers are embracing self‑generation as a core part of their expansion strategy. They are now actively building off‑grid and self‑powered data centers, signing federal pledges to do so and investing in dedicated generation at a scale that resembles private power grids.

The combination of AI‑driven load growth, interconnection delays and political pressure is making self‑supply the new default model for hyperscale expansion. It is a win for tech companies, utilities, politicians and consumers.

Kristen Walker is senior policy analyst and manager for energy and transportation with the American Consumer Institute, a nonprofit education and research organization.

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BlackRock and Others to Take AES Corp. Private for $33B

A consortium led by BlackRock’s Global Infrastructure Partners and Swedish private equity firm EQT AB agreed to buy AES Corp. in a deal valued at about $33.4 billion including debt.

AES said it expects its sale to private equity to close in late 2026 or early 2027. The company said its Indiana and Ohio utilities would remain locally operated and managed. Together, AES Indiana and AES Ohio serve about 1.1 million customers.

If approved by regulators, the ​consortium would acquire AES for $15/share in cash, representing a total equity value of $10.7 billion.

The investment group also includes California Public Employees’ Retirement System ⁠and ​the Qatar Investment Authority.

At the end of 2025, AES had $27.56 billion in net debt. Without the sale, AES said it would have been forced to reduce or eliminate dividend payments or make considerable ​new equity issuances.

AES said it has a “significant need for capital” beyond 2027 to meet demand growth. The company’s board of directors unanimously approved the transaction.

“This transaction will better position AES to drive long-term growth across its business units, including regulated electric utilities and competitive clean energy in the U.S. and critical energy infrastructure assets in Latin America. The consortium has deep experience investing in energy infrastructure businesses and shares AES’ commitment to safety, affordability and customer service,” AES said in a March 2 announcement.

AES said through the acquisition, it will become a “premier clean energy platform across the Americas.” It said it has 11.8 GW of clean energy supply agreements in place with major technology firms.

The company reported that as of late 2024, it has a little more than 32 GW of total gross capacity in operation; 64% of that renewable energy.

The deal continues a pattern of BlackRock and other asset managers expanding their reach into public utilities.

Global Infrastructure Partners, along with the Canada Pension Plan Investment Board, took Allete and Minnesota Power private for $6.2 billion in 2025. (See Minnesota PUC Approves BlackRock’s Purchase of Allete.)

The purchase agreement comes as AES Indiana and other Indiana utilities face a regulatory inquiry into energy affordability after raising their rates. (See Indiana Commission Opens Affordability Inquiry into Utilities.)

AES Board or Directors Chair Jay Morse said the decision followed a “rigorous review” of options. He said the sale is in the best interest of AES stockholders.

CEO Andrés Gluski also said the acquisition would “maximize value for existing stockholders and position the company for long-term success.”

AES cancelled a March 3 conference call to review its fourth quarter and 2025 financial results. Over 2024, AES reported $12.28 billion in total revenue, a roughly 3% decline from 2023.

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Company Briefs

Form Energy, Xcel Strike Deal to Power Google Data Center

Form Energy has reached a deal with Xcel Energy to build an iron-air battery storage plant in Minnesota that will supply a Google data center.

Xcel will install 300 MW of Form’s batteries, which will dispatch energy for up to 100 straight hours, in Pine Island, Minn. The facility is part of a larger agreement that will see Google pay Xcel to build 1.4 GW of wind and 200 MW of solar.

Form Energy expects to deliver the batteries to Xcel in 2028.

More: Canary Media

Plug Power Kills Plans for Hydrogen Plant

Plug Power has officially abandoned its plans for a hydrogen plant in Genesee County, N.Y.

Instead, Plug Power will sell its property at the STAMP site to developer Stream Data Centers for between $132.5 million and $142 million. Stream Data Centers is looking to build an $11.81 billion, 2.2 million-square-foot data center campus across three buildings at the site.

According to the agreement, the sale must close no later than June 30.

More: Buffalo Business First

Arevon COO Johnson Named Interim CEO

U.S. renewable energy developer and operator Arevon Energy appointed COO Justin Johnson as interim CEO, effective Feb. 20.

Johnson will continue to serve as COO while assuming the additional responsibilities of interim CEO, the company said. Former CEO Kevin Smith resigned Feb. 20.

More: Renewables Now

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Federal Briefs

EIA: U.S. Plans 11 GW of Retirements in 2026

Power plant owners plan to retire 11 GW of utility-scale generation in 2026, most of it from coal plants, according to the EIA’s Preliminary Monthly Electric Generator Inventory.

Most of the scheduled retirements are either coal-fired plants (58%) or steam turbines and simple-cycle natural gas (42%). The largest planned coal retirements planned are the 1,331-MW J.H. Campbell in Michigan and the 1,231-MW Cumberland Unit 2 in Tennessee.

Plans are subject to change due to recent policy shifts delaying retirements. Owners and operators planned to retire 12.3 GW of capacity in 2025 but retired only 4.6 GW following emergency orders from DOE to extend the operations of several coal plants.

More: EIA

U.S. Sets Tariffs on Asian Solar Imports

The Commerce Department announced tariffs on solar cells and panels imported by companies in India, Indonesia and Laos.

According to the department, it calculated rates of 125.87% on imports from India, 104.38% on imports from Indonesia and 80.67% on imports from Laos. The three nations accounted for $4.5 billion in imports in 2025, about two-thirds of the overall total, according to government trade data.

More: Reuters

BLM Approves Silver Peak Lithium Mine Expansion

The Bureau of Land Management approved expansion of the Silver Peak lithium mine in Nevada. The mine is now authorized to operate on 8,058 total acres, including 1,601 public acres.

The expansion allows for the use of new technologies that are expected to increase lithium recovery by up to 100% from the same amount of materials.

The mine has been in operation since 1965 and is currently the only producing lithium mine in the U.S.

More: BLM.gov

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State Briefs

CALIFORNIA

Diablo Canyon Receives Discharge Permits

The Central Coast Regional Water Board voted 6-0 to approve waste discharge permits for the Diablo Canyon nuclear plant.

The board also granted the plant a certification under the Clean Water Act, which was the last state regulatory hurdle the facility needed to clear before the Nuclear Regulatory Commission could renew its permit through 2045.

Pacific Gas and Electric originally planned to shut down the plant in 2025, but lawmakers extended the deadline by five years in 2022. Now it is likely to run through 2030.

More: Los Angeles Times

IOWA

House Approves Bill Preventing GHG Agricultural Lawsuits

The House of Representatives voted 66-24 to prohibit lawsuits stemming from greenhouse gas emissions linked to agricultural operations.

The bill would limit farmers’ and ranchers’ liability in cases alleging an “actual or potential” effect on the climate caused by greenhouse emissions. The House also adopted an amendment that added “petroleum source” to the list of greenhouse emissions described in the bill. 

The bill now heads to the Senate.

More: Iowa Capital Dispatch

LOUISIANA

PSC Rejects Investigation into Meta’s Data Center Financing

The Public Service Commission rejected a request from environmental and consumer advocacy groups to investigate Meta’s financing of a data center in Richland Parish.

Meta’s new financial arrangement has left a separate company, Blue Owl, as the majority owner of the data center. As a result of the new structure, the nonprofits argued, various ratepayer protections guaranteed by Meta are now called into question.

The PSC noted it can investigate in the future if new information arises.

More: Nola.com

MICHIGAN

DTE to Pay $100M for Clean Air Violations

District Judge Gershwin Drain ordered DTE Energy and three of its subsidiaries to pay $100 million to the Treasury Department for Clean Air Act violations at the EES Coke Battery on Zug Island.

The facility must come into compliance with the Clean Air Act by submitting new source review permit applications within 250 days, and form a community committee within 120 days and provide it with $20 million for air quality improvement programs. The court also found that DTE saved $70 million by failing to comply with regulation.

DTE said it plans to appeal the decision.

More: Planet Detroit

NEVADA

NV Energy to Refund $63M to Overcharged Customers

NV Energy will reimburse more than 108,000 customers about $63 million following a settlement with the Public Utilities Commission.

Over the past 20 years, NV Energy accidentally misclassified nearly 43,000 multifamily residential customers as single-family residential customers, which overcharged them. The overcharges total around $65 million and date back as far as 2002. The utility must issue refunds within 210 days with all money coming from shareholders.

More: The Nevada Independent

NORTH CAROLINA

UC Mistake Won’t Equal Refunds for Customers

The North Carolina Court of Appeals determined the Utilities Commission made a mistake in 2024 when it allowed Duke Energy to raise rates based on unrecovered fuel costs from 2022. However, a change in state law in 2025 means customers will not see any refunds based on the error.

The court agreed the commission should not have allowed Duke to pursue the unrecovered costs when rates were set two years later. While the case proceeded through the courts, the General Assembly approved a new law in June 2025 that removed a provision limiting fuel recovery costs to a designated “test period.”

More: The Carolina Journal

OREGON

Jury Awards Victims $305M for Santiam Canyon Wildfire

A jury awarded $305 million to 16 survivors of the Santiam Canyon wildfire that burned hundreds of thousands of acres in 2020.

It is the largest jury verdict issued in relation to the James v. PacifiCorp class-action lawsuit, pushing PacifiCorp’s total liability past $1 billion. It is the 15th trial to conclude so far, with another 167 trials scheduled through 2027.

PacifiCorp has appealed the class-action lawsuit. Executives continue to deny liability and point to a 2025 state report that found no evidence connecting PacifiCorp’s equipment to the fire.

More: Oregon Public Broadcasting

TEXAS

Xcel to Replace High-risk Power Poles After Settlement

A district court ordered Xcel Energy to replace damaged power poles in wildfire-prone areas following an agreement with Attorney General Ken Paxton.

Xcel is required to replace all poles with severe structural deterioration located in high wildfire risk areas within 14 days. It also is required to conduct inspections of its infrastructure in high-risk areas and inspect at least 35,000 poles annually. The company must notify the state once replacements are completed.

Paxton called the development the first step toward holding Xcel accountable for the 2024 Smokehouse Creek fire that burned through a million acres of the Panhandle.

More: The Texas Tribune

VIRGINIA

Data Center with Gas Plant Planned for Wise County

Officials released plans for a data center complex in Wise County that would be supported by an on-site natural gas plant.

The Wise Innovation Hub would be built in phases over 10 years at the Lonesome Pine Regional Business and Technology Park. Red Post Energy would design the natural gas plant.

The complex’s first 100 MW of gas generation could come online in about three years and eventually scale up to 500 or 600 MW, Red Post CEO Lance Medlin said.

More: Cardinal News

WEST VIRGINIA

Real Estate Firm to Invest $4B in New Data Center Development

Gov. Patrick Morrisey announced a new “high-impact intelligence center” that is expected to be built in Berkeley County.

Real estate investment and development firm Penzance Management will make a $4 billion investment in the project, which will connect to the grid and is expected to produce 600 MW of “critical IT capacity.” No other information was released.

More: West Virginia Watch