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March 5, 2026

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AES Indiana to Pay $90K for NERC Violations

FERC has approved a settlement between ReliabilityFirst and AES Indiana carrying a $90,000 penalty for violations of NERC reliability standards, along with a separate settlement between SERC Reliability and the U.S. Army Corps of Engineers Savannah District that will not require any payment.

NERC submitted the settlements to FERC Jan. 29 in its monthly spreadsheet notice of penalty (NP26-4), along with a separate SNOP detailing violations of the ERO’s Critical Infrastructure Protection standards. Details of the CIP violations, including the utilities and regional entities involved, were not disclosed.

The ERO’s Jan. 29 filing also included two violations involving SERC and the USACE Mobile District but, in errata filed Feb. 18, NERC withdrew those infringements from the SNOP without providing a reason.

AES Indiana’s settlement with RF covers two violations of VAR-002-4.1 (Generator operation for maintaining network voltage schedules). Requirement R1 of the standard requires that generators connected to the electric grid be operated in automatic voltage control mode, with automatic voltage regulator in service and controlling voltage, unless exempted by the transmission operator. Requirement R3 mandates that generator operators notify transmission operators of any change in reactive capability within 30 minutes of becoming aware of it.

The utility informed RF of its violation via a self-report submitted July 26, 2022, in connection with its Eagle Valley generating station. AES reported that the plant’s two gas turbines had not operated in AVC mode between May 2020 and April 2021, when the generating plant entered a planned outage.

Upon investigation, AES found that the gas turbines’ operators had changed their exciter controls to volt-ampere reactive (VAR) mode without informing the TOP. In addition, the plant’s steam turbine generator had also operated in VAR mode from April 2018 — its date of commercial operation — to April 2021. When the plant re-entered operation, all three generators were set to AVC mode and the TOP was notified. AES Indiana conducted an extent of condition review and found no other instances of noncompliance at the Eagle Valley station or any other generating facilities.

RF attributed the root cause of the violation to ineffective training and deficient procedures. The RE wrote that the utility “did not effectively train its operators” on identifying when the voltage regulator was in AVC mode as opposed to any other control mode, or on the need to notify the TOP of any changes in a timely fashion. AES Indiana’s VAR-002 procedure was also not clear enough on the need to operate with the regulator in AVC mode at all times, RF wrote.

The RE assessed both violations as a moderate risk, observing that the incidents were isolated to the Eagle Valley station, which “is located in an area with heavily networked 345/138-kV substations and an adjacent generator plant, which reduces the likelihood of voltage swings or thermal issues.” Against this, RF pointed out that the misoperation continued for multiple years, and AES Indiana discovered the violation only after returning from a prolonged planned outage, rather than because of internal controls.

AES Indiana’s mitigating actions included retraining all Eagle Valley board operators and supervisors on the VAR-002 standard, plant procedures and voltage schedule; implementing quarterly review requirements; and installing conspicuous signage to remind operators of the correct operating mode and the need to remind TOPs of any changes.

No Penalty for USACE-Savannah

The settlement between USACE-Savannah and SERC concerned PRC-005-6 (Protection system, automatic reclosing and sudden pressure relaying maintenance), requirement R3 of which sets the minimum maintenance activities and maximum maintenance intervals by which generation owners and transmission owners must maintain their protection system components.

USACE-Savannah notified SERC in December 2023 that it had failed to complete required maintenance activities for 83 out of 215 protective relays at three generation stations within the required six-calendar-year cadence; at the time, the longest lapse was at the utility’s Thurmond station, where the maintenance should have been completed by December 2021. USACE-Savannah completed all required maintenance by March 14, 2025. An EOC review found no additional instances of noncompliance.

SERC assessed the cause of the violation as “ineffective preventive controls and insufficient workforce assigned to complete required activities.” The RE wrote that the noncompliance posed a moderate risk. No monetary penalty was assessed because USACE-Savannah is a federal government entity, and therefore immune from such penalties as determined in Southwestern Power Administration v. FERC.

To mitigate the infringement, USACE-Savannah implemented a new quarterly review system to verify adherence to the protection system testing and maintenance schedule, and it addressed the staffing issue by training new engineers to specialize in testing the facilities.

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FERC Dismisses Challenge to Eversource X-178 Asset Condition Project

FERC has dismissed a complaint from two New Hampshire residents about a $385 million asset condition project on an Eversource Energy transmission line in New Hampshire, finding that the complaint failed to demonstrate any violations by the company (EL26-27).

Despite the dismissal, FERC left the door open to future challenges of the costs of the project. The commission said it is premature to challenge cost prudency before Eversource seeks cost recovery.

The project in question is a full rebuild of a 49-mile, 115-kV line owned by the Public Service Company of New Hampshire (PSNH), a subsidiary of Eversource. The company is scheduled to begin construction in early 2027, and the estimated in-service date is mid-2029.

In Eversource’s June 2024 presentation of the project to ISO-NE stakeholders, the company said its inspections indicate 43 of the line’s 594 structures warrant immediate replacement, while additional replacements would be needed due to uplift issues caused by the new structures.

By pursuing a full rebuild of the line, Eversource has said it will avoid additional costs and environmental impacts associated with a “piecemeal replacement of failing structures.”

Consumer advocates and the New England states have voiced strong concerns about the scope and need for the project, and some advocates say it has come to epitomize broader concerns about a lack of regulatory scrutiny on asset condition projects.

In a 2024 letter to Eversource, the New England States Committee on Electricity wrote it “is not persuaded that this investment is a reasonable use of consumer dollars,” and is “prepared to use its full resources to explore all available options to dispute the reasonableness of the investments, including but not limited to action at FERC.” (See New England States Raise Alarm on Eversource Asset Condition Project.)

In November, Kris Pastoriza, an activist who has been a vocal opponent of the project, and her mother Ruth Ward, a Republican state senator in New Hampshire, asked FERC to open an investigation into the project to ensure it is necessary and the costs are prudent.

“Eversource has avoided any scrutiny of the X-178 project,” the complainants argued. “As a result, ratepayers cannot know if the transmission charges on their monthly statements are just and reasonable as required by law.”

They also took aim at ISO-NE, arguing the RTO “failed its responsibility as the New England regional grid operator to review the X-178 to ensure that any charges to ratepayers are just and reasonable.”

They have argued the rebuild should not be exempted from ISO-NE planning procedures as an asset condition project, saying it would “more than double the line capacity,” replace existing wood structures with larger steel structures, install optical ground wire and construct permanent roads.

Responding to the complaint, Eversource argued that the complaint failed “to plead any claims upon which relief can be granted” and “grossly misrepresents the level of scrutiny” on the project.

The company added that asset condition projects undergo a “robust regional stakeholder review” at the ISO-NE Planning Advisory Committee and the NEPOOL Reliability Committee.

But for consumer advocates in the region, the existing ISO-NE review process of asset condition projects — which is not a regulatory process — is far from adequate. The transmission owners already have made several changes to the process in response to these concerns, and ISO-NE is working to establish internal capabilities to review whether the TOs have justified the need for projects and adequately evaluated alternatives. (See ISO-NE Responds to Feedback on Asset Condition Reviewer Role.)

The Maine Office of the Public Advocate (OPA) opposed Eversource’s motion to dismiss the complaint. It argued that the complaint raises “ample concerns” warranting investigation by the commission into “whether the project at issue is a system expansion and, if so, whether PSNH’s planned recovery of the cost of the X-178 project as replacement costs violates the filed rate doctrine.”

In its ruling on March 2, FERC found that the complaint “does not clearly identify or explain the action or inaction by PSNH that is alleged to violate applicable statutory or regulatory requirements.”

The commission added that, “for a complaint filed under FPA Section 206, the burden of proof is on the complainant to demonstrate that the rate is unjust and unreasonable, and we find that the broad allegations raised in the complaint are not sufficient to satisfy the complainants’ burden.”

However, FERC said interested parties will have the chance to request information and challenge project costs if Eversource seeks cost recovery for the project.

“To date PSNH has not sought to recover in rates the costs associated with the project, and until the costs of the project are proposed to be included in transmission rates, any challenges to including those costs in transmission rates are premature,” FERC wrote.

Reacting to the ruling, Andrew Landry, deputy public advocate at the Maine OPA, said he’s disappointed in FERC’s decision but is glad the commission expressed an openness to future challenges.

“We continue to believe that Eversource in particular, but some other utilities to a lesser extent, are abusing the asset condition process to move forward projects that ought to have a greater degree of review,” Landry said.

Eversource, which owns about 36% of transmission by mileage in New England, has been responsible for $3.66 billion — over 78% — of asset condition spending in the region since 2020, according to data from the TOs updated in October.

Landry said he’s hopeful the negotiations around an ISO-NE internal asset condition reviewer will lead to a more meaningful review process and greater transparency, but that he has lingering concerns about the TOs’ selection of project alternatives that are reviewed by ISO-NE.

Pastoriza noted that FERC’s dismissal does not prevent future challenges but wrote the process of allowing Eversource to build the line and then challenging costs after the fact “makes no sense, given the monumental, permanent and unnecessary environmental destruction that construction (as [Eversource] does it) would do to 50 miles of easements.”

Eversource did not respond to comment requests in time for publication. ISO-NE said TOs in the region are responsible for ensuring the prudency of their asset condition investments, and the RTO’s current authority “is only to ensure that any project placed into service does not harm the reliable operation of New England’s power system.”

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Trump Gets Tech Execs to Sign ‘Ratepayer Protection Pledge’

President Donald Trump gathered seven tech leaders at the White House to sign a ratepayer protection pledge holding that they will pay all the costs associated with the boom in construction of data centers.

“We follow through on an announcement I made in my State of the Union address last week, as America’s largest tech companies officially signed the ratepayer protection pledge,” Trump said. “It’s a big deal and going to have a tremendous impact on electricity costs. We’re bringing down all of the costs.”

The event included other administration officials, including Energy Secretary Chris Wright and most members of FERC. While Wright was talking about how FERC needed to speed up its processes, Trump asked the commissioners to stand.

“Because, you know, they’re the most powerful people in the country,” Trump said as they stood. “I have had more people say, ‘Do you know FERC?’ I said, ‘Do I know FERC? What about FERC?’ And I learned so much about you, and you are the most powerful people in the country, so we want to be very nice to you. Please get us approvals. Please get us those approvals. Okay?”

The pledge was signed by senior executives from Google, Meta, Microsoft, OpenAI, Amazon Web Services, Oracle and xAI.

“Data center infrastructure is the foundation of the internet, cloud computing and artificial intelligence (AI), and supports our economic and national security,” the pledge says. “As that infrastructure grows and the related electricity demand increases, the American people should not be footing the bill for the benefit of private companies. Instead, the data center boom should be leveraged to address affordability and benefit all American households and businesses.”

Trump called on hyperscalers and AI companies to “build, bring or buy all of the energy needed for building and operating data centers, paying the full cost of their energy and infrastructure, no matter what.”

That includes paying for the full cost of power plants and any required delivery infrastructure upgrades, whether the data centers wind up using the power or not. The pledge calls on data centers to make a more resilient grid by making their backup generation resources available at times of scarcity to prevent blackouts and power shortages in their communities.

“Basically, we’re building massive amounts of electricity, and you’re not paying for it at all,” Trump said. “And the companies want to do it because … otherwise they couldn’t build. I mean, the option really was not about cost, it was about there’s no way of possibly taking the old grid and doubling it in a matter of months or years.”

Wright said that, during one of his first meetings at the White House, the president told him the country must lead in AI.

“And the old energy policies that were going on would not lead in AI,” Wright said. “We need to lead in AI. Number two, the government’s a bureaucracy. It’s always in the way of things. It’s been in the way of AI. We’ve got to run the government like a business.”

‘Durable’ Solution Needed

Electric industry trade groups said they were ready to work with the Trump administration and hyperscalers to make the pledge a reality.

“We appreciate President Trump’s focus on ensuring that our nation can drive innovation while also protecting Americans who need affordable, reliable energy,” Edison Electric Institute CEO Drew Maloney said. “Our industry has built a strong record of working with the tech community on responsible agreements that benefit local communities and help strengthen the grid for the future. We are excited for the next phase of American innovation that will support jobs, help families and drive economic growth.”

EEI also released a snapshot of publicly announced data center and other large load projects being developed with investor-owned utilities.

“America has an opportunity to lead the world in artificial intelligence and the digital economy, and that leadership will require reliable, abundant, cost-effective electricity,” Electric Power Supply Association CEO Todd Snitchler said in a statement. “Competitive power generators are ready to deliver the energy needed to power that growth while ensuring that the costs associated with new data centers and rising power demand are borne by investors and private capital, not ratepayers. EPSA is confident that the competitive generation industry will meet this pivotal moment.”

EPSA members have announced their own agreements to power data centers without shifting investment risk to consumers. They have announced also more than 12 GW of additional generation capacity in PJM, where, according to the RTO’s Independent Market Monitor, data center demand has pushed up capacity prices by $23 billion in recent auctions.

Speaking at EPSA’s Competitive Power Summit a day before the White House event, Virginia State Corporation Commissioner Kelsey Bagot said the coming announcement, and others like it from the White House on the grid, are a helpful use of the bully pulpit.

“But I think at some point, all the smart people in this room and the states and at FERC need to really be the ones to solve the problem in a way that’s durable and isn’t going to change in three, four, five years’ time,” she said.

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Wash. AG, PIOs Sue to Overturn DOE Order to Keep Centralia Plant Running

Washington’s attorney general and a coalition of public interest organizations have filed separate lawsuits to overturn the U.S. Department of Energy’s order requiring TransAlta to continue operating the state’s last coal-fired plant beyond its scheduled retirement.

Both suits were filed in the 9th Circuit Court of Appeals. They come after DOE on Dec. 16 directed TransAlta to continue running Unit 2 of the Centralia Power Plant until March 16, 2026, citing an energy “emergency” in the Pacific Northwest this winter, despite the fact that neither NERC nor WECC had identified any such emergency in their winter reliability assessments. DOE issued the order based on its emergency authority under Section 202(c) of the Federal Power Act.

The unit had been slated for closure Dec. 31 based on a 2011 Washington law and subsequent agreement between the company and the state. (See DOE Orders Retiring Wash. Coal Plant to Stay Online for Winter.)

“Trying to force Washington to restart a defunct power plant is not only illegal, but would also jeopardize public health,” Washington Attorney General Nick Brown said in statement announcing his office’s suit. “Washington state will not be bullied.”

“Our region has moved beyond reliance on coal and this plant to meet our energy needs with cleaner sources,” Patti Goldman, the Earthjustice attorney leading the suit, said in a different statement. “This illegal DOE order does the opposite of solving problems — it forces a decrepit coal plant to produce unreliable power while worsening pollution and inevitably raising energy rates for Washington residents.”

The order was one of a handful the Trump administration’s DOE issued in 2025 to extend the life of retiring fossil fuel-fired plants, including in Michigan, Pennsylvania and Colorado.

A month after the Centralia order, Brown and a coalition of environmental groups — including Earthjustice, NW Energy Coalition, Washington Conservation Action, Climate Solutions, Sierra Club and the Environmental Defense Fund — filed separate requests to rehear the 90-day order, which DOE declined. (See Wash. AG, Environmental Groups Challenge DOE’s Centralia Coal Plant Order.)

“The groups’ legal challenge asserts the Trump administration is unlawfully using Section 202(c) of the Federal Power Act, which allows DOE to order power plants to operate for short periods of time in response to imminent and unexpected shortfalls — in other words, real emergencies,” the groups said in a press release. “This DOE order exceeds that authority and instead tries to impose the administration’s preference for coal-fired power.”

The PIOs contend that “other coal plants are experiencing extremely high costs to comply with similar DOE orders,” a statement supported by the recent revelation that, in the last seven months of 2025, Consumers Energy incurred $135 million in net costs to maintain operations at J.H. Campbell coal-fired plant in Michigan, which was to retire in May 2025. (See DOE Reups Campbell Coal Plant Emergency Ops; Losses Top $135M.)

In his suit, Brown said DOE issued the order “for reasons untethered from any actual immediate or even long-range problem with the Pacific Northwest’s grid.”

He contended the order “presents no legitimate factual basis — let alone substantial evidence — to support its claim that maintaining Centralia as a coal-fired facility is necessary to ‘meet’ any emergency,” but instead undermines “the very grid stability it purports to protect in a way that will be enormously detrimental to the Northwest’s ratepayers.”

“In doing so, DOE both misreads and misrepresents the sources it cites as support for an emergency — to the point that DOE’s order can only be explained as aimed to benefit the coal industry rather than at any true ‘emergency’ in the Northwest,” Brown wrote in the suit.

The PIOs argue along the same lines in their suit, adding that “[s]tate authorities, regional entities and utilities have been carefully planning for Centralia’s retirement for over a decade, securing replacement resources and continuously tailoring plans to evolving supply and demand conditions.”

They argue also that DOE “must abide by the limitations Congress set forth in Section 202(c). This includes limitations on what the department can require even if the department substantiated its emergency claim (which it has not).”

They add that DOE’s order must be consistent with state environmental laws to the greatest extent “practicable,” minimizing “adverse environmental impacts.”

“The department does neither,” the groups wrote.

DOE did not respond to a request for comments for this article.

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California’s Anxiety is not About Seams; It’s About Control

By Nick Myers

When institutions are confident, they don’t rush out carefully framed messaging two days before a major regional symposium. They don’t suddenly rediscover the dangers of “fragmentation.” And they don’t rely on allied advocacy groups to circulate modeling that conveniently reinforces their preferred outcome.

Yet that’s exactly what California is doing.

Just days before a scheduled SPP Markets+ Seams Symposium, CAISO released a blog post warning about the dangers of new “seams” and market fragmentation. The timing was conspicuous. It was not accidental. It was strategic.

Because for the first time in years, California’s grip on Western market design is genuinely at risk. (See CAISO Unveils Principles for Western Seams Coordination.)

California Built a System that Depends on the West

California’s grid does not operate in isolation. It relies heavily on imports during evening ramping hours, leans on regional flexibility to manage renewable over-generation and depends on diversity across the West to maintain reliability at a reasonable cost.

The Western Energy Imbalance Market (WEIM) provided measurable benefits, but it also reinforced something California would prefer not to admit: Its system increasingly depends on access to resources outside its borders.

Nick Myers

As utilities and states consider anchoring their day-ahead participation in Markets+ rather than California’s Extended Day-Ahead Market (EDAM), that dependency becomes a vulnerability. If enough states choose Markets+, California’s leverage shrinks. Trade patterns shift. Institutional influence weakens. Governance becomes less California-centric.

That is what’s driving the urgency.

Seams exist everywhere. The irony of CAISO’s sudden focus on “seams” is difficult to ignore. Seams are not unique to Markets+. They exist within EDAM as well. Different balancing authorities, governance boundaries and interconnections with other markets create friction points regardless of the market that is chosen.

No market expansion eliminates seams; it simply manages them. Portraying Markets+ participation as inherently “fragmenting” the West ignores the reality that EDAM itself operates across multiple jurisdictions with inherent boundary issues. Market design always involves coordination challenges. The question is not whether seams exist. It is how they are governed and who controls the rules.

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

The Aurora Study and Strategic Modeling

At the same time CAISO is amplifying its messaging, the Environmental Defense Fund released a study conducted by Aurora Energy Research comparing regional market outcomes. The modeling emphasizes friction costs and inefficiencies associated with certain participation pathways, while reinforcing the economic case for EDAM alignment. (See APS Would See Greater Savings in EDAM, Analysis Finds.)

Modeling assumptions drive outcomes. Inputs determine results. When an advocacy organization commissions such work during active market competition, the timing is intentional.

Environmental advocacy groups understand that California’s aggressive climate policies benefit from broad regional integration under structures California influences. A smaller footprint makes renewable balancing more difficult. This reality doesn’t invalidate the study, but its ideological perspective should be taken into account.

Governance is the Real Issue

Strip away the rhetoric about seams and fragmentation, and the core issue is governance. EDAM remains rooted in California’s regulatory structure and political environment. Markets+ offers a governance model that many Western states view as more regionally balanced and less tied to one state’s policy priorities.

That distinction matters.

California has not always played well with its neighbors. During WEIM’s rollout, governance control remained tightly anchored in California. Some states participated despite, not because of, the governance structure, largely because the operational benefits outweighed its objectionable governance. Now those same states are being invited to extend deeper into California-centered day-ahead governance. Unsurprisingly, some are reconsidering.

What Happens if California Loses Control?

If California no longer anchors the dominant Western day-ahead market, consequences follow:

    • Reduced ability to shape regional market rules.
    • Less influence over transmission prioritization.
    • Greater exposure to import price volatility.
    • Diminished leverage in balancing renewable intermittency.

California’s grid strategy has quietly assumed continued regional integration under its framework. If those assumptions do not materialize, California faces difficult tradeoffs: higher costs, tighter reserve margins and reduced flexibility. That is the backdrop behind the sudden surge in messaging in support of EDAM.

Markets should compete on their merits. If EDAM offers superior economics, governance and reliability, it should win without resorting to strategically timed blog posts and new studies. If Markets+ offers stronger regional balance and autonomy, states should be free to choose it without being accused of fragmenting the West.

The West is not fracturing. It is deciding. Perhaps the clearest signal of all is this: Institutions panic only when they fear losing something they’ve come to rely on.

California’s anxiety is not really about seams. It’s about control.

Nick Myers is chair of the Arizona Corporation Commission.

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EDAM Opening Schedule on Track Despite Lingering Testing Issues

It’s an “all-hands-on-deck” moment for CAISO to open its extended day-ahead market in less than two months, CAISO’s CEO Elliot Mainzer said at a Western Energy Market Board of Governors meeting.

The EDAM is on track to open May 1 with PacifiCorp as the first participant, but the ISO needs to work through a few issues it observed during PacifiCorp testing.

“We are on the threshold of EDAM implementation, [which] reflects several years of hard focus work,” Mainzer said at the March 3 meeting. “Our partners at PacificCorp are working so hard … they are going to be the first utility to join the new market just as they were the first utility to join the Western Energy Imbalance Market back in 2014.”

PacifiCorp recently finished CAISO’s market simulation and now is in parallel operations testing, which is divided into three parts, said Khaled Abdul-Rahman, CAISO vice president and chief information and technology officer. Each part does not take an equal amount of time: CAISO moves from one part to another depending on the results in a given part.

The final part of parallel operations testing should start in mid-March and focus not only on the day-ahead market, but also on rolling results into the real-time system, Abdul-Rahman said. This final phase will be a full, end-to-end test, starting from the day-ahead market and moving into the real-time market and then watching how the system and resources and market results perform, he said.

CAISO added an extra month to PacifiCorp’s parallel testing phase, pushing it to the end of April, days before EDAM opens. Typically, parallel operations testing takes about two months, but CAISO extended it to three months “to give us more time to work on any issues that are identified,” Abdul-Rahman said.

Despite this extension, CAISO is on track. “Things are looking really promising in terms of meeting our deadlines,” Abdul-Rahman said.

CAISO is using PacifiCorp’s onboarding and testing process to “beef up our training for [future] EDAM entities,” Abdul-Rahman said. “We are identifying issues and differences … between the real-time and day-ahead markets.”

One challenge has to do with the accuracy of charge codes in the EDAM system. Software updates are required to fix these code inaccuracies, and the updates are “being tested as we speak,” Abdul-Rahman added.

System scheduling issues arose because of differences between WEIM and EDAM. In particular, the real-time market uses the concept of a base schedule, which is not in EDAM. Instead, EDAM uses economic bids and self-scheduling, which will require more training,

WEM board member Robert Kondziolka asked if CAISO experienced challenges in working with PacifiCorp, since it has two balancing authorities.

“I don’t want to say it is complicated. … It looks like one entity that we are onboarding regardless of the number of balancing areas. The volume of the data is of course bigger,” Abdul-Rahman said.

CAISO is in the market simulation phase for EDAM’s second participant, Portland General Electric (PGE), which plans to join EDAM on Oct. 1. During this phase, CAISO will test all of its system interfaces to ensure the data flows.

“It’s a little early to report on PGE’s market simulation [results]. We just started the simulation literally yesterday,” Abdul-Rahman said.

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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.