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January 8, 2025

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In Letter to Senators, BPA Tempers Markets+ Leaning

The Bonneville Power Administration tamped down expectations that it is all in on SPP’s Markets+, clarifying in a recent letter to lawmakers representing Oregon and Washington that it’s still weighing the pros and cons of joining a day-ahead market.

In a Dec. 31 letter publicly released by the agency Jan. 7, BPA Administrator John Hairston said it’s possible in the short term that BPA will not join a day-ahead market and “continue to market surplus power and make short-term purchases through bilateral trading and optimize real-time activity in [CAISO’s Western Energy Imbalance Market].”

“In the long term, we are concerned, however, that most of our potential trading partners will be in a day-ahead market themselves and create challenges in relying on a bilateral market,” Hairston added. “We will continue to evaluate the development of Western electric markets to assess the potential costs and benefits of participation.”

Hairston also reiterated that BPA would join a day-ahead market only if the market’s framework is compatible with the agency’s statutory obligations and other commitments, including environmental, reliability and affordability.

Hairston’s comments came after Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) urged in a Dec.13 letter that the federal power marketing administration carefully weigh its choice between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

Markets+ and EDAM are vying for participants as they develop their market frameworks, with BPA leaning toward Markets+. Agency staff have recommended that BPA join Markets+, citing the market’s governance framework, which BPA believes provides greater independence from California state influence compared with the EDAM option.

However, the senators contended that the agency has failed to make a business case for Markets+, citing a BPA-commissioned study by consulting firm Environmental and Energy Economics.

That study, which relied on production cost analyses, found BPA would realize the most significant net economic benefits — $251 million in 2026 declining to $147 million in 2035 — in a “Westwide Market” scenario that includes California.

In his most recent letter, Hairston echoed arguments he’s made in correspondence with Seattle City Light, telling senators the study’s results “should be viewed with some skepticism” as the Western Interconnection likely will have two day-ahead markets, given that entities have signed agreements in favor of both Markets+ and EDAM.

Hairston added that numerous other elements not captured in production cost analyses can have an economic impact on expected benefits, such as governance structure, resource adequacy requirements, greenhouse gas accounting, fast-start pricing and scarcity pricing.

The Northwest region’s EDAM supporters also have criticized BPA’s apparent willingness to dole out $25 million to fund the Phase 2 implementation activities for Markets+ while declining to contribute $25,000 to the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets.

According to the senators’ letter, SPP has said the $25 million commitment is “essentially a market decision.” Hairston rebuffed this assertion in his most recent letter, saying “Phase 2 funding is not a commitment to joining Markets+; it is a commitment to continue funding development of the market.”

Similarly, he stated that BPA is, in fact, providing $25,000 to fund the Pathways Initiative but declined to make a public commitment before ensuring that the funding is “compatible with a different, much larger grant from the U.S. Department of Energy.”

Still, EDAM’s independence hinges on support from the California Legislature. Hairston noted, “It will be important to see if the Legislature will approve a full scope of independence.”

BPA will release a draft policy letter in March 2025 that will provide greater clarification on the agency’s final decision, according to the letter.

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NERC Submits Energy Assurance Standards to FERC

NERC has submitted two new reliability standards for FERC approval, both aimed at addressing the risks arising when energy resources with inconsistent output are unable to meet the demands of the grid and maintain reliability. 

The ERO filed BAL-007-1 (Energy reliability assessments) and TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) on Jan. 6, asking that the commission approve both standards, along with proposed definitions for the terms “energy reliability assessment” (ERA) and “near-term ERA.” If approved, the definitions will be added to NERC’s Glossary of Terms. 

NERC’s Board of Trustees approved the standards, their implementation plans and the definitions at its most recent open meeting Dec. 10, along with several other proposed standards. (See “Standards Approved for FERC Submission,” NERC Board of Trustees Briefs: Dec. 10, 2024.) 

BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources) and received segment-weighted approval votes of 81.53% and 92.77%, respectively, in a formal ballot round that ended Nov. 4. (See “Approved Standard to be Updated,” NERC Standards Committee Briefs: Nov. 13, 2024.) 

NERC began the project in response to the grid’s ongoing transition from traditional inertial generation resources to weather-dependent resources like solar and wind. The ERO said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources, which may suffer inconsistent output associated with the weather and volatility in load. 

It called BAL-007-1 “a step in transitioning to energy-based planning methods in the operations planning time horizon [by helping] achieve a level of consistency across the industry” in terms of planning methods and strategies. The standard would require BAs to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. 

Near-term ERAs required by the standard must include assessments of the resources necessary to serve demand while also providing operating reserves for the grid. An assessment period would begin no more than two days after the operating day, and cover between five days and six weeks. 

BAs would be able to specify the frequency of their ERAs. By default, all time periods must be covered, so that, for example, a near-term ERA that covers two weeks may be performed every two weeks or every other week, but not every three weeks, because this would leave a gap in coverage. This requirement may be waived if the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low. 

A BA could perform the near-term ERA for its work area alone or jointly with other BAs for all their areas together. NERC said this arrangement was meant to mirror partnerships that already exist between BAs for “other operations or planning activities and real-time operations.” 

The standard also lists minimum elements that BAs must include in near-term ERAs: 

    • forecast or assumed demand profiles; 
    • resource capabilities and operational limitations (including fuel supply); 
    • energy transfers with other BAs; and 
    • known grid transmission constraints that limit the ability of generation to deliver their output to load. 

The proposed changes in TPL-003-7 are relatively minor. NERC said they will “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.” 

As set forth in the proposed implementation plan, the ERO asked that FERC make TOP-003-7 effective the first day of the first calendar quarter that is 18 calendar months after the effective date of its order approving the standard, with BAL-007-1 to take effect six months later. This arrangement would provide six months for entities to collect the data needed for near-term ERAs and provide it to BAs before they are required to perform the assessments. 

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Delaware, US Wind Finalize $100M+ in Community Benefits

Delaware has finalized a benefit agreement with US Wind for allowing the developer to use a state park to run export cables from the offshore wind farms it hopes to build.

State officials announced Jan. 6 that the deal will be worth more than $128 million to the state and its residents over more than 20 years.

US Wind received key federal approvals in late 2024 for construction and operation of up to 2.2 GW of wind power generation capacity in three phases.

The developer has secured offshore renewable energy certificates from the state of Maryland for the first two phases, known as MarWin and Momentum Wind, rated at 1.1 GW combined.

US Wind’s 80,000-acre lease area sits at the latitude of northern Maryland, but the plan is to run the export cables farther north, to southern Delaware. US Wind wants to route them beneath a parking lot at the Delaware Seashore State Park, then under the Indian River Bay on their way to Delmarva Power and Light’s Indian River Substation in Dagsboro, Del.

The developer announced Dec. 10 that the state had approved three key permits to do this.

The Jan. 6 announcement by the state Department of Natural Resources and Environmental Control (DNREC) centered on compensation to Delaware for allowing it. The agreements include:

    • 150,000 renewable energy credits per year — estimated lifetime value of $76 million — transferred from US Wind to Delaware utilities to help them meet clean energy requirements, thereby lowering customer costs.
    • $40 million from US Wind over 20 years for coastal waterway dredging, clean energy workforce training, scholarships and resiliency and capital projects at state parks.
    • $12 million-plus in 25 years of lease payments to Delaware State Parks for the underground cables.

DNREC said indirect benefits to the state and its people over 20 years include up to $253 million in reduced electric costs for consumers and more than $200 million in transmission system upgrades.

Maryland is an enthusiastic supporter of offshore wind and has set an 8.5-GW goal for itself. But it has encountered the same headwinds as other states in trying to meet that goal. Ørsted has placed its Skipjack Wind plan on indefinite hold amid challenging economics, and Maryland has allowed US Wind to seek higher compensation so it does not succumb to those economic challenges.

There also is the inauguration in two weeks of a president who has been openly hostile to offshore wind development, which may complicate or delay development of MarWin and Momentum. Donald Trump doubled down on his campaign trail rhetoric Jan. 7, telling reporters he wants zero wind turbines erected during his administration.

Closer to home, there is some popular opposition to wind development off the Delmarva shoreline.

Local media have reported that Sussex County denied a US Wind subsidiary the permit it needs to build a substation, that Ocean City is suing to reverse federal approval of the project, and that opponents have appealed DNREC’s approval of the export line’s placement.

But Delaware focused on the positive in its Jan. 6 announcement. DNREC Secretary Shawn M. Garvin said in the news release:

“The DNREC State Energy Office’s recently released State Energy Plan emphasizes the need for offshore wind development in order to reach our emissions reduction goals, and the need to consider partnerships with other states and wind project developers to reduce costs. Additionally, the funding for dredging, resiliency and parks projects and workforce training will provide needed resources to protect and preserve Delaware’s natural resources for decades to come.”

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DC Circuit Rejects Challenge to FERC Approval of Indiana Pipeline

A three-judge panel of the D.C. Circuit Court of Appeals issued a decision Jan. 7 that sided with FERC in an appeal of the agency’s decision approving a natural gas pipeline in Indiana. 

The pipeline was proposed to serve new natural gas units the state had approved to replace a retiring coal plant. Citizens Action Coalition of Indiana argued that FERC failed to analyze non-gas alternatives before approving the pipeline. 

“We disagree,” the court said. “Congress gave FERC authority to promote the development of interstate natural gas pipelines, but it left the choice of energy generation to the states. The purpose of the pipeline was to support Indiana’s energy plan, and FERC has no statutory authority to consider non-gas alternatives already rejected by the state.” 

The win by FERC follows losses on other pipeline cases at the D.C. Circuit, including a New Jersey one in which the commission approved new pipeline capacity that the state opposed on the grounds that it clashed with its climate policies. (See DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections.) 

The Natural Gas Act requires FERC to approve a pipeline if it determines the project is “required by the present or future public convenience and necessity.” It also can approve a project when its public benefits outweigh its adverse impacts. 

Indiana regulators in 2017 approved CenterPoint Energy’s integrated resource plan, which included a proposal to replace coal generators at its A.B. Brown Generating Station with solar and natural gas facilities. The utility initially wanted an 850-MW gas-fired unit, but state regulators rejected that plan and approved two smaller gas turbines that together produce 460 MW. 

“That brings us to the pipeline at issue here,” the D.C. Circuit decision said. “CenterPoint contracted with Texas Gas Transmission to supply natural gas to the planned units. Texas Gas then applied to FERC for approval of a 24-mile pipeline crossing the Ohio River and connecting the A.B. Brown site to an existing pipeline system in Kentucky.” 

FERC approved the pipeline after performing an environmental impact statement. Citizens Action filed for rehearing on the grounds the commission failed to consider alternatives to the gas units, failed to determine the impact of emissions, was wrong to net the drop in emissions from replacing coal with gas, and failed to properly balance environmental impacts with its public convenience and necessity determination.

The National Environmental Policy Act does not require FERC to consider non-gas alternatives that are outside its jurisdiction and would fail to serve the purpose of the project. 

“The project seeking certification from FERC is not the natural gas units, but the pipeline serving those units,” the court said. “Before Texas Gas applied for a certificate, CenterPoint and the Indiana commission had already determined that the public interest would be best served by the construction of natural gas units that ensure grid reliability and support the move to wind and solar generation.”  

FERC rejected Citizens Action’s request that the project be defined as promoting solar and wind, saying detailed evaluations of other power generation alternatives are separate questions from the pipeline proceeding. 

“More to the point, FERC could not lawfully define the project’s purpose as broadly as Citizens Action requests because Congress has not authorized FERC to choose between electricity generation resources,” the court said. “The NGA empowers FERC to approve new gas pipelines. It does not permit FERC to regulate the energy generation facilities those pipelines supply.” 

States have the authority to choose their preferred mix of generation, leaving the CenterPoint turbines outside of FERC’s jurisdiction, the court found. 

FERC did assess whether the gas turbines could be served adequately by existing pipelines and looked into alternative routes, which the court said showed it “adequately considered alternatives.” 

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Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO

FERC authorized another hefty penalty concerning demand response violations in the MISO capacity market, this time approving an $18 million settlement over Voltus reportedly falsifying registrations and overstating capacity from 2017 to 2021.

Voltus — the first retail customer aggregator to participate in MISO capacity auctions — and FERC finalized a settlement Jan. 6 that has Voltus paying a $10.9 million civil penalty and reimbursing $7.1 million in profits to settle allegations that the company manipulated MISO’s demand response market (IN21-10). The settlement also directs Voltus co-founder and former CEO Gregg Dixon to pay a $1 million fine and step down from the Voltus Board of Directors.

Additionally, Voltus must file annual compliance monitoring reports to FERC enforcement staff for two years, with the potential for another two years of monitoring reports beyond that.

Voltus announced in early 2024 that Dixon stepped down as CEO but would remain on the company’s board of directors.

FERC’s Office of Enforcement concluded Voltus inappropriately gained access to customer data and used it to deceptively register load-modifying resources over four MISO capacity auctions. It said both Voltus and Dixon cooperated with its investigation, which began in 2021.

FERC staff said under Dixon’s direction, Voltus employees registered Ameren Illinois ratepayers as load-modifying resources without their knowledge or consent. Employees used Ameren account numbers on the utility’s website to download data required by MISO to register them.

Dixon reportedly learned from an employee sometime before MISO’s 2017/18 capacity auction that non-public data on Ameren’s customers could be obtained by registering as an Ameren business partner and then entering customer account numbers on its website.

According to Dixon, Ameren had “advanced metering infrastructure and meter data available” that enabled Voltus to “measure performance for dispatches of demand response without having to install our technology.”

Voltus in late 2016 rolled out what it called “Operation Violet” with a goal of selling 200 MW of demand reduction in MISO’s Zone 4 in southern Illinois. Voltus in some cases requested copies of Ameren customers’ utility bills to conduct analyses of what they could earn by participating in DR, FERC said, and noted that the bills contained account numbers.

For legitimate customers who entered Voltus’ aggregation program, FERC staff said Voltus employees — again at Dixon’s direction — would inflate on paper the levels of curtailment that the customers agreed to provide. FERC said Voltus employees registered some resources as if they would completely shut down if called upon without regard to whether that was possible or whether resources had agreed to it in their contracts.

According to FERC, a third-party contractor Voltus hired to help manage demand response registrations reportedly became uncomfortable over the possibility for fines and the “reputational risk for Voltus” and resigned in early 2017.

‘Scranta’

By summer 2017, Voltus had designed a computer program named “Scranta” based on a portmanteau of “scrape” and “Santa,” which scraped data from Ameren by submitting “tens of millions” of potential account numbers to the website. When the program landed on a genuine account number, it would collect customer data for a Voltus database.

When Voltus found accounts with peak demand above 50 kW, those accounts were added to an automated email distributed to Voltus leadership and a sales team to either become leads or involuntary participants in Voltus’ demand response program.

FERC said a Voltus employee sent an August 2017 email stating, “We should exercise caution increasing the scraping rate, as it would be very easy for [Ameren] to make this much harder for us with some simple server config changes.”

FERC said in its first MISO Planning Resource Auction for 2017/18, Voltus registered about 41 MW of load modifying resources without contracts. After rolling out Scranta, Voltus registered an uncontracted 207 MW with MISO in the 2018/19 PRA, 216 MW in the 2019/20 PRA and 65 MW in the 2020/21 PRA. The uncontracted megawatts included some resources that Voltus approached with unsuccessful sales pitches.

FERC said uncontracted or above-contract demand response made up 96% of Voltus’ MISO portfolio in the 2017/18 planning year, 49% in the 2018/19 planning year, 45% in the 2019/20 planning year and 29% in the 2020/21 planning year. FERC said over those years, MISO didn’t require aggregators to prove they had contractual relationships with the load-modifying resources they claimed to have at the ready.

FERC staff said Dixon acknowledged in testimony that Voltus didn’t know whether its DR resources without legitimate contracts would respond to MISO dispatch by reducing demand.

“I … noticed that you could just plug in any account number, that, you know, you could go to the [Ameren] website and just plug in — you know, you could essentially script the URL. It’s a 10-digit account number code. You could plug that in, just cycle through them, and it would identify — we created a program that would identify any loads,” Dixon told FERC staff during the investigation.

In an early 2019 Slack conversation with Voltus employees, Dixon likened the unauthorized DR registrations to his hobby clearing mountain biking trails on a nature preserve. Dixon said because he didn’t have explicit permission to cut new paths, he would work under the cover of darkness to clear brush.

An unnamed Voltus employee reportedly responded with, “If we sat around waiting for MISO to create the perfect rules for DR and always played by their exact rules there wouldn’t be DR in MISO at all!”

Parallels with Ketchup Caddy

The settlement is the latest in a string of disciplinary action from FERC regarding companies deceptively offering demand response in MISO’s capacity auctions.

This also is the second time Ameren’s website has been connected to phony demand response schemes in MISO. From 2019 to 2021, the founder of an obscure, Texas-based LLC meant to sell in-car ketchup holders used a random number generator on an Ameren website to land on actual customer accounts and cull data for fraudulent DR registrations. (See In a Pickle: FERC Issues $27M in Fines over Ketchup Caddy DR Deceit.)

Ameren did not return RTO Insider’s request for comment on whether it has addressed vulnerabilities within its website that allow companies to use random number generators to reveal customer account numbers and gain access to usage data.

Voltus Neither Admits nor Denies

Voltus said the settlement should not be construed as it admitting to market manipulation.

“Under the terms of the settlement agreement, we are not acknowledging wrongdoing in connection with bringing demand response to MISO for the first time. We have not been accused of, let alone admit to, any market manipulation. Rather, we are entering a no-admit/no-deny settlement on tariff violations. Moving forward, we will continue to act according to the letter and spirit of all applicable laws, regulations and market rules,” the company said in an emailed statement to RTO Insider.

Voltus said with the settlement behind it, its “team is free to put its undivided focus on creating opportunities for customers and on delivering a more reliable, affordable and sustainable electric grid.”

“Voltus will continue to work with regulators, including FERC, to ensure that tariffs that govern demand-side resources are clear and consistently applied,” the company said.

Voltus said it remains proud of the $175 million it has paid customers over the past nine years, “much of which comes from markets that previously did not allow demand response.”

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WAPA Sued Over 504-MW Wind Farm Interconnection Plan

A lawsuit seeks to block interconnection of what could become Wyoming’s largest wind farm, alleging an inadequate environmental review of the interconnection plan. 

The 504-MW Rail Tie Wind Project being developed by Repsol Renewables would have negative effects on local eagle populations and on the wide-open vistas in the area, the plaintiffs argue. 

They fault the Western Area Power Administration for this and are asking the court to set aside WAPA’s Record of Decision, Final Environmental Impact Statement and Historic Properties Treatment Plan. 

The lawsuit was filed in federal court in Wyoming on Dec. 23 against WAPA and Jennifer Granholm in her role as head of the U.S. Department of Energy, WAPA’s parent agency. As of Jan. 7, there was no indication in the federal court system’s public records portal of any reply by WAPA or DOE. 

The project would occupy 26,000 acres south of Laramie, near the Colorado border, and would interconnect with WAPA’s Ault-Craig 345-kV transmission line. 

WAPA published an environmental impact statement in late 2021, as required by the National Environmental Policy Act (NEPA), and issued its record of decision in mid-2022. 

On Oct. 28, 2024, WAPA issued a seven-point mitigation action plan that called for measures including a one-mile buffer zone around known eagle nests, preparation of an eagle conservation plan and funding for historic preservation efforts in the area, which has a connection to construction of the original transcontinental railroad. 

Two months later, attorneys for the plaintiffs — who are two neighbors of the site; a retired wildlife biologist who has placed satellite tags on 152 golden eagles for research purposes; a conservation nonprofit; and a professional archaeologists’ association — filed their suit in federal court in Wyoming. 

They assert and allege that: 

    • Rail Tie would be larger than any wind farm now operating in Wyoming. 
    • Construction would entail 60 miles of new roads, 109 stream crossings and 84 to 149 wind turbines standing 500 to 675 feet tall. 
    • By WAPA’s own admission, operation would present a “significant” threat to raptors including federally protected bald and golden eagles. 
    • The impact statement acknowledges that the size and number of turbines used in the project is unknown, so the analysis is based on “guesswork adorned with rhetorical misdirection.” 
    • WAPA “shrugs off any serious consideration of those effects” by deferring analysis to reports that will not be completed until many years after the NEPA process is completed, if at all. 
    • WAPA considered only two options — denying the interconnection request or approving it in its entirety. 
    • The next-closest 345-kV line is approximately 20 miles from Rail Tie’s sprawling footprint; connecting to that rather than to WAPA’s Ault-Craig line would cost at least $21.5 million and skew the economics of a project already expected to cost more than $500 million. 

The plaintiffs are asking the court to enjoin WAPA from authorizing interconnection of Rail Tie until the agency has complied with all of its obligations under federal law. 

The Rail Tie project website indicates the developer has been through review at the county, state and federal levels; has secured all major permits needed; is focused on final engineering and reconstruction activities; is finalizing an offtaker for the electricity the project would produce; and expects to start construction this spring. 

If it is completed as planned, Rail Tie would continue a striking transition in the nation’s leading coal-producing state: Since 2015, Wyoming’s coal production is down by nearly 40% while its wind power production has more than doubled, according to the U.S. Energy Information Administration. 

Southeast Wyoming — including Albany County, where Rail Tie would be built — has among the strongest wind resources in the nation, with swaths rated “excellent,” “outstanding” and “superb” under the Department of Energy’s WindExchange rating system. 

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NYISO Publishes Final Capacity Requirements for CY25/26

NYISO presented its final locational minimum installed capacity requirements for the 2025/26 capability year during the Installed Capacity Working Group’s first meeting of 2025 on Jan. 7, with only slight differences from the previous CY. 

The LCRs, expressed as a percentage of the peak load forecast, represents the minimum capacity that New York’s generators and load-serving entities must maintain within each of the downstate zones, which have transmission constraints. 

2025-2026 final LCR results | NYISO

Based on the 24.4% installed reserve margin approved by the New York State Reliability Council, NYISO determined the minimum capacity required for New York City, Long Island and the Lower Hudson Valley to be 78.5%, 106.5% and 78.8%, respectively. For CY24/25, they were 80.4%, 105.3% and 81%, respectively, based on a 22% IRM. 

NYISO also presented updated informational capacity accreditation factors (iCAFs) for CY25/26. The final CAFs will be calculated and posted by March 1.  

The iCAF values generally were lower than the initial ones presented in early October. NYISO staff said this was because of an increase in the loss-of-load expectation (LOLE). The exception to this was solar, which generally saw an increase in value. 

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State Briefs

FLORIDA 

Duke, Tampa Electric Seek Storm Recovery

Tampa Electric and Duke Energy recently filed storm recovery requests with the Public Service Commission. 

Duke, which requested $1.1 billion, said the costs are associated with storm cleanup from three major hurricanes. It would add about $31 to typical monthly residential bills starting in March. Tampa Electric is seeking to collect $464 million over one year, also starting in March, which would add more than $30 each month to typical residential bills. 

The PSC is expected to approve the proposed storm charges at its Feb. 4 meeting. 

More: Tampa Bay Times 

FPL to File New Rate Plan, Would Raise Rates 2.5% Through 2029

Florida Power & Light said it plans to file a rate increase with the Public Service Commission that would raise rates 2.5% through 2029. FPL will seek increases of about $1.55 billion that would take effect in 2026 and $930 million that would take effect in 2027, according to a letter filed with the PSC. FPL’s current four-year rate plan concludes at the end of 2025. 

More: WGCU 

MICHIGAN 

DNR to Clear 400+ Acres of State Forest for Solar Farm

The Department of Natural Resources confirmed that a 420-acre swath of state forestland will be cleared for a solar farm. 

The DNR assessed 1,200 acres of public trust land in Otsego County near a major transmission line to decide whether it was suitable for solar arrays. Agency leaders ultimately decided to lease 35% of that land to accompany a 200-MW farm and other adjacent solar projects. 

Since the decision was announced, some lawmakers have called for the firing of anyone involved in the decision. 

More: Michigan Live; The Detroit News 

MINNESOTA 

Monticello Nuclear Plant Gets Approval to Keep Operating Until 2050

The Nuclear Regulatory Commission recently renewed the operating license for Xcel Energy’s Monticello nuclear plant. The extension will keep the plant operating through Sept. 8, 2050. Xcel has said continuing to operate its two nuclear plants at Prairie Island and Monticello is critical to its carbon-free transition.

More: MPR News 

PUC Approves Xcel Rate Hike

The Public Utilities Commission approved a 5.2% rate hike for Xcel Energy. The increase will add $5.39 to the average monthly residential bill. 

The PUC approved the temporarily higher rates as it scrutinizes Xcel’s request for an even larger rate hike — its largest ever. It said it would wait to weigh in on that request until later this year. The rate request would amount to a 9.6% increase in 2025 and another 3.6% jump in 2026. 

More: The Minnesota Star Tribune 

MONTANA 

Supreme Court: DEQ Failed to Consider Pollution from New Plant

The state Supreme Court decided unanimously that both the Department of Environmental Quality and NorthWestern Energy skirted an environmental law by refusing to acknowledge or act on the greenhouse gases released by the Laurel Generation Station. 

The ruling will force the DEQ to go back and fully analyze the pollution impacts of the 18 methane-combustion generators and report the effects greenhouse gases and industrial lighting will have on the environment. However, the orders will do nothing to stop or change the operations or halt any of the pollution. 

The Sierra Club and the Montana Environmental Information Center were the organizations that challenged the plant. 

More: Daily Montanan 

NEW JERSEY

Leading Light Wind Seeks Second Delay for OSW Project

Leading Light Wind is seeking a second delay for its offshore wind project, claiming it can’t find someone to build crucial equipment for the turbines. 

Leading Light Wind already received one pause on its project from the Board of Public Utilities, but that pause ended Dec. 20. The day before, Leading Light asked the board for an additional stay, this time through May 20. It did not specify an inability to find a blade manufacturer as the reason for a second delay, but its most recent request said, “The offshore wind equipment market continues to experience significant price volatility, and the company has not yet identified a solution to that volatility.” 

The BPU could not estimate when it might consider the request. 

More: The Associated Press 

NORTH CAROLINA

Duke Energy Receives Approvals for New Gas Plants

The Utilities Commission recently approved Duke Energy’s plans to replace coal-fired power plants with gas-fired stations at two sites. 

Under the plans, Duke will replace two of the four coal-fired units at Person County’s Roxboro plant with gas-fired combined cycle units by 2029. Elsewhere, two of four coal-fired units at Catawba County’s Marshall plant will be replaced by a pair of gas-fired combustion turbines. 

The commission issued orders in early December deeming the gas plants necessary at both sites. That was followed by the Department of Environmental Quality granting air quality permits for the plants, with some conditions. 

More: The News & Observer 

SOUTH CAROLINA

SCANA Executive to Serve Time at Home Instead of Prison

U.S. District Judge Mary Geiger Lewis ordered Stephen Byrne, a former SCANA executive who was sentenced to 15 months in prison for his role in the failed V.C. Summer nuclear project, to serve his time at home instead of prison. 

While on home detention, Byrne will not be allowed to leave his house except to go to work, church, court hearings, doctor’s appointments and other pre-approved outings. He will have to pay the $200,000 fine and $1 million in restitution ordered in 2023. 

Byrne was sentenced in 2023 but never served any time, as prosecutors prepared to use his testimony against other people charged. Ultimately, however, Byrne never testified. 

More: South Carolina Daily Gazette 

TEXAS 

Supreme Court to Review 2021 Winter Storm Claims Against Utilities

The state Supreme Court is looking back to the arctic blast that swept the state in February 2021 and will decide whether families of those killed and injured in power outages can sue utilities. 

In a petition filed in May, the companies argue they were  following ERCOT’s orders to shed load to prevent the collapse of the power grid. The court is expected to hold oral arguments Feb. 19. 

More: NBCDFW 

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Federal Briefs

DOE Accepting Public Input on Hydrogen Facilities

The Department of Energy’s Office of Clean Energy Demonstrations is seeking public input as it begins to assess the potential impacts of the planned regional network of hydrogen facilities across Appalachia. 

The federally backed project to produce, store, distribute and use hydrogen as an energy source across West Virginia, Ohio and Pennsylvania has faced criticism over the lack of public involvement in its development. Residents have voiced concerns over the lack of transparency and information from the project developers and the government. 

Residents have until March 3 to submit comments. 

More: Mountain State Spotlight 

Biden Bans New Drilling off Nearly All US Coasts

President Joe Biden announced he would ban new offshore oil and gas drilling along most of America’s coastline. Biden is blocking new drilling along the Atlantic and Pacific coasts, the eastern Gulf of Mexico and portions of the North Bering Sea off the Alaskan coast. The decision would block the sale of new oil and gas leases across 625 million acres of ocean. Revoking the ban probably would require an act of Congress. 

More: The Hill 

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Company Briefs

Iberdrola Completes Buyout of Avangrid

Iberdrola announced it has completed its buyout of Avangrid. Iberdrola bought the remaining 18% of Avangrid’s publicly traded stock for $2.5 billion after receiving approval from state and federal regulators. The company will operate Avangrid as a private entity. 

More: Maine Public Radio 

Vistra First Utility to Top S&P 500 Since 2001

Vistra recently topped the leaderboard of the S&P 500 Index with an eye-popping 264% annual gain and became the first utility to do so in more than 20 years. 

The combination of increased demand, greater acceptance of nuclear power and artificial intelligence was credited with propelling Vistra’s stock, which is set to finish 2024 with a 264% annual gain. 

The last utility name to outperform every other stock in the S&P 500 was AES Corp. in 2001. 

More: The Dallas Morning News 

Entergy to Pay $12M Civil Penalty for Accounting Controls

Entergy has agreed to pay a $12 million civil penalty in a case involving internal accounting controls, the Securities and Exchange Commission announced. 

The commission said Entergy failed to accurately account for surplus materials and supplies. Those inaccuracies ended up on the utility’s books and in its financial statements. The accounting failed to comply with generally accepted accounting principles, the government said. 

More: Arkansas Business