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January 29, 2025

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PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor

PJM announced Jan. 28 that it will seek to establish a $325/MW-day price cap on capacity prices and a $175/MW-day floor for the 2026/27 and 2027/28 Base Residual Auctions (BRAs) following discussions with Pennsylvania Gov. Josh Shapiro to resolve a complaint he filed over increased capacity costs.

The RTO has scheduled a special session of the Members Committee on Feb. 7 to consult with stakeholders on the prospective Federal Power Act Section 205 filing, with meeting materials expected on Jan. 31. Consultation with transmission owners would also be necessary. PJM spokesperson Susan Buehler said the specifics of the proposal will be discussed Feb. 7 and clarified that the price cap and floor would extend to all zones.

The 2026/27 BRA is scheduled to be conducted in July, with several pending filings at FERC seeking changes to the auction design and stakeholder processes envisioning even more. Across several of those dockets, PJM has requested orders by Feb. 21, which it stated is necessary to ensure that it has adequate time to implement the changes in time for the auction.

The RTO noted that any changes are “subject to consultation with the PJM members and the PJM Board of Managers.”

“PJM did the right thing by listening to my concerns and coming to the table to find a path forward that will save Pennsylvanians billions of dollars on their electricity bills,” Shapiro said in his own announcement. “My administration will continue to work to ensure safe, reliable and affordable power for Pennsylvanians for the long term.”

In his complaint and letters to PJM’s board, Shapiro argued that the current price cap structure, which takes the greater of the gross cost of new entry (CONE) or 1.75 times net CONE, would result in total capacity costs $20.4 billion beyond what is necessary to maintain resource adequacy. (See PJM in Discussions with Gov. Shapiro on Capacity Price Cap.) The complaint sought to rework that formula to 1.5 times net CONE, arguing that would be the highest price necessary to ensure that the reference resource, a combustion turbine, is profitable (EL25-46).

The governors of New Jersey, Maryland, Illinois and Delaware have filed comments and sent letters supporting Pennsylvania’s complaint.

In a statement, Maryland Gov. Wes Moore’s office said he appreciates PJM’s responsiveness to mitigate unnecessarily high capacity prices.

“Today’s announcement of a path toward resolving a complaint filed by Pennsylvania — that was backed by Maryland and other states served by PJM — shows the grid operator has an understanding of the need to limit the future impacts of major price hikes on our ratepayers,” it said. “The governor remains concerned that while PJM has agreed to cap electricity costs, successful implementation of this approach depends on details that need to be worked out ahead of federal approval.”

Mila Myles, spokesperson for Delaware Gov. Matt Meyer, said he shares the other governors’ concerns about potential capacity cost increases.

“We welcome the news that PJM has reached a tentative settlement that will protect consumers in Delaware and other states from excessive increases in their electric bills,” she said in an email. “This is an example of how PJM can work with states to ensure that our constituents are protected from abrupt changes in energy markets. We hope this settlement opens the way to a more productive working relationship between PJM and the states it serves as we navigate a changing electric grid.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, told RTO Insider the agreement follows years of PJM being influenced by stakeholders to change market rules that disadvantage them, showing an institutional vulnerability that opens the door to any parties filing FPA Section 206 complaints and negotiating directly with PJM staff to satisfy politically driven interventions. He called the prospective price floor “window dressing” given the likelihood PJM and members have discussed of high prices in the 2026/27 auction.

“This is no longer a market when you’re just picking prices,” he said. “This is how wholesale markets die.”

In addition to the direct impact of suppressing prices in the coming auctions, he argued that the repeat rule changes are undermining investor confidence in the prices set by the capacity market. He noted that generation deactivation requests have been filed for the Elwood plant, owned by J-Power USA, and Avenue Capital Group’s Elgin generators in the ComEd zone. While Elgin has rescinded its request to retire following the 2025/26 price print, Sotkiewicz said the decision to continue Elgin on the path to deactivation makes sense even in the face of near-term high prices given the volatility PJM has created.

“You can’t run a market this way; there’s no way an investor can have confidence in a ruleset,” he said. “I have more certainty about building a generator in California than PJM.”

Sotkiewicz said the process of directly negotiating with one governor on the market design for an RTO with 14 jurisdictions and market participants who will be directly affected tells stakeholders that their perspectives don’t matter. He said PJM has repeatedly eschewed the stakeholder process to instead follow various special processes, often giving minimal notice to members before filing major redesigns on the capacity market.

“Why are we having a stakeholder process about anything when you’re just going to do whatever the hell you want?”

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Calif. Officials Propose New Safety Measures for Battery Storage

California regulators have proposed new safety standards for battery energy storage systems following a series of incidents at the facilities, including a major fire Jan. 16 at Vistra’s Moss Landing site. 

The California Public Utilities Commission is proposing the standards as an update to General Order 167, which was first adopted in 2004 and sets safety standards for electric generating facilities. The commission is expected to consider the update, known as GO 167-C, during a March 13 voting meeting. 

“Regulatory oversight of ESS [energy storage system] facilities is necessary because of the safety and reliability risks that can occur if ESS facilities are not properly operated and maintained,” the CPUC said in a proposed resolution to adopt the standards. 

In addition, a bill has been introduced in the California legislature addressing battery storage system safety. Assembly Bill 303 would restore local oversight for energy storage projects in the state, according to its author, Assemblymember Dawn Addis (D). 

Under the CPUC’s proposed standards, battery energy systems would face similar requirements to those of electric generating facilities.  

For example, ESS owners would be required to file operation and maintenance plans with the CPUC, steps now required of generating asset owners. ESS owners also would be required to report safety-related incidents to the CPUC within 24 hours — just as generating asset owners must do now. 

And in a new mandate for both energy storage and electric generation, facility owners would be required to work with local authorities to develop an emergency response and emergency action plan. 

The changes are in response to direction from state lawmakers in Senate Bill 1383 of 2022 and SB 38 of 2023. 

The CPUC held three workshops in 2024 to gather feedback while developing the proposed standards. 

Battery Blazes

Battery storage is seen as key to meeting the state’s clean energy goals. Batteries can store solar energy during the day and release it during peak demand in the evening. 

California’s battery energy storage capacity increased from 770 MW in 2019 to 13,391 MW in October 2024, with about 3 GW of that added since April 2024. (See California Hits Milestones for Batteries, DR Grid Support.) 

That puts the state at about a quarter of its projected energy storage need of 52,000 MW by 2045. 

But battery storage presents safety concerns. The worries were underscored Jan. 16, when a fire broke out at Vistra’s 300-MW energy storage facility at Moss Landing in Monterey County. The lithium-ion battery facility is one of the world’s largest battery energy storage systems. 

The fire, which prompted the evacuations of 1,200 people, is now under investigation. Staff from the CPUC’s Safety and Enforcement Division visited the site Jan. 22 as part of its probe. 

The CPUC listed nine other safety incidents at battery facilities since 2021, including four in 2024. In one incident in September 2024, a fire at a San Diego Gas and Electric battery storage facility in Escondido prompted evacuations. 

Evacuations were also ordered in May 2024 during a fire at REV Renewables’ Gateway Energy Storage facility in Otay Mesa. 

Battery Safety Bill

AB 303 from Assemblymember Addis is also known as the Battery Energy Safety and Accountability Act. 

The bill would prohibit battery energy systems of 200 MWh or more on an environmentally sensitive site or within 3,200 feet of a “sensitive receptor,” such as a home, school or community center. 

The bill would also exclude battery storage projects from the California Energy Commission’s opt-in certification process, a streamlined path to approval. (See 2 Huge Solar-plus-storage Projects Planned in California.) 

Under the opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits. 

“AB 303 is a proactive measure that will ensure companies like Vistra go through the normal, local, regulatory process,” Addis said in a statement. “It is designed to build trust, increase safety and give communities a choice by restoring local community processes for permitting these projects.” 

The California Energy Storage Alliance is opposed to the bill, saying it is “excessive and does nothing to enhance public safety.” 

“Instead, it creates unnecessary barriers to the deployment of critical energy storage systems needed to stabilize our grid and support California’s transition to a clean energy future,” CESA said in a release. 

AB 303 is awaiting assignment to committee. 

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Chevron, Engine No. 1 to Power Data Centers

Chevron and activist investor firm Engine No. 1 are teaming up on plans for what they expect will be the first multi-gigawatt gas-fired power plant co-located with a data center.

They said Jan. 28 that their partnership to build a new company to develop scalable and reliable power solutions for U.S. data centers is based on President Donald Trump’s supportive early moves for U.S. energy development, including in support of artificial intelligence.

They said they have secured manufacturing slots for seven of GE Vernova’s 7HA gas turbines and expect to install them at data centers in the Southeast, Midwest and West that they are calling “power foundries.”

They would total as much as 4 GW of capacity and would be targeted to be in service by the end of 2027. There is potential to expand beyond this capacity and potential for future addition of carbon capture and storage or other carbon-reduction strategies.

The generating units initially would not send power through the grid. But the model is designed to allow future interconnects.

Chevron, Engine No. 1 and GE Vernova offered comments directly in line with their roles as an oil supermajor, an industrial investment firm and a power equipment manufacturer.

Chevron CEO Mike Wirth said: “We are proud to play our part in bringing to fruition President Trump’s vision for a new American golden age, powered by our enormous energy resources and unrivaled workforce.”

Engine No. 1 CIO Chris James said: “By using abundant domestic natural gas to generate electricity directly connected to data centers, we can secure AI leadership, drive productivity gains across our economy and restore America’s standing as an industrial superpower.”

GE Vernova CEO Scott Strazik said: “GE Vernova is uniquely positioned to provide the energy systems and support required to make this large-scale endeavor possible, as the leading U.S. energy manufacturer.”

Almost all observers expect U.S. electricity demand to increase in coming years, in part because of the rise of energy-intensive artificial intelligence computing. There has been some disagreement on how sharply it will increase, however.

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Brattle Study Shows Big Benefits for California in ‘Expanded’ EDAM

California ratepayers would save millions more in a CAISO Extended Day-Ahead Market (EDAM) encompassing nearly all the West than in one that includes only those utilities likely to join the market, according to a new Brattle Group study. 

The study, which was commissioned by the California Energy Commission, covers nearly every utility in the state — except the Imperial Irrigation District (IID) — and not just members of CAISO, whose balancing authority areas accounts for about 80% of the state’s electricity load. It represents yet another in a series of Brattle — and other — production cost model studies published during the increasingly contentious competition between EDAM and SPP’s Markets+. 

Brattle Principal John Tsoukalis presented “preliminary” findings from the study during a Jan. 24 CEC workshop that examined the potential impact on California from the West-Wide Governance Pathway’s “Step 2” plan to establish an independent “regional organization” (RO) to oversee CAISO’s EDAM and Western Energy Imbalance Market (WEIM). 

“A larger market means a larger and more diverse pool of transmission and generation resources,” Tsoukalis said. “And what that means is … the market is able to more effectively shift from less efficient resources to more efficient resources. It finds the lowest-cost resource that can serve load in every given hour, and that leads to production cost savings for customers.” 

The study differs from previous Brattle studies in that the “Baseline” case is not the status quo — that is, the current arrangement before the launch of EDAM or Markets+ — but assumes a scenario in which EDAM is already operating but includes only CAISO and those entities that have already formally committed to that market. Those entities include PacifiCorp; Portland General Electric; Balancing Authority of Northern California (BANC) and its largest member, Sacramento Municipal Utility District; and Los Angeles Department of Water and Power (LADWP). 

Under Brattle’s “Baseline” case, California’s estimated total system cost is $4.511 billion a year.  

That figure drops by $112 million (to $4.399 billion) under a “Baseline+” case in which EDAM also consists of entities likely to join the market, which includes Idaho Power, NV Energy and Public Service Company of New Mexico.  

But the biggest savings for California by far are found in the “Expanded EDAM” case, in which the CAISO market includes nearly every Western BA except for Western Area Power Administration entities already engaged with SPP markets, Public Service Company of Colorado (PSCo) and IID. In that scenario, Golden State ratepayers save $780 million annually compared with the “Baseline” case. 

“Intermediate EDAM footprints [are] likely to produce benefits between the Baseline+ and Expanded EDAM ‘bookend,’” according to a slide from the Brattle presentation. 

But California would likely see significantly lower benefits than the top end — $182 million — in what will be the most likely outcome in the West — the “Split Market” case, where Markets+ consists of Powerex, the Bonneville Power Administration and most Washington utilities, NorthWestern Energy, PSCo, Arizona’s utilities and El Paso Electric. 

“The only difference between the Baseline+ case and the Split Market case is that we have Markets+ forming in that Split Market case, and what we see is there is a slight benefit, actually, to California customers from Markets+ forming, but it is about $500 million less than the Expanded EDAM case,” Tsoukalis said. 

The study drew that conclusion based partly on the assumption of a “relatively efficient seam” between EDAM and Markets+, an improvement over the current bilateral day-ahead market that would provide California customers with “increased access to low-cost resources in the Markets+ footprint.” 

Tsoukalis noted also that the study’s day-ahead market benefit estimates are likely “conservatively low,” just as previous studies had underestimated the actual benefits from the WEIM. 

Emissions, Reliability Benefits

Brattle’s study also shows significant carbon emissions benefits for California in the Expanded EDAM, with in-state gas generation falling by 31%, wind and solar curtailments falling by 10% and CO2 emissions declining by 11.2% — though emissions in the rest of the West would increase 1.3%. Under the Split case, emissions in California fall by 3.5% and rise by 2.1% in the rest of the West. 

The study also represents the first of the Brattle market studies that attempts to capture potential reliability benefits from the day-ahead market for all participants. To do that, it estimates the change in “market supply cushion,” representing “the available generating capacity not committed to serving load” during each hour, which Tsoukalis said consists only of dispatchable resources and explicitly excludes hydro, wind and solar. 

The study found that the supply cushion is about 25 GW higher in the Expanded than in the Split case. 

“Focusing on the 10 tightest hours of the year, the supply cushion in the EDAM is 20,000 MW larger in the Expanded EDAM case than in the Split Market case (27.8% of load vs. 24% of load),” the study said. 

Michael Wara, of Stanford University’s Woods Institute for the Environment, who followed Tsoukalis’ presentation with his own that showed the reliability benefits of Western grid regionalization, said he was “encouraged” to see Brattle’s findings around reliability. 

“I would have been surprised and a little depressed if their analysis, using a different method, said ‘not much benefit,’ but 25 GW of additional capacity is a substantial benefit on a hard day,” he said. 

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Constellation, Calpine Propose Selling PJM Plants to Cut Market Power

Constellation Energy and Calpine Corp. asked FERC to approve their proposed merger and offered to sell off most of the latter’s natural gas fleet in PJM to assuage market power concerns (EC25-43). (See Constellation to Acquire Calpine for $29.1B.) 

“The combined company will have a geographically diverse coast-to-coast presence and operate the most reliable and cleanest generation portfolio in the country,” the firms told FERC. “This will allow the company to better serve customers with a broader array of energy and sustainability products to power homes and businesses at competitive prices while continuing to provide reliable, clean and secure generation to the grid.” 

Calpine has a large presence in California, where Constellation is not very active, and the two overlap a little in New England, New York and the Midcontinent ISO, but their biggest overlap is PJM and specifically the eastern part of the RTO. 

The two firms proposed selling all but one of Calpine’s combined cycle natural gas plants in PJM, which totals 3,546 MW. The units that will go on sale if FERC approves the application are valuable and high-performing plants, and two of them are dual-fuel capable. 

The plants proposed for sale are the 1,134-MW Bethlehem Energy Center, the 569-MW York Energy Center 1, the 1,136-MW Hay Road Energy Center and the 707-MW Edge Moor Energy Center. 

Eastern PJM is the one area where the combined generation of Constellation and Calpine led to violations of market power screens. The application argued that those failures “do not reflect actual competitive concerns” because the region no longer should be considered a submarket, and Constellation’s bids already are covered by an agreement with PJM’s market monitor.

“Nevertheless, to avoid a potentially protracted regulatory proceeding and speed the governmental approval process, applicants commit to a robust mitigation plan that would involve the divestiture of all but one of Calpine’s combined cycle natural gas plants located in eastern PJM,” the application said. “As described below, that mitigation plan would eliminate all screen violations in these PJM submarkets.” 

Without the sales, the combined firm would own more than 25 GW of generation in PJM, which compares to just 8 GW in California and less in other markets. 

Constellation owns 2.3% of CAISO’s generation now and Calpine 13.4%, but their combination would have a minimal impact on market power there, the application argued. 

In PJM, Constellation owns 11.4% of the generation and the deal would bring an additional 3% under its corporate umbrella. The consultants hired by the merging firms argued that the submarkets FERC has looked at historically in PJM no longer make sense. Still, they said, the mitigation plan would eliminate market screen failures in all of them. 

There should be enough buyers that do not have significant ownership in PJM for the four power plants, but the application noted that FERC can review any potential buyers if it approves the Constellation-Calpine deal. 

For any period between the merger’s close and the sale of the four power plants, Constellation said it would abide by voluntary mitigation that keeps its bids in the relevant PJM submarkets near its generators’ costs. 

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Texas PUC Begins Registering Crypto Mining Facilities

The Texas Public Utility Commission has opened an online portal on its website to accept registrations from cryptocurrency mining facilities.

The PUC said Jan. 27 that facilities with a demand of more than 75 MW are required to register by Feb. 1. Future facilities must register no later than one working day after receiving retail service, it said. Crypto miners registered with the commission must provide information annually about the facility’s location, ownership and electricity demand.

Those facilities failing to register could face fines of $25,000 per violation per day.

The PUC in November adopted a new rule mandated by state law that requires crypto miners in ERCOT’s region to register. (See “New Rules for Crypto Miners,” ERCOT to Recommend RMR Agreement for Braunig).

ERCOT labels cryptocurrency facilities as “flexible loads” because of their ability to quickly adjust their power consumption in response to increasing demand or prices. The facilities often are compensated for shutting down their consumption; Riot Platforms in August 2023 earned $31.7 million for curtailing demand, almost four times the amount it made from producing bitcoin.

The Texas grid operator said in 2024 that it expects demand to nearly double in six years, from 85 GW to as much as 150 GW by 2030, due to cryptocurrency mining, data centers and artificial intelligence.

ERCOT Cancels MRA Request for Braunig 1, 2

ERCOT said Jan. 28 it is canceling a request for more cost-efficient must-run alternatives for two aging gas plants that it says are needed to support grid reliability.

The gird operator said it did not receive any eligible proposals that were more cost-effective than contracting for mobile generators leased by CenterPoint Energy to avoid committing CPS Energy’s Braunig Units 1 and 2 under a reliability must-run (RMR) contract.

ERCOT’s Board of Directors in December directed staff to develop an RMR agreement with CPS Energy, San Antonio’s municipality, to return Braunig 3 to service into 2027. (See “ERCOT to Pursue Braunig MRAs,” Texas PUC Shelves PCM Design Over Lack of Benefits.)

CPS Energy told ERCOT in 2024 that it intended to retire all three 1960-era units in March 2025.

ERCOT said it expects further discussion on the issue during the Feb. 3-4 board of directors meeting. The ISO also said it expects to provide a recommendation during a future special board meeting over whether to commit Braunig Units 1 and 2 through an RMR agreement or move forward with the mobile generation solution.

CPS Energy has told ERCOT the Braunig units’ standby costs are:

    • $2,382/hour for one year, $1,500/hour for two years (Braunig 1).
    • $2,558/hour for one year, $1,597/hour for two years (Braunig 2).
    • $3,599/hour for one year, $2,246/hour for two years (Braunig 3).
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Massachusetts DPU Approves Price Increase for NECEC Line

The Massachusetts Department of Public Utilities approved a settlement agreement for the New England Clean Energy Connect (NECEC) transmission line Jan. 27, authorizing a significant cost increase to account for regulatory delays to the project. 

The agreement comes after political and regulatory obstacles caused an approximately two-year pause in the line’s construction. Massachusetts ratepayers will now be on the hook for a price increase estimated to total $521 million in 2017 dollars, which equates to about $670 million (24-160). 

When in service, the 1,200-MW NECEC project will facilitate power flow from Quebec to New England. The project was selected by Massachusetts in a 2018 clean energy solicitation and is being developed by a subsidiary of Avangrid. 

While the project is now fully permitted and under construction, opposition to the line in Maine brought together an unlikely pairing of fossil fuel generators and environmental nonprofits, including the Sierra Club and the Natural Resources Council of Maine.  

This coalition succeeded in getting a ballot referendum passed in 2021 to stop the project, but it was eventually struck down by the Maine Supreme Judicial Court. Construction on the project resumed in August 2023. 

While NECEC was initially projected to come online in late 2022, it is now on track to be in service by the end of this year, according to a January progress report. The developer wrote that the HVDC line is fully cleared, with 919 pole bases set, 756 poles erected and wires installed on 554 poles. 

Negotiations on the settlement agreement included the utilities, the developer, the Massachusetts Attorney General’s Office and the state’s Department of Energy Resources. The utilities filed the agreement in October 2024. 

The DPU ruled that “the distribution companies and the other settling parties provided testimony and significant evidence” that the cost increases were caused by delays stemming from the Maine referendum. 

“The incremental cost increase negotiated by the settling parties is less than the costs NECEC claims to have incurred due to the Maine initiative,” the department noted. It highlighted the utilities’ findings that the project would still provide about $3.38 billion in net benefits, calculated in 2017 dollars. 

The DPU wrote that it expects the project to save customers an average of $18 to $20 per year and cut emissions by about $2 million tons annually for the length of the contract. 

The settlement agreement will increase the monthly transmission charges to the distribution companies for the first year of the contract from $9.29 to $13.61/kW-month. These charges will grow to $19.82/kW-month by the final year of the contract. 

“NECEC is essential to our shared clean energy goals,” DPU Chair James Van Nostrand said in a statement. “The project will not only provide renewable energy year-round, but most importantly, it will stabilize electric rates throughout the state, saving ratepayers money over time.” 

ISO-NE studies have shown that the project would bring significant reliability benefits to New England. In a 2024 study, the RTO found that the line would cut energy shortfall by 31 to 36% in a worst-case 21-day winter scenario, preventing about 80,000 MWh of shortfall. 

Avangrid also has an ongoing lawsuit against NextEra Energy, alleging it broke state and federal antitrust laws in its efforts to stop the project and caused damages of at least $350 million. NextEra owns several generators in the region that would likely be affected by the lower energy prices enabled by NECEC (3:24-cv-30141). (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.) 

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Company Briefs

EV Startup Canoo Files for Bankruptcy

Canoo on Jan. 17 said it would file for Chapter 7 bankruptcy and cease operations, effective immediately. 

Canoo said it had been unable to obtain funding from the Department of Energy’s Loan Program Office and its recent discussions to acquire capital from “foreign sources” also failed. 

More: Car and Driver 

Prysmian Group Pulls Plug on OSW Cable Plant

The Prysmian Group announced it has canceled its plans for a $300 million offshore wind cable plant in Massachusetts. 

The group spent nearly three years obtaining all the necessary state and local permits but ultimately decided to walk away from the project just days before Donald Trump, who has vowed to shut down the offshore wind industry in the U.S., took office. However, Prysmian did not mention Trump in a statement confirming its decision to not exercise an option to purchase land at Brayton Point and instead chalked the decision up to its efforts to align capacity to produce subsea cable with demand for its product. 

More: CommonWealth Beacon 

Senechal Named New CEO, President of NOVEC

The Northern Virginia Electric Cooperative’s (NOVEC) Board of Directors last week named Kristen Senechal as its next president and CEO, effective April 2. 

Senechal is currently the executive vice president of transmission and chief operating officer at Lower Colorado River Authority in Texas. She joined the authority in 2017 after nine years at CenterPoint Energy in Houston. 

Senechal will succeed David Schleicher, who will retire on April 1. 

More: Potomac Local News 

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State Briefs

CALIFORNIA 

Gov. Newsom Calls for Investigation of Moss Landing Fire

Gov. Gavin Newsom is calling for an investigation into a fire that occurred at Vistra Energy’s Moss Landing Energy Storage Facility two weeks ago. 

The fire was the latest in a string of incidents at Moss Landing. In September 2021, a purported software programming error caused a heat suppression system to activate and douse three 100-MW racks of batteries. A second, nearly identical issue involving the early detection safety system occurred in February 2022 in the 100-MW Phase II building next door. 

The PUC’s Safety and Enforcement Division was scheduled to meet with Vistra last week. 

More: Renewable Energy World 

GEORGIA 

PSC Approves New Rule for Data Centers

The Public Service Commission last week approved a rule that allows Georgia Power to charge new data centers in a manner that works to protect ratepayers from cost-shifting. 

The rule states that any new customers using more than 100 MW can be billed using terms and conditions beyond those used for standard customers to address risks associated with large-load users. The data centers would also pay for costs from upstream generation, transmission and distribution as construction on the data centers progresses. 

In addition, any new Georgia Power contract with a company that fits the 100-MW usage category must be submitted to the PSC for review. 

More: WXIA 

IOWA 

NextEra Starts Process to Reopen Duane Arnold Nuclear Plant

NextEra Energy Resources said it has filed a request with the Nuclear Regulatory Commission to potentially restore the Duane Arnold Energy Center’s operating license. 

The 50-year-old facility, which NextEra has owned since 2005, was decommissioned in 2020 amid the rise of wind and solar energy production. Now, the demand for electricity has the company eyeing a restart by the end of 2028. 

More: The Gazette 

KENTUCKY 

Devs Plan to Build State’s First ‘Hyperscale’ Data Center

PowerHouse Data Centers and Poe Companies of Louisville have announced plans to build the state’s first “hyperscale” data center in Louisville. 

The companies said they plan to build a 150-acre data center campus that is expected to use about 130 MW in 2026 when the center becomes operational. That total could eventually grow to 400 MW. 

More: WDRB 

MICHIGAN 

PSC Approves DTE Energy Rate Increase

The Public Service Commission last week approved a $217.4 million rate increase for DTE Energy. 

The hike, which will go into effect Feb. 6, will raise the typical residential bill by about $4.61/month. 

More: Detroit Free Press 

MINNESOTA 

PUC Approves Northland Reliability Project Tx Line

The Public Utilities Commission last week approved a certificate of need and route permit for a 180-mile high-voltage transmission line. 

Minnesota Power and Great River Energy jointly plan to build the Northland Reliability Project, which could cost more than $1 billion. 

The utilities say the new line is needed to help maintain a reliable grid as they transition away from fossil fuels to renewable energy. 

More: MPR News 

NEVADA 

Solar Facility Shutting Down Two-thirds of Plant

The 386-MW Ivanpah Solar Electric Generating Facility will shut down two-thirds of its capacity after Pacific Gas and Electric terminated its power purchase agreement with NRG Energy. 

PG&E contracted with NRG, who operates the plant, to provide energy to customers in 2009, and the agreement was planned to run until 2039. However, PG&E decided to end the agreement with plant owners Solar Partners to save ratepayers money, PG&E said. 

The California Public Utilities Commission must approve the termination agreement. 

More: Las Vegas Review-Journal 

OHIO 

Former FirstEnergy Execs Indicted on RICO Charges

A federal grand jury has indicted former FirstEnergy executives Charles E. Jones, 69, and Michael Dowling, 60, on one count of participating in a racketeering (RICO) conspiracy. 

From 2015 until 2020, when he was fired, Jones worked as a senior executive, including president and CEO. During that time, authorities say Jones earned around $65 million, with about $60 million coming from performance-based compensation connected partly to company stock prices. Dowling worked as senior vice president, and his compensation was also tied, in part, to stock prices. Both were indicted last year on state charges. 

According to the Southern District of Ohio, the two are accused of using “bribery, money laundering and obstruction to increase the company’s stock price and enrich themselves.” 

More: WEWS 

Power Siting Board Approves Solar Farm, Rejects Others

The Power Siting Board has approved a 100-MW solar project in Clermont County. 

The Clear Mountain Energy Center will proceed on 1,226 acres and will be paired with a 52-MW battery system. 

Meanwhile, the board rejected the 250-MW Richwood Solar project and the 70-MW Circleville Solar project due to heavy opposition. 

More: Cleveland.com 

UTAH 

PacifiCorp Extends Life of Coal-powered Plants

According to PacifiCorp’s long-term regional resource plan, both coal-fired plants in the state will not be retired before 2045. 

In the 2023 version of PacifiCorp’s Integrated Resource Plan, coal units at Hunter had an assumed end in 2042, while its Huntington units were scheduled to be retired in 2036. The company attributed the shift to “changes that have happened recently in regulatory requirements at the state and federal levels.” 

More: Utah News Dispatch 

VIRGINIA 

Blackstone to Buy $1B Power Plant Near Data Centers

Blackstone Energy Transition Partners last week announced it has agreed to buy a 774-MW natural gas-fired power plant in Loudoun County. 

The statement gave no financial details, but sources said Blackstone is paying around $1 billion for the Potomac Energy Center. The facility is in an area which is estimated to have around a quarter of the current U.S. data center capacity. 

More: Reuters 

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Federal Briefs

EIA: Wholesale, Retail Electricity Prices to Rise in 2025

U.S. wholesale power prices are expected to be slightly higher on average in 2025 in most regions outside of Texas and the Northwest, according to the EIA’s Short-Term Energy Outlook. 

The forecast expects the 11 wholesale prices it tracks to average $40/MWh in 2025, up 7% from 2024. It also expects the average residential prices to be 2% higher than the 2024 average, though after accounting for inflation, prices may remain relatively unchanged. 

The only two regions expected to have lower than average prices are ERCOT ($30/MWh) and the Northwest ($55/MWh). 

More: EIA 

DOJ Asked to Investigate Texas’ Handling of $1B in Harvey Recovery Funds

The U.S. Department of Housing and Urban Development (HUD) has asked the Justice Department to take action against the Texas General Land Office (GLO) after finding it had violated the Fair Housing Act by discriminating against Black and Hispanic residents when it designed a competition to allocate Hurricane Harvey relief money. 

HUD’s review of the GLO’s funding process revealed the state agency had engaged in a pattern of “discriminatory actions based on race and national origin,” wrote Ayelet Weiss, assistant general counsel for HUD’s Office of Fair Housing Enforcement, in a letter to the Justice Department. The GLO originally awarded no money to Houston or Harris County. 

More: Houston Chronicle 

BLM Seeks Public Input for Idaho Renewable Projects

The Bureau of Land Management is seeking public input on two renewable projects in Idaho proposed by Arevia Power. 

The proposed projects are for a 400-MW Snake River Energy Solar facility and a 500-MW Taurus Wind facility. The facilities will share a 550-MW battery storage facility and a transmission line. 

An informational forum will be held Jan. 28. The public may submit their input by email until Feb. 7. 

More: pv magazine