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December 16, 2025

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Xcel Energy, AEP Plan to Invest $132B Through 2030

Xcel Energy and American Electric Power said during their quarterly earnings calls that they have increased their capital investment spend to meet increasing demand from large loads.

Xcel told financial analysts Oct. 30 that it plans to invest $60 billion over the next five years to strengthen its infrastructure because of 11% annual rate base growth.

CEO Bob Frenzel said he expects the updated five-year plan to deliver 7,500 MW of zero-carbon renewable generation, 3,000 MW of gas-fired generation and almost 2,000 MW of energy storage to ensure system reliability, and 1,500 miles of HV transmission line miles to support demand growth. He said Xcel has safe-harbored all renewable and storage projects in the base capital plan.

The Minneapolis-based company says it has 19 turbines on order, taking advantage of its scale to meet the demand from oil and gas electrification in the Permian Basin.

“The growth you see in the Permian is probably a function of two things,” Frenzel said. “One is continued strength in mining in the Permian Basin. So just more wells, more infrastructure, more fields being open. The second is a trend toward electrification of those fields and of existing fields.”

Xcel said it recorded a $290 million ($0.36/share) charge in reaching a settlement with plaintiffs in the 2021 Marshall wildfire in Colorado. The amount has been excluded from quarterly and year-to-date ongoing earnings. The company expects to pay about $640 million related to these settlements, with about $353 million expected to be reimbursed to Public Service of Colorado by remaining insurance coverage.

“Xcel Energy does not admit any fault or wrongdoing in disputes that our equipment caused the second ignition,” CFO Brian Van Abel said. “We believe this provides a positive outcome for our communities and our investors.”

The company reported earnings of $524 million ($0.88/share) during the quarter, compared to $682 million ($1.21/share) for the same period in 2024.

Xcel reaffirmed its 2025 earnings guidance of $3.75-$3.85/share. Frenzel said he’s confident the company can deliver on earnings guidance for the 21st year in a row.

The company’s stock price closed at $81.59 Oct. 30, up 50 cents from its open.

AEP: $72B Capex Plan

AEP told financial analysts Oct. 29 that it’s revised its five-year capital plan to $72 billion and that it is supported by an expected $10% annual growth rate in its rate base. System demand is projected to surge to 65 GW by 2030, up from a current peak of 37 GW. Company executives said they will invest $30 billion in transmission, $20 billion in generation, $17 billion in distribution and $5 billion in other spending.

“Electricity demand growth is happening, and we are seeing it play out across the country in real time,” CEO Bill Fehrman told analysts. “Regions with concentrated data center and industrial development, including AEP’s footprint, are emerging as clear winners. Large annual capital budgets from hyperscalers totaling hundreds of billions of dollars reinforce the conviction, strength and staying power of this demand growth.”

The Columbus, Ohio-based company said its 28 GW of contract data center load all have financial commitments associated with them.

“That’s why we have so much confidence in the 28 GW,” CFO Trevor Mihalik said.

AEP reported third-quarter earnings of $972 million ($1.82/share), slightly above 2024’s performance of $960 million ($1.80/share) for the same period. The company reaffirmed its 2025 operating earnings guidance range of $5.75-$5.95/share, saying it expects to be in the upper half of the spread.

AEP’s stock price closed at $121.89 Oct. 30, up $6.79 (5.9%) from its Oct. 29 open.

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Analysis Finds ‘Material’ Parallel Flow Effects in CAISO from PacifiCorp BAA Transactions

In an ongoing high-stakes analysis, CAISO has determined that transactions between PacifiCorp’s two balancing authority areas can “materially” affect parallel flows on certain CAISO transmission constraints, an ISO representative told market officials and stakeholders.

The finding is part of CAISO’s analysis of congestion revenue allocation during parallel flow situations within the ISO’s Extended Day-Ahead Market (EDAM). EDAM is to begin operation next year, with PacifiCorp as an initial participant.

The subject of how to allocate congestion revenues under parallel — or loop — flows took priority at CAISO in February after Powerex argued the EDAM model contains a “design flaw” with potentially $1 billion in unjustifiable charges at stake. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.)

CAISO then began months of work to address the concern, culminating in June, when it approved a new method for allocating certain congestion revenues in EDAM during parallel flow times, a design FERC later accepted. (See CAISO Approves New EDAM Congestion Revenue Allocation Design.)

The newly approved method, however, could create unintended market incentives, said Guillermo Alderete, CAISO director of market performance and advanced analytics, at an Oct. 29 joint meeting of CAISO’s Board of Governors and the Western Energy Markets Governing Body. CAISO’s Market Surveillance Committee (MSC) in a June memo also said it is concerned about the new method’s potential to create self-scheduling incentives.

To address those concerns, CAISO and its Department of Market Monitor (DMM) developed three stages of analysis, starting with a study of congestion revenue and parallel flow data in the Western Energy Imbalance Market between January 2024 and August 2025.

In this first stage, CAISO found transactions between PacifiCorp areas can “materially impact” parallel flow on some major transmission constraints in CAISO’s region, Alderete said.

CAISO specifically found that about 145 congested constraints — about 96% of the total constraints— were in the ISO. Of these constraints, about 21% were affected by parallel flows generated by transactions between the PacifiCorp East and West areas, Alderete said.

Constraints on Path 26 — which consists of three 500-kV lines between Pacific Gas and Electric’s and Southern California Edison’s territories — can see up to 40% flow impacts from transactions between the PacifiCorp East and West regions, he said.

However, the direction of transaction flow determines whether congestion revenue rents increase or decrease. If a transaction in PacifiCorp’s region flows in the same direction as transaction constraints on CAISO’s system, then congestion revenue rents will increase, Alderete said. On the other hand, if a transaction in PacifiCorp’s region flows in the opposite direction as transaction constraints on CAISO’s system, then rents will decrease, he said.

“Based on what you’ve seen so far, are you seeing anything that would indicate that we have a red flag that we should be looking at or reassessing anything?” WEM Governing Body member Robert Kondziolka asked at the meeting.

“No, at this time we don’t see any reason to take any dramatic action to change our proposal,” said Anna McKenna, CAISO vice president of market design and analysis. “But the analysis thus far does indicate and confirm some of the differences in parallel flows, and this is not a surprise.”

In general, congestion across all areas is concentrated during solar hours and increases during evening peak hours in the summer, Alderete said. Transactions in CAISO’s region have “de minimis” parallel flow impacts on constraints in PacifiCorp’s areas, Alderete said.

The second stage of analysis will use EDAM market simulations to analyze whether problematic incentives appear in the EDAM under the new congestion revenue calculation method.

The third stage will occur after the EDAM begins in 2026 and will include analysis of actual congestion revenue allocations under parallel flows in the EDAM.

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Southern Co.: Data Centers Continue to Power Growth

During Southern Co.’s quarterly earnings call Oct. 30, CEO Chris Womack assured investors the company “continues to perform exceptionally well [with] an incredibly bright future ahead.”

Southern’s net income for the third quarter stood at $1.71 billion ($1.55/share), up from $1.54 billion ($1.40/share) in the same period in 2024. Year-to-date income was $3.93 billion ($3.56/share), up from $3.87 billion ($3.53/share) in the same period the year before.

Operating revenue for the quarter came to $7.82 billion, a $549 million increase from the third quarter of 2024, while year-to-date revenue also rose by $2.19 billion over the same period in 2024, to $22.57 billion. Operating expenses for the third quarter rose to $5.23 billion from $4.91 billion for the third quarter of 2024, and from $14.37 billion to $16.2 billion year-to-date.

Adjusted earnings per share came to $1.60, CFO David Poroch said, 17 cents higher than the same period last year and 10 cents above the company’s estimate. He attributed the growth to investment in state-regulated utilities and increased usage by customers, offset by milder-than-expected weather, higher depreciation and amortization, and higher interest costs. Southern predicts adjusted earnings per share of 54 cents for the fourth quarter and $4.30 for the full year.

Weather-normal retail electricity sales were up 1.8% from the first three quarters of 2024, Poroch said, on track for the highest annual increase since 2010 excluding the COVID-19 pandemic. The biggest change was in commercial customers, which grew 2.6%. Next came the industrial sector with 1.6% growth, and then residential with 1.2%. Sales to other sectors fell 2.5%.

For the third quarter alone, total weather-adjusted retail electricity sales grew 2.6%, again led by the commercial sector with growth of 3.5%. Residential sales were up 2.7%, while industrial sales rose 1.5% and others grew 1.9%.

Poroch attributed the growth in the commercial sector to increased sales to existing and new customers, including a 17% increase in electricity usage by data centers from the previous year. Overall economic growth across the company’s service territory “remains robust,” Poroch said, citing announcements in the third quarter by 22 companies to either establish or expand operations in the Southeast, resulting in an expected 5,000 new jobs and capital investments of about $2.8 billion.

Womack said the company has “made great progress with signing new large-load contracts,” with 23 projects totaling 7 GW of demand having already broken ground with construction expected to conclude by 2029. Additional contracted projects are expected to bring this total to 8 GW by the mid-2030s, Poroch said.

Southern is working to build the generation capacity to meet this demand, Womack added, pointing to the ongoing construction of natural gas and battery storage facilities in Georgia and Alabama totaling about 2.5 GW and expected to come online over the next two years.

Reviewing Southern’s financing activities, Poroch said the company issued $4 billion in long-term debt across its subsidiaries, crediting “the quality and credit strength” of the company for drawing “robust investor interest,” which in turn will lead to lower interest costs and long-term benefits to customers. He said the debt issues, combined with those of the first half of the year, “fully satisfied” each subsidiary’s long-term debt financing needs for 2025.

Southern has raised about $7 billion of the $9 billion in equity needed to fund its long-term $76 billion capital investment plan, with $1.8 billion of that total raised since the company’s July earnings call, Poroch said. (See Southern Expects Large Load Growth to Continue.)

Asked about his reaction to the federal government’s recently announced agreement with Westinghouse to build at least $80 billion of the company’s nuclear reactors nationwide, Womack said he was “incredibly excited” about the news and that the commitment represents an important step toward meeting the country’s growing electricity demand. (See U.S., Westinghouse Partner for $80B in Nuclear Construction.)

However, he said the company had not made any decisions about pursuing new nuclear construction after the completion of Plant Vogtle Units 3 and 4 in Georgia, the first new nuclear plants in a generation whose construction ran years behind schedule and vastly over budget.

“We want to make sure that all risks are mitigated before we make that kind of decision,” Womack said. “I’m excited about all the activity that’s occurring around the country with considerations about new nuclear, [and] we’re going to continue to work with the administration [and] other government agencies to talk about the … role that new nuclear can play in meeting this growing demand, but … we’re not in a position to make that decision at this point.”

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New APS Gas Plant Will Offer Large-user Subscriptions

Arizona Public Service plans to build an up-to-2-GW natural gas power plant that would be paid for in part by large-load subscribers such as data centers.

The Desert Sun Power Plant would be built west of Gila Bend, Ariz., in two phases, APS announced Oct. 30.

Phase 1 would serve APS’ existing customers and “business as usual” growth. It would be paid for by ratepayers. In contrast, Phase 2 would be paid for by the extra-large customers who would use its output through a subscription model. APS defines extra-large customers as those needing 25 MW or more.

Extra-large users would sign long-term contracts covering capital costs and assuming development risks. APS calls the strategy “growth pays for growth.”

“Additional natural gas generation is essential to support our existing customers and to begin addressing unprecedented requests from extra-large energy users, such as data centers,” said Jacob Tetlow, APS executive vice president and chief operating officer.

APS has nearly 4.5 GW of committed extra high load factor customer demand, Ted Geisler, CEO of APS parent company Pinnacle West, said during a second-quarter earnings call in August.

In addition, there is almost 20 GW of uncommitted demand from customers that have “expressed serious interest in new projects within our system,” Geisler said.

Tetlow called the load growth “unprecedented.” And large-load customers seem interested in the Desert Sun project.

“We’ve had a good response,” Tetlow told RTO Insider in an interview.

Desert Sun’s Phase 2 customers would buy into a portfolio containing the new gas plant and other resources such as solar, storage or wind, Tetlow said. Phase 2 contracts would go to the Arizona Corporation Commission, most likely in a package, for approval.

The capacity of the two phases combined could be as much as 2 GW, though the amount in each phase isn’t yet known. Project costs are being worked out.

Phase 1 would include transmission upgrades, whose costs would be incorporated into base rates, Tetlow said. Phase 2 would come with additional transmission upgrades that the extra-large load subscribers would fund.

APS now offers an extra-high load factor tariff for large customers. The subscription model would be an alternative, Tetlow said.

Because customers using the subscription model would help pay to build new resources, they could get service sooner. The model would provide cost certainty to the large customers, while preventing cost shifts to smaller customers, Tetlow said.

Phase 1 of the power plant is scheduled to begin operations by late 2030. Phase 2’s operation date will be determined through discussions with the extra-large customers.

The new plant will come with advanced emissions controls to meet federal and county air quality standards. Using hydrogen as fuel for the new plant or deploying carbon capture may be considered in the future, Tetlow said.

APS intends to supply the plant with natural gas via the proposed Transwestern Pipeline’s Desert Southwest expansion project.

APS plans to add nearly 7,300 MW of new resources by 2028, to meet rising demand due to Arizona’s rapid growth. Natural gas complements APS’ renewable resources, while nuclear energy and coal make the system resilient, the company said.

Although APS had planned to exit the coal-fired Four Corners Power Plant in 2031, the company is reserving the option to continue using Four Corners through 2038.

Tetlow noted the importance of reliability in Arizona’s climate.

“It’s 118 degrees sometimes,” he said. “[Desert Sun] is a resource to ensure reliability in the desert.”

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PGE to Explore Alternatives After Withdrawing from WRAP

Portland General Electric is exploring an alternative to the Western Power Pool’s Western Resource Adequacy Program (WRAP) that better suits its upcoming participation in CAISO’s Extended Day-Ahead Market, the utility has told Oregon regulators.

PGE expressed its intention in an Oct. 29 letter to the Oregon Public Utility Commission explaining why the utility was withdrawing from the WRAP ahead of the Oct. 31 deadline to commit to the program’s first “binding” — or penalty — phase covering winter 2027/28. Oregon rules require the state’s investor-owned utilities to participate in either a program such as WRAP or a state-run RA program.

The tone of the letter suggests PGE likely is closing the door on future participation in WRAP as developments point to an alternative program taking shape in the West.

“We are pursuing alternatives to WRAP that better align with the EDAM market to maximize the value to customers,” Sujata Pagedar, PGE senior director of regulatory and governance, told OPUC in the letter. “By maintaining open dialogue and focusing on shared objectives, we believe we can collectively build a framework that delivers lasting benefits for the region.”

The Oregon-based utility was one of five WRAP participants to notify WPP of their withdrawal by Oct. 29, although other dropouts are likely. (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits.)

Even before NV Energy conveyed its formal notice of withdrawal on Oct. 27, utility officials told Nevada regulators they were in discussion with other future EDAM participants about developing an alternative to WRAP. (See EDAM Participants Exploring Potential New Western RA Program.)

Asked whether PGE was participating in those discussions, utility spokesperson Drew Hanson told RTO Insider: “It is less about a specific new RA program and more about remaining committed to regional collaboration and actively exploring alternative resource adequacy solutions.”

‘Unwavering’ Commitment

In the letter to OPUC, Pagedar said PGE’s “decision was not made lightly” but reflected “the fact that there are significant unresolved uncertainties in the program design, reliability metrics, technology readiness and governance — with no clear timeline for resolving these issues and implementing necessary changes in time for PGE to adequately prepare the March 31, 2027, forward showing submittal for the first binding season, effective Nov. 1, 2027.”

She noted that PGE was a “foundational member” of WRAP, “worked diligently” to move to binding operations as quickly as possible and was the first participant to receive a “passing” score on the operations program report during the “nonbinding” phase.

Still, PGE had identified critical shortcomings.

Among those was WPP’s proposed realignment of the WRAP’s operation subregions with CAISO’s EDAM and SPP’s Markets+ (compared with the previous Northwest/Southwest breakdown), which Pagedar said was necessary for a “robust” RA framework but posed too much risk without postponing the first binding season.

She said such “a complete realignment in such a compressed timeline creates substantial risk regarding how these metrics will be recalibrated and how those changes will impact participants’ capacity demonstration and financial exposure” during the first winter binding season.

Pagedar said PGE was concerned about the outcome of efforts by the WRAP’s Planning Reserve Margin Task Force to evaluate new methodologies for setting planning reserve margins for program participants.

“These changes directly impact deficiency charge calculations and the risk profile for participants. The changes to the PRM methodology and timeline could directly impact the calculation of resource capacity contributions,” she wrote.

PGE expressed concern about the “technical readiness” of WRAP, which is being operated on behalf of WPP by SPP, saying the forward showing and operations platforms appear to “lack the technical stability and responsiveness needed for a binding adequacy program” and that user interface and system issues that “raise doubts about the operator’s ability to implement changes in time for market participants to adjust their IT systems.”

Pagedar concluded that PGE has an “unwavering” commitment to collaborating on regional RA.

“We will continue to work with partners across the West to advance solutions that strengthen reliability, affordability and resilience for all customers,” she wrote.

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Nvidia, Emerald AI, EPRI and PJM Announce Flexible Data Center Project

The artificial intelligence industry and power industry are working together to develop the first “power-flexible AI factory” at a 96-MW facility in Manassas, Va.

Nvidia, Emerald AI, the Electric Power Research Institute, Digital Realty and PJM are working to test the flexible capabilities of the Aurora AI Factory, which was designed from the bottom up to provide services to the grid. The power-flexible design, if adopted across the country, could unlock 100 GW of capacity on the grid, based on a study from Duke University. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

Emerald is a startup working on the data center flexibility project with Nvidia, the largest company by market capitalization in the world because of its advanced chips that have fueled the rise of AI. The project is meant to help show the system can work, which would increase speed to market for data centers and take pressure off the grid, Emerald Chief Scientist Ayse Coskun said in an interview.

“AI data centers are facing a lot of wait time,” Coskun said. “In Virginia, we hear about five- to seven-year wait times for data centers to get connected.”

Load flexibility on the part of data centers means they can plug into the grid much more quickly because they can get offline when the system is stressed.

Nvidia provides the chips and offers control services for the project. EPRI is involved with its “DCFlex Initiative,” and the data center will bid services into PJM’s wholesale markets. (See EPRI Launches DCFlex Initiative to Help Integrate Data Centers onto the Grid.)

Data centers have varying levels of flexibility, from little to none at customer-facing facilities that make up the bulk of the facilities in Northern Virginia’s Data Center Alley, to cryptomining facilities that fall off the grid as soon as prices make their production unprofitable. AI data centers can be somewhere in the middle.

“A key ingredient in our technology is to make sure we meet these quality-of-service or priority constraints of customers,” Coskun said. “Some AI workloads fall into this category of being urgent and therefore not being flexible, but there’s a lot of other AI workloads.”

Some of the computing processes can be slowed or delayed for the few hours at a time when the grid would need to count on demand response from data centers, she added.

“Overall, when you look into the performance impact for this kind of actions, it’s minuscule,” Coskun said. “And in some cases, it’s not even noticeable.”

With ample benefits from speed-to-market concerns and little impact on AI data centers’ operations, flexibility makes sense, but it is early days of the concept for the customer class.

“Emerald AI is positioning itself to be this interface layer between the data centers and the power grid,” Coskun said. “Traditionally, there wasn’t a ton of communication between the power grids and the data centers, but as we design our data centers in a smarter and more flexible way, we believe there’s going to be this communication and programs may evolve. … There’s a ton of mechanisms that are existing in power markets that are not heavily used by data centers.”

The exciting thing about the Aurora facility is that it is being developed from the ground up for flexibility, which normally is an afterthought for data centers, EPRI Emerging Technologies Executive Anuja Ratnayake said in an interview.

EPRI’s DCFlex initiative was started to help the power industry meet the fast-growing demand for electricity from their expansion. The program also is working on real-world demonstrations at data centers in North Carolina and Arizona, the latter of which also includes Emerald.

“The major challenge for the industry is powering the data centers that are coming up at the moment, and the challenge comes from the scale and the pace of the growth in the data center sector,” Ratnayake said. “For the last 20-plus years … data centers grew up for enterprise purposes and for social media purposes and then for cloud purposes. What we are seeing happening in the last about two years is there is sort of a new type of a data center, which is what Nvidia is terming the AI factories.”

Data centers used to be five or 10 MW on the large side, but now with AI’s need for computing power and the energy to run all those Nvidia chips, it is seeing requests for 500 MW or even 1 GW, which is the size of a major city, she said.

“Think about the grid that is planned around these little loads that come together in the form of a city versus a single point in the grid that represents that same load,” Ratnayake said. “That’s new, and what that means … is the grid has to do a whole host of new investments, both potentially on the generation side and on the grid side.”

It can take up to a decade or more to build new generation and wires, but the data centers want to connect in a year or two, she noted. If data centers can respond and cut the amount of energy pulled from the grid, they can get connected while the grid is being expanded.

“This is that seven- to 10-plus-year period,” Ratnayake said. “During that period, if you’re able to be flexible, we can potentially connect you faster. That’s where the flexibility piece becomes important.”

One of the questions EPRI is studying is how much flexibility data centers might continue to provide to the grid once it has been expanded.

“It will be tied closer to business models more than really the technology viability,” Ratnayake said. “The technology viability will exist forever, but it will be up to the data center operators to really embrace which business model makes the best sense.”

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Landmark Reached in Effort to Reshore Solar Manufacturing

With the start of production at an ingot and wafer factory in Michigan, all components of a photovoltaic solar module now can be sourced from U.S. manufacturers.

Every major piece of the solar supply chain has been reshored, the Solar Energy Industries Association said Oct. 29 as it marked this latest milestone in a solar manufacturing renaissance.

The news comes at a pivotal time for the solar power industry, given the federal policy changes engineered by President Donald Trump that will make solar power more expensive to develop and, in some cases, more difficult to site.

SEIA said 65 solar and storage component production facilities have come online or been expanded in 2025 through an investment of $4.5 billion. But more than 100 manufacturing projects and $31 billion in additional investments are at risk from the Trump administration’s attacks on the solar sector, SEIA added.

U.S. solar generation capacity has been soaring: It accounted for more than half of all new capacity added nationwide in the first half of 2025. Given its relatively low cost and relatively high speed to deploy at a time when other generation is slow and expensive, new solar arrays are not expected to suddenly stop being built. But the rate of growth is expected to slow.

Corning subsidiary Hemlock Semiconductor announced Oct. 30 it had started production in the third quarter at the largest solar ingot and wafer facility in the U.S. and is anticipating a steady stream of revenue from it, as it accelerates production from thousands of wafers per day to more than 1 million per day through the fourth quarter.

The new ingot and wafer factory is co-located with the Hemlock, Mich., polysilicon facility owned by Corning, which plans to build its solar business to a $2.5 billion annual revenue stream by 2028.

Corning said it has secured purchases of more than 80% of available polysilicon and wafer capacity for the next five years.

Hemlock said solar wafers have not been produced in the U.S. in nearly a decade. In its announcement, the company quoted Moustafa Ramadan, head of market research at PV Tech Research: “For the first time, a module can be completely U.S.-made, from polysilicon to the module. This is probably the first time in a long time that this is possible. It might not be sufficient to meet demand, but it is a big step for U.S. manufacturing.”

SEIA framed the development as a variation on the renewables-are-good-for-America theme the U.S. clean energy sector began broadcasting late on Election Day 2024, after Trump was elected on a pro-fossil fuel platform.

“This growth is a testament to the power of American innovation,” SEIA President Abigail Ross Hopper said in a news release. “We’re building factories, hiring American workers and showing that solar energy means made-in-America energy.”

But she added a caveat: “This industry has proven what’s possible when businesses have the certainty to invest. If the administration does not reverse their harmful actions that have undermined market certainty, energy costs will rise even further, and the next wave of factories and jobs could be at risk.”

In its latest update, SEIA’s Solar & Storage Supply Chain Dashboard shows $36.6 billion in U.S. solar manufacturing investments publicly announced since supportive federal policy changes in 2022 — $13.1 billion of which are operational, and $9.2 billion of which are under construction.

These facilities were expected to create 50,100 manufacturing jobs — 23,321 at facilities that are operational and 7,700 at facilities under construction.

Of the storage facilities announced since the Inflation Reduction Act’s passage, 21.8 GWh of battery cell and 69.4 GWh of battery pack manufacturing capacity have come online. Production facilities for components such as solar mounting systems, power electronics and grid technologies also have come online.

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J.H. Campbell Tab Rises to $80M on DOE’s Stay Open Orders

The J.H. Campbell coal plant in Michigan has racked up $80 million in net costs since late May to stay online, per emergency orders from the U.S. Department of Energy.

Plant owner Consumers Energy reported in an Oct. 30 filing to the U.S. Securities and Exchange Commission that from May 23 through Sept. 30, the costs of keeping the 1,420-MW plant online were about $164 million, with the utility offsetting $84 million with revenue from selling the plant’s output in the MISO markets.

J.H. Campell now costs more than $615,000 per day to operate since DOE issued its first emergency order to prevent the plant’s retirement as scheduled May 31. The plant now is operating under a second emergency order that expires Nov. 19. (See DOE Orders Mich. Coal Plant to Remain Available Another 90 Days.)

Consumers Energy divided the costs of running the plant into the two timespans of the emergency orders. From May 20 to Aug. 20, costs swelled to $120 million, with $67 million in revenues, leaving $53 million to be paid. From Aug. 21 through Sept. 30, costs reached $44 million, with power sales covering $17 million, leaving $27 million unpaid.

Consumers Energy will detail the remaining costs associated with the second DOE order in its next quarterly filing, due to the SEC in late January 2026.

Earthjustice senior attorney Michael Lenoff said DOE’s orders that the Campbell plant remain accessible are “extremely expensive.”

Earthjustice, the Sierra Club, Michigan Attorney General Dana Nessel and others are suing DOE, arguing separately that ratepayers are unfairly expected to pay for the plant’s expenses. (See Opponents Take DOE to Court over J.H. Campbell Retirement Delay.)

“Forcing this unnecessary coal plant to keep operating is bilking consumers for the benefit of the coal industry. Earthjustice is in court now to stop the administration from harming consumers, trampling markets and unlawfully usurping the authority of states and regulators to make decisions in the public interest,” Lenoff said in a statement.

Numbers from EPA’s Clean Air Markets Program Data show that J.H. Campbell’s three units were not consistently generating from July to September, when Unit 1 did not produce power on 25 of the 92 days; Unit 2 was dormant 74 of 92 days; and Unit 3 did not produce power 29 of 92 days.

Several organizations continue to argue that DOE’s pair of orders remain unnecessary.

In a September rehearing request challenging the second DOE order, Earthjustice and several other public interest groups argued that even on June 23, MISO’s tightest reserve margin day of the summer, the RTO had 3.3 GW of offers above what it needed to meet its 119-GW peak demand, with an additional 7 GW of emergency headroom from resources on standby. The groups argued that the “primary actors in the electric industry already protect resource adequacy without intrusion” from DOE (202-25-7).

The cost of operating the plant is set to be paid by ratepayers across MISO Midwest. (See FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States.)

Minnesota Public Utilities Commissioner Joseph Sullivan said DOE is infringing on state jurisdiction by ordering the plant to be kept online in rolling, 90-day increments. Sullivan told the MISO Board of Directors Sept. 18 that Consumers Energy, the state of Michigan, MISO and the Independent Market Monitor all agree that J.H. Campbell was “properly planned for retirement and not needed for reliability.”

DOE claims it’s directing not states but MISO and FERC to keep the plant open. Sullivan said DOE relied on MISO’s previous warnings that resource adequacy was in peril despite the 2025/26 capacity auction clearing sufficient resources.

“We need to be careful with our narrative,” Sullivan said. He warned MISO against assuming retiring generation won’t be replaced or presuming that new load would be brought onto the system without the resources to support it.

The Michigan Public Service Commission in late August accepted annual capacity demonstrations from Michigan’s electric utilities, indicating that each has enough capacity to meet customer needs four years into the future (U-21775).

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DTE Energy Lands 1.4-GW Hyperscaler Agreement

DTE Energy has secured its first hyperscaler agreement and says it has enough excess capacity to power the 1.4-GW data center load without new construction.

The Michigan utility said it does plan to add 1 GW of storage capacity in connection with the hyperscaler project in a peak-shaving role, but the customer will cover the cost.

However, if DTE secures the other data center agreements it is negotiating, it will need to add capacity.

In its third-quarter earnings report Oct. 30, DTE said it is boosting its five-year capital investment plan from $30 billion to $36.5 billion and allocating almost all of the additional $6.5 billion to its electric business to support data center development and the transition to cleaner power generation.

CEO Joi Harris said during an earnings call with financial analysts that DTE is in late-stage negotiations with other hyperscalers for about 3 GW of new load and it has potentially 3 to 4 GW in other data center opportunities further down in the pipeline.

DTE is looking at new gas-fired generation for some of this load.

Harris said DTE already is in the manufacturing queue for a combined-cycle gas turbine to replace the coal-fired Monroe Power Plant, which is slated for retirement as DTE works toward a complete exit from coal by 2032. The new gas facility will cost about $2.5 billion, or $2,500/kW, she said.

Additional combined-cycle gas turbines will be needed for new gigawatt-scale data centers, Harris said, but new demand from smaller data centers could be met with a mix of renewable and fossil generation and storage.

The wait time now is three to four years for a new combined-cycle gas turbine, she said, but less for smaller-scale gas generation equipment.

DTE expects to have a better picture of what mix of generation it needs once it firms up negotiations with some of the other potential large-load customers and knows what their anticipated ramp rates are. It plans to provide more details in its next integrated resource plan.

But the utility does anticipate the need for greater generation capacity — the 1.4-GW hyperscaler project alone will result in a 25% increase in load as it ramps up over the next two to three years, Harris said.

DTE will submit the hyperscaler contract for regulatory approval Oct. 31. It includes a 19-year power-supply agreement with minimum monthly charges.

The hyperscaler also will pay for the new energy storage through a 15-year contract. Two-thirds of the new storage capacity will be met with construction to start in 2026; the remainder will be met through tolling agreements.

Nationally, hyperscaler proposals drawing as much power as a small city have consumer advocates fretting over the impact on electric rates.

But Harris presented DTE’s 1.4-GW data center deal as a win for existing ratepayers, as they won’t have to pay for infrastructure up front or face the prospect of paying for stranded assets down the road.

“We don’t have to build anything substantial to support the load,” she said. “We’re using our excess capacity to support the load and building batteries on top of it, just for peak-shaving purposes. And the customers get that full benefit, so it will show up in the form of a lower ask over our next rate case cycle.”

The 1.4-GW agreement also will help drive 6 to 8% annual growth in earnings per share through 2030, Harris said.

DTE reported third-quarter 2025 net earnings of $419 million or $2.01/share on revenue of $3.53 billion, compared with $477 million, $2.30/share and $2.91 billion in the third quarter of 2024.

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MISO Predicts 103-GW Peak for Winter

MISO said even a 109-GW peak this winter shouldn’t prove problematic, though the RTO said a more probable scenario would deliver a 103-GW peak in January.

MISO’s coincident peak forecast from members estimates a 102.6-GW winter peak in January. However, MISO said there’s potential for a 108.9-GW peak using a non-coincident peak forecast.

MISO attracted 123.1 GW worth of offers in its winter capacity auction, with 120.2 GW ultimately clearing. The grid operator also has about 11 GW in load-modifying resources that can assist in an emergency during the season.

At an Oct. 29 Winter Readiness Workshop, MISO Senior Resource Adequacy Engineer Gurman Kaur said MISO believes it has more than enough supply to get through the winter.

However, MISO Director of Operations Risk Management Jason Howard said ongoing fleet change coupled with increasing demand and extreme weather could make for thorny operations.

“The combination of load growth, resource flexibility needs during the riskiest times of the day and the ever-present possibility of larger winter storms is our new reality,” Howard said in a press release. “In response to this complex risk environment, MISO is enhancing our forecasting capabilities, dynamic reserves and outage coordination processes to ensure MISO maintains reliability for the 45 million people we serve.”

Howard said MISO would rely on its Forward Reliability Assessment and Commitment system tool, which looks six days ahead to make unit commitments, and would issue grid notices and warnings days in advance when it notices reserves are poised to shrink.

MISO reminded stakeholders that it and its members “reliably and efficiently navigated several significant weather events last winter,” including an arctic 6.5-degree Fahrenheit average footprint-wide temperature Jan. 20-22 that sent systemwide peak demand shooting to 108 GW, with a record-high 33 GW of that from MISO South. (See MISO South Hit Record, 33-GW Winter Peak in Jan. Storm.)

MISO Manager of Operations Risk Assessment Matthew Campbell said during last winter’s trio of storms, MISO maintained consistent communications with members, conducted daily risk assessments and produced net uncertainty forecasts to guide unit commitments.

Campbell noted that the U.S. Energy Information Administration expects coal inventories at power plants to be lower than last winter and “on the lower end of the five-year average.” He likewise said natural gas storage is projected to be lower than a five-year average every month of winter.

MISO said winter 2024/25 — which was colder than usual due to periods of “durable” cold air — is the top comparison to draw on to predict winter 2025/26.

Ella Dankanics, a senior at Purdue University and a meteorological risk analyst for MISO, said the National Oceanic and Atmospheric Administration expects equal chances for MISO Midwest to have a colder- or warmer-than-normal winter. MISO interprets the equal opportunity could mean temperature swings.

Dankanics said warm and cold air could “battle” throughout the season, bringing a greater risk of equipment icing.

NOAA, meanwhile, anticipates above normal temperatures in MISO South. The agency also predicts active storm patterns and higher-than-average precipitation in the Great Lakes region with a drier season near the Gulf of Mexico.

Dankanics said there’s potential for a weaker La Niña weather pattern this winter that creates more opportunities for deep freezes, reinforced by weaker stratospheric winds.

Dankanics said in historical winters with a weak La Niña trend, MISO’s systemwide peak load consistently reached the 95th percentile, or about 97 GW.