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December 15, 2025

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Vistra to Pay $38M to Settle Decade-old MISO Capacity Market Manipulation Case

Vistra has agreed to pay $38 million to wind down a long-running FERC inquiry into whether it manipulated prices in MISO’s 2015/16 capacity auction. 

Vistra, Dynegy at the time of the alleged manipulation, said it’s ready to pay MISO $38 million, which MISO will distribute to net buyers of Zone 4 capacity in downstate Illinois in the 2015/16 auction and to customers of Ameren Illinois that paid the capacity charge resulting from the auction (ER25-3069).  

Vistra settled with complainants Public Citizen, the Illinois Attorney General, Southwestern Electric Cooperative, Illinois Municipal Electric Agency and the Illinois Industrial Energy Consumers. The agreement was struck first at a May 15 in-person settlement conference.  

FERC in 2024 directed hearing and settlement procedures after its Office of Enforcement in 2022 concluded Dynegy took actions to make sure one of its resources set the $150/MW-day clearing price for Southern Illinois to raise profits. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.) Vistra purchased Dynegy in 2018.  

In 2024, Vistra tried unsuccessfully to get FERC to back down on some of the findings from its staff. (See Dynegy Unsuccessful in Rehearing Requests of 2015 MISO Capacity Auction Manipulation Case.)  

Vistra Energy’s Coffeen Power Station in downstate Illinois retired in 2019 | Vistra Energy

The company asked FERC to issue an order approving the settlement agreement on or before Aug. 29. The settlement amount is not subject to additional interest, considering the 10 years that have passed since MISO held the auction.  

“While this figure was determined on a black-box basis, negotiations among the settling parties concerned issues such as the passage of time since Dynegy’s alleged actions, the time-value of money and the commission’s regulations regarding interest, demonstrating the importance to certain of the settling parties of speedy approval of the settlement and disbursement of the settlement amount,” Vistra said of negotiations in its Aug. 1 filing.  

The settlement is a fraction of the $429 million in refunds the Illinois Office of the Attorney General at one point claimed were due to Illinois ratepayers. 

The settlement would release Vistra from all claims of market manipulation and attempts to exercise market power in the Zone 4 auction for the 2015/16 MISO planning year and settle all challenges relating to the clearing price. Vistra said it likewise would withdraw all its appeals stemming from the lengthy case.  

Vistra continues to deny all allegations concerning Dynegy’s conduct.  

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New Report: Battery Storage Pivotal for MISO Savings

A new report shows the MISO footprint could ring up $27 billion in additional system costs through 2050 if it and members miss the boat on developing new gigawatts of battery storage.  

The report, from Austin, Texas-based Aurora Energy Research and commissioned by American Clean Power Association, concluded that without a widespread deployment of battery storage in the Midwest, MISO risks higher costs, less robust reliability and a more drawn-out transition to clean energy. 

Aurora said an 11-GW deployment of new battery storage in the Midwest and Central U.S. by 2035 could save consumers several billion dollars in energy costs and fortify reliable operations.  

Aurora’s modeling showed that without battery storage, MISO’s peak energy prices would climb $159/MWh higher during the times of highest demand by 2035, leading to an excess of $4.5 billion spent over 10 years. It estimated MISO would rely heavily on gas peaker plants to meet a 130-GW demand by then, adding an additional $493 million in energy prices and raising the average cost of peaker-generated electricity by $1.75/MWh. The report concluded more storage resources could slash evening energy price spikes by more than 60% between now and 2035.  

Aurora used a “no battery” scenario for comparison purposes, where it anticipated that only 250 MW worth of battery storage is online in the footprint by 2027, followed by a standstill in battery development thereafter. The research firm assumed natural gas prices would rise to about the $5/MMBtu mark by 2035. It also assumed the extension of production and investment tax credits and introduction of an investment tax credit for battery storage.  

Aurora said the more than $4.5 billion that batteries could save in energy costs by 2035 could reach more than $25 billion by 2050. It said its long-term modeling showed $27 billion in savings versus the no battery scenario, with savings originating from lowered wholesale prices on peak and smaller system costs through the flexibility that batteries can provide. 

Aurora’s two study scenarios through 2035, comparing an 11-GW battery storage buildout in MISO to a ‘no battery’ case. Batteries are shaded in yellow on the bar charts. | Aurora Energy Research

Without more battery assistance soon, the report projected that MISO’s wind and solar generation could be 8 TWh lower by 2035. Aurora anticipated a spike in the RTO’s ancillary service costs, with regulating reserve prices potentially increasing 179%.  

MISO has nearly 1 GW of storage online and registered and has about 70 GW of battery capacity in its generator interconnection queue. More than 25 GW of proposed battery storage projects lined up to connect to the system in 2024 alone. Historically, only about 20% of generation proposals ever make it to interconnection agreements in MISO.  

The planning scenario that MISO based its nearly $22 billion long-range transmission portfolio on in 2024 assumed 20 GW of new four-hour lithium-ion batteries by 2024.  

“There are hundreds of energy storage projects in the MISO project queue, working through their lengthy interconnection and permitting process. These projects represent billions of dollars in economic investment, thousands of jobs and billions of dollars in energy cost savings,” the American Clean Power Association said, urging policymakers to act now to help deploy projects.  

“As power demand surges, battery storage is one of the fastest and most effective ways to strengthen reliability and lower electricity bills,” Noah Roberts, American Clean Power’s vice president of energy storage, said in a press release. “Grid batteries deliver massive cost savings for families and businesses, while ensuring that the grid delivers power when it’s needed most. With more than $25 billion in energy savings at stake, this is a generational opportunity for the Midwest to secure a more reliable and affordable energy future.” 

At a July 30 MISO stakeholder workshop to discuss reliability, Clean Grid Alliance’s David Sapper said he hoped MISO could “do better in terms of fostering” battery storage.  

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Five Republican States File FERC Complaint to Undercut $22B MISO Long-range Tx Plan

Five state public service commissions have banded together to request that FERC order a recasting of MISO’s long-range transmission projects, arguing the projects aren’t as beneficial as MISO has advertised.  

The public service commissions of Arkansas, Louisiana, Mississippi, Montana and North Dakota registered a July 31 complaint. The states, calling themselves the “Concerned Commissions,” said MISO and its Board of Directors violated the MISO tariff when they recommended and approved the second, nearly $22 billion long-range transmission portfolio in late 2024 (EL25-109).  

The five asked FERC to conclude that MISO and its board erred by advancing transmission projects that will cost more than they’re worth, order MISO to reclassify the projects so they’re not regionally cost-shared and direct the RTO to file all future business cases supporting long-range transmission portfolios.  

The state commissions said MISO’s “miscalculation of benefits and a defective business case” convinced its Board of Directors to approve the plan. (See MISO Board Endorses $21.8B Long-range Transmission Plan.) 

The state commissioners argued that MISO’s collection of long-range transmission projects cannot provide benefits “equal to or in excess of forecasted costs” and should thus be reclassified, likely with a different cost allocation method. They said MISO currently has no authority to direct the projects’ construction because the projects don’t meet a required 1:1 benefit-cost ratio. 

The states said other MISO states are free to pay for the projects per the MISO tariff if they need them for decarbonization targets or renewable energy goals.  

MISO estimates the benefit-to-cost ratio of the portfolio to be between 1.8:1 and 3.5:1 over the first 20 service years of the projects, owing to production costs, improved reliability, avoided construction of new capacity and environmental benefits. The grid operator’s planners have emphasized that the benefit values are intentionally conservative. (See $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.) 

However, some states and MISO’s Independent Market Monitor have disputed MISO’s benefit estimates and said they’re overinflated. IMM David Patton appraised the value of the portfolio closer to a 0.3:1 benefit-to-cost ratio and advocated for a condensed portfolio. He repeatedly said the 20-year future MISO relied on to recommend the portfolio of mostly 765-kV lines is impractical and doesn’t represent the resource mix that will be built. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan.)  

MISO and its IMM’s disagreements over the second long-range portfolio culminated in a FERC case itself, where FERC decided that MISO’s Market Monitor was allowed to stray from markets to inspect the value of the RTO’s transmission planning — and get paid for it. (See FERC Sides with Market Monitor over MISO in Compensation Dispute.)  

The five state commissions said MISO ignored its IMM’s guidance while adjusting the benefit metrics it used in its first, $10 billion long-range portfolio in 2022 in an attempt to make the second round of projects look more valuable than it will be.  

Like MISO’s IMM, the states said MISO didn’t give enough thought to the concept that without a backbone network of 765-kV lines, members would build different generating units closer to their load at lower costs compared to the transmission expenses. MISO should not assume that its members would build the same remote generation with or without the portfolio, they said.  

The states also echoed the Monitor’s view that MISO should not have assumed it would have instances of load-shedding at the $3,500-$10,000/MWh value of lost load if it didn’t recommend the lines. They said state officials undoubtedly would take action to mend reliability before it reached that point.  

Finally, the states said it was inappropriate for MISO to use a social cost of carbon to justify transmission investment and said they do not share MISO’s estimation.  

The states argued that if MISO eliminated its overstated benefit estimates of a reliability upsurge and avoided capacity costs and decarbonization, the value of the portfolio would fall to $15.7 billion, far from MISO’s low-end estimate of $51.7 billion. They said with a more realistic view of benefits, the second long-range transmission portfolio would not be able to cover its construction costs.  

The group of states told FERC they are not relying on the $22 billion worth of projects to meet resource adequacy requirements or clean energy goals. Three of the MISO states — Arkansas, Louisiana and Mississippi — are in MISO South and not affected by the second long-range portfolio, whose projects are all in and cost shared among MISO Midwest.  

“These states and their utilities have or are building new generation, either close to load or where existing transmission can provide delivery to load, that is consistent with their integrated resource plans or similar state processes,” the states said, adding that they don’t have use for the additional transfer capability the projects will offer, nor “any interest in subsidizing … costs to advance the clean energy and decarbonization goals of other states in MISO.”  

MISO South Involvement May Presage Cost Allocation Battle

While Arkansas, Louisiana and Mississippi are not included in the cost allocation for the long-range transmission portfolio so far, the complaint could have implications for future long-range transmission projects prescribed for MISO South.  

MISO limited its 100% postage stamp allocation (based on a load ratio share) for the first two long-range transmission portfolios to MISO Midwest, where the projects will be built.  

MISO South won’t be the focus of long-range transmission planning until 2026, when MISO officials said they would begin drawing up early plans. MISO initially pledged to explore the development of a separate cost allocation for the South region, which it says has different priorities, and then insisted that its postage stamp remains the most appropriate mechanism for splitting up transmission costs. (See Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation.) 

MISO South regulators appear to be behind a recent push for the Organization of MISO States to take a stab at proposing a new cost allocation for MISO’s long-range projects. If efforts prove unsuccessful, the postage stamp design could become a backstop. (See State Regulators Weigh Drafting Alternative to MISO Tx Cost Allocation.)  

MISO South never has been the site of construction for a regionally cost-shared transmission project. MISO has said it could spend up to $100 billion across its long-range transmission portfolios. To date, it has designated $33 billion only in MISO Midwest. Multiple nonprofits and consumer advocates alongside former FERC Commissioner John Norris have called on MISO to start assembling a long-range plan for MISO South. (See MISO Says Public Communication Needs Work After NOLA Load Shed.)  

At a July 30 MISO stakeholder workshop to discuss reliability, MISO transmission planning lead Laura Rauch said she “would still be very comfortable testifying” to the benefits of the nearly $22 billion long-range transmission plan, even with the rollback of federal incentives for clean energy. 

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Newsom Reiterates Support for Western Regional Market Push

California Gov. Gavin Newsom reiterated support for the proposed bill that would allow CAISO to relinquish market governance to an independent “regional organization” (RO), saying during a July 31 press conference that the legislation can reduce electricity costs and improve reliability.

In a LinkedIn post, the California Community Choice Association (CalCCA) said the governor expressed his support for SB 540 during a press conference. The governor’s office confirmed with RTO Insider that Newsom supports the efforts but noted that it “may not be SB 540 itself — could be a different vehicle.”

Newsom commented on regionalization efforts during the press conference, saying “this is a very significant legislative effort that can actually impact the cost of electricity in this state, improve our reliability, mitigate the impacts on our access to supply, particularly during extreme heat events.”

Newsom said the effort is about California’s ability to maintain its authority to set its own “low-carbon green growth goals,” and referenced amendments aimed at limiting the federal government’s ability to intervene in those.

The governor praised the coalition behind the bill, saying it “is really with few precedents. I’m not aware of a more diverse and large coalition I’ve seen on an issue of energy in some time.” Backers of the bill include the state’s labor unions and publicly owned utilities, groups that strongly opposed previous efforts to “regionalize” CAISO, as well as CalCCA.

“I am supportive, directionally, and I look forward to the final product … that lands on my desk subject to final review of any amendments that will be made over the course of the next few weeks,” Newsom said.

Newsom previously signaled his support for efforts to expand California’s involvement in regional electricity markets. When RTO Insider asked the offices of Newsom and Assembly Speaker Robert Rivas (D) about the potential for other strategies that don’t include SB 540, including adding the bill’s provisions to another proposed piece of legislation, both declined to comment.

However, a source in the governor’s office told RTO Insider that the administration will not take the lead on the bill but will defer to the legislature.

SB 540, which passed in the California Senate in June, was set for a first hearing in the Assembly’s Utilities and Energy Committee on July 16 but was delayed until after the legislature’s summer break at the request of the bill’s author, Sen. Josh Becker (D). (See Calif. Pathways Bill Delayed After Orgs Withdraw Support, While Newsom Signals Backing for Effort.)

The delay came after 21 organizations pulled their support for the bill following an amendment that would establish a new Regional Energy Market Oversight Council responsible for ensuring CAISO’s participation in the regional energy market “serves the interests of the state.” The new council would be authorized to mandate withdrawal if those interests are compromised.

The coalition requested lawmakers remove the amendment, stating “the language in this section mandates the withdrawal of California entities from the market without exception or discretion, which is unacceptable.”

SB 540 is a result of the work of the West-Wide Governance Pathways Initiative, an effort to create an independent RO to govern CAISO’s Western Energy Imbalance Market and the soon-to-be-launched Extended Day-Ahead Market (EDAM). The effort aims to assuage concerns that the ISO — whose Board of Governors are appointed by California’s governor — would act primarily in the state’s interest.

Robert Mullin contributed to this story.

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N.Y. Makes Case for Extending Nuclear Subsidies to 2049

The New York Department of Public Service proposes the state extend its subsidy program for its commercial nuclear facilities from 2029 to 2049 to help ensure the operators of America’s two oldest reactors seek to relicense them. 

The move was not a surprise: Nuclear generation has less-than-unanimous support in the Democratic-led state, but there is wide recognition that the four operating reactors are a critical part of New York’s effort to reduce carbon emissions and an important part of the energy portfolio. 

The Public Service Commission took steps May 15 to reinvigorate New York’s lagging progress on its clean energy initiatives (Case 15-E-0302), including a neutrally worded directive to the DPS staff to evaluate how a continuation of the nuclear Zero Emission Credit program might be structured. (See N.Y. Moves to Boost Lagging Clean Energy Development.) 

The staff submitted the ZEC report July 31. It recognizes the economic and environmental importance of the existing nuclear fleet and recommends continuing the ZEC program with the same formula methodology and general structure, though with some revisions and potential for early termination, should the parameters on which it’s based change significantly. A public comment period will open for the report. 

From the 2017/18 budget year through 2023/24, $3.69 billion in ratepayer-funded ZECs have been paid to nuclear operators. The program terminates at the end of the 2028/29 budget year; the staff proposal would extend it to 2048/49. 

Constellation Energy’s Ginna, FitzPatrick and Nine Mile 1 and 2 reactors provided 22.2% of the electricity produced in New York in 2023 and nearly half its emissions-free electricity. Comparable fossil-fired generation would emit about 15 million tons of carbon per year. 

The long-running state plan to bring large amounts of emissions-free wind and solar online has been progressing slowly and is facing significant new challenges under the Trump administration. 

Further, these renewables are intermittent and highly variable — particularly solar, which drops to single-digit capacity factors in New York’s cloudy winters. By contrast, the four nuclear reactors have capacity factors in the mid 90% range. 

They also are expensive to operate. Then-owners Entergy and Exelon made plans to shut down FitzPatrick and Ginna in the mid-2010s because they were not economical, and Nine Mile was facing the same pressures, the report notes. This was the impetus for the ZEC program. 

Another issue facing New York’s fleet is its age. The reactors have been in service for an average of 50 years, and Nine Mile Unit 1, which entered commercial service in December 1969, has the distinction of being the nation’s oldest operating reactor. 

Its license, already renewed once, will expire in August 2029, and Constellation has an August 2026 deadline to apply for a second renewal. Ginna’s license expires in September 2029. It is the nation’s second-oldest operating reactor, and the deadline to seek relicensing is September 2026. 

The decision to invest in such facilities or continue their operation typically relies on certainty that the investment will be recouped, whether through public subsidies or private power purchase agreements. The 2049 sunset date in the new ZEC proposal is timed to the potentially extended operating life of Nine Mile 1 and Ginna. 

The authors of the DPS staff proposal concluded by saying: “Staff recognizes the complexity in extending a 20-year forward-looking program that both protects and provides the best value to ratepayers while ensuring the continued operation of necessary zero-emission nuclear resources. Staff believes this proposal effectively balances the interests of ratepayers and ensures the Upstate nuclear facilities pursue a subsequent license renewal.” 

Constellation and New York in January said they are collaborating to seek funding for early permitting for one or more advanced nuclear reactors that would be co-located with Nine Mile. 

In June, Constellation applauded Gov. Kathy Hochul (D) on her announcement that the state would seek to add at least 1 GW of advanced nuclear capacity to the grid. (See N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.) 

“It is yet another recognition of nuclear energy’s critical role in achieving the nation’s leading clean energy goals,” Constellation said. “We look forward to working with the governor and state leaders to ensure nuclear energy continues to power economic growth and a clean, affordable and reliable energy future for New York.” 

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Southern Expects Large Load Growth to Continue

Southern Co. CEO Chris Womack said during the company’s quarterly earnings call July 31 that “the economy in the Southeast” remains well positioned to support continued load growth. 

Net income for the second quarter came to $880 million ($0.80/share), down from $1.2 billion ($1.10/share) in the second quarter of 2024. Year-to-date net income was $2.2 billion ($2.01/share), down from $2.3 billion ($2.13/share) in the same period in 2024. 

Operating revenue for the quarter stood at $7 billion, up from $6.5 billion for the second quarter of 2024; year-to-date operating revenue also grew, from $13.1 billion to $14.7 billion. Operating expenses for the quarter were $5.2 billion, up from $4.5 billion, and year-to-date were $11 billion, up from $9.5 billion. 

CFO Dan Tucker, attending his last earnings call before his retirement, said adjusted earnings per share for the quarter came to 92 cents, 18 cents lower than the same period last year but 7 cents above the company’s estimate. Tucker said, “Increased earnings from investments in our state regulated utilities, along with higher usage and customer growth,” contributed 6 cents year over year compared to 2024. 

Weather-normal retail electricity sales were up 3% “across all customer classes” for the quarter compared to the same period last year, Tucker continued. Residential sales grew 2.8% thanks to both “the addition of over 15,000 new electric customers … and higher overall use per customer.” 

Commercial and industrial sales grew 3.5% and 2.8% respectively, which Tucker attributed to growth in data center usage, which was up 13% from last year. Transportation and primary metals were both up 6% as well, and paper was up 16%. 

Womack mentioned the data center sector as one where expansion is expected to continue in the Southeast, along with the aerospace and automotive industries. In all, he pointed to nearly $2 billion of capital investments announced during the second quarter across Southern’s service areas. 

He also said Southern is working to position itself for this expansion, pointing to an agreement reached in May between Georgia Power and the Georgia Public Service Commission to extend the utility’s 2022 alternate rate plan through 2028. He said this move would preclude the need for a 2025 base rate case filing and keep the “base rate stable and predictable over the next three years … with the exception of any future recovery of storm-related costs.” 

“Overall, this outcome demonstrates our commitment to capturing the benefits of this robust projected economic growth and prioritizing customer affordability,” Womack continued. “We believe this outcome, which preserves the existing regulatory framework in Georgia, benefits all stakeholders. Our vertically integrated market and constructive, orderly regulatory processes continue to help ensure we have the critical resources necessary to reliably and affordably serve our growing states.” 

Tucker’s successor as CFO, David Poroch, also joined the call to discuss the company’s capital investment plan, which earlier in 2025 was announced to total $63 billion over the next four years. (See Strong Southeast Economy Bolstered Southern Co. Growth in 2024.)  

Poroch said the total planned investment has grown to $76 billion, $10 billion of which is associated with planned resource additions of at least 6 GW that Georgia Power filed with the PSC earlier in 2025; $2 billion is attributed to modernization and updates to the existing fleet; and $1 billion for repowering three wind facilities, expected to be completed by the first half of 2027. 

Southern is projecting adjusted earnings per share of $1.50 for the third quarter of 2025, and $4.20 to $4.30 for the full year. 

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SPP’s Rew to Retire After 35 Years in Operations

SPP’s longest-tenured employee, Senior Vice President of Operations Bruce Rew, will retire in December after 35 years with the grid operator.

Rew will be replaced by C.J. Brown, who will become vice president of operations on Oct. 1. SPP said the overlapping months will ensure a smooth transition.

“We can’t begin to thank Bruce adequately for his three-plus decades of service to SPP,” COO Antoine Lucas said in a press release. “He’s incredibly valued and well respected across the board for his leadership and dedication. For years, he’s driven successful development of innovative services and projects for our members.”

Rew joined SPP in 1990 after graduating from college and serving in the U.S. Air Force on a nuclear missile launch crew. He was one of the 14 staffers on hand — they are memorialized in a photo displayed inside its Little Rock, Ark., headquarters — when the organization officially became an RTO in 1994.

Bruce Rew | © RTO Insider 

During his time with SPP, Rew helped the Regional State Committee develop a process for allocating transmission costs regionwide, drafted tariff language allowing customers to fund transmission projects, and implemented the grid operator’s first energy management and tariff-billing system.

“I retire with gratitude for the more than 35 years working together with SPP members,” Rew said. “The services SPP provide have changed dramatically over that time, but the power of relationships has remained a constant driving force for our region.”

The position oversees SPP’s regional operations center, from where staff coordinate the operation of the bulk power system across a 14-state region. The operations organization includes engineering, business support and real-time grid operator functions.

Lucas said the SPP “will remain in excellent hands” with Brown, who currently serves as senior director of system operations policy and performance support. The 19-year veteran has managed the RTO’s grid operations through some of the most challenging conditions in the region’s history. He has helped navigate three winter storms since 2021 and summer seasons with historically high temperatures and electricity use.

“It’s a true honor to be selected to step into the VP of operations role and follow Bruce, who has been a pillar at SPP,” Brown said.

He will report to Lucas after having reported to Rew for eight years.

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PG&E Data Center Proposals Nearly Double in 2025 to 10 GW

Data center applications are piling up in Pacific Gas and Electric’s territory with some of the new load projected to come online in 2027.

PG&E now has applications for about 10 GW of new data center load, up from about 5.5 GW at the end of 2024 and 8.7 GW in May.

“Once people found out that PG&E was ready to serve, the applications came rolling in,” CEO Patricia Poppe said during the company’s July 31 earnings call.

Poppe called the volume of data center demand growth “Goldilocks growth: not so much to be a problem, and yet enough to be beneficial for all of our customers.”

Of the proposed 10 GW, about 8.4 GW are in the application and preliminary stage, 1.5 GW in final engineering and 0.5 GW under construction.

Data center load growth could allow PG&E to use more of its existing power infrastructure, which would spread the fixed costs of operating and maintaining the grid over more units of energy and allow the utility to increase its average grid utilization rate, PG&E said in a July 31 press release.

Ten gigawatts of data center load could lead to lowering customer electric bills by 10% or more and generate $1.25 billion to $1.75 billion in increased property tax revenue, the utility claimed in the release. That volume of load is enough energy to power about 7.5 million homes, PG&E said. There are currently about 14.8 million housing units in California, according to the U.S. Census Bureau.

During the call, a participant asked Poppe to provide more information about proposed data center projects in San Jose. Poppe said PG&E has worked with city officials to accelerate permitting and construction.

“Construction and preparation will take most of 2026, then we see that pipeline both in San Jose and throughout the rest of the [PG&E] service area taking shape 2027, 2028 [and] 2029,” Poppe said. “We would see the rate benefits starting in probably 2027.”

PG&E’s new data center demand numbers are dramatically higher than what the California Energy Commission forecasted in its 2024 Integrated Energy Policy Report, which showed data center peak demand of about 2.8 GW in PG&E’s territory under the “high” case in 2040.

Last week, the California Public Utilities Commission partially approved a new electric rule that will make it easier for data centers and other large customers to complete transmission connection projects in PG&E’s territory. The new rule, Electric Rule 30, will help address the increase in PG&E’s retail customer transmission interconnection demand. PG&E has received 40 transmission connection applications since 2023. (See CPUC OKs New PG&E Rule to Speed Tx Connections for AI Data Centers, Others.)

PG&E earned $521 million in the third quarter ($0.24/share), up $1 million from the same period a year earlier.

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AEP, Xcel ‘Navigate Rapidly Evolving Energy Policy’

Two of the electric utility industry’s leading companies, American Electric Power and Xcel Energy, say clean energy projects are still a part of their plans, despite the hurdles placed in front of them by the federal government’s budget reconciliation law. 

Xcel CEO Bob Frenzel told financial analysts during the company’s quarterly earnings call July 31 that with renewable tax credits “front and center” during the debate on the legislation, “we expected limitations to credit.” He said the company expects to need between 15 and 29 GW of new generation before 2031, with a “significant amount” that could be sourced from wind and solar. 

“We’re navigating rapidly evolving energy policy landscape while we predominantly navigate resource plans and transition initiatives at a state level,” he said. “We’ve been working with our state commissions and other stakeholders on the substantial generation required in our operating regions. 

“Accordingly, we’ve already invested substantial capital and/or physically commenced construction of the clean energy resources included in our base capital plan as well as enough to execute on our incremental investment pipeline. … We’ll continue to monitor executive orders, agency rulemakings and trade and tariff actions, and make adjustments as needed as we continue to develop the energy assets that we need in our region.” 

AEP CEO Bill Fehrman had the same message during his company’s second-quarter earnings call July 30. He said the legislation “currently supports” all of the company’s $9.9 billion, five-year capital plan for wind and solar generation and maintains the “required criteria to capture the full tax credits.” 

Still, the company is “closely monitoring” and will assess the potential effect on tax qualification of President Donald Trump’s July 7 executive order implementing the law that further curtailed federal subsidies on wind and solar. (See U.S. Clean Energy Sector Faces Cuts and Limitations.) 

“Even if the U.S. Department of the Treasury issues new guidance under the order that redefines the beginning of construction criteria, we currently expect that only a few projects at the back end of the plan may need to be reassessed for tax-credit eligibility,” Fehrman said. 

Both companies told analysts that they plan to increase their capital expenditures in the face of electricity demand that is projected to surge as much as 35 to 50% by 2040. 

Xcel said it will likely need an additional $15 billion capital investment in addition to the $45 billion, five-year plan it outlined in fall 2024 to strengthen its infrastructure. It filed a generation plan in June for its Southwestern Public Service Co. subsidiary for 5.2 GW of generation and storage, much of it company owned and operated. 

AEP said it plans to announce about a 30% increase in its five-year capital plan, from $54 billion to approximately $70 billion, during its third-quarter conference call this fall. Fehrman said the company will allocate the incremental capital to transmission (50%), generation (40%) and distribution (10%). 

“Demand for power is growing at a pace I have not seen in my 45-year energy career,” Fehrman said. 

“We believe that we’re in the early stages of an infrastructure investment cycle in the United States that will define many industries for decades,” Frenzel said. “Not just the often-discussed AI boom; we see potential investment in onshoring and reshoring of manufacturing and other energy-intensive industries.” 

Earnings Results

Columbus, Ohio-based AEP reported earnings of $1.23 billion ($2.29/share), compared to $340 million ($0.64/share) for the same period a year ago. 

Fehrman said the company’s operating earnings of $1.43/share were the company’s “strongest ever” for a second quarter in its 100-year history. It also beat the Zacks Consensus Estimate of $1.28 by 11.7%. AEP’s stock price closed July 31 at $113.14, up $3.89 (3.6%) from its July 29 close. 

Xcel reported second-quarter earnings of $444 million ($0.75/share), reflecting increased recovery of infrastructure investments that were partly offset by higher interest charges, depreciation, and operations and maintenance expenses. 

The company beat the Zacks Consensus Estimate of $0.63/share by 19.05%. Xcel’s stock price closed July 31 at $73.44, up $1.05 on the day. 

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WEIM Q2 Benefits Exceed $420M, as Total Tops $7.4B

CAISO’s Western Energy Imbalance Market (WEIM) provided participants with $422.44 million in economic benefits during the second quarter of 2025, up 15% compared with the same period year earlier despite no change in membership. 

Cumulative benefits since the 2014 launch of the market reached $7.41 billion, according to the benefits report released by the ISO on July 31. The WEIM has over time expanded to include 22 participating balancing authority areas — including CAISO — representing more than 80% of load in the Western Interconnection. 

“The quarterly benefits have grown over time as a result of the participation of new BAAs, which results in benefits for both the individual BAA but also compounds the benefits to adjacent BAAs through additional transfers,” CAISO said in the report. 

NV Energy raked in the largest share of benefits, at $84.12 million, followed by Public Service Company of New Mexico ($48.96 million), Balancing Authority of Northern California ($35.86 million), PacifiCorp ($33.02 million), Los Angeles Department of Water and Power ($32.17 million) and Salt River Project (SRP) ($30.01 million). Nearly all those participants have committed to joining CAISO’s Extended Day-Ahead Market, except for SRP, which plans to join SPP’s Markets+. 

Maintaining a pattern of second-quarter market performance, solar-heavy CAISO was by far the largest net exporter of energy, with about 2.55 million MWh, down nearly 11% from a year earlier. PacifiCorp was the next largest next exporter at 931,263 MWh from both its East and West BAAs, followed by NV Energy (648,995 MWh), SRP (347,571 MWh), Puget Sound Energy (256,891 MWh) and the small Avangrid BAA in the Pacific Northwest (213,961 MWh). 

PacifiCorp was the largest net importer at 659,549 MWh, followed by CAISO (641,660 MWh), Powerex (611,111 MWh) and SRP (603,028 MWh). 

In the WEIM, a net export represents the difference between total exports and total imports for a BAA during a particular real-time interval, while a net import represents the inverse, meaning that a BAA can be both a heavy exporter and importer over an extended period based on varying momentary needs and trading positions over that period. 

CAISO was also the site of the greatest volume of wheel-through transfers during the quarter at 581,943 MWh. The next largest amount of such transfers went through Arizona Public Service (413,625 MWh), NV Energy (388,671 MWh), PacifiCorp-West (384,732 MWh) and Idaho Power (233,497 MWh). 

The ISO also noted that avoided renewable energy curtailments from WEIM operations reduced greenhouse gas emissions by 112,712 MWh over the quarter, displacing an estimated 48,241 metric tons of CO2 emissions from thermal sources that would have otherwise been needed to produce energy. Since 2015, the market has helped reduce CO2 emissions by more than 1.12 MT, the ISO said.