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December 6, 2025

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Dominion Reports on CVOW Progress, Data Center Growth in Q3 Earnings

Dominion Energy reported $1 billion in net income in the third quarter, which saw it remain on track with its offshore wind project while its pipeline of data center customers grew yet again.

The Coastal Virginia Offshore Wind (CVOW) project should see its first turbine installed later in November, with the first power delivery expected in the first quarter of 2026, Dominion CEO Robert Blue told analysts during a conference call held Oct. 31. Additional strings of turbines will be installed until the project’s completion target near the end of 2026.

“The project is now two-thirds complete and just a few months away from delivering much needed electricity to our customers,” Blue said.

While the project’s progress is on schedule now, analysts wondered if the upcoming gubernatorial election could throw it off. Gov. Glenn Youngkin (R) is term limited, and U.S. Rep. Abigail Spanberger (D) is leading in polls ahead of Election Day on Nov. 4.

All the candidates running for statewide office support CVOW, but one analyst asked what risk the project faced with a Democrat likely to become governor given how the Trump administration has treated offshore wind and other energy projects in Democratic-led states.

“It’s the fastest way to get 2.6 GW on the grid that’s going to serve AI and technology companies, defense security installations,” Blue said. “It’s critical to important infrastructure upgrades at the Oceana Naval Air Station. And if you stop it now, it causes energy inflation. So, it’s not surprising that we’re seeing bipartisan support at all levels of government, and we expect that to continue after the election.”

Dominion is also facing some delays in getting the ship it had built to install many of the wind plant’s components — the Charybdis — to work. The vessel is compliant with the Jones Act, which requires U.S.-owned and crewed vessels when sailing domestically, and was meant to “derisk” construction.

“This is the first Jones Act-compliant wind turbine insulation vessel to be built in the U.S. and subject to U.S. regulatory oversight,” Blue said. “It’s a big ship. It’s 472 feet long. It’s 184 feet wide. It weighs 27,000 tons. It’s got some complex systems on it. It’s got a 2,200-ton capacity crane. It’s got a jacking system that’s capable of creating a 40-meter air gap under the hull when the ship is jacked up.”

It was delivered to Portsmouth, Va., in October. Regulators there identified some issues that needed to be fixed before it can get to work. Regulators had concerns with the electrical systems, which Dominion’s workers are painstakingly reviewing, and some documentation issues, Blue said.

“To date, we’ve done over 4,000 inspections across 69 electrical systems, including 1,400 cable inspections,” Blue said. “We’ve got 200 people working around the clock. Of that original 200 punch-list items, we’ve closed out about 120, so it’s important to know not all those items are created equal. Some punch-list items are a little more complex and will take longer to resolve, but the progress has been really good.”

While for now Dominion expects CVOW to be fully installed by the end of 2026, the Charybdis’ issues could push that back to early 2027, Blue said.

Dominion now has 47 GW of data centers at various levels of development in its pipeline, which is up from 40 GW at the end of 2024, Blue said. The biggest chunk of those, 28.2 GW, is in the least-certain category, defined as only asking for an engineering study from the utility.

An additional 9 GW have signed a construction letter of authorization, which means Dominion can start work on upgrading infrastructure and the data center has to pay even if it walks away. And 9.8 GW have signed an electric service agreement, which defines how the data center will take service and lays out cost recovery.

“We welcome these customers to our system and recognize the vital contribution data centers make to national, state and community success,” Blue said. “We’re developing resources across distribution, transmission and generation to ensure we meet this critical need on a timely basis, while also taking active steps to safeguard all of our customers from the risk of paying more than their fair share for reliable and affordable electric service.”

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WRAP Wins Commitments from 16 Entities

Sixteen entities have committed to participating in the Western Resource Adequacy Program’s first financially “binding” season covering winter 2027/28, the Western Power Pool said Oct. 31 — the deadline for participants to commit to the program.

“As of the deadline, there are 16 current participants that will remain in the program for binding operations, including five in addition to the 11 who sent a commitment letter last month, and we expect more companies to join in the future,” WPP said in a notice posted on its website.

The committed participants include:

    • Arizona Public Service
    • Avista Corp.
    • Bonneville Power Administration
    • PUD No. 1 of Chelan County
    • Clatskanie People’s Utility District
    • Constellation
    • PUD No. 2 of Grant County
    • Idaho Power
    • NorthWestern Energy
    • Powerex Corp.
    • Puget Sound Energy
    • Salt River Project Agricultural Improvement and Power District
    • Seattle City Light
    • Tacoma Power
    • The Energy Authority
    • Tucson Electric Power

WPP said the participants “bring significant load (over 58,000 MW in peak load) and resources and a large, diverse geographic footprint, making WRAP one of the largest RA programs in the country and giving us critical mass for a binding program.”

New commitments after the initial 11 include Constellation, Grant County, Idaho Power, Seattle City Light and The Energy Authority. WPP noted the full group “includes members committed to or leaning toward” either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, “as well as some who have not indicated they will join a day-ahead market.” SPP is operating the WRAP on behalf of the WPP and its Markets+ day-ahead platform, which requires members to participate in the program.

The Oct. 31 announcement marks the conclusion of a tumultuous October for the WRAP. The month began with PacifiCorp asking the WPP’s board of directors to delay the program’s binding phase by at least one year to deal with uncertainties around the program, followed by a similar request from Portland General Electric (PGE). (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

Early October also brought news of NV Energy’s intent to withdraw from the WRAP, a move the utility explained to the Public Utilities Commission of Nevada in an Aug. 29 filing that didn’t come to light until the regulator resolved issues with its website. (See NV Energy to Withdraw from WRAP.)

Then came the development, revealed by NV Energy, that future EDAM participants already have begun discussions about developing an alternative to WRAP. (See EDAM Participants Exploring Potential New Western RA Program.)

Just ahead of the deadline, NV Energy, PacifiCorp and PGE issued letters notifying WPP of their withdrawal, along with Calpine, Eugene Water & Electric Board (EWEB) and Public Service Company of New Mexico (PNM). (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits and PacifiCorp Next to Leave WRAP After Raising Concerns.)

Among the five utilities withdrawing from the WRAP, four (NV Energy, PacifiCorp, PGE and PNM) have committed to joining the EDAM, while EWEB will be participating in Markets+ by virtue of its location with the Bonneville Power Administration’s balancing authority area.

Of the 16 committing to the first binding season, just two — Idaho Power and Seattle City Light (SCL) — have expressed leanings in favor of EDAM, although SCL’s geographic position adjacent to future Markets+ members — including BPA — could make participation in the CAISO market a challenge.

In an Oct. 30 letter affirming SCL’s commitment to WRAP, utility Power Supply Officer Siobhan Doherty called the program “a cornerstone for enhancing reliability and coordination across the Western Interconnection” and said the SCL’s participation already has “provided tangible benefits for Seattle and the broader region.”

But Doherty raised a concern shared by some withdrawing participants, saying SCL “continues to closely monitor developments related to planning reserve margin (PRM) volatility in the shoulder months, particularly June and September. We recognize this as an area that could materially affect program outcomes and merits continued refinement.”

California Dreamin’?

The WRAP withdrawals have generated speculation in the Western electric sector about what kind of RA alternative could take shape in the region, including the potential for a program that might include California utilities — and CAISO.

In an email to RTO Insider, the ISO said it recognized that some EDAM participants are exploring WRAP alternatives and acknowledged that “several have approached CAISO with preliminary questions regarding our technical capabilities in this area, and we remain open to those discussions as stakeholder needs evolve.

“Ultimately, decisions about participation in WRAP and any alternative approaches rest with the utilities, their regulators and stakeholders. As with WRAP, any new resource adequacy program will not alter the CAISO Balancing Authority’s existing resource adequacy requirements.”

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Advocates in Massachusetts Continue Push for All-electric Construction

A coalition of municipal officials and climate advocates in Massachusetts are renewing a push for the expansion of a state program allowing a select number of municipalities to ban fossil fuel hookups in new building construction and renovation projects.

The current program, established by a 2022 omnibus climate bill passed in the state, authorizes 10 municipalities to “require new building construction or major renovation projects to be fossil fuel-free,” with exceptions for scientific research and medical facilities.

Prior to the bill’s passage, the demonstration project faced significant opposition from real estate and business groups, who argued it would increase the costs of new construction.

Activists lobbied for an expansion of the program during the 2023-2024 legislative session, facing pushback from energy and real estate companies and groups including National Grid, the Massachusetts Energy Marketers Association and the real estate association NAIOP. (See Massachusetts Considers Legislation to Ban Gas in New Buildings.)

Ultimately, an expansion of the program was not included in a wide-ranging energy bill passed by the state in 2024. Disagreements over gas utility reforms were one of the key points of contention during negotiations between the House of Representatives and Senate, with the latter supporting a more ambitious approach to transitioning away from natural gas.

While an expansion of the demonstration program was not included in the 2024 bill, the legislation included a series of gas regulation reforms intended to rein in spending on pipe replacements and amend gas utilities’ legal obligation to provide gas service to customers. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)

At a hearing held by the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) on Oct. 29, advocates urged lawmakers to expand the cap on the demonstration program from 10 to 20 municipalities.

Proponents’ case for expanding the demonstration project was simple: The cost of all-electric buildings is generally on par with fossil buildings, and building all-electric would avoid costly retrofits in the future. Advocates also highlighted the climate and health benefits of electrifying buildings.

Several advocates cited a 2022 study by the Massachusetts Department of Energy Resources — conducted during the administration of Gov. Charlie Baker (R) — which projected the costs of all-electric homes to be cheaper than the cost of gas homes in most cases.

In 2024, a report commissioned by climate group ZeroCarbonMA found construction costs for all-electric buildings to be within 1% of fossil buildings, and forecast energy costs “to quickly become much more cost-effective than gas under expected emissions regulations and increasing average gas delivery costs.” (See Report Outlines Cost Savings of All-electric Buildings in Mass.)

Recent steps taken by the Massachusetts Department of Public Utilities could also shift the cost calculation in favor of electrification; the DPU has moved to prevent utilities from socializing the costs of new gas hookups across their rate base and has approved a new winter heat pump rate reducing winter costs for heat pump owners. (See Mass. DPU Requires Revisions to Gas Line Extension Policies and Report Details Cost Savings of Heat Pump Rates for Mass. Consumers.)

Katjana Ballantyne, mayor of the city of Somerville, said the city has “has overwhelmingly supported” joining the demonstration project and noted that the City Council in 2023 unanimously voted in favor of adopting a fossil-free building ordinance, though the city ultimately was not included in the program.

“All-electric new construction offers the easiest and most effective opportunity to begin decarbonizing buildings,” Ballantyne said. “The cost of all-electric new construction is level or even less than fossil fuel construction.”

Mark Sandeen, a member of the Lexington Select Board, said the town’s participation in the demonstration program “has been a huge win for affordable housing developers, and perhaps more importantly, for the eventual residents of those homes.”

Jonathan Kantar, manager of a design and construction company and a volunteer member of the city of Newton’s Design Review Committee and Energy Commission, said the city has found that “energy-efficient and all-electric buildings don’t cost any more than fossil fuel alternatives, and sometimes cost less.”

Representatives of groups that typically have opposed electrification requirements did not speak at the TUE hearing, though this does not mean they are not active on the issue.

A 2021 Brown University report on lobbying in the state noted that “major energy and utilities corporations and their trade groups only rarely submit public testimony in opposition to legislation advancing climate action,” but they have found significant success blocking legislation through behind-the-scenes lobbying.

According to state disclosures, over the first half of 2025, National Grid spent about $128,000 on lobbying; Eversource Energy spent $135,000; NAIOP spent $126,000; and the Home Builders and Remodelers Association of Massachusetts spent $61,000.

Sen. Mike Barrett (D), the top senator on the TUE Committee, said he is “starting to see significant indication” that building developers have “begun to move against” fossil fuel-free requirements and stricter building energy codes.

Massachusetts has three building codes available to municipalities: the base code; the stretch code, which includes increased energy efficiency requirements; and the specialized code, which incorporates even stricter requirements, including that buildings be pre-wired for electrification. Municipalities in the state can opt into either the stretch or specialized codes.

Barrett said that “early reports from participating communities I represent are that costs of installing heat pumps in new construction are equal to or lower than the costs of installing gas furnaces in new construction,” but he pressed advocates to provide clear data comparing the costs of all-electric construction and fossil construction.

“It seems to me that that proof point is going to be crucial in the next several months as people begin to hunt, as we must, for the real sources of the housing problem,” Barrett said.

In comments made to NetZero Insider following the hearing, representatives of real estate and building development groups argued that all-electric buildings are costlier to build.

“NAIOP is strongly opposed to the expansion of the fossil fuel-free demonstration program at this time,” said Anastasia Daou, vice president of policy at NAIOP Massachusetts. “The existing program dissuades investment, creates significant safety concerns with inconsistent applications of standards and empowers communities to block desperately needed housing in the commonwealth.”

A representative of the Home Builders and Remodelers Association of Massachusetts said the organization “absolutely opposes this expansion” and cited a 2023 industry-sponsored report that forecast Massachusetts’ specialized energy code to increase the construction costs of single-family homes by 1.8 to 3.8%.

A representative of Eversource said the company has “not provided testimony on this legislation and [does] not have anything to provide at this time.”

Representatives of National Grid and the office of Gov. Maura Healey (D) had not responded to requests for comment as of press time. Healey’s administration has not taken an official stance on the potential expansion of the program.

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PacifiCorp Next to Leave WRAP After Raising Concerns

PacifiCorp joins other utilities leaving the Western Power Pool’s Western Resource Adequacy Program just before the deadline to commit to the program’s first binding phase.

PacifiCorp submitted its withdrawal notice on Oct. 30. Michael Wilding, the utility’s vice president of energy supply management, signed the letter and addressed it to WPP Chief Strategy Officer Rebecca Sexton.

WRAP participants have until Oct. 31 to commit to WRAP’s first financially binding phase in winter 2027/28.

PacifiCorp’s withdrawal goes into effect before Nov. 1, 2027, and the utility will be subject to the requirements of WRAP’s tariff during the two-year withdrawal period, according to the letter.

Wilding did not shut the door entirely on rejoining the program, saying PacifiCorp “will continue to engage with the program for the duration of the withdrawal period.”

“Should circumstances change, the company can reenter the program by September 2026 to join other participants in the first financially binding program season in November 2027,” he added.

In an email to RTO Insider, PacifiCorp spokesperson Omar Granados said, “We appreciate the Western Power Pool and its leadership in addressing resource adequacy across the region. PacifiCorp remains committed to providing safe, reliable power, and we believe collaborating with our regional partners is the best way to develop long-term solutions for our customers.”

WRAP has stated it secured enough participants for the program to enter the first binding phase after 11 utilities reaffirmed their commitment in late September. (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.)

“The vast majority of our participants are remaining in the program,” Dave Zvareck, WRAP director, told RTO Insider. “We have received some exit notices this week, which was expected, as well as renewed commitment to the program, and we will move forward with binding operations in winter 2027/2028.”

PacifiCorp’s withdrawal comes after it asked WPP’s Board of Directors to allow WRAP participants to defer their decisions to commit to the program’s binding phase by at least one year after raising concerns about WRAP’s design, planning reserve margins, charges and its ability to adapt to the emergence of day-ahead markets in the West. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)

Other entities exiting the program have highlighted the challenges of navigating WRAP’s requirements when most of the West will be split into two day-ahead markets: SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

All load-serving entities in Markets+ must participate in WRAP, which is being operated by SPP on behalf of WPP. By contrast, EDAM doesn’t require participation in an organized resource adequacy program, instead leaving members the option of choosing their own RA programs. But EDAM will use a resource sufficiency evaluation to ensure participants’ RA going into the day-ahead and real-time time frames.

PacifiCorp now joins Calpine, Eugene Water & Electric Board, Portland General Electric, Public Service Company of New Mexico and NV Energy in exiting WRAP. Out of those six entities, only EWEB will participate in Markets+ because it sits within the Bonneville Power Administration’s balancing authority area. (See 4 Entities Join NV Energy in Exiting WRAP, While Idaho Power Commits.)

Under WRAP’s forward-showing requirement, participants must demonstrate they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus capacity must help those with a deficit in the hours of highest need.

The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season.

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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.”