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December 5, 2025

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Democrats Win the Races for Virginia Governor, Georgia PSC Seats

Democrats won off-cycle elections around the country Nov. 4, with races in Georgia, New Jersey and Virginia holding implications for energy policy.

In Virginia, Gov.-elect Abigail Spanberger (D) cruised to victory over Lt. Gov. Winsome Earle-Sears (R) in a race where energy was less of a focus than in New Jersey. (See related story, N.J. Backs Clean Energy Democrat for Governor.)

Democrats’ strong performance in Virginia was evident downballot, where they won all the statewide offices and added to their majority in the House of Delegates (state senators were not up for re-election).

“Virginians voted for a pragmatic leader who gets results, because we’re in the midst of a growing energy affordability crisis, and she will need to lead from Day 1,” Advanced Energy United Virginia Director Jim Purekal said in a statement. “Gov.-elect Spanberger has a clear mandate to make energy more affordable and reliable by making it easier to build low-cost clean energy and fixing the bottlenecks that slow progress.”

Environmental group Clean Virginia congratulated Spanberger and downballot Democrats in a statement.

“Virginians have made history,” Clean Virginia Executive Director Brennan Gilmore said. “For the first time, every statewide office and the majority of the House of Delegates will be held by leaders who do not accept money from Virginia’s monopoly utilities. That marks a sea change in Virginia politics and a clear rejection of the pay-to-play system that has dominated Richmond for decades.”

As home to the largest data center market in the world, which is growing fast, Virginia has had to contend with large load customers’ impact on the grid. Spanberger has said the data centers should pay for their fair share of grid impacts.

In 2025, a number of bills were introduced in the legislature that would have responded to data center growth. Most failed to make it through to law with a split government. That will not be an issue once Spanberger and newly elected legislators take office. (See Virginia Legislators Introduce Bills to Deal with Data Center Growth.)

One area of concern, which equity research firm Jeffries said is “hanging above all else,” is whether the change in governors will spell trouble for Dominion Energy’s Coastal Virginia Offshore Wind (CVOW) project.

Incumbent Gov. Glenn Youngkin (R) was term-limited, and the question is whether the Trump administration will leave the project alone, as it has so far. Roadblocks have been thrown up against offshore wind projects in Democratic-run states to Virginia’s north.

Dominion CEO Robert Blue addressed that issue on the firm’s earnings call a few days before the election, arguing that CVOW’s electrons were needed to meet growing demand from data centers and to power facilities vital to the U.S. Navy in southeast Virginia, so it should move forward with its planned completion in late 2026. (See Dominion Reports on CVOW Progress, Data Center Growth in Q3 Earnings.)

In Georgia, Democrats flipped two seats on the Public Service Commission as Alicia Johnson and Peter Hubbard handily defeated incumbent Republicans Tim Echols and Fitz Johnson. Echols has been on the PSC since 2011, while Fitz Johnson joined it in 2021.

Alicia Johnson has a background in health care, and her website calls her “a lifelong community advocate,” while Hubbard has 15 years of energy experience and has been active before the PSC via a nonprofit he founded in 2019: the Georgia Center for Energy Solutions. Both Democrats said cutting consumers’ power bills was a priority.

In a post-election note, Jeffries analyst Julien Dumoulin-Smith noted that Southern Co.’s Georgia Power has “top-tier authorized rates of return,” and the incoming commissioners’ election promises around affordability make the outcome of its next rate case, for deliveries starting in 2029, less certain.

In New Jersey, Democrat Mikie Sherrill campaigned on “affordability” for residents of the state, with a promise that on her first day in office, she would address the state’s dramatically rising electricity costs by declaring a “state of emergency” on utility costs, and freezing rates. Sherrill trounced Republican Jack Ciattarelli 56% to 42%.

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Ørsted Says U.S. Offshore Wind Projects on Track but Costly

Ørsted reported a net loss for the third quarter, attributed to the continuing financial challenges for its U.S. offshore wind portfolio, but it also said those projects are progressing well toward completion.

Revolution Wind is 85% complete and on track for commercial operation in the second half of 2026, the company said, while Sunrise Wind is 40% of the way to operational status in the second half of 2027.

Quitting either one now would be almost as expensive as finishing them, CEO Rasmus Errboe said Nov. 5 during a conference call with financial analysts, so the plan is to wrap them up and refocus offshore wind development efforts in other parts of the world.

The picture is different with U.S. onshore renewables, for which the company made a separate business unit on Oct. 1. Errboe said it has a pipeline of 6 to 7 GW of projects that will qualify for federal tax credits through 2029, and there are ample opportunities in the market.

The past few months have been eventful for the company: It completed a $9.3 billion rights issue that helped shore up its finances but tanked its stock price; it announced plans to shed a quarter of its personnel; and it reached a $6 billion deal to sell a 50% stake in the 2.9-GW Hornsea 3 project. (See Ørsted to Slash Workforce, Refocus on European OSW and Ørsted to Raise $9.3B, Self-finance Sunrise Wind.)

This last development, announced Nov. 3, should protect Ørsted’s investment-grade credit rating, CFO Trond Westlie said during the conference call.

Ørsted has three priorities now, Errboe said: continue the significant progress it has made in strengthening its capital structure; wrap up its 8.1-GW offshore wind construction portfolio; and prioritize value over volume as it focuses offshore wind development in Europe and certain Asian-Pacific markets.

Offshore wind has had troubles in much of the world because of its cost and supply chain problems, but attempts to launch a U.S. market have been especially problematic, even before Donald Trump was elected to a second term as president. Ørsted has suffered billions of dollars in losses and impairments on its U.S. projects.

But Ørsted also is the most prolific developer in the U.S. offshore wind market, operating the first offshore wind farm in the Americas (Block Island Wind), completing the first utility-scale project (South Fork Wind), and pressing ahead with Revolution and Sunrise, two of the five projects being built in U.S. waters.

Those seven projects appear likely to be the entirety of the U.S. offshore wind sector for years to come, given the hostility of the Trump administration and the time needed to reboot the industry should such an attempt be made during a future administration.

During the call, financial analysts asked about the prospects of further attacks on Revolution or Sunrise by the Trump administration, which hit Ørsted with a stop-work order in August. Ørsted sued the administration in September and won the right to resume work. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

That was only an injunction, one analyst pointed out. What if the court case drags on beyond the end of construction, and the administration is able to block operation or force a decommissioning?

Errboe would not speculate. He said the injunction allows work to continue and Revolution to begin operations. He said Ørsted continues a dual approach to the Trump administration on Revolution — litigation and negotiation — as best it can.

Another analyst asked why the construction timeline for Revolution stretches into the second half of 2026, as the components are progressing quickly to completion.

Every segment of the project’s cable, both of its offshore substations and each of its 65 turbines need to be energized individually, Errboe said, and that takes time.

At peak operation, Revolution will send 400 MW of electricity to Rhode Island and 304 MW to Connecticut. The 924-MW peak output of Sunrise is contracted to New York.

The remainder of the U.S. offshore wind sector is Equinor’s 810-MW Empire Wind 1, progressing toward a 2027 operation date; Dominion Energy’s 2.6-GW Coastal Virginia Offshore Wind, targeting operation in 2026; and Avangrid’s 800-MW Vineyard Wind, which has encountered extensive delays but made substantial progress.

Ørsted reported a net loss of $260 million largely from higher U.S. tariffs and the stop-work order. It would have been worse, Westlie said, except that interest costs decreased.

This compares with an $800 million profit in the third quarter of 2024, but $780 million of that was from a reversal of some costs that had been expected to accrue from Ørsted’s 2023 cancellation of the Ocean Wind project in New Jersey.

Looking at the year to date, the picture improves: Ørsted reported a profit of $1 billion for the first three quarters of 2025, compared with $939 million in the same period of 2024.

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Utilities in SERC, RF to Pay $185K in Penalties

FERC has approved settlements between East Kentucky Power Cooperative, Ohio Valley Electric Corp. and Seminole Electric Cooperative, and their respective regional entities, carrying monetary penalties totaling $185,000 for violations of NERC’s reliability standards.

NERC filed the settlements Sept. 30 in its monthly Spreadsheet Notice of Penalty (NP25-18), along with a separate, nonpublic SNOP for violations of the ERO’s Critical Infrastructure Protection standards and a $1.25 million settlement between SERC and Entergy. (See FERC Approves $1.25M SERC-Entergy Settlement.)

Commissioners said in an Oct. 30 filing that they would not further review the settlements, leaving the penalties intact. Chair Laura Swett and Commissioner David LaCerte, sworn in Oct. 20 and Oct. 27, respectively, did not participate.

EKPC’s Ratings Violations

EKPC settled with SERC Reliability for $95,000 over a violation of FAC-008-5 (Facility ratings). According to the SNOP, the utility self-reported the violation to SERC in April 2022, indicating that it had discovered two instances in which the utility “failed to have facility ratings that are consistent with” its facility ratings methodology as required by requirement R6 of the standard.

In the first instance, EKPC learned during a review of survey data on Sept. 27, 2021, that the transmission line on the Flemingsburg-Goddard 138-kV circuit, built in 2006, was too close to a distribution line below it because the distribution poles had been built five feet higher than the design indicated.

EKPC had discovered part of the improper construction in 2012 and lowered the maximum operating temperature of the transmission circuit from 212 degrees F to 175 degrees. However, the 2021 survey indicated that other sections of the distribution line had been built outside of specification, along with a mulch pile beneath the transmission line that had gone undetected in 2012. As a result, the utility further reduced the circuit’s maximum operating temperature to 140 degrees.

In the second case, the utility discovered in December 2021 that a set of 795 aluminum conducted (AAC) line jumpers at its Boone substation had been misidentified as 795 aluminum conductor steel reinforced (ACSR) line jumpers. AAC jumpers are limited to 332 MVA at an ambient temperature of 32 degrees, while ACSR jumpers are limited to 346 MVA, the rating EKPC had assigned the Boone substation. The utility derated the facility to 332 MVA.

After discovering these issues, EKPC began an extent of condition assessment on March 1, 2022, that included physical walk-downs of all substations to which FAC-008-5 is applicable. The utility identified incorrect equipment ratings at four substations that required facility derates ranging from 15-17%. EKPC also identified incorrect facility ratings at 40 transmission line facilities of up to 92% over the correct ratings, the majority of which were caused by line-to-ground and crossing clearances. The findings resulted in derates at 16 facilities.

In addition to re-rating the facilities, EKPC’s ongoing mitigation activities include updating its change management control to require inspecting one quarter of its substations each year until the entire system has been evaluated, starting in 2023. The utility has also developed processes to ensure facilities are inspected as they are built to “verify construction was completed according to the plans and specifications,” and to ensure facility ratings databases are updated correctly. These mitigations are expected to be completed by Dec. 26, 2026.

SERC assessed the violation as a moderate risk because of the number of instances reported, but observed the violation caused no operational issue or harm to the system. The RE awarded penalty credit for EKPC’s cooperation through the enforcement process and its agreement to settle the violation, but withheld credit for self-reporting because the notification occurred after the utility received an audit notification letter.

Reporting Mishaps at OVEC

OVEC’s settlement with ReliabilityFirst stemmed from a violation of requirement R2 of VAR-002-4.1 (Generator operation for maintaining network voltage schedules), which requires generator operators to notify transmission operators of deviations from the voltage or reactive power schedule provided by the TOP. The RE discovered the violation during a compliance audit conducted from Sept. 12-15, 2022.

RF’s audit team reviewed data for eight days across nine units sampled from OVEC’s Kyger Creek and Clifty Creek plants. For each date, auditors found the units spent multiple hours above OVEC’s voltage schedule and reactive power threshold that required it to notify its TOP, PJM, according to PJM’s manual. Despite the utility also receiving voltage deviation alarms of varying severity levels, it did not notify PJM as required. OVEC acknowledged to auditors that “such alarms went off frequently and were disregarded.”

OVEC conducted an extent of condition review following the audit covering about one-and-a-half years of voltage schedule deviation data, confirming that all units “were regularly outside of the restrictive bandwidths of its voltage schedule, and that it did not make the required notifications.”

RF concluded that the cause of the noncompliance was OVEC personnel misunderstanding their obligations under PJM’s manual and VAR-002-4.1. To mitigate the violation, OVEC has updated its generator reactive capability curve data and entered a new voltage schedule in PJM’s eDART reporting tool, and developed and trained system operators in a new bus voltage maintenance procedure.

SEC Settles over Multiple Issues

The last settlement in the SNOP was between SEC and SERC, covering violations of four separate standards with a collective $35,000 penalty. SEC self-reported all infringements.

In the first violation, SEC notified SERC on Sept. 28, 2023 that it was noncompliant with PRC-019-2 (Coordination of generating unit or plant capabilities, voltage regulating controls, and protection). Requirement R2 mandates that generator owners and transmission owners must coordinate voltage regulating system controls of applicable facilities within 90 days of any system, equipment or setting changes that will affect the voltage regulating systems.

Three instances of noncompliance were reported. In the first, SEC discovered during a 2023 system review that it had upgraded four relays and modified their protection settings in 2019 without performing a coordination review within the required time. SEC later discovered evidence that it had actually performed the coordination after all, so SERC dismissed this incident as a violation.

The second instance involved the upgrade of automatic voltage regulator limiters at five units in April and May of 2023, with coordination not completed until that October. Finally, SEC discovered in August of 2023 that it had upgraded relays on two units in 2019 but did not perform the coordination. This was completed in October 2024.

SEC’s next infringement involved PRC-023-4 (Transmission relay loadability), with the utility identifying three instances “where protective relaying on its transmission lines was set to operate at or below 150% of the highest seasonal facility rating of the circuit,” in violation of Requirement R1 of the standard. SEC discovered the first instance during an internal review prior to an audit, and the others in a subsequent extent of condition review.

SERC determined that the violation began on July 1, 2019, when SEC updated the first transmission line’s facility rating without updating the protective relay setting, and ended Jan. 6, 2025, when the utility updated relay settings for all three relays. The RE attributed the violation to deficient processes for internal coordination and communication.

Another violation involved PRC-027-1 (Coordination of protection systems for performance during faults). SEC notified SERC on Sept. 25, 2023, that it had not used the proper internal processes when it developed new protection system settings in recent years. Instead, the utility found that protection engineers “used generally accepted industry practices and guidelines.”

SEC reviewed protection systems developed since April 2021, discovering eight total setting changes that did not follow its procedures, beginning as early as May 17, 2021. To address the problem, the utility reset its protection system settings according to its documented procedure; this was done by June 13, 2025.

Finally, SEC notified SERC on July 5, 2024, that it was noncompliant with TOP-001-6 (Transmission operations). The utility indicated that when its energy management system went down for two hours and 10 minutes on July 6, 2023, SEC failed to ensure that a real-time assessment was performed at least once every 30 minutes, as required by requirement R13 of the standard.

The issue was caused by SEC inadvertently activating firewalls on its servers that blocked control room communication with the EMS, leaving operators unable to perform the RTA. SEC reviewed the past three years of EMS logs for any other outages of greater than 30 minutes and found none, concluding there were no other instances of operators being unable to complete the RTA.

To mitigate the violation, SEC ran the RTA as soon as it regained EMS access, conducted a cause analysis to determine the contributing factors, and developed internal controls and processes to prevent similar events.

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More Oversight Needed on Local Transmission Spending in NE, Panel Says

Despite recent transparency improvements, broader efforts are needed to address underlying concerns about a lack of regulatory oversight of local transmission costs in New England, according to panelists on a recent webinar held by Advanced Energy United.

Speakers at the Nov. 4 webinar emphasized the need to address the “regulatory gap” that allows most transmission spending in the region to avoid scrutiny.

The regulatory gap is a “consumer confidence issue,” said Jackie Bihrle, managing attorney at the Massachusetts Attorney General’s Office. “Consumers should be able to have confidence that utility spending is the least-cost, most effective solution, and that has dwindled with this gap.”

Local transmission projects, known as asset-condition projects (ACPs) in New England, are typically upgrades of existing assets deemed to be aging or deteriorating. The projects are not subject to competitive bidding processes or regional planning processes, and the transmission owners recover costs through FERC formula rates.

Asset-condition costs have risen significantly in New England in recent years. The region’s transmission owners reported nearly $4 billion in ACPs placed in service between 2020 and 2024, and the companies forecast spending in 2025 to total nearly $1.5 billion.

While substantial spending is necessary to maintain the region’s grid, more safeguards are needed to ensure this spending is as cost effective as possible, the panelists agreed.

Local transmission spending is subject to “the lightest touch review possible” at the federal level, and projects generally face minimal scrutiny from state-level permitting processes, said Matthew Christiansen, partner at Wilson Sonsini Goodrich & Rosati and former FERC general counsel.

He said there is clear evidence that transmission spending has been concentrated in recent years on projects that are not subject to regional planning or competitive solicitation processes. Along with increased spending on local projects, “you actually see the same thing with regional projects that are exempted from competition,” he said.

Christiansen added that formula rate procedures at FERC have created structural difficulties for stakeholders seeking to challenge the prudency of costs. Instead of requiring TOs to prove the prudency of investments, formula rates shift the burden of proof to third parties contesting the prudency of the spending.

“It really does change the playing field in terms of what has to be proven, in a way that makes it much more likely that costs will ultimately be passed through to ratepayers,” Christiansen said, adding that consumer advocates’ ability to challenge costs is typically minimized by limited resources and “informational asymmetries” between them and TOs.

In June, ISO-NE agreed to take on a non-regulatory “asset condition reviewer” role to provide increased transparency into project spending. In a recent update, the RTO said the role is “envisioned to provide an independent review and opinion of asset-condition projects submitted for review by the TOs,” which could help inform formula rate challenges with FERC. (See ISO-NE Gives Update on Asset Condition Reviewer Role.)

“It will help, I think, on the transparency issue,” Bihrle said. “This isn’t going to completely solve the underlying problem, but we think it’s a really important step in the right direction.”

The insight and “objective opinions” provided by ISO-NE could “provide some information upon which interested stakeholders could challenge asset-condition spending at FERC,” Bihrle added.

Discussing potential solutions to the broader issue, Christiansen said it is easier to diagnose the problems than it is to provide answers that would not have unintended consequences.

He said FERC could establish a dedicated “technical office” to perform targeted audits of local projects; this could provide a good starting point for identifying issues or trends.

Claire Wayner, senior associate at RMI, emphasized the importance of coordinating local and regional transmission projects and looking for opportunities to right-size projects to maximize potential benefits.

She said coordination and right-sizing discussions need to occur early in the planning process, as it can be hard to address these questions by the time projects reach state permitting proceedings.

“This cannot be solved alone by increased state-level oversight,” Wayner said. “We need to see regions do more regional-first planning.”

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Split Panel on the D.C. Circuit Upholds DOE’s Furnace Efficiency Rule

The D.C. Circuit Court of Appeals upheld the Department of Energy’s efficiency standard for natural gas furnaces and water heaters against appeals from gas trade associations.

In a 2-1 decision issued Nov. 4, the three-judge panel found DOE was within its authority on the standard, which will end the sale of “non-condensing” furnaces and water heaters because they cannot meet the requirements.

Non-condensing furnace or water heaters burn gas to heat air or water, and then the rest of the heated gas not used for the appliance is transferred out of the building via a chimney. Condensing units have a second powered heat exchanger that captures the excess heat, turns it into condensed water vapor and then transfers the cooler air out through a vent or the water through a drain.

“This added heat exchanger makes the condensing appliance more efficient overall as compared to its non-condensing counterpart,” the court explained in its decision.

The issue of whether non-condensing technologies represented a performance feature that cannot be eliminated under DOE’s authority to set efficiency standards has ping-ponged since the Obama administration, until the department under President Joe Biden was able to issue a final rule in 2023 that was appealed.

The parties in the case were split over whether Congress wanted to protect attributes — such as venting mechanisms, installation factors and how much space appliances take up — from being regulated away via DOE’s efficiency rules.

“Petitioners contend that non-condensing appliances, which use unpowered venting like vertical chimneys, offer performance characteristics to consumers that condensing appliances do not,” the court said. “According to petitioners, condensing appliances are incompatible with venting systems like chimneys because condensing appliances require a fan to generate enough pressure to push or pull gases outside.”

Condensing units also require drains and cannot use the same vents as their non-condensing counterparts.

The court noted that the American Gas Association, one of the petitioners, had asked Congress in 1986 to make it so “conventional, atmospherically vented furnace” were not impacted by its amendments to the Energy Policy and Conservation Act (ECPA), which was being amended. Congress did not include AGA’s language.

“At a certain level, it is obvious that consumers do not buy small furnaces or commercial water heaters because of how the appliance vents,” the court said. “In fact, venting is a quality that both condensing and non-condensing appliances share. It ‘is one of the basic components found in every gas-fired furnace.’”

The panel’s majority said the dissent, by Judge Neomi Rao, overlooked that aspect by claiming some consumers will be deprived of gas-powered appliances entirely. They will still have access to gas-fired condensing units, it said.

Rao argued that consumers under the standard could be forced to install a condensing model that often requires disruptive and expensive renovations to a building’s venting and plumbing systems.

“These standards run afoul of the careful balance Congress struck in the Energy Policy and Conservation Act between improving energy efficiency and preserving consumer choice,” Rao said. “While EPCA empowers the department to set efficiency standards, the statute also imposes a critical limit on that authority. The agency is prohibited from imposing an efficiency standard that will result in the ‘unavailability’ of a product with a ‘performance characteristic’ that consumers value.”

Many older homes and buildings only have a traditional chimney available for furnaces and water heaters, making a performance characteristic under the ECPA, she wrote.

In response to the ruling, the AGA, American Public Gas Association and National Propane Gas Association noted 55% of residential gas customers use non-condenser appliances.

“The D.C. Circuit Court failed the American people today, making a decision that removes choice and could force up to 55% of gas households into expensive home renovations and higher energy bills,” AGA President Karen Harbert said in a statement. “Longstanding U.S. law does not support this conclusion, and we strongly disagree with this decision. America’s natural gas industry will continue to fight to protect American consumers’ right to choose their appliances and energy sources.”

Efficiency advocates welcomed the court’s decision, which they said preserves the federal standards set to take effect in 2028 and are expected to save consumers $350 per unit over their lifetimes. The standards mandate furnaces that use 15% less energy than the least efficient models available today, and Canada has had a similar standard in effect since 2010, the Appliance Standards Awareness Project (ASAP) and the National Consumer Law Center said.

“This upholds long-awaited standards that will save households money on their heating bills while reducing pollution,” ASAP Executive Director Andrew deLaski said in a statement. “Ensuring new furnaces are more efficient may disappoint some gas utilities, but it’s a triumph for consumers.”

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Constellation Proposes up to 1,500 MW of New Capacity in Md.

Constellation Energy is proposing 714 MW of new gas-fired peaker capacity and up to 800 MW of storage in response to a Maryland solicitation.

Constellation also said it could provide additional gigawatts of power with a combination of new nuclear generation and extension or expansion of existing nuclear facilities in Maryland.

Constellation’s Nov. 4 announcement contains caveats: Some policymakers argue against building the additional natural gas infrastructure that the peakers would require; Maryland legislators need to provide clear direction and enabling legislation; and local utilities need to provide faster connections to the grid.

Meanwhile, Constellation and other major stakeholders are pressing for reforms in the PJM market. (See PJM Drops Non-capacity Backed Load, Shifts Focus to Resource Queue, PRD.)

Maryland Gov. Wes Moore (D) signed the Next Generation Energy Act (SB0937/HB1035) into law May 20.

In response, the Public Service Commission on Sept. 30 initiated Docket PC74 and issued a solicitation for dispatchable generation and large-capacity energy resources through an expedited certification of public convenience and necessity (CPCN) process.

The dispatchable generation must have an effective load carrying capability of at least 65% as determined by PJM’s most recent ELCC rating and must have a lower greenhouse gas emissions profile than coal- or oil-fired generation.

The energy resource must be a generating station or energy storage system that has applied for or been approved for PJM interconnection and must have a capacity rating of at least 20 MW after accounting for ELCC.

There were four responses by the Oct. 31 deadline:

A civil engineering firm submitted a confidential document; a group of environmental and community activists advocated in favor of solar, storage and wind but against natural gas; Alpha Generation requested a dispatchable resource CPCN for the 35-MW uprate it’s pursuing for its 766-MW gas-fired Keys Energy Center; and Constellation submitted its two gas and one storage projects for consideration as dispatchable generation resources.

The 150-MW and 564-MW gas projects would use turbines that Constellation owns and would relocate to the project sites, which are adjacent to existing, undisclosed power stations. Anticipated annual run times were not disclosed. Constellation expects to submit service requests to PJM before April 27, 2026, as part of the Cycle 1 interconnection process.

Constellation said it has submitted a new gas service request to Baltimore Gas and Electric for the two projects. Securing firm supply in the highly constrained Mid-Atlantic pipeline system is challenging, so it is working with BGE to determine availability and will continue discussions with other parties as needed to secure firm gas to the sites.

Constellation warned that if the two gas plants are to be built, policymakers must work with gas utilities to facilitate gas supply improvements expeditiously; include appropriate cost recovery for gas infrastructure investments; and potentially authorize a special contract between the gas utility and generator to ensure firm supply at predictable rates.

Constellation’s storage proposal would entail up to 800 MW of four-hour battery energy storage systems on up to four, 12.5-acre parcels owned by Constellation at undisclosed locations.

They would export electricity for sale in PJM real-time and day-ahead energy wholesale markets, fast-start ancillary services and capacity markets.

The anticipated ELCC rate would be 58%, which Constellation acknowledges falls short of the 65% minimum specified by the PSC. But it argues in its proposal that the anticipated unforced capacity — as much as 464 MW — would be a significant addition to PJM’s resource-constrained BGE Zone, and it would be emissions-free.

Constellation anticipates submitting this project as well in PJM’s Cycle 1 interconnection process.

Constellation’s potential increases in nuclear capacity are in earlier stages. They entail: Relicensing the two reactors at Calvert Cliffs to operate another 20 years beyond their current retirement dates, 2034 and 2036; investing in uprates to increase the Calvert Cliffs output by 10%, or 190 MW; and exploring construction of 2,000 MW of next-generation nuclear reactors beside Calvert Cliffs.

Together, these would equal 4,000 MW of emissions-free generation capacity added or not removed from the grid.

“Constellation could bring all — or any combination — of these new projects forward to meet Maryland’s energy generation needs at the lowest possible cost to consumers,” the company said, “provided we have clear direction and enabling legislation from Maryland’s policymakers.”

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Nonprofits Ask 9th Circ. to Vacate BPA’s ‘Shocking’ Day-ahead Market Decision

The group of nonprofits suing the Bonneville Power Administration in the 9th Circuit Court of Appeals filed its opening brief, saying BPA’s decision to join SPP’s Markets+ instead of CAISO’s Extended Day-Ahead Market “violated clear mandates from Congress.”

The group filed the opening brief Nov. 3, urging the court to vacate BPA’s record of decision to join Markets+. It also asked the court to order the agency to launch an Environmental Impact Statement (EIS) process.

Represented by Earthjustice, the organizations suing BPA include NW Energy Coalition, Idaho Conservation League, Montana Environmental Information Center, Oregon Citizens’ Utility Board and the Sierra Club.

“Bonneville’s failure to comply with the Power Act’s requirement to ensure its policy decision would keep power costs low in the Pacific Northwest while protecting environmental quality, and Bonneville’s decision to ignore its obligations under [National Environmental Policy Act], violated clear mandates from Congress,” the brief states. “Vacatur is the appropriate remedy here.”

On May 9, BPA issued its long-awaited decision to join Markets+ over EDAM. The announcement came after a lengthy debate over which day-ahead market would provide the most benefits to BPA and its customers. (See BPA Chooses Markets+ over EDAM.)

The plaintiffs in the underlying suit filed their claims July 10, alleging the agency failed to factor in environmental impacts and financial considerations in violation of the National Environmental Policy Act, the Pacific Northwest Electric Power Planning and Conservation Act and the Administrative Procedure Act. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)

‘Fight for It’

The opening brief reiterates many of the allegations in the lawsuit. For example, the plaintiffs claim BPA failed to consider several cost analyses showing the purported benefits of EDAM over Markets+.

The brief cites an analysis by state agencies in Washington and Oregon using BPA’s data that found the agency could have saved its customers $4.4 billion through 2035 by joining EDAM.

Those arguments follow a production cost study by Energy and Environmental Economics (E3) commissioned by BPA in 2024 that showed participation in EDAM under certain scenarios could deliver the agency up to $106 million in greater benefits than Markets+.

BPA also allegedly violated NEPA by failing to conduct an EIS and assess the environmental effects of its day-ahead market choice, according to the plaintiffs.

“It is shocking that the Bonneville Power Administration chose to undermine our grid reliability and forego $4 billion in reduced power costs for the Pacific Northwest region by choosing Markets+,” Jaimini Parekh, senior attorney with Earthjustice, told RTO Insider. “Low-cost, renewable power is available to our region if BPA chooses it, and we will fight for it through this case.”

A BPA spokesperson told RTO Insider the agency does not comment on active litigation. SPP also declined to comment.

However, BPA has argued its day-ahead market process was conducted with significant stakeholder input, noting in its final market decision that other electric utilities weighing which market to join have done so “without public process or transparency.”

As for the production cost studies, the agency has contended those failed to factor in other key issues, like governance. BPA says the SPP market’s governance structure is “superior” to EDAM’s, despite ongoing efforts by the West-Wide Governance Pathways Initiative to relax the state of California’s oversight for CAISO’s EDAM and WEIM.

Several trade organizations have filed motions to intervene in the suit in support of BPA, including SPP, Public Power Council, Alliance of Western Energy Consumers, Pacific Northwest Generating Cooperative and Northwest Requirements Utilities. (See BPA Supported by Trade Orgs in Suit over Day-ahead Market Decision.)

The BPA supporters have also highlighted Markets+’s governance approach and “overall design.”

PPC Director of Market Policy and Grid Strategy Lauren Tenney Denison told RTO Insider the organization “has repeatedly commented that we disagree with the assumption that Markets+ participation will increase power costs in the Northwest.”

Tenney Denison noted E3 has issued an updated analysis that reinforced “PPC’s perspective that there are broad directional benefits from day-ahead market participation, but the analysis falls short of encapsulating the aggregate impacts to preference customers of BPA’s day-ahead market decision.”

“This uncertainty around economic results leads PPC to place a higher importance on other aspects of the decision,” Tenney Denison said. “PPC continues to place significant value on the inclusive stakeholder-driven governance framework in Markets+. The value associated with BPA having a voice in how the market develops and responds to regulatory, legislative and operational needs will likely significantly outweigh the differences in market footprint estimated by production cost studies.”

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Stakeholder Forum: Turning Industrial Electrification into a Grid Solution

By Cihang Yuan

Every day, we push the grid harder — and expect it to keep up. Large new loads like data centers are arriving in clusters, EV sales continue climbing, renewables are growing quickly, and transmission and interconnection timelines run long. In fact, by the end of 2024, nearly 2,300 GW of generation and storage were waiting in interconnection queues.

The default solution to these challenges — building our way out of this only with new generation and higher-capacity wires — is expensive and slow. But there’s another critical lever to consider: managing when electricity is used, not just how much.

Industrial electrification can help ease grid pressures when it is designed and meaningfully incentivized for flexibility. When paired with thermal storage, electrified heat allows facilities to draw electricity when it is most cost-effective and clean and deliver heat whenever needed.

Industrial heat pumps add controllability, while targeted process scheduling and onsite resources can further smooth a facility’s net load. Together, these measures can turn portions of new industrial electrification demand into targeted, verifiable relief at the times and locations the grid needs most.

What’s Stressing the Grid

Today’s grid challenges are not just about growth, but about the nature of that growth. Demand is becoming spikier, more concentrated and less predictable.

Cihang Yuan |

Fast, lumpy load growth: Electricity demand from data centers is surging and is expected to double or even triple by 2028, according to the DOE projection. This growth arrives in large, geographically concentrated blocks, stressing local capacity and pushing resource adequacy to its limits. This dynamic dramatically elevates the value of locational, time-specific flexibility — the exact kind that flexible industrial loads are well positioned to provide.

Supply-side growing pains: As renewable penetration rises, the grid needs immense flexibility to manage steep ramps, absorb midday solar surplus and reduce costly curtailment. Simultaneously, interconnection backlogs are delaying the supply-side resources needed to meet demand. With the median time from a generation project’s grid request to its operation now at five years, demand-side solutions that can be deployed faster no longer are a luxury, but a necessity.

Peak-driven cost pressure: System peaks drive a disproportionate share of grid costs, from capacity procurement to transmission and distribution investments. Even a modest reduction in peak demand through targeted flexibility can yield significant savings.

Why Industrial Load is Different — and Useful

While data centers and EVs represent significant new loads, industrial facilities offer a unique combination of scale, predictability and inherent flexibility that makes them ideal grid partners.

Orchestrating flexibility at scale: A single industrial facility can offer megawatts of verifiable, dispatchable flexibility. This allows utilities to coordinate with a few large counterparties rather than attempting to aggregate thousands of smaller, less predictable residential devices. While data centers offer similar scale, their uptime and latency requirements limit their flexibility. Industrial processes, by contrast, often are better suited for deeper, more dependable demand-side response.

Harnessing intrinsic thermal flexibility: Most industrial processes rely on heat carried in water, steam or storage media. Electrifying heat and adding thermal storage decouple electricity draw from heat delivery. A thermal battery can be charged during low-cost — and usually renewable-abundant — windows while supplying steady 24/7 process heat from stored energy. This powerful load-shifting — further enhanced by controllable industrial heat pumps, hybrid systems and optimized process scheduling — transforms a constant thermal need into a flexible electrical load, well suited for shaving peaks and filling overnight valleys.

Delivering surgical grid support: Flexible industrial load can provide targeted relief exactly where it’s needed, serving as a non-wires alternative to defer or downsize costly grid upgrades. By adjusting demand at specific substations and during critical hours, these facilities can alleviate local congestion, absorb surplus renewable energy that otherwise might be curtailed and improve overall asset utilization.

What it Will Take to Unlock Flexible Industrial Load

Realizing this vision requires a strategic shift in how utilities, regulators and industrial customers collaborate. The following steps are critical:

Illuminate the path with data: Utilities and grid operators must provide more granular, accessible data on system conditions, such as through public hosting capacity maps. This visibility allows industrial customers to identify locations where the grid can accommodate new load and to right-size their investments in on-site storage and flexible equipment.

Foster proactive collaboration: Unlocking industrial flexibility begins with a transparent exchange of information. Utilities should communicate clearly where and when their systems are constrained and define the attributes of the flexibility they value most. In turn, industrial customers should share their electrification road maps and the operational flexibility they realistically can offer. This shared understanding prevents surprises, enables quicker wins and builds a foundation for scaling flexibility over time.

Price flexibility accurately: The value of flexibility must be reflected in the price of electricity. Regulators and utilities should design rate structures that align more closely with the real-time system value of flexibility. Today, most rates smooth out the real cost volatility between off-peak and peak hours. For flexibility to scale, pricing needs to move closer to reflecting real system conditions. This can be achieved through sharper, more granular time-of-use differentials, locational or congestion-based rate adders, or multipart dynamic rates that reflect real-time system needs. When industry sees the true value of shifting its load, it will invest to capture it.

Modernize demand response programs: For decades, industrial customers have been a critical part of demand response. But most existing programs were built for emergency, event-driven curtailments and haven’t kept pace with what newer technologies like thermal storage and flexible heat pumps can offer. Programs should be created or expanded to value load shifting as much as load shedding. By offering simple enrollment and predictable compensation for services like valley filling and peak shaving, utilities can give industrial customers the confidence to invest in the technologies that make their facilities dynamic grid assets.

Turning New Demand into a Grid Asset

Industrial electrification is coming, and how we choose to integrate it will define the American grid for a generation. Treating this new demand as “just more load” risks billions of dollars in avoidable grid upgrades and continued reliance on fossil-fueled peaker plants.

But a better path is available. For the first time, the very technologies driving new demand — smart heat pumps, thermal storage and advanced controls — also are the tools that can help manage it. By embracing this inherent flexibility, we can turn industry from an electricity consumer into one of the grid’s most reliable partners.

Proactive collaboration gives utilities a dynamic lever to manage system stress, offers manufacturers a competitive edge through lower energy costs and cleaner processes, and provides regulators a pathway to a greener grid without increasing energy costs for consumers. The time for collaboration is now.

Cihang Yuan is the World Wildlife Fund’s senior program officer for climate and renewable energy.

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FERC Approves $1.25M SERC-Entergy Settlement

Entergy must pay a $1.25 million penalty to SERC Reliability and comply with additional sanctions for an alleged violation of NERC’s reliability standards that put the Eastern Interconnection “at risk of potential voltage collapse, frequency fluctuations and possible blackout, according to a Notice of Penalty approved by FERC on Oct. 30 (NP25-17).

NERC submitted the NOP to FERC on Sept. 30; the commission said it would not further review the settlement, leaving the penalty and sanctions intact. Chair Laura Swett and Commissioner David LaCerte, who were sworn in Oct. 20 and Oct. 27, respectively, did not participate in the decision.

The settlement stemmed from TOP-001-5 (Transmission operations), which SERC alleged Entergy violated in its capacity as a transmission operator. Requirement R1 of the standard mandates that a TOP “act to maintain the reliability of its transmission operator area via its own actions or by issuing operating instructions.”

According to the settlement agreement, Entergy twice failed to appropriately react to alarms; one instance that caused a loss of load for several customers was not discovered until months after it occurred.

The first event that the utility discovered began Jan. 25, 2024, while Entergy was performing maintenance activities at the Willow Glen substation near Baton Rouge, La. These activities caused more than 3,500 alarms to trip at Entergy’s Transmission Control Center, which operators expected.

However, one of the alarms was a priority 1 notifying operators of low battery DC voltage, and TCC staff “mistook that alarm for one of the expected maintenance alarms and cleared it from the active screen without notifying the appropriate field personnel.” TCC operators are required to act within 24 hours of a P1 alarm to ensure the grid is in a safe condition, but Entergy did not take appropriate action until Jan. 29, SERC staff wrote.

On that date, TCC staff noticed that multiple remote terminal units (RTUs) in the area were offline. They dispatched investigators, who reported the issue was caused by low DC voltage at the Willow Glen station. By the following day, all RTUs had returned to service, with Willow Glen restored last.

On Feb. 21, 2024, while performing an extent-of-condition evaluation for the incident, Entergy staff discovered a similar earlier instance that had not been identified. This event occurred Oct. 24, 2023, when the TCC received a P1 alarm from the Sabine substation in Texas warning of loss of potential in the coupling capacitor voltage transformer. TCC staff did not notify field personnel at the time.

Two days later the transformer failed, causing multiple transmission line outages that affected 26 industrial customers. Three of these customers lost a total of 23.7 MW of load, while the others “experienced power quality issues” including voltage sag that caused large motors at eight sites to trip, requiring production equipment to be completely restarted. Process units at 13 sites tripped; another site had to restart its cogenerator; and a steam turbine at the final site tripped after its pumps went offline. Two generators at the nearby Sabine power station also tripped offline.

After the transformer failed, the “system responded as designed,” SERC staff wrote, with breakers opening to place the grid in a safe condition. Outage notifications were sent upon the transformer failure and the breakers tripping.

SERC considered both incidents to be part of the same violation. The regional entity blamed the issue on “ineffective management oversight, an improperly designed alarm program, lack of procedures and inadequate training.”

RE staff wrote the design of the alarm program permitted operators to experience “an exorbitant number of alarms,” receiving more than 100,000 P1 alarms alone per day on average at both the northern and southern TCCs. This constant warning prevents them from maintaining situational awareness, performing real-time assessments, working outages, and answering phone and radio calls without distraction, SERC said.

Entergy also had no written guidance on alarm generation designation, prioritization or review; no formal procedure for TCC alarm management; and no reference documentation for operators to use in day-to-day operations.

TCC operators do learn the process of identifying and addressing the different levels of alarm, SERC staff wrote, but this training only occurs once during an operator’s initial training. Entergy management “recognized the magnitude of alarms was a programmatic weakness and an error-likely scenario and failed to act to resolve the issue,” according to the RE.

SERC assessed the violation as posing “a serious and substantial risk” to grid reliability, saying that by failing to correct a known weakness, the utility had put itself and the entire Eastern Interconnection at risk of voltage collapse, frequency fluctuations and blackouts. The RE considered Entergy management’s “passive acceptance of the high volume of alarms” an aggravating factor in the penalty determination.

In addition to the monetary penalty, Entergy will have to adhere to several conditions as part of the settlement. Among these are the tracking of P1 and P2 alarms received on a monthly basis and how many were ignored, silenced or missed. Entergy must provide quarterly reports on these metrics to SERC and its chief security officer for the next two years, starting the quarter after FERC’s acceptance of the agreement.

Entergy executives must also attend quarterly meetings with SERC leadership to discuss these metrics and any other reliability issues as determined by both parties, and the RE will perform a spot check within one year of FERC’s approval.

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CPower’s 2025 VPP Dispatches Already More Than Double 2024 Levels

Rising demand and extreme weather led to a huge spike in dispatches across CPower Energy’s Virtual Power Plant (VPP) portfolio as customers it aggregated delivered 38 GWh of load relief over the first nine months of 2025, more than doubling the total from 2024.

“DR and VPPs are having a bit of a moment in the market,” CPower CEO Michael Smith said in an interview Nov. 3. “They’re extremely important flexibility provided to a market that’s growing in terms of demand, that’s experiencing more severe and more frequent weather incursions, and we continue to be an extremely important part of the energy transition in that regard.”

In 2024, CPower’s aggregated customers delivered just 16 GWh to the grid all year, which means for the first three quarters of 2025, they’ve already provided 137% more. That shows VPPs consistently answer the call for grid support and the resources can be relied on in the future, Smith said.

This summer had extreme heat in June that drove dispatches in PJM and ISO-NE, he added.

“You’re seeing, you know, two phenomena,” Smith said. “More customers seeking to access the opportunity represented by these markets. And … weather driving more dispatch.”

CPower also sees increased interest from large loads like data centers that want to be plugged into the grid quickly. Flexibility is going to be vital for the data center industry in the near term as a major goal for them is speed to market.

“Let’s call it three, five, seven years. Generation and transmission build is not going to catch up to the needs of the grid created by extreme demand growth,” Smith said. “So, we’re going to need the shock absorber provided by demand response and VPP providers.”

Once generation and transmission development catch up to the growth and can serve large loads at peak times without issue, some data centers still will want to earn money.

“Customers have inherent flexibility, and they get paid for it,” Smith said. “I think that continuing to go back to that fundamental principle would dictate that you’re always going to have this be part of the market, even when you do get supply/demand, generation/demand balanced.”

One issue CPower and other aggregators always have to balance is ensuring that customers who provide DR do not get burned out by being called upon constantly to balance the grid.

“We work with all of our customers to ensure that they’re comfortable with the commitment they’re making to an evolving market,” Smith said. “Some customers decide they want to commit less because they think they’re going to get dispatched more.”

Another factor they must compete against is large customers engaging in their own peak shaving to lower their bills, which has been a phenomenon since the markets launched.

“I would say those conversations, particularly after the dispatches of the summer of 2025, are more acute in our business,” Smith said. “But we’re not seeing customers fleeing these markets. Customers are in these markets. They’re participating. They’re getting compensated well for their participation in these markets.”

While large loads are driving changes and dominating the broader power industry’s attention in general, the biggest market potential for demand response remains residential and small commercial customers.

CPower supports a pending complaint from Voltus at FERC, which would allow for statistical modeling of their demand response to be used more widely in PJM due to difficulty in obtaining actual smart-meter data. (See Voltus, Mission:data Seek Changes to PJM Data Requirements for DR.)

The states control the rules around releasing data from smart meters to third parties such as DR/VPP aggregators due in part to concerns around data security, which can be overcome, Smith said.

“That’s traditionally been very hard for state commissions to get their heads around,” he added. “Collectively, think about going back to the opening of the retail power markets and retail energy providers not being able to get that same kind of data. So, we’re having those same discussions again. We’re seeing some movement at the state commission levels, but it’s going to take some time to get that right.”