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.”
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.”
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.
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.”
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.”
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.
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.
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.”
FERC has granted Great Basin Transmission’s request for incentives and a transmission owner tariff for its Southwest Intertie Project-North line — rejecting arguments that the project no longer makes sense with the cancellation of the Lava Ridge wind farm.
In an Oct. 31 order (ER25-2025), FERC accepted Great Basin’s proposed transmission owner tariff and formula rate for the project, also known as SWIP-North.
SWIP-North is a 285-mile, 500-kV line being developed by LS Power subsidiary Great Basin Transmission at an estimated cost of $1 billion. It will run from eastern Nevada near Ely to Idaho Power’s Midpoint Substation near Twin Falls, providing a bi-directional energy pathway between the Desert Southwest and the Pacific Northwest.
Great Basin’s transmission owner tariff includes the terms and conditions to participate as a Participating Transmission Owner (PTO) in CAISO. The PTO model allows lines outside of California to join the ISO while avoiding financial risks. (See CAISO Wins FERC Approval for Subscriber-funded Tx Plan.)
Great Basin said its tariff is consistent with other PTO tariffs on file at FERC, including those of affiliates DesertLink and LS Power Grid California.
FERC also granted Great Basin’s request for several transmission-development incentives.
The abandoned plant incentive will allow the company to recover its costs if the project is abandoned due to events beyond its control.
In addition, the commission granted Great Basin’s request for a regulatory asset incentive, which allows deferred recovery of prudently incurred pre-commercial costs through the creation of a regulatory asset. And FERC approved an RTO adder for SWIP-North, which will take effect when Great Basin joins CAISO and turns over operational control of the transmission line.
FERC Chair Laura Swett and Commissioner David LaCerte did not participate in the decision.
Reducing Congestion Costs
FERC’s approval of the abandoned-plant and regulatory-asset incentives is a reversal from the commission’s previous denial of Great Basin’s request. (See FERC Denies LS Power’s Bid for SWIP-N Incentives.)
In a Feb. 20 order, the commission found that the company failed to meet the criteria of FERC Order 679, which requires transmission incentive applicants to show that a project will ensure reliability or reduce costs associated with transmission congestion.
The incentive request was denied without prejudice. In its new request, filed April 23, Great Basin supplied an economic study by Hitachi Energy that showed annual congestion costs for the California-Oregon Intertie Corridor (COI corridor) would drop by about $38.6 million a year, to $156.7 million, with SWIP-North in place.
In addition, Great Basin argued, SWIP-North would give Idaho Power access to the Desert Southwest market, improving reliability during extreme cold weather events. By alleviating congestion constraints between the Pacific Northwest and Desert Southwest, the project would reduce the cost of delivered power, the company said.
And CAISO identified reliability benefits of the project, including resource diversity and the addition of a parallel path with the COI Corridor. Those could be important factors during wildfires or extreme weather.
A group called Stop Lava Ridge argued that recent policy changes reduce the chances of the development of the 1,000 MW of Idaho wind that Great Basin relies on in its application. The group noted the Department of the Interior’s cancellation Aug. 5 of the 1,000-MW Lava Ridge wind project. (See Interior Reverses Approval of Lava Ridge Wind Project.)
But Great Basin responded that SWIP-North’s congestion relief benefits are not tied to Lava Ridge wind.
“Whether the source is from nuclear generation, gas generation, hydro generation, geothermal generation or other nonwind resources, and regardless of the state of origin (i.e., Idaho, Oregon, Wyoming, Washington, etc.) of such generation, the addition of SWIP-North would still provide COI congestion relief benefits,” Jinxiang Zhu of Hitachi Energy said in a filing.
In fact, SWIP-North would relieve even more congestion without Idaho wind generation, Zhu said, reducing congestion costs by $47.2 million and further reducing the number of COI corridor congestion hours.
The NYISO Management Committee voted to approve the ISO’s 2025-2034 Comprehensive Reliability Plan, though stakeholders and the Market Monitoring Unit again voiced concerns with how it is structuring its planning.
The Natural Resources Defense Council voted against the plan at the committee’s meeting Oct. 29, while Energy Spectrum, the New York Utility Intervention Unit, Multiple Intervenors and New York City abstained.
The biennial CRP looks ahead 10 years to plan for long-term reliability. The latest plan did not identify a specific actionable reliability need but said that “New York’s electrical system faces an era of profound reliability challenges” and called for several thousand megawatts of additional dispatchable generation. (See NYISO Reliability Plan Calls for ‘New Dispatchable Generation’.)
It calls for looking at a wider range of scenarios for transmission planning and relying less on emergency measures for maintaining resource adequacy. Ross Altman, senior manager of reliability planning for NYISO, said implementing the plan could require manual and tariff changes.
“You want to consider a range of potential forecasts coupled with your ability to go ahead and procure through solicitation resources to meet whatever potential gap is in necessary resources,” said Howard Fromer, director of regulatory affairs for Bayonne Energy Center. “What do you propose to do about aligning our markets so that they are going out and procuring resources that are consistent with your reliability needs through your planning process?”
“I don’t have anything for you today because this is the beginning of the road,” Altman said. “What we actually plan for requires additional conversations in the next months.”
Altman said staff took Fromer’s point very seriously and that aligning markets with reliability planning was something the ISO was actively working on.
“My expectation is that you would want to conduct the [upcoming] Reliability Needs Assessment [RNA] with the new structure,” said Doreen Saia, chair of the energy and natural resources practice for Greenberg Traurig. She said this would require very fast action from NYISO and its stakeholder committees and asked the ISO to create a public schedule quickly. “Transparency is important. Notice is important.”
Zach Smith, NYISO vice president of system and resource planning, thanked Saia for pointing this out but cautioned that the ISO was not sure that tariff revisions were needed. If they were, the ISO would need to be mindful of the tight timeline to get revisions filed before the next RNA.
“I want to push back on the idea that we can commence the RNA without understanding how NYISO is going to determine actionable reliability,” the NRDC’s Chris Casey said. “The assumption that the ISO is planning to use different scenarios gets colored differently if those scenarios are informational versus actionable.”
“I actually fully agree with you,” Altman replied. He said the broad range of scenarios the ISO had previously shown was intended to illustrate what it had to account for. “The actual implementation of that, and the assumptions that will go into the RNA, will be very detailed.”
Casey pointed to a graph in the CRP that showed the state hitting a 4,000-MW shortfall and compared it to a more detailed slice of the same data. He said the ISO was overemphasizing the worst-case scenarios and that those scenarios did not have a sufficient basis to justify centering them.
Altman said these weren’t actually the worst cases and that staff actually excluded several outliers that assumed nuclear plants would not get relicensed. As the process continued, stakeholder feedback would be used to “find the balance.”
A representative from Earthjustice said that amid all the discussion of schedules and changes to the markets, they had not heard any evidence from NYISO that the changes it was presenting were necessary. They asked if the ISO had called in independent consultants to look at the changes to the reliability planning process to see if they made sense.
“I would strongly encourage the consideration of this before there’s this dramatic shift in the way the markets are planned and the way that reliability planning occurs,” they said.
The MMU said it was concerned that there is a growing gap between planning and the markets.
“We’ve been seeing that open up in the past couple of years, and I think it’s a concern because it’s going to provide the wrong incentive,” said Pallas LeeVanSchaick, vice president of Potomac Economics. He said that gap undermines the market’s ability to maintain reliability. It could also result in the ISO keeping more capacity than is needed to meet the needs of the system.
The CRP now goes before the Board of Directors, which is expected to pass it before the end of November. Discussions over the proposed planning process changes would then begin in December.
FRANKLIN TOWNSHIP, N.J. — New Jersey will need to overcome a raft of permitting, funding and policy issues as it seeks to remake its energy strategy to confront the sudden, data center-fueled rise in energy demand on the horizon, speakers told an energy forum organized by the state’s largest business group.
Perhaps the most urgent need is a clear-eyed look, coupled with some tough decisions, at what energy sources the state is going to pursue, keynote speaker Zenon Christodoulou, a commissioner on the Board of Public Utilities, said at the New Jersey Business & Industry Association’s annual Energy and Environmental Policy Forum, held Oct. 28-29.
As the state emerges from a vigorous, Democratic-led pursuit of offshore wind, Christodoulou warned against accepting the “agnostic” view of energy in which all sources are valid, commonly described as the “all of the above” approach.
“I know it sounds impartial and democratic,” but the word “agnostic” also “conveys a sense of ignorance and lack of knowledge,” and the state needs a more defined strategy, he said.
“We need to take some educated guesses here,” he said. “We need to find the best-of-the-above approach, not an old approach. And while we’re at it, maybe we can look at some below-the-surface approaches, like geothermal and hydrogen.”
The conference took place amid the final stages of the gubernatorial election to pick the successor to Gov. Phil Murphy (D), who aggressively pursued a clean energy strategy, the largest part of which — 11 GW of offshore wind — has largely stalled under unfavorable economic conditions and President Donald Trump’s opposition.
Energy issues have taken center stage in the state in large part from a predicted electricity shortfall and the impact on ratepayers. New Jersey ratepayers’ average electric bill rose 20% in June.
As one of the 13 states served by PJM, New Jersey faces a dramatic surge in demand, mainly because of the expected development of heavy electricity-using data centers. Analysts say the expected shortfall was also triggered by rapid closures of aging fossil fuel plants as new plants, mainly clean, have come online more slowly.
Importer or Exporter?
Former Gov. Chris Christie (R), a keynote speaker at the forum, said the state generated enough electricity that it was exporting power when he handed the reins to Murphy. He blamed the incumbent’s “hyper focus” on clean energy for the state’s current predicament and its swing to become an energy importer, rather than being self-sufficient.
“What he’s done is deter any baseload generation, and that begins the part of the problem,” Christie said. He added that the next governor will have to “bite the bullet” and develop natural gas plants.
“Their first step, in my view, if they asked [me], would be to sit down with utilities and say, ‘What do we need to do to get you to open two or three new natural gas generation plants as quickly as possible?’” he said.
But Brian O. Lipman, director of the New Jersey Division of Rate Counsel, told a panel on rates that the state has been a net importer of electricity since 1990, and that’s not a problem.
“We’re not an exporting state,” he said. “The whole point of PJM is that we could bring in cheaper electricity from other states. Generation is expensive to build, and it’s cheaper to build it, quite frankly, in Pennsylvania, in the middle of nowhere, than it is anywhere in New Jersey.
“We can talk about whether we should be an importer, and how much we should be, whether it’s economic to build in New Jersey at this time,” he said. “But the reality is, when it’s economic to build outside the state and bring electricity in, that’s what we should be doing.”
If New Jersey wants to generate its own power, then it needs to streamline and speed up the permitting process, he said. “We can do things with permitting where we can override the NIMBY issues that a lot of these projects are going to have,” he said.
He suggested the state could protect itself from bearing the burden and infrastructure costs of excessive data center demand by requiring such facilities to bring their own generation sources. But he also expressed caution.
“If you legislate too much, the data center is just going to go to another state,” he said. “And if the data center goes to Pennsylvania, we still have the same demand issues that we would have if they were in New Jersey. We just aren’t going to get any of the economic benefits that we would get if they were built in New Jersey.”
Backing Nuclear
With wind and solar largely an afterthought at the forum, the panelists more frequently focused on nuclear and gas to resolve the state’s looming power shortage.
Erick A. Ford, president of the New Jersey Energy Policy Coalition, which advocates for a “balanced” energy strategy, said the state is “uniquely positioned” to lead the move into nuclear, with an experienced workforce and a history of managing nuclear plants, including Public Service Enterprise Group’s three existing facilities in Salem and the now-defunct Oyster Creek plant.
Speakers on a panel titled “Nuclear Power – Is it in NJ’s Future?” cited several recent announcements that suggest nuclear power is increasingly viable. They included the U.S. government’s announcement on the same date as the conference that it had forged a partnership with the Canadian owners of Westinghouse Electric to spend at least $80 billion on nuclear reactors. In a separate announcement, NextEra Energy said it plans to restart the 50-year-old Duane Arnold Energy Center. (See related stories, U.S., Westinghouse Partner for $80B in Nuclear Construction and NextEra, Google Announce Nuclear Collaboration.)
New Jersey is home to a 50-acre technology center in Camden, run by Holtec International, which is restarting Michigan’s Palisades nuclear plant and plans to build two small modular reactors beside it. (See Holtec Announces SMR Plans at Palisades Nuclear Plant.)
The company also is decommissioning the Oyster Creek facility. Holtec CEO Krishna Singh told New Jersey legislators in August that the company is looking at whether four of its SMR-300 reactors could be sited in Oyster Creek, generating 1,300 MW of power.
Feasibility Challenges
Whether New Jersey is a contender for future reactors is unclear. The U.S. Nuclear Regulatory Commission in 2016 issued PSEG an early site permit for the Salem site that currently houses the three reactors it operates, but the company has yet to announce any plans for the site.
To host other facilities, the state would have to meet the needs of developers or their clients.
Ray Fakhoury, energy policy manager for Amazon Web Services, told the forum that nuclear projects will be critical to the company’s Net Zero by 2040 plan. Amazon on Oct. 16 outlined plans to build up to 12 SMRs and generate 5 GW of nuclear power by 2039.
In looking for sites to put a data center served by a nuclear project, the company’s first priority is access to a transmission line to “create the promise that there will be future growth opportunities to that potential area,” he said.
“The challenge is a one-off facility might not be so useful for Amazon because we can’t capture those economies of scale,” he said. In addition, having a site with a pre-application submitted, “early site works being done and permitting kind of being set forward are all really critical to building, and all of that is wrapped up in this nice bundle of policy certainty.”
Other challenges to developing nuclear sites in the state will be finding trained workers and overcoming the lack of a supply chain. On top of those challenges is the fact that nuclear plants take longer and cost more to build than other generating sources and so can’t meet the state’s urgent shorter-term needs.
Yet the NRC has reduced the 5-mile emergency management zone perimeter for nuclear plants, shrinking the footprint needed, which is helpful to densely populated states such as New Jersey. And nuclear plants last much longer than other plants.
Robert DeNight, vice president of nuclear engineering for PSEG, told the forum that the company may seek to extend the life of its three nuclear plants beyond 80 years, well beyond the operating license extensions it requested from the NRC last year. (See PSEG Plans for 80-year Nuclear Generation in NJ.)
“After we get 80 years, we’ll assess from a material standpoint and see if 100 years makes sense,” DeKnight said.
Patrick O’Brien, director of government affairs for Holtec, said, “The reality is you’re going to replace a wind and solar farm two or three times before you get to the end of a nuclear plant.”
“We’re running on average 95% of the time,” he said. “So there’s a lot of benefits there for long-term usage; a lot of energy density on a small piece of property.”
But any project will require investor confidence that it can be completed. And that has been sorely damaged by the Trump administration’s efforts to terminate offshore wind projects heading for completion, forum speakers said.
“The No. 1 concern is, how do I know three years, four years from now, my project will be safe?” said Matthew Leggett, an energy specialist at law firm K&L Gates. “Whether it’s an oil-and-gas project, a solar project, a wind project, any other kind of project — any multiyear, large, energy infrastructure investment has a question mark because of that uncertainty that’s been created.”
Timothy Fox, managing director at ClearView Energy Partners, added, “Project developers and especially the financiers behind those projects are going to be wary of investing in a capital-intensive industry with such demonstrable high election risk. Because can you really get a project through permitting and fully built in four years?”
