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December 8, 2025

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PJM Drops Non-capacity Backed Load, Shifts Focus to Resource Queue, PRD

PJM has withdrawn its non-capacity backed load (NCBL) proposal, shifting the focus of its solution for rising large load additions (LLAs) to creating a parallel resource interconnection queue, reworking price-responsive demand (PRD) and providing more insight into the load forecasting process for state utility commissions. (See PJM Revises Non-capacity Backed Load Proposal.)

The changes were presented Oct. 1 to stakeholders as part of PJM’s Critical Issue Fast Path (CIFP) process addressing LLAs, now in its second phase, in which design components are fine-tuned before being bundled into comprehensive solutions during phase 3. Another phase 2 meeting is scheduled for Oct. 14 with 11 proposal sponsors set to present.

PJM’s proposed expedited interconnection track (EIT) aims to create a pathway for resources capable of quickly entering service to receive a generator interconnection agreement through a 10-month study process. Applicants would be required to pay a nonrefundable study deposit starting at $500,000 and a $10,000/MW readiness deposit, as well as commit to being in service within three years of requesting an EIT study, though output may be limited if network upgrades are not complete by then. PJM Vice President of Planning Jason Connell said the EIT is envisioned as a permanent addition to the RTO’s interconnection processes.

If a resource does not enter service within three years, it would forfeit the readiness deposit and be subject to the same penalties for breaches of project milestones in the standard interconnection process.

All fuel types would be permitted, but projects would have to be at least 500 MW to participate and only 10 applications would be approved annually. The studies would be conducted according to when they were requested, and network upgrade costs would be assigned individually. No changes would be permitted in site control or attributes such as fuel type, nameplate capacity or equipment type.

Applications would be required to receive sponsorship from the state in which the resource would be located, which Connell said is intended to provide a degree of buy-in and reduce the odds that a project might receive expedited treatment from PJM only to become mired in siting and permitting challenges.

Connell said PJM decided on the 500-MW requirement by determining it would meet the amount of annual load growth expected while limiting the impact to projects in the standard interconnection queue. If a smaller requirement and larger number of applications were allowed, PJM found that would extend the amount of time needed to complete interconnection studies and defeat the purpose of an expedited pathway, he said.

Grant Glazer of MN8 Energy questioned if PJM would consider allowing a portfolio of projects to be included as one application to reach the 500-MW requirement. He said projects with a lower voltage and smaller nameplate capacity would be faster to develop and could provide a more economic form of capacity than larger resources.

PJM’s Tim Horger said EIT studies would use the latest system model case, and the upgrades they’re assigned would be added to the modeling for the next queue cycle. For any projects submitted while Transition Cycle 2 is ongoing, the latest model for that cluster would be used, and the resulting network upgrades would be added to the modeling for Cycle 1.

Adrien Ford, Constellation Energy’s vice president of wholesale market development, questioned if PJM would consider shrinking the 500-MW threshold, saying there are 300-MW uprate projects to nuclear units that could take advantage of the process.

Connell said PJM did not focus on facilitating uprates, as there are already opportunities for their studies to be accelerated.

Unpopular NCBL Dropped

The NCBL concept would have required participating large loads to forgo the guarantee of capacity, exempt them from paying for the service and removed that load from the capacity market.

It would have been triggered if the amount of forecast supply in a Base Residual Auction (BRA) fell short of the amount of expected demand.

The mandatory variant of the proposal received the greatest backlash from stakeholders, who argued it would make the PJM region unattractive for data center developers and undermine market signals. Opponents also argued that making the model voluntary would not solve jurisdictional issues around the RTO defining the retail service consumers could receive.

PJM sought to address the jurisdictional challenges by shifting the responsibility for assigning NCBL status to customers onto electric distribution companies and load-serving entities. It would have determined the RTO-wide amount of NCBL that would be needed to meet the reliability requirement in an auction and allocated portions to zones according to the amount of planned large loads forecast.

Claire Lang-Ree, an advocate with the Natural Resources Defense Council, said it was unlikely that resources utilizing EIT would be able to enter service before 2030, and thus would be unable to help with high capacity prices until after 2033. She questioned whether PJM’s revised proposal could deliver the same reliability as the mandatory NCBL concept.

Old Dominion Electric Cooperative’s Mike Cocco said removing NCBL from PJM’s proposal eliminates the original’s core design component from a reliability perspective. He said the load growth in PJM is unprecedented, and there needs to be a way to ensure it can be integrated reliably without impacting existing consumers, which NCBL would have accomplished. He suggested that changes to the manual load shed procedures could provide a similar benefit, but these decisions need to be part of the centralized CIFP solution, as the issue will only become more contentious if stakeholders wait to negotiate until after the capacity auction.

Horger said PJM is considering changes to manual load shed, but those will likely come outside the CIFP process.

Additional Changes to CIFP Proposal

Instead of the NCBL construct, Horger said PJM is now proposing changes to PRD to encourage flexibility from large loads.

The dynamic retail rate for PRD would be replaced with an energy market price, with the strike price serving as the offer. Horger said the change would make PRD function similar to a voluntary NCBL construct.

PJM is also proposing changes to its load forecasting process to add a step in which state utility commissions could review and provide feedback on the LLAs submitted by utilities under their jurisdiction.

Entities submitting LLAs would be required to ask the customer requesting service whether they are considering multiple sites for their projects and provide that response to PJM. Horger said the change is intended to identify instances where several utilities are projecting load growth for a data center that will ultimately only be built in one location.

Commitments to procure a minimum amount of capacity for planned large load customers are also being considered.

PJM Executive Vice President of Market Services and Strategy Stu Bresler said the RTO is open to exploring a model for long-term capacity procurement, either as part of its CIFP proposal or through subsequent stakeholder processes. He noted that the reliability backstop auction provides for some of that capability already, albeit following three years of the capacity market falling short of the reliability requirement and FERC approval of its implementation.

Advanced Power Proposes Higher Maximum Price

A design component from Advanced Power would double the maximum price of an Incremental Auction (IA) if the corresponding BRA clears short of the reliability requirement and use the increased ceiling for the subsequent BRA if the higher price is needed to clear enough capacity.

Ron Paryl, vice president of markets and risk management for Advanced, said this would create an additional opportunity for demand response to resolve the shortfall, while also allowing the auction to be responsive to updates to load forecasts and provide price discovery for the value of capacity. It would also avoid discrimination between consumers and allow those most price-sensitive to avoid high capacity costs, he said.

Advanced also proposed to lock resources’ effective load-carrying capability ratings if they would fall between a BRA and corresponding IAs, preventing sellers in the BRA from having to procure additional capacity to cover their commitment, particularly if prices increase above the original maximum price under the company’s first two components. If ELCC ratings increase, the resource owner would be able to bid that additional capability into the auction.

The potential for changes to the load forecast to shift resources’ ELCC ratings was seen in discussions around how to apply the 2025 load forecast to the parameters for the third 2025/26 IA; the forecast led the risk profile to shift toward the winter, causing ratings for several resource classes to fall. PJM opted not to include preliminary figures from the forecast, and stakeholders voted to lower the Capacity Performance penalties resources face if they cannot meet their commitment due to falling accreditation. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

Stakeholders questioned how DR offers are mitigated and whether the proposal would create market power concerns, while DR providers said adding reviews of offers would be complicated for aggregated resources.

Paryl said there is no requirement that DR be mitigated and so it should be able to make offers the sellers feel represent the costs for them to curtail.

Joint Proposal from Suppliers, Data Centers

A proposal from large suppliers and data centers would focus on making the forecasting of large loads more accurate and add triggers for demand and supply-side solutions. The proposal was sponsored by Calpine, Constellation, Talen Energy, Amazon, Google and Microsoft.

Large loads would be required to provide commitments, such as electric service agreements or arrangements to bring their own supply, in order to be included in the load forecast. A “reality check” would look at possible supply chain constraints, historic completion rates and other factors that could inhibit the number of projects completed. Characteristics such as ramping and utilization would also be factored in.

If a BRA falls below 98% of the reliability requirement, the demand-side solutions would be implemented immediately in that auction, starting with a voluntary large load DR model where participation is limited to a set number of hours a year, with reduced ELCC ratings. That could be followed by deployment of a new emergency procedure dispatching emergency backup generation to bring some of the large loads off the PJM system. The final step would be a curtailment of large loads participating in a voluntary model akin to NCBL.

If a shortfall persists after the demand-side options have been implemented, the proposal would see PJM solicit multiyear commitments of up to seven years, with shorter offers clearing first. Eligible resources include new and reactivated generation, existing generation with an offer cap above the top of the variable resource requirement (VRR) curve and DR. Those resources would clear at the top of the VRR curve and then enter subsequent auctions at the default gross avoidable-cost rate for their technology class minus the unit-specific estimated energy and ancillary service revenues. The clearing price the units would receive would remain the same across the duration of their commitment. The model would be in place between the 2028/29 and 2031/32 BRAs.

Constellation’s Ford said the BRA trigger criteria are important to minimize the impact to the market signals to attract long-term solutions. “We really want to avoid reliance on these potentially lower-quality products,” she said.

Enchanted Rock

A proposal from microgrid and backup power developer Enchanted Rock would establish a voluntary NCBL model in conjunction with states, EDCs and LSEs to allow large loads to be more flexible and create a pathway for them to interconnect ahead of network upgrades that might inhibit their ability to be reliably integrated onto the grid on a firm basis.

Joel Yu, Enchanted’s senior vice president of policy and external affairs, said voluntary NCBL is the best option for providing data centers with the ability to choose their level of flexibility, but there needs to be more adequate incentives on the supply side.

“If that load is making a commitment to provide flexibility via an NCBL structure or perhaps a different structure — as long as that flexibility can be modeled up front in an interconnection study process — we believe there’s an avenue for that load to access some amount of non-firm grid service on a provisional basis,” Yu said. “We’re not proposing any changes or options with respect to broader planning processes, but [it would] help to attract voluntary participation via the speed-to-power incentive.”

Additional Proposals to be Discussed Oct. 14

Several stakeholders have also submitted alternatives, to be presented during the CIFP meeting Oct. 14.

They include a joint proposal from Eolian Energy and the Brattle Group; proposals from the NRDC, Vistra and East Kentucky Power Cooperative; and a package from Johns Hopkins University associate professor Abe Silverman and Sue Glatz, principal consultant at Glatz Energy Consulting.

There will also be presentations from NOVEC, the Independent Market Monitor, Mainspring Energy, the Maryland Office of People’s Counsel and the office of Pennsylvania Gov. Josh Shapiro, but materials from these had not been posted online as of press time.

The EKPC proposal would require that large loads identify the LSE that will serve them before they can be incorporated into the load forecast and VRR curve, and institute “significant” penalties for LSEs that do not cover their own demand through owned or bilaterally contracted capacity. The penalties would only be assessed against LSEs within locational deliverability areas that are short of their reliability requirements in a BRA. Large loads would be defined as at least 50 MW.

Vistra proposed to impose penalties on any LSEs that are capacity deficient during emergency procedures in an effort to create an incentive for physical hedging and load flexibility. It includes a handful of options for how penalties could be determined.

The NRDC proposed a mandatory NCBL variant for any large loads coming online after the 2026/27 BRA that are not bringing their own generation. Large loads would also be able to gain firm service by participating as DR or PRD, or signing other loads to participate on their behalf; their curtailment risk could also be reduced by contracting with energy-only generation.

The Eolian and Brattle package would create a bilateral integration of generation portfolios and load structure for large loads to procure capacity through adjacent supply, with some backup provided by load flexibility. New resources participating would qualify for a 90-day expedited interconnection study and would not have their output derated by ELCC; instead, the owners of the resource and load would share the risk of underperformance.

The proposal from Silverman and Glatz is based on mandatory NCBL for new large loads so long as the capacity auction clears above the midpoint on the VRR curve. Another option would be to bifurcate the auction, first clearing non-LLA customers and then running a second auction for LLAs and any capacity resources that did not clear in the first run. To reduce the potential for double-counting large loads, they proposed to exclude them from the load forecast unless the relevant utility confirms that all distribution and transmission upgrades will be complete on time; the customer attests that it is not considering alternative locations for the project; and the customer can provide evidence of commercial maturity.

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Split Colo. PUC Approves Xcel Energy’s Markets+ Application

The Colorado Public Utilities Commission on Oct. 9 issued a split decision approving Public Service Company of Colorado’s application to join SPP’s Markets+, finding that market participation is in the public interest and will “provide a number of benefits.” 

The commission, in a 2-1 vote, approved PSCo’s participation, with Chair Eric Blank and Commissioner Tom Plant finding in favor of the request and Commissioner Megan Gilman dissenting. 

PSCo, a subsidiary of Xcel Energy, filed its request to join Markets+ in February. The commission voted to approve the utility’s participation July 30 but did not issue a comprehensive written decision — including approval of some cost-recovery measures — until now. (See Colo. PUC Approves PSCo’s Markets+ Participation.)  

“In sum, we grant Public Service’s application and authorize the company to recover the costs associated with joining SPP Markets+ because increased integration between Public Service and other utilities in the Western Interconnection will likely provide a number of benefits in the short term, while allowing the company and stakeholders to explore longer-term benefits that may result from [organized wholesale markets] or continued Markets+ participation,” Blank and Plant wrote. 

PSCo’s participation in Markets+ is in the public interest and will improve dispatch of generation resources in Colorado while alleviating market seams, Blank and Plant found. “Adding to those economic benefits are other shorter-term benefits, including near-term resource adequacy benefits associated with participation in the Western Resource Adequacy Program (WRAP),” the commissioners said. 

Markets+ has in place efficient greenhouse gas accounting mechanisms, and participation will lead to wholesale market price transparency and financial benefits, Blank and Plant wrote. Participation in Markets+ also is a step toward PSCo potentially joining an RTO in the future, the decision noted. 

However, Gilman did not share Blank and Plant’s conclusions, reiterating many points she made when the PUC approved PSCo’s Markets+ participation in July.  

Instead, Gilman sided with four organizations that intervened in the case to urge the commission to deny the application. Gilman wrote in her dissent that PSCo “fundamentally failed to satisfy the public interest criteria listed in commission Rule 3752(a) and, therefore, should have properly been denied by the commission without prejudice.” 

For example, Gilman argued that Markets+ lacks sufficient greenhouse gas accounting protocols, noting those are still in development, “leaving the final result unknown.” 

“Further, several parties point to the new potential for unprecedented federal interference, especially related to emissions tracking,” Gilman added. “Such an obvious and emerging risk should not be taken lightly and could stand to significantly complicate processes moving forward.” 

Blank and Plant noted in the decision that Colorado will have some utilities participating in RTO West and Markets+, both of which are operated by SPP, arguing that this is progress toward resolving seams issues. 

However, Gilman said, “There does not appear to be a solid plan for better integration of these markets, nor a timeline upon which to do so provided in this record.” 

Gilman also appeared skeptical that PSCo’s Markets+ participation will lead to greater economic benefits or that the utility will join an organized wholesale market by 2030 as required under Colorado law. 

On the issue of resource adequacy, Gilman noted that while SPP requires Markets+ participants to also join WRAP, the utility “could join the WRAP independent of joining Markets+.” 

“So, while it is accurate that such benefits could come from the necessity to join the WRAP in order to participate in Markets+, it is disingenuous to point to this as a benefit of Markets+, as the WRAP benefits could be achieved for a significantly lower cost in just joining WRAP itself,” Gilman added. 

Advanced Energy United was one of the intervening parties in the case. 

The organization’s regulatory director, Brian Turner, sits on the Launch Committee of the West-Wide Governance Pathways Initiative, established to shift governance of EDAM from CAISO to an independent regional organization. 

“This decision further balkanizes the Western grid, leaves Colorado clean energy isolated, and undermines Colorado’s ability to ensure an affordable, reliable energy future,” Turner told RTO Insider in an email. 

“We are pleased the Colorado Public Utilities Commission approved our participation in Markets+, a wholesale energy market that will benefit our customers and Colorado,” Xcel Energy spokesperson Michelle Aguayo said in an email. “Markets+ is anticipated to lead to economic, operational and environmental benefits, by reducing operational costs through more efficient use of generation resources, which could lead to lower overall energy costs for customers. When paired with a robust transmission network, it can enhance reliability of the power grid by providing sufficient generation resources during times of increased demand.” 

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Ørsted to Slash Workforce, Refocus on European OSW

Ørsted will reduce its workforce roughly 25% through the end of 2027 as it wraps up construction of offshore wind farms and remakes itself as a more competitive company.

The Danish company said Oct. 9 that it expects to shrink from approximately 8,000 employees to about 6,000 in the next 27 months, starting with around 500 who will be made “redundant” before the end of 2025.

CEO Rasmus Errboe made no specific mention of Ørsted’s U.S. projects in a news release, except to say that the company is committed to finalizing its existing portfolio off the coasts of three continents.

Ørsted’s financial problems stem to a significant degree from the U.S. market, where it built an early leadership position but has been sustaining substantial cost increases and impairments for more than two years. The future is even bleaker, thanks to President Donald Trump’s open hostility to offshore wind development and his administration’s efforts to thwart it.

Errboe said Ørsted will focus on the European market and certain Asian markets in its future offshore wind development efforts. In early 2024, the company said it remained committed to U.S. operations, despite problems there. (See Ørsted Exits Offshore Wind Markets, Remains Committed to US.)

The workforce reduction will come through attrition, terminations, divestment and outsourcing. Errboe said the process will yield a company that is more financially robust, competitive, efficient and flexible — and better able to bid on new offshore wind projects that would build value for Ørsted. It is expected to yield $310 million in annual cost savings.

“We’re committed to maintaining our position as a market leader in offshore wind,” he said. “We also need to reduce our costs for developing, constructing and operating offshore wind farms to strengthen our competitiveness.”

Ørsted has the largest fleet in the offshore wind industry, and the 8.1 GW now under construction would bring its installed capacity to 18.3 GW.

The company operates the first offshore wind farm built in U.S. waters, Block Island Wind, and the first utility-scale facility, South Fork Wind. It is building Revolution Wind and Sunrise Wind off New England and New York. It previously canceled its Ocean Wind project in New Jersey and paused Skipjack Wind in Maryland.

The portfolio is the largest in U.S. waters, and it ran into financial trouble well before Trump was elected to his second term, as the industry struggled with cost and supply chain challenges.

In the 11 months since the election, things have gotten even worse for Ørsted, culminating in a monthlong federal stop-work order in August against Revolution Wind, which was 80% complete at the time. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

Ørsted in August announced it would raise $9.3 billion and self-finance Sunrise Wind. (See Ørsted to Raise $9.3B, Self-finance Sunrise Wind.) Its stock price cratered on the news, punctuating a yearslong slide. The share price has rebounded since then but still is only half what it was a year ago.

Errboe spoke with journalists Oct. 7, after conclusion of Ørsted’s rights issue of new shares to raise the cash. Reuters reported that he said work has fully resumed on Revolution Wind, which is expected to begin operation in the second half of 2026, and that Sunrise Wind is still targeted for commercial operation in the second half of 2027.

Ørsted has said the combined investment in Revolution and Sunrise will be approximately $15.5 billion.

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Renewable Construction Slump Starts in 2028, Forecast Shows

U.S. construction of new wind, solar and energy storage facilities will decrease significantly over the next five years, with a cliff dive projected to take place in 2028, a BloombergNEF analyst said in an Oct. 8 presentation to the California Energy Commission. 

About 81 GW of new wind, solar and energy storage capacity is projected to be installed in the U.S. in 2027, falling to around 48 GW the following year, the analyst said. In total, the wind, solar and storage resource buildout by 2030 will be 23% below forecasts prior to the Trump administration’s One Big Beautiful Bill Act. 

The large drop in 2028 will stem from the effects of recent federal policies that will be seen more broadly by that time, Derrick Flakoll, policy expert at BloombergNEF, said at the CEC’s Oct. 8 business meeting. Renewable energy projects are, on the contrary, forecast to increase in the next two years as developers “rush to qualify for federal subsidies,” he said. 

But when the decline happens, it will be due in part to new restrictions placed on countries designated as foreign entities of concern, Flakoll said. 

“For both clean energy manufacturing and clean energy deployment, there are penalizations for … supply chains that are tied to China,” Flakoll said. “For projects beginning in 2026, anything other than energy storage needs to be at least 40% non-Chinese … or non-Foreign Entity of Concern.” 

Although construction of renewable energy projects will drop in the coming years, the impact could have been much harder, he said. 

“One reason we only see that 23% decrease is that renewables are generally the fastest thing to get on the grid,” Flakoll said. 

Wind, solar and storage are on average faster to connect to the grid than gas turbine facilities in all markets, except MISO, he said. 

Offshore wind projects are expected to see the sharpest decline in construction. 

“We don’t really see a lot of offshore wind [projects] coming online through 2035,” Flakoll said. “For markets like California, where floating offshore wind is in early stages, we don’t really see anything happening through 2040.” 

Even though construction of clean energy projects will slow in the U.S., domestic manufacturing of utility-scale energy storage equipment is projected to increase dramatically over the next 10 years, from about 12 GWh in 2025 to more than 60 GWh in 2035. This is due in part to battery manufacturing facilities in the U.S. shifting from making batteries for electric vehicles to building batteries for energy storage. 

“There might actually be enough [battery manufacturing] to meet U.S. demand,” Flakoll said. 

CEC Vice Chair Siva Gunda asked about the cost of EV charging in California versus other parts of the U.S.  

Prices will be different for each market, such as in California versus PJM, Flakoll said. These price differences “are ultimately political choices,” he said. 

“The way that California chooses to pay for certain [energy] programs might have an effect on electricity rates,” Flakoll said. “It is [also] based on California’s changing policy landscape. … We are seeing so much policy change in California as we speak.” 

Idaho Gas Plant Capacity Approved for Calif. Utilities

At the Oct. 8 meeting, the CEC also determined that a new, planned natural gas plant in Idaho meets California’s carbon dioxide emissions requirements. The gas plant can therefore provide capacity to Lassen Municipal Utility District and the Truckee Donner Public Utility District, the CEC said in its decision. 

The CEC specifically found that the gas plant’s emission in Idaho will be below the CEC’s Emission Performance Standard for Local Publicly Owned Electric Utilities, which limits generator facilities to 1,100 pounds of CO2 per MWh of energy. 

The planned 364-MW gas plant will be built in Power County, Idaho and owned by the Utah Associated Municipal Power Systems. It will provide about 7 MW of capacity to Lassen and 5.25 MW to Truckee, with both 30-year contracts starting on July 1, 2031. 

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NYISO Reliability Plan Calls for ‘New Dispatchable Generation’

NYISO released an updated draft of its Comprehensive Reliability Plan for 2025-2034 that calls for the acceleration of new generation development and preservation of “critical, dispatchable capability.”

“New York’s electric system faces an era of profound reliability challenges as resource retirements accelerate, economic development drives demand growth and project delays undermine confidence in future supply,” NYISO writes in the plan’s conclusion. “While this 2025-2034 CRP … identifies no actionable reliability need, this outcome should not be mistaken for long-term system adequacy. The margin for error is extremely narrow.”

This is from the broad range of scenarios for load growth, generation retirement and new generation construction. The majority of NYISO’s scenarios forecast statewide reserve margin declines. (See NYISO Dogged by Uncertainty in Comprehensive Reliability Plan.)

“In the best-case scenario we might have a reliability margin of 2,000 MW,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group on Oct. 7. “Worst case, we could be deficient by 10,000 MW.”

The ISO is calling for “several thousand megawatts of new dispatchable generation” by the 2030s.

“Depending on the load and the way that demand grows, the projected [amount] of green generation may not be enough,” Altman said. “Storage and renewables help, but they don’t get us all the way there.”

Environmental stakeholders at the meeting said this amounts to a call for new fossil fuel generation without outright saying it. But Matt Schwall, director of regulatory affairs for Alpha Generation, noted that NYISO did not “parse words” in its comments on New York’s draft State Energy Plan. “They clearly indicate there’s a need for fossil fuel-based generation: retention of existing and installation of new.”

He went on to say that if the word “dispatchable” was an issue, then maybe the term that should be used is “fossil fuel generation.”

“Well, I would ask for the empirical basis of that as well,” replied Michael Lenoff, an attorney representing Earthjustice.

Another stakeholder asked whether the ISO could highlight a “maybe not probable,” but possible, scenario where the reserve margin slips as soon as 2028. The stakeholder said that such a scenario was critical for evaluating the risks to the grid over the next five years.

NYISO recommends that reliability planning move away from a “reactive posture” toward a more proactive approach. The ISO’s preliminary recommendations include:

    • accounting for a wider range of outcomes in reliability planning rather than relying on a single “expected future”;
    • strengthening reliability planning beyond reliance on emergency measures;
    • including more approaches to address resource shortfalls beyond additional transmission planning; and
    • addressing system voltage performance issues from changes in flow patterns caused by distributed generation and large upstate loads.

NYISO said these recommendations may require changes to its planning process manual and tariff, which it plans to discuss with stakeholders in upcoming meetings.

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WPP Board Declines to Delay WRAP ‘Binding’ Phase Commitment Deadline

The Western Power Pool’s Board of Directors has denied PacifiCorp’s request to postpone the deadline by which Western Resource Adequacy Program (WRAP) participants must commit to the first “binding” phase of the program, scheduled for winter 2027/28. 

The board’s rejection comes just three weeks before the Oct. 31 commitment deadline and likely adds to the uncertainty building around how many participants could abandon the WRAP before it enters its penalty phase. NV Energy has already notified the Public Utilities Commission of Nevada of its intent to withdraw from the program. (See NV Energy to Withdraw from WRAP.) 

PacifiCorp CEO Cindy Crane requested a one-year postponement of the deadline in a letter to the board Sept. 30. She contended that the WRAP’s Day-Ahead Markets and Planning Reserve Margin task forces have identified critical issues that have emerged since the program was launched in 2020 — including challenges stemming from the split between participants choosing to join either CAISO’s Extended Day-Ahead Market or SPP’s Markets+. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.) 

In rejecting PacifiCorp’s request, WPP board Chair Bill Drummond said the board determined a delay would have a “detrimental effect” on the WRAP and its participants. 

“Delaying the participant decision deadline or the start of binding operations adds uncertainty, undermines confidence in our data and modeling, limits program compliance and stifles unlocking the full benefits of the program, which can only come with the certainty of binding operations,” Drummond said Oct. 8 in a letter addressed to Crane. 

Drummond added that the board “does not believe that the unilateral board action requested by PacifiCorp aligns with the tenets or the spirit of the established governance process, and driving such a request through the process contemplated by the [WRAP] tariff is not feasible with so little time before the decision deadline.” 

He said the voluntary nature of the WRAP “necessitates a bottom-up, member-driven process to make changes that will affect all participants in the program.” 

Drummond also noted that in September, 11 WRAP members “with substantial load, resources and geographic diversity” affirmed their commitment to the winter 2027/28 binding phase, a development that created “critical mass to move forward with confidence.” (See WRAP ‘Binding’ Phase Set for Winter 2027/28 After Utilities Affirm Commitment.) 

“Any further delay would jeopardize this critical progress,” Drummond wrote. 

Ten of those 11 members have already committed to joining Markets+, which requires its participants to join the WRAP. Starting in 2026, PacifiCorp will be the first participant in the EDAM, which has no RA program requirement. 

Addressing a second request by Crane, Drummond said WPP will continue to work with stakeholders to refine the design of the WRAP, pointing to “work underway to optimize the program in response to suggestions from participants, including task forces addressing some of the challenges you raised in your letter. These efforts are following the same governance process I referenced earlier.” 

Drummond acknowledged that his response might not satisfy PacifiCorp’s concerns about the WRAP and that the utility “may need to provide notice this month of intent to exit the program” before the first binding season. He said the program’s two-year exit notice means exiting participants continue to comply with the WRAP and remain able to engage in the stakeholder process. 

Asked to comment on Drummond’s letter and on whether the board’s response would mean PacifiCorp will not commit to the WRAP binding phase by the end of October, company spokesperson Omar Granados told RTO Insider: “PacifiCorp appreciates the Western Power Pool and its leadership in addressing resource adequacy in the West. We understand the constraints under which WPP is operating. 

“PacifiCorp remains committed to resolving resource adequacy challenges and engaging with regional partners to identify the best long-term solutions for our customers. With this in mind, we will use the time between now and the deadline to determine the best course of action.” 

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ISO-NE Reveals 1st Details of Long-term Transmission Proposals

ISO-NE received six proposals from four different companies in response to its request for proposals to address transmission constraints and interconnect onshore wind in Maine, COO Vamsi Chadalavada told the NEPOOL Participants Committee on Oct. 9.

The costs of the proposals range from about $960 million to $4.04 billion, Chadalavada said. Three of the proposals primarily rely on AC transmission, and three rely on HVDC, he added.

Despite ISO-NE’s attempts to standardize the cost calculation requirements, some of the proposals include the cost of corollary upgrades in their price estimates, Chadalavada said. The RTO will attempt to “create an even playing field” between proposals that included corollary upgrade costs and those that did not, he added.

The Longer-Term Transmission Planning procurement requires proposals to increase the capacity of the Maine-New Hampshire interface to 3,000 MW and the Surowiec-South interface to 3,200 MW, and support the interconnection of at least 1,200 MW of onshore wind in Northern Maine. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

Chadalavada said all proposals claim to meet these basic requirements and that ISO-NE received proposals to increase the Maine-New Hampshire interface to 3,600 MW and Surowiec-South to 3,800 MW.

The Maine-New Hampshire interface currently is limited to 2,000 MW, while Surowiec-South is limited to 1,800 MW. When the New England Clean Energy Connect (NECEC) line comes online — potentially around the end of 2025 — ISO-NE plans to increase the transfer limit of Maine-New Hampshire to 2,200 MW and Surowiec-South to 2,800 because of the upgrades associated with NECEC.

Also at the PC meeting, Chadalavada discussed market operations and performance, noting that energy market costs totaled $358 million in September (based on data through Sept. 30), an increase from $321 million in September 2024.

He said a planned transmission outage from mid-October to mid-November will limit flows from New York to New England to about 1,000 MW and flows from New England to New York to between 500 and 600 MW.

Responding to a stakeholder question about expected power imports from Québec in the coming winter, Chadalavada said ISO-NE’s “expectation is that we are going to see a reduced volume of imports, consistent with the past few years, but when we face really cold conditions, we expect the ties to be fully utilized.”

Imports from Québec have dropped significantly since early 2023, largely because of prolonged drought conditions in the province. Despite the significant reduction in total import volume, Hydro-Québec has continued to send large amounts of power during high-price periods in New England and has earned significant Pay-for-Performance credits in recent capacity scarcity events. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)

The PC also voted to approve planning procedure and operating procedure changes, including changes that set the load power factor ranges throughout the region. The revisions are “designed to address growing concerns around light-load and high-voltage conditions as the quantity of distributed energy resources on the New England system continues to increase.”

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European Regulator Issues ‘Factual Report’ on Iberian Outages

A new report from Europe’s electric grid regulator has revealed new details about the continent’s power system during April’s mass outages in Spain and Portugal, but insight into the causes of the blackout will have to wait for a follow-up report to be issued in 2026. 

The “Grid Incident in Spain and Portugal on 28 April 2025” document, issued Oct. 3 by the European Network of Transmission System Operators (ENTSO-E), constitutes “a factual record to transparently inform stakeholders and governance bodies” and not an assignment of blame for the mass outages. ENTSO-E is an association of 40 transmission system operators (TSO) spanning 36 European countries. 

The outage began the afternoon of April 28 and left the entire population of Spain and Portugal, as well as parts of France, without power for up to 18 hours. Spain’s government and grid operator Red Electrica released separate reports in June concluding the blackouts occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from frequency oscillations exacerbated by a faulty power plant controller.  

Reviewing those reports, U.S. experts — including NERC Chief Engineer Mark Lauby — said the U.S. grid was unlikely to suffer similar challenges because of reliability requirements put in place by FERC and NERC. Lauby said NERC would have to wait for ENTSO-E’s report “to gain any [further] insights into the incident. (See Lauby Says U.S. ‘On the Right Track’ After Iberian Blackout.) 

An expert panel comprising representatives of affected and non-affected transmission system operators (TSOs), national regulatory authorities, regional coordination centers (RCCs) and the European Union’s Agency for the Cooperation of Energy Regulators wrote the report. ENTSO-E set up the panel May 12 to review the outages as required by the EU’s Incident Classification Scale methodology after an event is classified as a Scale 3 incident, meaning termination of operation of part or all of a TSO’s transmission system. 

Red Electrica, Redes Elétrica Nacional and Réseau de Transport d’Électricité — the TSOs for Spain, Portugal and France, respectively — provided input and suggestions for specific chapters but did not act as primary authors for the chapters on their regions. The report’s authors wrote that this was “to ensure the neutrality of the reports delivered by the expert panel.” 

‘Systems Collapsed’

According to ENTSO-E’s report, at 9 a.m. the day of the incident, Spain’s electric grid began to display increasing variability in voltage. These variations were not significant until shortly after 10:30 a.m., when voltage briefly exceeded 430 kV in part of the 400-kV transmission network. 

When the outages began at 12:32 p.m., the voltage of the 400-kV network was below 420 kV and no oscillations with amplitude higher than 20 MHz were observed. Between 12:32:00 and 12:32:57, 208 MW worth of distributed wind and solar generators in southern Spain tripped offline, while distribution grids experienced a rise in net load of about 317 MW. The report’s authors did not identify a cause of this increase but theorized it “might be due to the disconnection of small embedded generators [of less than] 1 MW or to an actual increase in load,” or both. 

Major disconnection events occurred from 12:32:57 to 12:33:18 in the Granada, Badajoz, Sevilla, Segovia, Huelva and Cáceres regions, leading to an additional loss of at least 2 GW of generation. The reason for most of these trips is not known, though the report attributed an unspecified amount to over-voltage protection.  

No generation trips had been observed in Portugal or France up to this point. That changed between 12:33:18 and 12:33:21, when a sharp voltage increase in southern Spain bled over into Portugal, triggering “a cascade of generation losses that caused the frequency of the Spanish and Portuguese power system to decline.” Both countries’ grids began to lose synchronism with the rest of the European power system at 12:33:19.  

At that point, the automatic load shedding and system defense plans of Spain and Portugal were activated but could not prevent the ongoing collapse of the Iberian grid. At 12:33:20, the AC interconnection to Morocco tripped due to underfrequency, and a second later, protection devices disabled the AC overhead lines between France and Spain. Finally, the HVDC lines transmitting power from Spain to France tripped at 12:33:23 and “all system parameters of the Spanish and Portuguese electricity systems collapsed.” 

The French grid was “marginally affected,” according to the report. France experienced load loss of about 7 MW, and one nuclear power plant tripped offline during the incident. 

A review of RCC data indicated the grid was considered secure at the time of the event and no major issues were known. No congestion had been detected on the Iberian transmission network, and the available production capacity was believed to be sufficient for expected consumption. 

In an email to ERO Insider, Lauby wrote that NERC is reviewing ENTSO-E’s factual report and waiting for the regulator to issue its final report on the root causes of the outage, which is being developed by the same panel and expected in the first quarter of 2026. Lauby called this timeline “typical” for detailed system studies. 

“Overall, the lessons learned have not yet changed — that is, to ensure the actions taken to manage oscillations do not exacerbate the ability [to] manage voltage on the system [and] that generating resources should be enabled to provide dynamic voltage support,” Lauby wrote.  

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N.J. Seeks to Promote Energy-efficient Construction

The New Jersey Board of Public Utilities is looking to stimulate energy-efficient construction with a new program launched Oct. 7 that offers a simpler incentive application process and incentives of up to $2.50/square foot. 

The New Construction Program (NCP) provides builders, developers and project stakeholders with a “single point of entry” through which they can access a portfolio of financial incentives, the BPU said in a release. It replaces several old programs that were accessed independently with a consolidated system that offers “three distinct pathways” designed to meet the needs of different projects. 

Incentives under the new program start at $1/square foot for buildings that are ENERGY STAR certified or meet LEED V4.1 standards, rising to $2.50 for projects that achieve PHIUS certification, the board said. Projects can earn more incentives if they offer greenhouse gas reduction, develop affordable housing, or create industrial and high-energy intensity buildings in priority zones. 

BPU President Christine Guhl-Sadovy called the NCP a “pivotal step forward in making high-performance buildings more affordable and comfortable for New Jersey residents and businesses.” 

“By consolidating our previous programs and offering enhanced incentives, we’re creating clear pathways for builders to deliver energy-efficient buildings that reduce utility costs, improve indoor comfort and support those who choose to pursue clean energy options,” she said. 

Emphasis on Decarbonization

Creating energy-efficient buildings, mainly by electrifying heat and water heating systems, is a key plank of Gov. Phil Murphy’s effort to cut emissions and reach the state’s goal of having 100% clean electricity by 2035.  

The BPU is refining a new Energy Master Plan, a follow-up to the 2019 version, both of which lean heavily on building electrification. (See N.J. Releases Electrification-focused Energy Master Plan.) In December 2023, Murphy signed an executive order setting a goal of electrifying 400,000 additional dwelling units and 20,000 additional commercial spaces or public facilities by December 2030. (See N.J. Advances Multifaceted Building Decarbonization Strategy.) 

The NCP “strongly emphasizes decarbonization technologies, offering bonus incentives for projects incorporating all-electric systems such as heat pumps, helping support builders or homeowners who choose to pursue highly efficient and decarbonized air and water heating systems,” according to the BPU. 

In one of the options, a so-called “bundled pathway” combines several energy conservation measures that can be used on commercial and industrial buildings. A second, “streamlined” pathway offers a much simpler process for projects that harness only energy conservation measures. And a third, “high-performance” pathway allows the developer to obtain the most generous incentives by meeting “nationally recognized certifications.” 

DEP Seeks to Make Electrification Funding Easier

The BPU’s launch of NCP coincided with the announcement by the New Jersey Department of Environmental Protection of a new online tool that seeks to help residents, local governments, nonprofits and businesses find incentives for building electrification and other climate mitigation projects. 

The New Jersey Funding One Stop Shop can help reduce project costs by estimating which incentives are available and what percentage of a project is funded. It asks users about the project and provides information on possible grants, rebates, financing options and a technical assistance program, according to a DEP release. 

Among the target categories for the website are “building energy efficiency” and “energy generation.” The possible funding sources include the state’s $15 million NJ Cool pilot program, which opened in May and provides financial assistance to commercial, industrial and institutional building owners and tenants undertaking retrofit projects that reduce operating emissions from existing buildings. 

Another program reached through the site is one offered by Jersey Central Power & Light, one of four utilities that serve the state, which offers commercial and industrial customers up to $4 million for a “tailored, non-standard energy efficiency project.” 

“The One Stop Shop database is an easy-to-use tool that can help residents, local governments and nonprofits pursue critical green projects, like homeowners installing a heat pump [and] a government transitioning to an all-electric vehicle fleet,” DEP Commissioner Shawn M. LaTourette said. 

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FERC Ends Rule Pausing Pipeline Construction Pending Rehearing

FERC issued a final rule Oct. 7 that removes regulations that paused natural gas pipeline and LNG export facility construction pending appeals in order to encourage the development of plentiful gas at reasonable prices (RM25-9).

The rule reverses Order 871, which stopped the issuance of authorizations to proceed with construction of pipelines and LNG export facilities while rehearing requests were filed in opposition to project construction, operation or need. The order also adopted a policy of presumptively staying projects when a landowner affected by eminent domain protested a project.

FERC cited President Donald Trump’s executive orders seeking to “unleash” U.S. energy and prioritizing the construction of energy infrastructure. (See What is and isn’t in Trump’s National Energy Emergency Order.)

In April, the pipeline trade group Interstate Natural Gas Association of America filed a petition for rulemaking seeking to rescind Order 871, arguing a decision from the D.C. Circuit Court of Appeals affords stakeholders the same protections. The court allowed affected landowners and others to file an injunction halting construction as soon as 30 days after a rehearing request has been filed at FERC.

INGAA also argued the order effectively presumed FERC’s approvals of pipeline are wrong, which subjects developers to unnecessary costs and construction delays. Most of the requests under Order 871 came from parties that do not own land, INGAA said, arguing it had become a tool to delay authorized projects.

FERC issued a proposal to eliminate the order and its rules pausing construction in June, saying more gas pipelines are needed to meet increasing demand for the fuel from end users and power plants, and that pipeline expansion would make both the gas and bulk power systems more reliable.

Opponents included major environmental organizations, who argued that the court decision allowing for quicker injunctions still could let developers start construction on land seized by eminent domain before a stay from the courts was issued. FERC said that those concerns are addressed by existing landowner protections.

“The commission will continue to consider stay requests from landowners on a case-by-case basis, as well as continue the presumptive stay policy established in Order No. 871-B,” FERC said in the final rule. “The presumptive stay policy specifically protects directly affected landowners who would be subject to eminent domain.”

INGAA argued that the change was needed to help meet demand growth in the electricity sector, with FERC summarizing that “additional generation capacity is critical to the nation’s energy security needs, particularly given the development of data centers to advance artificial intelligence.”

Opponents acknowledged that demand is growing, but there is a lot of uncertainty in forecasted data center demand, and much of it will be met by renewable generation.

But FERC said the rule around staying construction was procedural, only delaying projects it found to be in the public interest. “Despite comments suggesting the contrary, it is not the mechanism by which the commission determines whether there is a need for additional energy infrastructure,” FERC said. “The commission continues to evaluate proposed projects under the existing standards in [Natural Gas Act] Sections 3 and 7, as appropriate.”

Even if natural gas generation will decrease over the long term, as some reports indicate, the power grid and natural gas system will continue to be interdependent.

“Even though more renewable energy resources, such as wind and solar, are supplying electric generation, the electric power sector has relied on natural gas over the past decades and continues to do so, which leads to increased interdependence,” FERC said. “Accordingly, an increase in electricity demand, without sufficient natural gas supplies and interstate transportation infrastructure to support such demand, could impact grid reliability even if renewable energy source generation increases.”

Opponents also questioned the value of relying on Trump’s executive orders, which independent agencies are not required to follow. But FERC said that those orders were not the primary basis for its decision. It instead relied on its authority under the NGA and considered the added costs and risks a delay of up to 150 days could cause a project it had previously found to be in the public interest.

“The commission did not rely on compliance with executive policy to justify the regulation’s removal; rather it discussed the executive orders as evidence that the pressing resource adequacy and system reliability concerns have been widely recognized,” FERC said.