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January 24, 2026

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SPP’s MOPC Adds Conditional IC Process for Large Loads

SPP stakeholders have overwhelmingly endorsed a conditional interconnection process for large loads that will be paired with two other FERC-approved processes as part of the grid operator’s effort to approve large loads.

The conditional high-impact large load service (CHILLS) tariff revision request (RR720) gives load two paths for conditional connection: CHILLS with sufficient designated resources but contingent on transmission upgrades, and a large-load generation assessment that requires accredited, equivalent support generation for the CHILL.

“Ultimately, we have what I would consider a policy that has a narrower scope than initially proposed before,” Yasser Bahbaz, senior director of operations, told the Markets and Operations Policy Committee during its Jan. 13-14 meeting. “It’s that way because it does address, and is designed to address, concerns with respect to impact to the system, from a market impact and market-energy pricing standpoint, and also from a reliability standpoint.”

The CHILLS proposal was split in September from the policy package that included a high-impact large load (HILL) study and high-impact large-load generation assessment (HILLGA) to give stakeholder groups more time to refine and address concerns expressed with the CHILL policy. FERC approved the HILL and HILLGA policies Jan. 15. (See FERC Approves SPP Large Load Interconnection Process.)

The HILL/HILLGA proposal accelerated studies and access to interconnection information, but market participants without generation cannot establish a delivery point for the HILL study. CHILLS expands on that policy to enable speed to power, not just speed to information, Bahbaz said.

“[HILL] information was basically saying, ‘This is what it takes, this is what it costs, and these are upgrades that are needed for these large loads to interconnect,” he said. “So, we are taking it from just a speed to information to speed to power.”

SPP’s Market Monitoring Unit said that with recent revisions to the proposal, it now supports the CHILLS policy. However, it called for the RTO to document that it will commit reliability status resources or make local reliability commitments only to supply firm load and ensure consideration in determining whether a participant has sufficient capacity to “cover” a CHILL with associated generation.

MMU lead Carrie Bivens noted that load-responsible entities (LREs) can use the same megawatts for both the planning reserve margin and to cover a CHILL.

The CHILLS load-interconnection process | SPP

“It’s the exact same megawatts of capacity that are pointed at two different purposes,” she said. “It does make the region reliant on essentially perfect responses from resources and CHILLS in order to mitigate reliability risks.”

MOPC members endorsed the proposal with 99.3% approval, although there were 43 abstentions. There were only five no votes.

Peak Demand Assessment Delayed

MOPC members voted to direct staff to modify revision request RR703 by altering the proposed peak demand assessment (PDA) to focus only on the forecast effects of load-modifying demand response resources (LMRs). The revised tariff change is to be brought back to working groups before the April MOPC meeting.

The endorsed motion was crafted as a compromise after a previous motion amending a Supply Adequacy Working Group recommendation to include a cap on LMRs based on 2025 actuals or workbook submittals failed. Members cited concerns over the load forecast’s evaluation while expressing support for the RR’s demand-response portion.

“I was hoping that this wouldn’t happen,” Evergy’s Jim Flucke, chair of the Market Working Group, said in offering the compromise motion. “It would allow for another three months to allow us to work through some of the concerns in the PDA. The big difference that we’re proposing is that we focus PDA strictly on the demand response.”

Flucke said the demand response piece would remain as “previously envisioned.” He said the key hurdle is working through demand response’s deployment and how “that’s going to fit into this approach of being able to evaluate your demand response portion and how well it is meeting what your expectation was in your workbook.”

SPP staff said they can work with the three-month delay in adding “increasingly critical” demand response as the RTO addresses rapid load growth, evolving resource mixes and tighter energy conditions. Natasha Henderson, senior director of grid asset utilization, said the grid operator will be reliant on FERC approval if it is to implement a revised PDA forecast in 2028 and with risk mitigation for 2027 “that isn’t full implementation.”

“I think this is doable … while I ask for 60 days [for FERC action], I suspect it’s going to be more like 180 days, given the contentious nature of this policy,” Henderson said.

RR703 is intended to increase the visibility and ability to deploy demand response by creating a participation model and accreditation framework for non-price-sensitive DR. SPP wants to incent LREs to manage peak loads by qualifying non-registered or load-modifying demand response capable of performing when their peak loads exceed their qualified resources. (See REAL Team Endorses DR Policy, CONE Value.)

In other actions, MOPC:

    • Approved base planning reserve margins for the RTO Expansion members of 19 and 40% for the summer and winter seasons, respectively. The PRMs are effective in 2027 to give the RTOE members time to adjust to integration into SPP. They were based on a loss-of-load expectation study and other analysis directed by an RTOE ad hoc study group and other stakeholders. The RTOE is one-tenth the size of SPP, with a little more than 5 GW of accredited capacity.
    • Endorsed a proposed tariff revision (RR534) that limits long-term firm services up to the interconnection limit at the point of interconnection for modeling and controlling energy storage resources hybrid configurations.

Wyoming Transmission Outage

A November grid disturbance resulted in a significant “uncontrolled” loss of generation (4 GW) and load (1 GW) across Wyoming and into western South Dakota, staff told MOPC.

The Nov. 13 event in the Western Interconnection began with the planned removal of a 500-kV transmission line in the PacifiCorp balancing authority area. That led to the immediate loss of another 500-kV line that triggered cascading outages around 12:34 p.m. (MST).

SPP’s Derek Hawkins, director of system operations, said the RTO’s reliability coordinator operators immediately responded to address severely loaded transmission constraints, working across internal and external transmission operators and the neighboring RC to return the system to a “secure operating state.”

“We did that very quickly … to get the system in a spot where we could start the restoration,” he said, noting the restoration was completed in the evening of Nov. 13.

NERC and WECC have launched a coordinated investigation into the event. Hawkins said they are likely to file a detailed report that covers the root causes, contributing factors and lessons learned from the event.

Hawkins also said high winds in December resulted in several new marks for wind generation, eventually topping out at 26.3 GW on Dec. 19. SPP’s previous high came in August 2025 at 24.3 GW.

Dueling CSP Studies

SPP staff told members that its joint operating agreement with MISO requires another joint study in 2026, even as the grid operators are completing their 2024 study.

The two RTOs have conducted preliminary screening analyses of 31 projects, using both original coordinated system plan (CSP) models and those that incorporate approved transmission projects from 2025. Staff will focus next on 14 projects, primarily along the southern seam in Arkansas, Louisiana, Oklahoma and Texas, in evaluating their reliability, economic and transfer benefits.

“We will begin to build a business case for any projects out of those 14 that make it through, that we want to even consider a little more in terms of benefits calculation,” Clint Savoy, SPP’s manager of interregional strategy and engagement, told MOPC. “We will start having conversations about cost allocation … and we expect those conversations to continue through this year.”

The grid operators plan to draft a report on the 2024/25 study’s results by March 9 and then develop a business case and allocate costs. They have yet to agree on a single joint project during the more than 10 years of the FERC Order 1000-compliant CSP process, usually disagreeing over the cost-benefit analysis.

Stakeholders have until Feb. 6 to submit transmission issues for 2026 that could be system needs to either MISO or SPP. The RTOs’ staffs will review the issues 2026 during a March 6 meeting.

RTOE RRs on Consent Agenda

The unanimously approved consent agenda, with two clean energy members abstaining, included an update to the 2027 Integrated Transmission Planning sunset and RTOE transition’s scope; an RTOE trading hub analysis; and the quarterly in-service date delay report.

MOPC also approved 19 tariff revision requests — several related to the RTOE —that, if approved by the board, will:

    • RR694: Align the analysis and changes during the annual flowgate assessment to the flowgate list with real-time operations.
    • RR704: Set standard, baseline assumptions for the annual loss-of-load expectation study and the process for studying sensitivity or assumption changes and their impact on the PRM.
    • RR714: Improve Business Practice 7060’s (Notification to Construct and Project Cost Estimating Processes) language for consistency, readability and procedural clarity.
    • RR718: Develop inverter-based resource requirements based on reliability needs for SPP governing documents.
    • RR723: Update the business practices for transmission service and related tagging practices when RTOE begins operations April 1.
    • RR724: Revise Attachment AQ’s study scope to include Integrated Transmission Planning project-selection criteria for network upgrades and consider zonal reliability upgrades.
    • RR725: Modify existing language requiring SPP to follow up with a phone call when a market participant does not confirm a commitment by making the calls optional, rather than mandatory, to reduce unnecessary manual interventions by operators.
    • RR726: Update applicable governing documents to support the integration of RTOE participants into SPP’s existing modeling and transmission planning processes, clarifying terminology and update references and incorporating modeling considerations specific to the Western Interconnection.
    • RR727: Update the revision request process document to include a new governing document (the CPP manual) required for the new regional planning and generation-interconnection study process.
    • RR729 Update the cost of new entry value based on SPP staff’s annual review for implementation in the 2026 summer season.
    • RR730: Clean up inaccuracies in the list of Western Area Power Administration-Colorado River Storage Project (WAPA-CRSP) resources to be included in its federal service exemption (FSE) resource hub.
    • RR733: Update tariff and protocol language to clarify how disputes between the MMU and a market participant (MP) will be handled and clarify that they can dispute the MMU’s ex-post verification of actual costs.
    • RR734: Clarify that SPP and MPs can use FSE transfer points and the WAPA-CRSP resource hub to obtain candidates and nominate auction revenue rights and long-term congestion rights consistent with the tariff’s FSE provisions.
    • RR735: Align tariff and protocol language with current congestion-management practices by replacing outdated market-flow submission requirements with the parallel flow visualization process.
    • RR736: Improve the regulation selection process’ efficiency by automatically selecting resources when their regulation capacity limits and ramp rates are equal to their energy capacity limits and ramp rates. The selection for regulation of eligible resources that cleared in the day-ahead market will be done as reliability unit commitments instead of the real-time balancing market.
    • RR737: Add administrative language to the SPP market protocols to effectuate and align with the approved RTOE tariff language. Settlement calculations will be relocated to a settlement-calculation reference manual.
    • RR738: Revised Business Practice 10000 (Reliability Coordinator Outage Coordination Methodology) to accommodate RTOE members.
    • RR740: Clarify current reliability coordinator (RC) function practices for identifying and addressing emergency conditions in the SPP RC area by adding a new section in SPP’s operating criteria.
    • RR741: Add an addendum to the tariff formalizing interregional-transmission planning coordination for the Western Interconnection to meet Order 1000 requirements and allow SPP to coordinate RTOE planning activities with adjacent Western planning regions.
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Advocates Trumpet Costs, Benefits of Clean Energy in Northeast

Two new studies released by advocates on opposite sides of the clean energy debate reach opposite conclusions about the economic benefits of renewables.

A coalition of free market think tanks on Jan. 13 trumpeted a new report by Always On Energy Research (AOER) concluding that if state renewable energy mandates in New England were abandoned in favor of new nuclear and natural gas generation, ratepayers would save hundreds of billions of dollars over the next 25 years.

The Coalition for Community Solar Access (CCSA) on Jan. 14 hailed a new report it commissioned from Synapse Energy Economics that found expanding New York’s distributed solar portfolio to 20 GW and increasing the state’s energy storage capacity could lead to $1 billion in annual energy cost savings for ratepayers by 2035.

The AOER report was quickly criticized in a rebuttal by a group of decarbonization advocates who called its data selective, its analyses flawed and its proposed scenarios highly unrealistic.

The CCSA report, on the other hand, is itself a rebuttal or rebuke of New York state’s recent step back from some of its clean energy goals and its governor’s interest in an all-of-the-above energy solution to ensure affordability.

Although the conclusions and suggested solutions vary widely, the underlying issue — expensive electricity — is not debatable.

In its most recent monthly price report, the U.S. Energy Information Administration calculated the average U.S. electricity price across all customer sectors nationwide at 13.63 cents/kWh in October 2025. New York was 57% higher at 21.34 cents and New England was 75% higher at 23.8 cents.

For all of 2024, those seven states ranged from 42 to 88% higher than the national average. Only California and Hawaii were higher.

New England

The AOER report was released by the Maine Policy Institute, Fiscal Alliance Foundation, Josiah Bartlett Center for Public Policy, Rhode Island Center for Freedom & Prosperity, Yankee Institute and Americans for Prosperity Foundation.

It is a continuation of previous AOER state-level analyses, including a 2024 study that modeled the economic and reliability impacts of energy policies in the six New England states; all but New Hampshire have established aggressive decarbonization requirements.

While AOER does not explicitly identify itself as pro-fossil fuel, it repeatedly describes itself with common pro-fossil keywords such as affordable, abundant and reliable, and its work frequently faults green policies.

The 2026 report — “Alternatives to New England’s Energy Affordability Crisis” — looked at four ways to meet a total peak demand of 52.5 GW on the ISO-NE grid in 2050:

    • The renewables scenario would combine 19.2 GW of onshore wind, 43 GW of four-hour storage, 66 GW of offshore wind and 68.4 GW of solar at a cost of $815 billion.
    • The nuclear scenario gradually replaces all carbon dioxide-emitting generation with 20.4 GW of large nuclear plants and 14.7 GW of small modular reactors, plus 13.7 GW of natural gas generation in a bridge and/or peaker role at a total cost of $415 billion.
    • The natural gas scenario entails all types of existing generation assets being used until they reach the end of their useful lives, then being replaced with new combined cycle gas-fired plants plus new gas combustion turbine peakers. This would cost $107 billion.
    • The “happy medium” scenario would add 10.8 GW of new nuclear and 24.3 GW of new gas capacity to existing generation at a cost of $196 billion.

The authors note that each scenario faces significant obstacles: the sheer scale of a wind-solar-storage buildout, anti-offshore wind policies, insufficient gas pipeline capacity and the very concept of building so many nuclear reactors. They also said they did not attempt to factor in the cost of things such as building electrification or quantify the fuel cost savings such steps would offer.

The think tanks that released the AOER report focused on the dollar figures and urged New England policymakers to turn away from renewables.

“New Englanders are being asked to bankroll an energy experiment that is dramatically more expensive and far less reliable than proven alternatives. This study puts hard numbers behind what families and businesses already feel every month. State-mandated wind and solar are driving up costs while increasing the risk of blackouts. Replacing these mandates with nuclear and natural gas would save hundreds of billions of dollars, strengthen grid reliability and deliver real emissions reductions without sacrificing affordability or economic competitiveness,” Fiscal Alliance Foundation Executive Director Paul Diego Craney said in a news release.

Not so fast, the Acadia Center said Jan. 16.

The 501(c)(3) working to reduce carbon emissions in the Northeast laid out a point-by-point rebuttal of the report three days after AOER released it, saying its analysis “grossly inflates the cost of clean energy, selectively ignores fuel savings and proposes highly unrealistic alternative scenarios.”

It also ignores the societal cost of carbon emissions, understates the cost of nuclear, overstates the installed capacity needed and does not consider the prospect of emerging clean-energy technologies, Acadia said.

Acadia similarly attacked AOER’s 2024 report, “The Staggering Costs of New England’s Green Energy Policies.”

New York’s Shift

The Empire State through rhetoric and policy has long been one of the most aggressively green states in the nation.

But energy development comes at a high cost and slow pace in New York, and renewables are lagging far behind the goals the state mandated in its landmark 2019 climate law.

With utility costs high and rising further, with existing generation assets aging and with the Trump administration actively opposing renewables, New York Gov. Kathy Hochul (D) recently has taken a more pragmatic stance, continuing to embrace the state’s green goals but hesitant about the cost of reaching them.

Among other things:

    • The New York Power Authority is taking a measured approach to its new role as renewable energy developer, initially targeting fewer and smaller projects than advocates would like and expecting a high attrition rate for them.
    • The newly updated State Energy Plan predicts a longer reliance on fossil fuels, possibly including what until recently was unthinkable — new-build fossil generation.
    • The state allowed a controversial gas pipeline expansion plan to go forward after previously rejecting it.
    • Hochul has held off on implementing a planned cap-and-invest system.
    • The state appears poised to continue its subsidies for existing nuclear power plants, which cost ratepayers about $500 million/year.
    • Hochul in mid-2025 ordered development of 1 GW of new nuclear capacity, then kicked that up to 5 GW in her 2026 State of the State Address.

All of which has left clean energy and public power advocates increasingly restive, but not resigned.

Distributed solar generation is one of the bright spots in New York’s clean energy landscape — deployment has surpassed goals and by some measures has led the nation.

A large group of mostly Democratic Assembly members and senators are sponsoring the Accelerate Solar for Affordable Power (ASAP) Act (A8758/S6570), which would boost the state’s goal from 10 GW of distributed solar by 2030 to 20 GW by 2035.

The seasonal contribution of solar and storage are shown by hour and month. The boldface outlines indicate the hours most likely to see NYISO reliability events. | Synapse Energy Economics

Installed capacity presently stands at 7.3 GW with 2.8 GW more in the development pipeline, advocates say.

The study Synapse Energy Economics conducted for CCSA concluded that with 20 GW of distributed solar and 3.7 GW of distributed storage in place by 2035, an estimated $1 billion/year in ratepayer energy costs would be avoided. The savings would accrue to all ratepayers, though not equally across regions.

This much capacity would avoid the use of 56 Bcf of gas for energy generation, or about 11% of New York’s total in 2024. That reduction would yield a savings of $947 million in societal cost of greenhouse gas emissions.

The authors say other benefits such as public health improvement and the ability to defer grid upgrades would be notable but were not quantified for the report.

Synapse lists multiple environmental advocacy organizations among its clients. The scope of its work includes a significant focus on green energy and decarbonization but extends to other aspects of the power grid.

“This study shows that smart policy choices can unlock real savings for all customers, not just those who install solar on their rooftops,” CCSA Northeast Director Kate Daniel said in a news release. “The ASAP Act is an opportunity to build on New York’s leadership and scale solutions that are already working.”

ASAP’s sponsors embraced that conclusion.

“In these uncertain times and with headwinds from the federal government, it’s more important than ever for New York state to lean into and expand on our successes,” said Assemblymember Didi Barrett (D), sponsor of the ASAP Act in the Assembly and chair of its Energy Committee.

“Solar energy is the cheapest form of energy to produce and a linchpin for affordability,” said State Sen. Pete Harckham (D), sponsor of ASAP in the Senate and chair of its Committee on Environmental Conservation. “This new study re-emphasizes the long-term, abiding value of renewable energy and storage systems in this regard. At this point, we should be exponentially increasing our clean energy efforts and gigawatt goals with distributed solar projects to create thousands of green jobs and save ratepayers millions of dollars.”

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PJM MRC/MC Preview: Jan. 22, 2026

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Jan. 22. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

    1. Endorse proposed revisions to the Regional Transmission and Energy Scheduling Practices document to codify the NAESB version 4.0 Business Scheduling Practice Standards.
    2. Endorse proposed revisions to Manual 2: Transmission Service Request drafted through its periodic review.
    3. Endorse proposed revisions to Manual 21B: PJM Rules and Procedures for Determination of Generation Capability to expand the definition of dual-fuel gas generation to include configurations where the secondary fuel is stored off-site but directly connected to the resource with a dedicated pipeline. (See “Stakeholders Endorse Expanded Dual Fuel Manual Definition,” PJM PC/TEAC Briefs: Jan. 6, 2026.)

Issue Tracking: Capacity Market Enhancements — ELCC Accreditation Methodology

    1. Endorse proposed revisions to Manual 28: Operating Agreement Accounting drafted through the document’s periodic review. The changes seek to clarify the opportunity cost calculation for hydro units, how day-ahead load response bids are included in the day-ahead operating reserve charges and the calculation of capped real-time synchronized reserve assignments for demand response.
    2. Endorse proposed revisions to Manual 38: Operations Planning proposed as part of its periodic review. The language details the long-term study process included in the Regional Transmission Expansion Plan and adds MISO solar generation to planning studies.

Endorsements (9:10-9:35)

    1. 2026/2027 3rd Incremental Auction (IA) Installed Reserve Margin (IRM) and Forecast Pool Requirement (FPR) (9:10-9:35)

PJM’s Josh Bruno will present the recommended IRM and FPR values for the 2026/27 Third IA, which is scheduled to be conducted on Feb. 24. The parameters were calculated with the 2026 load forecast, which scaled back PJM’s estimates of the load growth anticipated for the delivery year. This resulted in staff recommending an IRM of 18.6%, 0.5% lower than the margin used in the Base Residual Auction, and a 0.9291 FPR, 0.0121 higher than the BRA.

Stakeholders will be asked to endorse the parameters upon first read and same-day endorsement will be sought at the Members Committee meeting.

Members Committee

Endorsements (11:00-11:30)

    1. Minimum Capitalization (11:00-11:15)

PJM’s Ryan Jones will present a proposal to increase the minimum capitalization requirements to participate in its markets. It would double the tangible net worth requirement for market participants and add a 3% annual escalator. (See PJM Presents 1st Read on Minimum Capitalization Requirement Proposal.)

Issue Tracking: Review of Minimum Capitalizations for Participation in PJM Markets

    1. 2026/2027 3rd Incremental Auction (IA) Installed Reserve Margin (IRM) and Forecast Pool Requirement (FPR) (11:15-11:30)

If endorsed by the MRC, Bruno will present the recommended IRM and FPR values for the 2026/27 Third IA.

The committee will be asked to endorse the values on first read.

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NV Energy Says it Might Fall Short of State RPS

Facing surging electricity demand from data centers and artificial intelligence, NV Energy might soon be struggling to meet Nevada’s renewable portfolio standard.

That’s according to Janet Wells, NV Energy’s vice president of resource planning, who led a Jan. 14 stakeholder meeting on the company’s 2026 integrated resource plan.

Wells said the company expects to face challenges in meeting the RPS “for several years.”

“Federal policy has reduced the deliverability of new renewable resources while also increasing energy needs to support the [federal] AI action plan,” Wells said. “That combination will create challenges in meeting the RPS compliance.”

Among those challenges are soon-expiring federal tax credits for solar and wind projects, federal policy shifts on solar and wind, and potential tariff impact on imports, Wells said previously.

If the company misses the RPS target, it will ask regulators for a compliance waiver, Wells said.

NV Energy thus far has been meeting the state’s RPS, which requires a certain percentage of electricity sales to come from renewable resources. The RPS increased from 29% in 2022-23 to 34% in 2024-2026, 42% in 2027-2029, and 50% in 2030 and beyond. In 2024, the company exceeded the standard with 46.8% renewables.

Load Forecasts Unveiled

The stakeholder meeting was a follow-up to one held in December regarding NV Energy’s 2026 integrated resource plan, which it expects to file in late April. (See NV Energy’s Early IRP Filing Reflects Load, Resource Challenges in 2026.)

At the January meeting, Wells provided more detail on the load forecast on which the new IRP will be based.

A load forecast for the company’s 2024 IRP predicted system growth of 31,000 GWh over 20 years, or a compound annual growth rate of 3.2%.

In the new forecast, electricity sales from 2026-2046 are expected to reach 43,400 GWh, a 40% increase from the previous forecast, with a compound annual growth rate of 5.3%. Much of the growth will be concentrated in the northern part of the state.

“The main reason for the difference is a continued increase in the large customer requests, specifically data centers and AI-driven load,” Wells said.

As for the RPS, existing and approved renewable resources will be enough to meet the standard in 2027, NV Energy’s projections show. But more renewables will be needed starting in 2028 for RPS compliance.

To help meet its surging demand, NV Energy issued a request for proposals in 2024. The RFP drew 198 bids — a company record.

From there, the company developed a shortlist of 15 projects totaling 8 GW of capacity. About 3,800 MW is new generation and about 4,200 MW is storage, Wells said. NV Energy has requested regulatory approval for one project: a 150-MW power purchase agreement for the Dodge Flat battery storage system in northern Nevada.

Approval for other projects will be sought through the 2026 IRP. Wells said the expected ratio of renewables and storage to thermal resources is roughly 3:1. She noted that the earliest new gas combustion turbines could be in operation would be 2029 or 2030.

Allocating Costs

NV Energy’s base load forecast for its 2026 IRP includes “mitigation” for large loads — meaning requested loads are reduced by half if a line-extension contract has been signed or by 85% if there’s no contract, Wells said during the December meeting.

In addition, the company developed a “base minus” forecast that excludes growth from data centers and AI. Wells said resource costs to meet the two forecasts would be compared, and the extra costs seen in the base forecast could then be allocated to large load customers.

A third forecast called “base plus” assumes that all load will materialize from large customer projects with signed contracts.

In another consequence of surging demand, NV Energy is delaying plans to close its open position, which refers to resource needs that are met through short-term market purchases rather than by the utility’s own resources or long-term contracts.

Wells said the goal now is to gradually reduce the company’s open position from around 2,000 MW in 2027 to 500 MW by 2031.

NV Energy is required to file an IRP at least every three years. Legislation passed in 2023 authorized the company to file an IRP more often “if necessary.” The 2026 IRP is coming only two years after the company’s 2024 plan.

NV Energy plans to host a third stakeholder session on the 2026 IRP in February, with a focus on the company’s distributed resource plan, the transportation electrification plan and the demand-side management plan.

A consumer session also is planned.

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NYISO Operating Committee Passes Final Capacity Requirements

The NYISO Operating Committee has approved the ISO’s locational capacity requirements (LCRs) despite multiple stakeholders abstaining from the vote in protest of the process.

“On behalf of Multiple Intervenors and the city [of New York], we just want to express that we are deeply concerned with the process NYISO went through,” said Kevin Lang, a lawyer from Couch White who represents large industrial customers and NYC. “NYISO can’t surprise, and should not be surprising, market participants with last-minute changes in its methodology.”

In addition to the Multiple Intervenors group and NYC, PSEG Long Island and Energy Spectrum abstained from the Jan. 15 vote. All other members voted in favor of the LCRs.

Lang was referring to a presentation given to the New York State Reliability Council’s Executive Committee (NYSRC EC), in which changes to the 2026/27 installed reserve margin (IRM) study were discussed and voted on. According to the published LCR Study, the IRM report implemented changes to include modeling of the Champlain Hudson Power Express and winter fuel constraints. These changes included modeling of voluntary curtailments and distributed area resources. Transmission security floor values, which are used in the calculation of the LCRs, also were updated.

“The NYSRC EC is concerned with the timing and lack of notice in the NYISO TSL [transmission security limit] methodology and the apparent reversal of previous TSL positions without stakeholder or NYSRC input,” NYSRC EC chair Mark Domino was recorded saying in the meeting minutes. Domino said the NYSRC would reactivate the Reliability Resource Evaluation Working Group to consider a new reliability rule to address this issue.

The final LCRs were first presented Jan. 6 at an Installed Capacity Working Group (ICAP) meeting. (See NYISO Presents Final LCRs for 2026/27.) At that meeting, little discussion of the final LCRs occurred.

The LCRs, expressed as a percentage of peak load forecast, represent the minimum capacity that generators and load-serving entities must maintain within the downstate zones. These zones have substantial transmission constraints.

“We are going to work with the Reliability Council to address the minimum timing issue,” said Yvonne Huang, senior manager of ICAP market operations. “We will try to improve the process going forward.”

Huang asked NYISO to “never do that again” and requested clarification as to why the ISO waited until the last minute to introduce methodology changes to stakeholders. She said the ISO made the changes because of the reliability need that was discovered in 2025. (See NYISO Again Identifies Reliability Need for NYC.)

“I agree we should work better to improve and bring the changes early,” said Huang, who added that the changes were first brought up in a Nov. 20 Electric System Planning Working Group meeting. “We were working as fast as we could.”

Jason Ragona, representing Con Edison, issued a statement saying that while the company would vote to support the LCR motion, it wanted on the record that it shared Lang’s concerns about rapid changes to TSL and LCR calculations. Ragona encouraged the NYSRC to adopt procedural changes to “minimize” future occurrences.

The representative from PSEG Long Island issued a similar statement to Ragona’s, calling for more time to perform complete reviews and comments about any changes.

Other Business

The OC also heard the Operations Report for the New York Control Area for December 2025. The peak load for the month was 23,448 MW about 5 p.m. Dec. 15. That set the winter load record for the year. Wind generation peaked at 2,338 MW on Dec. 18 at 10 p.m. Solar peaked at 2,767 MW on Dec. 22 at 11 a.m. No major emergencies occurred, but seven alert states were issued during the month.

The committee also heard and approved revisions to the System Restoration Manual and approved a system impact study scope for a data center development on the former site of the Remington Arms Factory in Ilion. The Associated Press reported on the factory’s closure in 2024.

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MISO to End Market Platform Project in 2026, Leave Major Real-time Market Work Unfinished

After nine years, MISO will close out its multiphase market platform replacement project, leaving a bulk of unfinished work on its real-time market.

MISO said it’s “adjusting the remaining scope to conclude the program in 2026,” and will cut its work to build a new unit dispatch system from the multiyear effort. That undertaking will become a standalone project.

MISO’s unit dispatch system balances generation and load in five-minute intervals to clear the real-time market, selecting generators’ offered megawatts and prices while managing transmission congestion and meeting reserve requirements. The system sends five-minute dispatch and price signals to generators based on bids and system need.

MISO’s removal of a new unit dispatch system from the market platform project means that the RTO will spend an estimated $154 million on the market platform swap-out, not including the unit dispatch system. MISO began the platform project with a $130 million budget plus a 25% contingency, bringing the total spending limit to $162.5 million.

MISO said even though it’s cutting out the capstone task of the platform replacement project, the work thus far on the project would deliver about $425 million in benefits.

“Obviously, we’ve spent more than we anticipated,” MISO’s Scott Daugherty said during a Jan. 15 meeting of the Market Subcommittee. Daugherty added the expense is part of MISO being on the “cutting edge” of incorporating the newest technologies.

The RTO said it was experiencing difficulties completing work on the real-time market clearing engine in late 2025. At the time, it predicted that building a new unit dispatch system would cost about $20 million and take until 2028. (See MISO: Market Platform Replacement will be Overbudget, Stretch into 2028.)

MISO planned to build the unit dispatch system over 2026, test and deliver it sometime in 2027 and formally launch it in 2028. It’s unclear what a new budget and timeline might be. In the meantime, MISO will make do with its existing system.

MISO principal adviser Kevin Larson said re-platforming MISO’s market has been a complex endeavor.

“We originally hoped to be done with this in the late 2024/2025 timeline,” Larson said. (See MISO Sets Sights on 2025 Completion for New Market Platform.)

Daugherty said isolating the unit dispatch system overhaul as its own project will allow MISO to work more automation into the finished product.

“Eventually we’ll get the UDS to the current re-platformed engines,” he said.

“The core objective we were going after is performance and security,” Larson added.

In response to stakeholders’ questions, Larson said the new market platform won’t be embedded with AI-based technology. Larson said AI would show up in the market’s “secondary capabilities,” like MISO’s uncertainty management tool, which helps guide dispatch.

Some stakeholders said they were disappointed with MISO’s decision to strike the dispatch system rebuild.

“I’m trying to be calm; I am frustrated with this, but I understand this is difficult to do,” Fresh Energy’s Mike Schowalter said.

Schowalter said MISO has told stakeholders repeatedly the market platform replacement would allow MISO to make more complex market changes. He asked to what extent “carving out” the unit dispatch system would impede what’s possible.

Schowalter said the new market platform always has seemed like “black box that’s going to do all these magic things” that stakeholders might not understand. He asked for a more detailed explanation of what new capabilities the market platform would enable.

“What are those things that are going to have to wait another two years?” Schowalter asked. He added there’s “a lack of understanding on what’s waiting for what.”

Daugherty said the purpose of the market platform replacement is to “not do much that’s new but re-platform the existing capabilities” and position the markets to be more adaptable to new technologies and increasingly complex market products.

Kevin Larson (left) and Scott Daugherty, MISO | MISO

“We’ve had this big chunk of market enhancements we haven’t been able to go after,” Daugherty said.

Clean Grid Alliance’s David Sapper asked where MISO’s work to bring aggregated distributed energy resources into the market under FERC Order 2222 stood.

MISO staff took down the question to address later.

Michigan Public Power Agency’s Tom Weeks said the market platform replacement was sold by MISO as: “OK, all the things we can’t do in terms of improving the markets, we can do” once the new platform is in place. Weeks made the comment while asking MISO to create a commitment process especially for jointly owned generation resources.

MISO said the remaining sections of in-progress market platform work are positioned to be completed at the end of 2026. That includes the launch of its reliability assessment and commitment market tool, its look-ahead commitment tool and its one-stop repository for planning and operations data to create its models.

MISO unveiled its new day-ahead market clearing engine as part of the project in 2024.

Larson said MISO began the platform project in 2017 when it began having “on and off problems” with its day-ahead market clearing engine. At that time, it had a wish list of improvements the aging market platform wouldn’t be able to handle.

MISO needs pieces of the market platform replacement, specifically the new look-ahead commitment tool, to be able to comply with FERC’s Order 881, which requires real-time ambient-adjusted line ratings.

The look-ahead commitment tool works with the unit dispatch system to arrange near-term generator commitments.

Order 881 by 2028

MISO said it doesn’t expect full compliance with Order 881 until the end of 2028, due in part to the delay of the new look-ahead commitment clearing engine. (See MISO to Seek 3-Year Order 881 Delay for Vendor Holdups.)

At a Jan. 13 Reliability Subcommittee meeting, MISO also said its vendor might not be able to deliver the necessary software as scheduled in the second half of 2026 to ready its real-time system to incorporate the varied ratings. MISO added that its transmission owners are expected to prepare for the new rule into 2027.

“MISO’s systems being ready doesn’t mean that TO systems are ready,” MISO’s Paul Kasper said. He reminded stakeholders that TOs must conduct their own system testing and integration campaigns.

Kasper said MISO is taking “exceptional” steps to maintain its timeline on the project. “There’s only so much we can control with the vendor.”

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FERC Approves SPP Large Load Interconnection Process

FERC has approved SPP tariff additions that deploy novel study processes to quickly review requests for “high-impact” large loads seeking to interconnect to its system.

The new attachments to the tariff incorporate transmission, generation and load interconnection services into a single framework, effective Jan. 15. They establish a 90-day study-and-approval process for interconnecting large loads that will be paired with new generation or with current or planned generation (ER26-247).

In its Jan. 15 order, FERC said SPP showed that “unprecedented” growth in large loads in its footprint presented “significant and unique operational and planning challenges.” It found the grid operator’s addition of a high-impact large load (HILL) study and high-impact large load generation assessment (HILLGA) processes address those challenges “while maintaining the reliable operation of SPP’s transmission system.”

SPP CEO Lanny Nickell said in a statement that the grid operator is proud that it is “first in the nation” to blend transmission, generation and load interconnection services into a single framework.

“It’s essential to our nation’s competitive future that we can quickly, reliably and affordably meet vastly increasing energy demands,” he said. “We are now in a great position to enable this future.”

SPP defines HILLs as new commercial or industrial load, or an increase in the load, at a single site connected through one or more shared interconnection or delivery points, and where load is either 1) 10 MW or more if connected to the transmission system at a voltage level less than or equal to 69 kV; or 2) 50 MW or more if connected at a voltage level greater than 69 kV.

Customers registering their load as HILLs and with plans to acquire generation will get a 90-day study and provisional approval, with upgrades directly assigned until the customer acquires firm service for the new generation. They will not be required to have current generation or a generator interconnection agreement.

Under the HILLGA process, HILL customers bringing supporting generation will also receive a 90-day study and a limited interconnection agreement. Upgrades will be directly assigned to the generation customer.

Commissioner David Rosner filed a concurring opinion calling on other U.S. transmission providers to consider similar proposals to SPP’s “pragmatic steps” supporting economic growth in its footprint.

To submit a commentary on this topic, email forum@rtoinsider.com.

“Today’s order is a productive step toward facilitating the energy needed to win the AI race, bring back American manufacturing, and deliver the reliable and affordable energy on which families and small businesses depend,” he wrote.

FERC noted SPP’s filing contained several “ministerial errors” and directed the RTO to make a compliance filing within 30 days.

SPP developed the processes following a May directive from board Chair John Cupparo that staff deliver a timely, scalable and reliable approach to manage the exponential growth of load demand across the footprint. Staff’s first attempt was rejected by members in July before a revised version won endorsement from stakeholders and then the board in September. (See “Large Load Integration OK’d,” SPP Board Approves 765-kV Project’s Increased Cost.)

A third service, conditional high-impact large load service (CHILLS), was split out from the HILL/HILLGA policy package to give stakeholder groups sufficient time to refine and address concerns. Stakeholders have since approved the final framework and its two paths for load’s conditional connection.

SPP’s board will consider the CHILLS framework during its Feb. 3 meeting in Little Rock, Ark.

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MISO Preliminary Auction Data Shows Added Load in 2026/27

MISO is registering and accrediting resources to meet a roughly 2-GW uptick in load for the 2026/27 planning year.

The grid operator so far has recorded a preliminary 135.6 GW in total accredited capacity for the peak summer season, and it still has some resource registrations in progress.

The RTO reports it has nearly 175.6 GW of total installed capacity. For the 2025/26 planning year, the RTO had 139.4 GW in accredited capacity available to it in summer.

MISO has established an initial 137.5-GW initial planning reserve margin requirement to cover a 124.7-GW coincident peak forecast for summer. The RTO’s downward-sloping demand curve used in the auction likely will clear more capacity than the margin requirement. It entered the 2025/26 auction with a 135.2-GW margin requirement and ended with a nearly 137.6-GW requirement. Its 2025/26 coincident peak load forecast was 122.6 GW.

Speaking at a Jan. 14 Resource Adequacy Subcommittee meeting, MISO Manager of Resource Adequacy Andy Taylor said load forecasts have risen across the board for the upcoming planning year, according to load-serving entities. He said the increases aren’t large enough to cause panic.

The grid operator’s numbers, prepared for the upcoming spring capacity auction, are preliminary. MISO plans to post five more data updates through March 19.

MISO will open its capacity auction offer window March 26-31 and post auction results April 28.

MISO’s 2026/27 planning year will begin June 1.

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PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth

The PJM Board of Managers has selected a path forward for addressing a groundswell of large load interconnections expected over the coming decade. It announced a framework to speed the development of capacity resources, overhaul load forecasting and conduct a holistic review of how each of the RTO’s markets can better support resource adequacy needs. (See PJM Stakeholders Reject All CIFP Proposals on Large Loads.)

“This decision is about how PJM integrates large new loads in a way that preserves reliability for customers while creating a predictable, transparent path for growth,” said board Chair and interim CEO David Mills. “This is not a ‘yes/no’ to data centers; this is ‘how can we do this while keeping the lights on and recognizing the impact on consumers at the same time?’ We look forward to implementing, along with our stakeholders, these proposals to manage the phenomenal demand growth we are experiencing.”

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The proposal is the culmination of the Critical Issue Fast Path (CIFP) process initiated in August 2025 to address large load growth, which resulted in a dozen packages drafted by PJM staff and stakeholders being rejected by the membership in November.

The proposal directs staff to accelerate the reliability backstop to procure additional capacity and define how the related costs will be allocated to load-serving entities (LSEs). This includes exploring mechanisms to assign costs to utilities that are capacity deficient.

The board wrote that the current trigger for the backstop, which requires three consecutive capacity auctions falling short of the reliability requirement, is insufficient in light of the 6.6-GW shortfall in the 27/28 base residual auction (BRA). It also noted that FERC’s December 2025 order on co-located loads requested information about proposals to use the reliability backstop to address “acute resource adequacy shortfalls.”

The board wrote that the backstop is considered a “transitional measure” to maintain reliability while the holistic market review is ongoing. (See FERC Directs PJM to Issue Rules for Co-locating Generation and Load.)

The board pointed to a joint CIFP proposal from Amazon, Calpine, Constellation Energy, Google, Microsoft and Talen Energy that included an alternative reliability backstop triggered if a capacity auction clears below 98% of the reliability requirement. It would open an auction for multiyear capacity commitments for new resources or those outside the capacity market. While the board did not mirror the coalition proposal, it wrote that proposals should “specify price, term and quantity as core award parameters.” (See “Joint Stakeholder Proposal,” PJM Stakeholders to Vote on Large Load CIFP Proposals.)

PJM’s CIFP proposal requested a second phase of the process to evaluate changes to the reliability backstop and incentives for large loads to bring their own generation or participate in demand-side capacity resources. (See “PJM Proposal,” PJM Stakeholders to Vote on Large Load CIFP Proposals.)

A backstop auction was requested by governors of PJM states and the White House in a statement of principles released Jan. 16. It calls for the auction to be conducted by September 2026 to allow “15-year price certainty” for new capacity resources. The costs resulting from the auction should be allocated to LSEs that have not procured their own capacity or agreed to be curtailable. (See White House and PJM Governors Call for Backstop Capacity Auction.)

Another parallel between the statement of principles and the board’s proposal lies in the price collar limiting capacity prices to between $175 and $325/MW-day for the 2026/27 and 2027/28 capacity auctions. The statement requested that the collar be extended for two years, while the board requested feedback from stakeholders on such an extension.

During a press conference following the announcement of the 2027/28 BRA results, PJM said the auction would have cleared at $529/MW-day without the collar and the Dominion zone would have separated at $542/MW-day. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor and PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

The board’s proposal adopts staff’s recommendation to create a bring-your-own-new-generation pathway allowing new capacity paired with large loads to qualify for a fast-tracked interconnection process, expected to be rolled out by August 2026.

Large loads exceeding available incremental new resources within an LSE would be subject to curtailment under the proposal, under a model similar to the CIFP proposal sponsored by several state legislators, consumer advocates and the NRDC. The large loads would be curtailed prior to pre-emergency load management, which the board wrote is intended to avoid disrupting other demand response participants.

“Should system conditions over a given period force PJM to invoke its emergency procedures, the board finds it reasonable for certain large loads, including data centers, to move to their backup generators, or curtail their demand, for a limited number of hours during the year to prevent a larger-scale outage for residential and other consumers. Such curtailment would be expected to occur infrequently, for limited durations and only when necessary to prevent broader system impacts, consistent with PJM’s longstanding operational practice of avoiding curtailment whenever possible,” the board wrote.

The board directed a slate of changes to PJM’s load forecasting process, including a pathway for state utility commissions to review large load adjustments (LLAs) submitted by utilities, requirements for utilities to inquire with customers seeking service for large loads about whether they are exploring multiple sites for a single project, and a third-party review of the forecast to identify national trends that may impact PJM’s assumptions.

The holistic review of PJM’s markets is intended to improve how the energy, reserve and capacity markets create the incentives needed to meet resource adequacy. Staff will conduct an analysis in the first half of the year, followed by a stakeholder process to create a set of recommendations for the board to consider.

“PJM is establishing clear, transparent guardrails for integrating large new loads under defined conditions,” PJM Chief Operating Officer Stu Bresler said in the Jan. 16 announcement of the board’s proposal. “This proposed course of action will require intense work by all of us in 2026 and involve significant changes. But it’s clear that bold action will be required to support the positive growth that is happening throughout the PJM region and the nation.”

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White House and PJM Governors Call for Backstop Capacity Auction

The White House and governors in PJM states have released a plan to get more generation built in the RTO, which saw its recent capacity auction clear short of the target as data center demand proved too much to meet. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

“Under President Trump’s leadership, the administration is leading an unprecedented bipartisan effort urging PJM to fix the energy subtraction failures of the past, prevent price increases, and reduce the risk of blackouts,” White House spokesperson Taylor Rogers said Jan. 16.

The most immediate idea is to run a special auction that would procure generation for data centers, which they would pay for. Trump and the White House’s National Energy Dominance Council (NEDC) said they’ve reached agreement with several states to advance more than $15 billion of new generation projects and a “coalition of leading technology companies has committed to funding” the new capacity.

“This initiative will ensure we usher in the age of artificial intelligence with new power plants funded by the technology companies, not taxpayers, securing the steel of Pennsylvania, the manufacturing of Ohio and the ships of Virginia,” NEDC Chair and Interior Secretary Doug Burgum said in a statement.

The plan is to run a reliability backstop auction to procure the new capacity and give it 15-year contracts paid for by data centers. PJM’s tariff allows for a backstop capacity auction, but only after its main capacity auctions fall short for three years, so implementing it would require a rule change.

To submit a commentary on this topic, email forum@rtoinsider.com.

“PJM is reviewing the principles set forth by the White House and governors,” PJM said in a statement. “The PJM board’s decision, resulting from a multimonth stakeholder process on integrating large load additions, will be released later today. The board has been deliberating on this issue since the end of that stakeholder process. We will work with our stakeholders to assess how the White House directive aligns with the board’s decision.”

PJM planned to release its proposed reforms on the afternoon of Jan. 16, just hours after the governors met with the NEDC at the White House to sign their deal.

The NEDC and governors also called on the RTO to improve load forecasting and queue management and to return to “market fundamentals” with long-term capacity market reforms that should go into effect in time for the Base Residual Auction scheduled for May 2027. They suggest extending the price cap that has been in place for another two capacity auctions.

The governors agreed to use their powers to ensure that state regulators assign the costs from the backstop auction to data centers that have not otherwise procured supply or have agreed to flexible operations.

Pennsylvania Gov. Josh Shapiro (D) said in a statement that he’s been working to get power prices under control for two years and welcomed the deal with the White House and fellow governors.

“I sued PJM when they refused to act and secured a price cap that saved consumers tens of billions of dollars on their energy bills,” Shapiro said. “Since then, I’ve been working with my fellow governors and federal energy officials to push PJM to make needed reforms, and I’m glad the White House is following Pennsylvania’s lead and adopting the solutions we’ve been pushing for — including the extension of the price cap that I insisted be included today.”

Former FERC Chair Mark Christie welcomed the commitment for data centers to pay for the capacity they need to connect to the grid.

“In the Susquehanna case and the PJM co-location 206 proceeding initiated when I was chairman, that is exactly the principle I advocated, so I am glad the president and the governors are endorsing it,” Christie said. “Now I am interested to see the details of how PJM can or will implement this type of emergency auction for a 15-year PPA.”

The NEDC and governor’s proposals endorse the idea of “bring your own generation” with a special procurement auction, and that all makes sense, said PJM Independent Market Monitor Joe Bowring.

“One question is, how will those costs from the procurement be assigned to data centers and … is that literally a 15-year contract with the data centers that they have to pay regardless, or is there any risk that some of that cost will be shifted to load?” Bowring said. “So, I mean, this is an example of a question that you know is yet to be answered. But at a high level, it’s a positive, but there are a lot of details to be worked out.”

Based on the governors’ commitment on cost allocation, PJM likely will assign the costs of the special auction to load-serving entities and let the state regulators figure which data centers ultimately pay, he added. The question is who would cover the stranded costs if those data centers were to go away before the 15-year contracts expire, Bowring said.

Speaking at the American Enterprise Institute a couple of days before the PJM deal was announced, NEDC Senior Director of Power Peter Lake (the former Texas Public Utilities Commission chair) highlighted the issue around mismatched time scales in the two industries.

“Consuming electricity is not new to America, but it’s the timing that is unique, both in a challenging way, but also it presents an opportunity,” Lake said. “The speed which with which these large consumers of electricity come to market is certainly a new paradigm.”

Building major industrial facilities in the past often had similar time frames to building power plants: four to six years, and they both last for decades. Data centers take 18 to 24 months to be developed, and then the chips used in them become obsolete much more quickly than a factory’s assembly line.

“The technology inside the data center might be obsolete before the power plant is even built,” Lake said. “If you think of the value of the data center and the GPUs, that’s how fast the innovation is going, which is a good thing. We want the innovation. … We want to accelerate that. That’s the beautiful part of AI and all the wonderful things it can bring to enhance our lives, but that is such a staggering shift.”

That dynamic makes predicting data center load difficult, Bowring said.

“To me, the best way to manage the forecast is make the data center responsible for paying for whatever capacity they need,” he added. “So that gives them incentive to be as serious as possible building the data center. And if they incur the cost and then go walk away, then those costs stay with them.”

While Bowring sees the increased attention to the reliability crisis in PJM as generally good, nothing in the deal announced will negate the impact the growth in data centers already has had on consumers in PJM.

“We would not have this crisis but for data center load,” Bowring said. “So regardless of retirements, regardless of the economics of power plants — regardless of even PJM’s interconnection queue process difficulties, shall we say, holding all that constant — we would not have these problems, not be short, but for data center load. Data center load is forcing PJM to be short, and it’s imposed $23 billion worth of costs on customers.”

The gap between supply and demand is about 13,000 MW, but any backstop auction could be rounded up to a more even 15,000 MW, Bowring said.

The White House and politicians are not this involved in wholesale power markets, but Grid Strategies President Rob Gramlich noted in an interview that under President Bill Clinton, there was a coordinated effort to deal with the fallout from the California energy crisis by getting new contracts in place to keep power flowing.

The situation needs fixing, but the documents released about the plan are sparse on details, and those will be important, Gramlich said.

“There’s a bigger picture than this tries to address, that FERC didn’t address and didn’t have before the commission, which is new load came into the region and started buying up power from existing generation capacity,” Gramlich said. “And I think the states and consumers in the region thought that those power plants in the PJM region were there to serve them. They thought they could count on them, but unfortunately for them, those power plants had not committed their power under any contract.”

Gramlich has argued for years that power plants in the region needed long-term contracts, a position he came to after dealing with the California energy crisis, in which state rules requiring utilities to buy entirely from the spot market made things much worse.

State regulators and others in PJM did not heed his warnings largely because there were no counterparties big enough to take on the major, long-term contracts that hyperscalers have announced recently. Still other wholesale power markets with restructured states like Texas have had more long-term contracting than PJM, he added.

“The fact that the large buyers are willing to say they’ll pay their fair share and [are] willing to work with the bipartisan group of governors, and with the federal government to reach a conceptual proposal here, I think is very noteworthy,” Gramlich said. “And PJM does have the ability to do backstop auctions that are separate from its capacity market. So, I think there’s potentially a workable concept there.”

A big question is how the cost allocation and retail side of these reforms is handled. Gramlich indicated it ultimately might require an expansion of federal authority.

Everyone agrees PJM is struggling to add new generation and that some sort of intervention is required, but Aurora Energy Research’s USA East head Julia Hoos sounded a note of caution.

“This type of ‘out of market’ action can quickly add new generation, but may be financially disastrous for existing generation, which ultimately hurts reliability in the entire region,” Hoos said.

The separate auction is likely to reduce price signals for existing units and could affect the financial health of coal plants in PJM, which the Trump administration likes to keep open.

“Investor confidence to build new power generation in PJM has been low for years,” Hoos said. “Prices were low for almost a decade, and generators were shutting down, and no one was intervening to keep them online. Now that prices are high, PJM and lawmakers are intervening to keep them low. Understandably, developers willing to build new generation in PJM saw that as a substantial risk. Now, this action means that any existing generation is likely to see significantly lower prices, confirming those fears.”

In a thread on X, LS Power CEO Paul Segal made similar points to Hoos and cautioned that the special auction needs to be treated as a bridge.

“Bottom line: Shifting toward ‘pay your own way’ is directionally right,” Segal wrote. “Just don’t confuse a one-off auction (or a permanent cap) with the solution. The durable fix is stable rules + earlier signals + faster pathways to connect + true cost-causation — so competition can do its job.”