ISO-NE declared a capacity deficiency on the evening of Nov. 23 after an unexpected loss of generation left the region short of its operating reserve requirements.
“The timing of the generation loss, coupled with consumer demand being slightly higher than expected, meant other resources could not immediately fill the gap,” the RTO noted in a recap of the event, adding that its “highly trained system operators followed established procedures to maintain system reliability during the shortage period.”
The deficiency conditions lasted from 5:41 p.m. to 7 p.m. The hourly real-time LMP shot up from $111/MWh prior to the event to $865/MWh between 6 p.m. and 7 p.m. The five-minute real-time LMP peaked at $2,665/MWh.
ISO-NE noted that “preliminary information indicates the system event will trigger the region’s Forward Capacity Market Pay-for-Performance rules,” which determine resources’ charges and penalties associated with their performance during deficiency events.
This was the second capacity deficiency event of the year; the first occurred during a period of extreme heat on June 24. (See Extreme Heat Triggers Capacity Deficiency in New England.) While the June event coincided with a peak load of more than 26,000 MW, the highest experienced in the region since 2013, the Nov. 23 event coincided with a moderate peak of about 15,980 MW, which occurred around 5:45 p.m. This peak was about 270 MW higher than the peak forecast by ISO-NE.
While ISO-NE does not identify specific resource outages, data from the RTO show declining gas generation before and after the evening peak load. Gas generation dropped by roughly 1,400 MW between 5 p.m. and 6:30 p.m. Meanwhile, nearly 700 MW of oil generation kicked in during the event.
The two capacity scarcity events experienced so far in 2025 highlight what some market participants view as growing Pay-for-Performance risk in the ISO-NE capacity market. ISO-NE has experienced eight deficiency events since the start of 2016, with five occurring over the past three years.
An increasing number of capacity scarcity events, coupled with higher PFP rates implemented by ISO-NE in recent years, could lead to higher capacity prices in future auctions if participants price increased PFP risks into their capacity offers.
The Texas Public Utility Commission has signed a sixth loan agreement through the Texas Energy Fund’s in-ERCOT loan program, up to $370 million for a new 455-MW gas-fired plant in the Houston area.
The unit would more than double the capacity of NRG Energy’s existing Greens Bayou Generating Station. NRG has a large 78-MW steam turbine unit, three 54-MW gas or fuel turbine units and three 64-MW gas turbines, totaling 354 MW of capacity.
Greens Bayou Unit 6 is expected to come online in 2028. The TEF’s In-ERCOT Generation Loan Program has now produced loans for more than 3,500 MW of dispatchable gas generation. That is more than a third of the way to the $10 billion fund’s 10,000-MW objective.
NRG’s president of business and wholesale operations, Robert Gaudette, said reliable power is “essential” to keep fueling Texas’ “unprecedented” growth.
“Our investment at Greens Bayou reflects NRG’s commitment to delivering dependable, dispatchable generation when Texans need it most,” he said in a statement Nov. 20.
Total project costs under the loan agreement are estimated at less than $617 million. The PUC is providing a 20-year loan for up to $370 million, or 60% of total cost, at 3% interest. The loan’s term runs through November 2045, and Greens Bayou 6 must meet minimum performance standards.
The loan is the third that NRG has secured from the in-ERCOT program, which has been allocated $7.2 billion of the total fund. The Houston-based generator’s other projects were granted $778 million in loans for 1,177 MW of nameplate capacity. (See NRG Energy Secures $216M Loan from TEF and NRG Secures $562M Loan from Texas Energy Fund.)
The PUC is vetting 11 additional applications, representing 5,406 MW of gas generation, for TEF’s in-ERCOT program.
ERCOT stakeholders have endorsed a 1,109-mile, single-circuit 765-kV backbone transmission project that is expected to cost nearly $9.4 billion in capital, making it the largest initiative for the grid operator in decades.
The Texas 765-kV Strategic Transmission Expansion Plan (STEP) Eastern Backbone project is so large that some stakeholders referred to it with an uncapitalized term not found in the protocols.
“This project falls into the category of just a really big ass project,” the R Street Institute’s Beth Garza, who represents the Consumer segment, said during the Technical Advisory Committee’s Nov. 19 meeting. “It’s really big. It has the potential to be very impactful.”
The project involves four transmission service providers (American Electric Power, CenterPoint Energy, CPS Energy and Oncor) who will build seven segments of the extra-high-voltage transmission lines, four 765-kV substations, 11 765/345-kV transformers, and 69 765- or 345-kV circuit breakers. The result will be a rectangular network from Northeast Texas down to the Coastal Bend.
The backbone project dwarfs ERCOT’s Competitive Renewable Energy Zone program, which was completed in 2014 at a cost of $6.9 billion. The project came in $2 billion over projections, but the 3,600 miles of 345-kV CREZ lines freed up more than 23 GW of wind capacity in West Texas.
The 765-kV STEP was developed in 2024 along with ERCOT’s Regional Transmission Plan to address load projections of 150 GW — 65 GW above its current demand peak — in 2030 on an already congested system. ERCOT staff said the 765-kV backbone would enable power to flow more efficiently through long-distance transmission from resource-rich regions to urban load centers. (See 765-kV Lines in West Texas Inch Closer to Reality.)
Prabhu Gnanam, ERCOT’s director of grid planning, said the Eastern Backbone, a subset of the 765-kV STEP Core Plan, addresses the statewide EHV reliability needs identified in the RTP. He said the RTP’s sensitivity analysis indicated major portions of the Core Plan would still be needed, even with 20 GW less load.
TAC endorsed the project in a 23-2 vote, with two abstentions. South Texas Electric Cooperative and Brazos Electric Power Cooperative both voted against the measure.
STEC’s John Packard questioned the “unprecedented” speed of the project, which was submitted to ERCOT’s Regional Planning Group (RPG) in July before being recommended by staff. He said the proposal also lacks an accompanying legislative or regulatory mandate.
“I think a lot of this load that’s forecast … doesn’t hit ERCOT until 2030 to 2032, so there’s other projects that are going to be carrying some of this large load in the meantime,” he said. “I think it only makes sense to take maybe a more measured approach and incorporate some of these policy initiatives.”
“Generally, I’m in favor of transmission. In order to have a truly competitive market, we need robust and reliable transmission,” said Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas. “My real concern, though, is 1,100 miles of new right of way. We can get [construction permits] and get it built in five to seven years … but this price is going to creep as we start acquiring that right of way.”
The project’s price tag easily met the $100 million threshold to be classified as a Tier 1 project, requiring approval by the ERCOT Board of Directors.
TAC endorsed two other RPG-recommended Tier 1 projects, adding them to the combination ballot that is the committee’s answer to a consent agenda:
Oncor and AEP’s proposed 104-mile, single-circuit 765-kV project in West Texas that closes the western end of ERCOT’s EHV backbone. The Drill Hole-Solstice project has a projected capital price tag of $742.2 million.
Oncor upgrades to a 345/138-kV switch and 9 miles of 138-kV line, and 13 new miles of 345-kV lines in far West Texas. The project has an estimated capital cost of $110.6 million and completion date in December 2026.
All three projects will require construction permits from the Texas Public Utility Commission.
ERCOT Looks Past RTC Go-live
With the Real-time Co-optimization plus Batteries (RTC+B) project barreling toward its Dec. 5 go-live date, attention has begun to turn to the stabilization period after the market mechanism begins procuring energy and ancillary services every five minutes.
The committee and ERCOT’s Matt Mereness, chair of the RTC+B Task Force, discussed who would be responsible for monitoring and tracking the market’s data and issues, and for how long. Mereness said the task force could be sunset or incorporated in another stakeholder group.
TAC Chair Caitlin Smith, with Jupiter Power, pointed out ERCOT has been setting aside several other market designs to observe RTC’s effects on the market.
“I feel like as soon as RTC goes live, you’re going to have maybe even more on your plate, more varied things,” she told Mereness. “All the things you’ve said, ‘We’ll get back to it after RTC.’ All the things you’ve said, ‘We can revise as we go along with RTC and have data.’”
Harika Basaran, the Texas PUC’s director of market analysis, noted RTC is one of ERCOT’s performance measures. She pointed out that ERCOT will have initial RTC settlements but could have an old system using data from the new system. She suggested a “stabilization piece and the writing out of issues and getting those assigned to a safe landing spot or dealing with them there.”
“We could do that,” Mereness said.
Smith agreed that the proposal makes sense. Protocol revision requests would go through the normal process, but the task force or its successor would handle the “plan and timeline for what pieces need to be done next, and maybe some issue-spotting is brought there too.”
Mereness said staff have filed a notice with the PUC alerting it to “likely” protocol violations in three of the RTC’s 150 or so reports. One of the reports prints $9,000 prices at the cap, even though the cap was reduced to $5,000 after February 2021’s Winter Storm Uri. Staff are working on an urgent Nodal Protocol revision request to remedy the problem.
“In the meantime, we’re going to fix our systems to not print $9,000 prices as soon as we can after go-live,” he said. “In a way, we’re going live with something that may or may not show up because it only shows up in a load-shed type event.
“See you on the other side,” Mereness said in closing his presentation.
Large Loads ‘Consuming’ ERCOT
ERCOT has added 142.2 GW of interconnection requests by large loads during 2025, staff told TAC, pushing the total queue to 225.8 GW as of mid-November.
Over 193 GW of those requests are by standalone facilities, with co-located loads accounting for the rest.
“We thought [83 GW] was a lot,” ERCOT’s Julie Snitman said.
Nearly a quarter of the requests (91 of 366) are from loads larger than 1,000 MW apiece; the other 275 are at least 75 MW each. Developers submitted 78 requests during the second quarter and have already filed half of that midway through the fourth quarter. At the same time, staff said a little more than 5,000 MW of large loads have been “observed” as being energized.
“ERCOT is having a problem getting started with cluster studies because everybody keeps submitting new large loads to them,” Longhorn Power’s Bob Wittmeyer, who chairs TAC’s Large Load Working Group, told stakeholders. “Large loads are effectively consuming all of their resources by adding more large loads.”
“That’s really heating up our bandwidth,” ERCOT’s Agee Springer, senior manager of grid interconnections, said in agreement.
Several stakeholders questioned how staff can be sure the large loads will eventually show up. Kristi Hobbs, vice president of system planning and weatherization, said she has been “very active” in the PUC’s large load rulemaking process.
“It’s very important that we work with the commission to get this rule right because that will indicate what we will include in our forecast going forward,” she said.
ERCOT is partnering with Texas A&M’s Engineering Experiment Station to develop detailed generic dynamic models of large loads and how they can change their power output during and after grid disturbances. Wittmeyer said he recently attended a conference on interconnecting large loads in ERCOT, held by the university’s College of Engineering, that was “pretty well attended by a bunch of data center folks.”
Ross’ Last Meeting
The meeting marked the last for AEP’s Richard Ross, the longest-serving TAC member. Ross has represented AEP on the Investor-Owned Utility segment for about 23 years, he said.
“He’s not going anywhere. He’s not retiring,” Smith assured members.
Ross said he will continue to supply a word or theme of the day — a staple at both TAC and SPP Markets and Operations Policy Committee meetings — in the future.
His final word of the month? “Ventilate.”
“Gratitude” had been suggested before Ross joined the meeting. But “no, that’s not the theme at all,” he said. “If you want to go with it, that’s fine, but the word of the month is ‘ventilate’ … you know, we’ve ventilated on ERCOT’s opinion.
“Use ‘ventilate,’ ‘gratitude,’ whatever it takes to get us to 2 o’clock,” Ross said, referring to the meeting’s scheduled close.
“Unless anybody else has gratitude or ventilating or is retiring from TAC, I think we can adjourn,” Smith said in ending the meeting.
NPRR Comments Rule
The committee endorsed a protocol change (NPRR1298) that would require comments on proposed rule changes to be delivered to ERCOT within 14 days of the revision request’s posting. Comments posted after the 14-day comment period can be considered at the Protocol Revision Subcommittee’s discretion.
The measure passed 21-1, with six abstentions. Ross was the only member voting against it.
“I don’t think it was necessary,” Ross, who said he doesn’t like abstaining, observed in explaining his vote to Basaran. “We’ve worked well without this for many years … I don’t know if we had this rule in place for the last 20 years if it would have adversely impacted anything.”
TAC approved a request by BHER Power Resources for a permanent site-specific exemption from complying with metering protocols by placing it on the combination ballot. The company said its Falcon Seaboard facility in Big Spring was built in such a way that it can’t meet a 500-kW maximum load limit requirement for auxiliary distribution factors. The facility has been operating for 35 years.
The combo ballot also included five other NPRRs and single revisions to the Nodal Operating Guide and Planning Guide that, if approved by the board, will:
NPRR1274: update the estimated capital cost for the tier-classification rules used in the RPG process.
NPRR1287: replace the defined term “Maximum Daily Resource Planned Outage Capacity” with “Resource Planned Outage Limit” (RPOL) to align with the actual calculated RPOL; add the maximum duration of a proposed transmission outage with a described lead time to align with current outage-coordination practices; define conditions under which ERCOT can accept an outage request if it could exceed the planned outage limit; and clarify that energy storage resources submit outages.
NPRR1294: incorporate the Other Binding Document “Demand Response Data Definitions and Technical Specifications” into the protocols to standardize the approval process.
NPRR1300: implement Senate Bill 1877 by including the Texas Office of Public Utility Counsel as an entity permitted to receive protected information or ERCOT critical energy infrastructure information without violating the protocols.
NPRR1303: revise language to change the method for submitting and receiving declaration of natural gas pipeline coordination from a physical form to an electronic format.
NOGRR280: remove language governing communication path requirements for CREZ circuits and stations.
PGRR131: implement mandatory reporting requirements for transmission service providers’ and ERCOT’s interconnection-cost reporting and delete gray-box language superseded by the requirements.
The PJM Markets and Reliability Committee endorsed by acclamation an issue charge to explore how the performance of demand response and price-responsive demand (PRD) resources can be improved.
According to the accompanying problem statement, the six load management deployments in this summer had a weighted average performance of 67%, which is “significantly lower” than was observed during tests conducted in the 2024/25 delivery year and the actual performance in past years. It states that shrinking reserve margins are likely to require more regular DR and PRD dispatching. The committee approved the document during its Nov. 20 meeting.
“PJM seeks to ensure that stakeholders understand the existing load management dispatch process (and PRD required response) and the measurement and verification calculations used to determine Capacity Performance and real-time energy settlements,” it says.
It notes that the circumstances under which DR and PRD could be used were expanded in the 2024/25 delivery year to allow deployments outside a performance assessment interval (PAI). When a PAI is not active, demand-side resources are not subject to CP penalties if they do not perform and they can use historic test results to replace actual performance during a non-PAI event.
The Independent Market Monitor has pointed to the lack of penalties and the ability to substitute actual performance with test results as part of its opposition to expanding load flexibility as part of the Critical Issue Fast Path (CIFP) process focused on how to address rapid large load growth.
“Demand-side response when called is effectively voluntary based on the relatively weak incentives to respond, despite the fact that the tariff states that reductions are required. If demand-side resources do not respond when called, any actual performance penalties can be overridden by test results, if the performance issue is not during a PAI event,” the Monitor wrote in its State of the Market report for the third quarter.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the poor performance of demand-side resources casts a cloud over the CIFP proposals voted on by the Members Committee during its Nov. 19 meeting. (See related story, PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
The issue charge envisions “solutions that will improve performance when load management is dispatched, or PRD is required to respond, and ensure applicable tariff requirements associated with performance are met.”
The expected changes the issue charge lists are fairly broad, leaving the door open to “process and/or system changes” and corresponding changes to the governing documents and manual language. Implementation is targeted for the 2028/29 Base Residual Auction, which is scheduled to be conducted in June 2026, and a tariff filing is expected in late April.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said his client J-Power USA could not support the issue charge without a wider scope inclusive of how DR participates in the energy market. Adding a requirement that demand-side resources offer into the energy market should be on the table, he said.
Aaron Breidenbaugh, senior director of regulatory affairs at CPower Energy Management, said the energy and capacity markets do not always provide enough compensation to cover the costs of a curtailment. Trying to develop a cost-based offer structure for the resource class could take as long as a year.
FERC granted CAISO‘s request to remove the sunset date on the Western Energy Imbalance Market Assistance Energy Transfer feature, which has been used by more than 10 of the market’s balancing area authorities in recent years.
CAISO originally planned to end the AET feature Dec. 31, but asked FERC to allow it to keep the program in place to accommodate BAAs that continue to experience supply constraints during certain trading intervals in the WEIM (ER25-3491).
Under the WEIM tariff, when a BAA has insufficient supply or ramping capacity, CAISO can use the AET feature to limit the amount of market transfers into and out of the BAA. The BAA receives a surcharge based on the lower of either the failure amount or of the final incremental transfer amount.
The WEIM resource sufficiency evaluation shows whether a BAA has enough capacity and flexibility to meet forecast demand and uncertainty. The evaluation has four tests: a feasibility test, a balancing test, a capacity test and flexibility test. CAISO’s AET feature is open to a BAA that fails the capacity and/or the flexibility test.
Before the AET feature was implemented in 2023, if a BAA failed a capacity or flexibility test, they became ineligible to receive incremental energy transfers from other balancing areas in the WEIM, CAISO said in its Sept. 23 filing with FERC to extend AET.
Supporters of the AET extension include the Balancing Authority of Northern California, NV Energy and CAISO’s Department of Market Monitoring (DMM).
In the past two years, DMM has not found that a BAA systematically relies on the AET feature, DMM said in Oct. 14 comments to FERC.
“AET transfers occur relatively infrequently, and at relatively low volumes with low associated cost when they do occur,” DMM said in the comment filing.
However, DMM said it still has outstanding concerns about the feature, such as its potential to allow BAAs to inappropriately lean on the WEIM footprint for capacity, and for the possibility for surcharges to apply to WEIM transfers that are not the direct result of selecting the program, the order says. However, neither of these concerns requires immediate action: Each could be addressed in future revisions of the AET feature, DMM said, according to the order.
As part of the approved order, CAISO will also adjust the AET feature to exempt surcharges that occur when a BAA fails the resource sufficiency evaluation, as long as the BAA works with its reliability coordinator to ensure reliable operations, the order says. This change will help ensure WEIM participants do not need to weigh potential surcharge liabilities against prudent reliability-driven actions, the order says.
When CAISO launches its Extended-Day-Ahead Market (EDAM) next year, participants in that market will also be able to access the AET feature, the ISO said in the Sept. 23 filing.
The U.S. is entering one of the most transformative periods in the history of its electric grid. Demand growth once projected to be flat or modest has surged dramatically due to the rapid expansion of data centers, semiconductor manufacturing, electrified industrial processes and artificial intelligence infrastructure.
States like Arizona, Georgia, Texas and Virginia are experiencing unprecedented requests from large-load customers — sometimes hundreds of megawatts at a time, often with aggressive deadlines and nearly always with major implications for transmission planning, resource adequacy and local reliability.
Recognizing the magnitude of this coming shift, the Department of Energy issued a rare Section 403 directive Oct. 23, requesting that FERC initiate rulemaking procedures and consider an Advance Notice of Proposed Rulemaking (ANOPR) to create a new framework for the interconnection of large loads to the transmission system. The resulting ANOPR, now underway, will shape how quickly, fairly and reliably large loads gain access to the grid for years to come. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)
This development has generated broad national discussion, including among state utility regulators. At the National Association of Regulatory Utility Commissioners’ recent annual meeting, NARUC adopted a resolution emphasizing the need for FERC to respect state jurisdiction and collaborate closely with states as it considers how to regulate large-load interconnections. Far from attempting to block federal action, NARUC instead articulates an important message: States and the federal government must be partners in this process, not competitors. (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections.)
Collaboration, ultimately, must be the animating theme of our national approach. If we treat this as a jurisdictional contest between Washington and the states, we will fail to meet the urgency of the moment. If, instead, we treat this as a shared responsibility — with states leading on retail impacts and FERC serving as a federal backstop where interstate coordination is essential — we can deliver the infrastructure needed to support economic growth, protect reliability and ensure that retail customers are not unfairly burdened by the costs of new large loads.
The Moment Requires Cooperation, not Competition
It is tempting — especially in the traditionally divided landscape of energy regulation — to gravitate toward turf protection. But the challenge before us is too large, too complex and too time-sensitive for regulatory silos. State regulators, utilities, transmission providers, regional planning authorities and FERC must adopt a posture that is less competitive and more cooperative if we want to succeed.
Large-load interconnections today face three fundamental challenges:
Timing: Study processes never were designed for single customers requiring 100 to 1,500 MW of new demand in a matter of months.
Cost Allocation: Uncertainty about who pays for transmission upgrades can stall or kill major projects.
Reliability: Sudden new demand can strain generation reserves, transmission capacity and local distribution systems.
States understand these impacts more directly than anyone. They see the near-term pressures on local substations, on summer reliability margins and on the retail rates their constituents ultimately will pay. That is why NARUC’s resolution emphasizes the need to preserve state jurisdiction and ensure retail customers are not left subsidizing massive data center and industrial loads.
At the same time, FERC is the only entity with legal authority to ensure consistent treatment across interstate transmission systems. Large loads have regional impacts. Their interconnection often triggers bulk-system upgrades that span multiple states. Without a federal backstop, transmission planning across state lines becomes slower, riskier and less predictable.
Neither side can succeed alone. For that reason, cooperation — not competition — must be our guiding principle.
FERC as a Backstop Authority, not the Front-line Regulator
The most productive framing is one that treats FERC as a backstop authority — the referee who steps in when interstate coordination or minimum national standards are needed, but who does not displace the states’ essential authority to ensure resource adequacy, reliability and affordability.
Under this model:
States retain jurisdiction over retail rates, distribution infrastructure and siting.
States lead the conversations around cost shifts, local planning and reliability impacts.
Regional transmission operators and utilities handle the technical study processes, applying state-approved resource adequacy and planning assumptions.
FERC sets the minimum guardrails for transparency, open access and interconnection timelines on the transmission system.
FERC uses its authority only when regional issues cannot be resolved at the state level in a timely manner.
This approach ensures fairness and consistency without undermining state sovereignty. It also provides large-load customers with something they increasingly demand: certainty. Certainty that timelines will not drag on indefinitely. Certainty that rules will not change midprocess. Certainty that their project will not be subject to a patchwork of incompatible interconnection standards across the country.
In other words, FERC should not be the first mover. It should be the backstop — the stabilizing presence that steps in only when needed, and only where states agree that interstate coordination is indispensable.
Why States Must Lead — but not Alone
State regulators are closest to the impacts of large-load interconnection. When a data center proposes a 200-MW facility, it is the state commission that will hear from residents about reliability concerns. It is the state that will be responsible for ensuring adequate generation and reserves. It is the state commission that must determine how costs are recovered — and who bears them.
The NARUC resolution rightly stresses these points. It does not oppose federal involvement; instead, it advocates for a balanced framework in which states maintain authority over matters that directly affect retail customers. The resolution also acknowledges the need for collaboration with FERC and other stakeholders, recognizing that a purely state-led approach cannot solve every regional transmission challenge.
This dual recognition — that states must lead but cannot act alone — is essential. No state wants to see its retail customers subsidizing another state’s economic development. No state wants to compromise its reliability due to regional planning failures. And no state wants to be left without the tools to assess or assign the costs of substantial new load growth.
The Path Forward: A Shared National Strategy
To deliver the infrastructure required for the next generation of American energy and innovation, we will need a coordinated national strategy built around the following principles:
Clear, transparent interconnection processes. Large loads must know exactly how long studies will take, what upgrades are needed, and how costs will be allocated.
Strong state-federal coordination. State commissions must be at the table from the beginning—not reacting after federal rules are finalized.
FERC as a backstop — not an adversary. Federal authority should be triggered only when regional solutions are required and state-level mechanisms are insufficient.
Protection for retail customers. States must have a decisive role in evaluating whether new load will shift unfair costs to existing ratepayers.
A commitment to reliability above all else. New development cannot come at the expense of reliability or resource adequacy.
Conclusion: Meeting the Moment Together
Our country is facing an unprecedented wave of demand growth. We can either rise to meet it or fall behind and risk delaying economic development, hindering innovation and compromising the reliability of the electric grid.
Competition between states and FERC is not the answer. Cooperation is.
By embracing a framework in which states lead, FERC can be an essential federal backstop and provide large-load customers with clarity and predictability. This collaborative approach can support the next era of American growth while maintaining affordability and reliability for all consumers.
This moment demands partnership. It demands humility. And above all, it demands a shared commitment to building the grid of the future — not through conflict, but through collaboration.
Nick Myers is vice chair of the Arizona Corporation Commission.
IESO is proposing rule changes to eliminate unwarranted make-whole payments (MWPs) to operating reserve (OR) providers under Ontario’s nearly eight-month-old Market Renewal Program.
“These are very specific and limited circumstances and only became apparent after the Renewed Market ‘go-live’ and relate to the interaction between payments for energy and operating reserve,” the ISO said at an engagement session Nov. 21.
MWPs are intended to incentivize market participants to follow their schedules by compensating a resource for the financial difference between its actual dispatch and what it would have been based on its offer curves and LMPs.
Although improved alignment between schedules and LMPs under the new market has reduced the need for MWPs, they still are needed because of manual out-of-market actions taken for reliability and differences between scheduling passes and pricing passes.
Real-time MWPs should represent a resource’s physical capabilities and are calculated considering co-optimization of energy and OR. IESO calculates payments for lost costs and lost opportunity costs (LOCs) based on economic operating points (EOPs), which reflect the output a resource could have achieved based on its physical capabilities and LMP, under actual market conditions.
EOPs are based on offers and bids, resource-specific characteristics and LMPs. Lost cost scenarios occur when the LMP indicates a resource should have been scheduled lower.
The Renewed Market, which launched May 1, created a financially binding day-ahead market (DAM) and about 1,000 generation, load and intertie pricing nodes to replace its provincewide price. (See Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months.)
Hok Ng, IESO’s senior manager of market development, identified three types of inappropriate real-time make-whole payments:
EOPs and ‘Forbidden Regions’
Some hydro generators have “forbidden regions” in which they cannot maintain steady operation without damaging their equipment and thus must ramp through.
Although the forbidden regions are considered in dispatch schedules, they are not reflected in determining the EOPs on which MWPs are based.
The energy market accounts for cases in which EOPs are physically unattainable with a settlement process that subtracts the portion of the MWP resulting from an energy schedule in a forbidden region or at the upper boundary.
IESO’s proposed rule change (MR Ch.0.9 Section 3.5.6) would add a similar adjustment for OR MWP calculations.
OR Ramping in LOC EOP Calculations
An inconsistency between OR ramp constraints in the dispatch scheduling optimizer and EOP calculation engine is overstating EOPs beyond what resources can physically perform, resulting in unwarranted MWPs.
The EOP calculation engine is missing constraints containing the interval-to-interval energy ramp impact on available OR ramp.
IESO’s proposed revision would add equations including the interval-to-interval change in energy to the LOC EOP OR calculations (MR Ch.0.7 App. 7.8).
MWPs not Offsetting Energy and OR Products
Make-whole payments are intended to keep a resource whole for following dispatch instructions that are co-optimized across energy and reserve products, such as 10-minute spin, 10-minute non-spin and 30-minute reserves.
But the current LOC MWP settlement is ignoring profits realized for the same capacity in the market, resulting in market participants being paid twice for the same megawatts.
The proposed Market Rule Amendment (MR Ch.0.9 Section 3.5) and Market Manual changes (MM 0.5.5 Section 2.7) will clarify how the offsetting should be calculated.
Next Steps
IESO requests comments on the Adjustments to RT MWP engagement by Dec. 1 via its feedback form. The ISO will respond to feedback and present a red-lined draft of the market rule amendments on Dec. 16.
IESO’s Technical Panel will conduct an education session on the changes on Dec. 2 with a vote to recommend to the IESO board scheduled for Feb. 10, 2026.
A new FERC report adds to the growing body of work showing the complexity of confronting the seams issues likely to arise between the West’s two day-ahead markets when compared with challenges at the borders between RTOs and ISOs in the Eastern U.S.
In their white paper “Seams Coordination in the Western Interconnection,” released Nov. 21, FERC staff urge Western electricity industry stakeholders to get ahead of seams issues before CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ both go live, scheduled to occur in 2026 and 2027, respectively.
And the authors recommend steps the two market operators can take to manage the myriad challenges — mostly unique to the West — related to the existence of seams between the markets.
“These seams can create operational and reliability hurdles that arise from several related issues: overlapping transmission ownership and rights, differences in transmission modeling, and congestion caused by loop flow,” they said. “The same issues could diminish the economic benefits of EDAM, [CAISO’s Western Energy Imbalance Market], and Markets+ by limiting the ability to trade across markets.”
The paper outlines the history of seams coordination in the Eastern Interconnection, including the development of congestion management processes and market-to-market agreements typically wrapped into the joint operating agreements among RTOs such as PJM, MISO and SPP, and their neighboring non-market areas. Those JOAs include provisions for handling emergency energy flows between balancing authorities and managing trades across boundaries, such as through coordinated transaction scheduling (CTS), FERC staff noted.
The paper points to two efforts already underway to address seams issues in the West.
The first, not directly related to the two markets, is the joint work by CAISO’s RC West and SPP RC to propose improvements to the Western Interconnection Unscheduled Flow Mitigation Plan to the North American Energy Standards Board.
In April 2024, NAESB’s Enhanced Curtailment Calculator (ECC) Task Force — which includes members from both reliability coordinators — issued a white paper describing the problems with current unscheduled flow mitigation practices in the West. It explained that the region’s BAs and transmission operators largely rely on their own individual methods to resolve unscheduled flows, meaning that transmission customers on one system might experience curtailments for different reasons than similarly situated customers on a different system. To remedy the problem, the task force recommended expanded use of the ECC tool to bring more uniformity.
The second seams effort underway is the Markets+ Seams Working Group (MSWG), as well as work undertaken by other working groups helping to develop that market.
“From its inception, the MSWG was charged with supporting the development of seams coordination frameworks and identifying potential seams-related tariff content; early discussions on the working group’s scope included import/export and wheel-through issues and congestion management topics,” the paper says.
At the direction of the Markets+ Participant Executive Committee, the MSWG in 2024 began developing the Seams Strategy and Roadmap, designed to identify focus areas for policies and governing documents related to seams issues with neighboring areas.
Going to Flow-based Modeling
In the paper, FERC staff called out “three primary categories of issues that Western entities should consider addressing through seams coordination agreements,” including:
use of flow-based modeling rather than contract path modeling;
coordinating interchange between market areas to prioritize maintaining reliability and managing congestion; and
coordinating electricity flows to maximize economic efficiency.
On the modeling issue, the authors note that transmission availability in the West is mostly modeled on contract path-based models that assume flows on contracted paths between generation sources and load sinks, compared with the flow-based approach in the East that relies on a flowgate methodology to calculate available transfer capability (ATC).
“Because flow-based modeling uses actual power flows to model the transmission system, it is generally considered to be more efficient and robust than the contract-path based methodology,” FERC staff wrote, adding that use of the two methods is “inconsistent” across the West.
“The continued use of contract path-based modeling and the use of different modeling methodologies may complicate efforts to maintain reliability, mitigate congestion and enhance economic benefits in the Western Interconnection. Thus, before discussing more specific approaches to coordinating operations in the West, it is important to ensure that the transmission availability and usage metrics these markets rely on be modeled as consistently and accurately as possible,” they wrote.
Adoption of flowgate modeling would have two benefits, they said: more accurate estimation of ATC and “better coordination across seams during day-ahead and real-time operations by market operators and BAs.”
Given that EDAM and Markets+ will rely on transmission capacity being made available by market participants rather than transmission owners handing over control of their systems as in a full RTO, FERC staff said, “flow-based modeling of ATC could provide a more accurate view of how much transmission is actually available to allocate between the markets compared to the results of contract path-based modeling prior to the actual day-ahead and real-time market runs.
“Western entities could investigate whether this would ease longer-term transmission expansion needs and make more transmission available for day-ahead and real-time market optimization.”
Managing Reliability, Congestion
On the subject of coordinating interchange between markets, FERC staff called the process a “key tool” in maintaining reliability and managing congestion.
“Agreements that formalize interchange procedures during critical system conditions between markets, as well as those between markets and non-markets, have generally provided greater certainty to system operators and improved cooperation between BAs. These include agreements such as emergency energy agreements, reserve sharing arrangements and JOAs,” they wrote.
The paper recommends that Western entities consider how reliability agreements across seams address data and model coordination, emergency event protocols, and loop flow management.
FERC staff wrote that the expansion of centralized markets in the West “introduces new challenges and opportunities for managing congestion between markets areas as well as between markets and non-markets,” with EDAM and Markets+ schedules potentially causing loop flows that extend beyond their borders.
To limit the effects of congestion, the paper recommends the adoption of M2M coordination, which seeks to reduce congestion at the lowest cost through the sharing of market pricing data between two RTOs/ISOs to bring about the most efficient redispatch.
Economic Trading Across Seams
The paper says cross-seam coordination of electricity transfers for cost savings likely will take on different forms in the West than in the East.
Part of that has to do with the differences between how EDAM and Markets+ deal with bidding at their interties with non-participating BAs.
Under existing WEIM and EDAM rules, participating BAs can decide whether to allow non-resource specific bidding at their interties with non-participating BAs. In Markets+, intertie economic trading will be implemented uniformly along its seams, allowing participants to submit buy and sell offers for imports and exports as long as they have the necessary transmission rights — an approach the authors say “could facilitate more economically efficient trading across its seams.”
FERC staff suggest that Western market operators could implement coordinated economic trading between their two areas. That might entail a practice such as CTS, which allows market participants to use a single portal to submit bids based on spreads between delivery points on either side of market seam.
The market operators also could implement “some form of interchange optimization” that gives them visibility into each other’s system and pricing for each trading interval. That approach would allow market participants to submit bids within their own markets, with the operators then using that information to determine whether they can meet their needs most economically from their own resources or from transfers out of a neighboring area based on transmission constraints and other factors.
The FERC paper did not explore another complicating factor for the Western markets compared with the East: the highly fractured boundaries between EDAM and Markets+ that likely will effectively island some participants — particularly in Markets+.
During a meeting of CAISO’s Western Energy Markets Regional Issues Forum in April, Richard Doying of Grid Strategies, one of the designers of the MISO market, noted that non-contiguous market zones “will require drive-out, drive-through and drive-in transmission service and schedules,” an arrangement that will require new types of transmission service and coordination to avoid diminishing the value the markets are intended to bring.
“The complex seams arising in the West from the expansion of Western markets presents challenges to operations, reliability and the efficiency of the markets,” FERC staff wrote in the conclusion of their paper. “To address these challenges, FERC staff believe it is important that Western entities continue their work coordinating operations to ensure the reliability and efficiency of their markets and BAs as Western markets proceed toward implementation and in advance of live operations.”
BOSTON — Energy affordability and regional collaboration dominated talks at the New England-Canada Business Council’s annual Executive Energy Conference on Nov. 19-20.
While the event featured similar themes and rallying cries as the 2024 conference, calls for collaboration have taken on a different tone amid heightened tensions between Washington and Ottawa. (See US, Canadian Leaders Discuss Affordability of Energy Transition.)
Massachusetts Gov. Maura Healey (D) and Nova Scotia Premier Tim Houston both attended the event and emphasized the strong ties between the people and economies of the Northeast states and provinces.
“Our energy future is inextricably tied to Canada’s,” Healey said, noting that states and provinces are in regular communication on energy policy and planning through the Northeast International Committee on Energy, which reconvened in 2024.
She highlighted a resolution passed at the Annual Conference of New England Governors and Eastern Canadian Premiers during the prior weekend reaffirming “the importance of continued regional collaboration, including interregional information sharing, planning and analysis on energy matters.”
“We look forward to continuing to build on that and to strengthen the ties that bind us, especially on energy transmission,” she said.
Healey directly criticized the tariffs imposed by President Donald Trump for creating “needless friction” between the countries and driving up costs throughout energy infrastructure supply chains.
“Higher infrastructure costs ultimately make higher energy costs for our people, and it’s our businesses, our consumers and our residents who lose out,” Healey said. “Lift these tariffs, Mr. President, and lower housing costs and lower energy costs for the American people.”
Houston also touted the strength of cross-border relationships in the Northeast while emphasizing his commitment to transforming Nova Scotia into an “energy superpower.” The province has outlined plans to scale up offshore wind and offshore oil and gas drilling, with an eye toward ramping up its exports.
“Nova Scotia is the next frontier in generation,” Houston said. “As long as I’m in this chair, I will do everything I can to grow this industry.”
Several presenters spoke about the massive potential for wind generation in the province. According to the strategic plan for the province’s Wind West project, “Nova Scotia’s already studied and identified sites alone [that] have the capacity to generate 62 GW of new electricity supply, with capacity factors of up to 60%,” equal to about a quarter of Canada’s total energy capacity.
The Canada-Nova Scotia Offshore Energy Regulator has initiated a process of issuing licenses to develop up to 3,000 MW across three areas, while leaving the door open for licenses up to 5,000 MW.
Houston said he is confident about the viability of the sites, ports, workforce and matureness of the technology to support a large-scale wind buildout but acknowledged that questions remain about how to transport the power to markets in Canada and the U.S.
Dave MacGregor, associate deputy minister for the Nova Scotia Department of Energy, said he is “struck by the fact that we were talking about the exact same things 25 years ago — and I’m referring specifically to transmission.”
But despite the challenges of the past, he expressed hope that renewed collaboration efforts finally could make transmission projects a reality.
“For the first time in close to three decades, the staff are coming to Nova Scotia to figure this out,” MacGregor said. “I really have seen marked improvement, and I do see a path where New England can benefit and Canada can benefit.”
Transmission paths to New England or Quebec could follow either submarine or overland routes. Several panelists at the conference advocated for a subsea path.
“We would say submarine cable all day long,” said Donald Jessome, CEO of Transmission Developers Inc. “There’s no engineering issues; the technology is there today.”
Stuart Nachmias, CEO of Con Edison Transmission, agreed that the technology is available to support a submarine line but said there are challenges related to siting, permitting and offtake.
“Who’s going to pay? That’s always the issue,” Nachmias said.
Phil Bartlett, chair of the Maine Public Utilities Commission, concurred, emphasizing the importance of understanding what the costs would be and how they would be shared.
“It’s going to take regional collaboration. I think you would need multiple states interested in a project to move forward,” Bartlett said.
He expressed optimism about the recent increase in collaboration between the states on transmission issues, pointing to the ongoing ISO-NE Longer-term Transmission Planning (LTTP) procurement, which aims to reduce transmission constraints in Maine and help support the connection of 1,200 MW of onshore wind. (See ISO-NE Provides More Detail on Responses to LTTP Procurement.)
The newly established LTTP process includes a cost allocation framework, in which the costs of a solution selected by ISO-NE will, by default, be allocated by load share. The states have the option to submit an alternate cost allocation method or terminate the process.
In coordination with the LTTP solicitation, Maine has initiated a separate process to procure onshore wind in northern Maine and a transmission line connecting the generation to a new substation that would be created through the LTTP process.
Bartlett said he expects at least five of the six New England states to participate in this separate procurement, adding that “having the states working together on these procurement issues really helps to get it done.”
Bartlett said that 1,200 MW of onshore wind “is just the “tip of the iceberg of what’s available in Maine,” and that “we consider this Phase 1 of that buildout, recognizing there’s a lot more to do.”
‘Build, Baby, Build’
Some speakers called for increased efforts to address the infrastructure constraints that limit the flow of gas into New England.
Toby Rice, CEO of the EQT, praised the Trump administration’s energy policy approach and stressed the need to build more gas infrastructure to “win this AI race.”
“I don’t want to find out what happens if we don’t win this race,” Rice said.
It will be won, he said, by the country that can scale up generation most quickly. He noted that China is adding power at a far faster pace than the U.S.
“It’s no longer about ‘drill, baby, drill’; it’s about build, baby, build, and we’re hopeful that permitting reform will be a priority over the next 12 months,” Rice said.
He said the growth of intermittent renewables has caused gas resource capacity factors to decline, putting strain on the economics supporting gas generation in some areas. To address the issue, he advocated for increased incentives for gas resources to be available on standby.
At the same time, he opposed capping capacity prices, saying, “We have to experience a little bit of pain for the market signals to be there.”
John O’Brien, CEO of JERA Americas, said industry leaders should do more to advocate for adding gas pipeline capacity into the Northeast.
Business groups, such as the Associated Industries of Massachusetts and regional chambers of commerce, “have to be re-energized to actually take on those issues,” O’Brien said. “You should take on an agenda, and the agenda might be controversial, but that’s why you pay the big dues.”
He said New England “should recognize that we need this infrastructure to continue to have our key industries” and pushed back on the idea that it is a foregone conclusion that the gas constraint will prevent the region from hosting data centers.
“Are we going to say, ‘We’re going to forgo that opportunity because we would have to expand the gas system?’” O’Brien asked.
Other speakers focused their comments on the importance of demand-side actions and reining in spending on upgrades to existing assets.
Weezie Nuara, Massachusetts’ deputy secretary for federal and regional energy affairs, emphasized the “need to add transparency and scrutiny” to local transmission spending. She said ISO-NE’s recent work to establish a new in-house asset condition reviewer should “help us get our hands around the largest component of [transmission] spending.” (See More Oversight Needed on Local Transmission Spending in NE, Panel Says.)
Massachusetts Department of Public Utilities Commissioner Liz Anderson noted that, under state law, electric utilities cannot charge ratepayers for long-term gas pipeline contracts. She said the DPU is focused on addressing affordability through the means within its jurisdiction, including demand-side actions and scrutiny on infrastructure spending.
Advocates of this strategy argue that, without a focus on strategic electrification and pipe decommissioning, gas customers will be saddled with a rapidly increasing share of the gas network’s fixed costs as electrification customers exit the system.
In an op-ed published in the Boston Globe on Nov. 17, former DPU Chair Jamie Van Nostrand wrote that gas supply, which accounted for about two-thirds of customer costs a decade ago, now makes up less than a third. Meanwhile, “roughly 70% of the bill pays for infrastructure, profits and taxes,” he argued.
Anderson emphasized the importance of investment in energy efficiency and advanced metering infrastructure (AMI). The Massachusetts electric utilities aim to complete their deployment of AMI infrastructure by 2029. Once in place, the meters likely would enable development of time-varying rates that incentivize customers to reduce demand during peak periods.
“That’s a huge untapped resource, and I think that’s something we can do at the state level,” Anderson said.
FERC largely approved filings by California’s three major investor-owned utilities to comply with interconnection queue requirements under Order 2023 (ER24-2776, ER10-1391-003 and ER24-3032).
In three separate orders Nov. 20, FERC mostly accepted Southern California Edison, San Diego Gas & Electric and Pacific Gas and Electric’s tariff revisions, but the utilities must clarify some issues within 60 days.
In SCE’s case, FERC ordered the utility to file revisions related to storage operating assumptions, network upgrade cost allocation requirements, site control, the definition of regulatory limits and cluster study provisions.
On the operating assumptions, SCE argued it did not need to include those because it already offered similar provisions for electric storage resources under a commission-approved settlement agreement.
FERC rejected this argument, siding instead with renewable energy company Terra-Gen and the California Energy Storage Alliance (CESA), which contented the settlement agreement “is expressly conditioned on future compliance with commission orders.”
“Terra-Gen and CESA explain that while the settlement agreement has a moratorium prohibiting revisions to SoCal Edison’s tariff, there is also an exception allowing changes to be made if directed by a commission order or a final rule, such as Order No. 2023,” FERC said.
The two protesters asked FERC to reject SCE’s proposed revisions and direct the utility to revise its tariff to allow interconnection customers to provide operating assumptions for storage resources, according to the order.
FERC agreed, stating that “SoCal Edison has failed to adequately justify excluding the requirement for transmission providers to use operating assumptions, at the request of the interconnection customer, in interconnection studies that reflect the proposed charging behavior of an electric storage resource.”
“We are evaluating the order and are pleased to see much of our proposal approved,” Jeff Monford, spokesperson for SCE, told RTO Insider.
Meanwhile, in the SDG&E docket, CESA, along with the Clean Energy Alliance, San Diego Community Power and the Clean Coalition, also filed objections.
In one matter, CESA objected to SDG&E’s proposed rules regarding affected systems, arguing that they “are insufficiently detailed and could give rise to discriminatory practices.” FERC said it was “unpersuaded” by CESA’s arguments, finding that the utility included “requirements for circumstances where SDG&E is the host service provider.”
But the commission did order SDG&E to file revisions related to network upgrade cost allocations, commercial readiness and regulatory limits.
FERC likewise required PG&E to clarify or correct provisions pertaining to co-located generating facilities, operating assumptions, cluster study and site control, among other issues.
CESA contended PG&E failed to “provide interconnection customers with electric storage resources with the ability to design and charge their facilities in a manner sufficient to satisfy their proposed operating parameters,” according to FERC. The organization argued PG&E failed to explain how it would review interconnection customers’ requested operating assumptions or whether the company would allow customers to operate in accordance with those assumptions after entering service.
FERC noted that some of CESA’s concerns should be addressed by PG&E in its subsequent compliance filing but that its “concerns about PG&E not describing how it will analyze requested operating assumptions or allowing additional flexibility for interconnection customers to adopt control technologies are outside the scope of this compliance filing because these requirements were not established in Order No. 2023.”
The utilities said in their filings that they must navigate between Order 2023 requirements as well as their CAISO tariffs. FERC noted this and pointed to overlap in, for example, cluster study requirements in both CAISO and Order 2023.
PG&E spokesperson Jennifer Robison told RTO Insider that “FERC’s order will help expedite interconnection of wholesale generation on markets managed by [CAISO].”
“This is an important step in meeting CAISO’s load forecasts, which project significant electric demand growth in California driven mostly by new data centers, EV charging and building electrification,” Robison added. “We look forward to continuing to work with CAISO and other stakeholders on additional improvements to the interconnection process.”
FERC issued Order 2023 in July 2023 with the goal of clearing backlogged interconnection queues by implementing a first-ready, first-served cluster study process; increasing interconnection customers’ financial obligations; and penalizing grid operators for missing study deadlines. (See FERC Partly Accepts SPP’s Order 2023 Compliance.)
In 2024, the commission rejected challenges to the order, though it made several clarifications and minor modifications and established an extended compliance deadline with Order 2023-A. (See FERC Upholds, Clarifies Generator Interconnection Rule.)
