FERC approved MISO’s proposal to increase the number of generation projects it may study under its expedited interconnection queue lane from 10 to 15 per quarter.
The commission in a Nov. 25 order found that the increased quarterly project limit appears to be fair and aligns with its previous orders to speed up interconnection timelines reliably and transparently (ER25-3543).
FERC said it agreed with MISO that increasing project counts would help projects reach generation interconnection agreements faster and meet resource adequacy needs quicker. It said faster processing wouldn’t “adversely affect” MISO’s normal generator interconnection queue. (See MISO Moves to Increase Quarterly Project Count in Queue Express Lane.)
The change becomes effective Nov. 26, days before MISO kicks off acceptance of a second cycle of expedited generation requests.
The grid operator in late September filed with FERC to raise the quarterly rate, saying it could handle 15 project slots per quarter and potentially could close the temporary queue process earlier than the originally planned Aug. 31, 2027, retirement date.
MISO has to date received 49 project applications for its expedited queue, with most of the megawatts coming from gas-fired generators.
Kyle Trotter told stakeholders the RTO discovered it could process the generation projects faster than it previously anticipated.
“We didn’t see a reason not to try to go faster and expedite them even more. It doesn’t go deeper than that,” Trotter said at an October Interconnection Process Working Group meeting.
MISO Vice President of System Planning Aubrey Johnson told the Entergy Regional State Committee on Nov. 11 that the RTO believes the fast lane has met its objectives to accelerate resource additions.
However, environmental groups have challenged MISO’s and SPP’s queue fast tracks at the D.C. Circuit Court of Appeals, arguing the processes are unduly preferential, allowing primarily fossil fuel generation to skip queue lines while ratepayers fund the grid upgrades needed to accommodate them. (See Enviros Challenge MISO, SPP Queue Express Lanes.)
Altogether, MISO’s temporary process would accommodate 68 projects, with 10 reserved for submissions form independent power producers and eight from entities serving its retail choice load in downstate Illinois and a percentage of Michigan.
MISO is to roll out a new transmission warning declaration to give its members advanced notice when scarce transmission capacity is raising the risk of load shed.
Speaking at a Nov. 20 MISO Reliability Subcommittee meeting, Clayton Umlor, a MISO manager of reliability coordination, said a transmission emergency warning would establish “more transparency around transmission risk,” especially when load loss is imminent.
The RTO wants to put the new system in place sometime in the first quarter of 2026.
Umlor said MISO would institute the warning only after it has exhausted all normal congestion management procedures without relief, including generation redispatch, transmission loading relief and reconfiguration plans. The RTO alo would try deploying units’ emergency ranges and calling on its emergency-only units and load-modifying resources before sounding the alarm, he said.
MISO intends to use the warning when 100 MW or more of load is at risk after those actions, or when it finds transmission facilities rated above 100 kV have post-contingent flow greater than or equal to 115%.
Umlor said MISO would issue warnings when a reliability coordinator believes “system conditions warrant heightened awareness of potential transmission risk,” such as when load is being served radially due to a forced transmission outage or when a real-time flow of a transmission facility rated more than 100 kV is expected to exceed 100% of transfer capability.
The RTO would call off warnings once risk recedes.
Umlor said the new warnings would require software changes for its operator interface and some stakeholder training. “We want this to be a meaningful communication tool,” Umlor said, adding that MISO doesn’t want to issue the warnings so frequently that it becomes a “boy who cried wolf” situation.
He asked stakeholders to provide opinions on MISO’s proposed 100-MW threshold.
‘A Lot of Stakeholder Confusion’
The new warning category is the latest change MISO is pursuing after a May 2025 load-shedding event in New Orleans in which 600 MW was forced offline abruptly to avoid exceeding an interconnection reliability operating limit (IROL) on Entergy’s transmission system. (See MISO Mulling New Way to Convey Spate of Advisories in South.)
MISO has said an IROL “is the point when operational congestion becomes a reliability risk; crossing it isn’t just a violation — it’s a systemwide emergency.”
An Entergy representative at the RSC meeting said MISO’s designated actions during close calls aren’t always consistent.
Entergy associate general counsel Matt Brown said one shift of MISO operators could make one decision on a transmission plan of action while another shift could revoke that decision, even though criteria and conditions are unchanged.
“What it leads to is a lot of stakeholder confusion about what the risk level might be,” Brown said.
Brown said he understood MISO operators are under “tremendous pressure,” but added they sometimes make ambiguous declarations or split-second decisions the RTO struggles to explain afterward.
Umlor reiterated that the warning system is a “tool for communication that should be used infrequently enough that it is meaningful.” He said the set of criteria should be clear enough that the warning conveys real and present danger. MISO must be “vigilant to make this calibrated properly,” Umlor said.
Bill Booth, a consultant to the Mississippi Public Service Commission, asked if the warnings would come with any corrective actions for members.
“What’s the value of this warning if it doesn’t come with a directive?” Booth asked. He said when MISO delivers a capacity advisory, for instance, it comes with zero instructions.
Umlor said requests for action would come separately from MISO and not be tied to the warnings themselves.
John Harmon, MISO senior operations director of reliability, said the grid operator isn’t looking to change the existing action plans that it and utilities have in place — or their approach to public appeals for conservation.
Harmon said the intent is to “create an additional risk trigger instead of going straight to an emergency.”
Because transmission emergencies can involve shedding load, he said, it’s useful to add a layer of communication before outages that other MISO members can see. He added that MISO communicates directly in real time with utilities directly tied to the risk.
MISO has been declaring transmission and capacity advisories — mainly for its South region — since the springtime load shed.
Shedding Timed IROL Analyses
Relatedly, MISO plans to expand its IROL study timeline so it isn’t pressed to evaluate potential transmission emergencies in 15 minutes or less.
Harmon said the RTO would remove a 15-minute time limit to conduct cascade analyses from its emergency transmission procedures.
The grid operator’s current rules require it to complete an analysis on the possibility of cascading outages within 15 minutes before declaring a temporary IROL.
Harmon said MISO would be removing “an artificial time limit” and that additional minutes would allow it and its transmission owners to study, agree on and implement mitigation strategies before declaring a temporary IROL.
MISO said it’s “overly prescriptive” to assign a specific time limit on conducting studies. While the limit is “well intentioned,” it could rush decision-making and cause it to declare an IROL too quickly, especially in situations where load shed is pre-contingent, the RTO said.
Given PJM’s distinction of being both the nation’s largest wholesale electricity market and the epicenter of the data center boom, many hoped the grid operator would move closer to approving reforms governing large loads after a full day of committee proposals on Nov. 19. However, none of the dozen proposals considered were approved. (See: PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
The voting results suggest that an approach similar to PJM’s proposal may be on the horizon. As a demand response aggregator and virtual power plant platform, CPower would be supportive, assuming certain provisions from PJM’s proposal were to be implemented.
Regardless, we’d prefer PJM take the time to get large loads right rather than push through changes that could do more harm than good. PJM needs every megawatt of supply it can secure, and the last thing it should do is inadvertently force existing supply out of the market. With roughly 8 GW of DR in PJM, a poorly executed policy shift risks undermining a critical source of capacity.
Michael Smith
As it stands now, with new large loads coming online, commercial and industrial customers are likely to be dispatched more frequently, meaning manual load shedding is likely to become more common. In time, this could discourage the largest customers from providing the greatest load relief through DR participation, which has proven to be instrumental in maintaining system reliability during peak events and preventing deeper emergency actions in PJM.
If new large loads do not bring their own capacity, be it generation or demand flexibility at their site or elsewhere, the number of potential or actual reserve shortage hours over the next few years will rise to the point that PJM may routinely have hundreds of hours of DR calls.
With this in mind, we encourage the PJM Board of Managers to respect the following principles as it further deliberates reforms:
“Non-Firm Goes First.” New large loads that are not backed by DR or generator capacity have not purchased firm service and should be dispatched off the grid before pre-emergency DR providers.
DR is DR. New large loads participating in load management programs should be dispatched at the same time as pre-emergency and emergency DR and price responsive demand, not after.
DR Loads are DR Loads. Any new DR programs should be available to all customers, not just new large loads.
Capacity is Capacity. If data centers can buy capacity from a generator to meet a requirement, they should be able to purchase DR capacity for the same purpose.
Whatever path PJM chooses, other markets may follow. That makes this decision especially consequential, as it could set a precedent for future policies and shape how DR is used nationwide.
Getting it right and expanding the use of DR is essential, as it’s the most immediately available, affordable and reliable way to support rapid load growth and enable the innovative energy economy.
Michael D. Smith is CEO of CPower, a virtual power plant platform with 6.7 GW of customer capacity at more than 23,000 sites.
Industry stakeholders and the ERO Enterprise generally expressed support for FERC’s proposal to approve 11 proposed reliability standards intended to allow utilities to use virtualization technology, particularly calling on the commission to leave intact language in the standards that could allow exceptions to the new standards to be granted more easily (RM24-8).
Commenters on a second Notice of Proposed Rulemaking also supported a further modification to one of those standards that would improve cybersecurity at low-impact grid-connected cyber systems (RM25-8).
FERC issued both NOPRs in September along with a final rule directing NERC to develop standards addressing supply chain risk management and an order approving the ERO’s most recent cold weather standard. (See FERC Tackles Cybersecurity in Multiple Orders.) The virtualization updates touched almost every entry in the library of Critical Infrastructure Protection (CIP) standards:
CIP-002-7 (Cybersecurity — BES cyber system categorization)
Commissioners wrote that they supported NERC’s efforts to integrate virtualization and other new technologies into the grid but questioned the ERO’s proposal to replace the phrase “where technically feasible” in some standards with “per system capability” when granting exceptions to the new requirements. FERC asked stakeholders whether there is still a need for a technical feasibility exception (TFE) program, whether the proposed changes would result in entities seeking new exceptions and alternate approaches that would meet the ERO’s goals while allowing effective oversight.
In its response, NERC wrote that the “per system capability” language provides enough flexibility “to ensure the proposed … standards are forward-looking and enable responsible entities to adopt new technologies securely” but “does not absolve an entity from implementing methods to achieve the security objective.” The ERO observed that entities would be generally expected to “achieve the objective [of a given standard] by other means” if unable to implement the technology mentioned in the standard.
Compliance monitoring and enforcement engagements can also give the ERO insight into “how a responsible entity is mitigating risk unique to its environment,” not just its compliance with the letter of the standards, NERC wrote. The ERO wrote that under the existing standards, it collects data on technical feasibility exceptions each year, entities’ engagement with this program “has remained relatively stable over the past three years,” and entities are already required to explain how they are addressing the risks identified in the standards.
“NERC does not anticipate this trend shifting much with the transition to ‘per system capability’ language,” NERC wrote. “Responsible entities are likely to continue to use the mitigating approaches they are already implementing, and the TFE program has given NERC and the regional entities experience into what to expect as mitigating measures for ‘legacy’ systems.”
MRO’s NERC Standards Review Forum (NSRF) also wrote in support of the new language, explaining that the change “is designed to accommodate long-term situations” because the annual TFE reports require “administrative work that provides no benefit to the reliability of the grid [and] also have not proven to be beneficial.” The NSRF observed that “per system capability” or “per device capability” language “has been part of the CIP standards since 2016” and predicted that the proposed changes “should not impact the need for exception.”
The Bonneville Power Administration wrote that “exceptions to the CIP … standards are still necessary” because otherwise, “many utilities would be forced to immediately replace functional equipment at great cost and risk to reliability.” BPA added that it expected NERC and the REs to apply the same expectations to “per system capability” exceptions that it does to the TFE program, which REs can review through audits rather than requiring a separate process for approval.
NERC Argues Against Low-impact Study
In its other NOPR, FERC sought comment on its proposal to approve CIP-003-11 (Cybersecurity — security management controls), intended to address the risk of a coordinated attack using low-impact cyber systems.
Citing the China-linked Volt Typhoon group, which has been accused of embedding itself in the information technology networks of U.S. critical infrastructure organizations, the commission asked whether such actors could pose a threat to grid reliability and whether FERC should direct NERC to perform a study or develop a white paper on the issue.
NERC wrote against this suggestion, arguing that the organization is already studying relevant topics and that an order to conduct another study would be unnecessary. The ERO cited a 2023 data request that collected information from utilities on remote access incidents, along with a nonpublic Level 2 alert issued earlier in 2025 providing recommendations on remote access. Responses from industry “enabled NERC to further analyze the risks associated with cross-border remote access” to grid elements, the organization wrote.
ERO staff are “in the final stages … of developing recommendations” on the risk of remote access that will be published in a report by the end of the year, NERC continued. This report “will include detailed recommendations and next steps … that will inform NERC CIP reliability standards priorities over a multiyear horizon starting in 2026.” Because of this and other ongoing projects, NERC asked that FERC refrain from requiring further studies at least until the ERO has identified its next steps.
PJMpresented its Markets and Reliability Committee with a first read on a proposal to increase the minimum capitalization requirements to participate in its markets.
It was supported by 84% of stakeholders in the RTO’s Risk Management Committee in an October poll.
Under existing policy, entities participating in financial transmission rights markets must have either $1 million in tangible net worth (TNW) or $10 million in tangible assets. For those not involved in FTRs, the requirement is $500,000 in TNW or $5 million for tangible assets.
The proposal would increase the TNW threshold to $2 million for all participants with a 3% fixed rate escalation annually. It includes a transition period in which the TNW for non-FTR participants would first increase to $1 million and double over five years.
The TNW and tangible asset minimums have not been changed since they were instituted in 2011. PJM’s Ryan Jones said minimum capitalization requirements are meant to ensure that market participants can handle the risk associated with their activities and reduce the risk of default shifting costs to others.
An earlier version of the proposal would have required $5 million in TNW, but PJM decreased that after stakeholders voiced concern that it would create too big a barrier to participation, increase market concentration and reduce competition.
Independent Market Monitor Joe Bowring said he views the proposal as a modest requirement which would protect members against defaults by market participants who cannot meet their obligations.
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.
