AUSTIN, Texas — ERCOT staff and the Technical Advisory Committee’s leadership teed up for discussion Feb. 27 a pair of protocol revision requests related to the grid operator’s real-time co-optimization (RTC) and battery project, set to go live in December.

That gave TAC’s members an early opportunity to dive into the two proposed changes (NPRR1268 and NPRR1269) and lay out their concerns before the cadence of meetings quickens and they are brought for approval before the ERCOT Board of Directors in April. Staff hope to resolve those concerns, clearing the way for market trials and implementation.

“We really only have one shot at these in March,” said TAC Chair Caitlin Smith, with Jupiter Power, alluding to the committee’s only remaining meeting before the board gathers.

“Now is the time to engage as needed,” ERCOT’s Matt Mereness, chair of the Real-time Co-optimization plus Batteries Task Force, told TAC. “This is why we wanted to get it on the table. We didn’t want this to happen next month, when we’re under the gun.”

Two key upcoming meetings are those of Mereness’ task force (March 5) and TAC’s Protocol Revision Subcommittee (PRS) (March 12). The PRS is responsible for reviewing and recommending action on formally submitted NPRRs.

TAC would then consider the likely revisions to the proposed changes and any new NPRRs during its March 26 meeting. The board will meet April 7-8, with RTC market trials set to begin in May.

“That’s a pretty tight timeline,” Smith said. “There’s not really time for an extra TAC [meeting] between [March 26] and the board” meeting.

Much of the discussion centered on NPRR1269, staff’s effort to codify policy changes that were deferred from the original RTC-related protocols developed in 2020: parameters for ancillary service proxy offers floors; scaling factor values for ramping; and AS demand curves (ASDCs) for use in reliability unit commitment (RUC) studies.

ERCOT’s Independent Market Monitor filed comments saying proxy offers should be set at fixed values corresponding to the variable cost to provide the service. It said setting ASDC at 95% of the AS plan for a given product — as ERCOT plans to do — “results in proxy prices that are excessively high at times and could lead to reliability and market performance issues.”

The IMM also said capping AS’ proxy price at $2,000 is arbitrary and “excessively high relative to the cost to provide the service.”

Andrew Reimers, the IMM’s deputy administrator, said he has brought the Monitor’s concerns over the RUC offer floor to several stakeholder meetings.

“We were really hoping that this wasn’t implemented with an eye towards making sure that RUC always procured the whole AS plan; that there are going to be plenty of circumstances where we’re knowingly going short on the AS plan and printing non-zero prices for non-spin or ECRS [ERCOT contingency reserve service],” Reimers said. “We’re accepting the point that RUC is a different kind of tool than the real-time market or the day-ahead market [DAM] and already has kind of different penalty functions in it.

“Now that this is swinging back around to, ‘OK, well, if you’re going to do that in RUC, then you should also have the same offer floor in DAM,’ that’s a real problem for us and might be a deal breaker.”

Mereness said the task force’s consensus is that AS proxy offers distort the market and should be rare exceptions and quickly corrected. The PRS plans to request urgent status for NPRR1269 in March to keep the change on track for regulatory approval ahead of the RTC+B market trials. While the trials begin in May, ERCOT is opening the sandbox for system testing before then.

The IMM is behind NPRR1268, which defines a methodology for disaggregating the operating reserve demand curve (ORDC) and creates “blended” ASDCs.

“We had cliffs on the curves. Now, we have ramps in the curves,” Mereness said.

Texas Competitive Power Advocates, a trade association of competitive generators, filed comments supporting ERCOT’s suggestion to add an ASDC floor in RUC that ensures security-constrained economic dispatch (SCED) can procure its AS requirements. The association said that under this construct, market prices will incent the market to self-commit the capacity to meet the AS requirements, rather than have RUC commit them.

Michele Richmond, TCPA’s executive director, called in to the meeting to clarify that the association’s comments were not intended to set a price floor.

“The [Texas Public Utility Commission] has made it clear through their direction that they want to avoid [operations] watches. They want to consider the conservative operations that ERCOT has been doing,” she said. “We want to make sure that whatever amount of ancillary services ERCOT needs to procure in that endeavor are done through the competitive market, through market solutions, and not through out-of-market actions.”

After meeting twice on NPRR1268, the RTC+B Task Force is leaning toward a separate revision request with a broader scope for the aggregated ORDC and ASDC issues, Mereness said. He said a broader consensus exists with NPRR1270, with stakeholders wanting to remove its original qualification expansion to automatically include all SCED resources for the ECRS and non-spin AS products.

The RTC process dispatches energy and ancillary services interchangeably in the real-time market. ERCOT procures AS in the day-ahead market and says it does not typically move the products between resources in real time. The grid operator expects to save $1.6 billion annually in reduced energy costs.

The grid operator has been working on RTC since 2017, when the PUC directed it and the IMM to assess the process’s benefits. Work was delayed for several months after the disastrous February 2021 winter storm, known as Winter Storm Uri, that brought the ERCOT grid within minutes of collapsing.

ADER Discussion Moved to WMS

Stakeholders agreed to park continued discussion of an aggregated distributed energy resources (ADER) pilot project to the Wholesale Market Subcommittee.

The hope is that the WMS will be able to resolve issues around direct participation of third-party aggregators in the pilot and flexibility on limits, as well as consumer protection concerns and implications for load-serving entities.

The ADER pilot project is in its second phase and eyeing a third. The PUC voted Feb. 13 to move the project into ERCOT’s stakeholder process to determine the best way to move the initiative forward. (See “ADER Project Moved to ERCOT,” 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)

The pilot began in July 2022 and has resulted in three virtual power plants participating in the wholesale energy market and providing certain AS. Eight additional ADERs have been approved and are in various stages of registration. Their total capacity, qualified and potential, is 25.7 MW of energy, 11 MW of non-spin reserve service and 8.8 MW of ECRS.

Staff have been working with the ADER Task Force to develop a governing document for Phase 3 and gain board approval in April. Potential changes include a new participation model that would allow ADERs to provide AS as non-controllable load resources (NCLRs) not economically dispatched in real time, and all third-party aggregators as NCLRs when aggregation is larger than 100 kW.

The ADER pilot was originally given a three-year time frame.

Amended NPRR Passes

TAC endorsed a proposed protocol change (NPRR1190) that would allow recovery of a “demonstrable financial loss” arising from a manual high dispatch limit override reducing real power output when the output is intended to meet qualified scheduling entities’ load obligations.

The measure was amended to include ERCOT comments received Feb. 27. Staff pushed to lower the $10 million threshold to trigger a review proposed by Reliant Energy to $3.5 million, saying the larger threshold, based on historical payment amounts that included Uri, was not appropriate given recent market pricing changes.

Reliant’s Bill Barnes said he acknowledged the $10 million threshold was too high and agreed to the reduced amount.

Committee members tabled the NPRR in October 2024 after it was also tabled by the board and remanded back to TAC over concerns of a more equitable and fair treatment of all parties.

The measure passed 26-4, with four members of the consumer group casting no votes.

TAC also endorsed a slim consent agenda that included its 2025 goals and strategic objectives, a proposed protocol change and a revision to the Verifiable Cost Manual (VCMRR) that would, if approved by the board:

• • NPRR1241: clarify the hourly standby fee claw backs for firm fuel supply service during a winter weather watch by using a sliding scale approach.
  • VCMRR042: add seasonal sulfur dioxide and nitrogen oxide prices obtained from indices to calculate emission costs from May through September; annual prices would continue to be used from October through April.