Members Endorse Ancillary Services Methodology for 2025

ERCOT stakeholders have endorsed changes to the grid operator’s ancillary services methodology as part of the annual process to determine the minimum amount of products that will be procured in 2025.

Staff’s proposed modifications, presented to the Technical Advisory Committee during its regular monthly meeting Sept. 19, include three revisions to ERCOT contingency reserve service (ECRS). ERCOT introduced ECRS last year, but it drew opposition from the Independent Market Monitor, which said the service produced “massive” inefficient market costs totaling more than $12 billion in 2023. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)

The Monitor is working with ERCOT and Texas Public Utility Commission staffs on a report for the Texas Legislature that is due by October. The IMM’s director, Jeff McDonald, said there were “limited opportunities” to add lessons learned from the study to the AS methodology process but that he was happy with staff’s recommendations.

“I think we’ve learned some things about procurement targets and some potential recommendations for how the procurement process can be adjusted to result in a lower cost without compromising reliability,” McDonald told TAC. “We do note that that we’re seeing a more targeted procurement through this process, resulting in a reduction in both the ECRS and [non-spinning reserve service] levels procured. We’re happy to see that. … We will have some recommendations that come out of the AS study that we feel will be very important to be taken up and discussed in the 2026 methodology process.”

Staff proposals for ECRS include removing the adjustment for risk coverage during sunset hours to at least the 90th percentile; adjusting the frequency recovery portion to cover 70% of historic net load and inertia conditions; and computing the minimum ECRS requirements as the larger of the capacity needed to recover frequency and capacity needed to support net load forecast.

Since ECRS first was deployed in June 2023, staff said there have been “very few situations” when ECRS had to be released for net load forecast issues and frequency recovery needs. The changes will result in setting ECRS quantities based on needs of the dominant operational risk in every hour, they said.

Staff also proposed minor changes to non-spin, regulation service and responsive reserve service (RRS):

• • Non-spin would be revised so the methodology computing its quantities between 10 p.m. and 6 a.m. uses a four-hour-ahead net load forecast error.
  • Regulation quantities would be computed using the historic error in security-constrained economic dispatch’s forecasted net load.
  • The minimum RRS-primary frequency response (PFR) limit would change to 1,365 MW.

NRG Energy’s Bill Barnes, who represents Reliant Energy Retail Services, asked whether the transition to real-time co-optimization (RTC) next year will affect the math used to calculate “some amount” of AS to be procured throughout the year. ERCOT has set a December 2025 go-live date for RTC, which will procure energy and AS every five minutes. (See ERCOT Sets Go-live Date for RTC, ESR Project.)

“We implement RTC and that all goes away, right?” he asked. “Because how much ancillary services you actually procure is all dependent on price. At that point, the quantities will vary significantly. So I’m wondering, how do we bridge that gap, right?”

“From our perspective, RTC does not change the quantity of ancillary services that we need because the quantities are based on the fundamental operational risks,” said Jeff Billo, ERCOT’s director of operations planning. “So it’s how much RRS do you need to arrest the frequency? How much ECRS do you need to recover frequency? But those fundamentally are physics-based questions that RTC is not changing.”

Billo said ERCOT will propose a methodology similar to the current one as the grid operator goes into 2026. He said he took note of stakeholder feedback from a recent AS workshop about procuring the services closer to real time or the operating day, as opposed to calculating it annually.

“I think that could change the quantities, but we think that doing that at the same time as RTC may not be preferable, and so we want to kind of put that off to 2027,” he said.

The measure cleared TAC, 26-1, with a couple of abstentions. Calpine’s Bryan Sams cast the lone dissenting vote against the changes, saying his organization believes there’s additional risk with the reduction of regulation in the morning and during the winter.

“The second reason is we still believe that ECRS sends, or has sent, an investment signal for new generation development and the reductions in ECRS, I think, are harming that signal,” Sams said.

ERCOT’s protocols require staff to provide at least annually the methodology for determining the procured quantity of each AS needed for reliability. The grid operator’s Board of Directors and the Texas PUC will review the recommendations before making their decisions.

Members Discuss Stakeholder Process

TAC devoted the first two hours of the meeting to a discussion with staff of the stakeholder process and communications. Two hours and 25 minutes later, the membership agreed to reserve time at the next meeting to pick up the conversation.

Members discussed how decisions are made at TAC, how the decision-making process is presented to the board and how the reasoning behind opposing votes is shared with the board.

The discussion was prompted after the PUC’s chair, Thomas Gleeson, said the interaction between the board and TAC “did not work” for him during a July open meeting. (See Texas Commission Rejects ECRS Rule Change.)

The PUC’s Barksdale English, a TAC member when he was with Austin Energy, said commission staff are working on a rulemaking related to the appeal of board decisions to the PUC and “should be coming soon.”

“We talked a lot about what your role is here and how Barksdale English would love for TAC members to view your responsibility here,” English said. “I guess it almost seems like there’s another conversation that needs to be had around how do you codify TAC’s role in receiving recommendations from your subcommittees and how do you codify what you’re communicating up to the board. At the end of the day, it will be the board members’ decisions on how to receive those requests.”

‘Cookies and Laughter’

After committee Chair Caitlin Smith, of Jupiter Power, said during TAC’s August meeting that she was open to lightening the atmosphere for members following comments that “unlike SPP, we don’t have ‘cookies and laughter,’” stakeholders were greeted with a virtual cornucopia of tasty treats. (See “Lightening the Mood,” ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024.)

A large chocolate chip cookie that seemed to have been sent from SPP’s Markets and Operations Policy Committee included a greeting that read, “SPP Cookie Power: From our stakeholder group to yours, we heard y’all need some cookies.” Another container of cookies were iced with “SPP.”

“I had an oatmeal raisin. It was delicious,” one member said.

Two other boxes of cookies were decorated with images of ERCOT CEO Pablo Vegas, a laughing emoji and the words “TAC IS FUN.”

The levity was provided by CIM View Consulting’s Steve Reedy, who reminded TAC that it was “Talk Like a Pirate Day.”

“How many letters does the pirate alphabet have?” he asked, before providing the answer. “I, I, R and the seven Cs.”

Change to CLRs Dispatch

TAC unanimously endorsed a Nodal Protocol revision request and its accompanying Other Binding Document request (NPRR1188, OBDR046) after late comments were filed.

The protocol change would modify the dispatch and pricing of controllable load resources (CLRs) in response to the PUC’s directive to increase the “utilization of load resources for grid reliability.” It revises the market-participation model of CLRs that are not aggregate load resources so that they are dispatched at a nodal shift factor and settled for their energy consumption at a nodal price.

The committee also endorsed a combo ballot that included three NPRRs, one revision to the Nodal Operating Guide (NOGRR) and the annual under-frequency load shedding survey of transmission owners, which found they met requirements for all five thresholds.

The protocol and guide changes, if approved by the ERCOT board, will:

• • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the dpth percentile difference.
  • NPRR1237: document the scenarios in which market participants are required to successfully complete retail qualification testing, regardless of whether the market participant previously received a qualification letter from ERCOT from prior retail flight testing.
  • NPRR1244: align eligibility provisions for CLRs not providing PFR to provide ECRS. It would also include in physical responsive capability’s calculation only the capacity of CLRs when they are qualified to provide regulation service and/or RRS that requires the CLR to be capable of providing PFR.
  • NOGRR263: clarify that a CLR is only required to provide PFR when it is providing an AS that requires that resource to be able to provide PFR.