ERCOT stakeholders have advanced a protocol change that provides longer-duration ancillary services and state-of-charge (SOC) parameters in advance of real-time co-optimization’s deployment in December.

The ERCOT-sponsored protocol change (NPRR1282) updates duration requirements to 30 minutes for regulation service and responsive reserve service and one hour for ERCOT contingency reserve service (ECRS). It also revises reliability unit commitment studies’ requirement to a one-hour duration for all ancillary services, excluding fast frequency response.

Staff told Technical Advisory Committee members that longer-duration AS are needed to manage grid variability and uncertainty. The grid operator, the Independent Market Monitor and stakeholders were split on the appropriate duration for non-spin and ECRS.

Several renewable interests said ERCOT’s RTC dispatch or SOC enforcement requirements will be “unnecessarily and administratively restrictive” of the amount of megawatts energy storage resources can offer.

The IMM recommended setting the non-spin duration constraint to one hour instead of four, saying that would incent batteries to provide energy rather than reserves. It said the four-hour duration also would deplete batteries’ SOC.

“The operations posture we have is the operations posture we have,” said Nitika Mago, senior manager of balancing operations planning. “As things evolve, I’ve conceded again and again we are happy to revisit it. But today, with the way we operate the grid and with the type of risks we see for non-spin, a four-hour duration is appropriate.”

In the end, Mago’s commitment to review information generated during RTC’s market trials, which begin in July, and an analysis of duration in the 2027 AS methodology document won over many stakeholders with concerns.

A motion to approve the NPRR with comments filed by ENGIE and Jupiter Power, and its associated Nodal Operating Guide change (NOGRR277), failed 11-18. When the comments were removed, the measure passed 26-2, with one abstention. ENGIE and Jupiter Power cast the dissenting votes.

The NPRR was granted urgent status so its parameters can be installed for RTC’s market trials.

Members Table Curtailment Change

TAC’s members unanimously agreed to table NPRR1238 and NOGRR265 after a lengthy discussion on their merits. The changes introduce a new early curtailment load (ECL) category and also would establish a process allowing loads to operate as an ECL so they can be accounted for differently in load-shed tables.

The committee will take up the issue again during a special webinar June 12.

ERCOT legal staff recommended tabling the two measures pending the Texas Legislature’s final consideration of Senate Bill 6. The legislation, addressing large loads, was under consideration before the session’s expiration June 2; several parties agreed with the need to align with the legislative process. (See Growing Clean Energy Sector in Texas May Avoid Damaging Legislation.)

Staff said the grid operator generally supported the NPRR but said they had concerns over large-load curtailments before energy emergency alerts.

Stakeholders expressed concerns with mandating loads — primarily industrial — to register as curtailable. NPRR1238 is intended to cover flexible loads sensitive to high prices, not all large loads.

The Public Utility Commission’s Barksdale English agreed with the decision to table the changes, saying it would be “smart” after amendments had been added two days before.

Oncor $855M Project Endorsed

TAC endorsed staff’s recommendation to award Oncor Electric Delivery a $855.3 million project in West Texas by placing it on the combination ballot, which acts as a consent agenda.

Oncor submitted the proposed Delaware Basin Stage 5 project for the Regional Planning Group’s review in May 2024. Wind Energy Transmission Texas (WETT) submitted an alternative project in August 2024.

Staff said Oncor’s proposal addresses reliability concerns and accommodates “significant and rapid load growth” in the petroleum-rich Delaware Basin area and also was less costly and required the least amount of transmission lines requiring regulatory approval. Oncor’s project requires 220 miles of transmission approval, while WETT’s costlier proposal ($871 million) is 232 miles long.

The project was identified in a 2019 ERCOT study that found the need for an import path to serve load once the Basin’s peak demand is greater than 5,422 MW. Staff said the 2023 Regional Transmission Plan’s 2025 case exceeds that level.

The project is expected to be in service by December 2029.

Committee members also confirmed Longhorn Power’s Bob Wittmeyer and ERCOT’s Patrick Gravois as chair and vice chair, respectively, of the Large Load Working Group by adding the recommendation to the combo ballot. The group, which recently removed “Flexible” from its title, has scheduled a workshop July 11 for data centers and electronic loads, with a focus on behind-the-meter systems that can survive low voltage and stay on the grid or resolve low-voltage issues.

Outage Capacity Changes

Stakeholders unanimously approved staff’s revisions to the methodology used to calculate the maximum daily resource planned outage capacity (MDRPOC).

The revisions are intended to provide sufficient outage capacity compared to historical levels by applying a risk-based construct for outages more than seven days ahead. Staff created a new MDRPOC curve to better evaluate thermal resources, and they have incorporated minimum outage levels in winter and summer to spread outages throughout the year.

ERCOT plans to apply the first future year MDRPOC to subsequent future years, saying there is a higher risk of limited resource commitments and project load growth in later years. Renewable resources and storage units will have their MDROPC calculated based on 110% of the historical maximum planned outages from the previous three years.

The measure passed 17-0, with 10 abstentions. The independent generators, power marketers and retail segments each provided three abstentions.

ERCOT is accepting comments on its proposal through June 9. It will go before the board during its June 23-24 meeting.

TAC Endorses ADER Doc

TAC endorsed a governing document for the third phase of ERCOT’s Aggregated Distributed Energy Resources (ADER) pilot project by adding it to the combo ballot.

Staff proposed increasing participation limits to 160 MW for energy and 80 MW for non-spin reserve service and ECRS, respectively. Phase 3 will allow a new participation model similar to non-controllable load resource (NCLR) and will enable third-party qualified scheduling entity (QSE) aggregation under the NCLR model, regardless of load-serving entity affiliation.

The grid operator will continue to analyze ADERs’ effect on system reliability and market efficiency, focusing on shift factor discrepancies and telemetry validation improvements.

ERCOT said that as of May, three ADERs have been qualified. They offer 15.5 MW capability for energy, with 8.6 MW for non-spin and 8.8 MW for ECRS. Nine additional ADERs are in various stages of registration, it said.

The pilot began in July 2022 and recently transitioned to ERCOT. (See “ADER Discussion Moved to WMS,” ERCOT TAC Opens Discussion on Proposed RTC Changes.)

The combo ballot also included the strategic objectives for the Retail Market and Wholesale Market subcommittees, three other NPRRs, one NOGRR, a single change to the Planning Guide (PGRR) and an Other Binding Document (OBDRR) that, with required board approval, will:

• • NPRR1226: Direct ERCOT to prepare and publish estimated demand response data showing aggregated state estimated load points selected by ERCOT. Loads selected for the report will be based on periodically updated off-line analysis of the frequency and magnitude of reductions observed in historical state estimator load data that is associated with LMPs, ERCOT-wide conservation appeals or other market signals.
  • NPRR1267: Require a large-load interconnection status report be published. The report won’t define “large load”, leaving that to NPRR1234 (Interconnection Requirements for Large Loads and Modeling Standards for Loads 25 MW or Greater). Confidential customer information on large loads will be aggregated.
  • NPRR1276: Incorporate an OBD, “Emergency Response Service Procurement Methodology”, into the protocols to standardize the approval process.
  • NOGRR275: Align the guide with protocol changes to eliminate scheduling center requirements for QSEs that are not wide-area network participants.
  • OBDRR054: Create a process by which transmission and/or distribution service providers will require market participants to successfully test retail transactions before their data universal numbering system is activated in a TDSP’s production system.
  • PGRR125: Add language to that guide that allows an interconnecting entity or property owner to demonstrate compliance under the Lone Star Infrastructure Protection Act should it have a subsidiary or affiliate that falls under the act’s citizenship or headquarters criteria. The subsidiary must not have direct or remote access to or control of the project, the project’s real property, resource integration and ongoing operations, the market information system, other ERCOT systems or any confidential data from the systems.