ERCOT stakeholders last week endorsed the charter and leadership for a task force that will report directly to the Technical Advisory Committee and provide recommendations on real-time co-optimization (RTC) and energy storage resources’ (ESRs) state of charge (SOC).

The Real-time Co-optimization + Batteries Task Force (RTC+B) will coordinate and review ERCOT and market activities to mitigate risks and support the RTC+B program’s implementation. Its responsibilities include managing timelines, providing a forum for analysis or policy decisions and reviewing nodal protocol revision requests (NPRRs).

Battery issues unrelated to RTC are out of scope. However, ERCOT will make time available after the group’s meetings should stakeholders want to continue to explore storage.

ERCOT’s Matt Mereness, who has volunteered to chair the task force, said he simply forklifted the charter from the previous stakeholder group that produced NPRRs and other rule changes to guide staff’s implementation of RTC.

“We said, ‘What does it look like to remove implementation risk?’ And so structurally, everything is the same,” he said during TAC’s Aug. 22 meeting.

Mereness also chaired the RTC Task Force that took a first look at the market tool that procures energy and ancillary services every five minutes. Using the approved NPRRs, the new group will develop business requirements for RTC and single-model batteries and review a SOC concept for batteries. (See “RTC Stakeholder Group to Form,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.)

Key policy issues include parameters for ancillary service proxy offers, triggers for initiating off-cycle security-constrained economic dispatch (SCED) executions, allowing real-time updates to current market offers and in the future with RTC, and evaluating a framework for periodic analysis comparing RTC and the ORDC.

A vendor will start developing the SOC for batteries involved in RTC in January. The task force plans to deliver its completed work in 2026.

Faced with a December target to gain ERCOT Board of Directors approval of its work, the RTC+B group will move quickly. It has already scheduled a Sept. 8 meeting to nominate a vice chair and review the RTC task force’s previous work and the sequence of activities necessary for implementation.

“We do think it’s important that we get real-time co-optimization done as quickly as possible, given that it’s planned to save enormous amounts of money for the market when it’s implemented,” Mereness said.

The RTC Task Force was disbanded at the end of 2020 following the initiative’s completion. The disastrous and deadly February 2021 winter storm and the ensuing drain on staff resources postponed the initiative until recently.

SOC Transparency

In a split vote, TAC approved one of two ERCOT revision requests (NPRR1186) designed to improve the grid operator’s awareness, accounting and monitoring of an ESR’s SOC before the RTC+B project goes live.

As approved by the Protocol Revisions Subcommittee (PRS) earlier in August, the measure adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market (DAM) process should begin to respect the AS award limits for ESRs based on duration requirements.

ERCOT has held three workshops on NPRR1186, and it has been the subject of conversation during two PRS meetings. Still, it was discussed for 90 minutes before TAC voted on it.

Storage developers Eolian, Plus Power and Jupiter Power filed comments opposing it, saying it would disincentivize longer-duration ESRs that could diversify energy supply and help manage the growing evening ramp’s variability because “administratively applied withholding requirements” will limit the resources’ ability to provide multihour AS products.

The joint commenters suggested modifying the measure by adding a variable to the calculation of AS, eliminating the ESRs’ obligation to stop discharging energy while deployed to provide certain AS, and ensuring compliance obligations address ERCOT’s SOC monitoring goals and mitigate unintended consequences.

After TAC endorsed the NPRR in a 22-3 vote with five abstentions — with the consumer and retail electric provider segments providing the pushback — Eolian said it would appeal the approval to the ERCOT board when it meets Thursday and request ERCOT be directed to resubmit new NPRRs to separate out system coding issues from the determination of SOC parameters and related compliance obligations.

Eolian said the board should give market participants a chance to work with ERCOT to define “actual reliability issues” and determine how to solve them without creating dangerous unintended consequences.

“Failure to do so will certainly create a chilling effect in the ERCOT market by discouraging the development and construction of longer-duration ESRs in ERCOT, which will be to the detriment of grid resiliency and reliability, as well as all ERCOT consumers,” the developer wrote.

Staff pointed out that AS market products work as mechanisms that maintain reliability, not as standalone economic products, and that ESRs create a duration issue. They agreed to review how other grid operators are addressing duration issues.

“There needs to be some perspective on what’s on the system now versus what was on the system 10 years ago,” said ERCOT’s Kenan Ögelman, vice president of commercial operations.

New ORDC Price Floors Set

The committee endorsed another binding document request (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC) in a move to retain and incent new dispatchable thermal generation.

Price adders of $20/MWh and $10/MWh will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. ERCOT analysis has indicated the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.

The Texas Public Utility Commission approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, this month. (See Texas PUC Approves ERCOT’s ORDC Modifications.)

Stakeholders approved the OBDRR in a 22-7 vote, with one abstention. All six members of the consumer segment voted against the measure over concerns the structure guarantees revenues and prevents customers from responding.

The Texas Industrial Energy Consumers’ John Hubbard said the organization still opposes the change and that it has filed a notice of appeal.

The OBDRR was separated from TAC’s combination ballot, which passed unanimously. The combo ballot included seven NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), two additions to the Resource Registration Glossary (RRGRRs) and a change to the Planning Guide (PGRR). If approved by the board, these changes would:

• • NPRR1164: require that resource entities identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It would also require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
  • NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources (DGRs) and distribution energy storage resources (DESRs) seeking qualification to provide AS and/or participate in SCED.
  • NPRR1173: account for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
  • NPRR1174: establish a process allowing QSEs or congestion revenue right (CRR) account holders to return overpayment settlement funds to ERCOT.
  • NPRR1175: strengthen market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classify information in the background check as protected information, modify application forms for QSEs and CRR account holders and add a new background check fee to the grid operator’s fee schedule.
  • NPRR1185: add a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
  • NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for AS that resources can only provide fast-response service if awarded regulation service in the DAM for that resource.
  • NOGRR215: allow new remedial action schemes to only address actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
  • NOGRR249: specify methods for transmission operators to receive electronic communication of system operating limit exceedances.
  • RMGRR174: update language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
  • RRGRR033: add data to the resource registration glossary pursuant to NPRR1164.
  • RRGRR035: add fields consistent with NPRR1171.