ERCOT stakeholders last week endorsed the first batch of key principles that will lay the foundation for implementation of real-time co-optimization (RTC) in the market.

The Technical Advisory Committee on Wednesday readily endorsed five principles brought forward by the Real-Time Co-optimization Task Force (RTCTF). The principles still must be approved by the Board of Directors, which meets next on Aug. 13.

“I like to think of it as building a house,” said ERCOT Compliance Director Matt Mereness, who chairs the RTCTF. “The high-level principles are the blueprint that will provide direction in [the next] phase, which is developing the protocols.”

The stakeholder group, which has been meeting since April, has been charged with implementing RTC, a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements. ERCOT has said it can implement RTC by mid-2024, at a cost of at least $40 million.

The task force intends to bring the TAC a series of additional principles for endorsement through the end of the year using templates that “look eerily” like change request forms, as Mereness said. The RTCTF’s work will likely end the committee’s recent practice of canceling meetings (three so far in 2019) over a lack of voting items.

The TAC approved four key principles unanimously and with minimal discussion.

A debate erupted during discussion of the fifth — modifying AS’ deployment to accommodate real-time awards — over whether to use participation factors (PFs) in ERCOT’s regulation service instructions.

Staff recommended eliminating the use of PFs, which tell ERCOT how qualified scheduling entities (QSEs) plan to distribute deployment of AS across their qualified resources on a four-second basis. They proposed instead to make regulation service instructions resource-specific — ensuring that regulation awards are proportionate to deployment.

Crescent Power energy consultant Shams Siddiqi offered an alternative that would give QSEs the option of using PFs. Under his proposal, resources providing reg-up/reg-down would be expected to follow ERCOT resource-specific deployments after each RTC run, until the time the grid operator accepts new telemetered PFs. Once ERCOT accepts the entities’ new telemetered factors, resources would be expected to follow PF-adjusted, resource-specific reg-up/reg-down deployments until the next RTC run.

Mereness noted ERCOT’s regulation-service deployments are not economic solutions, and that keeping the PFs actually increases deployment efficiency.

ERCOT’s Dave Maggio said Siddiqi’s alternative proposal mixes approaches to regulation awards, using the grid operator’s proposal for the first part of the five-minute interval and the optional use of PFs for the second part. Siddiqi’s alternative may be technically feasible, Maggio said, but it is more complex and creates risk around telemetry management and validation.

Lower Colorado River Authority’s (LCRA) John Dumas said he was also concerned about the complexity the market would be adding with the alternative proposal, but would prefer to maintain its flexibility.

“[ERCOT’s proposal] would have ERCOT making all the decisions and taking away the flexibility from the owners,” he said. “We should maintain PFs as an option under real-time co-optimization.”

“It would be fairly low-cost to retain participation factors,” Reliant Energy Retail Services’ Bill Barnes said. “This really comes down to what we think additional cost and flexibility is. We’re just talking a couple of hundred megawatts [of regulation service] here. I’m not sure it’s worth it.”

Walter Reid, with the Advanced Power Alliance, pointed to Siddiqi’s comment that energy storage will provide most regulation service in the future.

“ERCOT has done a fair job of not overly complicating this,” he said. “I would certainly err on the side to give developers as much incentive as we can to enter ERCOT, because that will be much more valuable for loads as we move forward.”

The TAC rejected the alternative proposal by a 21-3 vote, with five abstentions. Members then approved ERCOT’s original suggestion, with Shell Energy North America abstaining.

The other four key principles (KPs) include:

• • KP 1.4 addresses the necessary modifications to ERCOT systems and applications that provide inputs for the real-time market optimization engine to accommodate RTC and the real-time AS awards.
  • KP 1.6 modifies the AS imbalance settlement process to award AS in real time.
  • KP 3 adds to the reliability unit commitment (RUC) process by reviewing resources scheduled to be available and study moving AS among qualified resources to meet forecasted conditions and align with the real-time market. The RUC process will study whether additional commitments are needed to meet the load forecast and minimum AS requirements, and resolve transmission congestion.
  • KP 4 eliminates the supplemental AS market, replacing it with an updated RUC process to resolve transmission congestion and ensure sufficient capacity is projected to be available in real time to meet the load forecast and AS plan.

The task force compromised on KP 3 by agreeing to allow RUC to use RUC AS demand curves. As originally drafted, the principle would have ruled against the use of the real-time AS demand curves.

STEC’s Lange Elected Vice Chair

Committee members elected Clif Lange, South Texas Electric Cooperative’s manager of wholesale marketing, as their new vice chair. Lange replaces Diana Coleman, who stepped down from the TAC when she accepted a position with San Antonio’s CPS Energy.

Members also approved the 2020 meeting calendar. The TAC will once again generally meet on the fourth or fifth Wednesday of the month, as it did this year.

TAC Endorses 15 Changes

The committee passed a previously tabled Nodal Protocol revision request (NPRR917) that replaces load-zone energy pricing with nodal energy pricing for settlement-only distribution and transmission generators (SODGs and SOTGs). The NPRR allows SODGs and SOTGs to request ERCOT continue to provide them load-zone pricing until they opt in for nodal pricing or until Jan. 1, 2030, whichever comes sooner.

Cypress Creek Renewables withdrew earlier comments calling for a 40-year grandfathering period and asked instead for a 20-year period to cover contractual agreements with off-takers. However, the Protocol Revision Subcommittee recommended a 10-year period.

LCRA proposed the opt-out option should also be made available to entities with executed development agreements before Jan. 1, 2019, and suggested the SODG or SOTG’s full capacity should be online as of June 1, 2020. LCRA’s comments were amended to the motion, which passed 23-5, with one abstention.

The TAC unanimously endorsed 10 other NPRRs, a change to the Nodal Operating Guide (NOGRR), an Other Binding Document (OBDRR) and two system change requests (SCRs):

• • NPRR823: Synchronizes the protocols’ “affiliate” definition with state law to allow exemptions for portfolio affiliates (two or more publicly traded companies in the same industry with common shareholders).
  • NPRR904: Revises the categories of ERCOT-directed actions that trigger the real-time online reliability deployment price adder (RTRDPA)’s pricing run to include DC tie-related actions to reflect current system conditions and corrects identified flaws with current RTRDPA design.
  • NPRR931: Modifies the hub average 345-kV price calculation to reflect the use of aggregated shift factors, as opposed to simple averaging of the component hubs’ prices.
  • NPRR932: Clarifies that new load added to an existing ERCOT system zone (including load from a non-ERCOT control area) can take effect immediately without board approval.
  • NPRR935: Requires ERCOT post values for wind and solar forecasts and include an indication of which model is being used for each forecast. Also requires ERCOT to issue a market notice and sponsor an NPRR proposing requirements for any new future forecasts.
  • NPRR940: Removes from the protocols NPRR664’s grey-boxed language introducing an optional, alternative fuel index price, which has never been implemented.
  • NPRR942: Clarifies in the protocols the timing of the final allocated transaction limit for the congestion revenue rights auction’s posting (the second-round limit).
  • NPRR943: Adds Martin Luther King Jr. Day to the list of ERCOT-observed holidays.
  • NPRR944: Updates the day-ahead market’s energy bid curve criteria language to align with current validation.
  • NPRR949: Removes the use of standard voice telephone circuits as an option for the grid operator to retrieve ERCOT-polled settlement meter data, effective Jan. 1, 2023.
  • NOGRR187: Aligns the NOG with NPRR863’s revisions to ancillary services.
  • OBDRR009: Paired with NPRR904, the change revises the online and offline capacity reserves for out-of-market actions related to DC ties, preventing price reversal and price distortion whenever ERCOT makes out-of-market actions.
  • SCR801: Corrects the global process ID for Texas standard electronic transaction (Texas SET) 867_03 by applying the same data lifecycle cross reference consistency for all 867_03 usage transactions.
  • SCR802: Improves system inertia communications by showing the real-time system inertia value under the Real-Time System Conditions display on the ERCOT website.

— Tom Kleckner