ERCOT’s Technical Advisory Committee endorsed two previously tabled nodal protocol revision requests (NPRRs) following lengthy discussions last week.

NPRR815 increases from 50% to 60% the limit on load resources providing responsive reserve service (RRS) and requires them to provide at least 1,150 MW of primary frequency response (PFR). Changing the constraint will allow additional resources to provide RRS at lower costs, the Protocol Revisions Subcommittee said.

Lower Colorado River Authority’s John Dumas questioned claims the higher limit would realize about $3 million annually. He said the analysis overlooked the costs of paying combined cycle units to pick up the inertia responsibilities of coal plants that will be retiring early next year. (See Vistra Energy to Close 2 More Coal Plants.)

“We all know combined cycle units are not going to run unless the energy price supports them running,” Dumas said. “If you need combined cycles to run, you’re going to have to cover their cost to run, which is going to have a cost impact on the energy price. So, I’m a little skeptical of the cost savings [ERCOT] has touted.

“I’m more worried about the reliability impact,” he added. “This is not the time to ‘un-table’ this.”

“Once again, we have the people that get fired for reliability saying they looked at it, they looked at 4,100 MW retiring, and they don’t see a problem with it,” said ReSolved Energy Consulting’s Bob Wittmeyer. “The question I have for ERCOT is, if we implement this today and once it is implemented, how long would it take you to say, ‘Uh oh, we need to back up and take 50% of generation again.’ Is this a four-month process to reverse, or can you do it overnight?”

Dan Woodfin, ERCOT’s senior director of system operations, reminded stakeholders that the NPRR approves methodology for determining the minimum ancillary service requirements that can be procured in the day-ahead market. The ISO’s new reliability desk can issue reliability unit commitment instructions or resort to the supplemental ancillary service market should the ISO be short in the intraday.

“We can change [the minimum ancillary service requirement] on a daily basis, if need be,” Woodfin said. “I realize that’s not preferable, and that’s why we try to cover 70% of the requirement in the ancillary services market.”

Woodfin said staff tested its methodology by taking out the retired resources and found there were some instances in the shoulder months when it would have had to buy an additional 50 MW of ancillary services.

Citigroup Energy’s Eric Goff was among the independent power marketers who opposed tabling the NPRR, saying, “We know ERCOT says it will save money. … We know ERCOT says it’s not needed for reliability. It has expressed that without reservations or doubt. This should be a noncontroversial vote.”

The Texas Industrial Energy Consumers (TIEC), which argued successfully for tabling the change in September, again pointed out that NPRR848, currently being debated in the Wholesale Market Subcommittee (WMS), would create separate pricing for load resources and PFR-capable resources providing RRS.

However, a roll call vote to keep the NPRR on the table was split down the middle, failing to gather a two-thirds majority. The ensuing vote to endorse the revision passed by a 78-22 margin.

Members also endorsed NPRR825, which had also been tabled in September to allow staff to rework its impact analysis. Staff said the revision, which requires ERCOT to issue a DC tie curtailment notice before curtailing the tie’s load, would result in a “more efficient operation of the grid.” It also addresses the ISO’s concerns about declaring an emergency condition before curtailing DC tie load for any reason, rather than using an automated process, staff said.

Staff estimate the NPRR’s requirements will add $200,000-300,000 in development costs for a software tool it would build with or without the NPRR, Woodfin said. “We need a robust tool … not just for this NPRR, but for a multiple of things, including future NERC requirements,” he said.

ERCOT currently issues curtailment watches instead of notices, doing so 48 hours in advance of the day-ahead market. Woodfin said automating the process would be a better option.

“We set limits [before the day-ahead market] and update them every hour going forward, so it’s sort of a rolling 48-hour limit,” he said. “Things change during the course of the day. Lines trip, that sort of thing. We need a mechanism to [automate] that.”

The motion passed despite opposition from the consumer segment, receiving eight no votes and two abstentions.

ERCOT Staff Preparing for New RMR Rules

ERCOT COO Cheryl Mele told the committee that staff are refining protocol revisions to incorporate the Texas Public Utility Commission’s September order on reliability-must-run service rules. (See “Commission Approves RMR Rule Change,” Texas PUC Resistant to NextEra’s Minority Interest in Oncor.)

The order adjusts the suspension-of-operations notice requirements and complaint timeline, requiring written notification to ERCOT at least 90 days before a generating resource is mothballed on a seasonal basis. It also gives the ISO discretion to decline entering RMR service agreements based on the economic value of lost load and requires Board of Directors approval of staff recommendations regarding must-run-alternative (MRA) service. Capital expenditures made under the service agreements could be refunded by the resource owner if the resource participates in the energy or ancillary service markets.

“Effective Jan. 1, we’ll have this new process going forward, despite not having all of the protocol changes defined,” Mele said.

Scott Ends 10 Years as RMS Chair, Vice Chair

CenterPoint Energy’s Kathy Scott received a standing ovation from her fellow members after delivering her last Retail Market Subcommittee report. Scott is cycling off the group’s leadership after 10 years as either its chair or vice chair.

“It’s a lot of work to lead a subcommittee,” said Sharyland Utilities’ B.J. Flowers. “We’re very happy Kathy has stayed with it for that long.”

TAC Approves 2 Changes to Ancillary Methodology

The committee endorsed staff’s recommendations to make two changes to its 2018 ancillary service methodology for determining non-spinning reserve needs.

The committee approved including solar generation in net load calculations and forecasts, and adjusting for additional over-forecast uncertainty from projected increases in installed wind capacity.

Goff, who chairs the Qualified Scheduling Entity Managers Working Group, asked that the WMS and the Retail Operations Subcommittee be directed to evaluate the non-spin procurement methodology, reflecting conversations taking place within his group and the WMS.

“Our deployments of non-spin aren’t closely correlated with the procurement of non-spin because we don’t typically forecast for error,” he said.

TAC Vice Chair Bob Helton, of Dynegy, reminded Goff that reviewing ancillary service methodology is a TAC goal for 2018.

Staff did not propose any changes for determining regulation service and responsive reserve quantities.

The TAC also unanimously approved four other NPRRs and a verifiable cost manual revision.

• NPRR834: Clarifies processes associated with ERCOT’s repossession of congestion revenue rights following a payment breach or other default by a market participant. The change specifies data transparency requirements; documents the disposition of auction revenue funds above amounts owed to ERCOT; clarifies that the one-time auction bids must be positive; and allows the immediate transfer of CRR ownership to the winning bidder should an auction be necessary.
• NPRR839: Updates the protocols to clarify that, upon receiving meter data transactions from transmission or distribution service providers, ERCOT will forward the transactions to the designated competitive retailer.
• NPRR843: Addresses four reporting items in Section 3 of the Nodal Protocols (Management Activities) by:
  • Changing the short-term system adequacy reports’ logic for more consistent treatment of resource status; adding language to provide clarity to the reports’ end users;
  • Creating a new report that will show the portion of ancillary service (AS) offers at or above 50 times the fuel index price (FIP) when the market-clearing price for capacity of the service exceeds 50 times FIP;
  • Adding elements to the “48-hour highest price AS offer selected” report, including the highest-priced AS offer selected in a supplemental AS market (SASM); and
  • Creating a SASM disclosure report to provide transparency into AS offers and awards for any SASMs executed within an operating day.
• NPRR846: Allows previously committed emergency response service (ERS) resources to participate in must-run-alternative agreements and modifies the methodology for evaluating the performance during the first partial interval for ERS loads on the alternate baseline. The change also defines acceptable parameters for an ERS generator’s self-serve capacity, sets the ERS test performance factor to significantly lower values and in some instances to zero for resources with three consecutive test failures in a 365-day period, along with additional administrative changes and clarifications to existing ERS protocol language.
• VCMRR019: Provides clarifications needed following the incorporation of NPRRs 485 and 617 by shortening the timeline for acceptance or rejection of approved verifiable costs from five to three business days.

— Tom Kleckner