ERCOT Technical Advisory Committee Briefs: July 29, 2020

Members Endorse Slew of Protocol Changes

Aug 2, 2020

ERCOT’s Technical Advisory Committee approved a standard contract term for emergency response service and some energy storage to use internal sensors.

ERCOT’s Technical Advisory Committee continues to refine its virtual voting practices, reverting to a combined ballot to reduce the number of roll-call votes and make the best use of members’ time.

Last week, that resulted in the unanimous approval of a ballot loaded with 23 revision requests, two key topics/concepts from the Battery Energy Storage Task Force (BESTF) and seven other items.

Only two nodal protocol revision requests (NPRRs) were voted on separately during TAC’s July 29 meeting. Both were easily endorsed. NPRR984 adds a fourth standard contract term per year for emergency response service (ERS), and NPRR1020 allows energy storage resources with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.

ERCOT granted the latter change urgent status because it affects ongoing interconnections. The revision will be sent to the Board of Directors for its Aug. 11 meeting.

Staff added clarifying comments to NPRR1020 for the required annual audit of the congestion revenue rights’ (CRR) allocation methodology by the resource entity calculating its ESR’s auxiliary load value. They said their revisions “simply require the audit to confirm that the resource entity’s calculation of auxiliary load ‘does not understate the load value,’ rather than specifying a band of allowable measurement error.”

ERCOT has estimated it will cost between $175,000 and $225,000 to make the change. Staff said resource limitations on software developers will delay work on the change until early next year. System implementation would also require revisions to the settlement metering operating guide.

NPRR1020’s sponsor, Tesla, said the urgent status will help it “achieve regulatory certainty and allow its investments to move forward.”

“I think we’ve got Tesla a level playing field with everyone else,” said Bob Wittmeyer, who represented energy-storage developer Broad Reach Power during the early stages of the revision request’s progress through the stakeholder process.

The measure passed without an opposing vote. EDF Trading North America abstained.

TAC endorsed NPRR984 28-1, with independent power marketer Morgan Stanley voting against the motion. Morgan Stanley representative Clayton Greer also indicated he would vote against tabling the change or moving it to the combination ballot, forcing the roll-call vote.

“I’ll vote no on everything with ERS,” he said.

ERCOT said changing the ERS standard contract terms would allow it to better align with typical seasonal conditions and help improve the service’s procurement.

Members, Staff Debate RR Development Budget

TAC approved two key topics/concepts (KTCs) from the BESTF, an initiative to address how to integrate ESRs into the ERCOT system.

Staff first had to allay stakeholder concerns that ERCOT is running out of time and money to incorporate the task force’s work, along with that of the Real-Time Co-optimization Task Force and other projects.

The Advanced Power Alliance’s Walter Reid called for the BESTF and distributed generation to be placed at the top of the ISO’s priority list of development projects

“The work the BEST Force has been doing to get batteries into the protocols needs to be finished,” he said. “We need to facilitate that [investment] … For DG, getting that done is critical.”

ERCOT currently allocates $4 million from its capital project budget to fund revision requests’ development. It has the flexibility to “exceed the target for priority needs,” spokesperson Leslie Sopko said in an email.

“We really do need to consider if there’s some way to relax that $4 million [limit],” Reid said.

Kenan Ögelman, the grid operator’s vice president of commercial operations, cautioned stakeholders against increasing the $4 million allocation.

“Expanding that doesn’t necessarily get [Reid] the relief he wants. The limits … are also resource limits,” Ögelman said. “You also have to look at expanding a budget in this environment of low interest rates and economic uncertainty. The only two options are to move dollars from elsewhere into the $4 million or expand the budget. I think you are at risk of moving dollars out of things ERCOT is doing behind the scene to deliver DG and BEST.”

Staff promised a prioritized list of projects on Aug. 3, with a follow-up discussion during a Protocol Revision Subcommittee meeting on Aug. 13.

The two endorsed KTCs are:

KTC 15-7: Restricts ESRs from withdrawing energy during a Level 3 energy emergency alert and addresses ancillary service responsibility compliance related to the charging suspensions.
KTC 15-8: Grandfathers NPRR989 ‘s reactive power requirements.

ERCOT Updates Price-correction Issue

Dave Maggio, ERCOT’s director of market design and analytics, told the committee staff expects to complete in two weeks a review of day-ahead and real-time market prices following the discovery of erroneous dynamic ratings for three 345/138-kV transformers.

Ratings from unrelated transformers were applied to the three transformers, possibly causing or missing congestion, on operating days between Feb. 12 and July 7, he said. Staff developed a software fix to resolve the issue on July 14.

ERCOT was able to issue a price correction for affected July 7 day-ahead prices. Should staff discover a need for price corrections during the historical period, which is outside the normal 30-day notification period, they will ask the Board of Directors to approve corrections, Maggio said.

Maggio said staff also discovered in May that a software glitch prevented the operating reserve demand curve (ORDC) from properly calculating certain resources’ capacity. Staff corrected the error with a software patch and conducted a detailed review of the ORDC calculations back to when it went live in 2014. They found no additional errors, Maggio said.

ERCOT staff is proposing a revision request to remove requirements that modify DC-tie load zones requiring board approval and a 48-month waiting period after approval. The issue stems from American Electric Power’s recent retirement of a DC tie near the Mexican border in South Texas.

“I think the majority of sensitivity around changes to typical load zone boundaries is because entities serving load to those areas potentially have long-term contracts,” said Reliant Energy Retail Services’ Bill Barnes. “There’s no load served there. It’s just used for export and import [of energy].”

TAC OKs Consent Agenda’s 23 Changes

TAC added NPRR1030 to the combination ballot after agreeing on a desktop edit provided by Greer. Or, as one member jokingly surmised, language provided by a ghostwriter.

“I had some help,” Greer acknowledged.

The measure changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to load ratio share based on adjusted metered load totals for each month. It also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and ease of implementation.

Greer offered language that provided market participants will not engage in DC tie export transactions “that are reasonably expected to be uneconomic in consideration of all costs and revenues associated with the transaction.” The language excludes CRR auction revenue distribution and CRR balancing account allocations.

By making clear such transactions would violate the Protocols, TAC was able to agree on accepting ERCOT’s comments, whose complexity extended to the measure’s implementation timeline from an estimated three months to 12 months. Staff corrected and clarified settlement formulas and corresponding variable definitions.

The edits will be temporarily “grey boxed” and eliminated with NPRR1030’s implementation.

The combination ballot included seven other NPRRs, a Load Profiling Guide revision (LPGRR), four changes to the Nodal Operating Guide (NOGRRs), four other binding document revisions (OBDRRs), a pair of changes to the Planning Guide (PGRRs), three revisions to the resource registration glossary (RRGRR) and one change to the verifiable cost manual (VCMRR).

It also included committee and subcommittee goals, a list of other binding documents and the 2021 meeting calendar. TAC will continue holding monthly meetings on the fourth Wednesday of the month to avoid conflicts with the Texas Public Utility Commission open meetings.

NPRR9 96: Aligns the Protocols’ hub bus names with the substation names within the ERCOT model.
NPRR 1000: Removes the term “dynamically scheduled resource” from the Protocols.
NPRR 1002: Establishes energy storage resource “single model” registration and charging restrictions during emergency conditions.
NPRR 1003: Replaces all remaining references to the resource asset registration form (RARF) with more general language in anticipation of the RARF’s elimination.
NPRR 1004: Creates a new process for determining the congestion revenue rights (CRR) auctions and day-ahead market clearing load-distribution factors by using load forecasting models and existing validation/error correction.
NPRR10 15: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service (RRS) and add ERCOT contingency reserve service.
NPRR10 16: Clarifies important reliability requirements for distribution generation resources (DGRs) seeking qualification to provide ancillary service(s) and/or participation in security-constrained economic dispatch.
LPG RR 067: Streamlines the assignment of oil and gas profiles by eliminating current processes that are no longer applicable. The revision validates weather sensitivity only for non-interval data recorder electric service identifiers that request the oil and gas flat profile; removes the “TOU Schedules” and “Non-ERCOT Profile IDs” worksheets; and changes the distributed generation profile segment assignment process.
NOGRR 195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
NOGRR20 8: Aligns the Nodal Operating Guide with the nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the Protocols.
NOGRR20 9: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
NOGRR 2 1 2: Aligns the Guide with NPRR1016’s revisions and clarifies DGRs’ reliability requirements.
OBDRR 0 18: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
OBDRR 0 19: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’ change control process with similar other binding documents.
OBDRR 0 21: Aligns the language in the calculation of RRS limits’ procedures for individual resources with the Protocols following NPRR863’s Phase 1 implementation. Also corrects inadvertent errors in the formulas for calculating droop performance to determine RRS limits.
OBDRR 022: Incorporates minor edits to the initial other binding document previously approved in conjunction with NPRR933.
PGRR07 6: Changes the generation resource interconnection or change request (GINR) process to specify that the proposed commercial operations date in the initial GINR application must be at least 15 months after the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
PGRR07 9: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
RR GRR023: Establishes the guide’s provisions and requirements for ESRs identical to those already in place for generation resources and settlement-only generators.
RRGRR02 4: Aligns the glossary with NPRR 1003’s changes by replacing all remaining references to the RARF.
RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
VCMRR 0 2 9: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.