AUSTIN, Texas — ERCOT staff last week told the Technical Advisory Committee that they will be reviewing and improving their market pricing processes as they bring price-correction issues to the Board of Directors in December.

ERCOT will be asking the board for permission to correct real-time and day-ahead prices for three weeks’ worth of operating days, accumulated following several software issues that led to pricing errors over three different time periods. Staff can revise pricing errors if they are caught within two business days of the operating day but must otherwise go to the board to correct the mistakes.

Kenan Ögelman, ERCOT’s vice president of commercial operations, told the committee during its meeting Wednesday that the grid operator is intent on improving the quality and delivery of its services.

“I don’t find these kinds of [market] outcomes acceptable relative to the disruption it causes,” he said. “We really want to go through our processes and … review our end of it.”

The pricing errors have resulted in resettled amounts as large as $123,000 and as small as $4, according to ERCOT’s preliminary data.

“I don’t know what ‘significant’ is, but I think I know what it isn’t,” said Morgan Stanley’s Clayton Greer, jerking his thumb at a slide filled with double-figured numbers.

Ögelman agreed with Greer. He said he would propose to the board that staff “look at making some cuts on significance” and see what the directors say.

“We have to do this work anyway to determine what the magnitude is,” he said. “There might have to be some better definitions.”

Staff told the TAC in October it would be taking the Sept. 16-23 day-ahead operating days’ prices to the board for its review after mistakes in modeling outages. ERCOT then issued a market notice on Oct. 24, saying that an update to the energy and market management system led to incorrect real-time prices for certain settlement points and energy-metered prices, requiring another board review for the Oct. 16-20 operating days. (See “ERCOT Likely to Reprice 13 Operating Days,” ERCOT Technical Advisory Committee Briefs: Oct. 23, 2019.)

In November, staff added another eight days to the pricing review when software intended to capture the list of electrical buses that are fully disconnected from the grid under a contingency incorrectly included additional buses between Oct. 22 and Nov. 6.

ERCOT has said it will begin resettling prices about a week after the Dec. 10 board meeting.

Staff, Stakeholders to Study Summer Issues

Ögelman and committee members divvied up a list of issues for further discussion following another summer of slim reserve margins and record demand.

“There are legitimate needs to discuss a lot of these items,” Ögelman said, imploring the TAC to help make the assignments.

Most of the issues will be taken up by the committee’s Reliability and Operations and Wholesale Market subcommittees. Topping the list was the use of switchable generation resources (SWGRs), units that participate in both ERCOT and its RTO neighbors and which Ögelman said are not “working exactly as intended.”

The subcommittees will ensure the SWGRs’ settlement, operator interactions and offers align with the Protocols and intended market design. The two subcommittees will also look at the use of emergency response service and whether it can be self-deployed.

“Would ERCOT be willing to put in the Protocols that self-deployment is allowed for these resources?” Reliant Energy Retail Services’ Bill Barnes asked. “If this is behavior you want to allow, maybe it should be in the Protocols.”

Calling it a “fair question,” Ögelman said he owed stakeholders an answer.

Other issues include:

• the use of operating condition notices;
• evaluation of the Texas Commission on Environmental Quality’s enforcement-discretion process;
• the summer demand response process; and
• continued improvement of gas-electric coordination.

Comptroller to Waive QSEs’ Resale Cert Obligation

ERCOT legal staff shared with the TAC a letter from the Texas Comptroller of Public Accounts that General Counsel Chad Seely said backed up his argument that electricity is tangible personal property and that qualified scheduling entities (QSEs) are required to provide resale certificates to the grid operator.

Teresa Bostick, the director of the comptroller’s tax policy division, said that under current law and policy, the QSEs are required to provide a valid resale certificate to ERCOT. However, she also noted that because “QSEs have no use for the electricity themselves and must sell it to another entity,” she would waive the requirement.

Seely said in an email to the committee that staff will work with the comptroller’s office to amend the Tax Administration Code and exempt QSEs from the certificate requirement. He thanked members for their feedback and “interest in this topic,” which resulted in vigorous stakeholder pushback during the TAC’s October meeting. (See “Stakeholders Push Back on Sales Tax Certifications,” ERCOT Technical Advisory Committee Briefs: Oct. 23, 2019.)

Senior Corporate Counsel Erika Kane, who bore the brunt of October’s heat, good naturedly accepted apologies from several TAC members.

“I feel I may have been a little harsh on you,” Barnes said, echoing others’ comments.

Staff also told members they are not proposing any changes to the methodologies, which rely on historic data, used to determine ancillary service quantities for 2020. Based on feedback from stakeholders, the ERCOT will compute responsive reserve service quantities with an updated resource contingency criteria of 2,805 MW.

TAC Endorses Storage, RTC Principles

The TAC unanimously endorsed the Battery Energy Storage Task Force’s first key topic/concept (KTC) recommendations as the principles that will be used in writing Nodal Protocol revision requests (NPRRs).

The task force reached consensus on all five KTCs. The documents recommend energy storage resources (ESRs) be treated like other short lead-time resources and security-constrained economic dispatched resources using nodal shift-factors and settled using nodal pricing when charging and discharging. The task force also determined the reliability unit commitment engine should evaluate ESRs based on the values in their current operating plans, reflecting their available capacity.

• KTC 2: Physical responsive capability and operating reserve demand curve reserve.
• KTC 3: ESR dispatch, pricing and mitigation.
• KTC 4: Technical requirements.
• KTC 6: ESR options to maintain desired level of state of charge.
• KTC 10: ESR study and capacity assumptions changes.

Beth Garza, director of ERCOT’s Independent Market Monitor, waved off stakeholder concerns that KTC 6, which allows ESRs to submit energy offer curves immediately prior to the operating hour’s start, would lead to potential gaming.

“Personally, I’m willing to accommodate the widest range of behavior we can accommodate,” she said. “Battery owners shouldn’t expect free rein forever. We’ll be looking at their behavior in the first years. If there are problems, we will need to address them.”

The TAC also endorsed 11 additional key principle (KP) documents that will guide ERCOT’s real-time co-optimization (RTC) design. The committee will hear the Real-Time Co-optimization Task Force’s final group of principles during its January meeting:

• KP 1.3 (8)c, (9), (12), (13): Outlines the key mechanisms and timelines for submitted ancillary service (AS) offers and the AS considered and awarded under RTC.
• KP 2 (1)-(6): Analyzes any changes to RTC’s suite of AS products.
• KP 5 (7): Identifies the AS virtual offers in the day-ahead market changes necessary to align their procurement with RTC’s implementation.

Members Approve Rio Grande Valley Hub

The committee approved the creation of a 138/345-kV trading hub for the Lower Rio Grande Valley that will allow additional trading liquidity and forward-price discovery in the area.

Staff and stakeholders’ review of NPRR941 indicated that it does not require changes to credit-monitoring activity. The NPRR’s cost ($250,000 to $350,000) is related to removing constraints that exist in the original system design.

Staff said work on the hub is not likely to go live until mid-2021.

The committee also approved three additional NPRRs and single revisions to the Planning Guide (PGRR), Retail Market Guide (RMGRR) and Verifiable Cost Manual (VCMRR).

• NPRR928: Defines “cybersecurity incident” and “cybersecurity contact,” classifying the former as protected information, and creates a form for notifying ERCOT of a cyber incident. The change also allows ERCOT to notify state or federal law enforcement of a cybersecurity incident and to notify market participants in order to mitigate further effects.
• NPRR957: Establishes the terms “energy storage system” (ESS) and “energy storage resource” (ESR). ESS is the umbrella term for storage assets. ESRs are ESSes eligible to participate in SCED and/or provide AS. ESRs must be registered with ERCOT as both a generation resource and a controllable load resource.
• NPRR972: Gives ERCOT the authority to decline to open a transaction-adjustment period for a congestion revenue right auction, even if the transactions submitted exceed the limit announced prior to the auction, as long as the number of transactions submitted does not exceed the number that can be processed by ERCOT’s systems.
• PGRR071: Updates the Planning Guide to align with NPRR926, which removed the 90-day period between subsynchronous resonance study approval and initial synchronization and was approved by the board in June.
• RMGRR162: Clarifies the purpose and appropriate use of the safety-net move-in process for competitive retailers and revises the timing for submitting such a request.
• VCMRR025: Removes the ESR definition from the manual, aligning it with NPRR957.

— Tom Kleckner