Stakeholders, Staff Try for Consensus on Gen Outage Approvals

ERCOT stakeholders and staff are continuing to hash out their differences and reach a consensus over the grid operator’s methodology for approving and denying planned generation maintenance outages.

Staff said they will review comments from stakeholders on the maximum daily resource planned outage capacity (MDRPOC) calculation, the key feature in ERCOT’s plan to evaluate outage requests. They plan to bring the revised methodology to the Board of Directors for its approval during its June 21 meeting.

In the meantime, staff agreed to hold a workshop on the MDRPOC calculation and to give the Technical Advisory Committee a chance to consolidate the three sets of comments generation members provided. They have said ERCOT’s goal is to allow as much capacity and flexibility as possible for planned outages while maintaining reliability.

The complex calculation takes installed thermal resources’ seasonal capacity, installed intermittent renewable resources’ capacity and other available capacity, and adds them together. It then subtracts from that targeted reserve capacity, forecasted reduction from price-responsive demand and other inputs.

Staff said using planned outages from last year, the highest since 2019, the proposed methodology’s calculated maximum outage capacity provides at least 20% additional margin for through 2026. They said the MDRPOC would require some outages to be moved earlier in the spring and later in the fall.

Woody Rickerson, ERCOT vice president of system planning and weatherization, said staff compared the calculation with what has been used in the past as an aggregate for the fleet and found the new methodology allows 10 to 15% more outages.

“I think that the methodology is such that there are some places that can be adjusted,” he said. “If we started having a number of planned outages that can’t be fit, then we can look at some of these dials.”

Staff have agreed to stakeholders’ request to regularly review the methodology and provide annual updates to TAC. They offered to track the number of outages denied for being over the MDRPOC but said it would be too time-consuming to post inputs used to calculate the cap, noting that the process will be automated.

“For any given point in time, we could do ad hoc reports,” Rickerson said. “Setting up something that shows every hour for five years is a bigger project and takes more time. This whole process is meant to be adjusted.”

The board in April granted staff’s appeal of a revised nodal protocol revision request (NPRR1108) that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages. Stakeholders earlier rejected staff’s version of the measure, unanimously approving an NPRR as amended by several joint commentators. (See ERCOT Board of Directors Briefs: April 28, 2022.)

Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that led to the near collapse of the Texas Interconnection. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”

ERCOT’s Credit Limits Align with Others

ERCOT staff told the committee that the grid operator’s unsecured credit limits process aligns with those of the six other U.S. grid operators. They limit counterparties to a $50 million cap in unsecured credit, as does ERCOT, with the total amount of outstanding unsecured credit ranging from approximately $100 million to $1.75 billion. ERCOT currently has about $1.4 billion in outstanding unsecured credit.

The ERCOT board requested the information after tabling NPRR1112 in April. The revision request lowers the unsecured credit limits to $30 million and was approved by TAC in April over staff’s objections. ERCOT then appealed the decision to the board.

Director John Swainson said during the April meeting that TAC’s argument “should raise a level of doubt in the board about the wisdom of proceeding” with the approach.

“We’re not going there to propose anything other than providing information they wanted,” ERCOT’s Mark Ruane said. “If the board feels it’s appropriate, we are certainly at any time willing to discuss looking at the credit rules as they currently stand.”

A 2013 decision by the Commodity Futures Trading Commission exempted grid operators from some legislative provisions. It disallowed the use of unsecured credit to cover credit exposure from financial transmission rights and reduced caps on unsecured credit limits to no more than $50 million per counterparty.

TAC Vice Chair Bob Helton, with Engie North America, said he will work with ERCOT staff to ensure the committee has an advocate for its position when the issue comes up again before the board.

Members to Work on Board Relationship

TAC’s leadership is working with ERCOT staff to set up a work session, tentatively scheduled for June 14, to consolidate around new processes for interacting with the grid operator’s new board.

Helton said he and Chair Clif Lange, who was absent from the TAC meeting, have had several discussions with the new board members that he termed “very positive.”

“It was apparent that the board was trying to indicate they completely see the need for the stakeholder process and TAC, and that they want to take full advantage as they can … of the talent and the knowledge of the stakeholder process and TAC,” Helton said. “We felt really pretty good about that coming out of” the meetings.

He said there is no plan to have the committee report to the board’s new Reliability and Markets committee, but that TAC will need to decide how it communicates with both the full board and the new committee. TAC members also plan to review the appeals process at the board and develop a way to consider revision requests requested by the Public Utility Commission on a separate track, Helton said.

The board wants TAC to comprise members that “have the ability to make the decisions and move things forward,” he said, “rather than having to take things back to their company all the time.”

“You don’t need to be an officer of the company,” Helton said, referring to an issue first raised last summer. (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)

Helton and Lange plan to take the work session’s results back to the full TAC for its June 29 meeting. They face a July 11 deadline to get their information back to the board.

$1.2M to be Uplifted to Market

Staff told the committee that more than $1.2 million in nonemergency short pays from the 2021 winter storm won’t be covered by securitization and will have to be recovered by an uplift to the market. ERCOT was to begin invoicing the funds on Friday and will begin distributing the funds to short-paid entities during the next several weeks.

Retailer Entrust Energy, which went into bankruptcy last year, owes the bulk of the $1.2 million.

ERCOT issued a market notice May 20 with the estimated cumulative aggregate short-paid amount at $2.3 billion. Much of that is owed by Brazos Electric Power Cooperative, currently in bankruptcy proceedings over the nearly $1.9 billion it owes the market.

TAC Honors Uvalde Shooting Victims

Helton asked for a moment of silence for those who died in the mass shooting the day before the meeting in Uvalde, only 160 miles away from ERCOT’s Austin headquarters.

“We live in a cruel world, an unsafe world, an unforgiving world,” he said. “I can’t imagine as a parent going through that … having to go through the tragedy of the loss of a child.”

Disconnected Load Still to be Served

The committee unanimously approved NPRR1100, which clarifies that a generation or energy storage resource (ESR) may serve customer load when the customer and the resource are both disconnected from the system because of a transmission or distribution outage. It is limited to configurations where the resource and customer load are using privately owned transmission and distribution infrastructure during a private microgrid island operation. The NPRR recharacterizes the load from wholesale storage (WSL) to non-WSL on an operating day basis as necessary to ensure the ESR load not eligible for WSL treatment is not provided WSL treatment.

The measure was voted on separately from the combination ballot, which also passed unanimously. The combo ballot included five other NPRRs and single changes to the Nodal Operating Guide revision (NOGRR) and the Planning Guide (PGRR):

• • NPRR1110: modifies the black start service (BSS) confidential information, contract period and backup fuel requirements; increases the BSS procurement period from two to four years; and adds an on-site 72-hour priority fuel requirement that can be waived in whole or in part to procure a sufficient number or preferred combination of resources.
  • NPRR1119: deletes extraneous protocol language that should have been removed as part of NPRR978.
  • NPRR1121: automates the market notice used in the exceptional fuel cost submission process to notify market participants when the costs have been submitted for the operating day.
  • NPRR1129: allows ERCOT to post on its website a list of electric service identifiers for transmission-voltage customer opt-outs from the securitization of $2.1 billion for load-serving entities’ extraordinary costs incurred during the 2021 winter storm.
  • NPRR1130: extends the sunset date for weatherization inspection fees from Sept. 1, 2022, to July 31, 2023.
  • NOGRR240: establishes frequency and voltage ride-through requirements for new DC ties interconnecting with ERCOT after Jan. 1, 2021, and the ties that will be modified.
  • PGRR100: revises the annual planning model base case update frequency from triannual to biannual, aligning it with the Steady-State Working Group’s plan to adjust its current case-building schedule to a biannual basis.

The ballot’s passage also approved the Large Flexible Load Task Force’s charter and leadership. Bill Blevins, ERCOT director of grid coordination, will chair the group, and consultant Bob Wittmeyer, who primarily represents municipalities and cooperatives, will serve as vice chair.

The task force is developing policy recommendations for integrating large flexible loads into the ERCOT system. It met May 24 to discuss interconnection issues and divvy up work assignments.