ERCOT’s Board of Directors last week approved market pricing corrections, but not the ones legislators, market participants and other stakeholders most want to see.

The board on Tuesday unanimously approved staff recommendation to reprice some market transactions stemming from a software error on Feb. 15, shortly after several waves of extreme winter weather caused days-long customer outages. (See Software Error Could Mean ERCOT Price Revisions.)

But the board did not address ERCOT’s decision not to exit energy emergency alert (EEA) conditions on Feb. 18-19, keeping wholesale prices at the $9,000/MWh systemwide price cap for 33 hours during the cold snap, even after the ISO had stopped shedding firm load following widespread outages.

ERCOT’s Independent Market Monitor said the action was a “billing error,” resulting in $5.1 billion in transactions and ancillary services’ costs that should be repriced. The Texas Senate last month passed a bill that would require repricing $4.2 billion in wholesale market transactions. (See Texas Senate Passes Bill to Reprice ERCOT Feb. Sales.)

Following an executive session that lasted more than five hours on April 13, board member Shannon McClendon, of Demand Control 2, withdrew her request to discuss ERCOT’s decision not to exit the EEA.

McClendon, recently elected to the board by the retail electric provider segment, said she would not “be the one to cause a perfect storm” with the grid operator again facing emergency conditions last week. (See ERCOT Faces Tight Conditions — Again.)

McClendon said that during the day-long session she and ERCOT General Counsel Chad Seely agreed to work together to determine whether the directors have the authority to order a Feb. 18-19 price correction.

“That will allow me an opportunity to present the jurisdiction that I believe the board does have,” McClendon said. “I’m not saying that he’s agreeing with me, but he’s willing to work through these items with me.”

Legal staff filed a memo before the meeting in anticipation of the agenda item, reiterating their position that the board lacks authority to direct the price correction in question. According to the grid operator’s protocols, ERCOT must first notify market participants of “a need for any price correction within 30 days of these operating days.”

Staff said examples of necessary real-time price corrections include any data input or output errors, hardware or software errors, or any “inconsistency” with the protocols or the Public Utility Commission’s rules. They offered other alternatives to resolve the matter, such as disputing the prices through an ERCOT process that has already drawn “numerous” settlement and billing disputes.

The PUC could also take up the issue or the Texas legislature could pass the Senate bill, staff said in the memo.

The software error led to a price correction because ERCOT did file a market notice after staff discovered that market management system programming errors resulted in incorrect megawatt amounts being used for the estimated deployed emergency response service (ERS) component of the real-time price adders for certain dispatch intervals on Feb. 15. The grid operator had already entered its highest level of energy emergency alert at that time, requiring prices at the $9,000/MWh cap.

The result was weather-sensitive (WS) ERS megawatts being included in the price-adder calculations for some SCED intervals when there was no WS ERS deployment obligations. Staff have since rerun the affected intervals to determine the correct prices.

The resettled prices amount to an additional $6.2 million in invoices due to ERCOT. The largest change to any single counterparty is more than $856,000 due to the ISO.

Short-pay Process in the Works

ERCOT Vice President of Commercial Operations Kenan Ögelman told the board that within 90 days the ISO will create a mechanism to recover the market’s short-pay amount and begin charging market participants. Allocations to market participants will be based on the month before their short pays occurred.

The ERCOT market was short $2.95 billion as of April 16, with the total varying as some market participants pay down balances and others continue to not pay invoices. ERCOT has begun entering into payment plans with some participants, Ögelman said.

The ISO must now determine how to allocate the default uplift, Ögelman said. Without any further short pays, it would take 80 years for the grid operator to recover the $2.95 billion total, given the ISO’s monthly uplift limit of $2.5 million, he said.

ERCOT outlined its proposal in a filing with the PUC. Market participants could always propose protocol revisions to change the cap or shorten the time between uplifts, Ögelman said.

The update was one of several by ERCOT executives.

Woody Rickerson, the ISO’s vice president of grid planning and operations, said that transmission and generation outages have increased significantly because of the lack of maintenance during the February storms and growth of the transmission system. The outages were partly blamed for the grid’s tight conditions last week.

ERCOT has responded to 31 questions as part of the FERC–NERC investigation of the February events in the Midwest, Chief Compliance Officer Betty Day said. Virtual site visits have been scheduled May 4 and May 7, giving staff an opportunity to present their perspective on the event, she said.

Staff is also drafting new reporting requirements for the amount of load each transmission service provider can effectively include in their rotating outages, among several other rule changes. They include new telemetry requirements for settlement-only distribution generators, increasing ERCOT’s transparency into the grid.

Board Delays Hiring Interim CEO

The board deferred an expected vote on an interim CEO following the executive session, saying it was still working on a solution to be released “relatively soon.”

ERCOT has since scheduled another board meeting for April 27.

The board fired Bill Magness as CEO in early March, allowing a 60-day transition period that expires after May 3. It does not expect to complete its search for a new CEO before then. (See ERCOT Board Cuts Ties with Magness.)

The interim CEO would serve for up to a year or when a full-time successor is named. The interim CEO could be re-elected to a second one-year term if a permanent candidate is not selected.

ERCOT must have a CEO to perform its statutory and corporate functions.

HR, Finance Chairs Elected

Directors Mark Carpenter and Nick Fehrenbach were elected as chairs of the Human Resources/Governance and Finance/Audit committees, respectively.

Carpenter, Oncor senior vice president of transmission and distribution operations, represents the investor-owned utility segment. He said the committee spent much of its April 12 meeting discussing the “unjust criticism” of staff and their pressures, frustrations and workload, and acknowledged “the vital work this ERCOT team does for all Texans.”

“This is a complex electric grid and a complex market,” Carpenter said. “Just like every other day, we badly need you to keep moving forward. We sincerely thank you for all you do and continue to do.”

Fehrenbach, the city of Dallas’ manager of regulatory affairs and utility franchising and the commercial consumer segment representative, said ERCOT’s annual financial audit is on hold in the aftermath of the February storms.

Members Pass 9 Change Measures

The board unanimously approved seven nodal protocol revision requests (NPRRs), a change to the Nodal Operating Guide (NOGRR), and another binding document revision request (OBDRR):

• • • NPRR1023: Establishes a process for liquidating a repossessed congestion revenue rights (CRR) portfolio by using financial security held by ERCOT for the defaulting CRR account holder for settlement purposes. The NPRR also modifies the process for forfeiture of CRRs resulting from the account holder’s non-payment or late payment of an invoice.
    • NPRR1045: Moves and revises the definition of transmission operator from the Nodal Operating Guide to the Protocols and adds a new section that clarifies the designation process and basic qualifications for TOs.
    • NPRR1057: Applies the hub LMP formulas to the Panhandle 345-kV hub and the Lower Rio Grande Valley 138/345-kV hub and eliminates portions of hub real-time settlement point prices formulas designed to address all buses within a hub being de-energized.
    • NPRR1059: Sends interval readings for non-interval data recorder meters, such as residential accounts with consumption under 700 kW, to settle on actual usage/generation instead of the load profile.
    • NPRR1065: Replaces a sentence describing a settlement-only generator’s (SOG) energy volumes subject to nodal versus zonal pricing with a formula; revises the name and definition of a related billing determinant to more accurately describe the data it represents; and adjusts the default uplift settlement to combine SOG generation with the counterparty’s other generation.
    • NPRR1066: Grants ERCOT the discretion to apply existing standards for grandfathered generation resources to an existing unit owned by a municipally owned utility or electric cooperative that is transferring load into ERCOT and seeks to interconnect the existing generation unit to the ISO’s system.
    • NPRR1069: Clarifies settlement billing determinants to ensure that an energy storage resource’s (ESR) capacity is not counted in the off-line reserve imbalance of the real-time ancillary service imbalance payment or charge.
    • NOGRR219: Removes the definition of transmission operator from the Nodal Operating Guide because it is being moved to the ERCOT Protocols by NPRR1045. This NOGRR also clarifies existing language relating to load shed obligations and removes the Load Shed Table from the Nodal Operating Guide. Instead, the Load Shed Table will be posted on the ERCOT website.
    • OBDRR028: Clarifies that ESR capacity will not be accounted for in the off-line portion of operating reserves.