Governance Changes for TAC, Stakeholder Process Remain Unclear

ERCOT’s Board of Directors left the grid operator’s top stakeholder committee, the Technical Advisory Committee, in a bit of limbo this week as it continued to debate governance and stakeholder coordination.

The directors on Tuesday first deferred confirmation of the TAC’s leadership, normally a routine matter, until the board’s April 27-28 meeting. That meeting was rescheduled from April 12 and would have conflicted with a TAC meeting. However, the committee moved its April 27 meeting up to April 13 to help push an urgent protocol revision request through the stakeholder process.

The directors then approved the creation of a board-level meeting committee to oversee ERCOT’s core functions. As proposed by staff, the Reliability and Markets Committee would focus on markets, planning, reliability and resilience. The scope would also include information technology and project delivery.

Both actions followed an extensive executive session that began Monday and ended Tuesday.

TAC Chair Clif Lange, with South Texas Electric Cooperative, said the delayed vote on his confirmation caught him by surprise and wasn’t telegraphed by ERCOT staff. He said he only became aware of the board’s actions when he started receiving texts from TAC members Tuesday morning.

“We didn’t see that coming,” Lange told RTO Insider. “Nothing had been communicated to us.”

He said nothing in the meeting materials indicated to him that the TAC would answer directly to the board and said that further modifications to the committee could be in the offing.

The board, which has met with all 11 members just twice since December, has been vocal in its previous meetings about the time it takes protocol revisions to clear the stakeholder process. The TAC is responsible for vetting and endorsing protocol revisions that come up from the working groups, while market participants’ heavy involvement in ERCOT’s governance has drawn attention since the February 2021 winter storm.

The TAC, for its part, has discussed the potential changes to the stakeholder process several times in recent months. (See “TAC Members Look for Direction on Governance Structure, Stakeholder Process,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“I know we on the TAC are a little concerned that not engaging stakeholders and shutting them out will result in suboptimal products for ERCOT,” said Lange, who added that he plans to take his concerns to interim CEO Brad Jones.

ERCOT officials say the eight new independent board directors are grappling with their new responsibilities.

Chris Ekoh, interim CEO of the Office of Public Utility Counsel (OPUC) and the only non-independent voting board member, read a memo into the record that expressed his concerns for the stakeholder process and with the new board committee. He asked whether the TAC will be disbanded or made “subservient” to the new board committee.

“It is not clear to OPUC how the creation of the new Reliability and Markets Committee will impact or coexist with the current stakeholder process,” he said. “How will the proposed Reliability and Markets Committee interact with TAC? How does the committee and TAC work together, if at all? How does it impact the protocol revision process?”

Ekoh also asked whether there were compliance concerns for ERCOT if the revision process is modified.

“Those are questions everybody has about how TAC is going to interact with the board,” Lange said.

There was no public discussion of Ekoh’s comments among the board members.

Upward Pressure on Admin Fee

CFO Sean Taylor told the directors that ERCOT’s costs are projected to continue to grow at a rate faster than shown in its current 2022-2023 budget, which was approved last year. He said additional demands placed on staff as a result of last year’s winter storm include new regulatory requirements, protocol and planning revisions, and increased IT support costs for new or improved services that were not expected.

“There is upward pressure on the 2023 budgeted system administration fee rate,” Taylor said. “That fee will not be as adequate as previously thought.”

ERCOT has maintained a system admin fee of 55.5 cents/MWh since 2016. It had projected increasing the fee to 66.5 cents/MWh in the 2024-2025 budget.

Staff reported a preliminary negative net variance of $25.5 million for 2021, with system admin fees coming in $10.9 million under expectations because of less energy sold. The grid operator had projected 413.1 TWh of energy sales in 2021, only to see 393.3 TWh of energy sold.

Expenditures were $14.4 million overbudget, primarily because of outside legal services, hardware and software support and maintenance, higher insurance premiums, and professional consulting.

ERCOT has operated with a biennial budget since 2014, at the Public Utility Commission’s request. Its filed budget includes four additional years of forecasted numbers.

Board Approves Firm Fuel Product

The board approved three revision requests that cleared the TAC with dissenting votes, including a nodal protocol revision request (NPRR1120) that creates a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather. The NPRR also compensates generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption.

The PUC has directed that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.

• • • OBDRR039: removes FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation.
    • PGRR095: establishes minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.

The directors also approved eight additional NPRRs, a Nodal Operating Guide revision (NOGRR), three more OBDRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and three system change requests (SCRs).

• • • NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
    • NPRR1097: creates reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
    • NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
    • NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
    • NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
    • NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
    • NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
    • NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
    • NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
    • OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
    • OBDRR037: caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
    • OBDRR038: updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
    • PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
    • RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
    • SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
    • SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
    • SCR819: improves dispatch of base points to resources to account for ramping un-curtailed IRRs.