Given the continued uncertainty of future in-person meetings, ERCOT stakeholders last week endorsed several bylaw amendments and rule changes to improve electronic meetings and votes.

As if to hammer the point home, the changes were among 15 voting items in an email vote that did not become official for two days. ERCOT rules currently require two full business days to allow stakeholders to return their votes.

Vickie Leady, ERCOT’s assistant general counsel, told the Technical Advisory Committee on Wednesday that the grid operator’s bylaws “never contemplated a situation with the scale and duration” in which stakeholders “could not safely convene together in one place.”

“It’s creating a risk to ERCOT,” Leady said.

ERCOT closed its facilities to most outside visitors and canceled in-person meetings in early March. Meetings have been conducted virtually ever since.

Legal staff proposed widening the definition of “urgent matters” to include when it would be “difficult or impossible” for a quorum of directors or subcommittee members to physically convene in one location. The changes would allow teleconference meetings and actions that, if otherwise delayed, “may result in operational (including, but not limited to those activities and functions affecting the ERCOT market or system), regulatory, legal, organizational or governance risk.”

Staff made other changes to the bylaws to closely align with the Texas Open Meetings Act and Texas Business Organizations Code’s teleconference technology methods.

The changes will now go before the Board of Directors during its June 9 teleconference. If approved, the board would issue a call on June 10 for a special meeting to vote on the bylaw changes by July 2. The changes would then be filed with the Texas Public Utility Commission by July 31 for its approval.

The TAC also approved several changes to its rules allowing for roll call votes. Chair Bob Helton, with ENGIE, said the committee would be using consent agendas to compensate for the extra time taken by email votes.

Corpus Christi Tx Project Gets OK

The TAC unanimously approved a $219 million transmission project, previously approved by the Regional Planning Group, that addresses more than 1 GW of future industrial load growth on the north shore of Corpus Christi Bay expected by 2024.

As recommended by staff following an independent review of AEP Texas’ proposal, the Corpus Christi North Shore RPG Project will comprise 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.

LNG plants account for more than half of the additional load. Cheniere Energy has developed an LNG export terminal in Corpus Christi’s harbor. Two trains are currently in operation, with a third planned to come online in the first half of 2021.

ERCOT’s review concluded that its recommended option does not cause new or additional congestion. Staff determined the 138-kV upgrade met economic planning criteria and added it to the project.

AEP’s Richard Ross said the company “supports and is comfortable at this point in time” with ERCOT’s recommendation.

ERS Payments up 1.6% to $48.2M

Staff shared ERCOT’s annual report on its emergency response service but received no questions from members. The report is required annually by the PUC (27706).

According to the report, demand response and behind-the-meter generation received $48.2 million in capacity payments during the program year for curtailing load or sending power to the grid, a 1.6% increase from the $47.5 million for the previous time period.

ERCOT deployed ERS twice last year during August’s two energy emergency alerts. The two deployments lasted a total of 95 minutes.

Members Disagree over Change to ERS’ Return

The TAC on Friday took up a second email vote to consider the only Nodal Protocol revision request (NPRR1006) that did not clear the email vote.

In a vote that closes at 5 p.m. Tuesday, committee members will weigh NPRR1006’s approval as amended by comments from Direct Energy.

The NPRR had received only four votes (Lower Colorado River Authority, South Texas Electric Cooperative, Exelon and Reliant Energy Retail Services), with 20 members opposing and two abstaining.

The change would return ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours. It also changes the process for annually updating the parameter by removing a real-time deployment price adder from the real-time ancillary service imbalance payment or charge.

Direct Energy expressed concern over the unintended consequences of the price adder’s elimination from the equation. The company urged interested parties to file their proposed changes in a separate NPRR “to facilitate the quick movement of the original intent of this NPRR through the approval process.”

Direct Energy’s Sandy Morris said stakeholders have not had the time or analysis to understand the full implications of the proposed change. Should the matter be separated, she wrote, “it could possibly continue through the proper channels of analysis and debate and still be implemented at the same time as … NPRR1006.”

The committee’s email vote unanimously approved eight other NPRRs, a change to the Nodal Operating Guide, an Other Binding Document revision request (OBDRR) and two system change requests (SCRs):

• NPRR933: adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the DR and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
• NPRR975: clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
• NPRR987: includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
• NPRR989: establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
• NPRR1018: clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
• NPRR1019: addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
• NPRR1021: shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
• NPRR1022: modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. The NPRR creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
• NOGRR204: together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (KTC-4) and establishes ESR technical requirements.
• OBDRR017: aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
• SCR807: increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
• SCR809: updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.