ERCOT’s Technical Advisory Committee last week conducted its first regular meeting since the February winter storm, with its aftereffects unsurprisingly dominating the discussion.

Liz Jones, vice president of regulatory affairs for Oncor Electric Delivery, addressed the committee regarding a recent ERCOT market notice alerting participants to an application for critical-load designation.

The notice is meant to allow gas facilities that provide fuel to generators to request designation as a “critical load-serving electric generation and cogeneration.”

Almost half of ERCOT’s natural gas-fired generation was lost during the February extreme weather because power was cut to gas infrastructure not listed as critical load. With compressor stations out of service and pipelines frozen, drilling companies had to burn off, or flare, so much gas flowing out of the ground that the flames could be seen from space.

Jones said the application, housed on ERCOT’s website but also linked from the Texas Railroad Commission’s website, is intended to identify the “entire natural gas supply chain.” The form also makes clear it does not guarantee an uninterrupted supply, she said.

“It asks for specific information about backup generation and restoration times,” Jones said. “This is a way that we will become better informed.”

The completed forms should be sent to the local transmission and distribution service providers responsible for the gas facilities.

Asked how the response has been, Jones said, “They haven’t come pouring in, but it’s early, yet. I’m hopeful that by providing it to industry trade organizations and the RRC letter, participation will increase.”

TAC also discussed its working list of potential solutions to the events preceding and following last month’s storms, which numbers more than 110 issues. Many of the issues are listed as awaiting legislative action or being long-term stakeholder items, but others are being parceled out to various subcommittees. (See “TAC Takes up Ideas for Solutions,” Texas PUC Won’t Reprice $16B Error.)

Reliant Energy Retail Services’ Bill Barnes urged his fellow members to be prepared to help policymakers as they consider legislation during the current session, which ends May 31.

“For the next two, two-and-a-half months, our priority will be waiting on the legislature,” he said. “I would encourage us to engage as much as possible, and prioritize those activities, to assist the legislature and work with the [Public Utility Commission]. We should assist where we can and be ready for efforts we’ll need to undertake in helping the commission and the legislature implement changes.”

Passport Program Faces Staffing Constraints

Staff said the Passport Program, which bundles several high-profile initiatives, remains on schedule despite staffing constraints from winter storm-related activities.

That has led ERCOT to evaluate staff resources for an upgrade to the energy management system (EMS) that will house the Passport’s programs, and its business requirements, said the ISO’s Matt Mereness.

“There’s some knowns and still some unknowns, given everything that’s going on,” Mereness said.

Passport’s 2021 objectives, which Mereness described as a “heavy lift,” include the EMS upgrade and developing and integrating the EMS, market management system (MMS), and settlements and billing business requirements. The MMS project began three months late, further squeezing available IT resources, but remains on schedule.

Passport is scheduled to be delivered in late 2024. It is comprised of implementing revision requests produced by the Real-Time Co-optimization (RTC) and Battery Energy Storage (BES) task forces along with the EMS upgrade. Passport will also integrate a 10-minute contingency reserve ancillary service product and improve distributed generation resources’ mapping.

Mereness put off a decision to sunset the RTC task force, but said staff wants to work with TAC leadership to develop a Passport implementation working group. TAC did sunset the BES task force.

Should the Passport’s work be delayed, Mereness said, a go/no-go decision point will be reached. “EMS would be put on its own path,” he said. “It can’t be delayed past 2024.”

The program has an $85.5 million budget, with $51.6 million allocated to the RTC effort and $27.1 million to the EMS upgrade.

$6.1M Price Correction

Staff also added further details to the recent software error that occurred after the February outages began, requiring a price correction by the Board of Directors. (See Software Error Could Mean ERCOT Price Revisions.)

Dave Maggio, ERCOT’s director of market design and analytics, said staff discovered that the MMS software contained programming errors that 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 $6.1 million in invoices due to ERCOT. The largest change to any single counterparty is more than $868,000 due to the ISO.

The price corrections are within the parameters for after-the-fact corrections. They will be taken to the board for its consideration during its scheduled April 13 meeting.

Demand Control 2’s Hendrix Joins TAC

The TAC welcomed Demand Control 2’s Chris Hendrix to the committee as an independent retail electric provider segment representative. He replaces Shannon McClendon, also with Demand Control 2, who recently took a seat on the Board of Directors as the retail sector’s representative.

Hendrix has previously served on New SPP Member Walmart Eyes ‘Everyday Low Costs’.)

Members Pass 11 Change Measures

Members approved a nodal protocol revision request (NPRR) and an other binding document revision request (OBDRR) related to emergency response service (ERS). Both measures were opposed by Morgan Stanley’s Clayton Greer, who has made a point of voting against anything related to ERS.

NPRR1060 makes a number of revisions pertaining to ERS, including: modifying and adding language related to ERS resource testing, sites that participate in more than one ERS resource, and availability determinations; simplifying the process for notifying ERCOT of planned maintenance and self-testing for ERS generators; clarifying metering requirements for ERS generators and the performance of co-located ERS generators; and addressing how ERCOT will treat ERS resources with missing meter data.

OBDRR027 clarifies OBDRR023’s implementation timeline to align ERS procurement methodology with previous Protocol changes. The latter change will be implemented over two separate dates: partial implementation that occurred Feb. 1 and the remaining language’s addition on Oct. 1.

The combination ballot, which included seven NPRRs, an OBDRR and a change to the Nodal Operating Guide (NOGRR), passed unanimously, 29-0:

• NPRR1023: establishes a process for liquidating a repossessed congestion revenue rights (CRR) portfolio through the use of 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 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 operating reserve’s off-line portion.