The ERCOT Board of Directors signed off on staff’s recommendation to move forward with executing a reliability-must-run (RMR) contract for CPS Energy’s Braunig Unit 3 while deferring a decision on the gas plant’s other two smaller units until February or later. 

ERCOT General Counsel Chad Seely told directors Dec. 3 that deferring a decision on the other two units will give staff time to continue negotiations with CPS, CenterPoint Energy and Life Cycle Power over moving 15 large generators and their 480 MW of capacity from Houston to distribution sites in the San Antonio area. CenterPoint leased the generators from Life Cycle for $800 million in 2021, but the large units sat idle during July’s Hurricane Beryl and drew heavy criticism from Houston residents and Texas politicians. (See ERCOT to Recommend RMR Agreement for Braunig.) 

“We do believe it is a better reliable solution for the risk that we’re trying to address for the next couple of years until the transmission solutions come into play,” Seely said. 

ERCOT is exploring the generators’ use because Braunig Units 1 and 2 are smaller (217-MW and 175-MW summer max ratings, respectively) and are susceptible to forced outages. Staff said the mobile generators, with shorter ramp times than the gas units, are more flexible and “likely to be more reliable.” 

Staff expect to move forward in mid-December with a request for must-run alternatives (MRAs) to the mobile generation to better understand the market’s appetite for the solution. A previous solicitation for MRAs drew a single response from a 200-MW multi-hour energy storage resource. 

“We want to be fair to the market and see if there’s anything that could compete against the mobile gen,” Seely said. He said ERCOT then would move forward with a recommendation to the board in February or a special meeting soon thereafter. 

ERCOT said the two-year RMR costs will be lower than the value of projected systemwide load shed should the units retire, with Braunig 3 providing the best value. It has a budgeted cost of $76,888/MW for the two years, compared to $113,920/MW and $151,012/MW for Units 1 and 2, respectively. 

CPS told ERCOT earlier in 2024 that it planned to retire the three Braunig units, which date back to the 1960s, in March 2025. However, ERCOT said the resources, with a combined summer seasonal net maximum sustainable rating of 859 MW, were necessary to mitigate the risk of systemwide load shed for the next two years. (See ERCOT, CPS Energy Negotiating RMR, MRA Options for Retiring Units.) 

ERCOT expects the RMR contract for Braunig Unit 3, its first since 2016, to be effective until June 2027, when a new transmission line to the South is completed. 

“Once that line is completed, then the need is no longer there for the RMR unit,” ERCOT COO Woody Rickerson told directors. 

ERCOT Prepared for Winter

Noting that 2024 is likely to be the warmest year on record for the planet, ERCOT’s Chris Coleman, supervisor of operational forecasting, said weather conditions still could lead to extreme cold in January or February. 

“We’re in a pattern now where, when we get a warm, mild winter, more times than not, we’re seeing a cold extreme. … We’re in a pattern now that supports something like a [Winter Storm] Uri,” Coleman told the board, referring to the February 2021 winter storm that almost brought down the ERCOT grid and killed hundreds of Texans. 

Coleman said ocean and atmospheric conditions are very similar to those that preceded the 2021 storm. Five of the past eight winters have brought extreme cold to Texas, including the warmest winter (2016/17), the sixth-warmest (2022/23) and the 11th-warmest (2023/24). 

“The more I look at this winter, the more cold potential I see,” Coleman said. “This is like a tornado watch. Doesn’t mean a tornado is going to happen. It means conditions are there.” 

ERCOT CEO Pablo Vegas said the grid operator’s analysis has indicated a “slightly higher” reliability risk probability from last winter, driven largely by increased load on the system and reduced support from solar resources, which were valuable in meeting demand this summer. 

The grid operator set a new winter peak of 78.35 GW last winter but has added more than 10 GW of capacity since then. Solar resources accounted for 5,155 MW and battery storage 3,693 MW, with natural gas adding 724 MW. 

Vegas pointed to ERCOT’s weatherization program as “one of the most statistically significant changes … that has markedly changed the risk profile of the ERCOT grid.” He said staff have conducted 2,892 inspections of generators and transmission facilities since Uri, with two-thirds of the inspections taking place within the generation fleet. 

“This has more than exceeded what the [Public Utility Commission’s] requirements for the inspections on the cyclical basis have been,” Vegas said. “We think it’s important to stay ahead of this because of the really high impact the weatherization program does have on the reliability of the fleet.” 

Misc. Approvals

Two transmission projects, a price correction and a protocol change, previously endorsed by the Technical Advisory Committee, all cleared the board with little discussion: 

• • The $202.2 million Oncor Delaware Basin Stages 3 and 4 Project came out of the 2019 Delaware Basin Load Integration Study and addresses reliability issues in West Texas. The project includes upgrading an existing capacitor station, building 22 miles of double-circuit 345-kV lines and 41 miles of 138-kV lines, and converting 41 miles of 138-kV lines to 345 kV. It is expected to be completed in 2027. 

• • American Electric Power’s Brownsville Area Improvements Transmission Project, a $423.8 million initiative addresses thermal overloads on 106 miles of 138-kV facilities in the Rio Grande Valley with either new or upgraded infrastructure. The project has a May 2029 in-service date. 

• • A price correction was issued for the Nov. 1 operating day after several real-time intervals were “significantly affected” by an incomplete weekly database load update. The largest dollar impact to any counterparty was about $2,758, above the criteria for a price correction. 

• • A Nodal Protocol revision request (NPRR1247) requires ERCOT to use a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. Generators and marketers opposed to the NPRR cited a lack of transparency and control over the methodology for incorporating “fictitious generation” to solve power flow issues with the projected load growth. 

TAC Membership Approved

Twenty-seven incumbents will return to TAC in 2025 following the board’s approval of its 30-member slate of representatives. 

Oncor’s Martha Henson replaces colleague Collin Martin in the Investor-Owned Utility segment; Vitol’s Seth Cochran, a previous TAC member, replaces National Grid Renewables’ Matthew Morais in the Independent Power Marketer’s segment; and Brazos Electric Cooperative’s Kyle Minnix replaces Pedernales Electric Cooperative’s Eric Blakey, a longtime representative in the Cooperative segment. 

Jupiter Power’s Caitlin Smith plans to return as TAC’s chair, and Henson is expected to replace Martin as vice chair. The committee’s leadership elections and those of its subcommittees will be held before its Jan. 22 meeting. 

ERCOT’s Day to Retire

The board meeting was the last for Betty Day, ERCOT’s chief compliance officer, who is retiring after 24 years with the grid operator and more than 30 in the industry. 

Vegas credited Day with being critical to the development of the zonal and nodal markets, and for integrating cyber, physical and emergency management and maturing the security function. 

“The time I’ve spent here at ERCOT has been the highlight of my career,” Day said after recognition from Vegas and board Chair Bill Flores. “The people have been amazing, both within the organization and with stakeholders, board members and countless people. I can’t even begin to name them all.” 

The directors also welcomed Ben Barkley to the board as the newly appointed CEO of the Texas Office of Public Utility Counsel. Gov. Greg Abbott appointed Barkley as CEO on Dec. 2, making him eligible for OPUC’s board seat. He previously was assistant general counsel for the Office of the Governor. 

ESR Revision Back to TAC

Directors remanded back to TAC a protocol change (NPRR1246) and related changes to the Nodal Operating Guide (NOGRR268), Other Binding Documents (OBDRR052) and Planning Guide (PGRR118) that insert terminology associated with energy storage resources into the protocols. The change aligns the ESRs’ provisions and requirements with those for generation resources and controllable load resources. 

Staff said the recent approval of NPRR1188, which modified the dispatch and pricing of controllable load resources, had a “cascading impact” on baseline language used in other revision requests. Seely said staff will work on additional ERCOT comments and clean up language before sending the change to TAC for its consideration. 

The board’s consent agenda included six other NPRRs, two NOGRRs, an OBDRR and two PGRRs that will: 

• • NPRR1180, PGRR107: incorporate a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecast load growth and additional load seeking interconnection. 

• • NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system’s secure area to the public ERCOT website. 

• • NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ECEII information from the secure area to the website. The change also conforms the rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website. 

• • NPRR1248: corrects language in NPRR1197 (Optional Exclusion of Load from Netting at ERCOT-Polled Settlement Metering Facilities which Include Resources) that did not correctly reflect the Protocol Revision Subcommittee’s vote to approve the change as amended by Oncor comments and revised by the PRS. 

• • NPRR1249: requires ERCOT to publish shift factors for all active transmission constraints in the real-time market. 

• • NPRR1254: requires resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies. 

• • OBDRR053: aligns non-spinning reserves’ deployment and recall procedure with NPRR1131’s revisions (Controllable Load Resource Participation in Non-Spin) along with other minor clean-ups.