Texas’ regulatory commission has adopted a reliability standard for the ERCOT region, one of several policy parameters that will be used in upcoming analyses for the proposed performance credit mechanism (PCM) market design.
As approved by the Public Utility Commission during its Aug. 29 open meeting, ERCOT must meet three criteria to comply with the reliability standard: frequency, duration and magnitude. To meet the standard, ERCOT outages should not occur more than once in 10 years on average, last more than 12 hours or lose more power than can be safely rotated (54584).
“Our system must continue to evolve to meet the growing demand for power in our state … it’s critical we clearly define the standard at which we expect the market and system to operate,” PUC Chair Thomas Gleeson said in a statement. “By establishing a reliability standard for the ERCOT region today, we are setting a strong expectation for the market and charting a clear path to further secure electric reliability.”
The new rule also establishes a process to regularly assess the ERCOT grid’s reliability. The commission directed ERCOT staff to conduct a probability-based assessment every three years, beginning Jan. 1, 2026, to determine whether the system is meeting the standard and is expected to continue to do so over the next three years.
Should that assessment indicate the system fails to meet the reliability standard, the Independent Market Monitor (IMM) must conduct an independent review and commission staff must recommend their own potential market design changes. The PUC then would review ERCOT’s assessment, the IMM’s review, commission staff’s recommendations and public comments to determine whether any market design changes are necessary.
ERCOT and IMM staff confirmed during the meeting that they have all they need to begin their respective analyses. Draft results are due to the PUC in early November; the commission will consider the final results in December.
The ISO said it will use 19 GW as the amount of load it can safely rotate during an outage in its cost/benefit analysis, as it proposed in an April research paper.
The reliability standard was just one of several actions the PUC took to establish regular assessments of the grid’s ability to meet demand and help determine any necessary future improvements.
It adopted a value of lost load of $35,000/MWh, using information from a survey of ERCOT consumers and a Brattle study. Staff proposed a $30,000 VOLL, but Gleeson recommended Brattle’s suggested $35,685, saying it was “reasonable” after a “detailed and thorough” analysis (55837).
“We don’t need the extra numbers in there,” Gleeson said.
ERCOT will use VOLL for cost/benefit analyses in its planning models. The PUC said it will not be used to update the operating reserve demand curve or any current market-design elements.
The commission also accepted staff’s final recommendations for each of the PCM’s 37 base case parameters, including a firm $1 billion gross cost cap to comply with state law (55000). ERCOT had proposed a counterfactual of energy-only market equilibrium reserve margin instead of the cost cap, a “purely theoretical number,” according to Stoic Energy principal Doug Lewin.
PUC staff and ERCOT also differed on four other parameters: the metric to determine performance credit (PC) hours; a duration-based cap for consecutive PC hours; the net-cost cap compliance framework; and non-performance penalties for PCs offered but not cleared in the forward market.
The PUC selected the PCM from among five other suggested market reforms as its design of choice and approved it in 2023. That same year, the Texas Legislature passed a bill setting a $1 billion annual cap for the PCM. (See Texas PUC Submits Reliability Plan to Legislature.)
The PCM will use the reliability standard and a corresponding quantity of PCs that must be produced during the highest reliability risk hours to meet the standard. Load-serving entities can purchase PCs, awarded to resources through a retrospective settlement process based on availability during hours of highest risk, and trade them with other LSEs and generators in a forward market; generators must participate in the forward market to qualify for the settlement process.
CPS Energy MRA, RMR Update
ERCOT told the PUC it has changed course on must-run alternatives for three retiring CPS Energy coal units, postponing an inspection of the largest unit until after the winter season (55999).
The San Antonio municipality told the commission this year it planned to retire the three coal units, which date back to the 1960s, in March 2025. However, ERCOT said the Braunig Power Station units, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for reliability-must-run proposals in July. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
The grid operator said in an update to the commission that while it continues to negotiate a potential agreement with CPS Energy to inspect the 412-MW Unit 3, it would be “more prudent” to allow the resource to operate through the winter’s peak demand period. ERCOT staff said the inspection could be held in mid-February or early March.
“If we waited until after winter peak load, we believe we’d still have plenty of time, barring unforeseen circumstances, to have the unit inspected and repaired during another shoulder season for outages and before the summer peak load season,” ERCOT’s Davida Dwyer said.
The ISO extended the deadline for RFP responses to Oct. 7 after receiving fewer than 10 proposals to its initial request. (See “ERCOT Extends MRA Timeline,” ERCOT Board of Directors Briefs: Aug. 19-20, 2024.)
Chad Seely, the ISO’s general counsel, told the commission the deadline would provide an “important data point” in seeing whether the industry has responded with enough MW to provide relief for a constrained area south of San Antonio.
“The additional time affords us a more deliberative process on these critical policy issues to see if the industry is going to respond to the must-run alternative,” Seely said, “and then continue to move forward [on] a path where we still think it’s appropriate and prudent for reliability to start to open up the unit in advance of any April 1 RMR agreement.”
“Is it looking bleak on the MRA?” Commissioner Lori Cobos asked Seely.
Noting that ERCOT has amended the RFP after stakeholder feedback, he said, “We’re hopeful, with the amendments that we put forward and allowing almost another month of time for people to go do their due diligence, and talk to their shops about options, that we will see a higher [number] of offers come in in October.”
“Ultimately, I don’t want RMR to be the norm, right?” Cobos responded.
Seely said the three units are in a “prime” location to relieve the constraint’s interconnection reliability operating limits (IROLs), which makes the pre-RMR inspection work such an “extraordinary situation.”
“[Braunig] is one of the best assets right now in the system, until we see other solutions to help relieve the overloads of the IROL for the next couple of years,” he said. “That’s why it’s critically important to be deliberative and these critical policy issues on how we approach this.”
CPS has said it will cost about $22 million to inspect, repair and prepare Braunig Unit 3 to remain in service past March and an additional $35 million for the other two units.
Utility and energy storage company Eolian announced Aug. 28 an agreement for two storage facilities south of San Antonio totaling 350 MW of capacity. The projects are not expected to come online until 2026, but work to upgrade the transmission infrastructure and relieve the South Texas constraint isn’t expected to be completed until the middle of 2027.
