AUSTIN, Texas — ERCOT last week announced two leadership changes it said would “sharpen our focus on daily operations” as it battles near-daily tight grid conditions.

The grid operator said in a Friday press release that Woody Rickerson, previously vice president of system planning and weatherization, has been promoted to senior vice president and COO. He will be responsible for grid operations, weatherization, planning and commercial operations.

“This new position will leverage Rickerson’s deep operations experience and support ERCOT’s continued investments in grid innovations,” ERCOT CEO Pablo Vegas said in a statement.

Kristi Hobbs, newly named vice president of system planning and weatherization, will handle some of Rickerson’s previous responsibilities. She will oversee transmission planning, generator interconnection activities, training and weatherization, and will report directly to Rickerson.

The promotions, both effective immediately, come after ERCOT made six appeals in seven days for voluntary conservation Aug. 24-Aug. 30. The grid operator has recorded 10 all-time peak records this summer. However, it has encountered tight conditions during the early evening, when solar power ramps down and wind resources, which generally contribute less than solar during the summer, try to fill the gap. (See ERCOT Continues to Rely on Voluntary Conservation.)

“As our industry faces dynamic changes, ERCOT is continuously evolving and making the necessary improvements to the grid to support the needs of a growing population and robust economy,” Vegas said

The announcement came the day after ERCOT’s Board of Directors re-ratified Rickerson and Hobbs as officers during its bimonthly meeting.

In two other organizational changes, Chief Compliance Officer Betty Day was given oversight of business continuity and Rebecca Zerwas named director of state policy and Public Utility Commission relations and a board liaison.

ERCOT has been operating without a COO since Cheryl Mele left ERCOT and the position in 2019. She now is vice president of customer care and corporate communications at El Paso Electric.

NPRR1186 Remanded to TAC

The board remanded back to the Technical Advisory Committee a nodal protocol revision request that has drawn opposition from the storage community.

The directors asked that stakeholders and staff address only unusual scarcity situations raised by Eolian, a storage developer that appealed TAC’s approval of NPRR1186. Eolian asked that ERCOT be directed to resubmit new NPRRs to determine batteries’ state-of-charge (SOC) parameters and related compliance obligations. (See “SOC Transparency,” ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.)

Eolian COO Stephanie Smith called for scarcity events to be carefully defined, “ideally with reasonable amounts of study to ensure no further unintended consequences to the market.” She said NPRR1186’s requirement that batteries meet an SOC obligation at the top of the hour will negatively affect reliability and counter the benefit multi-hour batteries provide.

“We don’t yet know whether there will be cost implications to consumers or if it will create grid conditions that lead to reliability concerns or events,” Smith said. “Unfortunately, we don’t always start at the top of an hour and even though we have hourly products, we don’t want all batteries charging at the same time to meet a requirement … that could lead to unintended consequences, especially during tight conditions.”

NPRR1186 also adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market process should begin to respect the AS award limits for ESRs based on duration requirements.

Staff says the measure provides a necessary, cost-effective interim solution to improve the awareness, accounting and monitoring of SOC before the Real-time Co-optimization + Batteries project finishes its work in 2026. As of June 1, ERCOT says there were about 3.3 GW of batteries energized on the system. That total could grow to 9.5 GW by October 2024 should interconnection queue projects with signed agreements and posted security join the grid.

Rickerson and other ERCOT executives said NPRR1186 simply allows them to see how much energy batteries have stored and whether that’s enough to meet their commitments.

“We have a reliability issue today … we want to use batteries. Batteries are the future,” Rickerson said. “But we can’t keep buying a service that isn’t always capable of being delivered. [NPRR1186] will fix that and allow us to get to this power over time.”

Vegas: Environmental Regs a Threat

Vegas reviewed for the board five environmental regulations with overlapping timelines that, when taken together, he said could have serious unintended consequences for the grid during peak demand periods.

“Many of these rules do apply to [thermal] resources,” he said. “They have to understand whether they comply with one, two, three or combinations. It’s a very complex system that could lead to very, very detrimental decisions.”

ERCOT’s generation fleet is reckoning with five recent regulations from EPA:

• • The coal combustion residuals (CCR) rule that regulates CCR disposal at inactive generating units and establishes groundwater monitoring, corrective action, closure and post-closure care requirements.
  • The greenhouse gas rule that proposes significantly lower carbon dioxide emissions for coal and gas units.
  • The Clean Air Act’s Good Neighbor Rule that lowers state-level nitrogen oxides from thermal units to mitigate pollutants to downwind states.
  • The Mercury and Air Toxics Standard rule that proposes particulate matter emissions standards for coal-fired generators and mercury emissions standards for lignite-fired generators.
  • Texas’s regional haze federal implementation plan that recommends new limits on sulfur dioxide and particulate matter emissions to meet air-visibility requirements at national parks and wilderness areas.

“We all need to keep in mind the compound nature of stacking multiple rules on top of each other because it’s pretty deadly when you’re the owner and private investment decisions need to be made,” board Vice Chair Bill Flores, a former U.S. representative, said. “It’s important for the Texas consumer to know that we’ve got 72 GW, over half of our fleet today, are these plants. These rules take a substantial amount of that offline within the short-term period, and there’s no replacement that provides reliable, cost-effective power.”

Vegas said ERCOT has filed comments on all five rules and has scheduled a meeting this week with EPA and U.S. Department of Energy “to continue that dialogue.”

“We are actively engaging with the Department of Energy and the EPA to make sure that they understand our risks as operators on the system,” he said. “We’re obviously continuing that dialogue with them so that they clearly understand that it’s not just a Texas issue, it’s a U.S. issue as the entire grid is transforming.”

The Good Neighbor Rule is not effective in Texas, Louisiana and Mississippi after the U.S. 5th Circuit Court of Appeals issued a stay in May. The court is not expected to make a final ruling until next year.

San Antonio Tx Projected OK’d

The board approved a $329 million reliability project in the San Antonio area that previously had been endorsed by TAC. The CPS Energy project addresses thermal overloads in South San Antonio and has been designated as a Tier 1 project because of its estimated capital costs of $100 million or more.

In other actions, the board also:

• • Authorized the creation of the Technology and Security Committee to provide oversight of technology-related functions and physical and cyber security initiatives and committee assignments for the board’s members. Director John Swainson will chair the committee, the board’s fourth.
  • Approved a date change for ERCOT’s annual meeting of members to Dec. 18, when the board’s committees will meet. The change, from Dec. 19, resolves a conflict with the full board’s meeting.

Board Approves 30 Rule Changes

The directors endorsed 30 revisions requests covering the three TAC meetings since the board last met. With the exception of an other binding document revision (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC), they all passed unanimously.

Office of Public Utility Counsel CEO Courtney Hjaltman abstained from voting on OBDRR048, which was opposed by all six members of TAC’s consumer segment. The measure adds price adders to the operating reserve demand curve of $20/MWh and $10/MWh that will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively.

The PUC approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, in August. (See Texas PUC Approves ERCOT’s ORDC Modifications.)

The board unanimously approved two other OBDRRs, 13 NPRRs, seven changes to the nodal operating guide, two revisions to the planning guide (PGRRs) and the resource registration glossary (RRGRRs) and single modifications to the retail market guide (RMGRR) and verifiable cost manual (VCMRR). They include:

• • NPRR1150: requires qualified scheduling entities (QSEs) that represent resource entities, emergency response service resources or other QSEs, and that receive or transmit wide-area network (WAN) data to maintain connections to the ERCOT WAN and a secure private network.
  • NPRR1163, LPGRR070: discontinue the process of evaluating interval data recorder meters to determine whether any are weather-sensitive.
  • NPRR1164: requires resource entities to identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It also would require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
  • NPRR1165: strengthens market entry eligibility and continued participation requirements for QSEs, congestion revenue right (CRR) account holders and other counterparties by removing minimum capitalization requirements; requiring counterparties to post independent amounts’ remove references to guarantors; clarifying financial statement requirements; and referencing International Financial Reporting Standards rather than retired International Accounting Standards.
  • NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources and distribution energy storage resources seeking qualification to provide ancillary services and/or participate in security constrained economic dispatch (SCED).
  • NPRR1173: accounts for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
  • NPRR1174: establishes a process allowing QSEs or CRR account holders to return overpayment settlement funds to ERCOT.
  • NPRR1175: strengthens market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classifies information in the background check as protected information, modifies application forms for QSEs and CRR account holders, and add a new background check fee to the grid operator’s fee schedule.
  • NPRR1176, NOGRR252: revise the Energy Emergency Alert (EEA) procedures to require a declaration of EEA Level 3 when physical responsive capability (PRC) cannot be maintained above 1,500 MW and require ERCOT to shed firm load to recover 1,500 MW of reserves within 30 minutes. The NPRR also would modify the trigger levels for EEA Level 1 and EEA Level 2, change the trigger for ERCOT’s consideration of alternative transmission ratings or configurations from advisory to watch when PRC drops below 3,000 MW and restore a frequency trigger for the EEA Level 3 declaration if the steady-state frequency drops below 59.8 Hz for any period of time.
  • NPRR1182: incorporates controllable load resources and energy storage resources (ESRs) into the constraint competitiveness test’s (CCT) long-term and SCED versions. Controllable load resources will not be mitigated but will be used to identify whether a market participant has market power in resolving a transmission constraint; other resources’ registration data will be used in the long-term CCT process, and real-time telemetry will be used in the SCED CCT process.
  • NPRR1183: revises rules for and make publicly available on ERCOT’s website general information documents that don’t include ERCOT critical energy infrastructure information (ECEII), remove a reference to the Freedom of Information Act from the ECEII’s definition and remove antiquated or duplicative language related to reliability must run.
  • NPRR1185: adds a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
  • NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for ancillary services that resources can provide fast-response service only if awarded regulation service in the day-ahead market for that resource.
  • NOGRR215: allows new remedial action schemes to address only actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
  • NOGRR230: ensures the WAN data transmission’s integrity by requiring data be shared in a manner that prevents denial of service and distributed denial-of-service attacks.
  • NOGRR247: increases the under-frequency load shed (UFLS) program’s load-shed stages from three to five and changes the transmission operator load-relief amounts to uniformly increment by 5% for each stage, adds a UFLS minimum time delay of six cycles (0.1 seconds) and adds 59.1 Hz to the list of UFLS stages and revises the gray-box language from NOGRR226 to provide that the transmission owners’ load value used to determine load at each frequency threshold will be the TO’s load at the time frequency reaches 59.5 Hz.
  • NOGRR249: specifies methods for TOs to receive electronic communication of system operating limit exceedances.
  • NOGRR251: adds cold weather conditions to the template used for developing emergency operations plans to align with NERC Reliability Standard EOP-011-2 (Emergency Preparedness and Operations).
  • OBDRR045: edits the demand response data definitions and technical specifications, including modifications to the electric service identifiers list provided to retail electric providers.
  • OBDRR047: clarifies treatment of unused funds from previous emergency response service standard contract terms.
  • PGRR103: requires interconnecting entities to complete all conditions for commercial operation of a generation resource or ESR within 180 days of receiving ERCOT’s approval for initial synchronization.
  • PGRR108: updates language to reflect the current practice of posting regional transmission plan and geomagnetic disturbance assessment plans and update data sets.
  • RMGRR174: updates language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
  • RRGRR033: adds data to the resource registration glossary pursuant to NPRR1164.
  • RRGRR035: adds data fields consistent with NPRR1171.
  • VCMRR034: provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.