ERCOT stakeholders are waiting on final direction from state lawmakers and regulators as they tackle a list of more than 100 emergency conditions issues arising out of February’s disastrous winter storm.

Just Energy’s Eric Blakey, chairing last week’s Technical Advisory Committee meeting in the absence of South Texas Electric Cooperative’s Clif Lange, told members that “to the extent we can, we’re moving forward.”

“As we move forward, we’ll start to get legislative direction,” Blakey said Wednesday. “We’ll begin working with the [Public Utility Commission] more directly on the projects they have ongoing to address some of these issues. Let’s continue to work the process.”

The list, first developed with input from then-CEO Bill Magness in March, now numbers 124 issues that have been parceled out to various stakeholder committees. (See “TAC Takes up Ideas for Solutions,” Texas PUC Won’t Reprice $16B Error.)

The vast majority of the issues, denoted as “awaiting legislative action,” or near- or long-term “stakeholder items,” have not started, with many others waiting until the PUC designates them as projects.

Only two items are in progress: accelerating ongoing improvements to resource adequacy reports by modeling the risk of various emergency events’ magnitudes; and updating the methodology used to determine the cost of new entry. The CONE is used to determine the systemwide offer cap, which has been reset to $2,000/MWh for the summer after hitting its $9,000/MWh limit during the February storm.

The Texas legislature adjourned Monday night until 2023. At least one special session is expected later this year.

Counterparties Face Tougher Entry Criteria

Stakeholders debated a measure that strengthens market entry qualifications for ERCOT counterparties and other entities before agreeing to table it and send it back to the Wholesale Market Subcommittee’s Market Credit Working Group for further refinement. The TAC plans to take a second look at the language during its July meeting before presenting it to the Board of Directors in August.

The nodal protocol revision request (NPRR1073) adds new criteria for qualified scheduling entities (QSEs), congestion revenue right account holders (CRRAHs) and other counterparties. It creates a new background check process as part of ERCOT’s review of current and prospective counterparties; authorizes staff to review current and prospective counterparties to determine whether they pose an unreasonable credit risk; authorizes ERCOT to suspend a QSE or CRRAH if they pose an unreasonable credit risk; and authorizes staff to terminate a counterparty’s registration if it is deemed an unreasonable credit risk that cannot be remedied.

ERCOT, Luminant and Shell Energy North America all filed late comments on the NPRR. ERCOT was supportive of the NPRR, saying the change would prohibit an entity from entering, returning to or participating in the market if it has a principal that was also a principal with a former market participant that still had a financial obligation to the grid operator. It noted that another proposed change (NPRR1067) creates a holistic background and credit check process and mitigates market exposure by bad actors by providing tools to assess counterparty creditworthiness.

Shell agreed with Luminant’s comments that NPRR1073 should focus on ensuring that market participants are responsible for their allocated default uplift and requiring that defaulted entities repay the default before any principals may return to the market. Resmi Surendran said care should be taken so that “good players [are not] at potential violation of the protocol as soon as the changes are approved” and asked for clarification on the measure’s implementation.

Lower Colorado River Authority’s John Dumas said the cooperative’s credit staff were confused about some of NPRR1073’s language and its potential conflict with securitization legislation being debated at the capitol.

“How will that new bill work with uplift rules and default rules currently in place?” he asked, agreeing that the Market Credit Working Group, with its “financial experts,” is the best place to hammer out those issues. “We’ve got to get the language and the rules right.”

The PUC’s Rebecca Zerwas said staff were supportive of ERCOT’s comments but still wanted to look at the language.

Urgent ESR Change Passes

TAC members approved a measure, granted urgent status to allow energy storage resources’ (ESRs) participation to grid reliability this summer, over the objections of industrial consumers. CMC Steel Texas and Air Liquide voted against the change, which passed 26-2 with one abstention.

NPRR1075 allows ESRs to update their high sustained limit (HSL) and/or maximum power consumption (MPC) in real time to maintain sufficient energy to meet an ancillary service resource responsibility. The carveout for ESRs will expire when either real-time co-optimization goes online or a mitigated offer cap for ESRs is implemented.

CMC’s Garret Kent said the NPRR poses important implications for ESRs that need to be addressed before the summer. ERCOT staff said they support the measure because of “various operational issues.”

The committee unanimously approved the combination ballot, which included four NPRRs, an other binding document revision (OBDRR) and single changes to the load profiling (LPGRR) and planning guides (PGRR):

• NPRR1062: changes the metering requirement for premises connected at transmission voltage and/or with a peak demand greater than 700 kW/700 kVA from an interval data recorder (IDR) meter to one that also includes advanced meters. The change also eliminates the IDR meter requirement report.
• NPRR1064: conforms ERCOT’s as-built systems protocol language with respect to the evaluation and reporting of chronic congestion. The revision also clarifies the grid operator’s expectations and processes for the verification of modeling information for elements included in the chronic-congestion report.
• NPRR1071: modifies the threshold for retail electric providers’ (REPs) participation in the annual survey of aggregate customer counts from 95% to 98%; the timing requirement for REPs to provide information to ERCOT regarding demand response deployments from Oct. 15 to Oct. 31; and the posting date for the final report from Dec. 15 to Dec. 31.
• NPRR1074: changes the definition of “mp” in the credit default allocation calculations substituting “existing” for “non-defaulting.”
• LPGRR068: adds two new PROFILETYPECODEs for use on premises billed on a four-coincident peak (4-CP) where transmission and/or distribution service providers can support a 4-CP billing rate with an advanced metering system profile: BUSLRG will be for premises without distributed generation and BUSLRGDG for those with DG. The existing BUSIDRRQ will remain an option for premises billed on a 4-CP tariff.
• OBDRR029: modifies the Demand Response Data Definitions and Technical Specifications OBDRR’s Excel templates in Appendix B (NOIE Submission File Template) and Appendix C (REP Event File Template) to clarify that electric service identifier numbers are to be provided instead of ESI ID lists. Also combines error descriptions and suggested fixes into a single table.
• PGRR088: includes the financial security amount necessary to fund the interconnection facilities in the monthly generator interconnection status report.