ERCOT Technical Advisory Committee Briefs: May 22, 2019

TAC Sends Proposed CONE Revisions to WMS

May 27, 2019 | Tom Kleckner

ERCOT in April set new monthly generation records for its wind and solar fleets, producing 7,148 GWh and 408 GWh, respectively.

AUSTIN, Texas — Unable to reach a decision on a rare update to a key metric used to determine systemwide offer caps, the ERCOT Technical Advisory Committee last week delegated a staff proposal to the Wholesale Market Subcommittee for further discussion.

ERCOT has proposed lowering the peaker net margin (PNM) threshold from $315,000/MW-year to $273,600/MW-year, based on a revised 2018 report by The Brattle Group that set the cost of new entry (CONE) for generation plants — typically combustion turbines — at $91,200/MW-year. The PNM threshold is set at three times the CONE, which means the $315,000/MW-year threshold used in recent years implies a CONE of $105,000/MW-year.

The PNM threshold is used to determine the point at which the systemwide offer cap is reset from the high offer cap of $9,000/MWh to the low offer cap (the higher number between $2,000/MWh or 50 times the daily effective fuel index price).

During its Wednesday meeting, the committee rejected two separate motions in roll-call votes, both of which would have referred the issue to the WMS for further discussion on the study’s values. One motion would have tabled ERCOT’s proposal; the second would have approved it. The latter motion fell just short, by a 66-34 margin.

When the smoke cleared, TAC Vice Chair Diana Coleman, of the Texas Office of Public Utility Counsel, agreed with ERCOT to send the proposal to the WMS.

Brattle initially set the CONE for CTs at $88,500/MW-year but revised it in the final draft estimate of ERCOT’s market equilibrium and economically optimal reserve margins. The study, which “translated” an earlier version conducted for PJM to account for locational cost differences, adjusted assumed interest rates and corporate tax rates to come up with the new CONE.

The current CONE dates back to a 2012 Brattle study, which the Texas Public Utility Commission used to update its resource adequacy requirements earlier this year (Project 48721). (See “PUC Amends Resource Adequacy Rules,” Texas PUC Briefs: May 9, 2019.)

“We’re in a rising interest rate environment,” Reliant Energy Retail Services’ Bill Barnes said in advocating for the WMS’ further evaluation. “Let’s avoid a 10-year backward-looking number and use values that make sense.”

ERCOT staff said they would take time to bring in a consultant to review the Brattle analysis. They noted its Independent Market Monitor, Potomac Economics, has used a CONE of between $80,000 to 95,000/MW-year in recent reports and that the process used to change the CONE is “consistent with our current methodology.”

Luminant’s Ian Haley countered by bringing up FERC’s recent approval of PJM’s quadrennial revision of its variable resource requirement (VRR) curve used in a pricing model, which has drawn requests for rehearing and protests by both load and supply interests (ER19-105). Brattle analyzed the VRR curve’s shape and its CONE in recommending several refinements. (See PJM to Consider Revisions to Demand Curve Design.)

“This is so controversial in PJM that this is being litigated at FERC,” Haley said, objecting to making a “major market change” with seven days’ notice. “This is not something PJM instituted and everyone grabbed hands and sang ‘Kumbaya.’ These are some numbers with big issues in other markets. I have a lot of trouble with [ERCOT] describing them and running with them and showing slight differences [justifying] why they work here in six slides.”

Subcommittees to Review Emergency Procedures

The TAC also delegated to the WMS and its Reliability and Operations Subcommittee further discussions on the need to balance emergency procedures and system reliability.

ERCOT has already spent the last month working to resolve issues raised by a late-winter cold-weather event that resulted in generation resources being forced to adjust their outage schedules. (See ERCOT Generators Upset over Early March Weather Event.)

The grid operator has held two workshops on its procedures for issuing operating condition notices (OCNs) and conducted a webinar on a Nodal Protocol revision request (NPRR930) that would require it to use a weekly reliability unit commitment process to commit resources with an approved outage. The NPRR also sets an offer floor for the resource at the systemwide offer cap. (See “Changes Coming to ERCOT’s OCN Process,” ERCOT Briefs: Week of April 22, 2019.)

Two other NPRRs (934 and 935) addressing emergency procedures are going through the stakeholder process.

TAC members pushed to gain a clearer understanding of ERCOT’s OCN procedures and asked for greater accuracy in weather forecasts and planning assumptions.

“The range of possible outcomes of load [and] the range of possible forecasts for wind and icing are all very situationally dependent,” ERCOT COO Cheryl Mele said. “I’m not sure that is something we can hard code. We want to make that as transparent as possible and share that information with folks as soon as we can. I don’t think we can develop specific criteria around that because cold weather, hot weather [and] wet weather combined with cold all present very different types of risks to us.”

“We don’t expect hard coding, but we think we can get close to it,” Calpine’s Brandon Whittle said. “I think there’s a way to narrow that scope a little bit to where we have general consistency.”

“We don’t want an emergency declared days in advance, which is not what ERCOT wants to do,” Citigroup Energy’s Eric Goff said. “There are certainly other instances in the protocols worth finding and revising. At the same time, we can ensure we have communications around emergency conditions that are very clear and procedures that don’t have much guesswork.”

Barnes said his concern is that market participants are using ERCOT’s planning assumptions and the planning process to make operational decisions, “so we’re always going to overshoot.”

“That’s the nature of solving this problem,” he said. “Inherent in our market design is an acknowledgement we’re willing to accept a high level of reliability risk.”

Barnes referred to recent comments filed by Texas Competitive Power Advocates, a trade association representing ERCOT generators, wholesalers and retail providers. TCPA called for a holistic review of ERCOT’s reliability standards by the grid operator itself, along with Texas Reliability Entity and market participants.

“[TCPA] is concerned that this fundamental conflict between the reliability standards and required scarcity means that even lower reserve margins will be required before the economic signals are apparent and trusted to lead to a turnaround in supply,” the association said.

“There’s a lot of subjectivity in interpreting the standards,” Barnes said. “Not just ERCOT, but every power market has this tension between the need to preserve reliability and the need to let markets solve those problems. I know we probably have a reluctant partner in ERCOT to review the standards to see if there’s more room for relaxation of those, but that’s worth continuing to discuss.”

Wind, Solar Energy Set New Marks in April

Mele’s revamped operations report revealed ERCOT in April set new monthly generation records for its wind and solar fleets, producing 7,148 GWh and 408 GWh, respectively. That bettered the previous marks of 7,060 GWh of wind in May 2018 and 368 GWh of solar last June.

Wind energy accounted for 26.7% of ERCOT’s production during April, besting coal (19%) and nuclear (12.3%), while gas accounted for 39.9%.

April’s peak demand of 51.6 GW was a 3.7% increase over April 2018’s peak (47.9 GW) but below the April 2017 record of 53.5 GW.

Mele said she wants to retire the previous operations report’s format but agreed to add real-time revenue neutrality allocation (RENA) metrics to the deck. RENA measures the amount of leftover market revenue paid to qualified scheduling entities on a load-ratio share to keep the grid operator revenue neutral.

TAC Tables One Change, but OKs 17 Others

Committee members tabled an NPPR (917) that would set a 20-year grandfathering period to assist settlement-only distribution and transmission generators (SODGs and SOTGs) in their transition from zonal to nodal energy pricing.

NPRR917 currently allows existing SODGs and SOTGs to apply for continued zonal pricing until they opt in for nodal pricing or Jan. 1, 2030, whichever comes first. The proposed rule would grandfather distributed generation resources that have entered into interconnection agreements or power purchase agreements before Jan. 1, 2019.

In objecting to the request, solar developer Cypress Creek Renewables called for allowing existing SODGs and SOTGs to opt out of nodal pricing and continue to receive zonal prices for five years, with the option of extending the treatment for additional five-year increments for up to 40 years.

Cypress Creek is supported by Lower Colorado River Authority, which prefers a longer grandfathering period rather than a shorter one. The two entities will work together over the next month on joint comments.

Ralph Daigneault, legal counsel for Potomac Economics, said the Monitor is concerned with any grandfathering clause, but even more so when the term extends to 40 years.

“We think it’s bad precedent and bad market design. Any exception to that perpetuates the bad market design,” he said. “I think the comments by Cypress Creek are a step backwards. The smaller we get with that number, the more comfortable the IMM is going to be.”

“The big motivation for doing this zonally is if you have a load entity in that zone, and your generation is in that zone, you get a natural hedge,” said Walter Reid of the Advanced Power Alliance. “That is the business model that was expected, but unfortunately, we’re changing that.”

ERCOT says the change would better align its operations with the overall nodal market design and reliability needs and would increase economic efficiency.

The TAC did approve seven other NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), four other binding document changes (OBDRRs), two modifications to the Planning Guide (PGRRs) and a system change request (SCR):

- - NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the Texas PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
  - NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
  - NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
  - NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
  - NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
  - NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study, and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
  - NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
  - NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Nodal Operating Guide.
  - NOGRR188: Aligns the guide’s language with ERCOT’s wide area network refresh project to allow implementation of Voice over Internet Protocol.
  - NOGRR189: Aligns the NOGs with NERC Reliability Standard PRC-002-2 (Disturbance Monitoring and Reporting Requirements).
  - OBDRR009: Revises the online and offline capacity reserves to prevent price reversal and price distortion during DC tie out-of-market actions.
  - OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
  - OBDRR014: Changes the location where resource nodes with disallowed energy-only offers, energy bids and point-to-point bids will be posted, and clarifies that the congestion revenue rights team will use the most recent list when building the auction model. The OBDRR also modifies its approval process to better account for revisions that may require a project and a separate SCR.
  - OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high systemwide offer cap to the low systemwide offer cap should the PNM exceed its threshold within an annual resource adequacy cycle.
  - PGRR069: Uses terms created by NPRR889 to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
  - PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
  - SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.