Monday, February 18, 2019

ERCOT Technical Advisory Committee Briefs: Jan. 25, 2018

TAC Asks WMS to Investigate 2 Market Events

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week asked its Wholesale Market Subcommittee (WMS) to determine what went wrong during two recent market events.

On Jan. 22, ERCOT disabled the 69-kV contingencies being solved by the day-ahead market (DAM) software, with the exception of a contingency included in a real-time binding constraint during the previous 30 days. Staff issued a market notice at the time.

ERCOT TAC wholesale market subcommittee

ERCOT’s Technical Advisory Committee gathers for its January meeting | © RTO Insider

ERCOT’s Carrie Bivens said staff followed protocols by issuing the notice. “The alternative was aborting the DAM run,” she said.

On Jan. 23, real-time prices jumped to $5,800/MWh for 15 minutes, forcing ERCOT to deploy non-spinning reserves. Prices also exceeded the energy offer cap of $9,000/MWh during two five-minute intervals.

The ISO said it was the first time market prices reached the $9,000 price cap during two security constrained economic dispatch (SCED) intervals, pointing to ramping issues because of cold weather and higher-than-expected load around 7 a.m. Resource adequacy was not a problem, ERCOT said.

Staff’s David Maggio said ERCOT doesn’t intend to reprice the event, noting the systems were “working as expected.”

“We don’t see any issue with how things worked out,” he said.

ERCOT TAC wholesale market subcommittee

Morgan Stanley’s Clayton Greer | © RTO Insider

Staff said the two events were unrelated, prompting Citigroup’s Eric Goff to respond, “They felt related to everyone.”

“The issue that caused the DAM software problem was unrelated to ramp constraining in real time,” Bivens said. “They just happened on the same operating day.”

The contingencies were restored Jan. 24 for the following operating day.

“We need a discussion at WMS, because you’re determining winners and losers when you turn off contingencies,” Morgan Stanley’s Clayton Greer said during the TAC’s Jan. 25 meeting.

The WMS next meets Jan. 31. The subcommittee will also provide real-time co-optimization training following its meeting.

ERCOT Sees 62% Drop in RUC Practices

ERCOT staff’s annual reliability unit commitment (RUC) report to the TAC last week revealed a more than 62% drop in the practice.

Maggio said that 562 instructed RUC resource-hours last year resulted in 534 effective RUC resource-hours, compared to 1,514 and 1,417, respectively, for all of 2016.

Of those resource-hours, 163 were successfully bought back, a clawback percentage similar to previous years. The total RUC make-whole amount was about $540,000, which was covered through capacity short charges.

The 534 effective RUC resource-hours were all a result of congestion (433), capacity (66) and Hurricane Harvey (35). No resource-hours were committed for ancillary service shortages, system inertia or extreme cold weather/start-up failures.

Maggio pointed to several recent improvements as causing the drop in RUCs, including reducing shadow price caps for transmission constraints from about $1 million/MWh to about $100,000/MWh and a nodal protocol revision request (NPRR744) that used a common trigger to fix the opt-out decision inconsistency between the SCED and settlements systems.

Staff and stakeholders are still working to improve both RUC functionality and transparency, Maggio said.

In other staff reports:

  • Assistant General Counsel Vickie Leady told stakeholders that staff have developed a definition of “affiliate” in line with the typical corporate use of the word. The proposed bylaw amendment clarifies when an affiliate relationship arises between two or more ERCOT members.
  • Members will be allocated almost $26,000 in resettlements from the Greens Bayou Unit 5 reliability-must-run contract, after certain costs were not fully settled before applicable true-up dates. The RMR, ERCOT’s first since 2011, was approved in June 2016 and terminated effective May 29, 2017.
  • Controller Sean Taylor said the ISO forecasts the system administration fee will be adequate and he “sees no need for a change” through 2019. Stakeholders had requested advance notice of any fee increases during the 2016-17 budget process.

Task Force Looks at Subcommittees’ Restructuring

Stakeholders agreed to form a task force to combine or restructure the TAC’s Retail Market (RMS) and Commercial Operations (COPS) subcommittees. The task force will begin its work Feb. 5, with the intention of reporting back to the committee for its Feb. 22 meeting.

Leadership from the two subcommittees met over the holidays and agreed on three options for restructuring them. The initiative is a result of the TAC’s annual structural review of its subcommittees and input from the Board of Directors’ Human Resources and Governance Committee.

Reliant Energy Retail Services’ Rebecca Reed Zerwas will lead the task force, after she was “‘volun-told’ to get this started.”

The RMS and COPS will continue in their current forms until a solution is endorsed by the TAC.

TAC Elects Helton Chair, Coleman Vice Chair

The committee unanimously elected Dynegy’s Bob Helton as its chairman, a position he has essentially held since September. Previously vice chair, Helton stepped into the role vacated by Adrianne Brandt, who left San Antonio’s CPS Energy to join Chair DeAnn Walker’s staff at the Public Utility Commission of Texas.

TAC Vice-Chair Diana Coleman, Chair Bob Helton | © RTO Insider

Diana Coleman, ‎senior market specialist with the ‎Office of Public Utility Counsel, was elected vice chair.

NPRR Clarifies ERCOT’s Jurisdictional Status Quo

The TAC unanimously endorsed NPRR861, which clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and market participants with respect to FERC. Possible actions include, but are not limited to, ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.

The PUC in December instructed the ISO to draw up the NPRR over concerns that transmission projects along the U.S. border with Mexico may threaten ERCOT’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See “Fending off FERC,” Texas PUC Challenging SPP-Mountain West Intertie Costs.)

FERC’s jurisdiction is derived from the Federal Power Act, which gives the commission broad authority to regulate interstate commerce by public utilities. FERC does not have plenary jurisdiction over the ISO because the energy generated in the region is not transmitted in interstate commerce, except for certain interconnections ordered by the commission that do not give rise to broader jurisdiction.

The committee also unanimously endorsed six other NPRRs, a system change request (SCR) and a nodal operating guide revision request (NOGRR):

  • NPRR819: Removes language referencing “data errors” for resettlement of the DAM and real-time market (RTM); gives the ERCOT board authority to direct a DAM resettlement parallel to its authority to direct an RTM resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
  • NPRR841: Determines in real time the day-ahead make-whole payment by incorporating the ancillary services infeasibility charge, approved with NPRR782, into the payment’s analysis.
  • NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone, used primarily for study purposes.
  • NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
  • NPRR852: Creates a more efficient approval process when updating the congestion revenue right activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the WMS.
  • NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
  • NOGRR169: Aligns the guide’s language with NERC Reliability Standard PRC-002-2 (Define Regional Disturbance Monitoring and Reporting Requirements) to determine required locations for NERC-required disturbance monitoring equipment. This relieves the burden on facility owners to adhere to two vastly different requirements for the same purpose.
  • SCR794: Updates how the SCED limit is calculated by the Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.

— Tom Kleckner