ERCOT’s Board of Directors last week approved an ISO request to correct real-time prices following a July event that caused brief market palpitations. (See “Stakeholders, Staff Discuss Price Investigation Notices,” ERCOT Technical Advisory Committee Briefs: July 26, 2018.)

The correction changes 25 security-constrained economic dispatch intervals and nine settlement intervals between 4:30 and 6:30 p.m. on July 18. The average revision across all settlement points was a $10.67/MWh decrease, while the average change in 15-minute settlement price points was a $8.78/MWh decrease.

The ISO was required to seek board approval for the price correction when staff missed a two-business-day deadline to correct the July 18 error on their own.

A data-input mistake in ERCOT’s weekly operational model resulted in two double-circuit contingencies on a 138-kV line east of Dallas being identified as two triple-circuit contingencies. Kenan Ogelman, ERCOT vice president of commercial operations, said the contingency bound when it shouldn’t have, restricting nearby generation and affecting both system prices and prices near the generating units.

The issue, which wasn’t caught until July 19, affected the July 18 real-time operating day and the July 20 day-ahead operating day. Corrected day-ahead prices were published on July 23.

Woody Rickerson, ERCOT vice president of grid planning and operations, said staff have changed the operational model’s automated process to avoid similar mistakes in the future. Each model includes about 7,000 contingencies.

“We fixed the problem; we’ve validated the contingency files; we’re moving forward with the same process,” Rickerson said.

Staff Continues Southern Cross Work

Compliance Director Matt Mereness briefed the directors on ERCOT’s progress in accommodating the Southern Cross Project (SCT), a 2-GW DC tie in East Texas that would connect the ISO with SERC Reliability Corp.

Because ERCOT’s largest existing DC tie is 600 MW, Texas’ Public Utility Commission last year directed the grid operator to address several issues as a condition for energizing SCT, asking it to respond to 14 directives (Project No. 46304).

Mereness said ERCOT has begun work on six of the directives and is engaging members through the stakeholder process. Two other directives are updates to the PUC and are ongoing.

The board approved staff’s recommendation that no protocol or binding documents concerning primary frequency response are necessary in determining whether SCT or any other entity scheduling flows across the tie should be required to provide or procure the service.

The project is scheduled to be energized in 2023.

ERCOT Reports $16.7M Net Revenue Favorable Variance

ERCOT CEO Bill Magness told the board the ISO’s revenues continue to be favorable, thanks mostly to the record demand this summer.

“It’s load and weather that drives ERCOT,” he reminded the directors.

Magness reported system administration fees were $5 million overbudget through June because of the weather and Texas’ stronger economy. Including $4.2 million in interest income, the ISO is $16.7 million above its year-to-date projected net revenues.

Staff is projecting a year-end total of $19.8 million in favorable net revenues.

ERCOT has also made “significant progress” on a delayed congestion revenue rights software update, Magness said. He said a go-live date is expected to be finalized in September, now that communication has been improved with the vendor and a better process for managing bug fixes is in place.

Special Membership Meeting to be Set

The board voted to call a special meeting of ERCOT’s corporate members “as soon as reasonably practicable” to hold votes on amendments to the ISO’s Articles of Incorporation, which has been renamed the Certificate of Formation, and to the bylaws, which clarify the definition of affiliates and affiliate relationships. The board unanimously approved both sets of amendments.

The members’ annual meeting isn’t until Dec. 11, but ERCOT’s legal department wants to ensure the amendments are effective for the 2019 membership year.

The directors also approved the 2019 schedule for board meetings and accepted a favorable audit report on ERCOT’s employee 401(k) plan.

Board Clears 15 Change Requests

The board unanimously approved its consent agenda, which included a Nodal Protocol revision request (NPRR) it had remanded back to the Technical Advisory Committee in June.

NPRR847 incorporates an intraday weighted average fuel price into the mitigated offer cap. It unanimously cleared the TAC in May, but the board sent it back over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)

The measure is intended to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.

Director Nick Fehrenbach, who represents the commercial sub-segment within the consumer market segment, said he was satisfied with the language changes. He thanked ERCOT for taking his comments into consideration.

The consent agenda also included seven other NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and two changes to the Verifiable Cost Manual (VCMRR).

• • NPRR856: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
  • NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
  • NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load or aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
  • NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
  • NPRR874: Changes the “net allocation to load settlement” stability report by breaking out the load-allocated CRRs monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
  • NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
  • NPRR877: Allows for use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
  • NOGRR174: Harmonizes the automatic voltage regulator and power system stabilizer testing requirements with the recently approved NERC Standard MOD-026-1.
  • PGRR061: Includes locations for registered DG facilities in the annual load data request process.
  • PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
  • RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
  • SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
  • VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing references to make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.
  • VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.

— Tom Kleckner