ERCOT Board of Directors Briefs: Oct. 9, 2018

Staff’s Determination on DC Tie Flows, Pricing Gets OK

Oct 11, 2018 | Tom Kleckner

ERCOT’s Board unanimously approved staff’s determination that no market changes are needed to address price formation issues as a result of DC tie flows.

ERCOT’s Board of Directors on Tuesday unanimously approved staff’s determination that no market changes are currently needed to address price formation issues as a result of DC tie flows during emergency events.

The determination was in response to one of the Texas Public Utility Commission’s 14 directives to ERCOT related to the Southern Cross Transmission project. In approving the project, which would create merchant ownership of a DC tie connection to the Southeast, the PUC directed ERCOT to complete a number of tasks before allowing the line to be energized (Project No. 46304).

ERCOT General Counsel Chad Seely assuaged the board’s concerns by noting filing documents and information in the PUC’s compliance docket allows the commissioners to discuss the grid operator’s updates and provide feedback during open meetings. Seely and Compliance Director Matt Mereness both pointed to an existing price mechanism that allows up to 1,250 MW of DC tie imports to contribute to a reliability price adder, as minimizing pricing effects within the Texas grid.

The Technical Advisory Committee endorsed the determination during its September meeting, but not before adding language to make it clear staff recognized “potential price formation issues” and that stakeholder discussions were ongoing. (See “TAC Approves First PUC Directive Related to DC Ties,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

“The determination doesn’t presuppose any type of future outcome,” Seely said. “If a market participant wants to move forward with a NPRR [Nodal Protocol revision request], ERCOT will work with the stakeholders to facilitate those discussions. No one has had an appetite to sponsor an NPRR to try move any of those issues forward, and we’re not sure it’s necessary at this time.”

Citigroup Energy’s Eric Goff, chair of the Qualified Scheduling Entity Managers Working Group, said during the TAC meeting that a market participant plans to file an NPRR related to the issue. Goff did not identify the participant.

Board Vice Chair Judy Walsh, who led Tuesday’s meeting in Chairman Craven Crowell’s absence, asked Seely if ERCOT would reach “a point of no return” where the Southern Cross project is energized and “we haven’t addressed these issues, and we’re behind the curve?”

Seely responded that even if the price formation issue isn’t addressed by stakeholders in some form, there would be no problem from Southern Cross energizing the project.

ERCOT Projects Year-end $25.5M Positive Budget Variance

ERCOT CEO Bill Magness continues to see a positive trend in budget differences, telling directors he expects “likely a significant [variance] at the end of the year.”

The grid operator’s net revenues were $23.3 million over budget as of Aug. 31, thanks to higher-than-expected loads ($6.7 million over) and increased income because of higher investment balances and rates ($6.4 million). Staff are projecting a year-end favorable variance of $25.5 million.

“We’re still managing to the budget,” Magness assured the board during his regular CEO’s report.

ERCOT has now scheduled a Nov. 19 go-live date for the delayed $2.9 million upgrade to the congestion revenue rights system, having seen “substantial progress” since the last board meeting and resolving “vendor-quality issues,” Magness said.

A re-plan is expected in October for a $4.3 million credit monitoring and management system project, a complex process that reaches down to staff PCs and ERCOT’s server racks.

Looking ahead, Magness previewed a pair of security-related NPRRs wending their way through the stakeholder process. NPRR899 looks at whether digital certificates are still state-of-the-art and creates an opt-out provision, while NPRR902 will provide a definition for ERCOT critical energy infrastructure information and a clear line between public and confidential information.

Magness also said NERC’s Accelerated Generation Retirements Special Reliability Assessment report will focus on the PJM and ERCOT systems. The assessment is expected to be discussed during the organization’s November Board of Trustees meeting.

West Texas Heat Could Mean More Wind Energy

Senior Meteorologist Chris Coleman shared an initial analysis of the effect of summer heat on wind generation, which seemed to bear out his hypothesis that more heat equals more wind energy.

“My theory is that hotter-than-normal weather equals greater-than-normal wind generation,” he said.

Coleman’s study came at the request of Director Clifton Karnei, who represents the cooperative segment. It compared June’s average high temperatures in Midland, Texas, with the average daily percentage of installed wind capacity at 5 p.m., dating back to 2014.

Over the past five summers, Midland’s average high temperature peaked at 98.3 degrees Fahrenheit in 2018 during the state’s fifth-hottest summer on record. That coincided with a 39.2% installed wind capacity production mark. Only June 2014’s 42.9% figure, when highs in Midland averaged 95.7 F, was higher.

The other three years saw average highs between 91.7 and 96.9 F, with no average daily wind capacity above 28.9%.

Coleman said there were some exceptions to his theory, but he couldn’t explain why. “I will need to chisel down into a day-by-day look,” he said.

His preliminary winter forecast projects near-normal weather. He cautioned the board that winter is a “different animal” in how it correlates to peak loads.

“If I forecast colder-than-normal weather, it may not mean a higher peak,” he said, noting that last winter’s coldest day in ERCOT since 2011 (Jan. 17) came during the state’s 75th coldest winter. “If I had to adjust [the forecast], I’d adjust it warmer.”

Staff Files Governance Changes with PUC

ERCOT has filed amendments to its Articles of Incorporation (which has been renamed the Certificate of Formation) and to its bylaws with the PUC (Docket No. 48677).

The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership by a Sept. 12 deadline. They had been previously approved by the board in August. (See “Special Membership Meeting to be Set,” ERCOT Board of Directors Briefs: Aug. 7, 2018.)

Assistant General Counsel Vickie Leady said she expects the PUC to confirm the articles and bylaws amendments by its Dec. 20 open meeting.

Board Clears 10 Revision Requests on Consent Agenda

The directors unanimously approved seven NPRRs, a change to the Nodal Operating Guide (NOGRR) and two revisions to the Planning Guide (PGRRs) on their consent agenda:

- - NPRR845: Incorporates numerous revisions to the reliability-must-run process, including standardizing the standby cost in terms of dollars per hour instead of dollars per megawatt; adjusting availability metrics used in settlements to the current operating plan rather than the availability plan; clarifying a resource’s post-RMR status and requiring an entity to submit a resource-notification change no later than 60 days before an agreement’s conclusion; allowing ERCOT to retain a mutually agreeable third party to help evaluate submitted RMR budgets; and modifying the RMR agreement to require detailed budgeted costs with or without capital expenditures.
  - NPRR857: Creates “direct current tie operator (DCTO)” as a market participant role, clarifying the obligations of entities operating DC ties interconnected with the ERCOT system.
  - NPRR869: Requires generators over 1 MW within a private use network (PUN) to provide modeling information to ERCOT if they are not: registered with the PUC as a power generation company; part of a PUN with more than one connection to the ERCOT grid; or registered to provide ancillary services. The change includes a netting exemption for a small qualifying facility that provides energy to a customer behind a single point of interconnection. It also deletes a reference to the now-expired System Benefit Fund.
  - NPRR880: Requires ERCOT to publish shift factors for PUN settlement points for the real-time market, as is currently done in the day-ahead market.
  - NPRR883: Removes the real-time reliability deployment price adder from the real-time settlement point price to avoid double payment when resources have received an ancillary services assignment.
  - NPRR888: Clarifies the four-coincident-peak adjustment methodology implemented in conjunction with NPRR830.
  - NPRR890: Aligns protocol price calculation formulas with ERCOT’s calculation of the real-time LMP at a logical resource node for an online combined cycle generation resource, distinguishing between scenarios in which the unit is online or offline.
  - NOGRR177: Revises the NOG to be consistent with NPRR857’s language on DCTOs.
  - PGRR063: Outlines the process for evaluating the reliability impact of transmission projects 100-kV or above that are expected to be in service before the next Regional Transmission Plan’s completion but that were not included in the current plan, a Regional Planning Group project submission, or a generation interconnection or change-request study.
  - PGRR064: Requires resource entities to verify that dynamic devices used for reliability reflect their operating characteristics.