AUSTIN, Texas — ERCOT’s legal department again delayed votes endorsing final changes to the grid operator’s bylaws and articles of incorporation, saying it needed additional time to evaluate a last-minute comment from Luminant.

Assistant General Counsel Vickie Leady told the Technical Advisory Committee last week that legal staff would delay final votes on the revisions until the August set of leadership meetings. She said ERCOT and Luminant are “on the same page,” but they are trying to figure out the language.

“We appreciate having people poke holes in the language,” Leady told the TAC during its May 24 meeting. “Given the importance and relative permanence of the language, we need more time to address it. Once we put stuff in the bylaws, it’s there for a long, long time.”

Legal staff had originally planned to put the proposed changes up for votes in April but pushed the final recommendation back to the June Board of Directors meeting. (See “ERCOT Legal Staff Delays Bylaw Revisions,” ERCOT Technical Advisory Committee Briefs: March 22, 2018.)

Luminant sent its comments after working hours on May 23, suggesting clarifications to the proposed affiliate definition. The generating company added language to the definition that read:

“A person who is not controlling, controlled by or under common control with another person as described above may nonetheless be determined to be an affiliate of another person, if ERCOT or a member alleges that such exercises directly or indirectly, through one or more intermediaries, substantial influence over another person. Such a determination may be made by the board only after notice and an opportunity for hearing at an ERCOT board meeting. The burden of proof to show substantial influence is on ERCOT or the member alleging such influence.”

Luminant’s Ian Haley apologized for the late filing, saying it was the first time the company had been able to gather together its legal counsel.

The company also suggested a central repository for the various clean and red-lined documents, which Leady said ERCOT would follow. Legal staff also plan to hold a workshop following the June board meeting to “facilitate a final set of comments.”

Leady said she has received no stakeholder comments on the articles of incorporation but that they should “travel together” with the bylaw changes.

Southern Cross Transmission (SCT) also filed comments requesting a delay of a decision regarding in which market segment it should be placed. SCT believes it should be included in a newly created DC Tie Operator segment.

Cratylus Advisors’ Mark Bruce, who represents the project’s developers, said SCT hopes that when the market segment question is revisited, “greater stakeholder familiarity with the SCT project will ease some of the controversy currently associated with the question of the appropriate market segment assignment for DC tie operators.”

Bruce wrote that he saw no harm in delaying the membership decision. Leady said staff would “reinitiate” stakeholder discussion of the segment definition “upon further certainty that the SCT project will be interconnected” to ERCOT.

Southern Cross is a proposed HVDC transmission project in East Texas that would be capable of shipping more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Texas’ Public Utility Commission last year directed ERCOT to address several issues as a condition for energizing SCT’s project. The conditions include determining “the appropriate market participation category for [SCT] and for any other entity … for which a new market-participant category may be appropriate” (Project No. 46304).

Staff Recommend 2 Transmission Projects

The committee endorsed staff’s recommendation of a $327.5 million Oncor project that addresses reliability concerns in ERCOT’s Far West region.

If approved by the Board of Directors in June, Oncor’s work will include building 40 miles of new 345-kV lines on double-circuit structures, adding two new 600-MVA, 345/138-kV autotransformers at a switch station, installing a second 345-kV circuit between Odessa and Riverton, and building two 20-mile segments of 138-kV line on double-circuit structures.

Construction is expected to begin next year, with completion in 2023.

Staff said the project will provide operational flexibility and resolve potential reliability issues in the face of oil and gas-related load growth.

Staff also shared with TAC members an additional study evaluating a Rayburn Country Electric Cooperative proposal to transfer its existing facilities and load into ERCOT, a plan filed last year with the PUC (Docket No. 47342).

The ISO said it is now recommending a “modified alternative option” to integrating Rayburn’s load, following an Oncor study of a transmission alternative than eliminated a 345-kV interconnection.

Staff concluded the second option, which still includes two 138-kV interconnections, has “similar reliability and long-term load-serving capability.” However, the modified alternative has a lower estimated capital cost of $31.7 million, leading ERCOT to propose the Oncor suggestion.

Staff’s initial study indicated capital costs of $41.7 million.

Rayburn, which sits on the ERCOT-SPP seam in East Texas, has proposed transferring load and transmission facilities into ERCOT. The co-op is an SPP member, but only about 150 MW (or less than 20%) of its load and 160 miles of its transmission sit in the Eastern Interconnection. (See “ERCOT, SPP Agree to Rayburn Country Migration Studies,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)

Members Approve Subcommittee’s Restructuring

Members unanimously approved a task force’s recommendation to designate the Commercial Operations Subcommittee (COPS) and several of its working groups as inactive, agreeing that it has reached a “steady state” situation concerning market communication and settlement issues.

The Wholesale Market Subcommittee will inherit the Settlement Working Group and the Commercial Operations (COP) Market Guide, while the Retail Market Subcommittee will pick up the Profiling Working Group, Load Profiling Guide and market communications.

The TAC Subcommittee Restructuring Task Force brought its recommendations to the committee in February. (See “Committee Endorses Task Force Restructuring Recommendations,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

The restructuring will require the following changes for the COP Market Guide and the Load Profiling and Retail Market guides:

• COPMGRR047: Relocates the COP guide to the WMS, moves other portions of the manual to the retail guide and removes language that is no longer applicable from the COP guide.
• LPGRR064: Moves the Load Profiling Guide and load-profiling responsibilities from COPS to the RMS and removes language from the guide that no longer applies.
• RMGRR151: Incorporates the market notice communication process and renewable energy credit information from the COP guide into the retail guide.

The task force will continue its development of a “three strikes” attendance policy for TAC and its subcommittees, whereby seated segment representatives that miss three meetings or fail to assign an alternate for those meetings will lose their seats. It will also aid the RMS with moving RMGRR151’s market notice process language into a standalone Other Binding Document.

TAC Re-elects Helton as Chairman

TAC once again elected Bob Helton as its chair, an action required following the latest change in his employment status and market segments.

Helton moved from ENGIE to Dynegy last year when the latter bought the former’s 17 U.S. power plants. He left Dynegy when it was subsequently acquired by Vistra Energy, recently rejoining ENGIE as its director of government and regulatory affairs.

“I know you guys may not know this person, and I know we’ve elected him three times in the last seven months,” began Sharyland Utilities’ B.J. Flowers as she teasingly nominated Helton for the vacant chair position.

Helton thanked the members for their support, saying he hopes to finish out the year as committee chair.

“Of course, you never know, the way jobs change around here,” he joked.

Committee Endorses 4 NPRRs, 7 Other Changes

The committee endorsed four Nodal Protocol revision requests, a revision to the Nodal Operating Guide, a pair of Other Binding Document revisions, two changes to the Planning Guide and two changes to the Verifiable Cost Manual.

• NPRR847: Incorporates an intraday or same-day weighted average fuel price into the mitigated offer cap to ensure that resources are capped at the appropriate cost during high fuel price events and LMPs reflect the true incremental cost of fuel.
• NPRR851: Establishes a clearly defined disconnection process within the market rules applicable to a transmission voltage connection to the grid that uses one electrical connection for both generation and load services.
• NPRR867: Caps the amount of each counterparty’s available credit limit locked for congestion revenue rights auctions at the pre-auction screening credit exposure amount.
• NPRR870: Deletes the gray-boxed requirement for ERCOT to post a forward adjustment factors summary report on the Market Information System’s certified area. The information in this report is already provided on each counterparty’s estimated aggregate liability summary report.
• NOGRR176: Clarifies that all transmission owners and qualified scheduling entities representing resources can participate in ERCOT hotline calls.
• OBDRR004: Revises the risk-weighting factors available for assignment to each emergency response service (ERS) time period; describes the process for updating the ERS time period expenditure limits for any subsequent standard contract terms (if money is needed to fund) and the ERS renewal contract period; and updates a table to reflect the risk-weighting factors’ proposed changes.
• OBDRR005: Revises the generic transmission constraint (GTC) shadow price cap that is used in SCED for base case constraints from $5,000/MWh to $9,251/MWh. The revision also updates the associated examples in SCED and makes an administrative edit to a protocol reference.
• PGRR059: Includes Regional Planning Group-related changes intended to improve and clarify existing processes.
• PGRR060: Updates the reliability performance criteria by defining a DC tie’s unavailability as a new contingency and clarifies the voltage level of transformers referred to in the reliability performance criteria.
• VCMRR020: Delays VCMRR014’s sunset date to permit stakeholders additional time to find a long-term solution that determines an appropriate adder for coal- and lignite-fired generation resources.
• VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing language providing for make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.

— Tom Kleckner