AUSTIN, Texas — An attempt by ERCOT legal staff last week to alert stakeholders that qualified scheduling entities (QSEs) will soon be required to submit certificates for the resale of electricity resulted in a bit of a kerfuffle.

Stakeholders pushed back against the proposal during the Technical Advisory Committee meeting Wednesday, complaining about what they saw as an added compliance burden and asking to see the legal opinion behind the proposal.

ERCOT Senior Corporate Counsel Erika Kane held firm, beginning her responses to repeated questions with, “Again…”

Other legal staff began filtering into the meeting room, with General Counsel Chad Seely eventually joining the fray.

“I haven’t heard all the discussion. I just got text messages,” Seely said, taking a seat at the table.

In teeing up the subject, Kane said that electricity sold in Texas for end use is a taxable good subject to sales tax, unless a tax exemption applies. The purchaser — the QSE — claiming a “sale for resale” exemption must provide a resale certificate to the seller to establish an exemption from sales tax. Tax-exempt entities, such as municipalities and cooperatives, can choose to provide a tax-exemption certificate.

Kane said ERCOT was only asking QSEs to conform with practices followed by other RTOs and ISOs, who have determined that their role as central counterparty raises a need for the certificates’ submission.

“We came to conclusion that looking at risk versus burden, this is the right path forward,” she said.

The subject had been discussed at the board level and with outside legal counsel, but not with stakeholders. Seely said that “through a lot of discussion,” staff felt it necessary to put in place a process to gather the sales tax resale certifications.

“Help us understand the onerous burden placed on QSEs to fill out this documentation,” he told stakeholders.

Reliant Energy Retail Services’ Bill Barnes said that while the certification may be simple, “it feels like ERCOT has had an awakening or a new interpretation of the protocols that has caused a concern and proposed to be resolved by pushing the burden onto all the QSEs.”

“It adds to the host of all other documentation we have to file when we register a new QSE or change a name and address, which some of us do quite a bit,” Barnes said. “It’s another form and requirement we need to remember to do, when it appears to us there’s an easier way to do it. We’re not getting a good answer as to why there’s not a simple statement in the protocols that clarifies ERCOT can’t and does not sell electricity to end-use customers.”

Noting the layers of laws ERCOT operates under, Seely said, “You can’t place a requirement that would usurp the Texas tax code in the protocols.”

Seely said there was no outside legal opinion to share with stakeholders — “Everything I’m saying has been run through outside counsel,” he said — and he seemed nonplussed when one member asked whether the state’s comptroller could come to the committee and offer its opinion.

“You want the comptroller to come into this forum?” Seely asked.

“The comptroller hasn’t had a problem with how we’ve operated for 19 years,” Morgan Stanley Capital International’s Clayton Greer said. “That’s baffling to me,” he added, referring to ERCOT’s proposed change.

“I don’t know why it’s baffling,” Seely responded. “Just because the comptroller hasn’t said anything doesn’t mean we shouldn’t be addressing the issue.”

Staff had intended to put out a market notice after first giving the committee a heads-up. Now they plan to return to the committee in November with additional information and a new plan for moving forward.

ERCOT Likely to Reprice 13 Operating Days

Staff told the committee they plan to ask the Board of Directors for permission to revise day-ahead and real-time prices for 13 operating days. ERCOT protocols require the grid operator to resettle prices to right the wrongs of any data mistakes.

Kenan Ögelman, ERCOT’s vice president of commercial operations, assured market participants that the price corrections will be made, but he said staff first need to finish their analysis. That data will be shared with the Wholesale Market Subcommittee on Nov. 6 and the TAC during its Nov. 20 meeting.

Ögelman said a May update to the ERCOT’s market management system, intended to model withdrawn outages in the day-ahead market and for reliability unit commitment where facilities were being restored, instead modeled all withdrawn outages. Outages withdrawn before their planned outage start date were erroneously modeled in the market as out of service.

“The transmission and distribution providers did everything exactly as they were supposed to,” Ögelman said. “It’s how our systems took that in and what they did with it. It was not about anything coming in incorrectly externally.”

“ERCOT should correct prices when they screw up the data,” said Beth Garza, director of the grid operator’s Independent Market Monitor. “This is an ERCOT-screwing-up-the-data thing. ERCOT has an obligation to correct and inform.”

When ERCOT became aware of the error in late September, staff began investigating prices for the May 30 to Sept. 25 operating days, Ögelman said. A patch was placed into production Sept. 26.

Staff identified erroneously modeled outages for the Aug. 20-21 and Sept. 16-25 operating days. They determined that only the Sept. 16-23 prices were eligible for board review.

Ögelman said the August prices could not be corrected, as they were outside the timeline for board review. However, staff were able to re-price the Sept. 24-25 days before the prices became final.

On Oct. 24, ERCOT notified market participants that a recent update to the energy and market management system led to incorrect real-time prices Oct. 16-21 for certain settlement points and energy metered for resources. The grid operator said it has corrected the Oct. 21 operating day prices, which were still within the review timeline.

ERCOT said it would begin the resettlement process about a week after the Dec. 10 board meeting.

TAC Approves BESTF Leaders, Scope

One month after approving the creation of a task force to best integrate battery storage into ERCOT, the TAC endorsed the group’s leadership and charter. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)

Members unanimously backed the Battery Energy Storage Task Force’s selection of ERCOT’s Ken Ragsdale as its chair and Lower Colorado River Authority’s Andy Nguyen to represent stakeholders as the vice chair.

Ragsdale demurred to Sandip Sharma, ERCOT’s manager of operations planning, as being the group’s real leader despite the title. “He’s our guiding light,” Ragsdale said.

According to its charter, the BESTF will develop policy recommendations for the TAC’s consideration that relate to the integration of battery energy storage resources into the ERCOT system.

Two issues are currently “pressing” on the task force, Ragsdale said. The first is filing Nodal Protocol revision requests (NPRRs) related to a single model to be incorporated along with real-time co-optimization upgrades in the first quarter of 2020. The second is beginning discussions by midyear on how to integrate hybrid resources (battery and thermal) and DC-coupled resources, where the battery and solar are both behind the inverter.

The group defines a single model as a future approach where the battery is a single resource. It defines the combo model as the current approach representing a battery as a generating resource and a controllable load resource.

“We hope to come up with a proposal in early January and get some ideas on what the solution is before the second quarter of 2020,” Ragsdale said.

The BESTF held its first meeting Oct. 18 and has two more scheduled this year. It plans to follow the same review process as the Real-Time Co-optimization Task Force (RTCTF) by first developing principles or key topic/concept (KTC) recommendations that will be used to write the revision requests. The group plans to bring its first KTCs to the TAC’s Nov. 20 meeting.

“We’re still doing our homework,” Ragsdale said. He said the group is checking with other grid operators, developers and the Electric Power Research Institute to understand the design drivers.

RTC KPs

The committee endorsed the largest batch of real-time co-optimization key principles — 19 in all — yet offered up by the RTCTF.

The principles (KPs) fall under three categories:

• KP 1.1 (5): Defines ERCOT’s parameters in representing the disaggregation of ancillary service (AS) demand curves so that potential future changes in values and distribution will not require system changes.
• KP 1.3 (1)-KP 1.3 (11): Outline the key mechanisms and timelines for submitted AS offers and the AS considered and awarded under real-time co-optimization.
• KP 5 (1)-KP 5 (6): Identifies day-ahead market changes necessary to align day-ahead AS procurement with real-time co-optimization’s implementation.

ERCOT’s Matt Mereness, who chairs the RTCTF, promised more than 20 items in KP 5 before the group is finished.

The task force has six meetings left, with the final one scheduled for Jan. 22. “We’re going right up to the wire,” Mereness said.

Members Endorse 9 Revisions

TAC members approved six NPRRs, a change to the Nodal Operating Guide (NOGRR) and two system-change request (SCRs):

• NPRR849: Clarifies the range of voltages at a generation resource’s point of interconnection and circumstances for which its reactive capability must be designed to meet.
• NPRR902: Defines ERCOT Critical Energy Infrastructure Information (ECEII), adds items that are considered ECEII, specifies the restrictions imposed upon parties that receive or create ECEII, and provides a framework for the submission of ECEII to ERCOT.
• NPRR937: Removes distribution-level and non-settlement metered block load transfers from deployment during Level 2 energy emergency alerts (EEAs).
• NPRR965: Excludes a quick-start resource’s five-minute intervals from the generation resource energy deployment performance calculation when the resource is engaging in the decommitment process or telemetering “shutdown” status.
• NPRR968: Updates Protocol language to comply with NERC reliability standards BAL-002-3 (Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event) and EOP-011-1 (Emergency Operations) by changing the physical responsive capability trigger for a Level 3 EEA to match a new most severe single contingency of 1,430 MW, to be implemented on Jan. 1, 2020.
• NPRR969: Clarifies ERCOT is the final authority in qualifying market participants.
• NOGRR197: Updates the responsive reserve service (RRS) manual deployment to provide flexibility in the amount of RRS capacity that is released to the security-constrained economic dispatch engine during scarcity conditions.
• SCR800: Incorporates DC tie-scheduled ramp into SCED by updating the resource limit calculator’s formula to determine the generation-to-be-dispatched value and adding a scheduled five-minute DC tie ramp rate (DCTRR). The DCTRR will be calculated from the scheduled systemwide DC tie ramp multiplied by five and a configurable factor to capture the scheduled five-minute ramp.
• SCR805: Allows ERCOT to automatically provide certain reports to requesting transmission service providers (TSPs) before they are posted to the market information system public area. TSPs will receive the reports once a formal request has been approved by ERCOT.

— Tom Kleckner