ERCOT staff told stakeholders last week they are working to reduce errors following two recent unrelated events that led to price corrections and resettlements.

Kenan Ögelman, ERCOT’s vice president of commercial operations, shared with the Technical Advisory Committee the speaking points he will deliver to the Board of Directors during its Oct. 12 meeting. He said the grid operator has several initiatives that will cut down on errors and price corrections and will also elevate testing, “which is kind of our last line of defense.”

“We’re making additional revisions and [instituting] controls around market changes that impact pricing,” Ögelman said during the TAC’s meeting Wednesday. “We’re reviewing all of our manual processes … especially around resettlement items.”

Ögelman said several revision requests are being drafted to address the problem. ERCOT is also evaluating protocol language to address recent discussions the Public Utility Commission has had in open meetings. While discussing a telemetry error that led to a price correction Sept. 14, PUC Chair DeAnn Walker said, “We shouldn’t wait for there to be a really huge event.” (See Texas PUC Rejects Call to Reprice Error.)

In February, staff updated the network model by adding dynamic ratings for three transmission transformers. A software error erroneously applied the new ratings to three unrelated 345/138-kV transformers in addition to the intended transformers. ERCOT didn’t discover the cause of the error and the affected transformers until July, when it issued a market notice.

Staff reviewed all binding transmission constraints in the day-ahead market between Feb. 14 and July 7, finding 67 operating days that had at least one constraint binding on one of the transformers. They also found one instance of binding transmission in the real-time market.

Staff will ask the ERCOT board to review day-ahead and real-time prices for the June and July operating days that are eligible for repricing, as required by the grid operator’s protocols. David Maggio, ERCOT’s director of market design and analytics, said the pricing changes were “fairly minimal,” but balancing account changes resulted in an overpayment to load of about $8,000 for June and an underpayment to load of approximately $15,000 for July.

The real-time constraint resulted in a net settlement to counterparties of almost $47,000.

More recently, a manual update to the network model inadvertently disabled a remedial action scheme for four day-ahead market operating days in August. Staff were able to correct the prices before they became final during the last day and will ask the board to review the other three operating days.

Members Reject Ancillary Service NPRR

Members rejected a Nodal Protocol revision request (NPRR1025) that would remove the real-time online reliability deployment price (RDP) from ancillary service imbalance calculations. The measure was approved by an 18-10 margin, with two abstentions, but its 64% approval fell short of the two-thirds threshold for endorsement.

ERCOT’s Independent Market Monitor reiterated its opposition to the NPRR as written, citing what it said were two flaws.

“The first, and most important, is that it breaks a foundational principle in the market, that dispatch sent out by ERCOT should be the most profitable dispatch, given their offers and limitations. With this NPRR, in times of high ERS [emergency response service], that won’t be true anymore,” the IMM’s Steve Reedy said.

“Secondly, the [operating reserve demand curve] adder calculation is not affected by the ERS deployment,” he said. “That weight is carrying right now by the RDP adder. If you take that away from resources … that should raise the ORDC adder. We would support this with those associated indifference payments, which would be smaller than the megawatt implications in effect right now.”

The NPRR was drafted by the Lower Colorado River Authority. John Dumas, the public utility’s vice president of market operations, said it was driven by the divergence between the value of real-time reserves and day-ahead ancillary service prices during ERCOT’s 2019 energy emergency alerts, caused by including the RDP in the price of real-time reserves.

“LCRA believes that only the ORDC adder should be included in the price of real-time reserves,” Dumas said. “This removes what we believe is an undue risk to loads and generators for participating in the day-ahead ancillary service market. It removes the real-time deployment price adder and removes risk and cost.”

2% Solution: Monitor to Draft NPRR

Based on discussions with TAC leadership and the IMM, the Monitor will draft an NPRR to address a desk procedure left over from ERCOT’s zonal market, Ögelman said.

Several stakeholders had suggested such action when staff brought forward a discussion of the “2% rule” to the August TAC meeting. An artifact from the zonal market, which was replaced by the nodal market in 2011, the rule says generating units with shift factors of less than 2% should not be dispatched by the real-time market in response to transmission overloads. (See ERCOT Technical Advisory Committee Briefs: Aug. 26, 2020.)

The IMM in August said it believes the 2% rule should be eliminated and all congestion priced in real time, regardless of generation’s effect. “Prices matter,” IMM Director Carrie Bivens said during the discussion.

“I presume [the Monitor will] be putting the [shift-factor] percentage at zero, and we’ll see how that progresses,” Ögelman said. “Stakeholders can modify that as they see fit.”

He said ERCOT will take a position on the issue when comments are filed.

Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, ERCOT operators must verify that a mitigation plan or temporary outage action plan exists for the contingency, and they are to review the plans with the affected transmission owner. If no plans exist, then the operators are to develop a mitigation plan with ERCOT’s operations support engineer. If no plans have been developed within 30 minutes, the operations desk issues a transmission watch, a step down from an emergency.

TAC Adds 10 Change Requests to List

TAC Chair Bob Helton complimented the committee for its virtual work this year, noting that it has passed 79 revision requests, with 65 more in the pipeline, while working from home.

“That says a lot about how we’ve progressed in troubled times,” Helton said.

The committee then passed a combination ballot, with an abstention, that added 10 more RRs to the approval list.

In a separate vote, the TAC approved the annual update to the major transmission elements list. Four members abstained from the vote.

One of the endorsed changes, a revision to the Planning Guide, will likely be appealed during the October board meeting. The change (PGRR077) clarifies that ERCOT’s transmission planning analysis will assume DC tie flows are curtailed when necessary to meet reliability criteria.

Shams Siddiqi, with Rainbow Energy Marketing, said the current $23/MWh transmission charge for DC tie exports during summer off-peak hours is a significant barrier to exporting energy. It also suppresses the market’s opportunity to address the allocation of sunk costs, adversely affecting decisions to consume or export, he said. Only the Public Utility Commission can modify the DC tie export’s Tariff, he said.

“Until and unless the PUC eliminates or significantly reduces the DC tie export tariff, the only equitable treatment of DC tie load is to treat DC tie load as other load in the ERCOT reliability transmission planning process,” Siddiqi said in filed comments. “If the PUCT were to eliminate the DC tie export tariff … [it] would remove an inefficient barrier to trade.”

Staff told Siddiqi he could appeal the revision request when it comes before the board next month. Helton noted that at least one PUC commissioner will call in to the meeting.

“If parties or stakeholders want to do it, they can file a petition for a rulemaking at the PUC,” said Katie Coleman, who represents Texas Industrial Energy Consumers. “The issue of transmission allocations is a really old issue that’s come up multiple times. I think the PUC is aware of these issues and can address them, if [it] wants to.”

The combo ballot included six other NPRRs, two changes to the Nodal Operating Guide (NOG) and a system change request (SCR):

• NPRR999: Revises protocol language on DC tie schedules and creates a section related to ramp limitations on DC ties. It is intended to clarify that when ERCOT determines system conditions show insufficient ramp capability to meet the sum of all DC ties’ scheduled ramp, it will curtail schedules on a last-in, first-out basis. Before curtailing DC tie schedules, ERCOT, with enough time, may request one or more qualified scheduling entities to voluntarily resubmit e-tags with an adjusted ramp duration.
• NPRR1033: Specifies that ERCOT does not have an obligation to pay interest on former market participants’ cash collateral balances upon its determination that financial security is no longer needed to cover the terminated participant’s potential future obligations.
• NPRR1035: Requires ERCOT to publish all DC tie schedules 60 days after the operating day.
• NPRR1036: Clarifies some processes associated with late payments and payment breaches and aligns protocol language on market participants’ registration and qualification with language in the standard form market participant agreements.
• NPRR1037: Corrects switchable generation resources’ (SWGRs) settlement when instructed to switch from a non-ERCOT control area to the ERCOT control area. The NPRR includes the SWGR’s operational costs in the non-ERCOT control area in calculating switchable generation operating cost for resources with approved verifiable costs.
• NPRR1038: Establishes a limited exemption from reactive power requirements for some energy storage resources (ESRs). The exemption is available only to an ESR that achieved initial synchronization before Dec. 16, 2019, and applies only to the extent the resource is unable to comply with the reactive power requirements when it is charging. To qualify, the ESR’s operator must submit a notarized attestation to ERCOT that says the ESR would be unable to comply with the requirements without making physical or software changes.
• NOGRR214: Describes ERCOT’s process for collecting geomagnetically induced current monitor and magnetometer data to satisfy requirements of NERC Reliability Standard TPL-007-3 (Transmission System Planned Performance for Geomagnetic Disturbance Events).
• NOGRR218: Removes the requirement that disturbance-monitoring equipment owners annually submit their databases to ERCOT.
• SCR811: Adds a predicted five-minute solar ramp to the resource-limit calculator’s formula for calculating the generation-to-be-dispatched value. The solar ramp rate will be calculated from the intra-hour PV power forecast and the short-term PV power forecast.