AUSTIN, Texas — ERCOT stakeholders last week tabled a proposal to eliminate the reduction of congestion revenue rights (CRR) payments — “deration,” in the ERCOT vernacular — after the measure failed to pass the Technical Advisory Committee.

The nodal protocol revision request (NPRR821) would reverse the deration-settlement mechanism, which was introduced to deter market manipulation but has resulted in large financial losses to generators.

Lower Colorado River Authority’s Randa Stephenson recalled when her company lost $2 million over three months because of a forced outage at one of its power plants. She said generators face downside risk because CRRs are settled in the day-ahead market, which sometimes doesn’t align with real-time outcomes.

“All the generators are trying to do here is the right thing,” said Stephenson, a former TAC chair. “We’re trying to hedge our congestion risk in the real-time, and we don’t feel like we can do that right now.”

The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. CRR payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.

Stakeholders willing to eliminate CRR deration have expressed concern that NPRR821 unfairly changes allocations so that load will bear 100% of the risk associated with deration. Other participants countered that the shortfall is borne by CRR holders when a balancing account is exhausted and said the shortfall risk is not exclusive to load.

“We think the deration process that’s in place now is appropriate,” said Amanda Frazier of Luminant, the only generator to vote against eliminating CRR deration. “It’s a risk that can be managed. It allows for appropriate values of CRR on paths where we have unexpected outages that cause those paths to be oversold.”

TAC’s consumer and independent retail electric provider (REP) segments voted unanimously with Luminant against the measure, providing 10 of the 12 “no” votes. The 15 favorable votes were not enough to meet the required two-thirds threshold to approve the measure.

“The real issue is the risk itself is not changing … and you’re transferring the risk to load, instead of the market participants that are participating in the CRR auction,” said one REP representative, Read Comstock of Source Power & Gas. “I have sympathy for LCRA’s issue, but I’m assuming the price they offered considered that risk that existed. This same risk is going to be transferred to load with this NPRR change.”

“This NPRR is just like insurance. You overpay for insurance, and I think we’re going to wind up overpaying for the CRRs,” said Morgan Stanley’s Clayton Greer, who voted to eliminate deration. “Right now, we have hedges that don’t work when you need them. It’s like buying flood insurance that has an exemption for when it rains. Whenever the outages are taken, that’s when the congestion hits — and that’s when we actually need the coverage.”

Asked by stakeholders to weigh in, Beth Garza, the Independent Market Monitor, said she would leave the “very hard discussion” on money and value assessments to the TAC to decide.

“One of the aspects brought up in discussion that hasn’t been brought up today in the deration process is a way to manage potential manipulation,” Garza said. “I would argue it’s a very heavy-handed way to do that, and an unnecessary way to monitor for manipulative intervention in the CRR market. We don’t see a need for the current deration process.”

“This is very unique when it happens. It’s just the generators that get the derates and take the hit,” Stephenson said. “We’re trying to have a tool here that makes sense for us when we have these unique situations. It’s very hard to predict behavior if we’re going to have price blowouts on the upside, or CRRs get more expensive and give the load more money.”

Comstock urged stakeholders to remain engaged in the auction process. If not, he said, “we’re going to see CRR market participants push for more capacity to be sold at longer terms, because they’re not concerned about risk that exists if they are oversold.”

Stephenson, who was sitting in for John Dumas, the LCRA’s normal TAC representative, said she would bring back additional comments and math samples of the “unique situations” to provide a “deeper discussion” on the proposed change.

The motion to table passed by a 23-6 margin. Further discussions will take place at the Wholesale Market Subcommittee (WMS), and possibly the Qualified Scheduling Entity Managers Working Group, before returning to TAC.

“821 is getting rid of the entire deration process in order to fix a relatively small problem,” Frazier said. “There are very directed ways to address the LCRA issue. That’s an issue we are interested in trying to resolve as well.”

EEA Price Adder Change Tabled

The TAC also tabled for another meeting the only revision request that required significant discussion.

The Texas Industrial Energy Consumers has opposed NPRR768 throughout the stakeholder process. The NPRR would revise the categories of ERCOT-initiated actions, such as energy emergency alerts (EEAs), that trigger a real-time deployment adder so that prices reflect current system conditions.

“What ERCOT is really doing [when it calls DC tie imports] is replicating what a good market outcome would be,” said the TIEC’s legal counsel, Katie Coleman. “I know EEAs don’t happen often, but when they do, this could keep prices at the cap for significantly longer than they would be otherwise, and this is real money for my members.”

Referencing ERCOT’s systemwide offer cap of $9,000/MWh, Coleman said, “When you have an EEA in ERCOT and prices are at $9,000, everybody has every incentive to sell power into the ERCOT market.”

In her opening statement, Coleman also said the TIEC is concerned NPRR768 would apply to the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.

“When you’re talking about making a price adjustment for up to 2,000 MW of import, that starts to be real money,” she said.

In delaying action on the proposal in the past, stakeholders have noted the Southern Cross proposal was part of a recent docket before the Public Utility Commission of Texas (45624). In a resulting compliance docket (46304), the commission directed ERCOT to determine the project’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and whether any price adjustments are necessary. (See “Southern Cross HVDC Project,” ERCOT Technical Advisory Committee Briefs.)

Coleman said that the commission did not direct ERCOT to take specific action on NPRR768 or similar proposals, and that the ISO’s decision to file the NPRR, rather than leave the issue to stakeholders, was concerning.

“It’s not necessarily an appropriate role for ERCOT to be filing things that increase prices for customers,” she said.

Frazier said Luminant, a participant in the Southern Cross litigation before the PUC, asserted a price correction would be needed if ERCOT curtailed DC ties for reliability reasons. As the Southern Cross DC tie would be a merchant tie, she said, there was little reason to be concerned about replicating market actions.

“[Southern Cross] will have those incentives to operate, so this is more of a backup position,” Frazer said. “Where if ERCOT is taking command and control over someone’s assets that would otherwise be doing something else — and they’re doing that to preserve the reliability of the ERCOT system — then there should be a price correction for that action, which is how we treat other reliability actions.”

“The problem is, the Southern Cross facility [is] not being built to facilitate market transactions in and out of ERCOT,” Coleman countered. “It’s being built to facilitate moving wind from SPP and Texas to regulated utilities in the Eastern Interconnection so they can fulfill renewable requirements.

“We’re concerned the incentives won’t be appropriate for people to sell into ERCOT, even when prices are $9,000.”

The WMS will be given the opportunity to weigh in before the discussion is scheduled to resume during August’s meeting.

TAC Approves 5 Revision Requests

The TAC approved two additional NPRRs, revisions to the load profiling guide (LPGRR) and the retail market guide, and a system change request (SCR):

• NPRR822: Establishes the procedure for identifying resource nodes as an “other binding document” instead of a “business practice manual,” and adjusts the process for handling a retired resource’s nodes by allowing ERCOT to convert CRRs at that node to a different, nearby settlement point.
• NPRR833: Adjusts NPRR827’s language to account for the steady state when ERCOT implements the long-term, automated change affecting point-to-point (PTP) obligation bid clearing. The NPRR updates the day-ahead market optimization engine to address situations where a contingency disconnects a resource node. The engine will pick up the PTP megawatts and distribute them to other nodes, instead of ignoring them in a contingency analysis if that PTP sources or sinks at the disconnected point.
• LPGRR063: Clarifies the wording referring to the competitive retailer (CR) of record for certain profile type requests, and specifies only the CR of record may request certain profile assignments.
• RMGRR149: Clarifies certain communications processes for electric service identifiers (ESI IDs) without a REP.
• SCR792: Allows ERCOT to send the consecutive clock-minute average exceedances of Balancing Authority ACE Limit (BAAL) to the appropriate entities, and creates a situational awareness display in the information system’s public area that displays consecutive clock-minute average exceedances of BAAL.

— Tom Kleckner