After two months of significant discussion at various levels of ERCOT’s stakeholder process, the Technical Advisory Committee on Thursday unanimously approved compromise language eliminating the reduction of congestion revenue rights (CRRs), or “deration.”

The nodal protocol revision request (NPRR821) eliminates the deration process for resource node-to-hub or load zone CRRs. Stakeholders drafted compromise language in the Protocol Revision Subcommittee (PRS) to address concerns that the deration process interfered with hedging behavior.

In the end, stakeholders agreed that the language deters the exploitation of CRR gaming opportunities that pose the most risk to loads, and continues the policy of sharing CRR underfunding costs established when the nodal market went live.

“Stakeholders have been working on and debating a solution for three months now,” Reliant Energy’s Bill Barnes said. “Parties on all sides have had follow-up discussions and gotten comfortable with what’s proposed here.”

“This solution is better than what we had,” Shell Energy’s Greg Thurnher said. “I do believe this particular solution solves the vast majority of the needs. … I suggest we test the waters with this solution and revisit it in the future. The seemingly yearlong discussion may have been unnecessary, but we’ve rid ourselves of unnecessary processes.”

The new process will be implemented by July 1, 2019, despite a request by the Lower Colorado River Authority (LRCA), one of those pushing for the change, to deploy it as soon as possible.

“As soon as it’s implemented, we eliminate the risk we’re concerned about,” LCRA’s John Dumas said.

The TAC tabled the NPRR during its July meeting, then remanded it back to the PRS in August. (See “CRR Deration Remanded Back to Subcommittee,” ERCOT Technical Advisory Committee Briefs: Aug. 24, 2017.)

Revision Request Would Create Panhandle Hub

Stakeholders also easily approved NPRR817, which will allow additional trading liquidity and forward price discovery in the Texas Panhandle with the creation of the “Panhandle 345-kV Hub.” The revision excludes the new hub from the existing ERCOT-wide hub and bus average calculations.

Citigroup Energy’s Eric Goff argued the NPRR’s estimated $150,000 to $200,000 implementation costs would be a one-time hit, eased by additions of new hubs in ERCOT’s southern or western footprint.

“I anticipate further need for additional hubs that will reduce the cost substantially each time,” he said. “This NPRR allows very simple hedging for the Panhandle.”

Goff explained that, under current practice, any generator in that area seeking to hedge must pick a resource node that could at times be subject to a random outage because of maintenance or some unforeseen event.

“This will improve the commercial hedging and has one-time upfront costs that address concerns raised by those comments [about costs],” he said.

Staff agreed, saying future hubs could be created at 30 to 40% of the cost of the new Panhandle hub.

TAC Tables Several Market Changes

After a roll call vote following vigorous discussion, stakeholders agreed to table NPRR815, which would revise the current limit of 50% for load resources providing responsive reserve service (RRS) to any capacity above a minimum level of RRS offered by resources providing primary frequency response (PRF).

Katie Coleman, legal counsel for Texas Industrial Energy Consumers, asked to table the NPRR following the filing two days earlier of a related revision request (NPRR848), which would create separate pricing for load resources and PRF-capable resources providing RRS. Coleman said she had not yet been able to gather her group’s position on the latest change.

“There’s a relationship between the issues in this NPRR and the issues in 848,” she said. “If 848 moves forward, we would want not only this but probably much more significant changes to how the load megawatts are determined.”

The motion to table was opposed by several generating members, who feared reliability issues. Bob Wittmeyer, a consultant with Resolved Energy, pointed to the change’s estimated $3 million in average savings and urged the TAC to considering rejecting the motion to table.

“Tabling this today is not a one-month delay; it’s a two-month delay,” he said. “There are two groups of people in this room — the ones that sell ancillary services and want to table it, and the ones that get fired if we have a reliability problem. The ones that get fired if we have a reliability problem are saying this is not a reliability problem. They’re also saying we can save $3 million a year.”

ERCOT staff pushed back against claims that grid reliability would be harmed, with Sandip Sharma saying he wanted to “rule out reliability issues.”

“This NPRR allows ERCOT to procure ancillary services in a more cost-effective way, while it is meeting its reliability obligation,” he said. “In the absence of this NPRR, we would do exactly the same study we do today, but we would increase the number, because there is a limitation on load resources. The loads are not allowed to provide more than 50%, especially during the time when they are more effective solving reliability issues … that’s the main issue here.”

Only three members eventually opposed tabling the NPRR.

The committee also tabled NPRR825 and a verifiable cost manual revision request (VCMRR019). Staff said it missed a system requirement in the NPRR’s impact analysis (IA), which likely would increase the costs of issuing DC tie curtailment notices before curtailing the tie’s load.

“We’re reviewing the IA process, so we can improve and bring things to you more accurately,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “That may require us taking more time than we have on some of these, but ERCOT-wide, from the executives to every person, we’re not satisfied with how this is playing out.”

PRS Adds Resource Definition Task Force

The TAC approved a previously tabled revision request (NPRR829), despite a revised impact analysis of between $200,000 and $300,000. The increase came after staff added previously overlooked distributed generation resources in its analysis.

The change requires the day-ahead market to use telemetered data from non-modeled generation to more accurately calculate collateral requirements for qualified scheduling entities (QSEs). The NPRR increases day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.

“If we don’t do these infrastructure changes now, it’ll be sometime in the future,” Thurnher said. “It’s not a small segment anymore, in terms of megawatts. The class that will use this will continue to grow in the future. This levels the playing field. Right now, distributed generation does not get the same credit treatment as traditional generation does when it injects into the system.”

The NPRR passed, with three members voting against it.

The committee unanimously approved single NPRRs, nodal operating guide requests (NOGRR) and system change requests (SCR). It also approved ERCOT’s high-impact transmission element list, which doubled last year’s list at 222 elements.

• NPRR840: Synchronizes implementation of NPRR782, which removes inconsistencies in protocol language governing the settlement of ancillary services for resources unable to deliver on their responsibilities due to transmission constraints. The change removes the two-hour advance notice period inadvertently left in the protocols when 782 was approved, allowing ERCOT to declare an ancillary service as infeasible in either the adjustment or operating period.
• NOGRR173: Removes orphaned grey-boxed language in order to align with NOGRR166, which struck language added with NOGRR084. The change cleans up removal of other items related to NOGRR084 and NOGRR166, but does not remove any current reporting requirements in Section 9.4.3 (Resource-Specific Responsive Reserve Performance)’s duplicative language to the current black-lined language.
• SCR791: Populates unused megawatt price values in SCED generation-resource data energy-offer curves with null values rather than zero. The zero values make the energy-offer curves non-monotonic and are indistinguishable from valid zero offers.

— Tom Kleckner