ERCOT stakeholders last week debated an artifact from the old zonal market, eventually tabling action without a revision request to act on.

Staff brought forward to the Technical Advisory Committee discussion of the “2% rule,” which directs that generating units with shift factors of less than 2% will not be dispatched by the real-time market to respond to transmission overloads. A desk procedure in 2011, shortly after the nodal market went live, clarified the use of the 2% shift factor cutoff in real time.

Under the rule, if a transmission constraint exists for which there are no generator shift factors of at least 2%, operators must verify 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.

ERCOT has conducted several recent analyses on the effects of activating low shift-factor constraints in the economic dispatch engine. Staff found that the effect of activating the constraints is dependent on the system’s topology near the constraint and observed no oscillation in the resource’s output level.

The Congestion Management Working Group has been unable to reach a consensus on whether to eliminate the rule, despite working on the issue since last year.

“It feels like we’ve been talking about it forever,” said CPS Energy’s David Kee, who chairs the Wholesale Market Subcommittee, to which the working group reports.

ERCOT’s Independent Market Monitor, however, believes the 2% rule should be eliminated, with all congestion priced in real time, regardless of generation’s effect.

“Prices matter. The whole market is predicated on that,” said Monitor Director Carrie Bivens in arguing against out-of-market actions. “Whether or not an existing resource can move to resolve the constraint is not relevant to whether it should be priced. We don’t need to define in advance what the response will be. The magic of the market is that it can and does respond to those market signals.”

Bivens said incorporating a price signal for what would be an out-of-market action on hidden congestion would incentivize the market to resolve the issue.

She noted that ERCOT only activates contingency constraints if three thresholds are met: the system is loaded at 98% of the emergency limit; a resource shift factor of 2% or more exists; and a similar constraint is not already activated.

Other markets have lower constraint thresholds, are lowering them or don’t have them at all, Bivens said. MISO’s Independent Market Monitor is urging the RTO to remove its 1.5% threshold; PJM just removed its threshold; and CAISO is discussing a change to its 2% rule, she said.

With an efficient congestion revenue rights (CRR) market, she said, the overall cost to load does not increase. “If the real-time congestion rent goes up, the day-ahead market’s congestion rent will rise and the CRR revenue goes up,” Bivens said.

“This is a pretty significant issue for the market. It’s in the ERCOT procedure manual, but this needs to be documented in a guide procedure,” Morgan Stanley’s Clayton Greer said. “In my view, we’re going to see [the] effective elimination of the 2% rule anyway with all the distributed generation going out on the system. I’d rather just rip the Band-Aid off, let the market see the change and everyone adapt to the change [at the same time].”

Kenan Ögelman, ERCOT’s vice president of commercial operations, said the Monitor “brought up a worthy issue for consideration,” but because the 2% rule doesn’t reside in the protocols or another binding document, options are limited.

“This is something that needs to be resolved to move the issue forward, one way or another,” Ögelman said.

“Maybe it would be cleaner if there was an NPRR [Nodal Protocol revision request],” said Eric Goff, a residential representative in the Consumer segment.

TAC Chair Bob Helton, of ENGIE, said he will discuss the matter offline with Ögelman and TAC Vice Chair Clif Lange, of South Texas Electric Cooperative, and work on a document that stakeholders can vote on.

On that, members were able to reach consensus.

PRS Prioritizes List of Approved RRs

The Protocol Revision Subcommittee (PRS) and ERCOT staff have spent the past few months prioritizing work on approved revision requests to balance resource availability with the flood of changes.

ERCOT’s Troy Anderson said 40 items on the priority list, “an unusual amount,” have yet to be started. That doesn’t take into account RRs from stakeholder groups working on real-time co-optimization, energy storage and distributed generation.

“We’ll be starting on real-time co-optimization, the [Battery Energy Storage Task Force] and [distributed generation] in the very near future,” Anderson said. “We have to be careful not to put those items at risk. This doesn’t mean the remaining items won’t get done. We will seek opportunities for those items when the resources become available or we have the opportunities to work on them.”

Anderson shared with the TAC a graphic that listed more than 70 RRs or other initiatives currently underway or waiting in the wings. ERCOT has a limited number of resources available to work on the backlog.

“We want to ensure we have prioritized the right items to be worked on soonest,” Anderson said.

Committee Passes 3 Change Requests

The TAC approved three revision requests in two roll-call votes.

The first vote paired an NPRR (NPRR984) with an accompanying Other Binding Document request (OBDRR023), both related to emergency response service (ERS) in what Helton dubbed “the Clayton ballot.” Greer, the ballot’s namesake, said during July’s TAC meeting that he would vote against anything related to ERS. True to form, he cast the lone vote against the measures on behalf of Morgan Stanley, but he did side with the majority on behalf of his proxy, EDF Trading’s Kevin Bunch.

NPRR984 changes the number of ERS standard contract terms from three to four per program year to align the terms with typical seasonal conditions and improve ERS’ procurement. OBDRR023 changes ERS’ procurement methodology to match NPRR984’s protocol changes.

In addition, the committee unanimously approved NPRR1027, which removes gray-boxed language from the protocols related to NPRR702 (Flexible Accounts, Payment of Invoices, and Disposition of Interest on Cash Collateral) following the elimination of prepay accounts.