By Tom Kleckner

The Public Utility Commission of Texas last week asked its staff to revise a rulemaking on emergency response service (ERS), saying it did not favor expanding the program to prevent local load-shed events (Project No. 45927).

As drafted, the proposed order would permit ERCOT to use ERS to prevent firm load shedding (rolling blackouts) in the event of local transmission emergencies. It also would give ERS resources the flexibility to replace reliability-must-run services.

ERS pays loads for reducing their consumption and distributed generation such as backup generators for injecting power during emergencies. ERS currently is used for non-local emergencies and is not permitted to also serve as a must-run alternative (MRA).

Commission staff published the rulemaking for comments in June 2016. The proposed amendments drew comments from 13 different groups, including ERCOT, its Independent Market Monitor and various energy companies and industry and environmental associations.

Price Suppression Concerns

PUC Chairman Donna Nelson said Thursday she “struggled” with the rulemaking and was concerned about ERS suppressing local prices when it is deployed to address local congestion. The draft order said the issue of price suppression should be addressed through the ERCOT stakeholder process.

Commissioner Ken Anderson said he shared Nelson’s concerns, and asked staff to return to the amendment’s original concept of allowing ERS participants to opt out of ERS “if they’re in a situation in which ERCOT is seeking load alternative to RMR.”

“If they’re in an [MRA] contract, they can opt out at their choosing, but they forego the [ERS] payment,” he said.

SCED Integration?

Anderson also asked staff to delete language in the preamble referencing a Shell Energy North America proposal to expand the current ERS program by allowing some resources to submit energy offer curves to ERCOT’s security constrained economic dispatch (SCED) algorithm. As drafted, the proposed order says the commission agrees with ERCOT that requiring ERS resources to telemeter bids and respond to SCED dispatch would “undermine a core purpose of the ERS program — to capture the benefit of demand response or generation that otherwise would be unable to participate in the ERCOT market.”

Anderson said the rulemaking had identified a bigger issue: the integration of distributed generation and allowing the resources to bid into SCED.

“Whether it’s paired with load or just on its own, [DG] needs to be integrated into ERCOT,” Anderson said. DG “should get the LMP. I know ERCOT is working on that, but I would strongly encourage them to make it a priority.”

RMR Alternatives

Anderson told Monitor Beth Garza he thought one reason staff expanded the amendment’s original scope was to address suggestions made by the Monitor that there might be other alternatives than the Greens Bayou Unit 5 RMR agreement. (See ERCOT Ending Greens Bayou RMR May 29.)

“It would be helpful if you could come up with a real concrete proposal that we could shoot at,” he said.

Garza said her initial suggestion for using ERS resources in local emergencies was “not necessarily directed at RMRing Greens Bayou.”

“Frankly, it was a response to … other times we have had to shed load,” she said, pointing to localized events. “I consider ERS as a program that allows loads to be paid, to be the first in line to be curtailed when we’re at the cliff. At that point, the need for effective market mechanisms diminishes. Prices should be reflective of that. ERS is a way for specific loads to step up and say, ‘Yes, I’ll be the first ones to go.’”

Co-Optimizing

Anderson said that with a recent ERCOT cost-benefit analysis indicating a multi-interval SCED would not be cost effective, it opens up the discussion about co-optimizing the real-time market (shifting the responsibility for providing reserve services to online generation resources with the lowest incremental energy cost).

“Which we’ve been talking about for how long?” Nelson asked.

“I still had hair, I think,” Anderson joked. “[Co-optimization] would help with the whole proper price signal and dispatching, hopefully minimizing reliability unit commitments. Then if we co-optimize, we could adopt local [operating reserve demand curves] that reflect that sort of scarcity.”

Anderson was careful to say he was not expressing an opinion, but just hopeful of addressing congestion and local transmission problems.

“To the extent that you just eliminate unnecessary barriers, that’s fine,” he said. “I don’t think ERCOT should spend a lot of time trying to use ERS to relieve localized problems.”

“I would just leave the must-run alternative agreement aspect in the rule, and limit it to that,” Nelson said, saying she was concerned about interfering with ERCOT’s competitive market. “The whole purpose of opening this rulemaking was to look at ways of using ERS as it currently exists and the money that’s being spent. I do not in any way want to enlarge ERS … it shouldn’t be larger than it is.”

The draft order rejected calls to eliminate or increase the $50 million annual cap on ERS spending but promised the commission would review the limit if the new ERS local deployment product results in costs threatening to exceed the limit.

The commissioners asked staff to return with a rulemaking reflecting the day’s discussion for the PUC’s next open meeting March 30. Staff is targeting a March 23 publication of the revised language.

The PUC also:

• Approved the City of Garland’s request to amend its certificate of convenience and necessity with a final route for a double-circuit 345-kV transmission line east of Dallas that will interconnect ERCOT with the SERC Reliability Corp. through the proposed Southern Cross DC tie in Louisiana (Docket No. 45624). The line will connect an Oncor substation with a Garland substation, that will then connect with the Southern Cross.
• Approved a settlement between Entergy Texas and its customers allowing the utility to recover an annual revenue requirement of $29.5 million, almost $19 million above the amount approved in its previous transmission cost recovery (TCRF) factor proceeding (Docket No. 46357). Entergy will recover almost $3.4 million in additional transmission-related revenues through its base rates than it did when the TCRF baseline was set, because of an increase in billing determinants since its last base rate case.
• Reduced revenue requirements for Electric Transmission Texas by $46.2 million (Project No. 44550) and Cross Texas Transmission by $86.5 million (Project No. 45636). The reductions were a result of the PUC’s annual true-up for regulated entities.