By Tom Kleckner

AUSTIN, Texas — Industry experts and ERCOT stakeholders and staff jammed the Texas Public Utility Commission’s hearing room Friday for the first of several discussions on scarcity pricing and other price-formation issues in the grid operator’s energy-only market.

The PUC workshop was called to discuss a report commissioned by independent power producers NRG Energy and Calpine, which asserted that subsidized renewable resources, socialized transmission planning and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to the ISO’s pricing rules. (See PUCT Workshop to Address ERCOT Market Improvements.)

Some participants were not convinced of the need for the session.

Amanda Frazier spoke for Luminant, the state’s largest generator, when she wondered aloud what ERCOT market problem needed to be solved. “We don’t believe the question was answered,” said Frazier, vice president of regulatory policy for Luminant parent Vistra Energy.

The report, “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT,” recommends several market improvements, including adjusting the operating reserve demand curve (ORDC) and adding local scarcity pricing, to address intermittent renewables and improve incentives for generators.

“Fundamentally, we don’t see the system as broken,” said Harvard University’s William Hogan, who cowrote the report with FTI Consulting’s Susan Pope. “We tried to look at those issues … scarcity pricing and related subjects, that might be considered further. They’ve been discussed in the past and postponed, but now might be a good time to look at them.”

Commissioner Ken Anderson agreed with the report’s conclusion that the ERCOT system isn’t broken.

“It’s been six years since we went to the nodal system,” Anderson said. “I think it’s a good time to see whether we need any material improvements to the system, and what the costs and benefits to the system are.”

Unlike RTOs in the East, ERCOT does not run a capacity market, which pays generators to keep their plants ready to run. The Texas grid relies on price spikes during scarcity events — currently capped at $9,000/MWh — to incent the construction of new plants and maintenance of aging facilities.

However, ERCOT’s nearly 20 GW of wind generation and an expected wave of solar generation threaten to push the grid’s coal- and nuclear-fired generation out of the market. Investment firm Tudor, Pickering, Holt & Co. has said all but two of Texas’ 15 coal plants are losing money.

Still, scarcity pricing is “working just as designed,” Hogan told the commissioners as he and Pope reviewed their report with the PUC.

“You’ve been fortunate in that you have a lot of capacity and short-term load growth,” Hogan said. “Scarcity pricing has been pretty small, which should happen. It’s working … but the other side of story is it’s not been severely tested.”

“If someone asked me today what’s the biggest problem with our market, it would be that we have too much power,” Commissioner Brandy Marty Marquez said. “We do have so much surplus.”

David Patton, president of Potomac Economics, ERCOT’s Independent Market Monitor, cautioned against relying on the generation surplus. The ISO has said it has 81.6 GW of capacity available this summer, more than enough to meet a projected demand peak of 72.9 GW.

“It can be easy to have a false sense of security and think you have this big surplus. Then, all of a sudden, a couple of units retire and there’s no surplus any more, in the span of a year,” Patton said. “It’s pretty clear to me there are resources in Texas under extreme economic pressure. If operators decide it’s not worth it to continue losing money, you’ll see the surplus disappear.”

Patton reminded the commission of the Monitor’s recent State of the Market report, which listed co-optimizing energy and ancillary services among seven proposed market improvements. The report suggests using a local reserve product, such as the 30-minute reserves used by other RTOs, and considering including marginal losses in LMPs. (See ERCOT Monitor: Optimizing Energy, A/S Top Priority.)

“Implement software to better commit peaking resources more economically,” Patton said. “Whatever you do to try and solve the RUC [reliability unit commitment] problem with regard to pricing, it’s probably much less if you economically commit those units and assist participants with committing those units in a short time frame.”

Patton has a supporter in Golden Spread Electric Cooperative’s Mike Wise. The co-op’s s senior vice president of regulatory and market strategy, who has railed against the use of RUCs in both ERCOT and SPP, said it has supported a local reserve product since 2013.

“Additionally, Golden Spread has had positive experiences with real-time co-optimization in [SPP] and is optimistic ERCOT can realize significant benefits from implementation of that feature as well,” Wise said. “An effective marginal-loss methodology helps achieve the best price signals in an organized wholesale electric market.”

Vistra’s Frazier disagreed.

“We’re concerned with Dr. Patton’s suggestions that we should make major changes to the wholesale market just because economists generally think they are good ideas, without assessing the costs and benefits of those changes,” Frazier said. “This is particularly the case since all three experts admitted that they had not performed any studies to evaluate the impacts of implementing marginal losses in ERCOT,” she said, referring to Patton and the study’s authors.

Assessing the costs and benefits of implementing real-time co-optimization and scarcity pricing has been left to the ISO. Staff has already estimated it will take at least $40 million and up to five years to deploy co-optimization, citing the project’s complexity and scope: It would affect 13 ERCOT systems. Staff have yet to define requirements or develop a design, and face months of testing and market trials.

“It’s a large-scale, high-impact project. It impacts multiple core systems of ERCOT,” said Chad Seely, ERCOT’s general counsel and corporate secretary. “A large assumption here is if the commission decides to move forward with real-time co-optimization, we would still work on other projects while also working on real-time co-optimization.”

“I had hoped this was a simpler process, given that other RTOs have done it,” Anderson said.

Seely told the commissioners ERCOT would likely have to rely on outside consulting to quantify the benefits of the proposed market improvements.

“I’m not sure how I think about that,” Anderson said. “I’m a little hesitant to launch off on a project of this magnitude and complexity, particularly based on ERCOT’s view that this is a four- or five-year project and a $40 million cost.”

“On the other hand, if you have too many more $50 million [reliability-must-run contracts], that load could have already bought [the project],” Marquez pointed out, referring to a costly RMR contract in Houston that recently ended. (See ERCOT Ending Greens Bayou RMR May 29.)

Implementing scarcity pricing would be a project similar in cost and scope as the co-optimization initiative, staff said. Kenan Ögelman, ERCOT’s vice president of commercial operations, said staff have discussed marginal losses and locational reserves with NYISO and ISO-NE. ERCOT has promised further information on co-optimization and scarcity pricing before the PUC’s Oct. 12 open meeting.

Anderson also asked Patton to file with the PUC a document that would put “meat on the bones” of his proposal to address RMR issues with a local reserve product.

The workshop was the first of at least two, although the next session has yet to be scheduled. Several stakeholders took advantage of the opportunity to question Hogan, Pope and Patton. Stakeholders also have been promised a chance to present their cases for and against the market recommendations.

The two commissioners — a third is not expected to be appointed until Texas’ current special legislative session ends — will take up the issue again at their next open meeting Thursday. PUC staff said they would resubmit their May 31 request for comment, which includes a list of questions for stakeholders, as a starting point in the docket (No. 47199).

“I want to chew on this cost and benefit analysis,” Anderson said. “I’m inclined to believe there are proposals, or changes or modifications, that make a lot of sense. The question is, what foundation do we need to build or support a decision like that?”