ERCOT is leaving significant amounts of money on the table by not using real-time co-optimization (RTC) of energy and ancillary services in its market operations, a study by the ISO’s Independent Market Monitor has concluded.

In its study filed last month with the Public Utility Commission of Texas, the Monitor found ERCOT last year could have realized savings of $257 million in congestion costs, $155 million in ancillary services costs, about $4/MWh in energy costs and $10 million to $12 million in production cost savings (Docket No. 47199).

The Monitor recommended ERCOT and the PUC implement RTC “as expeditiously as possible.” Noting that ERCOT has said it will cost about $40 million and take four or five years to begin using the process, the Monitor said the annual production cost savings and its analysis “provides quantitative evidence of [RTC’s] benefits and improved market efficiencies … [that] more than justify the implementation costs.”

“It’s the key missing link in our market,” IMM Director Beth Garza said last month in Houston. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to the point where we see tighter reserve margins, the likelihood of scarcity pricing increases. And high prices are an indication of the ineffective allocation of reserves.”

The Monitor has consistently recommended the use of RTC since the nodal market went online in 2010, calling it “foundational” to efficient pricing. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)

The Monitor used historical offers and commitment status of resources from 2017 to simulate the effect RTC would have had on dispatch, prices, costs and system conditions, assuming that market participant behavior would remain unchanged.

It found that “jointly optimizing all products in each interval allows [ancillary services] responsibilities to be continually adjusted in response to changing market conditions.” It also said that RTC improves the accuracy of shortage pricing, pointing out that even using data from a year with high installed reserves, it found there were many intervals where average load prices implied scarcity.

“With RTC, however, the number of those intervals decreased significantly,” the Monitor said. “In an energy-only market that depends on scarcity pricing signals to provide incentive for proper levels of investment, it is important the scarcity pricing reflects actual scarcity rather than the inefficient assignment of reserve capacity.”

The analysis also revealed a “significant improvement” in system reliability because of reduced overloading on network constraints and a reduced use of regulation-up service.

As part of the PUC docket, ERCOT staff also filed a report on co-optimization’s operational benefits and its expected effect on reliability unit commitment (RUC) and supplemental ancillary services markets (SASMs). Staff filed a separate report addressing the benefits of incorporating marginal losses into security-constrained economic dispatch.

ERCOT’s analysis anticipates significant operational benefits from RTC’s implementation, including the timelier procurement of additional ancillary services, more effective congestion management, less manual actions by operators and “an improved management of resource-specific capabilities in assigning and deploying” ancillary services.

Staff said ERCOT has executed 391 SASMs covering more than 2,200 operating hours at average clearing prices of $100/MWh more than the corresponding day-ahead price since the nodal market began. When priced at the $100/MWh premium, they said, the megawatts procured in the SASMs resulted in an $11 million difference.

The ISO’s scarcity pricing study indicated it will likely realize production cost savings and reduced consumer costs by incorporating marginal losses in system dispatch decisions. The analysis also projected increases in unit make-whole payments and start-up costs, “which could indicate possible additional costs if marginal losses are implemented.”

The PUC last year directed ERCOT and the Monitor to produce the studies as part of its efforts to improve market performance. The Monitor has made the simulation program code, data and use instructions available on ERCOT’s website.

July Begins with Another Monthly Demand Record

ERCOT wasted no time setting a new monthly demand record for the third straight month when the system recorded demand of 69.6 GW on July 3 during the 4-5 p.m. hour. July’s previous high was set last year at 69.5 GW.

System demand also topped the old record during the 5-6 p.m. hour.

The ISO has now recorded four new monthly highs this year. Staff has forecasted demand will exceed 70 GW in July and August, with a new summer peak of 72.97 GW expected next month.

Real-time prices topped out at $71.85/MWh during the interval ending at 2:30 p.m. on July 3.

The grid operator has yet to issue a conservation appeal this summer. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

Garland Generating Units Return to Mothballs

ERCOT has approved two separate requests by the city of Garland to return 572 MW of generating capacity to mothball status this fall.

The ISO on Friday approved a notification of suspension of operations (NSO) for two units at Garland’s Spencer plant, effective Oct. 3. The two gas-fired units have a total capacity of 118 MW.

ERCOT earlier had approved an NSO for the city’s 454-MW, coal-fired Gibbons Creek facility, effective Oct. 1.

The grid operator determined the generation resources were not necessary to support transmission system reliability during their unavailability.

Both units were returned to seasonal status this spring.

— Tom Kleckner