ERCOT will rely on its stakeholders to improve its reliability-must-run (RMR) practices after a second rejection last week of a protocol change that would allow the economic dispatch of RMR units.

The ISO’s Board of Directors on Aug. 9 rejected NRG Texas and Reliant Energy Retail Services’ appeal of a nodal protocol revision request (NPRR) addressing how RMR units are priced and dispatched. The appeal was shot down by an 11-3 vote, with one abstention.

The two companies also lost an appeal in July to the Technical Advisory Committee (TAC) after the revision request failed to clear the Protocol Revision Subcommittee (PRS). (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)

NRG drafted NPRR 784 earlier this summer as ERCOT was in the process of issuing and extending into 2018 an RMR contract for the company’s Greens Bayou Unit 5, a 371-MW gas plant near Houston. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)

The protocol change would have allowed security constrained economic dispatch (SCED) of RMR units to relieve transmission congestion, after all other capacity available for transmission congestion relief had been exhausted. It would have applied only when generator offers are mitigated due to inadequate competition.

RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50 to $60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the proposed change.

The revision request would have required all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.

NRG’s Bill Barnes said the proposed change raised a pricing policy question that is fundamental to the energy-only market design. “The energy-only market requires effective pricing, and it does so all the time,” he said.

“It sends a signal for existing resources to remain in the market or exit if they’re uneconomic. Second, it provides incentives for new investment. Locational price signals are equally important as systemwide price signals.”

Air Liquide’s Phillip Oldham advocated TAC’s position by urging the board to reject NRG’s appeal, given the “important stakeholder input” provided by its failure at TAC and PRS. He reminded the directors that RMR protocols are currently being reviewed and asked they let the process play out.

“We believe [784] is inconsistent with market principles that have been in place,” Oldham said. “We fundamentally disagree, even at the most basic levels, about what an RMR is. It is not a generation issue. It’s a transmission issue.”

Oldham said the revision request doesn’t support resource-adequacy objectives, noting Greens Bayou Unit 5 is an RMR for local reliability, not systemwide capacity. He also pointed to the $590 million Houston Import transmission project as the RMR “exit strategy” for the Houston area, a position later supported by ERCOT’s COO, Cheryl Mele.

“Using the RMR to set high prices in Houston between now and 2018 will not incentivize new resources because a transmission solution is already in process,” Oldham said.

ERCOT Director Nick Fehrenbach, the City of Dallas’ manager of regulatory affairs and utility franchising, said he had received calls from his consumer market segment members worried about the revision request’s consequences.

“They’re concerned about the impact this could have on load in the Houston area,” he said. “It’s simply a short-term solution before we get the Houston Import project built. I don’t think this is a smart move.”

ERCOT’s RMR contract with Greens Bayou requires the ISO to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the unit’s capacity.

“As you saw in the debate … there’s some sense of urgency around looking at this,” said ERCOT CEO Bill Magness when the smoke had cleared. “[RMR] is an important reliability tool, but it’s a relatively blunt instrument. It is a large bundle of issues, but one that we believe, with a lot of effort and focus from stakeholders and staff, we can get some items to the board for consideration fairly soon.”

TAC Chair Randa Stephenson of the Lower Colorado River Authority was reminded her committee had predicted NPRR 784 would be a “hot topic” six months ago. She said stakeholders have been “digging into the protocols” and existing parameters as they try to improve the RMR process.

At a workshop in May, stakeholders identified 18 RMR-related issues, giving priority to the following three:

• A timeline on notifications suspending operations;
• Studies, processes and criteria used to identify whether a resource is needed for RMR service; and
• Capital contributions to an RMR unit.

Several NPRRs are currently being developed that address the RMR process, timeline and notice. Stephenson said the timing of a staff-drafted revision request modifying the current RMR process has yet to be determined, but other NPRRs will bubble up through the stakeholder request during the next six months.

Last month, ERCOT also issued a request for must-run alternative resource proposals that offer more cost-effective solutions (defined as more than $1 million in savings) than Greens Bayou. Responses are due Aug. 24, with any agreements to be announced Oct. 7.

IMM Notes 26% Drop in Real-Time Prices

The Independent Market Monitor reported that the growing abundance of Texas’ wind resources helped cut load-weighted real-time prices 26% in the first half of 2016 compared with 2015.

IMM Director Beth Garza said ERCOT’s real-time prices have averaged $20/MWh through June, compared with $27/MWh for the same period last year. She called the number “momentous” but said prices will increase “as you factor in the effects of last month and going into August.”

Garza said ERCOT’s wind fleet has grown so much that in June there was never less than 3,500 MW available. She said average capacity factors and energy totals have been higher per MW of nameplate capacity this year, thanks to ERCOT’s recent transmission buildout.

“And the preliminary data in July shows the wind will be higher than it was in June,” she said. “ … People are building more of it, so we get more energy.”

ERCOT’s generation-interconnection status report shows more than 10,000 MW of wind generation due to come online through 2018.

Garza’s report also noted that ERCOT’s ancillary service (AS) costs at mid-year have increased $0.05/MWh over 2015, even though the ISO is procuring fewer such services. She said the IMM will continue to monitor the AS market to determine the cause of the increase.

Magness Reports Favorable Financials to Board

Magness said August’s searing temperatures are expected to make up for milder conditions earlier in the year. The ISO’s net revenues were $4.9 million over budget through June, despite being $2.5 million behind on administration fees. Those numbers are currently projected to finish $7.5 million and $0.5 million over budget, respectively.

The president’s report also addressed the July 7 Energy Management System (EMS) outage and TAC’s concerns that ERCOT did not communicate quickly enough with the market. (See “Committee Discusses July 7 System Outage,” ERCOT Technical Advisory Committee Briefs.)

“It’s always a balance of not wanting to speak until we know what’s going on, but that’s something we’re working on,” Magness said. “It was a human error event, and we took responsibility for that. We’ve changed the process to make sure that is not an error we’re going to see again.”

Magness also took time to recognize the 170-person team behind ERCOT’s recent EMS upgrade. The four-year project went live June 16 following 84,000 person-hours of work, coming in under budget and ahead of schedule.

“The EMS upgrade was one of those processes that’s described as performing brain surgery on the pilot while he’s flying the plane,” he said.

Board Approves 8 Protocol Revisions, 2 Other Changes

The board approved seven NPRRs, a system-change request (SCR) and revisions to the Planning Guide (PGRR) and the Resource Registration Glossary (RRGRR). NPRRs 696 and 738 were the only two revision requests that received any opposing votes.

• NPRR696: Establishes price corrections following a SCED failure by correcting prices for settlement intervals corresponding to the active watch period, giving market participants transparency to known prices that reflect the last good SCED execution.
• NPRR738: Excludes intervals from performance calculations when an emergency response service generator is unable to meet its obligations due to transmission or distribution service provider (TDSP) outages.
• NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities for voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
• NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for including startup costs in the make-whole payment calculation.
• NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary services capacity monitor.
• NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises to avoid transactional, billing and out-of-sync issues.
• NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
• PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbance events by specifying a process for developing geomagnetically-induced system models.
• RRGRR009: Adds three categories of data to the Resource Registration Glossary: Voltage limits for transmission level equipment at generator substations; geomagnetically-induced currents and the presence of blocking devices to allow identification of vulnerabilities due to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
• SCR789: Updates the network model management system topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.

— Tom Kleckner