AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week rejected a request to allow economic dispatch of reliability-must-run (RMR) units over the objections of the ISO’s Independent Market Monitor and several of its Houston-area market participants.

NRG Texas drafted nodal protocol revision request 784, which addresses how RMR units are priced and dispatched, about the same time as ERCOT made its recent decision to extend into 2018 an RMR contract for NRG’s Greens Bayou Unit 5 near Houston.

The contract requires ERCOT to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the 371-MW gas-fired unit’s capacity during summer months through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)

NRG’s request would allow security constrained economic dispatch of RMR units to relieve transmission congestion after all other capacity available for transmission congestion relief had been exhausted.

Market Monitor Beth Garza supported the proposal, which she said would increase the dispatch price of RMR units, allowing other market units to be dispatched to resolve the constraint first.

In ERCOT’s energy-only market, an RMR agreement results from either a poorly designed evaluation process — which mistakenly identifies a resource as needed — or a failure of the market to provide sufficient revenue to justify continued operation of a needed resource, she said.

“Should the failure be in the RMR designation process, the resource is unlikely to be deployed and its energy offer price will be immaterial,” Garza said. “However, if the failure is in the market signal to units in this constrained area, the unit is likely to be deployed and the energy offer price will matter.”

Bill Barnes, NRG Energy’s director of regulatory affairs, said the request underscores the importance of sending the right price signals in the ERCOT market.

“We’re spending $60 million on an RMR contract for the months of June, July, August and September,” he said. “When you look at the State of the Market report for 2015, the real-time congestion rent for three of the major north-of-Houston constraints is $5 million. We’re spending $60 million to solve a $5 million problem. There are legitimate situations where the market solves the problem in a cheaper way. The boogeyman that is high prices gets pummeled by the boogeyman that is RMR.”

As drafted, NPRR784 would only apply when generator offers are mitigated because there is 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 $50-60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the NPRR.

The revision request would instead require 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.

The NPRR failed to gain the Protocol Revisions Subcommittee’s endorsement during a roll-call vote July 14, but NRG appealed to the TAC. The revision request eventually fell short of the necessary two-thirds approval, with 54% positive votes and four abstentions.

NRG on Friday filed another appeal with the Board of Directors, which will consider the proposal at its Aug. 9 meeting.

“How do you prevent future RMR? By sending the right price signals,” Barnes said. “The presence of the RMR is evidence the market signal has failed. 784 addresses the most important RMR issue: How do you send the right price signal? It’s not a perfect solution, but is it better than what we have today? We believe the answer is yes.”

Garza supported Barnes’ position, although she also said she is a “huge believer” in ERCOT’s stakeholder process and “what this room can do.”

“Our position has been the objective of the RMR should be the price should be reflective of the unit not being there, but we should have the energy available to resolve the constraint,” Garza said. “It is absolutely a shortage condition. If that situation did not exist, Greens Bayou would be on the way to the scrap heap right now.

“I’m sympathetic to the argument that, ‘Gosh darn it, we spent $60 million on this unit, why can’t we use it?’” Garza said. “However, believe it or not, those are sunk costs … that don’t change if you resolve this situation. When you’re talking about resources necessary to resolve a transmission constraint, there are two factors: the offer price or mitigated offer cap, and the shift factor of the unit on that constraint — the effectiveness of that unit to relieve the constraint.”

“We generally agree with the IMM … but we disagree that 784 as a one-off is the solution,” said Energy Future Holdings’ Amanda Frazier, chair of the PRS. “We’re concerned [NPRR784] is reactionary. It doesn’t address whether Houston prices are high enough to allow RMR. If we pass this, we’re paying for incorrect price signals.”

Katie Coleman, with the Texas Industrial Energy Consumers group, represented the PRS position, arguing NRG’s proposal is punitive to loads, encourages unit retirements by providing scarcity pricing in non-scarcity conditions and prevents the RMR unit from solving other constraints beyond a single transmission line.

“We have concerns about requiring loads to also pay $600-800/MWh to use that unit for the very purpose it was placed under an RMR contract,” she said. “We have concerns about the incentive this creates for a generating company with a fleet of units in a certain area to retire units and get high pricing for its other units. [NPRR784] would require Greens Bayou to be priced at the highest possible price to solve, which would preclude it from solving other constraints in area.”

Noting that the revision request has been classified as urgent, Coleman said that electric retailers are concerned its requested September implementation timeline does not provide enough lead time for Greens Bayou and other generators in the area.

Coleman also noted customers are paying for Greens Bayou only until the Houston Import Project goes into service as early as 2018, when it is expected to solve the region’s congestion issues.

“This NPRR is sending a price signal too late to matter,” Citigroup Energy’s Eric Goff said. “The fact the contract exists is interfering with what would happen had the unit been allowed to retire. It gets to the point of whether there’s a weird incentive here.”

“If you’re a load outside of Houston, I have no idea why you’re not outraged,” Barnes said. “If the load in Houston has a small load-ratio share, I can understand why you would want someone else to solve your problem. We’re an energy-only market. Price signal is everything.”

Shortly after the TAC meeting concluded Thursday, ERCOT posted answers to questions it received from its request for proposals for must-run alternatives to the Greens Bayou RMR contract. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.)

Committee Discusses July 7 System Outage

ERCOT staff shared its analysis of the July 7 outage of its Energy Management System. The outage lasted 102 minutes and resulted in corrupted data being passed to downstream systems, including settlements and reports. Market participants said they saw a perceived drop-off in load and generation, but their primary complaints were around a lack of information coming from the ISO.

“When these things are occurring, I know ERCOT is scrambling to recover and get the grid stable again,” Barnes said. “From a market perspective, it was pure chaos. Market notices should be crystal clear about what is happening.”

“We just knew something was wrong because of operation notices,” Goff said. “Knowing the extent of the outage would be beneficial to the market.”

“We want to share with you the information we definitively know as quickly as possible,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “The tension we’re trying to balance is how long to hold information back until we can be sure” it’s accurate information.

The problem began at 11:41 a.m., when an operator mistakenly loaded test data into the active system, which corrupted data in the emergency system’s network model. Between 11:59 a.m. and 12:16 p.m., the market’s qualified scheduling entities were instructed to assume constant frequency control. By 1:23 p.m., the data had been corrected and verified, and operations returned to normal.

Corrected prices were posted for the affected SCED intervals, and staff said that it is continuing to evaluate alternatives that may affect subsequent settlements.

Price-Correction NPRR Approved

Barnes was successful with a second NPRR, dealing with ERCOT’s price-correction process following a SCED failure. NPRR696, which Barnes drafted on behalf of NRG subsidiary Reliant Energy Retail Services, passed with 72% of the vote.

“When the SCED system is not running, inputs grow stale. When it starts back up, things don’t make sense,” Barnes said. “It comes down to whether you believe the last best price, or whatever it spits out.”

NPRR696 establishes a price-correction policy that uses the last good price for settlement until ERCOT no longer requires manual action to stabilize the system. Barnes said that correcting prices for settlement intervals corresponding to the active watch period would give market participants transparency to known prices that reflect the last good SCED execution.

“This policy would extend that last good price for another 15 minutes,” Barnes said. “It could be the last high price or the last low price.”

The TAC unanimously endorsed six other NPRRs, a system-change request (SCR) and revisions to the Nodal Operating Guide (NOGRR), the Planning Guide (PGRR), the Retail Market Guide (RMGRR) and the Resource Registration Glossary (RRGRR).

• NPRR738: Excludes from performance calculations intervals when an emergency response service generator is unable to meet its obligations because of transmission/distribution service provider (TDSP) outages.
• NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities related to 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 startup costs included 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 service 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, avoiding related transactional, billing and out-of-sync issues.
• NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
• NOGRR155: Clarifies voltage ride-through performance requirements for all generation resources immediately following a fault, stipulating that they must remain online and connected to the transmission system, and also maintain real power.
• PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbances by specifying a process for developing geomagnetically induced system models.
• RMGRR138: Removes the requirement for retail electric providers serving pre-pay customers to provide a weekly list of electric service identifiers to Oncor, replacing it with the requirement to provide the prepay list upon Oncor’s request.
• RRGRR009: Adds three categories of data: voltage limits for resources’ substation transmission level equipment; geomagnetically induced currents and the presence of blocking devices to allow for the study of any vulnerability attributed 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