ERCOT’s Technical Advisory Committee last week tabled a proposal to pay lost opportunity costs to generators ordered to ramp down for grid reliability, choosing instead to take advantage of extra time on the calendar and schedule a workshop on the issue.
The Board of Directors remanded the proposal (NPRR649) back to the TAC in February. It had received 56% support in a TAC roll call vote in November, short of the two-thirds threshold for approval. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)
The TAC set March 7, 9 or 23 as possible dates for the workshop. The committee doesn’t meet again until March 31, giving it a month and a half before it must report back to the board April 12 with either a final version of NPRR649, an alternative version or reasons for rejecting it.
TAC Chair Randa Stephenson said she would prefer an early workshop, but she also wanted to ensure ERCOT staff had enough time to draft language that helps the committee develop alternative recommendations.
Kenan Ögelman, vice president of commercial operations, said the delay would give staff ample time to write a new nodal protocol revision request that would be an “option B.”
“It would be very different from the existing 649,” Ögelman said. “We would like to spend more time on option B and describe it better.”
Staff is working on what Ögelman called “attestation language” that better describes the circumstances of ramping down units in the day-ahead market.
The attestation language “needs to be broad enough to cover the multiple ways people use their units for hedging purposes,” Denton Municipal’s Lance Cunningham said.
DREAM Task Force Submits Final Report
The TAC told its Distributed Resource Energy Ancillaries Market (DREAM) Task Force to develop a matrix of “actionable, clear points” for the committee to consider at its April meeting.
The committee was responding to the final report of the task force, which was chartered to analyze the regulatory and market framework governing distributed generation resources’ participation in ERCOT.
The report sought the TAC’s direction on eight policy questions that might be put to stakeholder votes. Ögelman told the committee ERCOT would like to merge a staff white paper with the DREAM team’s work before going through the stakeholder process.
“We would like to start working on NPRRs and other potential changes,” Ögelman said. “We would like to engage stakeholders further on an individual basis as we work through the issues.”
“I want to be clear on exactly what DREAM and ERCOT are asking TAC to do with this information, the items in the white paper and presentation,” said Diana Coleman, senior market specialist with the Texas Office of Public Utility Counsel.
ERCOT, which has a little more than 550 MW of DG, is projecting those resources will grow by 10% annually.
The task force said ERCOT lacks explicit rules for DG resources 10 MW or greater that are connected at a distribution voltage, and that intend to inject into the distribution system rather than reduce load. It also needs a more precise definition of the term “customer,” the task force said, citing “ambiguous reference[s] to distribution customer, load, etc.”
“These are rapidly growing, very flexible resources,” said Shell Energy’s Greg Thurnher, the task force chair. At 10% growth, he noted, ERCOT would essentially be adding the capacity of a nuclear unit similar to those at the South Texas Project over about seven years.
Thurnher said the wide disparity of business interests and opinions within the DREAM team “make it difficult to make further progress — absent a voting structure.”
ERCOT has DG resources in more than 7,600 locations in competitive areas. Its congestion revenue rights software can only handle about 600 resource nodes at a time.
“There are computing constraints to how large we can make this system,” Thurnher said.
“The key to the nodal market is having as much visibility into the market as possible,” Calpine’s Randy Jones said. “We need to give ERCOT the observability they have to have, and to be able to model” DG resources.
Other stakeholders said the proposed changes are an “unnecessary layer of complexity.” They also discussed optionality between load zone and nodal pricing.
“These types of resources are growing in ERCOT and will have an impact on market solutions,” Ögelman said. “The stakeholders can address the potential growth in distributed resources, and you address those by having market rules.”
Regional Haze Workshop
The committee and its Wholesale Market Subcommittee agreed to hold a workshop devoted to regional haze and reliability-must-run (RMR) services.
ERCOT staff had proposed a fall date for the workshop, after any potential litigation on EPA’s regional haze rules is settled. However, the WMS and other market participants expressed a desire to hold the workshop earlier.
“You’re not getting anything by fall from the courts,” Stephenson said.
“If [market participants] are more focused on the RMR aspects of it, we can have the workshop sooner, rather than later,” Citigroup Energy’s Eric Goff said. “If you’re talking about the regional haze aspect, that’s a lot of moving parts.”
Goff noted that EPA dismissed ERCOT’s concerns about reliability implications, saying, “If ERCOT doesn’t have enough notice on RMR operations, maybe it should change the notice of suspension requirements.
“I don’t know if they considered the kind of Pandora’s box that opens,” he said. “ERCOT could benefit from the market’s input on fleshing out the protocol language.”
Ögelman said ERCOT staff would commit to coming back to the TAC and reviewing the RMR processes, but that its answers might be different.
“ERCOT needs to bring their concerns and ideas,” Stephenson said. “The stakeholders have their concerns. Now, we need ideas and solutions.”
Ancillary Service Redesign Project
ERCOT staff is conducting an additional cost-benefit analysis on the ancillary service redesign project and should be done in time for the Protocol Revisions Subcommittee’s March meeting, ERCOT’s Kenneth Ragsdale told the TAC.
While ERCOT has been successful in complying with NERC reliability standards, its ancillary service framework, which dates back to the late 1990s, “does not adequately address ongoing changes to the ERCOT system,” nor does it anticipate those in the future, such as DG and utility-scale intermittent renewables, according to NPRR667.
“ERCOT still believes 667 has some worthy concepts in it,” Ragsdale said.
He said staff is considering phased transition plans for the NPRR, allowing it to be implemented sooner.
Reserve Discount Factor Proposal
ERCOT staff told the committee it will be recommending changes to the reserve discount factors (RDF) used in its physical response capability calculation as a result of unannounced testing conducted in 2014-15.
When temperatures are below 95 degrees, staff is suggesting a resource’s high sustained limits (HSL) should not be discounted. However, when temperatures exceed 95 degrees, HSLs would be discounted, but only by 1%, instead of the current 2%.
Manager of Operations Planning Sandip Sharma said ERCOT would recommend procuring additional responsive reserves when temperatures are above 95 degrees.
Amanda Frazier, senior director of regulatory policy at Energy Future Holdings, said her company analyzed 12 months of data and found similar results to ERCOT’s. “We did see a difference in the high hours,” she said. “But does it make sense to reduce the RDF to zero in hours not above 95?”
Calpine’s Jones questioned ERCOT’s motivation. “If you’re producing more [responsive reserves] for price formation, just say so,” he said.
Ögelman responded that the idea behind the change was “not necessarily” price formation, but the 1% discount factor.
“There’s evidence we should wait a bit, and there’s evidence we should reduce it all the way to zero,” he said. “In the proposal, it can only come down 1%. I would point to the existence of reserve discount factors as the driver for action.”
ERCOT staff will take the proposal back to the Reliability and Operations Subcommittee. According to the staff timeline, the issue will come back to the TAC in April.
NPRRs, Subcommittee Goals Approved
The TAC approved its goals and strategic objectives for 2016, along with the goals of its Commercial Operations, Reliability and Operations, and Wholesale Market subcommittees.
The committee also easily approved two NPRRs and a system change request, along with a nodal operating guide revision request it had tabled in January.
- NPRR749, Option Cost for Outstanding CRRs.
- NPRR750, Clarify Resource Status when Providing Fast Responding Regulation Service.
- SCR787, Maintain NDCRC Data for Generator Transfer Between Resource Entities.
- NOGRR143, Alignment of Nodal Operating Guiders with NERC Reliability Standard, BAL-001-TRE1.
Budget Issues
The Protocol Revisions Committee told the TAC that ERCOT has raised its internal labor rate from $65/hour to $75/hour in calculating impact-analysis cost estimates and project labor costs for staff who work on capital projects. The PRS said the old rate had been in effect for more than 10 years.
ERCOT has allocated a $400,000 contingency fund for 2016-17 market projects to ensure board-approved revision requests are not delayed. The change does not affect the system administration fee.
Leadership Posts Filled
The TAC unanimously approved the re-election of Adrianne Brandt as its vice chair. Brandt left Austin Energy for San Antonio’s CPS Energy shortly after the year began, requiring a second vote from members before she could officially take her position.
The committee also approved the Retail Market Subcommittee’s leadership (Chair Kathy Scott of CenterPoint Energy and Vice Chair Rebecca Reed Zerwas of NRG Energy) and that of its four working groups and task forces.
— Tom Kleckner
