By Tom Kleckner
TAC Endorses Granularity to Ancillary Services Products
ERCOT stakeholders last week moved to address the Texas grid’s growing pains by tweaking the system’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010.
The Technical Advisory Committee on Jan. 30 endorsed a Nodal Protocol revision request (NPRR863) that modifies responsive reserve service (RRS) to become primarily a frequency response service, allowing resources to earn compensation for providing primary frequency response (PFR). It also creates a new ERCOT contingency reserve service (ECRS), providing the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix.
Electranet Power’s Marty Downey, representing the Independent Retail Electric Providers segment, pointed out that while wind energy and other renewables increase their presence in the ERCOT market, the ancillary services’ design has remained the same.
“Our grid has changed dramatically,” he said. “Wind energy continues to put pressure on ERCOT to address lower inertia. This gives ERCOT the tools to address that.”
South Texas Electric Cooperative (STEC), which sponsored the revision request, said RRS has been a staple of ancillary service offerings since the beginning of the zonal market. Its two components — PFR and 10-minute energy deployment — reflect the thermal generation technology available when the market opened, STEC said.
The co-op noted that NERC reliability standards require ERCOT’s online resources to provide PFR unless exempted by the grid operator. The system’s generation resources end up “providing an uncompensated service … and are subject to compliance risk” regardless of whether they have an RRS responsibility at the time, it said.
STEC also said ECRS provides ERCOT with additional flexibility while also “liberating” the 10-minute component from RRS. The co-op said creating two distinct ancillary service products removes barriers to entry, creates market efficiencies and appropriately compensates resources for the services they provide.
The Advanced Power Alliance’s (formerly The Wind Coalition) Walter Reid supported the NPRR. “Our members are all developing batteries and solar,” he said, pointing to more than 2 MW of energy storage in ERCOT’s interconnection queue.
“This is going to happen. We need to do things to facilitate this happening,” Reid said, calling for the revision request’s quick implementation.
As proposed, fast frequency response will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.
Stakeholders rejected a suggestion from industrial consumers, uncomfortable with the bifurcated approach and $2.5 million to $3.5 million in costs, to move implementation back to 2021 and 2022, respectively. An amended motion failed on a roll-call vote, gaining only 36% support.
The motion to endorse NPRR863 passed by an 86-14 margin. Luminant Generation, Reliant Energy Retail Services and industrial consumers voted against the measure.
“The market does need certainty,” said Ian Haley, director of ERCOT regulatory policy for Luminant. “We have a fleet of generation resources that need to know what to provide. Having uncertainty seems scary to someone in our position.”
“We’re going to add a lot more renewables this year and next year. Inertia is going to be low,” said Sandip Sharma, ERCOT’s manager of operations planning. He said the grid operator hit 127 MW of inertia in 2018, its lowest level ever.
“ERCOT has been waving the inertia flag for several years. We’re on the cusp of that,” STEC’s Clif Lange said. “Now’s the time. … Holding off on PFR only increases the cost to consumers.”
Members Approve Urgent Battery Request
The committee accepted an urgent revision request that will allow Luminant to operate an energy storage system in West Texas, without setting requirements for future storage facilities.
NPRR915 defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy-offer curve.
The measure, sponsored by Luminant, passed with one abstention.
Haley said as Luminant developed its 9.9-MW Upton 2 energy storage system, which became operational Dec. 31 south of the Midland-Odessa region, it became apparent the generator would have to register the battery under requirements not currently defined in the protocols. Upton 2, the largest storage project in Texas, was designed as a settlement-only resource, but it would have been required to register as a “capital G” generation resource.
Haley noted that while Luminant can update market offers from the battery, the fully charged resource will only last 4.5 hours when pushing its full capacity onto the grid, possibly leaving it “completely deployed and drained before those offers can take effect. This clarifies how we are supposed to let ERCOT know, ‘Please do not deploy the battery for the next [security-constrained economic dispatch] run.’”
Haley described NPRR915 as a one-off until ERCOT can get a handle on how to better accommodate battery storage systems.
“This shouldn’t apply to all batteries until we have a holistic view on all of this, but we should have a way for our battery to operate,” he said.
ERCOT said it plans to hold one or two workshops addressing energy storage issues, likely following the March spring break season. TAC Chair Bob Helton, of ENGIE, said the workshops will help determine whether to create a task force or turn the work over to stakeholder groups.
“We’re going to need a couple different set of rules for how batteries are operated, rather than shoehorning them into our existing software,” Reliant Energy Retail Services’ Bill Barnes said. “We encourage ERCOT to move forward [with the workshop] and get rules in place that make sense.”
ERCOT Director of System Planning Warren Lasher committed to previewing with the TAC at its next meeting a list of issues to be discussed during the workshops.
Reid was among several stakeholders urging ERCOT to hold the workshops as soon as possible. He reminded the committee that storage facilities are currently being registered in the market.
“The toe is in the water and batteries are hitting the ground, so the iron is getting ahead of the paper,” he said.
ERCOT’s RUC Activity Up over 2017
Staff’s annual review of reliability unit commitment (RUC) activity indicated a 14.2% increase over 2017, much of it to help resolve local issues with high load in the Permian Basin.
ERCOT’s 642 instructed resource hours in 2018 resulted in 613 effective RUC resource-hours, as compared to 562 and 534, respectively, for 2017. Staff said 22% of the effective resource-hours were bought back, resulting in a total RUC make-whole amount of about $460,000.
More than half of the total resource-hours came during the first half of May in the Permian Basin, where oil and gas production continues to drive much of the load.
In a separate required report, ERCOT’s Sean Taylor said the grid operator’s forecasted system administration fee of 55.5 cents/MWh for 2020 and 2021 will be “adequate.” Taylor said staff will provide an update when the commission weighs in on how it intends to fund real-time co-optimization.
Members Re-elect Helton, Coleman to TAC Leadership
The TAC re-elected Helton as chair and the Texas Office of Public Utility Counsel’s Diana Coleman as vice chair for 2019.
The members also confirmed the leadership of its Protocol Revision (Chair Martha Henson, Oncor, and Vice Chair Melissa Trevino, Occidental Chemical), Reliability and Operations (Chair Kevin Bunch, EDF Energy Services, and Vice Chair Tim Hall, Southern Power), and Wholesale Market (Chair David Kee, CPS Energy, and Vice Chair Resmi Surendran, Shell Energy) subcommittees.
The Retail Market Subcommittee’s leadership will be confirmed at the TAC’s next meeting.
TAC Endorses PUC’s Changes to ORDC
Responding to a January directive from the Texas Public Utility Commission, the committee endorsed an Other Binding Documents revision request (OBDRR011) that modifies ERCOT’s operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity. (See Texas PUC Responds to Shrinking Reserve Margin.)
The change shifts the ORDC’s loss of load probability (LOLP) curve by 0.25 standard deviations in 2019 and by the same measure in 2020. The use of a single blended ORDC curve is expected to lead to its more frequent use, and at higher levels.
The commercial and industrial consumer segments abstained from the vote. So did Direct Energy’s Sandy Morris, who said she continues to have concerns about consolidating the curves.
In “respectfully” abstaining, Thompson & Knight attorney Katie Coleman, representing the Texas Industrial Energy Consumers, noted her association’s longstanding opposition to the change and its potential increased costs.
“We’re still not in favor of it,” Coleman said. “In addition to not being comfortable with the magnitude of the shift, we’re also uncomfortable with combining the curves. It amplifies the pricing impacts.”
The PUC asked staff to provide to the commission a high-level implementation plan and timeline during its Feb. 7 open meeting. The grid operator is planning a March implementation.
The TAC also endorsed NPRR871, which had previously been tabled. The revision request gives ERCOT a mechanism to conduct a reliability review of customer- or resource-funded transmission projects, but without providing a recommendation.
“We don’t want the review process short-circuited by the project’s source of funds,” said STEC’s Lange, who helped supply the NPRR’s final language.
Jeff Billo, ERCOT’s senior manager of transmission planning, told stakeholders the grid operator would follow its normal study process in conducting the review, which would take 90 to 150 days. Billo said should staff identify a reliability or congestion problem, ERCOT would have the authority to recommend the project not proceed.
The TAC approved six other NPRRs, a second OBDRR and two Retail Market Guide changes (RMGRR):
- NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart and how activities will be settled.
- NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
- NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives an RUC instruction.
- NPRR911: Reinstates previous language in the applicable protocol sections for determining online combined cycle generation resources’ (CCGRs) logical resource nodes’ real-time LMPs, following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
- OBDRR010: Codifies that the high sustained limit will be included in the ORDC pricing’s online capacity for resources that have been awarded a three-part supply offer in the day-ahead market, but decide not to operate in the real-time market and subsequently receive a RUC instruction. Related to NPRR910.
- RMGRR156: Moves ERCOT-specific market communication responsibilities to the Business Practice Manual while retaining retail-specific market communications and processes in the RMG.
- RMGRR157: Allows transmission and/or distribution service providers to give an internet-based solution for safety-net submittals.