ERCOT stakeholders last week endorsed a final batch of key principles (KPs) that will guide the Texas grid operator’s implementation of real-time co-optimization into its energy market.

“We’re in a transition period today,” ERCOT’s Matt Mereness told the Technical Advisory Committee during its meeting Wednesday. “We have to button up a lot of business to get on with our work.”

Mereness, chair of the Real-Time Co-optimization Task Force, said staff have already begun to draft the revision requests necessary to add real-time co-optimization (RTC), a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

ERCOT is recommending the task force serve as a clearinghouse to address protocol language changes and stakeholder comments. Staff plan to file an expected full set of 10 RTC change requests and a single impact statement in March, Mereness said.

The grid operator has estimated it will cost at least $40 million to add RTC to the market, with a projected implementation in mid-2024. Staff hope to submit all comments to the Protocol Revisions Subcommittee (PRS) in November and gain the TAC’s endorsement and the Board of Directors’ approval by year-end.

“This is the critical path to getting the program off and running,” Mereness said, promising that stakeholders will continue to be heavily involved.

“We’ll be done with the protocols in the relatively near future, but I think it’s very important we keep you updated on how the project’s going,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “Ultimately, your feedback is really valuable as to how you’d like us to keep you updated. If you think there’s something that we’re not providing informationally and that’s of value to you, we’re all ears.”

The approved principles included the need to modify the market participants’ disclosure reports on 15-minute settlement intervals filed 60 days before the current operating day. With RTC, each five-minute interval will now include more than 45,000 values and numbers.

The other KPs included:

• KP 1.1 (2), (6), (7), (8): Continues use of a pricing run to capture the effects of reliability deployments and the existing triggers to execute the deployment process. The pricing run will be modified to also co-optimize energy and AS. The real-time online reliability deployment price adder process will apply to both energy and AS; the adder for each AS product will be the positive increase in market clearing price for capacity between the dispatch and pricing run.
• KP 1.2 (3): The values of and interaction between systemwide offer cap, value of lost load and the power balance penalty price and their potential changes must be evaluated as part of RTC’s implementation.
• KP 1.3 (11), 14: The security-constrained economic dispatch (SCED) tool will use the most recently available AS offer as qualified scheduling entities (QSEs) continuously update their AS offers. A behavioral rule will be created to prevent QSEs from submitting confirmed trades for AS sub-types in excess of their day-ahead market self-arrangement quantity.
• KP 1.4 (3), (4): QSEs will continue to send up and down normal ramp rates that represent a resource’s five-minute ramping capability but will submit new telemetry to inform ERCOT of a qualified resource’s physical capability to provide AS. These telemetry points will be used as additional limits on AS awards given the resource’s other constraints.
• KP 1.5 (14-16): RTC systems will consider AS awards from the most recent SCED execution. No new settlement calculations will be needed to address a SCED failure. Fast-responding regulation service will be removed as a subset of regulation AS. Energy storage resources will be required to qualify and provide the same regulation service as other resources.
• KP 1.6 (5): Credit exposure calculations will be revised to account for RTC AS activity.
• KP 3 (13-20): Reliability unit commitment (RUC) will review available scheduled resources and consider moving AS among qualified resources to meet the real-time forecasted conditions.
• KP 5 (2)(a), (7)(b), (7)(j): Identifies necessary changes for the day-ahead market to bring day-ahead AS procurement into alignment with RTC’s implementation.
• KP 6: Identifies performance-monitoring changes necessary to reflect RTC’s implementation.
• KP 7: Captures design concepts that were considered during the RTC principles’ development but were deemed to be outside the implementation’s scope.

TAC Endorses 7 Energy Storage Concepts

The TAC endorsed seven key topic/concepts (KTCs) as part of the Battery Energy Storage Task Force’s (BESTF) effort to integrate battery storage resources into ERCOT. The task force is considering operational and market design policies that could eventually be implemented.

• KTC 1: Proposes that energy storage systems participating in SCED and AS markets register as an energy storage resource (ESR).
• KTC 3: Recommends ESRs suspend charging, unless instructed otherwise by ERCOT, during all levels of an energy emergency alert.
• KTC 5: Would score ESR performance using ESR energy deployment performance (ESREDP) percentages and megawatts. The BESTF recommends ESREDP tolerance to be the greater of 3% or 3 MW.
• KTC 6: Allows limited-duration resources to submit updates to energy offer curves immediately before an operating hour begins.
• KTC 7: Sets requirements for settling ESRs in the day-ahead and real-time markets.
• KTC 8: Conforms to Public Utility Commission rules that wholesale storage load (WSL) occurs when stored energy is “subsequently regenerated and sold at wholesale as energy or ancillary services” by requiring batteries serving retail load behind their interconnection point to be ineligible for WSL treatment.
• KTC 10: Proposes ERCOT and the Supply Analysis Working Group develop a threshold above which ESRs will be included in the Capacity, Demand and Reserves (CDR) report. It also proposes near- and longer-term methodologies for considering ESR capacity in outage coordination studies, operations studies other than RUC and transmission planning studies.

ERCOT: DC Economic Dispatch not ‘Feasible’

Members endorsed ERCOT’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.”

Staff said such an effort would require ERCOT to coordinate the development of a joint-dispatch mechanism with the system operators at the other end of each affected tie. “Such a mechanism would almost certainly require ERCOT and each other affected system operator to enter into a binding commitment to use the dispatch mechanism and to accept the output in system dispatch, which would limit ERCOT’s authority over one aspect of its market design,” staff said in a memo to the TAC.

ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.

The directive was one of a number to the grid operator related to the Southern Cross Transmission DC tie-line, a proposed Pattern Development HVDC transmission project in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets (46304). (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

The committee’s six consumer representatives — the Texas Office of Public Utility Counsel, independent consultant Eric Goff, CMC Steel Texas, Air Liquide, and the cities of Lewisville and Eastland — abstained from the vote, as did ENGIE’s Bob Helton and Exelon’s Marka Shaw. An earlier Goff amendment to the motion that would have required ERCOT to re-evaluate its congestion management plans for DC ties fell short by a 63-37 margin.

ERCOT said it would consider any constraint management plan (CMP) or remedial action scheme (RAS) that it developed or other entities properly proposed “at the appropriate time.”

Helton, Lange Re-elected to TAC Leadership

Committee members re-elected Helton and South Texas Electric Cooperative’s Clif Lange as chair and vice chair, respectively. The elections will give Lange a full year as vice chair before potentially assuming the chairmanship a year from now.

Helton welcomed several new members to the committee including Goff, a former TAC member when he was at Citigroup Energy. Also joining the committee this year are ACES Power’s Roy True, representing Brazos Electric Power Cooperative; AP Gas & Electric’s Jennifer Schmitt in the Independent Retail Electric Provider segment; and Shaw in the Independent Generator segment.

Members also approved the 2020 subcommittee leadership.

RUC Resource-hours Fall 67%

ERCOT staff’s annual RUC report revealed a 67% drop in effective resource-hours, from 613 in 2018 to 201.7 last year. The total RUC make-whole payment was about $48,000, almost exclusively covered through capacity-short charges, staff said.

Resources in the petroleum-rich Permian Basin accounted for more than 53% of the total resource-hours, necessary to help resolve local issues associated with the area’s high load and transmission outages.

Staff credited several TAC-endorsed system changes, including the application of an offer floor when a RUC resource was previously awarded a supply offer, for the reduction.

“We’re seeing some of the fruits of our work,” Reliant Energy Retail Services’ Bill Barnes said.

Staff also told the committee that ERCOT’s system administration fee, currently 55.5 cents/MWh and level since 2016, is forecast to be adequate for 2021. The notice fulfilled a market participant request for more advance notice of any future rate increases.

TAC Approves 19 Change Requests

The committee approved the PRS’ two-month backlog of revision requests, including the first one to address the BESTF’s key topics and concepts. The change (NPRR986) gives energy storage resources more flexibility in updating real-time energy offer curves and bids.

Stakeholders discussed extending the flexibility to make real-time updates to all generators. Ögelman said potential system “performance issues” would pose a challenge that needs to be resolved.

“Once we’re through with [NPRR986’s implementation], we’re willing to work on extending the flexibility to other resources as well,” Ögelman said.

The committee approved 15 additional NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR), and a system change request (SCR), with only a pair of abstentions:

• NPRR826: Creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
• NPRR838: Revises the RMR process by deleting the requirement for a unit to submit operations and maintenance estimates and canceling the requirement for RMR resources to submit quarterly O&M updates.
• NPRR955: Defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
• NPRR963: Allows an ESR’s components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
• NPRR964: Removes from the RMR process the term “synchronous condenser unit” and its related agreement.
• NPRR967: Removes the 10-MW limit for limited-duration resources.
• NPRR970: Clarifies the fuel-dispute process for RUC make-whole payments.
• NPRR971: Updates the energy offer curve’s cost cap value.
• NPRR974: Requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
• NPRR977: Requires ERCOT to post a report of canceled RUCs to the market information system.
• NPRR978: Incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
• NPRR980: Changes how forced outages longer than 180 days are treated in ERCOT’s CDR report.
• NPRR982: Clarifies that a deployed block-load transfer will be appropriately compensated.
• NPRR985: Modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
• NPRR988: Corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
• NOGRR183: Aligns the guides with NERC’s RAS reliability standard.
• SCR806: Adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
• VCMRR026: Removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.

— Tom Kleckner