ERCOT Board of Directors Briefs: Aug. 11, 2020

Sneak Peek: Passport Program to Integrate Major Projects in 2024

Aug 16, 2020 | Tom Kleckner

ERCOT CEO Bill Magness told the board that load has begun to return to pre-COVID-19 levels, as evidenced by energy usage in June and July.

ERCOT is facing a collision of major system changes in 2024 when a new energy management system (EMS), real-time co-optimization (RTC) and energy storage and distributed generation resources will all be brought together.

If handled correctly, ERCOT “will have as modern a system as operated by anyone in the world, by a fair amount,” CEO Bill Magness told the Board of Directors on Aug. 11.

Under the Texas grid operator’s Passport Program, staff and stakeholders will bring an upgraded EMS online in June 2024. At the same time, they plan to incorporate the work currently being done by the Real-Time Co-optimization and Battery Energy Storage task forces. They will also add solutions for energy storage resources (ESRs) and distributed generation resources (DGRs).

Passport may not be on the same scale as the Nodal Program market redesign, which lasted more than four years, involved hundreds of contractors and cost hundreds of millions of dollars. When it was all over in 2010, nodal replaced ERCOT’s zonal market structure with a more granular structure comprising more than 8,000 resource nodes.

“This is a multiyear effort that’s going to require strong coordination,” Magness said. “One of the challenges [in] the next few years … will be resources. Some of these systems will need changes, and there are only so many people who can do coding.”

The program’s immediate focus is to complete the market rules for RTC and ESRs this year “so we can hit the ground running in 2021 writing the requirements,” he said.

The Passport Program will be more broadly communicated to stakeholders in September during ERCOT’s annual strategic planning sessions with the membership segments.

Unaffiliated board member Peter Cramton said Passport’s integrated approach to delivering the various projects is important, as the projects are interrelated and should be treated holistically.

“In June 2024, ERCOT should be in a position to be leading the world in modern electricity markets,” he said.

Peak, Wind, Solar Records as Load Returns

Magness told the board that load has begun to return to pre-COVID-19 levels as evidenced by increased energy usage in June and July.

Usage in June was nearly 1% higher than June 2019 and usage in July was up 2.7% when compared to July 2019. ERCOT set a new monthly peak demand on July 13 at 74.3 GW, breaking the previous mark of 73.5 GW.

Demand in the grid operator’s West Texas zones has also reached record levels, Magness said during his CEO’s report. The Far West and West zones exceeded prior summer peaks by 7% and 9%, respectively, during mid-July.

ERCOT also set records for wind and solar generation during June and July. Wind production reached a peak of 21.4 GW on June 28, while solar production topped out at 3.7 GW on July 3. The grid operator has added an additional 3.2 GW of wind and solar nameplate capacity since last summer.

“We’re really starting to see the impact of [utility-scale] resources,” Magness said. He noted that prices were $25 to $33/MWh during the July peak, reflecting a lack of scarcity pricing.

He said ERCOT will continue to produce COVID-19 load impact analyses through September, even though they’ve “kind of hit a groove.”

Hurricane Hanna inflicted “significant damage” in South Texas “that could have been worse” when it made landfall on July 24, damaging 30 138-kV and 69-kV lines, Magness said. He said American Electric Power’s Wade Smith, an ERCOT director, told him the night before the board meeting that AEP had restored a critical 138-kV transmission line several days ahead of schedule.

“The lines were basically lying on the ground,” Magness said. “What AEP did, in the heat of August, in the [Rio Grande] Valley, with COVID, was really remarkable.”

COVID-19’s effects have led to a $9 million drop in system administration fees. Combined with a $15.9 million negative variance in interest expense, a timing issue “that is going to save us in the long term,” ERCOT is currently facing a $28 million year-end negative variance, Magness said.

Retired DC Tie’s Load Zone Removed

The board approved staff’s recommendation to delete the recently retired Eagle Pass DC tie’s load zone in South Texas.

The DC tie began a forced outage in March. AEP, the tie’s owner, told ERCOT in April that it was permanently removing the tie from service because replacement parts were unavailable. The grid operator has since stopped approving injections onto the tie.

ERCOT’s protocols require a 48-month waiting period before a load zone can be removed. Staff are considering sponsoring a Nodal Protocol revision request (NPRR1017) to remove the board’s required approval and aligning DC-tie load zone deletions with the timeline for removing resource nodes.

The DC tie remains a settlement point for congestion revenue rights (CRRs) through 2022.

Direct Energy’s Ross Voted onto Board

Board Chair Craven Crowell said Direct Energy’s Ned Ross has been elected to replace Rick Bluntzer as the Independent Retail Electric Provider segment’s representative on the board. Bluntzer resigned from the board effective July 31.

Infinite Energy’s Steve Madden was elected to replace Ross as the segment’s alternate.

Consent Agenda Includes 35 Changes

The directors unanimously approved 34 revision requests and ERCOT’s methodologies for determining minimum ancillary service requirements on its consent agenda.

The latter change simply removes the use of the Resource Asset Registration Form (RARF) with more general language. A Resource Definition Task Force recently completed a three-and-a-half-year review of ERCOT’s definitions that resulted in several protocol changes.

The Resource Integration and Ongoing Operations (RIOO) function will replace the RARF, enabling market participants to electronically review and edit existing resource asset registration data. By the end of next year, ERCOT hopes to be able to add ESRs and DGRs to the RIOO.

The package of changes came with individual costs as high as $1.3 million.

“We feel like we’re in good shape financially with the implementation of these over time,” Magness said. “It’s not an issue of running out of money for this, but the buckets are getting full, and we have to make priorities.”

The changes included 15 Nodal Protocol revision requests (NPRRs), six changes to the Nodal Operating Guide (NOGRRs), a pair of Other Binding Document revisions (OBDRRs), five changes to the Planning Guide (PGRRs), three revisions to the Resource Registration Glossary (RRGRR), a system change request (SCR) and two changes to the Verifiable Cost Manual (VCMRR).

- - NPRR903: Clarifies the deviations that may occur with day-ahead market (DAM) delays and adds language requiring ERCOT to issue a market notice for any act or omission to ensure the DAM process is successfully completed.
  - NPRR973: Adds definitions for “generator step-up” and “main power transformer” to the Nodal Protocols and clarifies their uses.
  - NPRR983: Deletes remaining gray-boxed language associated with NPRR257 (Monitoring Programs and Changes to Posting Requirements of Documents Considered CEII).
  - NPRR990: Deletes the remaining gray-box for NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) and relocates the defined term “combined cycle train” from “Resource” to “Resource Attribute.”
  - NPRR992: Ensures that the day-ahead liability estimate correctly includes ERCOT contingency reserve service (ECRS) charges and payments, as intended by NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
  - NPRR993: Clarifies grey-boxed language after the concurrent approval of NPRR902 (ERCOT Critical Energy Infrastructure Information) and NPRR928 (Cybersecurity Incident Notification).
  - NPRR996: Aligns the protocols’ hub bus names with the substation names within the ERCOT model.
  - NPRR1000: Removes the term “dynamically scheduled resource” from the protocols.
  - NPRR1002: Establishes ESR “single model” registration and charging restrictions during emergency conditions.
  - NPRR1003: Replaces all remaining references to the RARF with more general language in anticipation of the form’s elimination.
  - NPRR1004: Creates a new process for determining the CRR auctions and DAM clearing load-distribution factors by using load forecasting models and existing validation/error correction to determine daily load-distribution factors.
  - NPRR1015: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service and add ERCOT contingency reserve service.
  - NPRR101 6: Clarifies various important reliability requirements for DGRs seeking qualification to provide ancillary service(s) and/or participate in security-constrained economic dispatch.
  - NPRR10 20: Allows ESRs with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.
  - NPRR10 30: Changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to a load-ratio share based on adjusted metered load totals for each month. Also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and implementation’s ease.
  - NOGRR195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
  - NOGRR196: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - NOGRR200: Deletes all remaining gray-boxed language associated with NOGRR025 (Monitoring Programs for QSEs, TSPs and ERCOT).
  - NOGRR208: Aligns the NOG with the Nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the protocols.
  - NOGRR209: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
  - NOGRR 2 1 2: Aligns the guide with NPRR1016’s revisions and clarifies DGRs’ various reliability requirements.
  - OBDRR018: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
  - OBDRR019: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’s change control process with similar OBDs.
  - PGRR074: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - PGRR076: Changes the generation resource interconnection or change request process to specify that the proposed commercial operations date in the initial application must be 15 months or greater than the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
  - PGRR078: Specifies that data related to the regional transmission plan and special planning studies considered protected information may be posted to the market information system’s (MIS) certified area for transmission service providers. The change also includes updated resource asset registration form generator data postings to the MIS.
  - PGRR079: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
  - PGRR080: Aligns the Planning Guide with NERC Reliability Standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
  - RRGRR022: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - RRGRR02 4: Aligns the glossary with NPRR1003’s changes by replacing all remaining references to the RARF.
  - RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
  - SCR810: Adds logic to ERCOT’s EMS by removing the flag that indicates to the operator that a unit representing a DC tie does not count toward the 2% criterion for activating transmission constraints.
  - VCMRR207: Removes from the manual and its appendix language regarding the validation rules imposed on ERCOT’s external telemetry and used in the resource-limit calculator. This maintains consistency between the manual and the protocols by aligning ESR-related provisions with NPRR986 (BESTF-2 Energy Storage Resource Energy Offer Curves, Pricing, Dispatch, and Mitigation) and its provision that ESRs do not have start-up or minimum-energy costs and sets their mitigated offer cap at the systemwide cap.
  - VCMRR 0 2 9: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.