AUSTIN, Texas — ERCOT stakeholders last week unanimously endorsed Oncor and American Electric Power’s 345-kV Far West Texas Project that addresses continued load growth southwest of Odessa, Texas.

Since 2010, the area has seen annual load growth of about 8%, driven by increases in the region’s oil and natural gas production. While demand growth projections have tapered off recently — only 2.4% through 2020 — Oncor predicts annual load growths as high as 11% within portions of the area over the next five years. More than 1,600 MW of solar resources are expected to come online during that time frame.

Oncor and AEP’s original request to ERCOT’s Regional Planning Group last April estimated the project’s price tag at $423 million.

However, a staff review of 40 different alternatives lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place — substation expansions and other transmission elements. One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second, 68-mile 345-kV line would run from the Solstice switching station to the Bakersfield switch station. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”

Two of the other options would have closed the 345-kV loop between the two lines, while a third would operate the transmission lines at 138 kV on double-circuit structures. The costs ranged between $446 million and $501 million.

“My only concern is it keeps a tight bandwidth on future growth,” Oncor’s Collin Martin said during Thursday’s Technical Advisory Committee meeting.

Staff admitted the loop could be completed but said its recommended option would provide the best reliability solution while “augment[ing] the load-serving capability … as the outlook for greater load and generation resources in this region becomes more certain.”

The project has been proposed to go in service by 2022. Oncor, AEP and the Lower Colorado River Authority would be responsible for the parts of the project within their service territories.

The project still needs approval from the ISO’s Board of Directors and a certificate of convenience and necessity from the Public Utility Commission of Texas.

Rayburn Country Integration

Staff also updated the TAC on the potential integration of the 20% of Rayburn Country Electric Cooperative load that sits in the Eastern Interconnection. The East Texas co-op is considering connecting the load — approximately 190 MW — to ERCOT as early as December 2019. The ISO already serves the other 80%.

A study has identified a least-cost option of $38 million, primarily for a new 345-kV substation, a 138-kV switching station and the expansion of several 138-kV lines.

Southern Cross HVDC Project

TAC Chair Adrienne Brandt, of San Antonio’s CPS Energy, asked the Reliability and Operations Subcommittee (ROS) to schedule a joint workshop with the Wholesale Market Subcommittee to resolve issues arising from the PUC’s final scoping order related to an HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.

“This will ensure everyone has transparency between what the other group is talking about and make sure there are no conflicts,” Brandt said.

The PUC has directed ERCOT to complete a number of tasks before it allows the city of Garland to energize an approved 38-mile, 345-kV line that would interconnect the Texas grid to the Southern Cross DC tie in Louisiana. The tasks identified in the commission’s final order include determining Southern Cross Transmission’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and resolving price-formation issues (Docket 45624).

TAC Subcommittee to Take up DER Issue

ERCOT’s effort to increase visibility into distributed energy resources will begin at the subcommittee level after the TAC declined to get into an in-depth discussion of the growing challenge posed by small generation sources.

Saying she did not want to have the discussion at the TAC “just yet,” Brandt proposed starting it at the ROS. She did not receive any pushback.

ERCOT has proposed a collaborative process involving transmission and distribution service providers (TDSPs), “in which the locations of large DERs or large clusters of small DERs are mapped to their appropriate modeled transmission loads.”

The ISO has published a white paper, in which it proposes working with TDSPs to develop “a standardized method of providing and collecting appropriate data for mapping current and future registered DER units” to their common information model (CIM) loads. Staff said they will also work with stakeholders to develop a process for DSPs in competitive choice regions and non-opt-in entities (NOIE) “to monitor the accumulation of clusters of unregistered (less than 1 MW) DER units connected to specific CIM loads.”

Based on annual reports filed at the PUC, staff estimates nearly 900 MW of distributed generation were interconnected as of Dec. 31, 2015, along with more than an estimated 200 MW deployed in NOIE territories. (The reports use the terms DG and DER interchangeably.) Staff has added 20 new registered DER since November, giving ERCOT a total of 99 registered DER as of May 1.

The ISO suggests working with the TDSPs to jointly develop thresholds for “accumulations” of DER, reporting those that exceed the threshold and mapping clusters that exceed the threshold to a CIM load.

ERCOT defines DER as generation, storage technology or a combination of the two that is interconnected at or below 60 kV and operates in parallel with the distribution system. DER does not currently include demand response.

Woody Rickerson, ERCOT’s vice president of grid planning and operations, told the TAC the white paper builds on the Distributed Resource Energy Ancillaries Market (DREAM) task force’s work, which ended last year. (See “DREAM Task Force’s Work Now Ready for Stakeholder Process,” ERCOT Tech Advisory Committee Briefs.)

He said staff wants to produce annual reports so the grid operator knows how many DER are in its footprint and “what makes sense with aggregation.” Staff will insert the resources into the network model as it maps them to their CIM load points, improving the control room’s situational awareness.

ERCOT Reports Software Issue, Schedules Meeting on Outages

COO Cheryl Mele alerted the TAC to a market notice reporting on a May 22 incident in which a vendor’s issue-tracking system briefly allowed its software clients to view tickets from any other client, including ERCOT. Upon being notified by a non-ERCOT market participant and stakeholder, the ISO asked the vendor to shut down access to the system.

In the market notice, the ISO said it has been told a forensics team “has not found any evidence to suggest that information from ERCOT’s tracking system has been viewed by other software clients.” It is also conducting an internal investigation to evaluate the types of information in the tracking system and to try and determine who accessed or could have accessed the ISO’s information.

Mele also told the committee the Texas grid operator will host a June 15 WebEx on extended 345-kV outages in Northwest Texas this summer. Electric Transmission Texas (ETT) notified ERCOT on May 19 it would be inspecting a number of transmission lines ETT built as part of the Competitive Renewable Energy Zone and, if necessary, replacing components as a part of a warranty claim.

The outages are expected to last through November 2018.

Revision Requests Pass Easily

Confronted with 19 revision requests, the TAC separated onto a consent agenda those requests that had reached the committee unopposed or had impact assessments of more than $10,000.

The only nodal protocol revision request (NPRR) to receive an opposing vote was NPRR831, which also received one abstention, relating to private-use networks — networks connected to the ERCOT grid that contain load that is typically netted with internal generation and not directly metered by ERCOT. The change updates market systems to calculate a net load value for each private-use network that will be included in the load zone price for all markets, when the load is a net consumer from the ERCOT grid.

The NPRR was given urgent status to address instances in which LMPs do not reflect congestion. Kenan Ögelman, ERCOT’s vice president of commercial operations, said from a system perspective, “This is the quickest way to do this accurately.”

The committee passed NPRR827, which bars the ISO from awarding point-to-point (PTP) obligations in the day-ahead market when the corresponding clearing price is greater than the bid price by 25 cents/MWh or more, passed with one abstention.

ERCOT’s Carrie Bivens, manager of forward markets, said there is a market-design problem in the way PTP obligations are currently cleared in the day-ahead market. “We’re contemplating a different design choice for a long-term solution,” she said.

The committee unanimously approved NPRR830, which has an impact assessment of $120,000 to $160,000 and revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC-tie flows.

Members approved editing the business case to say the NPRR will “avoid rebilling costs resulting from the assignment of the 4-CP to an incorrect interval” and that it is consistent with direction from the PUC.

A pair of revisions to the Planning Guide (PGRRs) sailed through individual votes without opposition, but PGRR058, which clarifies specific generation to be included in the guide, was sent back to the Protocol Revision Subcommittee.

• PGRR056: Accounts for potential subsynchronous resonance (SSR) vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR and removing its definition from the guides. SSR is a potentially harmful phenomenon involving coincident oscillation between two or more transmission elements or generation resources at frequencies lower than the ERCOT system’s normal operating frequency (60 Hz). The change aligns the Planning Guide with ERCOT comments to NPRR562, which was also approved. NPRR562 clarifies responsibilities for affected entities and creates new requirements for the identification, study, mitigation of and protection against SSR. The ERCOT system has become more vulnerable to SSR because of the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and/or resources and lead to cascading outages. The NPRR was first introduced four years ago.
• PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.

The consent agenda included three additional NPRRs, three changes to the Retail Market Guide (RMGRR), a change to the Verifiable Cost Manual (VCMRR), and revisions to the Commercial Operations Market Guide, Load Profiling Guide, Nodal Operating Guide and the Resource Registration Glossary. The guide and glossary changes expand the list of revision requests requiring ERCOT board approval and would first consider those revisions at the voting subcommittee level.

• NPRR796: Specifies that character set validations are available within each Texas standard electronic transaction (TX SET) implementation guide, which recognizes all characters within the basic character set.
• NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
• NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts (EEA) and real power balancing control performance.
• RMGRR145: Provides the format for transmission or distribution service providers, municipally owned utilities and cooperatives to use a mass customer list to inform market participants of all customers in its service territories when entering competition or expanding its service territory.
• RMGRR146: Expands the list of RMGRRs requiring board approval and provides additional clarifications to the RMGRR process.
• RMGRR147: Updates protocol language by providing the option of generating a standalone invoice for meter tampering charges when there is no change in usage consumption.
• VCMRR018: Aligns the manual’s revision process with the Protocols and market guides by changing the length of the comment period for newly submitted VCMRRs from seven to 14 days; requires review of all VCMRR impact analyses by the Wholesale Market Subcommittee; aligns the process for submission and review of urgent VCMRRs with other revision-request types; expands the list of VCMRRs requiring board approval; and provides additional revisions to mirror the Protocols and market guides.

— Tom Kleckner