AUSTIN, Texas — ERCOT staff told the Technical Advisory Committee last week it is preparing a proposal to map registered distributed generation units and a white paper addressing the reliability of distributed energy resources.

The work builds partly on that of the Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, which produced a draft report earlier this year before going inactive. (See “DREAM Task Force Submits Final Report,” ERCOT Technical Advisory Committee Briefs.)

“We’re trying to look into what we need for the future … and focus our attention on improving our reporting requirements,” Kenan Ögelman, ERCOT’s vice president of commercial operations, told the TAC on Thursday.

As of late October, 541 MW of DG from competitive and “non-opt-in” entities — those not participating in the market, such as Austin Energy and San Antonio’s CPS Energy — had registered with the Public Utility Commission through their local utilities. The commission has estimated there are more than 7,600 DG locations in competitive areas, with the load expected to grow at a 10% annual rate.

Unregistered DG accounts for another 112 MW in ERCOT’s various load zones. Ögelman said there is no requirement for the ISO to gather data on unregistered DG, but that it occurs “more by happenstance.”

Under current rules, distributed resources injecting to the grid are paid the load zone price, allowing them to deliver energy in real time but giving ERCOT no notification of their intent to deploy.

In addition, distributed resources are compensated by load-zone pricing regardless of their location within the zone or their impact on congested elements. ERCOT says development of a resource node for distributed resources would improve reliability and the ability of DER to participate in its market.

ERCOT defines DG as any generating facility of 10 MW or less located at a customer’s point of delivery and connected at a voltage less than or equal to 60 kV.

Ögelman said ERCOT currently compiles DG data on from a variety of sources:

• Load profiles and annual reports to the PUC for resources less than or equal to 50 kW;
• Load profiles, PUC reports and unregistered DG reports for resources greater than 50 kW, but less than or equal to 1 MW;
• PUC reports and unregistered DG reports for resources greater than 1 MW that are not exporting to the grid; and
• ERCOT resource asset registration forms for non-modeled generation, but only from resources greater than 1 MW that export to the grid.

He explained that ERCOT no longer “ratchets down” its reporting of DG resources. Nodal protocol revision request (NPRR) 719, which was approved by the Board of Directors last December, removed a provision that reset DG registration thresholds when the total unregistered capacity of DG greater than 50 kW in any load zone reaches 10 MW. “There was an expectation of, ‘Hey, what’s going on? We have all this DG on the system, but there’s no ratcheting going on?’” Ögelman said.

He said staff is working with stakeholders and other interested parties to find a way to draft NPRR language “that addresses everyone’s concerns.” The white paper, Ögelman said, will “show the concern for reliability outcomes.”

Stakeholders had suggested staff use the annual load data request (ALDR) forms to track distributed resources, but Ögelman said, “The ALDR reports don’t have a very well-defined reporting requirement or change process around them.

“It’s difficult to aggregate and see a very good picture of the submitted load data to ERCOT.”

IT Staff Working to Prevent Further SCED Outages

Steve Daniels, ERCOT’s vice president of application development and IT operations, assured stakeholders that staff is working to prevent a repeat of recent outages of the security constrained economic dispatch (SCED) system.

In July, human error led to a 100-minute outage that affected 20 five-minute dispatch intervals. In October, a software failure with the market-management system’s interface resulted in a 75-minute outage. Two smaller SCED failures related to hardware issues also occurred in August and September. Load frequency control signals were also affected in the first three outages.

Daniels noted while SCED has failed in each of the last four months, the system operated smoothly in his first 16 months on the job. He said staff completed a “very thorough” root-cause analysis after each event, using both internal and external resources.

“I can assure you the attention paid to these [outages] and the amount of effort going into remediation, lessons learned and finding ways to ensure we don’t have this going forward is a very concentrated and focused effort,” Daniels said.

He told stakeholders staff is implementing new monitoring procedures, adding new software and working with its vendors “to make sure we don’t see these same issues pop up again.”

Daniels said additional measures have been added around the SCED system “to give us better visibility when those issues arise and what we can do about them.”

That seemed to satisfy stakeholders, who asked Daniels whether there is a way to avoid future single point-of-failures, where one system affects another. He said staff is continuing to “look at ways where we can make … data available to operate the system effectively and reliably when we have SCED issues.”

TAC Approves Ancillary Service Change, Tx Element List

The TAC unanimously approved staff’s proposal to make two minor changes to its 2017 ancillary service methodology. The first removes exhaustion-rate feedback from the regulation-procurement analysis, and the second adds solar generation when estimating five-minute net-load variability.

“We have 400, 450 MW of solar, so we think it’s useful to start capturing the effects,” ERCOT’s Nitika Mago said.

No changes were proposed to the methodologies for determining responsive-reserve service and non-spin reserve service.

The committee also endorsed the Reliability and Operations Subcommittee’s recommendation to approve ERCOT’s original list of high-impact transmission elements. The list will be expanded once a working group can be chartered.

NRG Texas abstained from the vote, saying it had been “late to the party” and was unable to get its comments in. The list “seems to be more backward-looking, based on an analysis of historical congestion,” NRG’s Bill Barnes said. “If [an element] didn’t cause congestion in the past, it’s difficult to get on the list.”

11 Revisions Sent to ERCOT Board

The TAC pulled NPRR773 from the list of revision requests up for a vote. Barnes, chair of the Market Credit Working Group, said the revision request includes language that expands the types of financial institutions that can offer letters of credit, but that outside counsel has proposed additional changes that are “more substantial” than those approved by his group.

The committee did approve five NPRRs, two nodal operating guide revisions (NOGRRs) and revisions to the load profiling guide (LPGRR), retail market guide (RMGRR), resource registration glossary (RRGRR) and the Verifiable Cost Manual (VCMRR).

• NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
• NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analyses, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
• NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities (QSEs); restores the IEL for traders (inadvertently omitted from NPRR741); and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
• NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
• NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
• LPGRR057: Updates the load profiling guide by eliminating language, processes and methodologies no longer necessary within ERCOT’s market.
• NOGRR154: Allows a QSE to designate an agent to connect to ERCOT’s wide area network (WAN) and requires the ISO and market participants to use the WAN to exchange resource-specific XML data.
• NOGRR159: Modifies the use of the term Texas Reliability Entity to distinguish between references to the NERC Regional Entity and the Texas PUC Reliability Monitor. It also clarifies that the Independent Market Monitor is an included party in several provisions related to the ERCOT stakeholder process.
• RMGRR139: Modifies market processes to align with NPRR778’s changes to the protocols’ evaluation window for date changes and cancellations.
• RRGRR010: Amends the seasonal net max sustainable rating definitions by including ambient conditions (including temperature and humidity) representative of conditions that exist during peak load periods in which the generation resource operates. The change is intended to correct an overestimation of summer capacity ratings for gas-fired generation. ERCOT discovered the same temperature value had been used for summer and winter seasonal ratings for a significant number of gas-fired units, with resources reporting temperatures of 36 to 110 degrees F for their summer ratings.
• VCMRR013: Clarifies the process for appealing ERCOT’s denial of submitted verifiable costs. The changes address timelines and ERCOT representation in the appeal process and align with NPRR769, approved by the board Oct. 11.

– Tom Kleckner