Monday, February 18, 2019

ERCOT Technical Advisory Committee Briefs: March 22, 2018

Members Approve Changes Removing RUC Capacity from ORDC

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week approved staff’s recommendation to remove reliability unit commitment (RUC) capacity from the grid operator’s operating reserve demand curve (ORDC), passing a revision request with minimal discussion.

Technical Advisory Committee gathers for March meeting. | © RTO Insider

Staff’s other binding document revision request (OBDRR) revises the online and offline capacity reserves for those resources online during a RUC instruction, and meets the Public Utility Commission of Texas’ directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.)


Kenan Ögelman explains proposed changes to ERCOT’s operating reserve demand curve. | © RTO Insider

The OBDRR, which passed unanimously, will go to a vote of the Board of Directors during its April 10 meeting. Kenan Ogelman, ERCOT vice president of commercial operations, said staff will work “expeditiously” to get the change made by July 1.

“We’ve committed to the PUC that we would implement this as early as possible,” Ogelman said during the TAC’s March 22 meeting.

The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.

ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 estimate ERCOT gave the PUC earlier this month. The affected systems include Market Management Systems, data and information products, and analytic data.

ERCOT Legal Staff Delays Bylaw Revisions


ERCOT’s Vickie Leady reviews amendments to the ISO’s bylaws. | © RTO Insider

ERCOT’s legal staff said they need a two-month delay to complete changes to the grid operator’s bylaws and articles of incorporation to include additional feedback from stakeholders. Staff was to share with the TAC comments and its recommendations for the board’s April 10 meeting but will now not make a final recommendation until the June board meeting.

Vickie Leady, ERCOT’s assistant general counsel and assistant corporate secretary, said staff have received “extraordinarily helpful” comments from stakeholders on issues such as definitions of affiliates and membership segments. The bylaws were last revised in 2000.

Some of the market’s largest players — American Electric Power, CenterPoint Energy, Exelon, Oncor and Luminant Generation — banded together to provide joint comments.

The delay puts a hold on Southern Cross Transmission’s (SCT) bid to become ERCOT’s first merchant DC tie operator. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Oncor and Texas Industrial Energy Customers filed comments recommending SCT be placed in the independent power market segment, while SCT reiterated that it should be placed in the investor-owned utility segment. ERCOT continues to believe that those are the two most appropriate segments for SCT.

Market’s Weather-Sensitive ERS down in 2017

AEP’s Richard Ross makes a point. | © RTO Insider

ERCOT procured 9.17 MW of weather-sensitive emergency response service (ERS) last summer, about half the amount procured in each of the two previous summers, despite the disruptions caused by Hurricane Harvey.

Weather-sensitive ERS was implemented in 2014 to capture the demand response potential of summer residential and commercial air conditioning loads.

Mark Patterson, manager of market operations support, said the decrease resulted because several transmission and distribution service providers recently modified their standard-offer programs to allow more participation from residential loads — reducing the load that bid to serve as weather-sensitive ERS.

Patterson said on Harvey’s worst day, Aug. 29, the hurricane only reduced 20 MW of capacity obligated to provide service from the 2,300 ERS sites in the storm’s area.

The grid operator projected it will have spent $49.4 million procuring ERS during the year, leaving more than $577,000 unspent.

TAC Unanimously Approves Protocol Changes

Members unanimously endorsed a nodal protocol revision request (NPRR868) that modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems.


Cheryl Mele, Bob Helton and Diana Coleman lead the March TAC meeting. | © RTO Insider

Staff sponsored the NPRR, noting there can be differences between power flow buses and electrical buses, making it more suitable to use power flow buses.

Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure  — are defined statically. A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment.

However, electrical buses are used for real-time hub and load zone calculations.

The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. For the day-ahead and CRR calculations, the LMP of the hub bus is the simple average of the LMPs for each energized power flow bus in the hub. If all power flow buses within a hub bus are de-energized, the LMP does not include the de-energized hub bus. If power flow buses are de-energized under a contingency, the disconnected megawatts are redistributed among the remaining energized buses.

Staff designated the NPRR as urgent and said it would be implemented as soon as possible following board approval.

The TAC also unanimously approved three other NPRRs, two system-change requests (SCRs) and a change to the retail market guide (RMGRR):

  • NPRR858: Requires ERCOT to publish all current operating plans (COPS) data that are submitted by generators, once its confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COPS data, as generators can update them at any time and change aggregate information available to the market.
  • NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if redispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPS many hours earlier.
  • NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
  • SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
  • SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.
  • RMGRRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).

— Tom Kleckner