AUSTIN, Texas — ERCOT’s Technical Advisory Committee endorsed the Wholesale Market Subcommittee’s recommendation to increase the fuel adder factor for coal- and lignite-fired resources to $1.10/MMBtu from $0.50/MMBtu. The committee added a sunset date of June 1, 2018, and directed the subcommittee to continue developing a permanent solution to address changing coal prices.

“Given the ongoing pressures in the coal markets, we’d like to see additional work on getting an indexed price for coal, like we have for gas,” Austin Energy’s Barksdale English said. “We’d like to get something a little more dynamic that reflects ongoing changes in the market.”

Citigroup Energy’s Eric Goff said any “hard-coded dollar amount[s]” included in ERCOT’s protocols should be handled “with great caution.”

“If we hard-code that amount, we should make sure it expires,” Goff said. “We’re talking about costs, but not costs we get from market prices. It’s important generators can recover their costs.”

The recommendation was one of two verifiable cost manual revision requests (VCMRRs) brought to the TAC by the WMS. VCMRR 009 was also endorsed, with one abstention; it clarifies the calculation of the minimum requirements fee assessed to qualified scheduling entities based on the total amount of fuel purchased and transported.

TAC Sends 12 Revision Requests on to Board

The TAC unanimously endorsed a nodal protocol revision request providing improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. The committee, however, asked that more information on the matter be brought back to the committee.

NPRR 758 would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes. Determining who develops the outage list and who reviews it will be part of the “homework” that TAC Chair Randa Stephenson, of the Lower Colorado River Authority (LCRA), asked to be brought back to the committee.

“I’m expecting the primary focus of this to be transparency … not to make it more difficult for me to get the transmission I need,” American Electric Power’s Richard Ross said during the discussion.

“The idea is you may not have as much visibility of the problems you create in the market,” said Morgan Stanley’s Clayton Greer. “LCRA may have a 169-kV switch causing millions in congestion, but the wires side has no concept. You’re taking outages, but Oncor may be taking outages at the same time. That could cause major market disruptions.”

The NPRR was developed following a year of work by a task force focused on outage-coordination improvements. It has an estimated cost impact to ERCOT of between $300,000 to $400,000, but the spending won’t happen until 2017, when improvements to the Outage Scheduler system are expected to be completed.

The TAC also briefly discussed NPRR 766 before giving it a unanimous endorsement. The revision request aligns ERCOT’s systemwide discount factor with a proposed operational adjustment to the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation, ensuring consistency with a proposed timeline for changes to the RDF. (See “Reserve Discount Factor Proposal,” ERCOT Technical Advisory Committee Briefs.)

The committee changed the effective date from July 1 to Oct. 1, giving staff additional time to analyze the results of this summer’s RDFs. The PRC used a 2% discount factor last year; ERCOT has proposed a 1% factor.

The committee unanimously endorsed seven other NPRRs, a pair of revision requests to the Commercial Operations Market Guide and a revision to the Nodal Operating Guide, and a system change request:

Nodal Protocol Revision Requests

• NPRR 709: modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
• NPRR 754: revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
• NPRR 761: clarifies that a resource will not be eligible for make-whole payment start-up cost compensation in the day-ahead market when the market considers the resource as not having a start-up cost.
• NPRR 762: removes references to the provision of responsive reserves across DC ties.
• NPRR 763: corrects the formula for calculating qualified scheduling entities’ load-allocated monthly block load transfer amount to reflect a charge, rather than a payment.
• NPRR 764: changes calculations for charges to entities short their capacity obligations in the reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
• NPRR 765: eliminates publisher names for various fuel prices and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.

Commercial Operations Market Guide Revision Requests

• COPMGRR 041: updates to reflect current ERCOT and market participant practices for market notices.
• COPMGRR 042: updates to reflect the Market Data Working Group’s creation and the Profiling Working Group’s responsibilities.

Nodal Operating Guide Revision Request

• NOGRR 050: removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.

System Change Request

• SCR 790: adds an additional level of geographical granularity — the Panhandle/North area — to existing reports for wind energy production and forecasts.

The TAC once again tabled, this time for two months, whether to consider an appeal of NOGRR 149. The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission-operator services from a third-party provider if their annual peak is less than 25 MW.

The Reliability and Operations Subcommittee rejected the NOGRR in March.

Transmission Reports Endorsed

ERCOT staff shared two reviews of planning projects designed to address reliability and import issues in the high-growth Rio Grande Valley region along the Texas-Mexico border. The TAC endorsed both reviews, though each received a pair of abstentions.

Jeff Billo, ERCOT’s senior manager of transmission planning, said staff’s voltage and transient stability review of the Valley Import Regional Planning Group project narrowed 10 solutions down to a preferred option: a $91 million project to add two static VAR compensators capable of handling an additional 2,800 MW of summer peak load.

The project review was driven by competing project proposals from AEP and Sharyland Utilities-CPS Energy, designed to meet a 2011 report that identified upgrades needed in the region by 2020. Direct Energy’s 2014 announcement that it would disconnect from ERCOT and begin dispatching its 524-MW Frontera combined cycle plant to the Mexican market only increased the urgency.

ERCOT’s review assumed six LNG plants proposed for the Port of Brownsville would add 2,400 MW of load but that a 780-MW generation project would also be built.

“We recognize that if the additional generation doesn’t show up, we may be back asking for additional upgrades,” Billo said.

Staff also reviewed AEP’s proposed project to address reliability needs in the North McAllen-Edinburg area. ERCOT’s planning group is recommending an option that will add two new 345-kV lines, a 345-kV double-circuit line, two 345/138-kV transformers and various other improvements at an estimated cost of $51.5 million.

ERCOT’s analysis did not account for the roughly 50 MW of distributed generation in the valley because “DGs are not dispatchable by ERCOT,” Billo said. “They’re not price-sensitive to the LMPs.”

– Tom Kleckner