Monday, June 25, 2018

ERCOT Technical Advisory Committee Briefs

TAC Endorses Forward-Pricing Credit Methodology

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week endorsed a protocol change that incorporates futures prices to estimate forward risk, a change that the ISO says could reduce market-wide collateral requirements by $30 million to $70 million, depending on several parameters.

ercot technical advisory committee

Beth Garza, director of ERCOT’s Independent Market Monitoring group, and TAC Vice-Chair Bob Helton, Dynegy. | © RTO Insider

Under Nodal Protocol Revision Request 800, collateral requirements would be calculated using a ratio of the futures average price to the historic average price. It would be based on the Intercontinental Exchange’s 21-day North Hub price curves.

ERCOT said exchange-based electricity futures market prices are “assumed” to be a better indicator of forward risk than historic ERCOT market prices.

Reliant Energy Retail Services’ Bill Barnes, representing the independent retail electric providers, called the change a “novel approach,” saying ERCOT may be the first electricity market to use this methodology.

“There is no better way to assess forward-price risk than to use the forwards, and that’s what this does,” he said. “It pulls those in and uses them to adjust your historical credit exposure.”

Barnes said the revision request represents two years of work by the Credit Working Group to improve how forward collateral evaluations are working in the protocols. ERCOT’s current methodology uses historical prices in its evaluations.

“In vetting [the current] approach, the working group found there were some pretty severe flaws in how they worked,” he said. “The most accurate way to collateralize future credit risk … [is] what do we think your participant represents as far as a credit risk to the ERCOT market.”

“It’s consistent with how we mark our exposure to the markets,” said Shell Energy North America’s Greg Thurnher. “It seems to make common sense. It seems to be more effective than our previous practices, which essentially look in arrears to anticipate a forward exposure when the seasonality of our market paints a very different picture.”

Luminant cast the lone dissenting vote, saying its opposition to the NPRR was based solely on the implementation costs to ERCOT and individual market participants.

“We estimate costs of up to $300,000 to make changes in our systems, and we don’t see the requisite benefit,” said Luminant’s Amanda Frazier.

Barnes noted the revision request was granted urgency status so that it could be incorporated into an existing release bundle for ERCOT’s credit monitoring and management system.

“That will potentially help streamline the implementation and perhaps lower the cost,” he said.

The change is estimated to cost ERCOT as much as $250,000 to implement. It has the support of the ISO’s Finance and Audit Committee.

Small Municipalities’ Revision Request Tabled for 7th Time

Tom Anson, an attorney representing the Small Public Power Group of Texas (SPPG), was granted a request to table until August his appeal of a rejected revision to the Nodal Operating Guide regarding the definition of transmission owners. This marks the seventh time NOGRR 149’s appeal has been tabled since it was first brought to the TAC last March, shortly after it failed to pass the Reliability and Operations Subcommittee.

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 NOGRR was developed in 2015 to settle the noncompliant status of seven municipally owned utilities, ranging in size from 9 to 21 MW.

Anson said the SPPG has been told it is “trying to make a market where there isn’t one,” and he said one transmission provider told the group it didn’t have “much of an appetite to provide service.” However, he also said the SPPG has four “conceptual” proposals in hand.

“These things take time,” Anson said. “We can’t promise we can turn any of these into a reality, but if the SPPG is willing to invest time and money into the effort with those who are helping them, we’ll see if we can’t turn one of these into not just a potential market solution, but a real market solution.”

Anson said the SPPG would withdraw its appeal should it reach a deal with one of the transmission service providers. He agreed to return to the TAC in May with an update.

ERCOT to Keep Admin Fee Flat Through 2019

Staff told stakeholders the ISO intends to maintain its system administration fee of 55.5 cents/MWh through 2019.

Market participants requested more advance notice of future fee increases during the 2016-17 budgeting process. The fee was raised from 46.5 cents/MWh during those discussions.

Committee Chairs, Vice Chairs Approved

The TAC confirmed its subcommittee leadership for 2017. The chairs and vice chairs are:

  • Commercial Operations Subcommittee: Chair Michelle Trenary, Tenaska Power Services; Vice Chair Heddie Lookadoo, Reliant Energy Retail Services.
  • Protocol Revision Subcommittee: Chair Martha Henson, Oncor Electric Delivery; Vice Chair Diana Coleman, Texas Office of Public Utility Counsel.
  • Reliability and Operations Subcommittee: Chair Alan Bern, Oncor; Vice Chair Boone Staples, Tenaska.
  • Retail Market Subcommittee: Chair Kathy Scott, CenterPoint Energy; Vice Chair Rebecca Reed Zerwas, Reliant Energy.
  • Wholesale Market Subcommittee: Chair Jeremy Carpenter, Tenaska; Vice Chair David Kee, CPS Energy.

Stakeholders Vote for More Inclusive Steady State Models

Stakeholders unanimously endorsed a revision to the Planning Guide that modifies the conditions proposed generating resources must meet to be included in steady state working group (SSWG) base cases (PGRR 053).

ERCOT TAC Underway | © RTO Insider

The change would require only the data provided for full interconnection studies (the standard generation interconnection agreement, applicable permits, notice to proceed and financial security) for including a proposed generation resource in the base case. ERCOT says the current rules, which also require completion of a resource asset registration form, has “created a need to unnecessarily use extraordinary dispatch conditions in the SSWG base cases.” The change will result in more representative generation dispatch scenarios in base cases, the ISO said.

“This lessens that data that’s required,” said ERCOT’s Jay Teixeira prior to including proposed All-Inclusive Generation Resources in the planning models. “Our intention was to pick up every resource that submits a resource form and are in the non-network model.”

The vote came after members struck references to “all-inclusive” generation resources, which had been added by the Reliability and Operations Subcommittee. Stakeholders said the term created confusion.

Katie Coleman, an attorney representing industrial customers, said she is working with ERCOT staff to update NPRR 190, which could help clear up the confusion. The NPRR was withdrawn in 2010 and was designed to add language acknowledging the existence of generation resources that qualify as distributed generation or are self-generators.

Revision Requests, Shadow-Price Cap Change Endorsed

The committee unanimously approved staff revisions to how ERCOT sets shadow-price caps and power-balance penalties under security constrained economic dispatch. The revisions update the shadow-price offer caps from $5,000/MWh to $9,000/MWh, reflecting the ISO’s current value for shadow-price caps.

The TAC also unanimously approved three additional NPRRs, another NOGRR and revisions to the Planning Guide. They will be brought to the Board of Directors on Feb. 14.

  • NPRR 794: Moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols. The NPRR was approved in conjunction with COPMGRR 044.
  • NPRR 805: Clarifies the criteria under which congestion revenue rights (CRRs) account holders can submit multi-month offers for long-term auctions. The months must be consecutive, within the period covered by the auction and during months when the account holder has ownership of the CRR.
  • NPRR 806: Clarifies that municipalities and cooperatives not participating in ERCOT’s competitive market (non-opt-in entities, or NOIEs) have the option of accepting a refund or capacity for their preassigned CRR-eligible resources. The NOIEs cannot select one option for some months of the year and the other option for the remaining months.
  • NOGRR 165: Aligns the operating guides with NERC reliability standards to ensure ERCOT and its transmission operators develop plans to mitigate operating emergencies. The plans should address NERC standard EOP-011 (Emergency Operations Planning) requirements and does not include black start or geomagnetic disturbance plans.
  • PGRR 052: Ensures appropriate operating limits are established when stability studies are performed after a full interconnection study (FIS) has been completed and model data or transmission system changes not available during the FIS become available before the new unit is brought online.

Tom Kleckner

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