ERCOT Board of Directors Briefs: April 9, 2019

Staff Warns of Credit Risks Heading into Summer

Apr 15, 2019

ERCOT staff warned that forward energy markets indicate high prices this summer, which could lead to unexpected increases in credit obligations.

ERCOT staff last week warned that forward energy markets indicate high prices this summer, which could lead to unexpected increases in credit obligations.

Given current forward prices, Mark Ruane, ERCOT director of settlements, retail and credit, told the Board of Directors during its April 9 bimonthly meeting that forward adjustment factors may increase materially as summer draws closer, leading to “substantial increases in collateral requirements for ERCOT counterparties.”

ERCOT’s April Board of Directors meeting

Ruane said the market “seems to be expecting high prices,” pointing to August forwards that approached $185/MWh for ERCOT’s North hub but settled back to $160/MWh in mid-March. July forwards were about $100/MWh, and June forwards $85/MWh.

Forward prices are used to adjust the day-ahead and real-time exposure components of ERCOT’s credit calculation. Counterparty letters-of-credit are capped at $750 million, which has been reached only three times — all during last summer.

Ruane said he wants to ensure counterparties are aware of the risks of increased credit requirements and constraints on letter-of-credit issuers, and that they maintain “appropriate collateral” and sufficient letter-of-credit capacity.

“We’re highlighting this risk because we hit the limit three times” last summer, Ruane said.

The Texas grid operator has a historically low planning reserve margin of 7.4% as it heads into summer. It is projecting a record peak of 74.9 GW this summer, with 78.2 GW of capacity on hand. (See ERCOT Summer Forecast: Record Demand, Alerts.)

Ruane also said ERCOT will be holding a mass transition drill with market participants and Texas regulatory staff during the second quarter. The drill is intended to identify potential issues in transitioning a defaulting competitive retailer’s electric service identifier IDs.

Staff, TAC Promise Updates on Cold Weather Event

ERCOT CEO Bill Magness and ENGIE’s Bob Helton, chair of the Technical Advisory Committee, both promised directors and stakeholders a future update on the grid operator’s actions to address events during an early March cold spell that led to much market consternation. (See ERCOT Generators Upset over Early March Weather Event.)

Magness said ERCOT actions “focused on delaying scheduled outages that had not begun prior to forecast peak day morning loads.” Stakeholders complained about a lack of transparency into market information and confusion over communications.

“Sometimes, it’s very important what words you use. ‘Request’ and ‘instruction’ are different things in our world,” Magness said during his CEO update. “The market has to know exactly what to expect from us when we get into these situations.”

The TAC has created a task force to determine improvements that can be made in future situations. Magness said changes could involve:

Communications and procedures during anticipated emergency conditions;
Market visibility of ERCOT forecasts as conditions change;
A process governing delay or withdrawal of planned outages; and
Consideration of cost recovery related to postponing or canceling outages for reliability reasons.

Helton said the TAC plans to hold one or two workshops on the recommendations that might come out of the work.

“We were using new tools, based on where we are today in unchartered territory,” he said. “Sometimes, when you use those tools, you find concerns. There was a little rust on those tools.”

ERCOT Board Chairman Craven Crowell (left) and CEO Bill Magness (right)

ERCOT Projecting $34M Favorable Budget Variance

Magness told the board that ERCOT is already projecting a favorable budget variance of $34 million this year, after having ended last year with a roughly $29 million favorable variance.

The CEO said the variance is driven by interest income from congestion revenue rights and continued load growth. Interest income is expected to be almost $19 million over budget this year as a result of higher balances and rates, and administrative fees are projected to be $6.1 million over budget, based on current system load actuals and forecasts.

A reduction in ERCOT project costs could add another $7 million to the variance. The grid operator moved several projects up from 2019 into 2018, accounting for much of the variance, Magness said.

Magness also unveiled ERCOT’s annual State of the Grid report in a redesigned format that features major accomplishments from 2018’s record-breaking year and highlights the grid operator’s effort to facilitate a competitive retail market, incorporate new technologies and improve cybersecurity awareness.

Directors Approve Changes to NPRR916

The board unanimously approved a pair of Nodal Protocol revision requests (NPRRs) previously endorsed by the TAC during its March meeting.

NPRR916, which changes the mitigated floor for natural gas units from a fuel-indexed price to -$20/MWh, was approved as amended by ERCOT comments. Staff recommended the mitigated floor price be reduced from its original level of $0 and also requested the NPRR’s implementation be accelerated from May 1 to April 10 to “correct inconsistencies in pricing outcomes.” (See “ERCOT to Ask Board for NPRR916 Changes,” ERCOT Briefs: Week of April 1, 2019.)

Mark Ruane, ERCOT director of settlements

The amendments were driven by recent negative gas prices at the Waha Hub and to match the mitigated floor for coal and lignite units.

NPRR909 resolves a gap in the protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators. Morgan Stanley, in the Independent Power Marketer segment, cast the lone opposing vote at the TAC “as a matter of principle,” Helton said.

Directors also approved the Human Resources and Governance Committee’s recommendation to allow business-continuity emergency purchases by ERCOT of up to $5 million and unanimously approved nine other NPRRs, a change to the Retail Market Guide (RMGRR) and a system change request (SCR) on its consent agenda:

NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, Texas Public Utility Commission rules and system design.
NPRR906: Streamlines the protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during the security-constrained economic dispatch (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities (QSEs) to match with RMGRR159’s revisions.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR8920: Modifies the resource ramp rate logic in the protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR159: Clarifies the mass transition processes and communications by shortening required minimum timelines for initial notification to affected parties from two hours to one hour, and allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed. Also clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per QSE and per counterparty. The limit will apply to the number of bid IDs per operating day.