A tag team of ERCOT executives last week reviewed the grid operator’s summer preparations at the Board of Directors’ last meeting before the big heat. Judging by the few questions from the board, the presentation was well received.

Staff have said they expect to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW. ERCOT has available capacity of 78.9 GW and a reserve margin of 8.6%. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)

Dan Woodfin, senior director of system operations, told the board that ERCOT expects to “implement energy emergency alerts several times this summer.” He said the alerts would allow it to take advantage of the extra 2 to 3 GW of resources available “only in those limited situations.”

The grid operator does not expect any “wide-area reliability concerns,” Woodfin said. He said Far West Texas may see some congestion from oil and gas and solar development, and areas in the Texas Hill Country and the Rio Grande Valley could experience congestion as well.

The ERCOT system could get a boost if weather forecasts predicting cooler temperatures than the summer of 2018 — when the grid operator set a new peak demand of 73.5 GW — prove accurate. Senior Meteorologist Chris Coleman said it’s “unlikely” to be as hot as last summer, pointing to the ninth-wettest year on record for Texas.

“Wetness tends to suppress heat, to some extent,” Coleman said. He is projecting almost half as many 100-degree days in various Texas cities than last year (five to 14 in Austin, compared to 41 in 2018).

Kenan Ögelman, ERCOT’s vice president of commercial operations, reminded the board of two Public Utility Commission-mandated changes to the operating reserve demand curve (ORDC), which provides a price adder when generation is scarce.

The grid operator will now blend 24 different ORDC curves, based on season and hour blocks, into one curve that aggregates all the data. This will raise adders above 2 GW of reserves during the summer months, but lower them in the winter, Ögelman said.

The PUC also directed ERCOT to shift the ORDC curve by 0.25 standard deviations, which Ögelman said will create a higher adder for any level of reserves above 2 GW.

IMM Market Report: Load Continues to Climb

The ERCOT Independent Market Monitor’s 2018 State of the Market report says the wholesale market performed “competitively” last year, but it also includes some future warning signs.

In briefing the report, which was filed at the PUC on June 5, IMM Director Beth Garza told the board that load is increasing in all four ERCOT load zones, led by a 15.4% increase in average real-time load from 2017 in the West zone, which includes the petroleum-rich Permian Basin. The average load in the North zone, home to Dallas and Fort Worth, increased 6.5% over 2017, and it was up 5.3% for the ERCOT system.

“There’s substantial load growth everywhere. There’s no other word to describe it,” Garza said.

She said the additional load amounts to a 2.2-GW increase each hour, noting, “That’s like two new combined cycle [generating units] to serve load every hour.”

Given the ever-increasing load, Garza said, “In 2022, the existing fleet is no longer sufficient to serve peak load.”

As it is, the IMM report said system shortages increased in 2018, with about 17 hours of prices above $1,000/MWh. The Monitor expects the trend to continue in 2019.

“What seem like very low reserves may just be the new normal,” the report says. “Given the overall size of the system and projected growth, a more robust reserve margin may no longer be required to cover load forecast errors and mitigate generator availability risks.”

The report also said with distributed generation playing an “increasingly important role in ERCOT, the risk associated with generator outages should decrease.”

Overall, ERCOT’s average prices climbed to $35.63/MWh, a 26% increase from 2017. Higher natural gas prices helped drive the increase, up 8% to $3.22/MMBtu.

The grid operator’s real-time market experienced a 30% increase in congestion costs, which totaled $1.26 billion. The IMM said a costly, localized constraint in Far West Texas was the primary culprit.

The report offers three recommendations to improve the reliability commitment process and resulting pricing:

• Evaluate and improve the reliability deployment price adder, which the IMM says is producing results “inconsistent with its original intent.”
• Explore options to consider commitment costs for RUC-committed units.
• Eliminate the opt-out option for RUC-committed resources.

“Continuing to have the opt-out option is an incentive to withhold capacity,” Garza said. “In our decentralized market, where we count on people to make their own best decisions, the incentives in front of us lead to a situation where people are incented not to commit.”

Magness Reviews Legislative Session

During his regular CEO’s report, Bill Magness briefed the board on the Texas 86th Legislative Session, which ended May 27 and included a significant right-of-first-refusal bill. (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)

Senate Bill 1938 gives incumbent utilities the first shot at building transmission projects in the state. The bill, which went into effect immediately after Gov. Greg Abbott signed it May 16, will require ERCOT to modify its transmission planning process to no longer designate transmission provider endpoints.

A second law already in effect — SB475, signed June 7 — creates a Texas Electric Grid Security Council composed of Magness, PUC Chair DeAnn Walker and a designee of Abbott. Magness said Walker will chair the council, which will begin meeting later this year.

SB936, signed June 10 and effective Sept. 1, requires ERCOT and the PUC to contract with an entity to serve as the commission’s cybersecurity monitor. It will be funded by the grid operator’s system administrative fee, Magness said.

Magness also celebrated a two-year delay in the grid operator’s sunset review, which also applies to the PUC and the Texas Office of Public Utility Counsel (OPUC). The review has been pushed back to 2024/25.

“While we always welcome sunset reviews, we’re happy for it to be in 2024 and 2025,” he cracked.

ERCOT’s positive year-end variance to budget has slipped slightly, from $34 million to $33.2 million, still boosted by a large gain in interest income ($18.7 million), Magness said.

Telemetry Data Blamed for Market Event

Ögelman told the board that a May 30 market event that briefly resulted in $9,000/MWh prices was the result of the security-constrained economic dispatch system receiving bad telemetry data.

“This happens,” Ögelman said. “Normally for very short durations, but it doesn’t hit the SCED. This hit the [market] run.”

The telemetry data indicated about 5,000 MW of resources wanted to move down during an interval, he said, and when the market didn’t respond quickly enough, the SCED engine used regulation up to get the ramp it thought it needed. Energy on the power balance penalty curve, used by ERCOT to price ancillary services such as regulation up, hit $9,000.01/MWh for about 2.5 minutes before operators, sensing something was wrong, reran SCED and corrected the data.

The blip resulted in settlement prices of as much as $1,500/MWh in some load zones for one 15-minute interval, Ögelman said.

Staff investigated the event but determined it didn’t warrant a price correction, according to ERCOT’s Protocols.

“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman said. Telemetry data are owned by the resources, not the grid operator.

He said staff would look into strengthening its telemetry data and follow up with stakeholders to evaluate alternatives.

TAC Vice Chair Coleman Leaves for CPS

Technical Advisory Committee Chair Bob Helton said the committee will “bring on” a new vice chair before the next board meeting, replacing longtime member Diana Coleman, who has left OPUC to take a position at CPS Energy, San Antonio’s municipal provider.

Coleman had served as the TAC’s vice chair since 2018, when Helton moved up from vice chair to chair to replace Adrianne Brandt when she also left for CPS.

Board Approves Budget, Change Requests

ERCOT’s system administrative fee will remain at 55.5 cents/MWh through 2021 as a result of the board’s unanimous approval of the 2020/21 biennial budget. The fee has remained level since 2016.

The board approved $268.3 million and $275.2 million for operating expenses, project spending and debt-service obligations for 2020 and 2021, respectively.

The board also approved seven Nodal Protocol revision requests (NPRRs), a change to the Nodal Operating Guide (NOGRR), two new Other Binding Documents (OBDRRs), two Planning Guide additions (PGRRs) and a system change request (SCR) on its consent agenda:

• NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
• NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
• NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
• NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
• NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
• NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
• NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
• NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the NOG.
• OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
• OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high cap to the low cap should the peaker net margin exceed its threshold within an annual resource adequacy cycle.
• PGRR069: Uses terms created by NPRR889 to replace “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
• PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
• SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.

— Tom Kleckner