ERCOT staff’s work on summer reserve margins has drawn the attention of NERC executives, CEO Bill Magness told the Board of Directors last week.

“We’ve been talking to NERC about how they want to see a summer assessment identified,” Magness said during the Feb. 9 meeting. “[NERC executives] are looking at whether they want to have people try different ways to measure reserve margins, as we are doing.”

The Texas grid operator’s planning reserve margin for this summer is 15.5%, thanks to large amounts of utility-scale solar resources. That figure, which comes out of the December capacity, demand and reserves (CDR) report, is almost 2 percentage points lower than the May 2020 CDR report, which indicated a planning reserve margin of 17.28%. (See Solar Power Boosts ERCOT’s Reserve Margins.)

Magness attributed much of the decrease to planned project delays in solar development.

“Utility-scale solar can move much faster and be built much faster than conventional units. They’re able to be much more nimble and make decisions later in the planning cycle,” he explained.

The key in ERCOT’s energy-only market is net load, a measure of demand minus expected generation from intermittent resources, Magness said. The grid operator’s Supply Analysis Working Group (SAWG) has begun to study net-load-capacity risks to the CDR. That includes improving CDR methodologies for wind and solar capacity that more closely aligns with their reliability contributions and developing a capacity-contribution methodology for battery energy storage systems.

Staff developed a probabilistic risk assessment model for last summer using ERCOT’s seasonal assessment of resource adequacy as a starting point. The model determines the probability of energy emergency alert events for each hour on peak load days (hours ending 1 to 8 p.m.). Staff and the SAWG will determine the model’s next steps when it is used to support a new requirement to provide resource adequacy risk metrics for the NERC 2021 summer reliability assessment.

“There’s a lot of work to assess the quality of the various reporting mechanisms that assess changes on the grid,” Magness said.

Two additional metrics are ERCOT’s market equilibrium reserve margin (MERM) and the economically optimal reserve margin (EORM), both of which the grid operator reports every two years to the Texas Public Utility Commission. The reserve margin studies analyze scarcity conditions for every hour of the year through 2024, while the CDR measures available resources and demand in the current year’s peak hour.

Astrapé Consulting recently filed a report that indicates a MERM of 12.25% in 2024, up from 10.25% in its 2018 study, and an EORM of 11%.

ERCOT Finishes 2020 with $27.6M Loss

Magness reviewed the 2020 budget and the preliminary 2021 financials during his president’s report, saying ERCOT expects another negative variance this year on top of 2020’s.

According to the final unaudited numbers for 2020, ERCOT took a $27.6 million loss last year, with interest income $15.7 million below budget and a $10.5 million shortfall in the system administrative fee, due mostly to the economic downturn. Interconnection revenues also were under budget, by $900,000. Expenditures were $2.3 million over budget.

ERCOT budgeted an interest rate of more than 2%, which fell to zero under the weight of the COVID-19 pandemic. It projected a 2.25% interest rate this year, which it expects will result in a $19.9 million loss. Overall, the grid operator expects to come in $23.9 million short of its 2021 budget.

The interest rate “seemed like it was low at the time,” Magness said.

Stakeholders will get their first look at the 2022-2023 budget during the April board meeting. Magness reminded those on the phone that ERCOT won’t be asking for a change in its administrative fee, which has remained at 55.5 cents/MWh since 2019.

Magness said 95% of staff continue to work remotely and have had “good luck with health.” ERCOT has requested 210 “essential worker vaccines” for some staff from the Texas Department of State Health Services but has yet to hear back. In the meantime, Magness said it is working with public and private entities to get essential workers vaccinated as soon as possible.

ERCOT will wait until mid-March to next assess when to return staff to the workplace. Any decision will be dependent on the vaccinations’ progress and case counts.

When staff do return to the office, it won’t be long before they move into a new facility. Magness said construction will be complete by year-end on a new, single-story building near its current headquarters. ERCOT will be the only tenant and will have more meeting space than it currently does.

“We’re excited about what we’re going to be able to offer, not only for ourselves, but for the board and stakeholders,” Magness said. “I do hope we have some meetings in the old Met Center.”

ERCOT Projects ‘Just Keep Swimming’

Mandy Bauld, senior director of ERCOT’s Project Management Office (PMO), said her group completed 29 projects during 2020 despite most of the staff working from home with limited personal interaction. The PMO typically runs about 40 active projects each year, worth $60 million, but ran 80 unique projects last year.

“It reminds me of the quote from ‘Finding Nemo,’ which is kind of corny: ‘Just keep swimming,’” Bauld said. “Amid the organization’s shift to working fully remote in March, the organization continues to meet project objectives.”

Topping the PMO’s objectives for 2021 is the Passport Program, which combines the implementation of real-time co-optimization, energy storage resources, and distributed energy resources with ERCOT’s energy management system upgrade. (See “Passport Program Picking up RTC, Energy Storage Work,” ERCOT Technical Advisory Committee Briefs: Jan. 27, 2021.)

The Passport Program faces a 2024 implementation deadline.

Talberg Chairs 1st Meeting

Chairing her first board meeting, former Michigan Public Service Commissioner Sally Talberg shared her two priorities for the coming year. (See Former Mich. Regulator Talberg to Chair ERCOT Board.)

She told directors and stakeholders that the first item on her plate is “building connections with all of you,” in addition to ERCOT staff and the PUC.

“Second, I want to prioritize the successful implementation of the key initiatives in the Passport Program,” Talberg said. “So much work went into this last year … I feel fortunate ERCOT is in such a position of strength. This is truly a world-class grid operator, recognized around the world for that.”

Talberg thanked her predecessor, nine-year chairman Craven Crowell, for his mentorship and said she was “drinking by the firehose” as she gets up to speed on ERCOT’s issues.

“I’m fortunate to learn from the founding fathers and mothers of ERCOT,” she said.

Talberg is joined on the board by fellow rookies Raymond Hepper, who retired from ISO-NE as its general counsel, and Just Energy’s Vanessa Anesetti-Parra, who replaces Ned Ross in representing the independent retail electric provider segment.

The directors also confirmed South Texas Electric Cooperative’s Clif Lange as the Technical Advisory Committee’s chair and Just Energy’s Eric Blakey as the vice chair.

Board Approves 17 Protocol Changes

The board unanimously approved 17 revision requests, all but one of which appeared on the consent agenda. Directors unanimously passed the lone Nodal Protocol revision request (NPRR994) that received an opposing vote at the TAC.

The NPRR clarifies which transmission improvement projects associated with the interconnecting new generation resources should be classified as “neutral” projects, including new substations, and delineates which interconnection facilities are considered before ERCOT performs an economic analysis.

The consent agenda included 11 other NPRRs, three revisions to the Planning Guide (PGRRs), and single changes to the Resource Registration Glossary (RRGRR) and the Settlement Metering Operating Guide (SMOGRR):

• • • NPRR1024: authorizes staff to consider significance in determining whether to perform a price correction for the day-ahead or real-time markets, introducing metrics for determining when to perform a price correction or request the board’s approval.
    • NPRR1034: creates a new protocol section (Frequency-Based Limits on DC Tie Imports or Exports) that enables ERCOT to establish import or export limits on DC ties and avoid the risk of unacceptable frequency deviation during an unexpected loss of one or more DC ties during the import/export. Staff will be able to curtail DC tie schedules on a last-in-first-out basis.
    • NPRR1040: establishes compliance metrics for ancillary service supply responsibility.
    • NPRR1044: requires generation resources and ESRs to develop and implement subsynchronous resonance mitigation plans to address vulnerabilities in the event of six or fewer concurrent transmission outages, an increase from the current threshold of four or fewer.
    • NPRR1048: changes certain required system adequacy reports to being aggregated by forecast zone instead of by load zone. Forecast zones have the same boundaries as the 2003 congestion management zones: North, South, West and Houston.
    • NPRR1049: removes the requirement to obtain board approval to add, delete or change a DC tie load zone and also removes the 48-month waiting period before such actions can go into effect.
    • NPRR1050: changes the summer projected commercial operations date deadline to July 1 from the start of the summer peak load season, June 1.
    • NPRR1051: removes the administrative price floor of -$251/MWh from all day-ahead settlement point prices.
    • NPRR1052: ensures that energy storage systems registered as settlement-only generators will continue to have their injections and withdrawals settled at load zone pricing until nodal pricing for injections and withdrawals is approved and implemented.
    • NPRR1053: establishes an exemption from ancillary service supply compliance requirements for any qualified scheduling entity (QSE) representing an ESR whose ability to charge is restricted during a Level 3 energy emergency alert event. The change also clarifies that the compliance exemption does not impact the QSE’s financial responsibility because of the AS insufficiency.
    • NPRR1054: removes all references to the Oklaunion Exemption from the protocols and adjusts the affected sections’ remaining language accordingly. The coal-fired Oklaunion plant was retired in October.
    • PGRR085: requires resource entities, interconnecting entities (IEs) and TOs to provide reports benchmarking the power system computer-aided design (PSCAD) model against actual hardware testing. Also requires them to provide parameter verification documentation confirming that model settings match those implemented in the field.
    • PGRR086: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application.
    • PGRR087: clarifies that remedial action schemes should not be relied upon to resolve planning criteria violations.
    • RRGRR027: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application. PSCAD models should be required before the applicable quarterly stability assessment deadline.
    • SMOGRR024: makes modifications to accommodate telemetered auxiliary load, allowing sites to comply with NPRR1020.