In its first report since the COVID-19 coronavirus pandemic forced most Texans to stay at home, ERCOT said last week it has seen a weekly 2% reduction in energy usage.

ERCOT Senior Director of System Planning Warren Lasher said during the Technical Advisory Committee’s webinar Thursday that the grid operator has seen little change to its daily afternoon peaks. However, load has been off as much as 10% from 6 to 10 a.m., according to the grid operator’s analysis.

Lasher cautioned that ERCOT is hampered by a delay in obtaining customer-specific data and has “limited operational” data to work with. He cautioned that spring break has also had some effect “on what we see.”

Staff developed their analysis by taking a load forecast from January used for daily operational forecasts and added actual weather conditions to create a backcast model. The data Lasher referred to came from the week beginning March 22.

“Much of the variability in customer demand is driven by weather variability,” Lasher said. Texas saw unseasonably high temperatures during March, with temperatures reaching the low 90s in some parts of the state.

Lasher promised to share a more granular look at the data in the near future and regular updates with the TAC.

Staff Following Pandemic Plan

Meanwhile, ERCOT continues its efforts to minimize the effects of the pandemic on operations.

Kristi Hobbs, who is responsible for ERCOT’s enterprise risk management, said staff are following the grid operator’s pandemic plan. Most have been working from home since March 18 — “We’ve been able to maintain a lot of productivity,” Hobbs said — while operators have been alternating shifts between both control rooms. That allows for deep cleaning of the control rooms between shifts.

ERCOT has yet to report a positive test for the virus. Hobbs said a contractor is on call should a workspace need to be disinfected following a positive COVID-19 test.

“Our goal is to ensure we protect our employees and ensure ERCOT can maintain the key business functions you expect from us,” Hobbs told the committee.

Staff have also drafted a document for qualified scheduling entities (QSEs) that describes how to set up remote control rooms and the importance of redundancy. The draft was to be finalized Friday and then posted publicly after a conference call to be scheduled with the QSEs.

Credit Becoming an Issue in ERCOT’s Market

Reliant Energy Retail Services’ Bill Barnes, who chairs the Market Credit Working Group, warned that there may not be enough collateral in the market to keep some retail electric providers (REPs) from defaulting on their credit.

“We’ve done a good job to assess market-pricing risk. This event we’re facing is not a market-pricing risk,” Barnes said. “We have to prepare for an event where you’ll see some REPs default. The concern is the collateral level that is held. The collateral ERCOT is holding may not be enough.”

Barnes said his group is taking a hard look at all the parameters related to market participants’ short payments, including: the timing of when ERCOT can recover short-paid funds (currently six months); the $2.5 million cap on the amount that ERCOT can recover in each default uplift invoice; and the time between when ERCOT issues default uplift invoices (30 days).

The working group, which evaluates credit-risk mitigation and the effect of protocol or market design changes on credit, will discuss a Nodal Protocol revision request (NPRR) addressing a quicker recovery of short-pay amounts during its scheduled April 15 meeting.

“The impact of COVID-19 on retail markets is something that was not contemplated in the ERCOT credit rules. This could be a long, drawn-out process,” Barnes said. “Everything is being looked at to see if there’s a better way to recover amounts quicker.”

Real-time Co-optimization’s Cost: up to $55M

Real-time co-optimization’s (RTC) price tag has grown to $50 million to $55 million with an estimated timeline of up to four-and-a-half years, according to an impact analysis following the development of principles, or boundaries, that will guide ERCOT’s implementation of the market tool.

ERCOT had originally projected it would cost at least $40 million to add RTC to its energy-only market. RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

ERCOT’s Matt Mereness, chair of the Real-Time Co-optimization Task Force, told the TAC that the group has identified about 190 different protocol sections that will need to be modified or written. The task force has produced a 44-page document encapsulating the nine months of work on the key principles, which were approved by the grid operator’s Board of Directors in February. (See “Real-Time Co-optimization Team Finalizes Scope,” ERCOT Board of Directors Briefs: Feb. 11, 2020.)

“2020 is the year to get the protocols done so we can work on the business requirements,” Mereness said. “The key is to be wrapped up by the middle of 2021 so we can develop the systems.”

Mereness promised more details during the task force’s April 8 meeting, when the group will take its first dive into the protocol section.

The RTC project will touch at least a dozen systems. The task force expects ERCOT’s Market Management System to be the most affected system.

Mereness said there is little slack in the project’s timeline and that the task force plans to avoid mistakes similar to those of the nodal market project, which was beset by ballooning costs and delays as teams added unnecessary elements to the systems.

“If there’s something wrong or missing, we’ll get in there and fix it,” he said. “But if it’s additional functionality or something nice to have, that’s where we would challenge any and all changes that will affect the schedule and the budget.”

TAC Endorses 4 More Energy Storage Concepts

The committee endorsed four additional key topic/concepts (KTCs) brought forth by the Battery Energy Storage Task Force, which has been charged with integrating battery energy storage resources (ESRs) into ERCOT:

• KTC 11: Establishes how DC-coupled resources register and participate in the combo-model and single-model “era” (before single-model ESR implementation). Single-model will be implemented in 2024 when RTC goes live.
• KTC 12: Recommends that the existing market rules and practices are sufficient for co-located AC-connected ESRs for registration, participation model, forecasting, performance, mitigation treatment in security-constrained economic dispatch, wholesale storage load treatment and data requirements from QSEs.
• KTC 13: Defines a self-limiting generation site as a combination of one or more resources combined with an energy storage system behind a single point of interconnection, where the generation and energy storage system’s total capacity is greater than either the interconnection agreement’s maximum power export (Pmax) rating or the inverter rating. Similar consideration may also apply to maximum power withdrawal (Pmin). QSEs should manage a self-limiting generation site’s performance to not exceed the established Pmax or withdraw more than the established Pmin from the grid.
• KTC 15: Describes the proxy process for both ESR models.

The BESTF has developed an issue-tracking spreadsheet to monitor discussion points and its progress. Chair Kenneth Ragsdale, with ERCOT, said the group is working through the NPRRs that will be submitted to the Protocol Revision Subcommittee.

TAC Approves 4 Change Requests

The committee approved three NPRRs and a single change to the Planning Guide (PGRR) in a nearly unanimous email vote that concluded Friday. The lone dissent was independent power marketer Morgan Stanley’s opposing vote against NPRR998.

• NPRR953: Defines relay loadability rating to align with NERC’s definition changes, which adds a requirement to include protection system limitations for operational planning analysis and real-time assessments. The changes also support ERCOT housing and monitoring the relay loadability rating in Energy Management System applications.
• NPRR997: Requires an entity controlling a primarily natural gas-fired generation resource to supply ERCOT with a declaration contained in the summer weather preparedness form. The declaration should state that the resource entity or the resource entity’s QSE has made a written effort to communicate with the operator of each gas pipeline that is directly connected to the entity’s generation resource to coordinate any planned pipeline outages to maximize the resource’s availability during the summer peak load season.
• NPRR998: Establishes a requirement that ERCOT post a message to the Market Information System’s public area every time emergency response service is deployed or recalled.
• PGRR075: Requires resource entities and interconnecting entities to provide model-quality test results that demonstrate appropriate performance for submitted dynamic models. Also clarifies that dynamic model data shall be provided using the appropriate dynamic model template; raises awareness of requirements associated with user-written dynamic models; and makes various miscellaneous language updates and corrections, including the elimination of a section superseded by NERC Reliability Standard PRC-002-2 and a Nodal Operating Guide section on phasor measurement recording equipment.

ERCOT’s legal staff have approved the use of electronic votes by stakeholders during the pandemic emergency, asking only that such meetings use communications equipment that allows attendees to hear each other. If necessary, votes can be validated after the meeting, staff said.

— Tom Kleckner