By Tom Kleckner

Favorable Budget Variance to Fund RTC Project

ERCOT CEO Bill Magness said last week that the grid operator will use favorable budget variances to fund the addition of real-time co-optimization (RTC), as it has been directed to do by the Texas Public Utility Commission.

In delivering his CEO report to the ERCOT Board of Directors during its regular bimonthly meeting Feb. 12, Magness said staff have identified $43.7 million in favorable variances that would cover the project’s estimated $40 million cost. Much of the variance is because of aggressive interest rate assumptions set in 2017, Magness said.

The PUC last month directed ERCOT to proceed with RTC’s implementation. Commission Chair DeAnn Walker has said that RTC would bring economic and operational benefits to the market. (See Texas PUC Responds to Shrinking Reserve Margin.)

Staff have said it will take four to five years to implement RTC, the process of procuring energy and ancillary services simultaneously in the real-time market every five minutes to find the most cost-effective solution for both requirements.

Magness said he would provide a clearer picture during the board’s April meeting, following a financial audit that determines the final variances.

“As we know from past projects, until we get the protocols written and we know what we’re building, it’s hard to get a much better estimate than the one we’ve provided,” he said.

As for the interest assumptions, Magness said, “We’ll be reupping those and changing those to where we accurately believe we are in 2020 and 2021.”

Staff Present Transmission Planning Report

Jeff Billo, ERCOT’s senior manager of transmission planning, briefed the board on the grid operator’s transmission planning practices, assuring them that staff carefully match projects and needs.

“We take our job very seriously, and we only build what needs to be built,” he said.

Annual transmission costs — charged to consumers to pay for ERCOT’s system — have steadily risen from about $1.3 billion in 2008 to nearly $3.5 billion in 2017. Billo said the rise can be attributed to the Competitive Renewable Energy Zone (CREZ) project, natural load growth and Far West Texas load growth.

According to NERC’s 2018 long-term reliability assessment, ERCOT’s 1.76% 10-year forecasted growth rate trails only that of the Western Electricity Coordinating Council’s Rocky Mountain Reserve Group subregion (1.8%).

“A strong economy leads to load growth,” Billo said.

Much of the CREZ project, a 345-kV infrastructure build connecting wind-rich West Texas with urban centers, went into service in 2013. Almost $5 billion was invested that year alone, resulting in a $700 million one-time bump in transmission costs, he said. However, CREZ has also provided a strong 345-kV backbone as ERCOT works to meet the growing petroleum-fueled load growth in the Permian Basin, where peak demand has doubled since 2009.

“Without CREZ, we would have seen a significant amount of transmission needed for far West Texas,” Billo said. “It’s been a challenge keeping up with that growth.”

He said transmission upgrades incorporate double-circuit capability and higher-voltage lines to be able to meet even higher loads in the future. ERCOT has conducted special assessments to try and get ahead of that higher growth.

“Based on 2018 forecasts and studies, our plan is sufficient,” Billo said.

A wave of wind and solar projects in West Texas — “There’s more wind and solar existing or planned than CREZ’s capacity,” Billo said — and increased LNG activity on the Gulf Coast will result in more load growth and congestion. ERCOT has already approved the Freeport Master Plan Project to address LNG growth, and the work to integrate Lubbock Power & Light’s load is expected to relieve constraints in that region. (See “Regulators Grant Preliminary Approval to Sharyland-LP&L Projects,” Texas Public Utility Commission Briefs: Feb. 7, 2019.)

Board Approves Leadership for 2019

Magness introduced Jeyant Tamby to the directors as an ERCOT senior vice president and its first chief administrative officer. Tamby, who was among the officers ratified by the board for one-year terms, served as former CEO H.B. “Trip” Doggett’s (2010-2016) chief of staff. He will bring together many of ERCOT’s corporate functions into a more efficient structure, Magness said.

Magness, who was elected to another one-year term as CEO, also announced the retirement of Human Resources Vice President Diane Williams, who joined ERCOT in 2014.

“I’ve seen pictures of her grandchild,” he joked. “I can’t convince her to stay.”

Craven Crowell and Judy Walsh were re-elected to the board as chair and vice chair, respectively. However, Walsh has stepped down as chair of the Finance and Audit Committee and will be replaced by unaffiliated director Terry Bulger.

The board also confirmed ENGIE’s Bob Helton and the Office of Public Utility Counsel’s Diana Coleman as chair and vice chair, respectively, of the Technical Advisory Committee.

ERCOT, SPP, MISO Hammer out Coordination Plans

ERCOT Assistant General Counsel Nathan Bigbee said staff have revised a coordination plan with SPP and, pending final direction from the board and additional comments, will negotiate the final revisions with its neighbor.

ERCOT has been working on a new bilateral agreement with SPP since 2016 as a result of its switchable generation resource (SWGR) policy review. ERCOT began similar discussions with MISO last year. The three grid operators met to jointly discuss coordination principles and develop updated agreements and are currently taking their coordination plans through their respective stakeholder processes.

Bigbee said the plans offer greater detail around switchable-unit operations during emergency situations. The biggest change authorizes the requesting grid operator to issue directives upon receiving notification of an SWGR’s release. The controlling grid operator is required to notify the resource’s operator that the unit is needed to address an emergency condition in the neighboring region.

The release can be denied should the SWGR’s release “cause or exacerbate” an emergency condition. In the unlikely event of a simultaneous emergency scenario, primary control is assigned to the grid operator when the SWGR’s capacity has been nominated to satisfy that operator’s supply adequacy or capacity planning requirements.

“You may be asking, ‘We don’t even have a capacity market in the ERCOT region. How can we ever be primary?’” Bigbee said. “If the capacity has been nominated to satisfy supply adequacy requirements in the region, then it’s considered to be our capacity. We presume that capacity is going to be available on peak, unless you’ve submitted a notification under the protocols that says the capacity is obligated elsewhere by a contractual obligation during peak-load season.”

ERCOT will post the plans’ final executed versions on its website.

Board Approves Ancillary Service Changes

The board approved the TAC’s recommendation to tweak ERCOT’s ancillary service offerings, which predate the switch from a zonal to a nodal market in 2010. (See “TAC Endorses Granularity to Ancillary Services Products,” ERCOT Technical Advisory Committee Briefs: Jan. 30, 2019.)

The Nodal Protocol revision request (NPRR863) creates a new ERCOT contingency reserve service (ECRS) and modifies responsive reserve service to become primarily a fast frequency response (FFR) service. The changes are designed to provide the grid operator with more “granular tools” to resolve low inertia levels caused by the changing resource mix, and to allow resources to earn compensation for providing primary frequency response.

ERCOT’s ancillary services design has remained the same, as wind, solar and battery resources increase their market presence.

ExxonMobil Power and Gas Services’ Glen Lyons, representing the consumer market segment’s industrial sub-segment, abstained from the vote. Lyons noted the four opposing votes cast during the TAC meeting by industry consumer groups, which opposed the implementation timeline.

FFR will be implemented in 2020 and ECRS no earlier than Jan. 1, 2022.

The board approved eight other NPRRs and two Other Binding Documents revision requests (OBDRRs) on its consent agenda:

• NPRR850: Lays out principles for ERCOT and market participants to follow during a market suspension and restart, and how activities will be settled during those events.
• NPRR871: Gives ERCOT a mechanism to conduct a reliability review through its normal study process of customer- or resource-funded transmission projects, but without providing a recommendation.
• NPRR886: Requires ERCOT, to the extent possible, to provide notice and allow time for comments before executing any new or amended agreement with another control area operator.
• NPRR905: Provides resettlement to reflect the proper distribution of the congestion revenue rights balancing account.
• NPRR907: Replaces the M1a component of the total potential exposure calculation with a value that can vary based on non-banking business days and ERCOT holidays following the specific operating day. The M1a component sets a time period reflecting the number of days between an operating day and the beginning of a mass transition of the market participant’s electric service identifiers.
• NPRR910: Codifies eligibility, pricing and settlement for a resource that has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market, and subsequently receives a reliability unit commitment instruction.
• NPRR911: Reinstates previous language in the applicable protocol sections for determining the real-time LMPs of logical resource nodes for online combined cycle generation resources (CCGRs), following NPRR890’s approval. The LMPs will now be based on their weighted average at the resource node for each of the generation resources in the online CCGRs, using their real-time telemetered outputs to calculate the weight factor.
• NPRR915: Defines batteries and other limited-duration resources and clarifies how their qualified scheduling entities should indicate to ERCOT their unwillingness to be deployed in real time, thus reserving the capacity for expected values above the energy offer curve.
• OBDRR010: Codifies that the high sustained limit for a resource will continue to be included in the online capacity considered in operating reserve demand curve (ORDC) pricing even when that resource has been awarded a three-part supply offer in the day-ahead market but decides not to operate in the real-time market and subsequently receives a RUC instruction. Related to NPRR910.
• OBDRR011: Shifts the ORDC’s loss-of-load probability curve by 0.25 standard deviations in 2019 and by the same measure in 2020, resulting in a single blended ORDC curve.