AUSTIN, Texas — ERCOT celebrated a trio of memorable anniversaries Tuesday by getting part of the band back together for its Annual Membership Meeting.

ERCOT, which became the first ISO in the U.S. 20 years ago, also marked its 15th anniversary as the single control area for the state’s competitive market and the 75th anniversary of the Texas Interconnected System, when the state’s utilities banded together to ship power to the shipyards and refineries on the Gulf Coast during World War II.

“We remain the only independent, state-controlled system operator,” ERCOT CEO Bill Magness told the membership, “and we like it that way.”

To mark the occasion, ERCOT unveiled a historical video and brought back its first Board of Directors chairman, former Oncor president Mike Greene, to introduce one of the primary architects of the state’s electric restructuring bill as the meeting’s guest speaker. Steve Wolens, a retired 12-term Democratic state representative, worked with Republican State Sen. David Sibley to push Senate Bill 7 through the Texas Legislature in 1999 against only four opposing votes.

Greene name-dropped former Texas PUC commissioner and current ERCOT Director Judy Walsh, former FERC and PUC commissioner Pat Wood and others from the past before eventually introducing Wolens.

“My role has been reversed. I’m standing at the microphone, and Steve is in the audience wondering what I’m going to say,” Greene said, before taking a pause. “I’m actually starting to enjoy this.”

“It’s an honor to be back,” said Wolens, pegged by Texas Monthly in 1999 as the “Intellectual Gladiator” for his legislative work. The magazine noted Wolens “produced an electricity deregulation bill that won the support of consumers, environmentalists and utilities.” When the bill passed, Wolens’ colleagues honored him with a standing ovation.

Wolens, who also led a push to reform ethics laws before retiring from the Legislature in 2005, was recently named by Texas House Speaker Joe Straus to serve on the Texas Ethics Commission. His term will last until November 2019.

Recounting SB7’s history, Wolens said “there was no reason to restructure in the 90s,” given Texas had the lowest electric rates in the country. However, the state also had some of the highest bills ($1,064 annually for the average residential customer, he said) and a reserve margin that was predicted to drop below 8% by 2004.

“And here we were in Texas, boasting about the state and boasting about our growth.”

Wolens said the inability to get energy companies to invest and Ohio-based American Electric Power’s announcement that it would acquire Dallas-based Central and South West Corp. in 1997 gave the restructuring legislation a boost.

“We had to bring more certainty, more reliability to the market,” he said. “Our goal was to reduce the risk to private investment and do whatever we could to keep the local companies we had.”

The key to SB7 was its price-to-beat (PTB) measure, Wolens said. The bill required incumbent utilities to take a 6% rate cut and hold that for three years, or until they lost 40% of their previously regulated market share.

This was to discourage what Texas had seen in other restructured markets, Wolens said. “We had seen it all,” he said, referring to trucking, banking and airline deregulation. “Once you deregulate, the incumbent in that particular industry, the powerful player, cuts rates and drives everyone else out of business. The three years allowed new competitors to come in.”

And that’s exactly what happened in the ERCOT market. Wolens noted nearly 200 residential retail electric providers currently operate in the state, offering in his estimation some 2,000 plans to choose from. The ERCOT market will record its lowest average energy prices this year ($24.64/MWh) since the market opened ($25.64/MWh in 2002).

“The PTB was the DNA of the entire bill,” Wolens said.

SB7 and the ensuing $7 billion Competitive Renewable Energy Zone transmission project, which connected windy West Texas with the growing urban population centers to the east, has given the state almost 18,000 MW of installed wind capacity. If the Lone Star State were its own country, it would rank sixth in the world in wind capacity.

The Texas market is so strong, Wolens said, it will survive a future that may include the country’s withdrawal from the Paris Agreement, the loss of wind and solar tax credits and “installing a climate denier” at EPA.

“All those issues aside, it’s not going to make a difference because the market is vibrant,” he said. “It’s exactly what we hoped for in 1999.”

Magness Celebrates ERCOT’s Achievements

Magness listed ERCOT’s 2016 achievements before the luncheon began, including maintaining a reliable system and efficient market, upgrading the Energy Management System, revising the criteria for reliability-must-run studies, completing transmission improvements in the Rio Grande Valley and integrating wind generation.

The ERCOT market generated more than 15,000 MW of wind energy for the first time in 2016, setting a new record of 15,033 MW in November. It also recorded three new marks for wind penetration during the year, topping out at 48.28% of load in March.

Magness credited stakeholders’ collaboration with staff and their forward thinking with making the records possible.

“We’ve always said if we can see it, we can integrate it,” he said. “When we hit 15,000 MW of wind and high penetration levels, people asked, ‘How do you do that? How is that possible?’ It’s possible because in ERCOT, when those things start to happen, we talk about it. That’s the value of thinking ahead while still in real time.”

ERCOT also set a new system peak (71,110 MW on Aug. 11), two monthly demand highs (during a warmer-than-normal September and October) and a new weekend peak (Aug. 7). The ISO’s annual Capacity, Demand and Reserve report released Thursday foresees demand rising to more than 77,000 MW by the summer of 2021. (See related story, ERCOT Sees Increased Load Growth, Shrinking Margins.)

Increasing Demand Boosts Finances

The high demand in the fall means the ISO should go into 2017 — the second year of its two-year spending plan — with net revenues as much as $13 million above budget. Also helping ERCOT’s finances are savings in resource management costs (primarily staffing management and project work), expected to come in $3.9 million under budget, and computer hardware purchases, at $1.9 million under budget.

“We challenged ourselves as a management team to maintaining some flexibility for ourselves, going into [the] second year,” Magness said. “We’re committed to keeping a flat [administrative] fee for at least two years. Keeping that budget discipline is going to be really important in maintaining that. One year in, we feel like we’re in a pretty good place.”

Magness also said ERCOT’s “technology refresh” to update aging computer technology is well underway. The four-year project began in 2015 and is forecast to come in at or under its $48 million budget. Magness said 60% of the contracts are locked in place, with 21% of the hardware already deployed.

Board Passes Transmission Planning Change

The board easily passed the only contested revision request before it, a planning guide change revising the criteria used to determine the need for new transmission projects that faced some pushback at the Technical Advisory Committee earlier this month. (See ERCOT Addresses Transmission Planning Challenges with New Rule.)

Valero Services’ Jack Durland, representing the Industrial Consumer sector, cast the lone dissenting vote. He questioned the planning guide revision request’s (PGRR) “bounded higher of” load forecast methodology, in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone, and the need for two additional staffers to work on the planning process.

“Does one size fit all the [ERCOT] regions?” Durland asked. “If it doesn’t, we’ll end up with constraints, specifically in Houston. We’d like to see maybe some backcasting to understand this higher boundary methodology actually does fit most scenarios.”

PGRR042 defines considerations for selecting the most appropriate demand forecast in planning studies and how to model certain generation resources, such as mothballed units or those that can be also be connected outside the ERCOT region, in planning cases. It also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements but have not met all the requirements to be included in transmission planning studies.

Warren Lasher, ERCOT’s senior director of system planning, told the board the ISO will “grey box” the PGRR’s language before formally codifying it for 2018. In the meantime, he promised staff would work closely with stakeholders throughout next year “to ensure we have an appropriate mechanism to make sure we have adequate transmission.”

“We have been having discussions with stakeholders about doing backcasts for the forecasts in the planning working groups,” Lasher said, “and we will continue to have those discussions … to make sure that the needs of customers, especially in the Houston region, and other regions of the state are met.”

“I can tell you with confidence that we can move around folks,” Magness said, addressing the staff additions. “Two [full-time employees], we can handle.”

Magness reminded stakeholders that PGRR042 came from a Public Utility Commission of Texas request to re-evaluate ERCOT’s planning process, part of the commission’s approval order for the Houston Import Project, a $590 million initiative due to be completed by summer 2018.

“This planning guide became the vehicle for the analysis,” he said. “Our folks feel comfortable they have sufficient flexibility and options for making sure the change works. It was a successful accommodation … of something we could work with, and we felt like folks in the market could work with, as well.”

New Board, TAC Members Approved

The ERCOT board approved Calpine’s Randy Jones and Source Power & Gas’ John Werner as new members of the board for 2017. The two, who served as alternates last year, will represent the Independent Generator and Independent Retail Electric Provider segments, respectively.

Jones is switching places with E.ON Climate and Renewables’ Kevin Gresham, while Werner replaces Direct Energy’s Read Comstock.

The board has yet to fill the unaffiliated position vacated by Jorge Bermudez, who resigned from the board in October when his pending marriage created a conflict of interest. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)

“We were distressed to find out you love someone more than us,” joked Board Chair Craven Crowell, before presenting Bermudez with a resolution honoring his service.

The board also approved the Lower Colorado River Authority’s John Dumas and Golden Spread Electric’s Mike Wise (Cooperatives), SESCO’s David Hastings (Independent Power Marketers) and Direct Energy’s Sandra Morris and Noble Americas Energy Solution’s Clint Sandidge (Independent Retail Electric Providers) as new TAC members.

Ancillary Service Changes, NPRRs Sail Through

The directors unanimously approved “very minimal” changes to the minimum ancillary service requirements, after two years of more substantial changes.

Staff limited its changes to regulation service. It proposed removing the exhaustion rate feedback metric from the regulation-procurement analysis, estimating five-minute net load variability by including solar generation and making annual updates to the 2013 General Electric study’s tables reflecting incremental installed wind generation.

The board also unanimously approved a clean Statement on Standards for Attestation Engagements (SSAE) No. 16 audit report, modifications to forms ensuring the credit worthiness of market participants and five changes to the 2016 list of key performance indicators used to drive organizational performance.

The board consent agenda, which passed unanimously, listed eight nodal protocol revision requests (NPRRs):

• NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
• NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
• NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analysis, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
• NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities; restores the IEL for traders (inadvertently omitted from NPRR741) and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
• NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. The approval resulted in the TAC conducting an email vote on a related nodal operating guide request, NOGRR164, which was approved Thursday, 21-0.
• NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
• NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
• NPRR803: Removes un-codified language from NPRR439, which was approved four years ago to allow counterparties to increase their credit limit for the day-ahead market’s current day.

-Tom Kleckner