AUSTIN, Texas — The ERCOT Board of Directors last week unanimously approved a $246.7 million transmission project to address growing energy needs along the Texas Gulf Coast.

The Freeport Master Plan Project was endorsed in November by the Technical Advisory Committee before coming to the board Dec. 12. (See ERCOT Stakeholders OK $246.7M in Freeport Reliability Projects.)

Freeport is a highly industrialized region with several large chemical facilities and a major seaport. ERCOT projects that by 2019, the Freeport area’s load will increase 92% to 1,979 MW, with much of that growth coming from a large chemical plant. An additional 300 MW is expected by the end of 2022.

“We continue to see growing demand for electricity in the ERCOT region, especially in areas affected by industrial growth and oil and gas activity,” said ERCOT Senior Manager of Transmission Planning Jeff Billo.

The ISO’s independent review of the project confirmed its necessity. Staff analyzed five options and proposed the most cost-effective to support future electric needs in the area.

CenterPoint Energy, which services the area, suggested a two-phase approach to solve reliability criteria violations caused by the increased load. A $32.3 million first phase, or “bridge-the-gap upgrades,” focuses on near-term reliability needs with a 345-kV loop and a series of reactors, autotransformers and capacitor banks at a key substation.

The $214.4 million second phase comprises a new 48-mile, 345-kV double-circuit line and circuit upgrades to another 345-kV line.

Any projects approved by ERCOT that cost $50 million or more are classified as Tier 1 initiatives and require board approval.

The project must also be approved by the Public Utility Commission of Texas. Work is expected to be completed by 2022.

NPRRs Clear Board, Despite Opposition

The board approved two nodal protocol revision requests (NPRRs) recently taken off the table by the TAC, but with varying degrees of opposition.

Brazos Electric Power Cooperative’s Clifton Karnei, representing the cooperative segment, cast the lone dissenting vote against NPRR815. The change increases from 50% to 60% the limit on load resources providing responsive reserve service (RRS), with at least 1,150 MW coming from resources that can provide primary frequency response.

The Protocol Revisions Subcommittee said changing the constraint will allow additional resources to provide RRS at lower costs. However, the Lower Colorado River Authority’s John Dumas, who opposed the measure when it passed the TAC last month, told the board that NPRR815 could harm reliability because of the reduction in generation resources that provide inertia and voltage support. (See “TAC ‘Un-Tables,’ Endorses NPRRs,” ERCOT Technical Advisory Committee Briefs.)

“Our opposition has to do with concerns over reliability risk and commercial risk,” Dumas said. “When you increase the amount of load in responsive reserves, you’re decreasing the amount of potential generation on the grid to manage things like voltage, inertia and ramping capabilities. When you take generation off the grid, you’re reducing reliability, you’re not improving reliability.”

Dumas said the commercial risk comes from a possible increase in RRS price spikes during high-wind, low-load situations.

“You can commit enough capacity to cover your energy position, but you cannot … when you suddenly have a wind variation or a unit trip,” he said. “When you reduce the amount of supply from generation, you’re reducing the offer curve.”

Woody Rickerson, ERCOT’s vice president of grid planning and operations, pushed back on the reliability concerns.

“[NPRR]815 in no way changes what we need for responsive reserves, only how we procure it,” he said. “We’ve gone through probably six months of questions on it. We’ve studied it, and it in no way endangers reliability.”

Rickerson pointed out ERCOT monitors inertia separately from responsive reserves, and that the ISO can always procure more services beyond the minimum amount.

NPRR825 also cleared the board, but with four votes in opposition from cooperative and consumer interests. The revision requires ERCOT to issue a DC tie curtailment notice before curtailing the tie’s load, addressing the ISO’s concerns about declaring an emergency condition before curtailing DC tie load for any reason, staff said.

Several directors were concerned about the NPRR’s price tag — $200,000 to $300,000 in development costs as part of a larger software tool — but staff said the change would result in automated processes and system reports. Rickerson told directors that the day before, staff had to issue a watch to curtail 27 MW.

“It’s increasing transparency in the marketplace,” said unaffiliated director Karl Pfirrmann, speaking in favor of the NPRR. “That should make things more efficient and helps prepare us for emergency situations.”

ERCOT Sees Favorable $8M Budget Variance

ERCOT CEO Bill Magness said the ISO is projecting to end the year nearly $8 million under budget following a warmer-than-normal October.

“Revenues go up, but so does congestion,” he told the board.

A positive variance in October for ERCOT’s system administration fee helped reduce an unfavorable year-end projection to about $100,000. Much of the overall positive variance stems from $4.1 million savings in interest expense because of project funding and minimal revolver usage, and interest income because of higher rates.

Magness said staff has completed their reliability-must-run studies of planned generator retirements and determined none of the units needs to be kept on for reliability needs. He also said the Texas grid is seeing higher-than-expected congestion in the day-ahead market, but that congestion revenue rights funding is not a concern.

IMM: Ancillary Services Market Growing in Importance

Beth Garza, director of the Independent Market Monitor, focused her board report on ancillary services, which have declined with the advent of the nodal market in 2011.

Garza said the services cost $1.03/MWh in 2016 and averaged 87 cents/MWh through Oct. 7, but that is likely to change with the pending retirement of more than 2 GW of aging generation (though those units only have provided 2.5% of regulation up and 6.4% of regulation down in 2017 through October). Regulation up and down have seen the biggest decrease since the zonal market was replaced, with dispatch now occurring every five minutes instead of 15.

“It’s that efficiency of procuring on smaller time frames, and not over-procuring, that has brought the overall average down,” Garza said. “These things we call ancillary will become more important in a future market that has more load to zero-cost variable resources. As the [ancillary services market] becomes more important and [resources] scarcer, as less units are around to provide those services, those prices are likely to become higher and more important going forward.”

Asked if she was comfortable with ERCOT’s ancillary market performance, Garza said the interaction between regulation and security-constrained economic dispatch “continues to be refined,” but she noted total regulation has seen about a two-thirds reduction from the 1,800 MW in the zonal market.

“That balance seems pretty good,” she said.

The Monitor is projecting ERCOT’s real-time prices will be above last year’s record low average of $24.62/MWh. Through the first 10 months of 2017, prices are up 17% to $28.97/MWh compared to the same period last year. Real-time prices settled at $24.

Gas prices averaged $2.44/MMBtu last year but were $3/MMBtu for the first 10 months of 2017.

Membership Approves 5 New Directors

ERCOT’s corporate members approved the election of Terry J. Bulger and the re-election of Peter Cramton to three-year terms during their annual membership meeting. Cramton’s current term will expire on Aug. 1.

Bulger is a 35-year banking professional with ABN AMRO and Bank of Montreal, and has more than 25 years of experience in risk management. Cramton is an economics professor at the University of Maryland and the University of Cologne.

Members also approved four new segment directors, who were previously segment alternates, and their alternates, to serve in 2018. The directors are:

• Industrial consumers — Sam Harper, Chaparral Steel Midlothian
• Independent generators — Kevin Gresham, E.ON Climate & Renewables North America
• Independent retail electric providers — Rick Bluntzer, Just Energy Texas
• Investor-owned utilities — Kenneth Mercado, CenterPoint Energy

The new segment alternates are:

• Industrial consumers — Mark Schwirtz, Golden Spread Electric Cooperative
• Independent generators — Amanda Frazier, Luminant
• Independent retail electric providers — Mohsin Hassan, VEH
• Investor-owned utilities — Mark Carpenter, Oncor

TAC Gets 6 New Members

The membership also approved six new members to the TAC, which makes recommendations to the board and is aided by five subcommittees:

• Independent generators — Ian Haley, Luminant
• Independent power marketers — Kevin Bunch, EDF Energy Services, and former ERCOT staffer Resmi Surendran, Shell Energy North America
• Independent retail electric providers — Sandra Morris, Direct Energy
• Investor-owned utilities — Walter Bartel, CenterPoint
• Municipals — John Bonnin, CPS Energy

Board Clears 4 NPRRs, Other Measures

The board unanimously approved revisions to the methodology for computing responsive reserves as a result of NPRR815’s implementation, and two changes to determining non-spinning reserves in 2018; associated with NPRR815 and two changes to determining non-spinning reserves in 2018; accepted a clean system and organization control audit; and approved new key performance indicators.

The directors also unanimously approved NPRR846 by itself, and three other NPRRs on the consent agenda.

• NPRR846: Allows previously committed emergency response service (ERS) resources to participate in must-run alternative agreements and modifies the methodology for evaluating the impact of ERS load performance during the first partial interval on calculating the alternate baseline. The change also defines acceptable parameters for an ERS generator’s self-serve capacity, and sets the ERS test performance factor to significantly lower values, in some instances to zero for resources with three consecutive test failures within a 365-day period. The NPRR includes additional administrative changes and clarifications to existing ERS protocol language.
• NPRR834: Clarifies processes associated with ERCOT’s repossession of congestion revenue rights following a payment breach or other default by a market participant. The change specifies data transparency requirements; documents the disposition of auction revenue funds above amounts owed to ERCOT; clarifies that the one-time auction bids must be positive; and allows the immediate transfer of CRR ownership to the winning bidder should an auction be necessary.
• NPRR839: Updates the protocols to clarify that, upon receiving meter data transactions from transmission or distribution service providers, ERCOT will forward the transactions to the designated competitive retailer.
• NPRR843: Addresses four reporting items in Section 3 of the Nodal Protocols (Management Activities) by:
  • Changing the logic of short-term system adequacy reports for more consistent treatment of resource status; adding language to provide clarity to the reports’ end users;
  • Creating a new report that will show the portion of ancillary service offers at or above 50 times the fuel index price (FIP) when the market-clearing price for capacity of the service exceeds 50 times FIP;
  • Adding elements to the “48-hour highest price [ancillary service] offer selected” report, including the highest-priced offer selected in a supplemental ancillary service market (SASM); and
  • Creating a SASM disclosure report to provide transparency into ancillary service offers and awards for any SASMs executed within an operating day.

— Tom Kleckner