By Tom Kleckner

Staff Revisiting 2018 Playbook in Planning for 2019’s Slim Reserve Margins

AUSTIN, Texas — ERCOT is repeating many of the preparations it took before last summer — and adding others — as it looks ahead to even tighter reserve margins in 2019.

CEO Bill Magness told the Board of Directors on Dec. 11 that meetings have already begun with stakeholders as the grid operator begins preparations to take on summer load with an 8.1% reserve margin. Staff and stakeholders collaborated similarly last year to minimize generation downtime and ensure the availability of resources during the high-demand periods.

ERCOT’s 2017 year-end capacity, demand and reserves report revealed a 9.3% reserve margin. A 525-MW increase in generation capacity helped improve that margin to 11% before the summer season began. The grid operator met 14 new demand peaks above the previous record without resorting to emergency measures.

“As we did last summer, and with tight reserves expected, we’re going in and talking with all of you … on the things we can be doing and the things we can be doing together to make sure that we’re ready for a tight summer,” Magness said.

DeAnn Walker, chair of the Texas Public Utility Commission, has already coordinated meetings between the electric sector and gas pipelines.

Separately, ERCOT has made distributed energy resources and switchable units — interconnected to other regions but available to ERCOT — a point of emphasis. The board’s recently approved Nodal Protocol revision request (NPRR869) requires certain behind-the-meter generators over 1 MW to provide modeling information. Staff has also been working to clarify operating agreements with SPP and MISO over the use of switchable units.

“It’s incredibly important that your model reflect what is on your system when you have tight conditions, and you really need to know what to expect,” Magness said.

Another measure, NPRR901, part of the board’s consent agenda last week, adds a new resource status code for switchable resources operating in a non-ERCOT control area. Magness said a staff proposal, NPRR912, which is currently before the Protocol Revision Subcommittee, “will address the compensation issue for when units move back and forth.”

“That discussion has begun,” Magness said.

Addressing the shrinking reserve margin, Magness said there were no major retirements akin to 2017’s 4-GW loss of coal-fired capacity. He said a change in the calculation of emergency response reserve service, capacity deratings and delayed renewable and gas projects accounted for 2.5 percentage points of the 2.9-point drop in the reserve margin.

A 564-MW increase in the load forecast for the Far West Texas weather zone, fueled by oil and gas production in the reserves-heavy Permian Basin, represented almost a percentage point decrease in the reserve margin.

The growth has been fueled by the Permian Basin’s rich petroleum reserves, the largest in the U.S. Production has nearly doubled in the last three years, to 3.4 million barrels/day.

“We’ve been talking about Far West Texas load at every board meeting for at least a year, because we continue to see accelerating load growth in that area, an area with very little load until recently,” Magness said.

He noted the board has approved transmission projects in recent years to meet the growing demand. (See ERCOT Board Approves $53.3M Economic Tx Project, and “$327M in Tx Projects will Meet Permian Basin’s Load Growth,” ERCOT Board of Directors Briefs: June 12, 2018.)

Revenues Up

ERCOT is looking at a $26.1 million favorable variance in net revenues, Magness said, mostly because of an $11 million gain in interest income and a $7.5 million jump in system administration fees.

“I wish I could credit that to our financial wizardry, but it is more that revenues have increased substantially over what was originally budgeted,” Magness said.

Staff used an interest rate of about 0.37% when they drafted the biennial 2018-19 budget. Magness noted rates have increased to a “shocking” 1.73% since then.

“That’s something, as we budget for 2020, we see ourselves correcting as we align that more with current interest rates,” he said.

New World of Gas Prices for Market

Beth Garza, executive director of ERCOT’s Independent Market Monitor, warned stakeholders that the market is “heading into a very different natural gas world.”

“We’re starting to see some very different gas prices than we’ve seen the last few years,” she said during her regular board report.

The Monitor uses Houston Ship Channel prices as its underlying index price. Garza said the index’s November prices are at $4.10/MMBtu after almost two years in the $2/MMBtu range.

The increase in gas prices has resulted in an accompanying 24% increase in average real-time energy prices, to $35.90/MWh through October. Prices were at $29/MWh a year ago, on their way to finishing 2017 at $28.30/MWh.

Forward prices for summer 2019 are also on the rise, Garza said, with $173/MWh prices for August as of Nov. 23.

“That’s not as high as we saw heading into July and August of last [summer], but we’re in December,” she said.

ERCOT Staff Share 5-Year Strategic Plan

Staff delivered an overview of the 2019-2023 strategic plan, telling the board and stakeholders that ERCOT’s leadership is setting up the organization to “quickly adapt to those changes that may come to us.”

“What we are required to do as an organization has not changed, but we must proactively change how we do things so that we can keep up with those things that are happening to us,” said Kristi Hobbs, ERCOT’s director of enterprise risk management and strategic analysis, who led the team.

The team solicited feedback from 200 stakeholders in drafting a plan that lists four objectives:

• Enhancing operating capabilities to maintain reliability in an increasingly complex system;
• Improving information exchange to facilitate collaboration;
• Advancing competitive solutions to industry changes; and
• Optimizing the use of ERCOT resources to “continuously provide high-value services.”

In an opening message, Magness wrote that there is no magic to the five-year time horizon, but that it “does require us to think far enough into the future to consider potential technological, economic and policy changes.”

2019 Board Members, TAC Reps Approved

Members approved and confirmed directors and segment alternates to the board for 2019 during ERCOT’s 48th Annual Membership Meeting.

Exelon’s Bill Berg and Direct Energy’s Ned Ross will join the board as segment alternates in the Independent Generator and Independent Retail Electric Provider segments, respectively. Berg replaces Luminant’s Amanda Frazier, and Ross steps in for VEH’s Mohsin Hassan.

Two board positions are vacant. The Consumer-Texas Office of Public Utility Counsel position is empty, following the recent departure of Tonya Baer, who has become the deputy director for the Texas Commission on Environmental Quality’s Office of Air.

The board also has a vacancy in the Unaffiliated segment.

The board previously confirmed the Technical Advisory Committee’s members for 2019.

The TAC will welcome Brandon Whittle (Calpine), Marty Downey (Electranet Power) and David Kee (CPS Energy) as new members. They replace Thresa Allen (Avangrid Renewables), Read Comstock (Source Power & Gas) and John Bonnin (CPS), respectively.

TAC will hold its meetings on the fourth Wednesday of the month next year, a switch from Thursdays.

Board Approves Staff Recs, 31 Change Requests

The board unanimously approved ERCOT’s key performance indicators for 2019 staff compensation and Schellman & Co.’s 2018 system and organization control audit report, which found no exceptions. It also approved two TAC-endorsed staff recommendations: an increase from 5% to 7.5% of the boundary threshold used in calculating load forecasts for Far West Texas, and removing a 1,375-MW floor on non-spinning reserves, part of the annual review of ERCOT’s methodology for determining ancillary service requirements. (See ERCOT Technical Advisory Committee Briefs: Nov. 29, 2018.)

The board also unanimously passed a consent agenda that included 14 NPRRs, a Load Profiling Guide revision request (LPGRR), two changes to the Nodal Operating Guide (NOGRRs), three Other Binding Document revisions (OBDRRs), four changes to the Planning Guide (PGRRs), a Retail Market Guide change (RMGRR), two revisions to the Resource Registration Glossary (RRGRR) and a system change request (SCR):

• NPRR878: Emergency response service obligation report for transmission and/or distribution service providers.
• NPRR879: Security-constrained economic dispatch base point, base point deviation and performance evaluation changes for intermittent renewable resources (IRRs) that carry ancillary services.
• NPRR881: Reduces the residential validations requirements from an annual process to a triennial market event.
• NPRR882: Procedures for wind and solar equipment change. (Related to PGRR067.)
• NPRR884: Introduces systems changes needed to manage cases when ERCOT issues a reliability unit commitment instruction to a combined cycle resource that is already a qualified scheduling entity committed for an hour. The resource will operate in a configuration with greater capacity for that same hour.
• NPRR887: Creates a new market information system certified area posting that provides insight into the potential risk associated with each counterparty’s default uplift charges.
• NPRR892: Places a $75/MWh floor on energy for units carrying non-spinning reserve and responsive reserves and/or regulation up service concurrently to ensure the non-spin capacity is priced above the floor.
• NPRR893: Clarification of fuel index price and incorporation of systemwide offer cap and scarcity pricing mechanism methodology into protocols.
• NPRR894: Corrects the formula for allocating unaccounted for energy (UFE) to UFE categories by removing obsolete components.
• NPRR895: Removes the current exclusion for IRRs that are not wind-powered in calculating the real-time ancillary services imbalance payment or charge. Photovoltaic generation resources are currently excluded in both the methodology for implementing the operating reserve demand curve to calculate the real-time reserve price adder and the process for settling the real-time ancillary services imbalance payment or charge.
• NPRR897: Adjusts the black start service procurement and testing process timeline, adds a weather limitation disclosure form and aligns the load-carrying test procedure with actual practice.
• NPRR898: Allows the electronic return of ERCOT-polled settlement metering site certification documents to the transmission and/or distribution service provider.
• NPRR899: Creates a new process by which qualified market participants can opt out of receiving digital certificates and having to appoint a user security administrator (USA); clarifies ambiguous requirements certificate holders must meet to receive and continue to hold digital certificates; and clarifies that a USA may be responsible for managing access to certain ERCOT computer systems that do not require digital certificates.
• NPRR901: Proposes a new resource status code (“EMRSWGR”) for switchable generation resources operating in a non-ERCOT control area to provide additional transparency for operations and reporting.
• LPGRR065: Related to NPRR881, this change reduces the residential validations requirements from an annual process to a triennial market event and removes unnecessary load profile model approval process language.
• NOGRR178: Clarifies language relating to automatic load shedding.
• NOGRR182: Harmonizes the transmission operator emergency operations plan submittals with NERC reliability standard EOP-011-1 by clarifying that TOP plans should be received by Feb. 15 as part of the annual effort to review them within 30 days.
• OBDRR006: Aligns language with NPRR884’s changes.
• OBDRR007: Changes the ORDC’s methodology to consider curtailed PV resources in determining the ORDC price adders.
• OBDRR009: Revises the online and offline capacity reserves for ERCOT out-of-market actions related to DC ties.
• PGRR065: Documents and clarifies existing processes by including transmission project information and tracking report and data requirements.
• PGRR066: Creates an inactive status generation interconnection or change request (GINR) projects that won’t be listed in ERCOT’s monthly generation interconnection status report but will retain the interconnection request numbers. Also defines a process that can be used to cancel interconnection requests that have failed to meet requirements.
• PGRR067: Describes how wind and solar facility equipment changes are treated throughout the generation interconnection process and clarifies language for GINR-related fees.
• PGRR068: Lays out the process for adding a DC tie to ERCOT’s planning models and associated requirements; related to the Texas PUC’s directive to determine how to model the proposed Southern Cross DC tie in its planning cases (Project 46304). (See “Staff’s Determination on DC Tie Flows, Pricing Gets OK ,” ERCOT Board of Directors Briefs: Oct. 9, 2018.)
• RMGRR155: Related to NPRR889, the change uses the new term, settlement-only distribution generator (SOG), to replace references to non-modeled generator and registered distributed generation.
• RRGRR018: Also related to NPRR889, uses the SOG term to replace glossary references to non-modeled generator.
• RRGRR019: Adds a modeling designation for switchable generation resources (SWGRs) to the resource asset registration form, indicating that SWGRs can potentially operate in another control area.
• SCR797: Allows ERCOT to automatically share current operating plans with a transmission service provider upon request by that provider.