By: Schwertner, et al. S.B. No. 7

A BILL TO BE ENTITLED

AN ACT

relating to the reliability of the ERCOT power grid.

BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:

SECTION 1. The heading to Section 39.159, Utilities Code, as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021, is amended to read as follows:

Sec. 39.159. POWER REGION RELIABILITY AND DISPATCHABLE GENERATION.

SECTION 2. Section 39.159, Utilities Code, as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021, is amended by amending Subsection (b) and adding Subsections (b-1), (b-2), (d),(e), and (f) to read as follows:

(b) The commission shall ensure that the independent organization certified under Section 39.151 for the ERCOT power region:

(1) establishes requirements to meet the reliability needs of the power region;

(2) periodically, but at least annually, determines the quantity and characteristics of ancillary or reliability services necessary to ensure appropriate reliability during extreme heat and extreme cold weather conditions and during times of low non-dispatchable power production in the power region;

(3) procures ancillary or reliability services on a competitive basis to ensure appropriate reliability during extreme heat and extreme cold weather conditions and during times of low non-dispatchable power production in the power region;

(4) develops appropriate qualification and performance requirements for providing services under Subdivision (3), including appropriate penalties for failure to provide the services; [and]

(5) sizes the services procured under Subdivision (3) to prevent prolonged rotating outages due to net load variability in high demand and low supply scenarios; and

(6) allocates the cost of providing ancillary services and reliability services procured under this section on a semiannual basis among dispatchable generation facilities, non-dispatchable generation facilities, and load serving entities in proportion to their contribution to unreliability during the highest net load hours in the preceding six months, as determined by the commission based on a number of hours adopted by the commission for that six-month period, as follows:

(A) for each dispatchable generation facility, the difference between the forced outage rate of the facility and the forced outage rate of the facility during the corresponding season for the three years prior to the current season, multiplied by the installed capacity of the facility;

(B) for non-dispatchable generation facilities, the difference between the mean of the lowest quartile generation for each non-dispatchable generation facility and the mean generation of the facility; and

(C) for each load serving entity, the difference between the mean of the highest quartile of total ERCOT load and the mean of total ERCOT load during the net load hours, multiplied by the load ratio share of each load serving entity during the net load hours.

(b-1) Subsection (b)(6) applies only to a generation facility or load serving entity that has participated in the ERCOT market for at least one year, including a load serving entity whose parent company or affiliate has participated in the ERCOT market for at least one year.

(b-2) Subsection (b)(6) does not apply to electric energy storage.

(d) The commission shall require the independent organization certified under Section 39.151 for the ERCOT power region to develop and implement an ancillary services program to procure dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. Under the required program, the independent organization shall:

(1) determine the quantity of services necessary based on historical variations in generation availability for each season based on a targeted reliability standard or goal, including intermittency of non-dispatchable generation facilities and forced outage rates, for dispatchable generation facilities;

(2) develop criteria for resource participation that require a resource to:

(A) be capable of running for at least four hours at the resource's high sustained limit;

(B) be online and dispatchable not more than two hours after being called on for deployment; and

(C) have the dispatchable flexibility to address inter-hour operational challenges; and

(3) reduce the amount of reliability unit commitment by the amount of dispatchable reliability reserve services procured under this section.

(e) The commission may adopt additional programs under Subsection (b) (6) at the same time as the program adopted under Subsection (d).

(f) Notwithstanding Subsection (d)(2)(A), the independent organization certified under Section 39.151 for the ERCOT power region may require a resource to be capable of running for more than four hours as the organization determines is needed.

SECTION 3. Subchapter D, Chapter 39, Utilities Code, is amended by adding Section 39.1591 to read as follows:

Sec. 39.1591. REPORT ON DISPATCHABLE AND NON-DISPATCHABLE GENERATION FACILITIES. Not later than December 1 of each year, the commission shall file a report with the legislature that:

(1) includes:

(A) the estimated annual costs incurred under this subchapter by dispatchable and non-dispatchable generators to guarantee that a firm amount of electric energy will be provided for the ERCOT power grid; and

(B) as calculated by the independent system operator, the cumulative annual costs that have been incurred in the ERCOT market to facilitate the transmission of non-dispatchable and dispatchable electricity to load and to interconnect transmission level loads;

(2) documents the status of the implementation of this subchapter, including whether the rules and protocols adopted to implement this subchapter have materially improved the reliability, resilience, and transparency of the electricity market; and

(3) includes recommendations for any additional legislative measures needed to empower the commission to implement market reforms to ensure that market signals are adequate to preserve existing dispatchable generation and incentivize the construction of new dispatchable generation sufficient to maintain reliability standards for at least five years after the date of the report.

SECTION 4. Subchapter D, Chapter 39, Utilities Code, is amended by adding Section 39.1595 to read as follows:

Sec. 39.1595. RELIABILITY PROGRAM. (a) Under Section 39.159(b), as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021, or other law, the commission may not adopt a reliability program for the ERCOT power region that requires the purchase of capacity credits earned by generators to support a reserve margin mandate unless the commission ensures that:

(1) the cost to the ERCOT market of the credits does not exceed $500 million annually;

(2) credits are available only for dispatchable generation, excluding load resources and electric energy storage;

(3) the cost of credits is assigned to generation facilities and load serving entities according to Section 39.159(b)(6), as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021;

(4) the program includes appropriate penalties for a failure to perform during a reliability event caused by factors within the reasonable control of the generator, including a requirement for a generator to buy back credits that the generator sold but for which the generator did not provide the required capacity;

(5) the independent organization certified under Section 39.151 for the ERCOT power region begins implementing real time co-optimization of energy and ancillary services in the ERCOT wholesale market before the program is implemented;

(6) all elements of the program are initially implemented on a single starting date;

(7) the terms of the program and any associated market rules do not assign costs, credit, or collateral for the program in a manner that provides a cost advantage to load serving entities who own, or whose affiliates own, generation facilities;

(8) generators who receive credits may not self-arrange credit exchanges with any affiliated competitive retail electric providers;

(9) secured financial credit and collateral requirements are adopted for the program to ensure that other market participants do not bear the risk of nonperformance or nonpayment;

(10) qualifying generators do not receive credits that exceed the amount of generation bid into the forward market on an individual resource basis; and

(11) the wholesale electric market monitor has the authority and necessary resources to investigate potential instances of market manipulation by program participants, including financial and physical actions, and recommend penalties to the commission.

(b) This section does not require the commission to adopt a reliability program that requires an entity to purchase capacity credits.

(c) The commission and the independent organization certified under Section 39.151 for the ERCOT power region shall consider comments and recommendations from a technical advisory committee established under the bylaws of the independent organization that includes market participants when adopting and implementing a program described by Subsection (a), if any.

(d) If the commission adopts a program described by Subsection (a), not later than January 1, 2029, the commission shall require the wholesale electric market monitor to submit to the commission and the legislature a report on the costs and benefits of continuing the program. This subsection expires September 1, 2029.

SECTION 5. (a) Not later than September 1, 2024, the Public Utility Commission of Texas shall implement the changes in law made by this Act to Section 39.159(b), Utilities Code, as added by Chapter 426 (S.B. 3), Acts of the 87th Legislature, Regular Session, 2021.

(b) The Public Utility Commission of Texas shall require the independent organization certified under Section 39.151, Utilities Code, for the ERCOT power region to implement the program required by Section 39.159(d), Utilities Code, as added by this Act, not later than December 1, 2024.

(c) The Public Utility Commission of Texas is required to prepare the portions of the report required by Sections 39.1591(2) and (3), Utilities Code, as added by this Act, only for reports due on or after December 1, 2024.

SECTION 6. This Act takes effect immediately if it receives a vote of two-thirds of all the members elected to each house, as provided by Section 39, Article III, Texas Constitution. If this Act does not receive the vote necessary for immediate effect, this Act takes effect September 1, 2023.