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.