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.