Bill Text: TX SB7 | 2023-2024 | 88th Legislature | Comm Sub

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Bill Title: Relating to the reliability of the ERCOT power grid.

Sponsorship: Partisan Bill (Republican 5)

Status: (Engrossed - Dead) 2023-05-26 - House appoints conferees-reported [SB7 Detail]

Download: Texas-2023-SB7-Comm_Sub.html

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88R31129 CXP-D
By: Schwertner, et al. S.B. No. 7
(Hunter)
Substitute the following for S.B. No. 7: No.

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 adding Subsections (d), (e), and (f) to
read as follows:
(d) The commission shall require the independent
organization certified under Section 39.151 for the ERCOT power
region to consider implementing an ancillary services program to
procure dispatchable reliability reserve services on a day-ahead
and real-time basis to account for market uncertainty. The program
to be considered may:
(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 or for more than four hours
as the organization determines is needed;
(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 independent organization certified under Section
39.151 for the ERCOT power region may implement programs described
by Subsections (d) and (f) simultaneously.
(f) The commission shall require the independent
organization certified under Section 39.151 for the ERCOT power
region to develop and implement a program to ensure minimum
generation performance during times of high reliability risk due to
low operating reserves. The program must:
(1) apply to each electric power generation resource
in the ERCOT power region that enters into a signed generator
interconnection agreement after January 1, 2026;
(2) be independently evaluated by the wholesale
electric market monitor, including a historical analysis;
(3) allow entities, at the portfolio level, to meet
the performance requirements by supplementing or contracting with
on-site or off-site resources, including battery energy storage
resources and load resources;
(4) provide penalties for failing to comply with the
performance requirements and financial incentives for exceeding
those requirements, except that penalties may not apply to resource
unavailability due to planned maintenance outages or physical
transmission outages or during hours when the resource would not be
expected to perform based on the resource type; and
(5) exempt battery energy storage resources from the
generation performance requirements.
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 dispatchable and
non-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 39.166 to read as follows:
Sec. 39.166. RELIABILITY PROGRAM. (a) The commission may
not require retail customers or load-serving entities in the ERCOT
power region to purchase credits designed to support a required
reserve margin or other capacity or reliability requirement until:
(1) the independent organization certified under
Section 39.151 for the ERCOT power region and the wholesale
electric market monitor complete an updated assessment on the cost
to and effects on the ERCOT market of the proposed reliability
program; and
(2) 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.
(b) The assessment required under Subsection (a) must
include:
(1) an evaluation of the cost of new entry and the
effects of the proposed reliability program on consumer costs and
the competitive retail market;
(2) a compilation of detailed information regarding
cost offsets realized through a reduction in costs in the energy and
ancillary services markets and use of reliability unit commitments;
(3) a set of metrics to measure the effects of the
proposed reliability program on system reliability;
(4) an evaluation of the cost to retain existing
dispatchable resources in the ERCOT power region;
(5) an evaluation of the planned timeline for
implementation of real time co-optimization for energy and
ancillary services in the ERCOT power region; and
(6) anticipated market and reliability effects of new
and updated ancillary service products.
(c) The commission may not implement a reliability program
described by Subsection (a) unless the commission by rule
establishes the essential features of the program, including
requirements to meet the reliability needs of the power region, and
the program:
(1) requires the independent organization certified
under Section 39.151 for the ERCOT power region to procure the
credits centrally in a manner designed to prevent market
manipulation by affiliated generation and retail companies;
(2) limits participation in the program to
dispatchable resources with the specific attributes necessary to
meet operational needs of the ERCOT power region;
(3) ensures that a generator cannot receive credits
that exceed the amount of generation bid into the forward market by
that generator;
(4) ensures that an electric generating unit can
receive a credit only for being available to perform in real time
during the tightest intervals of low supply and high demand on the
grid, as defined by the commission on a seasonal basis;
(5) establishes a penalty structure, resulting in a
net benefit to load, for generators that bid into the forward market
but do not meet the full obligation;
(6) provides the wholesale electric market monitor
with the authority and resources necessary to investigate potential
instances of market manipulation by any means, including by
financial or physical actions;
(7) ensures that any program reliability standard
reasonably balances the incremental reliability benefits to
customers against the incremental costs of the program based on an
evaluation by the wholesale electric market monitor;
(8) establishes a single ERCOT-wide clearing price for
the program and does not differentiate payments or credit values
based on locational constraints;
(9) does 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;
(10) requires sufficient secured collateral so that
other market participants do not bear the risk of non-performance
or non-payment;
(11) ensures that the cost of all credits paid to
dispatchable resources is allocated to loads based on an hourly
load ratio share; and
(12) removes any market changes implemented as a
bridge solution for the program not later than the first
anniversary of the date the program was implemented.
(d) The commission and the independent organization
certified under Section 39.151 for the ERCOT power region may not
adopt a market rule for the ERCOT power region associated with the
implementation of a reliability program described by Subsection (a)
that provides a cost advantage to load-serving entities who own, or
whose affiliates own, generation facilities.
(e) The commission and the independent organization
certified under Section 39.151 for the ERCOT power region shall
ensure that the net cost imposed on the ERCOT market for the credits
does not exceed $1 billion annually, less the cost of any interim or
bridge solutions that are lawfully implemented, except that the
commission may adjust the limit:
(1) proportionally according to the highest net peak
demand year-over-year with a base year of 2026; and
(2) for inflation with a base year of 2026.
(f) The wholesale electric market monitor biennially shall:
(1) evaluate the incremental reliability benefits of
the program for consumers compared to the costs to consumers of the
program and the costs in the energy and ancillary services markets;
and
(2) report the results of each evaluation to the
legislature.
SECTION 5. (a) Not later than September 1, 2024, the
Public Utility Commission of Texas shall implement the changes in
law made by Section 39.159(f), Utilities Code, as added by this Act.
(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.
(d) Not later than December 31, 2024, the wholesale electric
market monitor described by Section 39.1515, Utilities Code, shall
submit to the legislature recommendations regarding the
implementation of the program required by Section 39.159(f),
Utilities Code, as added by this Act.
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.