By: King, et al. S.B. No. 6
A BILL TO BE ENTITLED
AN ACT
relating to electricity planning and infrastructure costs for large
loads.
BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
SECTION 1. Section 35.004, Utilities Code, is amended by
adding Subsections (c-1) and (c-2) to read as follows:
(c-1) The commission by rule shall ensure that a large load
customer who is subject to the standards adopted under Section
37.0561 contributes to the recovery of the interconnecting electric
utility's costs to interconnect the large load to the utility's
system.
(c-2) An electric cooperative or municipally owned utility
that has not adopted customer choice shall pass through to a large
load customer who is subject to the standards adopted under Section
37.0561 the reasonable costs to interconnect the large load in a
manner determined by the electric cooperative or municipally owned
utility.
SECTION 2. Subchapter B, Chapter 37, Utilities Code, is
amended by adding Section 37.0561 to read as follows:
Sec. 37.0561. PLANNING REQUIREMENTS FOR LARGE LOADS. (a)
The commission by rule shall establish standards for
interconnecting large load customers in the ERCOT power region in a
manner designed to support business development in this state while
minimizing the potential for stranded infrastructure costs and
maintaining system reliability.
(b) The standards must apply only to customers requesting a
new or expanded interconnection where the total load at a single
site would exceed a demand threshold established by the commission
based on the size of loads that significantly impact transmission
needs in the ERCOT power region. The commission shall establish a
demand threshold of 75 megawatts unless the commission determines
that a lower threshold is necessary to accomplish the purposes
described by Subsection (a).
(c) The standards must require each large load customer
subject to Subsection (b) to disclose to the interconnecting
electric utility or municipally owned utility whether the customer
is pursuing a substantially similar request for electric service,
inside or outside this state, the approval of which would result in
the customer materially changing, delaying, or withdrawing the
interconnection request. The disclosure may withhold or anonymize
competitively sensitive details. The commission by rule shall
prohibit an electric utility or municipally owned utility from
selling, sharing, or disclosing information submitted to the
utility under this subsection other than a disclosure to the
commission or the independent organization certified under Section
39.151 for the ERCOT power region, subject to appropriate
confidentiality protections.
(d) The standards must require each interconnected large
load customer subject to Subsection (b) to disclose to the
interconnecting electric utility or municipally owned utility
information about the customer's on-site backup generating
facilities and require the interconnecting electric utility or
municipally owned utility to provide the information to the
independent organization certified under Section 39.151 for the
ERCOT power region. For the purposes of this subsection, "on-site
backup generating facilities" means generation that is not capable
of exporting energy to the ERCOT transmission grid and that, in the
aggregate, can serve at least 50 percent of on-site demand. The
independent organization certified under Section 39.151 for the
ERCOT power region shall establish a threshold during an energy
emergency alert where the organization may, after reasonable
notice, direct the applicable electric utility or municipally owned
utility to require the large load customer to either deploy the
customer's on-site backup generating facility or curtail load. The
independent organization certified under Section 39.151 for the
ERCOT power region shall include a deployment under this section as
firm load shed when calculating any price adjustments for
reliability deployments. This subsection does not:
(1) authorize or require a violation of any emissions
limitation in state or federal law or a violation of any other
environmental regulation; or
(2) prohibit a large load customer from participating
in a service authorized by Section 39.170(b).
(e) The standards must set a flat study fee of at least
$100,000 to be paid to the interconnecting electric utility or
municipally owned utility for initial transmission screening
studies for large loads subject to Subsection (b). A large load
customer that requests additional capacity following the screening
study must pay an additional study fee based on the new request.
The interconnecting electric utility or municipally owned utility
shall apply any unused portion of the initial transmission
screening study fee as a credit toward satisfying financial
obligations for procurement or interconnection agreements at the
same geographic site.
(f) The standards must include a method for a large load
customer subject to Subsection (b) to demonstrate site control for
the proposed load location through an ownership interest, lease, or
another legal interest acceptable to the commission.
(g) The standards must include uniform financial commitment
standards for the development of transmission infrastructure
needed to serve a large load customer subject to Subsection (b)
before an electric utility or municipally owned utility may submit
a project for review to the independent organization certified
under Section 39.151 for the ERCOT power region based on the large
load customer's demand. The standards must provide that
satisfactory proof of financial commitment may include:
(1) security provided on a dollar per megawatt basis
as set by the commission;
(2) contribution in aid of construction;
(3) security provided under an agreement that requires
a large load customer to pay for significant equipment or services
in advance of signing an agreement to establish electric delivery
service; or
(4) a form of financial commitment acceptable to the
commission other than those provided by Subdivisions (1)-(3).
(h) Security provided under Subsection (g)(1) must be
refunded, in whole or in part, after the security is applied to any
outstanding amounts owed:
(1) as the large load customer meets the customer's
load ramp milestones and sustains operations for a prescribed
period as determined by the commission; or
(2) if the large load customer withdraws the
customer's request for all or a portion of the requested capacity.
(i) The standards must establish a procedure to allow the
independent organization certified under Section 39.151 for the
ERCOT power region to access any information collected by the
interconnecting electric utility or municipally owned utility to
ensure compliance with the standards for transmission planning
analysis. Any customer-specific or competitively sensitive
information obtained under this subsection is confidential and not
subject to disclosure under Chapter 552, Government Code.
(j) The commission may not limit the authority of a
municipally owned utility or an electric cooperative to impose
retail electric service requirements for large load customers on
their systems in addition to the standards adopted under this
section.
(k) Notwithstanding the forecasted load growth and
additional load currently seeking interconnection required to be
considered under Section 37.056(c-1), the commission by rule shall
establish criteria by which the independent organization certified
under Section 39.151 for the ERCOT power region includes forecasted
large load of any peak demand in the organization's transmission
planning and resource adequacy models and reports.
SECTION 3. Section 39.002, Utilities Code, is amended to
read as follows:
Sec. 39.002. APPLICABILITY. This chapter, other than
Sections 39.151, 39.1516, 39.155, 39.157(e), 39.161, 39.162,
39.163, 39.169, 39.170, 39.203, 39.9051, 39.9052, and 39.914(e),
and Subchapters M and N, does not apply to a municipally owned
utility or an electric cooperative. Sections 39.157(e) and 39.203
apply only to a municipally owned utility or an electric
cooperative that is offering customer choice. If there is a
conflict between the specific provisions of this chapter and any
other provisions of this title, except for Chapters 40 and 41, the
provisions of this chapter control.
SECTION 4. Subchapter D, Chapter 39, Utilities Code, is
amended by adding Sections 39.169 and 39.170 to read as follows:
Sec. 39.169. CO-LOCATION OF RETAIL CUSTOMER WITH EXISTING
GENERATION RESOURCE. (a) A power generation company, municipally
owned utility, or electric cooperative must submit a notice to the
commission and the independent organization certified under
Section 39.151 for the ERCOT power region before implementing a net
metering arrangement between an existing, operating facility
registered with the independent organization as a generation
resource and a new large load customer as described by Section
37.0561(b).
(b) The new net metering arrangement must be requested or
consented to by the electric cooperative, electric utility, or
municipally owned utility certificated to provide retail electric
service at the location. The electric cooperative, electric
utility, or municipally owned utility may withhold consent to a
proposal that is consistent with the determination provided under
Subsection (c) and applicable law only for a reasonable cause.
(c) With input from the independent organization certified
under Section 39.151 for the ERCOT power region, not later than the
180th day after the date the commission receives the notice under
Subsection (a), the commission shall approve, deny, or impose
reasonable conditions on a proposed net metering arrangement
described by Subsection (a) as necessary to maintain system
reliability, including transmission security and resource adequacy
impacts. The conditions may:
(1) require the retail customer who is served
behind-the-meter to reduce load during certain events;
(2) require the generation resource to make capacity
available to the ERCOT power region during certain events; or
(3) provide that the owner of the generation resource
may be held liable for stranded or underutilized transmission
assets resulting from the behind-the-meter operation.
(d) If the commission does not approve, deny, or impose
reasonable conditions on a proposed net metering arrangement before
the expiration of the deadline established by Subsection (c), the
commission is considered to have approved the arrangement.
(e) If conditions imposed under Subsection (c) are not
limited to a specific period, the commission shall review the
conditions at least every five years to determine whether the
conditions should be extended or rescinded.
(f) The parties to a proceeding under this section are
limited to the commission, the independent organization certified
under Section 39.151 for the ERCOT power region, the
interconnecting electric cooperative, electric utility, or
municipally owned utility, and a party in the net metering
arrangement.
Sec. 39.170. LARGE LOAD DEMAND MANAGEMENT SERVICE.
(a) The commission shall require the independent organization
certified under Section 39.151 for the ERCOT power region to ensure
that each electric cooperative, electric utility, and municipally
owned utility serving a transmission-voltage customer develops a
protocol and installs, or requires to be installed, before the
customer is interconnected, any necessary equipment to allow the
load to be curtailed during firm load shed. The electric
cooperative, electric utility, or municipally owned utility shall
confer with the customer to the extent feasible to shed load in a
coordinated manner. This subsection applies only to a load
interconnected after December 31, 2025, that is not:
(1) load operated by a critical load industrial
customer, as defined by Section 17.002; or
(2) designated as a critical natural gas facility
under Section 38.074.
(b) The commission shall require the independent
organization certified under Section 39.151 for the ERCOT power
region to develop a reliability service to competitively procure
demand reductions from large load customers with a demand of at
least 75 megawatts to be deployed in the event of an anticipated
emergency condition. The rules governing this service must:
(1) specify the periods when the service may be used to
assist with maintaining reliability during extreme weather events;
(2) ensure that the independent organization provides
at least a 24-hour notice to large load customers and requires each
large load to remain curtailed for the duration of the energy
emergency alert event or until the load can be recalled safely; and
(3) prohibit participation by any large load customer
that curtails in response to the wholesale price of electricity, as
determined by the independent organization certified under Section
39.151 for the ERCOT power region, or that otherwise participates
in a different reliability or ancillary service.
(c) The independent organization certified under Section
39.151 for the ERCOT power region shall include a deployment under
this section when calculating any price adjustments for reliability
deployments.
SECTION 5. (a) The Public Utility Commission of Texas shall
evaluate whether the existing methodology used to charge wholesale
transmission costs to distribution providers under Section
35.004(d), Utilities Code, continues to appropriately assign costs
for transmission investment. The commission shall also evaluate:
(1) whether the current four coincident peak
methodology used to calculate wholesale transmission rates ensures
that all loads appropriately contribute to the recovery of an
electric cooperative's, electric utility's, or municipally owned
utility's costs to provide access to the transmission system;
(2) whether alternative methods to calculate
wholesale transmission rates would more appropriately assign the
cost of providing access to and wholesale service from the
transmission system, such as consideration of multiple seasonal
peak demands, demand during different length daily intervals, or
peak energy intervals; and
(3) the portion of the costs related to access to and
wholesale service from the transmission system that should be
nonbypassable, consistent with Section 35.004(c-1), Utilities
Code, as added by this Act.
(b) The Public Utility Commission of Texas shall evaluate
whether the commission's retail ratemaking practices ensure that
transmission cost recovery appropriately charges the system costs
that are caused by each customer class.
(c) The Public Utility Commission of Texas shall begin the
evaluation required under Subsection (a) of this section not later
than the 90th day after the effective date of this Act. After
completion of the evaluation project and not later than December
31, 2026, the commission shall amend commission rules to ensure
that wholesale transmission charges appropriately assign costs for
transmission investment.
SECTION 6. Section 35.004(c-1), Utilities Code, as added by
this Act, applies only to an interconnection agreement entered into
on or after the effective date of this Act.
SECTION 7. 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, 2025.