SB 6

relating to electricity planning and infrastructure costs for large
BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
SECTION 1.  Section 35.004(d), Utilities Code, is amended to
(d)  The commission shall price wholesale transmission
services within ERCOT based on the postage stamp method of pricing
under which a transmission-owning utility's rate is based on the
ERCOT utilities' combined annual costs of transmission, other than
costs described by Subsections (d-2) and (d-3), divided by the
total demand placed on the combined transmission systems of all
such transmission-owning utilities within a power region.  For
purposes of establishing the postage stamp rate, each
distribution-owning utility in ERCOT shall report the additional
billing determinants that would be created by applying the minimum
transmission charge calculation under Section 36.010 to the
distribution-owning utility's service area.  An electric utility
subject to the freeze period imposed by Section 39.052 may treat
transmission costs in excess of transmission revenues during the
freeze period as an expense for purposes of determining annual
costs in the annual report filed under Section 39.257.
Notwithstanding Section 36.201, the commission may approve
wholesale rates that may be periodically adjusted to ensure timely
recovery of transmission investment.  Notwithstanding Section
36.054(a), if the commission determines that conditions warrant the
action, the commission may authorize the inclusion of construction
work in progress in the rate base for transmission investment
required by the commission under Section 39.203(e).
SECTION 2.  Subchapter A, Chapter 36, Utilities Code, is
amended by adding Section 36.010 to read as follows:
Sec. 36.010.  MINIMUM TRANSMISSION CHARGE.  To ensure that
all users of the transmission system in the ERCOT power region
contribute to transmission cost recovery, the commission shall
implement minimum rates that require all retail customers in that
region served behind-the-meter to pay retail transmission charges
based on a percentage of the customer's non-coincident peak demand
from the utility system as identified in the customer's service
agreement.  A municipally owned utility or electric cooperative
that has not adopted customer choice shall pass through the minimum
wholesale transmission rate to the utility's or cooperative's
retail customers in a manner determined by the utility or
SECTION 3.  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 at transmission voltage in the
ERCOT power region in a manner designed to support business
development in this state while minimizing the potential for
(b)  The standards must apply only to customers with a load
that exceeds 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
(c)  The standards must require each large load customer
seeking interconnection to disclose to the interconnecting
electric utility or municipally owned utility whether the customer
is pursuing a duplicate request for electric service, inside or
outside this state, the approval of which would result in the
customer materially changing or withdrawing the interconnection
request.  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.
(d)  The standards must require each interconnected large
load customer to disclose to the independent organization certified
under Section 39.151 for the ERCOT power region information about
the customer's on-site backup generating facilities.  To achieve
firm load shed during an energy emergency alert, the independent
organization certified under Section 39.151 for the ERCOT power
region may, after reasonable notice, direct the applicable electric
utility or municipally owned utility to require the large load
customer to deploy the customer's on-site backup generating
facility.  This subsection does not:
(1)  authorize a violation of any emissions limitation
in state or federal law or a violation of any other environmental
(2)  prohibit a large load 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 for initial transmission screening studies for large loads
above the minimum demand threshold determined under Subsection (b).
Any unused portion of the initial transmission screening study fee
must be applied as a credit toward security for procurement or
interconnection agreements at the same geographic site.
(f)  The standards must include a method for a large load
customer to demonstrate that the customer controls the site where
the load will be located through an ownership interest 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 before an electric utility or
municipally owned utility may submit a project for review by ERCOT
based on the large load customer's demand.  The standards must
provide that satisfactory proof of financial commitment may
(1)  security provided on a dollar per megawatt basis
(2)  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
(3)  another form of financial commitment acceptable to
(h)  Security provided under Subsection (g)(1) must be
refunded, in whole or in part, as the large load customer meets the
customer's requested load ramp milestones and sustains operations
for a prescribed period of time as determined by the commission.
(i)  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 in
addition to the standards adopted under this section.
SECTION 4.  Section 39.002, Utilities Code, is amended to
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 5.  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 new
net metering arrangement between a facility registered with the
independent organization as a generation resource and an
unaffiliated retail customer if:
(1)  the retail customer's demand would exceed 10
percent of the nameplate capacity of the existing generation
(2)  the facility owner has not proposed to construct
an equal amount of replacement capacity in the same general area.
(b)  For the purposes of Subsection (a)(2), nameplate
capacity from dispatchable thermal generation is considered to be
replaced only if the replacement capacity is from dispatchable
(c)  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
(d)  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.  The conditions may include requirements:
(1)  that behind-the-meter load ramp down during
(2)  that generation reenter energy markets in the
ERCOT power region during certain events; and
(3)  that the generation resource will be held liable
for stranded or underutilized transmission assets resulting from
the behind-the-meter operation.
(e)  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
(d), the commission is considered to have approved the 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 large load customer that is
subject to the standards adopted under Section 37.0561 installs, or
requires to be installed, before the customer is interconnected,
equipment that allows the load to be remotely disconnected during
firm load shed.  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
(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 subject to the
standards adopted under Section 37.0561 in advance of a projected
energy emergency alert event.  The service must provide at least a
24-hour notice to large load customers that participate in the
service and shall require each participating large load to remain
curtailed for the duration of the energy emergency alert event or
until the load can be recalled safely.  A large load customer may
not offer for the service megawatts that curtail 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 participate in a different reliability or
SECTION 6.  (a) The Public Utility Commission of Texas shall
evaluate whether the existing methodology used to allocate
wholesale transmission costs to distribution providers under
Section 35.004(d), Utilities Code, continues to appropriately
assign costs for transmission investment.  The commission shall
(1)  the current methodology, including the four
coincident peak methodology, for allocating transmission costs by
transmission and distribution utilities in the ERCOT power region
to their customer classes results in a just and reasonable
(2)  alternative methodologies should be considered.
(b)  The Public Utility Commission of Texas shall open a
rulemaking project regarding the evaluation required under
Subsection (a) of this section not later than the 90th day after the
effective date of this Act.  If the commission determines in the
project that a commission rule should be amended, the commission
shall adopt the final rule not later than December 31, 2026.
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.