S.B. No. 6
 
 
 
 
AN ACT
  relating to the planning for, interconnection and operation of, and
  costs related to providing service for certain electrical loads and
  to the generation of electric power by a water supply or sewer
  service corporation.
         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 FOR AND INTERCONNECTION OF LARGE
  LOADS. (a) For the purposes of this section, a large load customer
  includes an entity requesting an interconnection that exceeds the
  demand threshold adopted under Subsection (c) and a successor in
  interest to such an entity.
         (b)  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.
         (c)  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 (b).
         (d)  The standards must require each large load customer
  subject to Subsection (c) to disclose to the interconnecting
  electric utility or municipally owned utility whether the customer
  is pursuing a substantially similar request for electric service in
  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.
         (e)  The standards must require each interconnected large
  load customer subject to Subsection (c) 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 shall establish a threshold before or
  during an energy emergency alert at which the organization may
  issue reasonable notice that large load customers with on-site
  backup generating facilities may be directed to either deploy the
  customer's on-site backup generating facilities or curtail load.  
  After the independent organization deploys all available market
  services, except for frequency responsive services, the
  independent organization may 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
  facilities or curtail load.  The independent organization 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).
         (f)  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 (c). 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.
         (g)  The standards must include a method for a large load
  customer subject to Subsection (c) to demonstrate site control for
  the proposed load location through an ownership interest, lease, or
  another legal interest acceptable to the commission.
         (h)  The standards must include uniform financial commitment
  requirements for the development of transmission infrastructure
  needed to serve a large load customer subject to Subsection (c).  
  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).
         (i)  Security provided under Subsection (h)(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;
               (2)  if the large load customer withdraws the
  customer's request for all or a portion of the requested capacity;
  or
               (3)  if capacity subject to a financial commitment will
  be reallocated to one or more other customers.
         (j)  The commission shall establish uniform requirements for
  determining when capacity that is subject to an outstanding
  financial commitment under this section may be reallocated.
         (k)  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.
         (l)  The commission may not limit the authority of a
  municipally owned utility or an electric cooperative to impose
  electric service requirements for large load customers on their
  systems in addition to the standards adopted under this section.
         (m)  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 LARGE LOAD CUSTOMER WITH
  EXISTING GENERATION RESOURCE. (a)  A power generation company,
  municipally owned utility, or electric cooperative must submit a
  notice to the independent organization certified under Section
  39.151 for the ERCOT power region before implementing a net
  metering arrangement between an operating facility registered with
  the independent organization as a stand-alone generation resource
  as of September 1, 2025, and a new large load customer as described
  by Section 37.0561(c).
         (b)  This section does not apply to a generation resource:
               (1)  the registration for which included a co-located
  large load customer at the time of energization, regardless of
  whether the load was energized at a later date; or
               (2)  a majority interest of which is owned indirectly
  or directly as of January 1, 2025, by a parent company of the
  customer that participates in the new net metering arrangement.
         (c)  The electric cooperative, transmission and distribution
  utility, or municipally owned utility that provides electric
  service at the location of the new net metering arrangement may for
  reasonable cause including a violation of other law, object to the
  arrangement, provided however, that no reasonable cause objection
  may be raised after a final decision by the commission is issued
  under this section.
         (d)  The independent organization certified under Section
  39.151 for the ERCOT power region shall study the system impacts of
  a proposed net metering arrangement and removal of generation for
  which the independent organization receives a notice under
  Subsection (a) after the independent organization receives all
  information regarding the arrangement required by the independent
  organization to be submitted to the independent organization.  The
  independent organization must complete the study and submit the
  results to the commission with any associated recommendations not
  later than the 120th day after the independent organization
  receives all required information regarding the arrangement.  Not
  later than the 60th day after the date the commission receives the
  study results from the independent organization, the commission
  shall approve, deny, or impose reasonable conditions on the
  proposed net metering arrangement as necessary to maintain system
  reliability, including transmission security and resource adequacy
  impacts.  The conditions must require a generation resource that
  makes dispatchable capacity available to the ERCOT power region
  before the implementation of a net metering arrangement under this
  section to make at least that amount of dispatchable capacity
  available to the ERCOT power region after the implementation of the
  arrangement at the direction of the independent organization in
  advance of an anticipated emergency condition.  The conditions may
  include:
               (1)  requiring the retail customer who is served
  behind-the-meter to reduce load during certain events;
               (2)  requiring the generation resource to make capacity
  available to the ERCOT power region during certain events; or
               (3)  requiring customers to be held harmless 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.
         (f)  If conditions imposed under Subsection (d) 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.
         (g)  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, transmission and
  distribution utility, or municipally owned utility, and a party in
  the net metering arrangement.
         (h)  The commission shall post the decision made on each
  notice submitted under this section on the commission's Internet
  website.  The commission may not post information regarding the
  decision that is competitively sensitive or otherwise considered
  confidential.
         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, transmission and distribution
  utility, and municipally owned utility serving a
  transmission-voltage customer develops a protocol, including the
  installation of any necessary equipment or technology before the
  customer is interconnected, to allow the load to be curtailed
  during firm load shed. The electric cooperative, transmission and
  distribution 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.  Subchapter A, Chapter 67, Water Code, is amended
  by adding Section 67.0115 to read as follows:
         Sec. 67.0115.  ELECTRIC GENERATION. (a) A corporation may
  generate electric power for use in the corporation's operations,
  limited to:
               (1)  powering water well pumps, service pumps, and
  other equipment for the production, treatment, and transportation
  of raw water; and
               (2)  powering infrastructure for the treatment and
  delivery of potable drinking water.
         (b)  For the purposes of Subsection (a), a corporation
  operating solely as a wholesale water supplier or sewer service in a
  county with a population of less than 350,000 may generate excess
  electric power in conjunction with the uses described in Subsection
  (a) for sale in the ERCOT power region to provide revenue for the
  corporation only if the corporation:
               (1)  primarily generates electric power solely for the
  uses described in Subsection (a); and
               (2)  registers as a power generation company under
  Section 39.351, Utilities Code.
         (c)  A corporation that generates electric power for sale
  under Subsection (b) shall account for and use the revenue from
  those sales in a manner that complies with Section 67.004. The
  revenue that accrues from those sales of electric power may be used
  by the corporation only for:
               (1)  the corporation's costs of producing and selling
  electric power, including administration, employees, equipment,
  fuel, and maintenance; or
               (2)  a purpose described by Section 67.002.
         SECTION 6.  (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 7.  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 8.  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.
 
 
 
 
 
 
  ______________________________ ______________________________
     President of the Senate Speaker of the House     
 
         I hereby certify that S.B. No. 6 passed the Senate on
  March 19, 2025, by the following vote: Yeas 31, Nays 0; and that
  the Senate concurred in House amendments on May 29, 2025, by the
  following vote: Yeas 31, Nays 0.
 
 
  ______________________________
  Secretary of the Senate    
 
         I hereby certify that S.B. No. 6 passed the House, with
  amendments, on May 27, 2025, by the following vote: Yeas 103,
  Nays 25, two present not voting.
 
 
  ______________________________
  Chief Clerk of the House   
 
 
 
  Approved:
 
  ______________________________ 
              Date
 
 
  ______________________________ 
            Governor