89R12894 JXC-F     By: King, Schwertner 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(d), Utilities Code, is amended to   read as follows:          (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   cooperative.          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   stranded infrastructure costs.          (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   by Subsection (a).          (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   regulation; or                (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   include:                (1)  security provided on a dollar per megawatt basis   as set by the commission;                (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   service; or                (3)  another form of financial commitment acceptable to   the commission.          (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   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 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   resource; and                (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   thermal generation.          (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   service at the location.          (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   certain events;                (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   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 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   ancillary service.          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   also evaluate whether:                (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   allocation; or                (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.