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.