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:

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Date

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Governor