89R30659 JXC-F

By: King, et al. S.B. No. 6

(King)

Substitute the following for S.B. No. 6: No.

A BILL TO BE ENTITLED

AN ACT

relating to the planning for, interconnection and operation of, and costs related to providing service for certain electrical 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 Sections 37.0561 and 37.0562 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 may be directed to deploy on-site backup generating facilities or curtail load. After the independent organization deploys all available market services, except for frequency response 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 standards for the development of transmission infrastructure needed to serve a large load customer subject to Subsection (c) 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. Unless the payment is later refunded, an interconnecting electric utility or municipally owned utility that receives a payment that meets the financial commitment standards shall preserve the ability of the large load customer to interconnect and retain the customer's contract capacity under the interconnection or facilities extension agreement, once the utility has approved the customer's initial or modified request for interconnection. 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.

Sec. 37.0562. EXPEDITED INTERCONNECTION FOR CERTAIN LARGE LOADS. (a) In this section:

(1) "Behind-the-meter generation" means a generation facility on the retail customer's side of the meter capable of serving the full load requirement of the retail customer.

(2) "Flexible load" means a large load operated by a retail customer who is obligated by contract or agreement in the ERCOT market to reduce the load or power the load exclusively with back-up generation:

(A) at the direction of the independent organization certified under Section 39.151 for the ERCOT power region; or

(B) as required to protect the integrity of the ERCOT grid.

(b) The commission by rule shall establish a program to provide an expedited process for the interconnection of large loads. The program must require the interconnecting municipally owned utility or electric utility and the independent organization certified under Section 39.151 for the ERCOT power region to give priority in the interconnection queue to a large load for which a retail customer has received approval for expedited processing over any other large loads that have not entered into a contractual agreement with the municipally owned utility or electric utility regarding the provision of electric service. If applicable, the generation interconnection application for a generation facility associated with the large load must be processed in parallel with the large load.

(c) The program must require a large load to qualify for expedited interconnection processing by bringing in-service, not later than the 180th day after the interconnection date, behind-the-meter generation that is:

(1) registered with the independent organization certified under Section 39.151 for the ERCOT power region; and

(2) capable of serving the full load requirement of the customer.

(d) As an alternative to the requirements of Subsection (c), a large load may qualify for expedited interconnection processing, if the load is a facility with an aggregated peak demand at a single site of more than 75 megawatts, by:

(1) providing to the interconnecting municipally owned utility or electric utility all data regarding, and making satisfactory proof of financial commitment for, the load; and

(2) being subject to a binding commitment with the independent organization certified under Section 39.151 for the ERCOT power region to establish the load as a flexible load for a minimum period established by the commission, which must be at least 10 years.

(e) A large load that qualifies for expedited interconnection processing may choose:

(1) if authorized by the independent organization certified under Section 39.151 for the ERCOT power region and the relevant municipally owned utility or electric utility, to contract with a vendor approved by the relevant utility or by the independent organization to perform all studies required by the relevant utility before the approval of the interconnection application; and

(2) if authorized by the relevant municipally owned utility or electric utility:

(A) to procure equipment required for the interconnection in accordance with technical specifications provided by the relevant utility; and

(B) to construct interconnection facilities in accordance with technical and other requirements of the relevant utility.

(f) The program may provide that studies required by a municipally owned utility or electric utility before the approval of an interconnection application for a flexible load may evaluate the load as non-firm.

(g) Demand reductions from flexible loads that receive expedited processing and are removed from the system through the utilization of behind-the-meter generation during an energy emergency alert must be counted toward any obligation of the municipally owned utility or electric utility to shed load.

(h) The independent organization certified under Section 39.151 for the ERCOT power region shall consider action taken under this section as a reliability deployment when calculating any price adjustments for reliability deployments.

(i) The commission shall establish financial penalties the commission may impose on an owner or operator of a large load that is approved for expedited interconnection processing but fails to reduce the load or power the load with back-up generation as directed by the independent organization certified under Section 39.151 for the ERCOT power region.

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 new net metering arrangement must be requested or consented to by the electric cooperative, electric utility, or municipally owned utility certificated to provide 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 (d) and applicable law only for a reasonable cause.

(d) Not later than the 180th day after the date the independent organization certified under Section 39.151 for the ERCOT power region receives the notice under Subsection (a), the independent organization 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 must require a generation resource that makes 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 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:

(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.

(e) If the independent organization certified under Section 39.151 for the ERCOT power region 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 independent organization is considered to have approved the arrangement.

(f) If conditions imposed under Subsection (d) are not limited to a specific period, the independent organization certified under Section 39.151 for the ERCOT power region 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, electric utility, or municipally owned utility, and a party in the net metering arrangement. A final decision made by the independent organization related to this section may be appealed to the commission by the owner of the generation resource or the large load customer.

(h) The commission shall post the decision made by the independent organization certified under Section 39.151 for the ERCOT power region 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 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, 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. (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.