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On March 26, 2026 the Public Utility Commission of Texas (PUCT) issued an order adopted rules for net metering arrangements involving large load co-located with an existing generation resource under PURA § 39.16.  Order adopting 16 TAC §25.205.  (Also see Order (Pages 101-142))

As reported previously, the new rule applies to a net metering arrangement involving a large load customer and an existing generation resource and establishes the criteria for ERCOT’ s study of a net metering arrangement. The rule also sets forth the procedural steps for ERCOT to complete its study of a proposed net metering arrangement within 120 days and the procedural steps for the commission to approve, with or without conditions, or deny a proposed net metering arrangement within 60 days after ERCOT files its study results and recommendations with the commission.

The commission received written reply comments from Calpine; CenterPoint; CTEI; Cruose Energy Systems LLC (Crusoe); DCC; Enchanted Rock, LLC (Enchanted Rock); Eolian; ERCOT; OPUC; Oncor; Sierra Club; TAEBA; TCPA; TEC; TIEC; TNMP; TPPA; TSSA; and Vistra.

The commission invited interested persons to address five questions related to various provisions of the proposed rule. The Commission’s responses to each identified question is presented below.

1. Does the commission have authority to approve a net metering arrangement if retail electric service to the large load customer would not be provided by the municipally owned utility or electric cooperative that is certificated to provide retail electric service to the area in which the large load customer is located?

Commission Response:

“The commission agrees with Calpine that this question may be best resolved on a case-bycase basis involving resolution of an objection raised by an electric utility, municipally owned utility, or electric cooperative based on a violation of other law.”

2. PURA §39.169(c) authorizes the electric cooperative, transmission and distribution utility, or municipally owned utility that provides electric service at the location of the new net metering arrangement to object to the arrangement for reasonable cause, including a violation of other law. 2a. How should the commission interpret “electric service” in PURA §39.169(c)?

Commission Response:

“The commission agrees with TIEC that “electric service” includes the delivery of electric services provided to the large load customer and the existing generation resource. This interpretation is also consistent with the definition for “service” that is set forth in PURA §11.003(19) and is recommended by AEP and TEC. PURA §11.003(19) defines service to include any act performed, anything supplied, and any facilities used or supplied by a public utility in the performance of the utility’s duties under Title II of the Texas Utilities Code to its patrons, employees, other public utilities, an electric cooperative, and the public. Therefore, the commission modifies adopted §25.205(b) to add definitions for “interconnecting distribution service provider (DSP)” and “interconnecting TSF’ consistent with this interpretation. The commission also modifies adopted §25.205(d)(1) to require that an application for approval of a net metering arrangement identify the interconnecting TSP and the interconnecting DSP; modifies adopted §25.205(d)(2) to require service of the application on the interconnecting TSP and the interconnecting DSP; and modifies adopted §25.205(e)(1) to specify that the interconnecting TSP and the interconnecting DSP are both parties to the proceeding.”

2b. What process should be used for addressing an objection to a net metering arrangement based on a violation of other law?

Commission Response:

“The commission agrees with AEP, CenterPoint, TAEBA, TIEC, and Vistra that parties are able to avail themselves of existing processes and procedures to resolve an objection to a net metering arrangement based on a violation of other law. These existing processes and procedures may include filing a petition for a declaratory order or filing an objection in the contested case proceeding in which the net metering arrangement is under consideration for commission approval. The commission notes that adopted §25.205* requires the interconnecting TSP and the interconnecting DSP to file an objection not later than ten days after ERCOT files its study results and recommendations.”

3. PURA §39.169(g) limits the parties to a proceeding under PURA §39.169 to the commission, ERCOT, the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility, and a party in the net metering arrangement. How should the commission interpret “interconnecting” in PURA §39.169(g)?

Commission Response:

“The commission determines that “interconnecting utility” as that term is used in PURA §39.169(g) includes the electric utility, municipally owned utility, or electric cooperative that is the TSP that owns and operates the physical facilities that interconnect the large load customer or the existing generation resource and also includes the electric utility, municipally owned utility, or electric cooperative that is the DSP certificated to provide retail electric service in the service area in which the large load customer is located or seeks interconnection.”

4. Is there a scenario where the electric cooperative, transmission and distribution utility, or municipally owned utility that objects to a net metering arrangement under PURA §39.169(c) is not a party to the proceeding under PURA §39.169(g)? If so, how can these two statutory provisions be reconciled?

Commission Response:

“The commission agrees with AEP, Calpine, CenterPoint, TEC, and TPPA that such a scenario would not exist because both PURA provisions include: (1) the electric utility, municipally owned utility, or electric cooperative that is the TSP that owns and operates the physical facilities that interconnect the large load customer or the generation resource, and (2) the electric utility, municipally owned utility, or electric cooperative that is the DSP that is certificated to provide retail electric service in the service area in which the large load customer is located or seeks interconnection and both PURA provisions also include.”

5. PURA §39.169(d) states that if the commission imposes conditions on a proposed net metering arrangement, the conditions must require a generation resource that makes dispatchable capacity available to the ERCOT 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.

5a. How should the commission interpret “dispatchable capacity”?

Commission Response:

“The commission substantively agrees with Calpine, Crusoe, CTEI, Enchanted Rock, ERCOT, OPUC, Sierra Club, TAEBA, TCPA, TIEC, and Vistra that “dispatchable capacity” means capacity, the output of which can be controlled primarily by forces under human control. The commission modifies the adopted rule to add a definition for “dispatchable capacity” defining the term to mean “output capacity that can be controlled primarily by forces under human control.”

5b. How should the commission interpret “make available”?

Commission Response:

“The commission agrees with ERCOT and LCRA that the full capacity of an existing generation resource that has entered into a net-metering arrangement with a large load customer is made available first and foremost through the full curtailment of the large load customer that is co-located with the existing generation resource. In addition, the commission agrees with Eolian that an existing generation resource must make its dispatchable capacity available by maintaining operational readiness and the physical, telemetry, and interconnection capability necessary for ERCOT to dispatch, schedule, or commit that existing generation resource’s capacity for energy at ERCOT’s direction when needed. In order to satisfy the statutorily required condition imposed on an existing generation resource, the existing generation resource must maintain the ability-through its control systems, state-of-charge management (as applicable), and telemetry-to deliver its committed capacity within ERCOT’s operational timeframe when called upon to support system reliability. The commission modifies adopted §25.205(k)(3) to explicitly require that an existing generation resource that must make dispatchable capacity available under subsection (k)(1) of the rule must make its dispatchable capacity available by adjusting the existing generation resource’s output in accordance with ERCOT instructions. For additional clarity, the commission adds a new provision to specify that an existing generation resource that must make capacity available under subsection (k)(2) of the rule must make capacity available by complying with any conditions specific to the existing generation resource. The commission also adds adopted §25.205(k)(7), which clarifies that nothing in the adopted rule limits the commission’s authority to impose conditions on a net metering arrangement under PURA.

Additionally, the commission expects ERCOT to develop protocols via the stakeholder process to develop standard communication, settlement, and compliance requirements for all net metered loads and existing generation resources before, during, and after emergencies. For example, the status of an existing generation resource in a private use network (PUN) must be ON both pre- and post-load curtailment if the existing generation resource is running. By updating its high sustained limit (HSL) telemetry to ERCOT, an existing generation resource would reflect the increase in its net capability after the load curtailment. This would make the existing generation resource’s capacity available to ERCOT. If the existing generation resource is not running pre- or post-deployment, then ERCOT would issue a typical reliability unit commitment instruction. No compensation will be provided to the large load customer for the curtailment. Being curtailed or having an existing generation resource controlled by ERCOT are known risks that these entities take on by entering into a net metering arrangement.

The commission disagrees with TCPA that load curtailments, backup generation utilization, and new generation capacity that is not at the site of the co-location net metering arrangement have the same net effect for resource adequacy. Although a simple accounting exercise on paper to provide a similar number of MW, the characteristics and location of the existing generation resource are studied together for transmission security and resource adequacy. Therefore, the commission concludes that an existing generation resource that is subject to a condition requiring the existing generation resource to make capacity available consistent with PURA §39.169 must make its own capacity available.

5c. How far in advance of an anticipated emergency condition should ERCOT be able to direct a generation resource to make dispatchable capacity available to the ERCOT region? Should “advance” be measured based on time, megawatt, or some other metric?

Commission Response:

“The commission agrees with ERCOT that “advance” should be interpreted to mean when ERCOT anticipates entering EEA Level 1. Currently, EEA Level 1 is issued when ERCOT’s operating reserves drop below 2,500 MW and are expected to remain below that level for at least 30 minutes.

The commission agrees with Oncor that ERCOT should have the operational flexibility to adapt the process in the moment according to real-time conditions and over time according to past experiences when directing dispatchable capacity be made available.

The commission disagrees with AEP and TEC that “advance” should be measured in terms of the time associated with the startup times and capabilities of the existing generation resource with respect to ERCOT’s issuance of instructions to make capacity available. However, startup times and capabilities of load and generation should be considered by ERCOT in its issuance of instructions and monitoring of compliance.

Thus, the commission concludes that standardizing how far in advance the notice for anticipated emergency should be provided should be addressed in ERCOT protocols based on whether the emergency is a systemwide or local transmission emergency, the season, and other conditions of the grid. As ERCOT will have multiple net metering arrangements and curtailable large load customers available across the region, ERCOT will need to develop a holistic approach. However, the details for response time after the notice is issued for a specific existing generation resource and large load customer will be addressed in the contested case proceeding for a net metering arrangement and will take into consideration the startup times and capabilities of the existing generation resource and large load customer.

5d. How should the commission interpret an “anticipated emergency condition”?

Commission Response:

“The commission agrees with AEP, ERCOT, Oncor, and TEC that an “emergency condition” should be interpreted consistent with the definition in ERCOT protocols: “an operating condition in which the safety or reliability of the ERCOT System is compromised or threatened, as determined by ERCOT.” The commission also agrees with TEC and ERCOT that an emergency condition encompasses capacity emergencies and transmission emergencies. Therefore, ERCOT should have the latitude to deploy generation and curtail large loads in an emergency condition, including local and system-wide emergency conditions.”

The order also addressed general comments submitted by parties. See entire order for complete overview.