TITLE 16. ECONOMIC REGULATION

DIVISION 1. OPEN-ACCESS COMPARABLE TRANSMISSION SERVICE FOR ELECTRIC UTILITIES IN THE ELECTRIC RELIABILITY COUNCIL OF TEXAS

16 TAC §25.205

The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.205, relating to Net Metering Arrangements Involving a Large Load Customer Co-Located with an Existing Generation Resource, with changes to the proposed text as published in the October 3, 2025 issue of the Texas Register (50 TexReg 6409). The new rule implements Public Utility Regulatory Act (PURA) §39.169, as enacted by Senate Bill (SB) 6 during the Texas 89th Regular Legislative Session. 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. This section is adopted under Project Number 58479. This rule will be republished.

The commission received written initial comments on the proposed section 25.205 from AEP Texas Inc. (AEP); Calpine Corporation (Calpine); CenterPoint Energy Houston Electric, LLC (CenterPoint); Conservative Texans for Energy Innovation (CTEI); Data Center Coalition (DCC); EdgeConneX (ECX); Electric Transmission Texas, LLC (ETT); Eolian, L.P. (Eolian); Electric Reliability Council of Texas, Inc. (ERCOT); Lower Colorado River Authority and LCRA Transmission Services Corporation (LCRA); Office of Public Utility Counsel (OPUC); Oncor Electric Delivery Company LLC (Oncor); Onward Energy Holdings, LLC and its Texas subsidiaries, including Route 66 Wind Power II, LLC, South Plains Wind Energy II, LLC, Turkey Track Wind Energy, LLC, Maplewood Holdco LLC, and Maplewood II Holdco LLC (Onward); Satoshi Energy (Satoshi); Sierra Club Lone Star Chapter (Sierra Club); Splight Inc. (Splight); Texas Advanced Energy Business Alliance (TAEBA); Texas Competitive Power Advocates (TCPA); Texas Electric Cooperatives, Inc. (TEC); Texas Industrial Energy Consumers (TIEC); Texas Public Power Association (TPPA); Texas Solar + Storage Association (TSSA); Texas-New Mexico Power Company (TNMP); and Vistra Corp. (Vistra).

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.

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?

AEP, Calpine, CenterPoint, Crusoe, Eolian, and Sierra Club recommended that the commission has the authority to approve a net metering arrangement in the event that 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. Calpine noted that this issue may not be ripe for decision given that PURA §39.169(c) provides a specific opportunity for a municipally owned utility or electric cooperative that serves the applicable retail electric service area for a proposed net metering arrangement the opportunity to object.

LCRA recommended that municipally owned utilities and electric cooperatives have the exclusive right and obligation to provide electric service to all customers within their certificated services areas. Attendant with that right and obligation, these entities should maintain discretion on determining how net metering arrangements comport with their retail terms of services. Similarly, TIEC recommended that only the certificated distribution utility is authorized to provide retail electric service in its service area, unless the commission grants an exception. Moreover, the physical location of a consuming facility in a service area is the relevant factor when determining which utility has a right to serve a customer, not the location of the point of delivery.

TEC recommended that the commission cannot approve a net metering arrangement in an electric cooperative or municipally owned utility's service area if the net metering arrangement is not intermediated by the cooperative or municipally owned utility. TEC explained that the generation resource must sell the power to the cooperative or municipally owned utility who then sells the power to the large load customer.

TPPA answered in the negative, recommending that municipally owned utilities and electric cooperatives have exclusive jurisdiction to provide retail electric service within their service territories and may do so in accordance with the retail tariffs approved by their governing bodies. A net metering arrangement involving a private use network, which involves common ownership between the co-located load and generation resource, would be appropriate within a municipally owned utility or electric cooperative's service territory because no retail or wholesale sale of electricity occurs behind the meter. However, the municipally owned utility or electric cooperative would have exclusive jurisdiction to serve that load at retail once a retail transaction occurs. Before such a transaction, there is no issue with a commonly owned generation resource serving the load directly.

TAEBA recommended that the intent of Senate Bill 6 has nothing to do with changing billing or tariff authority of any class of load serving entity, including municipally owned utilities or electric cooperatives.

Vistra recommended that the commission apply its well-developed law regarding implementation of retail electricity choice, which holds that a retail customer whose consuming facility is wholly or partially located in an area that is not singly-certificated to a non-opt-in entity (NOIE) is entitled to choose its retail electricity provider. Additionally, Vistra recommended applying the law regarding the legality of self-service by a customer.

Commission Response

The commission agrees with Calpine that this question may be best resolved on a case-by-case 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)?

AEP and TEC recommended that the term "electric service" as that term is used in PURA §39.169(c) should be interpreted consistent with the definition for "service" under PURA §11.003(19). The term "service" includes any act performed, anything supplied, and any facilities used or supplied by a public utility in the performance of the utility's duties under this title to its patrons, employees, other public utilities, an electric cooperative, and the public. The term also includes the interchange of facilities between two or more public utilities. Similarly, TIEC recommended that "electric service" includes the delivery services provided to the retail customer and the existing generation facility. In essence, either the transmission service provider (TSP) at the generation resource's point of interconnection or the retail electric service provider may object to a net metering arrangement for good cause.

Eolian recommended that the term "electric service" as that term is used in PURA §39.169 should be interpreted to mean electric delivery service, which is the provision of transmission or distribution service to the physical location. Eolian reasoned that if the Legislature had meant "retail service" it could have included retail electric providers in the list of parties to a net metering arrangement proceeding. Moreover, the consistent use of "interconnecting" across PURA §39.169(c) and (g) indicates the focus is on physical interconnection and delivery, not retail sales.

Calpine, TCPA, and Vistra recommended that the term "electric service" as that term is used in PURA §39.169(c) should be interpreted to mean retail delivery service. That is: "any act performed, electricity supplied, and any facilities used or supplied by a public utility in performance of the utility's duties to provide electricity to a large load customer, including the provision of electrons from the grid whether ongoing or an as needed basis." Similarly, TNMP recommended that "electric service" means the electric utility certificated to provide retail service at the location of the new proposed net metering arrangement (i.e., the utility that is legally authorized and required to serve load in the service territory).

CenterPoint recommended that the term "electric service" as that term is used in PURA §39.169(c) should be interpreted to mean retail electric delivery service and wholesale transmission service.

ECX recommended that the term "electric service" for purposes of a net metering arrangement means the provision of power from the grid to the meter of the net metering arrangement.

TPPA recommended that "electric service" means the service provided to access the poles and wires needed to connect to the bulk power system, both at the transmission and distribution level.

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 TSP" 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?

AEP recommended that parties should be able to avail themselves of current processes, including a request for a declaratory order, to resolve disputes related to a violation of PURA, commission rules, or ERCOT protocols. Similarly, CenterPoint recommended that an objection to a net metering arrangement as a violation of law should be filed as a petition for declaratory order or ruling to challenge the arrangement.

TAEBA recommended using the current reporting methods set forth in 16 TAC §22.246 (relating to Administrative Penalties) and 16 TAC §22.242 (relating to Formal Complaint Process).

Vistra recommended that the commission use the existing process for evaluating and deciding legal issues. That is the commission should receive arguments and briefing from all the parties to the proceeding and then evaluate the objection as a legal issue.

TIEC recommended that if a party objects to a net metering arrangement, even for a violation of law, the commission should hold a contested case proceeding to consider the validity of the party's claim. This could occur as part of the commission's approval process or prior to ERCOT's study, depending on the timing of the objection. However, Crusoe and TIEC cautioned that being granted party status should not broaden the issues that the parties have standing to dispute.

Calpine, Crusoe, Eolian, and TCPA recommended that an objection to a net metering arrangement based on a violation of other law should be addressed within the proceeding evaluating the net metering arrangement for commission approval. TCPA recommended that a procedural schedule for briefing on the issue could be issued after the application is filed, allowing for resolution of the objection within the 120-day study period and before the commission's 60-day process begins. Eolian recommended that an objection should be evaluated within the commission's 60-day decision period following ERCOT's filing of its study results and recommendations.

ECX recommended a process be put in place that ensures time limitations on when an objection can be raised based on a violation of other law.

Sierra Club recommended allowing a municipally owned utility or electric cooperative in such a scenario to be a party to the net metering arrangement proceeding.

TEC recommended that the commission must evaluate and resolve an objection to a net metering arrangement before the arrangement is approved.

TNMP recommended that objections to a net metering arrangement based on a violation of other law be adjudicated either through an enforcement proceeding or a contested case proceeding.

TPPA was supportive of adjudicating objections in a contested case proceeding and recommended that the commission establish clear and substantive requirements for net metering arrangements within its rules. These requirements should limit the types of allowable arrangements. For example, any large load and generation resource seeking to establish a net metering arrangement should be required to obtain consent from the poles and wires company or companies before submitting a net metering arrangement request to ERCOT. Additionally, TPPA recommended that the commission retain the authority to issue conditional approval of a net metering arrangement, subject to the condition that the arrangement is subsequently found to be lawful in any related or pending proceedings.

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(j) 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)?

AEP recommended that "interconnecting" as that term is used in PURA §39.169(g) includes any party that could interconnect the subject load, including the electric cooperative, transmission and distribution utility, or municipally owned utility associated with the certificated retail service territory and the electric cooperative, transmission and distribution utility, or municipally owned utility that provides electric service at the location of the new net metering arrangement.

Similarly, TEC recommended that "interconnecting" is not limited to physical interconnection but includes the entity that is certificated to provide retail electric service at that location. TEC noted that a contrary interpretation would mean that a large load customer and generation resource could abrogate the rights of a retail electric utility simply by designing an arrangement, even if that arrangement violates PURA. TPPA recommended that "interconnecting' means the poles and wires company or companies, (i.e., both the TSP as well as the DSP) for each service territory that a net metering arrangement is requested).

Calpine and TIEC recommended that "interconnecting" includes any electric cooperative, transmission and distribution utility, or municipally owned utility that is either a party to an interconnection agreement with the generation resource participating in the proposed net metering arrangement or who has the certificate of convenience and necessity (CCN) to provide retail delivery service to the load site, under a commission-approved or otherwise duly adopted tariff, to the large load customer. CenterPoint recommended that the "interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility" is both the interconnecting TSP and the interconnecting retail electric utility.

DCC recommended that "interconnecting" refers exclusively to the electric cooperative, transmission and distribution utility, or municipally owned utility that physically connects the large load customer's facilities to the ERCOT transmission system and is responsible for constructing, operating, and maintaining the interconnection facilities. DCC reasoned that this interpretation ensures that only entities with direct operational responsibility for the physical grid interconnection are considered parties under PURA §39.169(g). Large load customers who self-supply and do not rely on or expect energy from the grid should not be deemed "interconnected" for purposes of this provision. Likewise, retail electric providers or other entities without direct interconnection responsibilities should not qualify as parties.

ECX recommended that "interconnecting" means receiving power from the grid and receiving benefits from the grid connection. ECX also recommended that a net metering arrangement that is fully islanded and not connected to the grid should not be considered "interconnecting" under PURA §39.169.

Eolian recommended that "interconnecting" refers to the entity providing electric delivery service at the location, not retail electric service. Accordingly, Eolian recommended that the proposed rule clarify that "provides electric service at the location" in PURA §39.169(c) means electric delivery responsibility at the premises (transmission or distribution), not retail supply, while "interconnecting" in PURA §39.169(g) means the utility that owns or operates the point of interconnection facilities used by the arrangement. Under this approach, a utility that provides delivery elsewhere on the premises but does not own or operate the specific transmission or distribution facilities at the actual point of interconnection used by the net metering arrangement may still file a reasonable cause objection under PURA §39.169(c) if the utility provides electric service at the location, but party status under PURA §39.169(g) remains limited to the interconnecting utility (or utilities) whose point of interconnection assets are directly implicated.

Similarly, ERCOT recommended that "interconnecting" refers to the retail electric utility certificated to provide electric delivery service to the large load customer. ERCOT reasoned that PURA §37.051(a) prohibits an electric utility from providing service to the public without a certificate of convenience and necessity (CCN). Therefore, only the certificated retail electric utility can lawfully interconnect a retail customer to the grid and deliver power to that customer.

Sierra Club recommended interpreting the term broadly to include a municipally owned utility or electric cooperative that serves the area, even if the municipally owned utility or electric cooperative is not directly "interconnecting" the large load customer.

TAEBA recommended that the "interconnecting" electric cooperative, transmission and distribution utility, or municipally owned utility is the entity providing service and from whom the large load customer received its interconnection agreement. Similarly, TCPA and Vistra recommended that the "interconnecting" entity is the entity that is a party to a standard generation interconnection agreement with the generator.

TNMP recommended that PURA §39.169 must be harmonized in a manner that affirms that net metering arrangements cannot encroach upon the certificated retail utility's exclusive role. In practice, TNMP explained that this means any metering of a large co-located load must use the facilities of the authorized retail utility with the sole authority to deliver electricity and implement load curtailment within its certificated service territory.

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?

Consistent with their recommendations in response to question two above, AEP, Calpine, CenterPoint, TEC, and TPPA recommended that such a scenario would not exist because both PURA provisions capture both the interconnecting TSP and the interconnecting retail electric utility. Additionally, TEC recommended that the commission require a net metering arrangement to include as party to the arrangement any utility with the right to provide retail service in the area where the net metering arrangement is located.

ECX and Sierra Club suggested that it is possible an electric cooperative, transmission and distribution utility, or municipally owned utility that can object to the proceeding under PURA §39.169(g) but not be a party to the proceeding. For example, a TSP that is not party to the net metering arrangement but has transmission assets that are stranded or underutilized as a result of the net metering arrangement, that TSP could object to the net metering arrangement. Sierra Club did not object to including such a municipally owned utility or electric cooperative as a party in the net metering arrangement proceeding since ultimately the commission will be the final arbiter.

Eolian noted that where a project site straddles two certificated service areas, where legacy or dual-feed facilities exist, or where a service area exception has been granted, an entity may provide electric delivery service elsewhere on the premises (and thus qualify as "providing electric service at the location") but may not own or operate the specific point of interconnection facilities used by the behind the meter arrangement. In such cases, the electric utility providing service elsewhere on the premises may still submit an objection under PURA §39.169(c) for reasonable cause, but the electric utility would not automatically become a "party" under PURA §39.169(g). To reconcile these provisions, Eolian recommended PURA §39.169(g) should be read to limit party status to the interconnecting utility--that is, the entity whose transmission or distribution facilities from the point of interconnection and are directly implicated by the arrangement. Under this reading, an objecting electric utility that is not the interconnecting utility may have its objection included in the record and considered by the commission when deciding whether to approve, deny, or condition a netting arrangement, but that objection does not expand the list of formal parties beyond the statutory text of PURA §39.169(g).

LCRA and TIEC recommended that in order to reconcile the statutory provisions in PURA §39.169(c) with those in PURA §39.169(g), the electric cooperative, transmission and distribution utility, or municipally owned utility certificated to provide electric service to either the existing generation resource or the large load customer seeking interconnection are both allowed to object to the arrangement for reasonable cause and be a party to a proceeding under PURA §39.169(g). TIEC noted that it would be nonsensical not to allow the party who has a right to serve the retail load to participate in the proceeding.

TNMP recommended reconciling the two provisions by interpreting them to refer to the same utility, the certificated utility that is legally authorized or required to provide retail electric service at that location.

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"?

AEP recommended that "dispatchable capacity" be interpreted consistent with ERCOT Planning Guide 4.1.1.7 Minimum Deliverability Criteria.

Calpine, Crusoe, CTEI, Enchanted Rock, ERCOT, OPUC, Sierra Club, TAEBA, TCPA, TIEC, and Vistra recommended that "dispatchable capacity" means "capacity, the output of which can be controlled primarily by forces under human control." Additionally, Enchanted Rock recommended that the term "dispatchable capacity" requires a generation resource to: (1) be capable of running for at least four hours at the resource's HSL; (2) be online and capable of dispatch no more than two hours after being called on for deployment; and (3) have the flexibility to address inter-hour operational challenges.

Crusoe, CTEI, Onward, OPUC, and TSSA recommended that "dispatchable capacity" is only available from dispatchable generation resources that include thermal generation units, such as natural gas and coal, and excludes intermittent resources, such as solar.

CenterPoint recommended that "dispatchable capacity" means the generation capacity that has been committed to ERCOT by a registered generation or energy storage resource to be available immediately when demanded by ERCOT.

Oncor, TEC, and TPPA recommended that "dispatchable capacity" means the amount of power the existing generation facility was able to deliver on demand to the grid before the net metering arrangement was implemented. TEC and TPPA opposed an interpretation that includes or excludes certain types of generation resources because the statute uses the term "dispatchable capacity," not "dispatchable generator" to describe capacity capable of being dispatched.

ECX recommended that "dispatchable capacity" means the maximum amount of electricity available to the grid operator that can be quickly ramped up or down to meet the fluctuations in load demand.

Eolian recommended that "dispatchable capacity" means the portion of a resource's reliability deliverable output that ERCOT can schedule, commit, or dispatch in response to real-time or forecasted reliability needs. Dispatchable capacity should reflect demonstrated performance capability--such as 50-60% effective load carrying capability (ELCC) for four-hour energy storage resources and up to 90% for eight-hour energy storage resources; ensure operational readiness and telemetry controllability to respond to ERCOT direction during emergency or scarcity conditions; and enable ERCOT to incorporate realistic hybrid and storage dispatch assumptions into its interconnection and reliability studies. Moreover, Eolian recommended that the commission direct ERCOT and the applicable non-opt-in entities and TDUs recognize and credit the net dispatchable contribution of hybrid, paired, or storage-backed configurations--i.e., facilities combining generation, storage, or controllable load behind a common point of interconnection--based on observed reliability performance and validated study results, rather than on static derates, duration thresholds, or default assumptions that systematically understate energy storage resources' contribution to system adequacy.

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"?

AEP noted that transmission operators are unable to disconnect only the load in situations where the load is located behind-the-meter. In these situations, the generator becomes the responsible party for the disconnection of that load. Therefore, AEP recommended that "make available" in these circumstances means that the point of interconnection must be able to export the dispatchable capacity that was established prior to the net metering arrangement.

ERCOT and LCRA recommended that the full capacity of a generation resource that has entered into a net-metering arrangement with a large load customer is made available through the full curtailment of that large load.

Onward and TEC recommended that "make available" means providing energy when requested by ERCOT. Additionally, Onward recommended that non-dispatchable resources, such as wind and solar, should be able to curtail rather than firm their capacity. TSSA recommended that "make available" means that the generation resource must be ready to offer its energy into the market at a competitive price to address a serious reliability concern during a defined event as specified in a condition imposed by the commission.

Calpine, Crusoe, ERCOT, TIEC, and Vistra recommended that a generation resource could make dispatchable capacity available through the use of backup generation (i.e., the large load customer would switch from consuming power from the existing generation resource to consuming power from its backup generation). Calpine, TIEC, and Vistra also recommended load curtailment or a new build from elsewhere could satisfy the requirement. Additionally, Calpine and Vistra recommended that a generation resource could make dispatchable capacity available through bilateral trades in the ERCOT wholesale market.

ERCOT, TAEBA, and TPPA disagreed that curtailment from elsewhere or a new build from elsewhere could satisfy the requirement, nor can bilateral trades satisfy the requirement because these mechanisms do not account for circumstances in which the location of the generation export or load curtailment could be critical to ensuring reliability. TAEBA noted that if these types of bilateral market purchases are allowed to be made with offsite resources, it is possible that system reserves could be miscalculated, and ERCOT would have to account for those contracts to ensure it does not happen. Additionally, under energy emergency alert (EEA) emergency conditions, it is possible those loads would be required to be shed themselves, irrespective of contractual needs. Any contracted generation would have to be removed from system margin calculations, preemptively adding to generation reserve constraints. Even if all those risks could be avoided, the possibility that off-site resources would not contribute to the same geographic system that the net metered large load customer is connected to would mean that local reliability for that load resource's impacts would be improperly managed.

CenterPoint and CTEI recommended that "make available" means to be made immediately dispatchable when called upon by ERCOT. Oncor recommended that "make available" requires the existing generation resource to deliver its dispatchable capacity to the ERCOT grid within a reasonable time after being called upon in real-time. TAEBA recommended "make available" means the net metered generation resource is capable of injecting energy into the system during emergency conditions.

TPPA recommended that the method by which the generation will be made available need not be defined.

ECX recommended that "make available" means a generation resource's ability to provide power to the grid and a commitment by that resource to reserve that power to be called upon by ERCOT as needed. OPUC recommended that "make available" means the ability to make generation available for dispatch in the real-time market. Sierra Club recommended that "make available" means to be available to provide energy (or ancillary services) to the market through SCED or direct dispatch.

DCC recommended that the commission should provide large load customers with as much flexibility as possible to manage their load and shift to backup generation to meet requests for dispatchable energy. DCC also recommended that ERCOT should provide a large load customer as much time as possible to meet these requests and ultimately, ERCOT should limit these requests to grid emergencies. Finally, DCC recommended that the requirements should be consistent across all types of large load customers, not solely net metering arrangements.

Eolian recommended that "make available" means maintaining operational readiness and the physical, telemetry, and interconnection capability necessary for ERCOT to dispatch, schedule, or commit that capacity for energy at its direction under emergency or scarcity protocols (e.g., under the EEA framework). A resource satisfies this statutory duty when it maintains 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.

TCPA cautioned against an interpretation that would foreclose load curtailments, backup generation utilization, and new generation capacity, as these have the same net effect for resource adequacy even if not at the site of the co-location net metering arrangement.

Enchanted Rock recommended that the program under PURA §39.170 could be used to satisfy the "make available" requirement by leveraging ERCOT's existing emergency response service (ERS) construct as a mechanism for procurement, dispatch, settlement, and performance monitoring for large loads and establishing a new, long lead-time (24-hour) ERS product tailored to large load participation. Alternatively, Enchanted Rock recommended that "make available" should be interpreted to include participation in either the program under PURA §39.170 or ERS.

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?

AEP recommended that "advance" should be measured in terms of the time associated with the startup times of the unit prior to the unit's participation in the net metering arrangement. Similarly, TEC recommended that "advance" should be measured based on time and capabilities of the unit. TEC reasoned that some generating units may be able to respond to ERCOT directives on a faster timeline than others, so the standards should recognize these varying capabilities.

Sierra Club recommended that the metric may be dependent on the capability of the resource, i.e., how fast the resource can respond, but generally, Sierra Club recommended the metric should be based on time, such as four hours. OPUC recommended that advance notice should be given within one hour and no later than when ERCOT declares a Watch condition for low reserves.

TAEBA recommended that resources should be notified of their required availability once ERCOT enters into a Watch scenario. This will permit resources to prepare for any potential dispatch in an EEA.

ERCOT recommended that "advance" should be interpreted to mean when ERCOT anticipates that physical responsive capability (PRC) could fall below 2,500 MW or when PRC has fallen below, 2,500 MW. ERCOT noted that the ERCOT protocols currently define a 2,500 MW PRC trigger for EEA Level 1. Oncor recommended that the rule should give ERCOT the operational flexibility to adapt this process in the moment according to real-time conditions and over time according to past experiences.

Calpine recommended that "in advance of an anticipated emergency condition" should allow for fact-specific consideration of individual proposed net metering arrangements including equitable consideration of front-of-the-meter loads with on-site backup generation and behind-the-meter loads with on-site backup generation which are also co-located with an existing generation resource. Calpine reasoned that under PURA §37.0561, ERCOT may not direct the applicable interconnecting utility to require the large load customer to deploy its backup generation or curtail load until ERCOT has already deployed all available market services, except for frequency responsive services.

Similarly, Crusoe, CTEI, and Eolian recommended that PURA §39.169(d) and PURA §37.0561(e) should be read to apply under the same set of circumstances, when ERCOT declares an EEA Level 2 and before ERCOT declares an EEA Level 3. Eolian also recommended clarifying that "in advance" does not authorize ERCOT to impose inflexible must-run or must-discharge obligations that contradict the resource's technical design or state-of-charge management. Finally, Eolian recommended clarifying that compliance may be demonstrated through verified telemetry, state-of-charge status, and resource commitment plans during declared or forecasted emergency periods.

TCPA noted that ERCOT's 2024 Energy Emergency Alert Overview provides specific markers for when different resources are deployed and in what order, based on pre-defined degradation in frequency or RPC reserves. TCPA recommended that applying similar criteria to resources associated with large loads would be appropriate. However, TCPA cautioned that the commission should avoid (or at the very least, minimize) discriminatory treatment based on whether a resource is behind the meter or in front of the meter.

CenterPoint recommended that "in advance of an anticipated emergency condition" means that ERCOT should be able to direct a generation resource to be ready to make dispatchable capacity available to ERCOT as soon as it becomes reasonably foreseeable to ERCOT that an emergency condition may occur. Similarly, TNMP recommended that ERCOT should be required to direct a generation resource to make dispatchable capacity available to the ERCOT region in advance of an anticipated emergency condition as soon as reasonably possible or feasible.

CTEI, ECX, and Vistra recommended that a generation resource should have a minimum of 24 hours' notice in order to make dispatchable capacity available to ERCOT. Additionally, any advance notice should have specific time and megawatt parameters.

Enchanted Rock recommended that ERCOT could issue deployment instructions consistent with existing ERS protocols, such as 10-minute or 30-minute response windows, or through a new product with up to 24-hour notice, consistent with PURA §39.170 requirements. Enchanted Rock also recommended that faster-responding products should receive higher compensation than slower or day-ahead resources.

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"?

TNMP recommended "an anticipated emergency condition" includes emergency conditions as otherwise defined under commission rules or the ERCOT Nodal Protocols.

AEP, ERCOT, Oncor, and TEC recommended using the definition for "emergency condition" in the ERCOT protocols: "an operating condition in which the safety or reliability of the ERCOT System is compromised or threatened, as determined by ERCOT." Moreover, AEP recommended that an "anticipated emergency condition" is one where ERCOT is aware that an "emergency condition" is likely to occur to the point that ERCOT determines that it must take action in order to be prepared for the emergency condition. ERCOT further noted that an "anticipated emergency condition" has historically encompassed capacity emergencies and transmission emergencies. TEC reasoned that ERCOT should have the latitude to deploy generation or curtail large loads in an emergency situation, including local and system-wide emergency conditions.

Similarly, CenterPoint recommended that an "anticipated emergency condition" means a reasonably foreseeable critical condition on the ERCOT system that could lead to the issuance of EEAs and ERCOT's analysis of what constitutes an emergency condition. Oncor and TPPA agreed that an anticipated emergency condition should be interpreted as an anticipated EEA, as determined by ERCOT. However, Oncor and TPPA cautioned against limiting this definition to a system-wide EEA event--an "anticipated emergency condition" must also include anticipated regional or localized emergencies.

Calpine recommended defining "anticipated emergency condition" consistent with the definition for an energy emergency under 16 TAC §25.52(c): "any event that results in or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas." Similarly, ECX recommended that "an anticipated emergency condition" is an expected or predicted EEA as defined by the ERCOT protocols.

OPUC recommended that an anticipated emergency condition, for purposes of providing advance notice, could be when PRC is expected to fall below 4,000 MW for a sustained period and that actual dispatch of existing generation resources could be expected when PRC falls below 3,000 MW. However, OPUC recommended that specific PRC values not be included in the rule. Instead, the commission should direct ERCOT to develop a procedure, including any required protocol or guide changes necessary to implement the rule. In contrast, DCC recommended that ERCOT should not require large load customers to curtail during a watch period but should instead do so during an EEA.

TCPA recommended that an EEA Level 2.5 is an anticipated emergency condition and noted that the North American Electric Reliability Corporation (NERC) defines an "energy emergency" as "a condition when a load serving entity or balancing authority has exhausted all other resource options and can no longer meet its expected load obligations. TCPA also cautioned against uncompensated emergency action outside the risk of EEA Level 3 resulting from resource insufficiency.

Enchanted Rock and TAEBA recommended that an "anticipated emergency condition" is an EEA. Crusoe, CTEI, and Sierra Club recommended that an "anticipated emergency condition" is an EEA Level 3.

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.

General Comments

"Proposed" net metering arrangement

In sections of the proposed rule describing activities occurring prior to the commission issuing its findings related to the net metering arrangement, OPUC recommended adding the descriptor "proposed" in front of "net metering arrangement."

Commission Response

The commission declines to adopt OPUC's recommendation to add the descriptor "proposed" in front of "net metering arrangement" in sections of the adopted rule describing activities occurring prior to the commission issuing its findings related to the net metering arrangement because it is unnecessary.

Broaden the applicability

TPPA recommended defining net metering in a manner that requires all co-located loads participating in a net metering arrangement to be separately metered, with the energy flows measured at the load's meter subject to ancillary service obligations, transmission charges, and line loss charges.

Commission Response

The commission declines to adopt TPPA's recommendation to define net metering in a manner that requires all co-located loads participating in a net metering arrangement to be separately metered, with the energy flows measured at the load's meter subject to ancillary service obligations, transmission charges, and line loss charges because it exceeds the scope of this rulemaking.

Exclude energy storage resources

TPPA recommended that an energy storage resource should not be permitted to participate in a net metering arrangement because such an arrangement violates 16 TAC §25.501(m) (relating to Wholesale Market Design for the Electric Reliability Council of Texas). TPPA reads §25.501(m)(2) to mean that any co-located load not directly consumed by the energy storage resource for resale is subject to retail rates, charges, and fees, including ancillary service obligations and load ratio share allocation. Read in its entirety, TPPA concluded that §25.501(m) requires all loads to pay the applicable retail charges, including retail rates, ancillary service obligations, load ratio share uplift charges, line losses, and transmission system charges.

Eolian and TSSA recommended that TPPA's interpretation conflates settlement separation with interconnection eligibility. According to Eolian and TSSA §25.501 governs the mechanism for settlement, not commission jurisdiction. As long as an ESR's charging energy can be properly metered to separate it from other non-wholesale storage loads (WSL), the ESR's participation in a net metering arrangement does not violate §25.501. Moreover, Eolian noted that concerns about potential cost-shifting appear to reflect a different reading of the statute's purpose and that proper metering, as well as ERCOT's existing oversight processes are designed to prevent cost allocation or settlement errors.

Commission Response

The commission declines to adopt TPPA's recommendation to exclude energy storage resources from participating in a net metering arrangement. Under PURA §39.169, an existing generation resource must obtain approval from the commission before a net metering arrangement can be implemented and an electric utility, municipally owned utility, or electric cooperative may object to the net metering arrangement based on a violation of other law. Moreover, it is the applicants that bear the burden of proving that the net metering arrangement should be approved consistent with all applicable laws. The commission declines to modify the adopted rule to exclude energy storage resources from participating in a net metering arrangement. However, the commission notes that the adopted rule does not address what entities are eligible to participate in a net metering arrangement but simply identifies what entities must comply with the rule if seeking to participate in a net metering arrangement. The commission further notes that the adopted rule does not supplant other applicable laws. Thus, the change is unnecessary.

Objections

DCC recommended that the commission clarify that objections to net metering arrangements are limited to parties that have standing to file a complaint directly related to their relationship with the net metering arrangement.

TEC recommended that the commission develop a form objection for specific situations, such as when an arrangement does not include the electric cooperative or municipally owned utility as the entity with both the obligation and the right to furnish power to the end-consumer.

Commission Response

The commission declines to adopt DCC's recommendation to clarify that objections to net metering arrangements are limited to parties that have standing to file a complaint directly related to their relationship with the net metering arrangement because it is unnecessary. PURA §39.169(g) limits the parties and thereby limits who has standing. Additionally, PURA §39.169(c) identifies the entities that may object to a net metering arrangement. The commission also declines to adopt TEC's recommendation to develop a form objection for specific situations, such as when an arrangement does not include the electric cooperative or municipally owned utility as the entity with both the obligation and the right to furnish power to the end-consumer because it is unnecessary.

Operational implementation and modeling

Eolian recommended that the commission direct ERCOT and the relevant non-opt-in entity or transmission and distribution utility (i.e., the "interconnecting TSP) to perform a unified full interconnection study encompassing both the large load customer and any associated generation resource or energy storage resource that is party to a net metering arrangement and subject to the requirements of PURA §39.169. Eolian reasoned that evaluating a co-located large load customer with the associated generation resource or energy storage resource as a single, netting configuration enables ERCOT to assess their true reliability contribution, rather than overstating both demand and supply through disaggregated modeling.

Commission Response

The commission declines to adopt Eolian's recommendation to direct ERCOT and the relevant non-opt-in entity or transmission and distribution utility to perform a unified full interconnection study encompassing both the large load customer and any associated generation resource or energy storage resource that is party to a net metering arrangement and subject to the requirements of PURA §39.169. ERCOT has the technical expertise to appropriately determine how best to conduct the study under PURA §39.169. Therefore, the commission declines to make the change.

Supporting study to determine whether a transmission asset is underutilized or stranded

Oncor recommended that the rule clarify the kind of supporting study required to determine whether a transmission asset is underutilized or stranded, and which entity will be responsible for conducting that study. Oncor is not familiar with an existing power flow model that would accurately forecast the annual utilization of a given networked transmission line with an acceptable degree of certainty. There are thousands of variables that impact the flows of power on the network and the utilization of networked assets. However, Oncor noted that this issue is moot if the commission adopts its recommendation to consolidate the definitions for stranded and underutilized transmission assets and define the term as a radial transmission line that is effectively unused as a result of a net metering arrangement other than in times when the now behind-the-meter generation makes available its capacity to the ERCOT market as required by PURA §39.169.

Commission Response

The commission declines to adopt Oncor's recommendation to clarify the kind of supporting study required to determine whether a transmission asset is underutilized or stranded. The commission expects the interconnecting TSP and ERCOT to work together to identify the relevant information for this type of study. Additionally, the commission modifies the adopted rule to add a requirement for the interconnecting TSP to submit the assets and facilities that are de-energized as a result of the net metering arrangement.

Net metering arrangement study process

Oncor recommended that the rule clarify that ERCOT's 120-day study period does not commence until the full suite of interconnection studies, conducted by the TSP, are complete and provided to ERCOT. Any additional study required by ERCOT's study of the arrangement not already included within the large load interconnection study will take well over 120 days to conduct. Oncor further recommended that proposed §25.205(g)(2) could be modified to include a new required submission after (A): "all other transmission security analysis studies required under subsection (h)(2) of this rule, which are to be prescribed during ERCOT's large load interconnection study process."

Commission Response

The commission declines to adopt Oncor's recommendation to modify adopted §25.205(g)(2) to clarify that ERCOT's 120-day study period does not commence until the full suite of interconnection studies, conducted by the TSP, are complete and provided to ERCOT. Instead, the commission addresses Oncor's recommendation in adopted §25.205(d). For additional clarity, the commission modifies adopted §25.205(d) to add a provision that specifically addresses circumstances in which the information submitted to ERCOT by the parties to a net metering arrangement materially changes or new information becomes available.

The commission agrees with Oncor that the adopted rule does not change the large load interconnection process, which applies equally to any large load customer regardless of whether the large load customer is co-located under the existing large load interconnection study process that in effect now or the proposed batch study process under development, which will have specific study requirements that must be completed by a TSP and/or ERCOT.

Proposed §25.205(a) - Applicability

Proposed §25.205(a) states that the proposed rule applies to a net metering arrangement involving a large load customer and an existing generation resource. Additionally, proposed §25.205(a) states that the proposed rule does not apply to a generation resource or energy storage resource: (1) the registration for which included a co-located large load customer at the time of the generation resource or energy storage resource's energization, regardless of whether the large load customer 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 a customer that participates in the new net metering arrangement.

CenterPoint recommended modifying proposed §25.205(a) to specifically limit the proposed rule to net metering arrangements in the ERCOT region because the scope of PURA §39.169 is limited to the ERCOT region.

Eolian recommended modifying proposed §25.205(a) to reference the full interconnection study rather than ERCOT registration as the relevant point for determining whether a generation resource or energy storage resource with a co-located large load is exempt from the proposed rule.

TCPA and Vistra recommended modifying proposed §25.205(a) to clarify and reflect that the proposed rule applies to implementation of a net metering arrangement, not the actual contract. TCPA and Vistra also recommended conforming changes throughout the proposed rule.

TPPA recommended modifying proposed §25.205(a)(1) to specify the applicable date as September 1, 2025 consistent with the effective date of Senate Bill 6.

TAEBA recommended modifying proposed §25.205(a)(1) and (2) to state: "the generation or energy storage resource" instead of "registration for which" and "which is."

Commission Response

The commission adopts CenterPoint's recommendation to modify adopted §25.205(a) to specifically state the rule applies to net metering arrangements in the ERCOT region.

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(a) to reference the full interconnection study rather than ERCOT registration as the relevant point for determining whether a generation resource or energy storage resource with a co-located large load is exempt from the adopted rule. ERCOT registration is consistent with PURA §39.169(a), which states that a power generation company, municipally owned utility, or electric cooperative must submit a notice to ERCOT before implementing a net metering arrangement between an operating facility registered with ERCOT as a stand-alone generation resource as of September 1, 2025, and a new large load customer.

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(a) to state that the adopted rule applies to implementation of a net metering arrangement. The commission does not approve implementation of the net metering arrangement but rather approves the net metering arrangement and determines whether to impose conditions, such as ongoing, operational requirements, before implementation may occur.

The commission declines to adopt TPPA's recommendation to modify adopted §25.205(a)(1) to specify the applicable date as September 1, 2025 because it is unnecessary. On September 19, 2025, ERCOT identified and publicly filed in Project No. 58317, SB 6 Implementation, and in this project, each generation resource and energy storage resource that the adopted rule will apply to base on their status as of September 1, 2025.

The commission substantively adopts TAEBA's recommendation to modify adopted §25.205(a)(1) by replacing "registration of which" with "generation resource or energy storage resource." Specifically, the commission modifies adopted §25.205(a)(1) by replacing "registration of which" with "the modeled generation resource or energy storage facility." The commission adopts TAEBA's recommendation to modify adopted §25.205(a)(2) by replacing "which is" with "generation resource or energy storage resource."

Proposed §25.205(b) - Definitions

Proposed §25.205(b) sets forth the definitions for specific terms used in the proposed rule.

Add a new definition for application

TCPA recommended adding a new definition that defines "application" to mean a filing for approval by the parties with the commission as required under subsection (d) to obtain commission approval to implement the net metering arrangement. TCPA reasoned that the addition of this definition provides a clear point in time that triggers the beginning of the statutory 180-day timeframe for the process, as well as the discovery timeline for the contested case.

Commission Response

The commission declines to adopt TCPA's recommendation to add a new definition that defines "application" to mean a filing for approval by the parties with the commission as required under subsection (d) to obtain commission approval to implement the net metering arrangement because it is unnecessary. The clear point in time that triggers the beginning of the statutory deadlines for the process is when ERCOT determines that it has all the necessary information to conduct the study. Adopted §25.205(g)(3) provides this clarity by requiring ERCOT to conduct its study upon receipt of all necessary information and within seven days of commencing its study to file notice in the docket indicating the date that ERCOT commenced its study and the date ERCOT must file its study results and recommendations. This aligns with PURA §39.169(d), which requires ERCOT to study the system impacts of a proposed net metering arrangement and removal of generation after receiving all information regarding the arrangement that is required by ERCOT.

Add a new definition for interconnecting utility

CenterPoint recommended adding a new definition that defines "interconnecting utility" to mean both the electric cooperative, transmission and distribution utility, or municipally owned utility that is interconnected with the existing generation resource who is entering into a net metering arrangement and, if different entities, the electric cooperative, transmission and distribution utility, or municipally owned utility that is responsible for interconnecting with the large load customer who is entering into a net metering arrangement. Similarly, Eolian recommended adding a new definition that defines "interconnecting utility" to mean the transmission or distribution utility (including a municipally owned utility or electric cooperative) that owns or operates the facilities at the point of interconnection used by the net metering arrangement.

Commission Response

The commission declines to adopt CenterPoint's recommendation to add a new definition that defines "interconnecting utility" to mean both the electric cooperative, transmission and distribution utility, or municipally owned utility that is interconnected with the existing generation resource who is entering into a net metering arrangement and, if different entities, the electric cooperative, transmission and distribution utility, or municipally owned utility that is responsible for the interconnecting with the large load customer who is entering into a net metering arrangement because it is unnecessary. To maintain consistency across the rules implementing Senate Bill 6, the commission uses the phrases "interconnecting TSP" and "interconnecting DSP." The commission modifies adopted §25.205(b) to add definitions for these terms.

Add a new definition for parties

TEC recommended adding a new definition for "parties to a net metering arrangement" to mean the parties to a net metering arrangement shall include at least the existing generation resource, the large load customer, and any electric cooperative or municipally owned utility certificated to interconnect or provide retail electric utility service at the location of the net metering arrangement.

Commission Response

The commission declines to adopt TEC's recommendation to add a new definition for "parties to a net metering arrangement" to mean the parties to a net metering arrangement shall include at least the existing generation resource, the large load customer, and any electric cooperative or municipally owned utility certificated to interconnect or provide retail electric utility service at the location of the net metering arrangement because it is unnecessary. However, the commission modifies adopted §25.205(b)(1) to clarify within the definition for applicants that the applicants are the large load customer and the power generation company, municipally owned utility, or electric cooperative that are parties to a net metering arrangement for which approval is sought.

Add a new definition for PUN

CenterPoint and OPUC recommended adding a new definition for "PUN." CenterPoint recommended defining PUN to mean a non-utility owned interconnection facility.

Commission Response

The commission declines to adopt CenterPoint and OPUC's recommendation to add a new definition for "PUN." However, the commission replaces references in the adopted rule to "PUN load" with "modeled load other than auxiliary load" for added clarification.

Add a new definition for dispatchable capacity

Sierra Club recommended adding a new definition that defines "dispatchable capacity" as power generation resources, including energy storage resources, that can be instructed by ERCOT to increase or decrease their output in response to real-time grid conditions to meet electricity demand, and are not powered by renewable resources.

Commission Response

The commission adopts Sierra Club's recommendation to add a new definition for "dispatchable capacity." However, the commission defines "dispatchable capacity" as output capacity that can be controlled primarily by forces under human control.

Add a new definition for necessary information

Vistra recommended adding a new definition that defines "necessary information" as the discrete list of information designated by ERCOT in a market notice, protocol, planning guide, or other binding document specifically identified and which sets forth the specific information regarding a net metering arrangement required to be submitted to ERCOT in order for ERCOT to begin its system reliability study under this section. Vistra also recommended modifying proposed §25.205(g)(1) and (2)(C) and proposed §25.205(i) to make conforming changes by replacing references to "information that ERCOT deems necessary" with the newly defined term, "necessary information."

Commission Response

The commission declines to adopt Vistra's recommendation to add a new definition for "necessary information" and therefore also declines to adopt Vistra's recommended conforming changes. The necessary information that must be submitted to ERCOT is best addressed by ERCOT and does not require commission direction through the adopted rule.

Proposed §25.205(b)(1) - Definition for applicants

Proposed §25.205(b)(1) defines applicants as the parties to a net metering arrangement for which approval is sought under this section.

TEC recommended modifying proposed §25.205(b)(1) to define applicants as the parties to a net metering arrangement that apply for approval of the arrangement under this section.

TPPA recommended modifying proposed §25.205(b)(1) to specify that "applicants" refers exclusively to the large load customer and the generation resource.

Commission Response

The commission declines to adopt TEC's recommendation to modify adopted §25.205(b)(1) to define "applicants" as the parties to a net metering arrangement because it is unnecessary. The commission substantively adopts TPPA's recommendation to modify adopted §25.205(b)(1) to specify that "applicants" refers exclusively to the large load customer and the generation resource that are parties to the net metering arrangement for which approval is sought. The commission modifies adopted §25.205(b)(1) to specify that "applicants" refers exclusively to the large load customer and the owner of the existing generation resource that are parties to the net metering arrangement for which approval is sought. The commission further notes that any approval of a net metering arrangement will apply only to the applicants and is not transferable or assignable without commission approval. The approval is exclusively for the applicants and is not a transferrable right to non-applicants.

Proposed §25.205(b)(2) - Definition for energy storage resource

Proposed §25.205(b)(2) defines an energy storage resource as an energy storage system registered with ERCOT as an energy storage resource for the purpose of providing energy or ancillary services to the ERCOT grid and associated facilities that are behind the system's point of interconnection, necessary for the operation of the system, and not part of a manufacturing process that is separate from the generation of electricity.

OPUC recommended modifying proposed §25.205(b)(2) to broaden the definition by referencing all processes instead of manufacturing processes and clarify that "generation of electricity" is intended for delivery to the ERCOT system.

Eolian recommended modifying proposed §25.205(b)(2) to cite the definition for an energy storage resource in the ERCOT protocols.

Consistent with its general comments that an energy storage resource should not be authorized to participate in a net metering arrangement, TPPA recommended modifying the proposed rule to remove the definition for energy storage resource and all references to the term in the proposed rule.

Commission Response

The commission declines to adopt OPUC's recommendation to modify adopted §25.205(b)(3) to broaden the definition by referencing all processes instead of manufacturing process and clarify that "generation of electricity" is intended for delivery to the system. Instead, the commission adopts Eolian's recommendation to modify adopted §25.205(b)(3) to cite to the definition for an energy storage resource in ERCOT protocols to maintain consistency across the commission rules and ERCOT protocols.

The commission declines to adopt TPPA's recommendation to remove the definition for energy storage resource and all references to the term in the rule because the commission declines to adopt TPPA's general recommendation to explicitly exclude energy storage resources from the rule's applicability. Therefore, the recommended change is unnecessary.

Proposed §25.205(b)(3) - Definition for an existing generation resource

Proposed §25.205(b)(3) defines an existing generation resource as a generation resource registered with ERCOT as a stand-alone generation resource as of September 1, 2025 or an energy storage resource registered with ERCOT as a stand-alone energy storage resource as of September 1, 2025.

Eolian recommended modifying proposed §25.205(b)(3) to replace "registered" with "operating" and to clarify that the cutoff date applies to facilities operating and registered with ERCOT as of September 1, 2025. Eolian reasoned that this change implements PURA §39.169(a)(9), which explicitly references "operating facilities registered with ERCOT," and ensures that only active, available, or dispatchable units are captured--excluding mothballed, retired, or otherwise dormant assets.

TPPA recommended modifying proposed §25.205(b)(3) to expand the definition for an "existing generation resource" to include any generation resource that does not have a net metering arrangement request upon initial registration with ERCOT, regardless of when the resource was or is built. TPPA reasoned that PURA §39.169 prescribes the arrangements that the commission must review but does not prohibit the commission from reviewing all net metering arrangements more holistically.

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(b)(5) to replace "registered" with "operating" to ensure that only active available, or dispatchable units are captured--excluding mothballed, retired, or otherwise dormant assets--because it is unnecessary.

The commission declines to adopt TPPA's recommendation to modify adopted §25.205(b)(5) to expand the definition for an "existing generation resource" to include any generation resource that does not have a net metering arrangement request upon initial registration with ERCOT, regardless of when the resource was or is built. PURA §39.169 applies to an operating facility registered with ERCOT as a stand-alone generation resource as of September 1, 2025. Therefore, broadening the applicability of the adopted rule would exceed the commission's statutory authority and render the registration status meaningless, which is inconsistent with Texas Government Code §311.021(2).

Proposed §25.205(b)(4) - Definition for generation resource

Proposed §25.205(b)(4) defines a generation resource as a generator registered with ERCOT as a generation resource and capable of providing energy or ancillary services to the ERCOT grid, as well as associated facilities that are behind the generator's point of interconnection, necessary for the operation of the generator, and not part of a manufacturing process that is separate from the generation of electricity.

OPUC recommended modifying proposed §25.205(b)(4) to broaden the definition by referencing all processes instead of manufacturing processes and clarify that "generation of electricity" is intended for delivery to the ERCOT system.

Eolian recommended modifying proposed §25.205(b)(4) to cite to the definition for a generation resource in the ERCOT protocols.

TPPA recommended modifying proposed §25.205(b)(4) to mirror the definition for a generation resource in the ERCOT protocols.

Commission Response

The commission declines to adopt OPUC's recommendation to modify adopted §25.205(b)(6) to broaden the definition by referencing all processes instead of manufacturing process and clarify that "generation of electricity" is intended for delivery to the system. The commission also declines to adopt TPPA's recommendation to modify adopted §25.205(b)(6) to mirror the definition for a generation resource in the ERCOT protocols. Instead, the commission adopts Eolian's recommendation to modify adopted §25.205(b)(6) to cite the definition for a generation resource in the ERCOT protocols to maintain consistency across the commission rules and ERCOT protocols.

Proposed §25.205(b)(5) - Definition for large load customer

Proposed §25.205(b)(5) defines a large load customer as a customer that requests a new or expanded interconnection where the total load at a single site is equal to or greater than 75 megawatts (MW), and as of September 1, 2025, was not modeled in ERCOT's Network Operations Model as part of a generation resource PUN or an energy storage resource PUN.

Specify interconnection is at transmission voltage

OPUC recommended modifying proposed §25.205(b)(5) to specify load that is connected at transmission voltage. OPUC reasoned that loads greater than 50 MW are connected at transmission voltage and removing the involvement of DSPs may simplify roles and responsibilities.

Commission Response

The commission declines to adopt OPUC's recommendation to modify adopted §25.205(b)(9) to specify that the definition applies to a load that is connected at transmission voltage because the relevant determination is the size of the load, not the voltage level that the large load customer interconnects. Moreover, removing involvement of a DSP may not simplify roles because regardless of the voltage level that a large load customer interconnects, a generation resource cannot sell power directly to an end-use consumer. Thus, 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 must necessarily be involved.

Reduce the demand threshold to 25 MW

Sierra Club recommended modifying proposed §25.205(b)(5) to change the demand threshold for identifying a large load customer from 75 MW to 25 MW.

Commission Response

The commission declines to adopt Sierra Club's recommendation to modify adopted §25.205(b)(9) to change the demand threshold for identifying a large load customer from 75 MW to 25 MW. The 75 MW demand threshold aligns with the commission's approach in other rules implementing Senate Bill 6 and qualitative analysis has not been provided indicating that a lower demand threshold is appropriate to achieve the objectives specific to implementing PURA §39.169. To further maintain consistency, the commission modifies the definition for a large load customer to better align the definition with that used in other rules implementing Senate Bill 6.

Remove reference to expanded

TCPA and Vistra recommended modifying proposed §25.205(b)(5) to remove reference to "expanded" because unlike PURA §37.0561, PURA §39.169(a) is limited to new interconnections.

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(b)(9) to remove reference to "expanded." PURA §39.169(a) specifically cites to the description for a large load customer in PURA §37.0561(c). PURA §37.0561(c) describes a large load customer as a customer requesting 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. PURA §37.0561(c) also states the commission must establish a demand threshold of 75 MW unless the commission determines that a lower threshold is necessary to accomplish the purposes described by PURA §37.0561(b). Thus, the commission determines that based on a plain reading of the language in the statute, a new large load customer as described by PURA §37.0561(c) encompasses the full description in PURA §37.0561, including a customer requesting expanded interconnection that would result in the total load at a single site exceeding 75 MW. Moreover, limiting the definition to only customers requesting a new interconnection would open the door to gamesmanship. Thus, the commission determines that the definition in adopted §25.205(b)(9) aligns with a plain reading of PURA §39.169, is unambiguous, and results in a good policy outcome. Therefore, the commission declines to make the recommended changes.

Remove "and as of September 1, 2025, was not modeled in ERCOT's Network Operations Model as part of a generation resource PUN or an energy storage resource PUN"

TCPA, TPPA, and Vistra recommended modifying proposed §25.205(b)(5) to remove "and as of September 1, 2025, was not modeled in ERCOT's Network Operations Model as part of a generation resource PUN or an energy storage resource PUN." TCPA noted that this language is not part of the statute. TPPA reasoned that "private use network" is not defined in PURA, commission rules, or ERCOT protocols, and the date does not seem relevant to the applicability of the definition. Vistra reasoned that a customer is not modeled and the presence of a customer's load in the model is not a relevant consideration.

Commission Response

The commission declines to adopt TCPA, TPPA, and Vistra's recommendation to modify adopted §25.205(b)(9) to remove "and as of September 1, 2025, was not modeled in ERCOT's Network Operations Model as part of a generation resource private use network (PUN) or an energy storage resource PUN." The date is meaningful insofar as PURA §39.169(a) requires notice to ERCOT before implementing a net metering arrangement between an operating facility registered with ERCOT as a stand-alone generation resource as of September 1, 2025, and a new large load customer. Additionally, the commission notes that PUN is defined in ERCOT protocols and is a meaningful term. The commission also notes that while this language is not part of the statute, the purpose of rules is to fill in the gaps in statutes. Finally, the commission determines that the presence of a customer's load in the model is a relevant consideration because it gives meaning to PURA §39.169(b)(2), which states the statute does not apply to a generation resource, 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.

Proposed §25.205(b)(6) - Definition for large load interconnection study

Proposed §25.205(b)(6) defines a large load interconnection study to have the same meaning as defined in ERCOT protocols.

TPPA recommended modifying proposed §25.205(b)(6) to incorporate the full definition from the ERCOT protocols directly into the proposed rule, rather than referencing the protocols. TPPA reasoned that this approach would prevent potential issues arising from future changes to the ERCOT protocols that could impact the rule without consideration of their effects.

Commission Response

The commission declines to adopt TPPA's recommendation to modify the definition for large load interconnection study to incorporate the full definition from the ERCOT protocols directly into the adopted rule, rather than referencing the protocols. Instead, the commission removes the definition from the adopted rule because the definition is unnecessary.

Proposed §25.205(b)(7) - Definition for net metering arrangement

Proposed §25.205(b)(7) defines a net metering arrangement as a contractual arrangement in which an existing generation resource and a large load customer agree to net the generation resource's output with the customer's load for settlement purposes based on a net metering scheme approved by ERCOT.

Calpine recommended modifying proposed §25.205(b)(7) to strike the reference to "contractual" because a contractual arrangement is unnecessary. Calpine reasoned that netting is established through the existing settlement procedures in the ERCOT protocols regardless of a written agreement.

Eolian recommended modifying proposed §25.205(b)(7) to clarify that a net metering arrangement is a contractual arrangement between an existing generation resource or energy storage resource and a new large load customer. Eolian reasoned that this change identifies the responsible parties consistent with ERCOT's market and metering structure, thereby improving transparency regarding compliance obligations. Moreover, the change aligns the proposed rule with ERCOT's operational treatment of paired generation and load configurations, supports accurate registration and telemetry, and reduces potential ambiguity in future applications.

TPPA recommended modifying proposed §25.205(b)(7) consistent with its general comments recommending that the commission ensure that meters serving large load customers are still allocated ancillary service obligations, transmission costs, load ratio share uplift charges, and charges associated with line losses.

Commission Response

The commission adopts Calpine's recommendation to modify adopted §25.205(b)(10) to remove the reference to "contractual" because the term "contractual" could be interpreted to narrow the applicability of the adopted rule, which is not the intent. There may be aspects of a net metering arrangement that are not reflected in a contract but may be subject to the requirements of the adopted rule. For added clarity, the commission notes that the change does not alter the relevance of a contract in a contested case proceeding evaluating a net metering arrangement.

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(b)(10) to state that a net metering arrangement is a contractual arrangement between an existing generation resource or energy storage resource and a new large load customer because it is unnecessary. The commission declines to adopt TPPA's recommendation to modify adopted §25.205(b)(10) to ensure that meters serving large load customers are still allocated ancillary service obligations, transmission costs, load ratio share uplift charges, and charges associated with line losses because it is outside the scope of this rulemaking and is unnecessary. The commission has other pending rules that will address a large load customer's contribution to system upgrades and the ERCOT protocols already address how ERCOT settles net metering.

Proposed §25.205(b)(8) - Definition for stand-alone energy storage resource

Proposed §25.205(b)(8) defines a "stand-alone energy storage resource" as an energy storage resource that, as of September 1,2025, was included in ERCOT's Network Operations Model and such model of the resource site did not include a PUN load.

TPPA recommended modifying proposed §25.205(b) to remove proposed §25.205(b)(8) consistent with TPPA's recommendation to exclude energy storage resources from the proposed rule.

Vistra recommended modifying proposed §25.205(b)(8) to define a stand-alone energy storage resource as one that, as of September 1, 2025, was registered with ERCOT as a resource and for which a transmission and distribution service provider had not begun a large load interconnection study for a load to be netted with the resource. Vistra reasoned that the definition in proposed §25.205(b)(8) runs counter to the statute's general objectives and imposes additional burdens, conditions, or restrictions in excess of and inconsistent with PURA §39.169. Vistra noted that the Legislature declared in PURA §37.0561(b) that the overall objective for interconnecting large load customers is to support business development in this state while maintaining system reliability. Additionally, Vistra cited to a discussion on the floor of the Texas House of Representatives in support of its assertion that the key legislative goals are to "not slow down large load projects that are currently in the works" and to "not add new processes or requirements" for projects for which the parties signed a contract for services before September 1, 2025.

Vistra also noted that under the definition in proposed §25.205(b)(8), a stand-alone energy storage resource would have needed to have submitted an application to include a PUN by May 1, 2025 to achieve the status set forth in the proposed definition. Thus, Vistra reasoned that the proposed definition effectively turns a September 1, 2025 cut-off date into a May 1, 2025 cut-off date. Moreover, Vistra asserted that the excessive burden of the proposed rule's approach can be demonstrated by noting that, to obtain regulatory predictability, an entity would have had to have predicted the outcome of Senate Bill 6 and would have needed to have taken the steps to make filings at ERCOT during the first few months of the Legislative session, before the bill had a substantive hearing in the Texas House, which occurred on May 7, 2025.

Finally, Vistra asserted that "stand-alone energy storage resource" should be interpreted consistent with the Texas Code Construction Act and based on legislative intent, the object sought to be attained (economic development), legislative history, and the consequences of a particular construction. For the same reasons, Vistra also recommended conforming changes to proposed §25.205(b)(9), which defines a "stand-alone generation resource."

Commission Response

The commission declines to adopt TPPA's recommendation to remove the definition for a stand-alone energy storage resource because the commission declines to adopt TPPA's general recommendation to exclude energy storage resources from the applicability of the adopted rule. Therefore, the change is unnecessary.

The commission declines to adopt Vistra's recommendation to modify adopted §25.205(b)(11) to define a stand-alone energy storage resource as one that, as of September 1, 2025, was registered with ERCOT as a resource and for which a transmission and distribution service provider had not begun a large load interconnection study for a load to be netted with the resource. An energy storage resource's status as of September 1, 2025 is appropriately determined by looking at whether ERCOT's system information reflected the addition of a large load customer at the energy storage resource site as of September 1, 2025. The addition of a large load customer would have required a change to reflect that load in ERCOT's Network Operations Model. Therefore, it is appropriate to consider an energy storage resource to be a stand-alone energy storage resource as of September 1, 2025 if the resource was (1) included in ERCOT's Network Operations Model as of September 1, 2025, and (2) the modeled energy storage facility that included the energy storage resource did not include a modeled load other than auxiliary load as of that date.

In support of its recommended definition for a stand-alone energy storage resource, Vistra cites PURA §37.0561, which requires the commission to establish standards for interconnecting large load customers in the ERCOT power region in a manner designed to support business development while minimizing the potential for stranded infrastructure costs and maintaining system reliability. The commission notes that while a large load customer requesting interconnection must comply with the requirements set forth in PURA §37.0561 and the stated purpose of PURA §37.0561 governs those requirements, PURA §37.0561(b) does not govern the commission's implementation of PURA §39.169 except where explicitly cited, such as the definition for a large load customer. However, even if the stated purpose of PURA §37.0561(b) did govern the commission's implementation of PURA §39.169, Vistra's assertion that the definition for a stand-alone energy storage resource runs counter to the statute's general objectives and imposes additional burdens, conditions, or restrictions in excess of and inconsistent with PURA §39.169 is unfounded.

The commission first notes that the Texas Supreme Court has stated a statute's objective is discerned from its plain text. Tex. Bd. Of Chiropractic Exam'rs v. Tex. Med. Ass'n, 616 S.W.3d 558, 569 (Tex. 2021) (citing Tex. State Bd. Of Exam'rs of Marriage & Fam. Therapists v. Tex. Med. Ass'n, 511 S.W.3d 28, 33 (Tex. 2017)). Moreover, the Texas Supreme Court takes statutes as it finds them, presuming the Legislature included words that it intended to include and omitted words it intended to omit. Union Carbide Corp. v. Synatzske, 438 S.W.3d 39, 52 (Tex. 2014). Notably, Vistra relies on a discussion on the floor of the Texas House of Representatives in support of its assertion that the key legislative goals are to "not slow down large load projects that are currently in the works" and to "not add new processes or requirements" for projects for which the parties signed a contract for services before September 1, 2025. However, these goals are not stated in PURA §39.169. Therefore, the commission determines, based on the guidance of the Texas Supreme Court in interpreting statutes, that the commission's interpretation of the Legislature's intent must be guided by the plain language of PURA §39.169.

Relatedly, PURA §39.169 requires the commission to evaluate whether to approve, with or without conditions, or deny a net metering arrangement and authorizes the commission to impose reasonable conditions on the proposed net metering arrangement as necessary to maintain system reliability, including transmission security and resource adequacy. Thus, based on the plain text of the statute, the commission determines that the legislative goal was to support business development by continuing to permit net metering arrangements but to balance that support with maintaining system reliability by granting the commission oversight authority to impose reasonable conditions to maintain system reliability. Additionally, the commission notes that the Legislature was concerned about customers in the ERCOT region paying for stranded or underutilized transmission assets, and therefore the Legislature explicitly included in PURA §39.169 that the commission may impose a condition holding customers harmless for stranded or underutilized transmission assets.

Second, the commission notes that "stand-alone" is not defined in PURA, commission rules, or ERCOT protocols, nor does it exist as a unique registration category. Thus, it is appropriate for the commission to interpret the statutory language "registered with the independent organization as a stand-alone generation resource" as describing the resource's registration status at a point in time. "Stand-alone" in this context indicates that the energy storage resource or generation resource is not co-located with a large load customer. Because stand-alone generation resource is not a defined registration category, the resource's registration status as a stand-alone generation resource at any point in time is best reflected by ERCOT's Network Operations Model, which indicates whether a large load customer is co-located with an energy storage resource or a generation resource in a PUN. Therefore, the commission determines that it is appropriate to define a stand-alone energy storage resource as an energy storage resource that, as of September 1, 2025, was included in ERCOT's Network Operations Model and such model of the resource site did not include modeled load other than auxiliary load.

Finally, the commission disagrees with Vistra's assertion that the adopted rule imposes an excessive burden, which according to Vistra can be demonstrated by noting that, to obtain regulatory predictability, an entity would have had to have predicted the outcome of Senate Bill 6 and would have needed to have taken the steps to make filings at ERCOT during the first few months of the Legislative session, before the bill had a substantive hearing in the Texas House, which occurred on May 7, 2025. Anytime a new law is enacted, it impacts entities on a going forward basis. This is not an excessive burden. Moreover, while regulatory predictability provides benefits, the inability to determine in advance whether an entity might consider a different course of action, is not an excessive burden. Nor is an excessive burden the legal standard for statutory interpretation.

Proposed §25.205(b)(9) - Definition for stand-alone generation resource

Proposed §25.205(b)(9) defines a "stand-alone generation resource" as a generation resource that, as of September 1, 2025, was included in ERCOT's Network Operations Model and such model of the resource site did not include a PUN load.

TPPA recommended removing the reference to "PUN" and broadening the definition to ensure that any future generation resource built and energized without an associated net metering arrangement would also be required to comply with the processes outlined in the proposed rule.

Consistent with its recommended changes to proposed §25.205(b)(8), Vistra recommended conforming changes to proposed §25.205(b)(9).

Commission Response

The commission adopts TPPA's recommendation to modify adopted §25.205(b)(12) to remove the reference to "PUN." Accordingly, the commission modifies adopted §25.205(b)(12) to replace the reference to "PUN load" with "modeled load other than auxiliary load." The commission declines to adopt TPPA's recommendation to modify adopted §25.205(b)(12) to broaden the definition to ensure that any future generation resource built and energized without an associated net metering arrangement would also be required to comply with the processes outlined in the proposed rule. PURA §39.169 applies to an operating facility registered with ERCOT as a stand-alone generation resource as of September 1, 2025. Therefore, broadening the applicability of the adopted rule would render the registration status on September 1, 2025 meaningless, which is inconsistent with Texas Government Code §311.021(2).

The commission declines to adopt Vistra's recommendation to modify adopted §25.205(b)(12) to conform with Vistra's recommended changes to adopted §25.205(b)(11) because the commission declines to adopt Vistra's recommended changes to adopted §25.205(b)(11).

Proposed §25.205(b)(10) - Definition for stranded transmission asset

Proposed §25.205(b)(10) defines a stranded transmission asset as a transmission asset that, as a result of a net metering arrangement, is no longer providing service to the public or may otherwise be retired from service without impairing the ability of the transmission system to provide adequate transmission service to customers.

Satoshi recommended modifying proposed §25.205(b)(10) to provide clarity and promote consistent application by replacing "is no longer providing service to the public or may otherwise be retired from service without impairing the ability of the transmission system to provide adequate transmission service to customers" with "results in a permanently de-energized electrical bus from the transmission system."

If its primary recommendation to consolidate the definitions for "stranded transmission asset" and "underutilized transmission asset" is not adopted, then TSSA recommended modifying proposed §25.205(b)(10) to state: "a transmission asset that is necessary to maintain system reliability but is no longer used and useful in the provision of electric service as a result of a net metering arrangement."

OPUC recommended replacing the definition in proposed §25.205(b)(10) with: "a transmission asset that was primarily built to interconnect a generation resource to the system, but as a result of a net metering arrangement, never materialized or was used in providing service to the public."

Commission Response

The commission declines to adopt Satoshi's recommendation to modify adopted §25.205(b)(13) by replacing "is no longer providing service to the public or may otherwise be retired from service without impairing the ability of the transmission system to provide adequate service to customers" with "results in a permanently de-energized electrical bus from the transmission system." Satoshi's recommended language describes the action taken in the event of a stranded asset being identified rather than describes what a stranded asset is. Therefore, the commission declines to adopt the recommended change.

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(b)(13) to state: "a transmission asset that is necessary to maintain system reliability but is no longer used and useful in the provision of electric service as a result of a net metering arrangement." PURA §39.169(d)(3) authorizes the commission to impose conditions, including a requirement that customers be held harmless for stranded or underutilized transmission assets resulting from the behind-the-meter operation. PURA §39.169(d)(3) does not specify that the condition is limited to only those transmission assets that are necessary to maintain system reliability. Moreover, it is in the public interest to ensure that customers are held harmless for all transmission assets that are stranded or underutilized as a result of a net metering arrangement, not just for those transmission assets that are necessary to maintain system reliability.

The commission declines to adopt OPUC's recommendation to replace the definition for stranded transmission asset with "a transmission asset that was primarily built to interconnect a generation resource to the system, but as a result of a net metering arrangement, never materialized or was used in providing service to the public." The recommended language could be read to narrow the transmission assets that customers may be held harmless for to only those that were built for the intended purpose of serving a generation resource. PURA §39.169(d)(3) does not limit the condition to those transmission assets that are primarily built to interconnect a generation resource to the system and never materialized or were used in providing service to the public.

Proposed §25.205(b)(10) and (12) - Definitions for stranded transmission asset and underutilized transmission asset

Proposed §25.205(b)(10) defines a stranded transmission asset as a transmission asset that, as a result of a net metering arrangement, is no longer providing service to the public or may otherwise be retired from service without impairing the ability of the transmission system to provide adequate transmission service to customers. Proposed §25.205(b)(12) defines an underutilized transmission asset as a transmission asset that, as a result of a net metering arrangement, is expected to transmit, on an average, annual basis at least 25% less power and is not providing significant reliability benefits to the system commensurate with its ability to transmit power.

Calpine, CenterPoint, Oncor, TCPA, TSSA, and Vistra recommended consolidating the definitions for stranded transmission asset and underutilized transmission asset set forth in proposed §25.205(b)(10) and (12). Specifically, Oncor recommended using a single definition to define stranded or underutilized transmission asset as a radial transmission line that is effectively unused as a result of a net metering arrangement other than in times when the now behind-the-meter generation makes available its capacity to the ERCOT market as required by PURA §39.169. Oncor reasoned that this definition would clarify the scope of these assets to only radial connections to existing generation resources. This is appropriate because radial lines are the only assets that will be rendered stranded or underutilized by net metering arrangements. Non-radial assets remain useful to the system due to the way an electric grid functions and adapts to various contingencies on a day in and day out basis. Networked transmission lines cannot be, by definition, stranded or underutilized assets because they provide essential alternate pathways for power to flow on the system regardless of average usage. Calpine and CenterPoint supported Oncor's recommendation and reasoning to consolidate the two definitions. However, Calpine recommended removing "effectively" from Oncor's proposed recommended change because the term is ambiguous.

TCPA recommended keeping the definition for stranded transmission asset but using that definition for "stranded or underutilized transmission asset." TCPA reasoned that transmission infrastructure is not valued on its annual average power flow generally, so to do so singularly in this rule would be an arbitrary distinction--especially given a fair presumption that many net metering arrangements subject to PURA §39.169(d)(3) will be flexible and include criteria for the generation resource's output to flow back over those transmission facilities to other loads. If its primary recommendation to modify proposed §25.205(b)(12) is not adopted, then Vistra recommended, in the alternative, consolidating the definitions for stranded transmission asset and underutilized transmission asset, as proposed by TCPA.

TSSA recommended using the following for the consolidated definition: "a transmission asset that is necessary to maintain system reliability but is no longer used and useful in the provision of electric service as a result of a net metering arrangement." TSSA reasoned that PURA §39.169(d)(3) limits the commission's authority to impose a condition, including a condition that holds customers harmless for "stranded or underutilized transmission assets" resulting from a net metering arrangement, only as necessary to maintain system reliability. Thus, the plain language of the statute authorizes the commission "to approve, deny, or impose reasonable conditions on the proposed net metering arrangement as necessary to maintain system reliability, including transmission security and resource adequacy impact."

Commission Response

The commission declines to adopt Calpine, CenterPoint, Oncor, TCPA, TSSA and Vistra's recommendation to consolidate the definitions for stranded transmission asset and underutilized transmission asset. Stranded and underutilized are not synonymous terms. Moreover, Texas Government Code §311.021(2) states that the entire statute is presumed to be effective, which means that each word is presumed to have meaning. Therefore, the commission concludes that separate and distinct definitions should be maintained for stranded transmission assets and underutilized transmission assets. The commission also disagrees with TSSA's interpretation of PURA §39.169(d)(3). PURA §39.169(d)(3) specifically enumerates holding customers harmless as a condition that the commission may impose and does not limit that condition to stranded or underutilized transmission assets that are necessary to maintain system reliability.

Proposed §25.205(b)(11) - Definition for system

Proposed §25.205(b)(11) defines "system" as the bulk power system in the ERCOT region.

Eolian recommended modifying proposed §25.205(b)(11) to cite to the definition for "system" in the ERCOT protocols.

Commission Response

The commission adopts Eolian's recommendation to modify the definition for system to cite to the definition for "ERCOT system" in the ERCOT protocols. The commission also adds "ERCOT" in front of "system" to denote the term being defined is "ERCOT system" and modifies adopted §25.205(b) to place "ERCOT system" in alphabetical order of the other definitions.

Proposed §25.205(b)(12) - Definition for underutilized transmission asset

Proposed §25.205(b)(12) defines an underutilized transmission asset as a transmission asset that, as a result of a net metering arrangement, is expected to transmit, on an average, annual basis at least 25% less power and is not providing significant reliability benefits to the system commensurate with its ability to transmit power.

Calpine and Vistra recommended modifying proposed §25.205(b)(12) to remove the reference to a specific percentage so as to allow the commission flexibility in its assessment of whether a transmission asset is underutilized. Additionally, Calpine and Vistra recommended modifying proposed §25.205(b)(12) to state that an underutilized transmission asset is one that is providing no reliability benefit rather than one that provides no significant reliability benefit.

CenterPoint noted that not all transmission assets transmit power and the meaning of "25% less power" as used in the definition for underutilized transmission asset is ambiguous. Twenty-five percent less power could mean a transmission reduction of at least 25% as measured against (1) the nameplate capacity of the generation resource, (2) the amount of power actually transmitted to the ERCOT system from the generation resource during the previous year, or (3) some other baseline. Therefore, CenterPoint recommended modifying proposed §25.205(b)(12) to add clarity to the definition for underutilized transmission asset.

OPUC recommended replacing the definition in proposed §25.205(b)(12) with: "a transmission asset that was already built to connect a generation resource to the system, and was used by the generation resource to transmit power to the system, but as a result of the net metering arrangement, is no longer used to transmit power to the system but for emergencies to sustain system reliability."

CTEI recommended removing the definition for underutilized transmission asset and instead defining the term in the ERCOT protocols.

If its primary recommendation to consolidate the definitions for "stranded transmission asset" and "underutilized transmission asset" is not adopted, then TSSA recommended modifying proposed §25.205(b)(12) to state: "a transmission asset that is necessary to maintain system reliability but will no longer significantly provide useful electric service as a result of a net metering arrangement." ERCOT is directed to develop specific details and metrics through the ERCOT stakeholder process regarding identification of underutilized transmission assets."

If TCPA's primary recommendation to consolidate the definitions for stranded transmission assets and underutilized transmission assets is not adopted, then TCPA recommended increasing the threshold from "25%" to "75%." TCPA reasoned that unless the planning process for the transmission system ceases to plan for the full firm load scenario then a 25% threshold is (1) disconnected from transmission planning criteria; (2) unjustified by relevant factual context(s); and (3) would apply a discriminatory standard to existing generation resources that are co-located with a large load customer (which could be required to pay for "underutilized" transmission assets in a hold harmless proceeding) compared to that applied to other net metering arrangements with assets that are not subject to review under PURA §39.169.

TPPA recommended modifying proposed §25.205(b)(12) to clarify that the "25% less power" relates to the asset's maximum capacity.

Commission Response

The commission adopts TPPA's recommendation to modify adopted §25.205(b)(14) to clarify that the "25% less power" relates to the asset's maximum capacity. This approach also addresses CenterPoint's recommendation to clarify what the 25% is measured against. The commission declines to adopt Calpine and Vistra's recommendation to remove the reference to a specific percentage to state that an underutilized transmission asset is one that is providing no reliability benefit rather than one that provides no significant reliability benefit because this would essentially define an underutilized transmission asset the same as a stranded transmission asset. Thus, rendering the distinction meaningless. When interpreting a statute, the commission must presume that the Legislature intended to give meaning to each word. The commission declines to adopt OPUC's recommendation to replace the definition in adopted §25.205(b)(14) with "a transmission asset that was already built to connect a generation resource to the system, and was used by the generation resource to transmit power to the system, but as a result of the net metering arrangement, is no longer used to transmit power to the system but for emergencies to sustain system reliability" because it is too limiting. The commission declines to adopt CTEI's recommendation to remove the definition for underutilized transmission asset and instead define the term in ERCOT protocols because it is unnecessary. Similarly, the commission declines to adopt TSSA's recommendation to modify the definition to state "a transmission asset that is necessary to maintain system reliability but will no longer significantly provide useful electric service as a result of a net metering arrangement" and direct ERCOT to develop specific details and metrics through the ERCOT stakeholder process. The definition for an underutilized transmission asset is a policy decision that is within the purview of the commission. The commission declines to adopt TCPA's recommendation to increase the threshold from 25% to 75% because customers should be held harmless for a transmission asset that is no longer consistently used for the primary function it was built to serve. Therefore, the commission determines that 25% is an appropriate threshold.

Proposed §25.205(c) - Commission approval required

Proposed §25.205(c) states a power generation company, municipally owned utility, or electric cooperative must not implement a net metering arrangement involving a large load customer and an existing generation resource unless the net metering arrangement is approved by the commission.

Eolian recommended modifying proposed §25.205(c) to add language that clarifies entities or arrangements falling within the statutory exemption under PURA §39.169(b) are not required to obtain commission approval before implementing a net metering arrangement. Eolian reasoned that this change ensures that only non-exempt power generation companies, municipally owned utilities, or electric cooperatives must seek commission approval prior to implementation.

TCPA recommended modifying proposed §25.205(c) to add the following: "The commission shall issue the final order in a proceeding initiated under this section not later than the 180th day after the filing of a complete, non-deficient request. If the commission does not approve, deny, or impose reasonable conditions on a proposed net metering arrangement before the 180th day, the commission is considered to have approved implementation of the arrangement." TCPA reasoned that this addition aligns the proposed rule with the language PURA §39.169 and provides additional clarity.

TPPA recommended modifying proposed §25.205(c) consistent with its general comments recommending that the proposed rule's applicability be expanded so that the commission is required to review and approve all net metering arrangements.

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(c) to add language stating entities or arrangements falling within the statutory exemption under PURA §39.169(d) are not required to obtain commission approval before implementing a net metering arrangement because it is unnecessary. Adopted §25.205(a) addresses what entities must comply with the adopted rule and what entities are exempt from complying with the adopted rule. The commission declines to adopt TCPA's recommendation to modify adopted §25.205(c) to add the following: "The commission shall issue the final order in a proceeding initiated under this section not later than the 180th day after the filing of a complete, non-deficient request. If the commission does not approve, deny, or impose reasonable conditions on a proposed net metering arrangement before the 180th day, the commission is considered to have approved implementation of the arrangement." The change is unnecessary because PURA §39.169(d) addresses the timeline for the commission to issue a decision and PURA §39.169(e) addresses the fact that if the commission does not approve deny, or impose reasonable conditions on a proposed net metering arrangement before the timeline identified in PURA §39.169(d), then the net metering arrangement is considered approved. The commission declines to adopt TPPA's conforming changes because the commission declines to adopt TPPA's general recommendation to expand the applicability of the adopted rule.

Proposed §25.205(d) - Initiating the process for approval of a net metering arrangement

Proposed §25.205(d) requires the parties to a net metering arrangement (the applicants) to initiate the process for obtaining commission approval of the net metering arrangement by filing an application that meets the requirements of 16 TAC §22.73. Proposed §25.205(d)(2) requires the applicants to serve copies of their application on: (A) ERCOT; (B) the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility; and (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.

CenterPoint recommended modifying §25.205(d) to specify that the applicants must include direct testimony supporting the application, the status of the large load customer's request for interconnection with an interconnecting utility, and the identification of the interconnecting utility for both the generation resource and the large load customer. Vistra disagreed that the proposed rule should be modified to require direct testimony be filed with the application. According to Vistra, requiring testimony would serve only to add regulatory burden to the applicant and delay the filing of an application, which directly contravenes express legislative intent "not to slow down large load projects that are currently in the works." Moreover, Vistra asserted that the commission's approval, denial, or conditional approval of an application is to hinge on its evaluation of the impact of the arrangement on system reliability after it considers ERCOT's evaluation of system reliability impacts. Thus, it is the technical evaluation of system reliability impacts, not applicant testimony, that is critical to the commission's decision-making.

TPPA recommended modifying proposed §25.205(d)(2) to require the applicants serve copies of the application on ERCOT, the transmission utility certificated to serve the area and the distribution utility certificated to serve the area (if different from the TSP).

Commission Response

The commission adopts CenterPoint's recommendation to modify adopted §25.205(d) to specify that the application must include direct testimony supporting the application. Requiring that direct testimony be filed with the application clarifies that the burden of proof resides with the applicants, who are the parties seeking relief from the commission. This also aligns the timeline for filing direct testimony with other contested case proceedings in which applicants present their direct case by filing direct testimony with their application.

The commission disagrees with Vistra that requiring direct testimony contravenes the legislative intent. The commission's approval, with or without conditions, or denial of an application must be based on evidence that supports the commission's findings of fact and conclusions of law. The applicants' direct testimony provides the evidentiary basis for the underlying information that ERCOT is relying upon for its study of the system impacts of the net metering arrangement. Therefore, the applicants must file direct testimony supporting their application, including the underlying information that was provided to ERCOT for its study of the system impacts of the net metering arrangement.

The commission declines to adopt CenterPoint's recommendation to modify adopted §25.205(d) to specify that the application must identify the status of the large load customer's request for interconnection. However, the commission modifies adopted §25.205(d) to specify that the application must include a completed large load interconnection study as the term is defined in ERCOT protocols as of the date the application is filed with the commission or a study report from another completed study process to interconnect a large load customer that is required by ERCOT protocols as of the date the application is filed with the commission.

The commission declines to adopt CenterPoint's recommendation to modify adopted §25.205(d)(2) to specify that the application must identify the electric utility, municipally owned utility, or electric cooperative responsible for interconnecting the large load customer, responsible for interconnecting the generation resource, and responsible for retail delivery service at the location of the net metering arrangement. Instead, the commission modifies adopted §25.205(d)(2) to specify that the application must identify the interconnecting TSP and the interconnecting DSP.

The commission declines to adopt TPPA's recommendation to modify adopted §25.205(d)(2) to require the applicants to serve copies of the application on ERCOT, the transmission utility certificated to serve the area, and the distribution utility certificated to serve the area (if different than the TSP). However, the commission modifies adopted §25.205(d)(2) to require the applicants to serve copies of the application on ERCOT, the interconnecting TSP, and if different from the interconnecting TSP, the interconnecting DSP.

Proposed §25.205(e) - Parties to a proceeding under this section

Proposed §25.205(e) limits the parties to a proceeding under the proposed rule to the applicants; commission staff; ERCOT; and the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility.

CenterPoint recommended modifying proposed §25.205(e) to clarify that in situations where one utility is interconnected with an existing generation resource, and a different utility is responsible for the interconnection of the co-located large load customer, both interconnecting utilities should be granted party status in a net metering arrangement proceeding involving that generation resource and large load customer, since both may be affected.

TEC recommended modifying proposed §25.205(e) to permit the parties to a net metering arrangement to participate in the proceeding. Additionally, TEC recommended modifying proposed §25.205(e) to add a new subsection expanding the listed parties permitted to participate in the proceeding to an electric cooperative or a municipally owned utility certificated to interconnect or provide retail electric utility service at the location of the net metering arrangement. Finally, TEC recommended modifying proposed §25.205(e) to authorize the parties to the proceeding to file a notice regarding whether the party intends to participate in the proceeding.

Crusoe recommended modifying proposed (e)(1) to separately identify the DSP and the interconnecting TSP.

TIEC recommended modifying proposed §25.205(e)(1)(D) to specify that the interconnecting electric cooperative, transmission distribution utility, and/or municipally owned utility providing retail electric delivery service to the large load customer or transmission service to the existing generator is a party to the proceeding. Additionally, Crusoe and TIEC recommended modifying proposed §25.205(e)(2) to include a statement that a party to the proceeding shall only take positions on issues that it would otherwise have direct standing to pursue.

TPPA recommended modifying proposed §25.205(e)(1) to conform with its recommended changes to proposed §25.205(d)(2) by limiting the parties to the applicants, commission staff, ERCOT, the transmission utility service provider certificated to serve the area, and the DSP certificated to serve the area (if different than the TSP).

Commission Response

The commission adopts TEC, Crusoe, and TIEC's recommendation to separately identify that the interconnecting TSP and the interconnecting DSP (if different from the interconnecting TSP) are both parties to the proceeding. This approach also addresses CenterPoint's recommendation to clarify that in situations where one utility is interconnected with an existing generation resource and a different utility is responsible for the interconnection of the co-located large load customer, both interconnecting utilities should be granted party status. The commission modifies adopted §25.205(e) accordingly. The commission adopts TEC's recommendation to modify adopted §25.205(e) to authorize a party to the proceeding to file notice identifying whether the party intends to participate in the proceeding. Accordingly, the commission adds adopted §25.205(e)(3).

The commission declines to adopt TEC's recommendation to modify adopted §25.205(e) to specify that the parties to a net metering arrangement are parties to the proceeding because it is unnecessary. The parties to a net metering arrangement are the applicants and adopted §25.205(e) specifies that the applicants are parties to the proceeding. The commission declines to adopt Crusoe and TIEC's recommendation to modify adopted §25.205(e)(2) to include a statement that a party to the proceeding shall only take positions on issues that it would otherwise have direct standing to pursue. A party either has standing to participate in a proceeding, or the party does not have standing to participate. It is not appropriate to impose limitations that exceed the statute.

Proposed §25.205(g) - Commencement of ERCOT study.

Proposed §25.205(g) sets forth the requirements for ERCOT to commence its study. Proposed §25.205(g)(1) requires the parties to a net metering arrangement to provide ERCOT all information that ERCOT deems necessary regarding the net metering arrangement. Proposed §25.205(g)(2) requires the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility to submit to ERCOT a large load interconnection study, the results of power flow modeling, and any other information that ERCOT deems necessary. Proposed §25.502(g)(3) requires ERCOT, upon receipt of all necessary information, to conduct a study of the system impacts of the net metering arrangement, including transmission security and resource adequacy impacts, and stranded or underutilized transmission assets associated with the net metering arrangement. Finally, proposed §25.205(g)(4) requires ERCOT to provide commission staff any access, information, support, or cooperation that commission staff determines is necessary to provide its recommendations.

A large load interconnection study may not always be conducted

CenterPoint recommended modifying proposed §25.205(g) to reflect that a large load interconnection study may not always be conducted by the interconnecting utility. CenterPoint noted that a large load customer co-located with an existing generation resource can elect to interconnect directly to a PUN and forego an interconnection request with the electric utility that serves the area in which the PUN is located.

Commission Response

The commission adopts CenterPoint's recommendation to modify adopted §25.205(g) to reflect that a large load interconnection study may not always be conducted by the interconnecting utility. However, the commission modifies adopted §25.205(g) to reflect that a large load customer must have completed the studies required by ERCOT protocols.

Notice to the parties to a net metering arrangement and the interconnecting utility that all information is received

Eolian recommended modifying proposed §25.205(g) to clarify ERCOT's procedural obligations by requiring ERCOT to notify both the parties to the net metering arrangement and the interconnecting utility once it determines that all necessary study information has been received and deemed complete.

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(g) to clarify ERCOT's procedural obligations by requiring ERCOT to notify both the parties to the net metering arrangement and the interconnecting utility once it determines that all necessary study information has been received and deemed complete because it is unnecessary. Adopted §25.205(g)(3) already requires ERCOT, not later than seven days after commencing its study, to file notice in the docket indicating the date that ERCOT commenced its study and the date ERCOT must file its study results and recommendations. The commission notes that the contested case proceeding is like any other contested case proceeding docketed at the commission in that the commission has specific procedural rules that control service of pleadings and other documents. Restating those requirements in the adopted rule is not necessary.

Coordination with TSP and evaluation on a net-impact basis

Eolian recommended adding a new paragraph that requires ERCOT to coordinate its analysis with the TSP and evaluate both facilities on a net-impact basis through a unified interconnection study. Eolian reasoned that this coordinated study requirement prevents double counting of imports and exports, aligns with ERCOT Planning Guide §5 and §9, and implements PURA §37.0561(b) and PURA §39.151 by promoting nondiscriminatory, reliability-based evaluation of integrated projects.

Commission Response

The commission declines to adopt Eolian's recommendation to require ERCOT to coordinate its analysis with the TSP because it is unnecessary. ERCOT has processes and procedures in place that already involve coordination with TSPs. Additionally, ERCOT is specifically involved in scoping the large load interconnection study that a TSP conducts.

Deadline to complete large load interconnection studies

Calpine recommended modifying proposed §25.205(g) to impose a deadline for TDSPs to complete large load interconnection studies.

Commission Response

The commission declines to adopt Calpine's recommendation to modify adopted §25.205(g) to impose a deadline for TDSPs to complete large load interconnection studies because it is unnecessary. ERCOT is currently developing a batch study process to improve efficiencies related to the large load interconnection studies.

Delineate the information that parties must provide to ERCOT

TCPA recommended modifying proposed §25.205(g)(1) to include specific language delineating the information that parties must provide ERCOT to ensure full transparency and defined criteria upfront for parties to use as a checklist when compiling their application. Specifically, TCPA recommended requiring (1) project information including name, county, point of interconnection, voltage, demand and coordinates; (2) anticipated peak demand; (3) customer, TSP, TDSP, and LSE contact information; (4) anticipated net-metered load details; and (5) anticipated curtailment and back-up generation capabilities.

Commission Response

The commission declines to adopt TCPA's recommendation to modify §25.205(g)(1) to include specific language delineating the information that parties must provide ERCOT. The commission expects ERCOT, who has the technical expertise to conduct the study, to develop this information and publish it in a transparent manner without the need to require such action through the adopted rule.

Replace "all information that ERCOT deems necessary" with "all necessary information"

TSSA recommended modifying proposed §25.205(g)(1) to state that the parties to a net metering arrangement must provide ERCOT all necessary information instead of all information that ERCOT deems necessary. TSSA reasoned that in the unlikely event that ERCOT were to request information that was perhaps desirable but not strictly necessary or to request information in a form that was unavailable, then the parties to the net metering arrangement should have the right to petition the commission to resolve the issue. The determination of what information is necessary should not rest solely with ERCOT.

Commission Response

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(g)(1) to state that the parties to a net metering arrangement must provide ERCOT all necessary information instead of all information that ERCOT deems necessary. The commission expects ERCOT to work in collaboration with the parties to a net metering arrangement, as well as the interconnecting TSP and the interconnecting DSP. In light of the short timeframe and the technical requirements for the study, the commission determines that it is appropriate for ERCOT to receive all information that it deems necessary. Moreover, this approach is consistent with PURA §39.169(d), which states that ERCOT must study the system impacts of a net metering arrangement after ERCOT receives all information regarding the arrangement required by ERCOT.

Remove requirement for interconnecting utility to submit a large load interconnection study to ERCOT

ERCOT recommended modifying proposed §25.205(g) to remove proposed §25.205(g)(2)(A), which requires the interconnecting utility to submit a large load interconnection study to ERCOT, and modifying proposed §25.205(g)(3) to provide that ERCOT's obligation to conduct the study only ripens once the large load interconnection study has been completed and it has received all necessary information. ERCOT reasoned that it does not need the interconnecting utility to submit a copy of the large load interconnection study because ERCOT will already have access to the study by virtue of its duty to review and confirm completion of the study. Moreover, depending on how "interconnecting" is defined, it is possible that the interconnecting utility was not the lead TSP responsible for completing the large load interconnection study and may not have access to that study in some case. Therefore, to avoid potential confusion about whether a separate submission of that study is required by the interconnecting utility, ERCOT recommends modifying proposed §25.205(g)(2) and (3).

Commission Response

The commission declines to adopt ERCOT's recommendation to modify adopted §25.205(g)(2) to remove the requirement for the interconnecting utility to submit a large load interconnection study to ERCOT. However, the commission modifies adopted §25.205(g)(2)(A) by replacing the requirement to provide a large load interconnection study with a requirement to provide all transmission security analysis studies, which are to be prescribed during ERCOT's large load interconnection study process. The commission adopts ERCOT's recommendation to modify adopted §25.205(g)(3) to provide that ERCOT's obligation to conduct the study only ripens once the large load interconnection study has been completed and ERCOT has received all necessary information.

Limit the circumstances for requiring power flow modeling

Calpine recommended modifying proposed §25.205(g)(2) to require ERCOT to include power flow modeling in its study only if the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility asserts that stranded or underutilized transmission assets will result from the arrangement.

Commission Response

The commission declines to adopt Calpine's recommendation to modify adopted §25.205(g)(2) to require ERCOT to include power flow modeling in its study only if the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility asserts that stranded or underutilized transmission assets will result from the arrangement. PURA §39.169 limits the time by which ERCOT must complete its study of a net metering arrangement to 120 days and limits the time by which the commission must issue a decision approving a net metering arrangement, with or without conditions, or denying a net metering arrangement to 60 days. This expedited timeframe requires that all the necessary analysis be completed at the outset. Therefore, it is appropriate for ERCOT to study whether conditions are appropriate as part of its overall analysis. Additionally, PURA §39.169 does not limit the circumstances that the commission may impose a condition holding customers harmless. Accordingly, the commission declines to limit the study of stranded or underutilized transmission assets based on whether ERCOT recommends other conditions.

Remove requirement to provide any other information that ERCOT deems necessary

TCPA recommended modifying proposed §25.205(g)(2) to remove proposed §25.205(g)(2)(C) because it is duplicative and unnecessarily expansive in scope. TCPA reasoned that the information deemed necessary should be fixed and objective. Inclusion of proposed §25.205(g)(2)(C) would make the study scope subject to ERCOT discretionary expansion.

Commission Response

The commission declines to adopt TCPA's recommendation to modify adopted §25.205(g)(2) to remove the requirement to provide any other information that ERCOT deems necessary. PURA §39.169 limits the time by which ERCOT must complete its study of a net metering arrangement to 120 days and limits the time by which the commission must issue a decision approving a net metering arrangement, with or without conditions, or denying a net metering arrangement to 60 days. This expedited timeframe requires that all the necessary analysis be completed at the outset and that ERCOT have all the information that it deems necessary to be able to conduct the study, which requires technical expertise. Thus, the commission concludes that it is appropriate for ERCOT to determine what information is necessary. This approach is also consistent with PURA §39.169(d), which states that ERCOT must study the system impacts of a net metering arrangement after ERCOT receives all information regarding the arrangement required by ERCOT.

Specify the statutory timeline for ERCOT and the commission to adjudicate the contested case

TCPA recommended adding a new subsection that specifies the timeline allotted in statute for both ERCOT and the commission to adjudicate cases under PURA §39.169 and requires ERCOT to issue a notice of sufficiency. Additionally, TCPA recommended that if ERCOT is lacking any information from any of the parties required to submit information to ERCOT, the specific information that is lacking should be identified and the parties should be afforded seven business days to remedy the insufficiency.

Commission Response

The commission declines to adopt TCPA's recommendation to add a new subsection that specifies the timeline allotted in statute for both ERCOT and the commission to adjudicate cases under PURA §39.169 and requires ERCOT to issue a notice of sufficiency because it is unnecessary. The statutory deadlines apply regardless of whether they are restated in the adopted rule. Additionally, adopted §25.205(g)(3) already requires ERCOT to commence its study upon receiving all necessary information and to file, not later than seven days after commencing its study, notice in the docket indicating the date that ERCOT commenced its study and the date ERCOT must file its study results and recommendations. The commission also declines to modify the adopted rule to require ERCOT to afford parties to a net metering arrangement seven business days to remedy a deficiency in the information submitted because it is unnecessary. Moreover, a different deadline may be appropriate based on the nature of the deficient information. However, the commission expects ERCOT to work with the parties to a net metering arrangement to expeditiously and efficiently resolve issues, and to develop standardized processes and procedures for resolving issues.

Remove or limit the requirement for ERCOT to study stranded or underutilized transmission assets

Calpine, TCPA, and Vistra recommended modifying proposed §25.205(g)(3) to remove the requirement for ERCOT to include in its study, stranded or underutilized transmission assets associated with the net metering arrangement. Calpine reasoned that holding customers harmless for stranded or underutilized transmission assets resulting from a net metering arrangement will only be relevant on a case-by-case basis and to the extent a party to the net metering arrangement affirmatively raises the issue. Vistra reasoned that only if the approval of a net metering arrangement is conditioned is the hold-harmless provision potentially triggered and even then the commission has discretion on whether to impose the hold harmless condition. Vistra recommended conforming changes to proposed §25.205(h) by removing proposed §25.205(h)(3) and conforming changes to proposed §25.205(i)(3)(F) to require ERCOT's complete study to detail whether any transmission assets may be stranded or underutilized, including the identity of the associated TSPs, if ERCOT recommends any conditions under paragraph (2)(F).

TSSA recommended modifying proposed §25.205(g)(3) to limit ERCOT's study of stranded or underutilized transmission assets to those that are necessary to maintain system reliability. TSSA reasoned that PURA §39.169(d) limits ERCOT's study to an evaluation of "system impacts" and narrows the scope of the commission's power "to approve, deny, or impose reasonable conditions on the proposed net metering arrangement only as necessary to maintain system reliability, including transmission security and resource adequacy impact."

Commission Response

The commission declines to adopt Calpine, TCPA, and Vistra's recommendation to modify adopted §25.205(g)(3) to remove the requirement for ERCOT to include in its study, stranded or underutilized transmission assets associated with the net metering arrangement. PURA §39.169 limits the time by which ERCOT must complete its study of a net metering arrangement to 120 days and limits the time by which the commission must issue a decision approving a net metering arrangement, with or without conditions, or denying a net metering arrangement to 60 days. This expedited timeframe requires that all the necessary analysis be completed at the outset. Therefore, it is appropriate for ERCOT to study whether conditions are appropriate as part of its overall analysis. Additionally, PURA §39.169 does not limit the circumstances that the commission may impose a condition holding customers harmless. Therefore, the commission also declines to adopt TSSA's recommendation to limit ERCOT's study of stranded or underutilized transmission assets to those that are necessary to maintain system reliability.

Avoid duplicative study

Satoshi recommended modifying proposed §25.205(g)(3) to clarify that any subsequent study conducted by ERCOT must not duplicate the analyses already performed as part of the large load interconnection study.

Commission Response

The commission agrees that duplicative work is not necessary. However, the commission declines to adopt Satoshi's recommendation to modify adopted §25.205(g)(3) to clarify that any subsequent study by ERCOT must not duplicate the analyses already performed as part of the large load interconnection study because it is unnecessary. Moreover, the batch study process that ERCOT is currently developing is likely to change the workflows associated with the large load interconnection study.

Proposed §25.205(h) - General requirements of ERCOT study

Proposed §25.205(h) sets forth the general requirements for the study that ERCOT must conduct. Proposed §25.205(h)(2) requires a transmission security analysis that is comprised of a steady state and stability load serving study with and without the generation, under peak scenarios and off-peak scenarios. Proposed §25.205(h)(3) requires ERCOT to conduct an analysis identifying transmission assets that may become stranded or underutilized as a result of the net metering arrangement, including the identity of the TSP associated with each such asset and the degree to which any transmission assets are expected to be underutilized from both a delivery and reliability perspective. Proposed §25.205(h)(4) requires ERCOT to conduct any other analysis or study that ERCOT determines is necessary.

Limit to system impacts

Eolian recommended modifying proposed §25.205(h) to clarify that ERCOT's statutory study obligation is limited to system impacts related to transmission reliability, system reliability, and stranded or underutilized transmission assets, and does not extend to system-wide resource adequacy modeling. Eolian reasoned that this distinction reflects the plain language of PURA §39.169(d), which directs ERCOT to study "system impacts" and "removal of generation," not to perform statewide resource adequacy forecasts. Eolian also recommended modifying proposed §25.205(i) to conform with its recommended modifications to proposed §25.205(h).

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(h) to clarify that ERCOT's statutory study obligation is limited to system impacts related to transmission reliability, system reliability, and stranded or underutilized transmission assets, and does not extend to system-wide resource adequacy modeling because the commission disagrees with Eolian's interpretation of PURA §39.169. PURA §39.169(d) states the commission must 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. Moreover, the commission's approval, denial, or imposition of conditions is predicated on ERCOT's study of the system impacts of the net metering arrangement. Thus, the statute contemplates that ERCOT's study of the system impacts includes resource adequacy impacts.

Specify the evaluation is based on expectations and remove the requirement to evaluate impacts of reduced net capability or lower availability on reserve margins

TCPA and Vistra recommended modifying proposed §25.205(h)(1) to specify "expected" curtailment capability, on-site backup generating capability, availability, and impacts on reserve margins or other resource adequacy criteria. TCPA and Vistra also recommended modifying proposed §25.205(h)(1)(E) to remove "of reduced net capability or lower availability" and to replace "other reliability criteria" with "other resource adequacy criteria." and to replace "other reliability criteria" with "other resource adequacy criteria."

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(h)(1) to specify "expected" curtailment capability, on-site backup generating capability, availability, and impacts on reserve margins or other resource adequacy criteria because the qualifier is not appropriate in this context. Curtailment capability, on-site backup generating capability, availability, and impacts on reserve margins or other resource adequacy criteria should be known and based on objective information provided in the evidentiary record as part of the application for approval of the net metering arrangement. This information should not be speculative. The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(h)(1)(E) to remove "of reduced net capability or lower availability" and to replace "other reliability criteria" with "other resource adequacy criteria." The language that TCPA and Vistra recommend removing provides clear metrics and increased transparency. Thus, the commission declines to adopt the recommended changes.

Expand the reliability metrics

Onward recommended modifying proposed §25.205(h)(1) to expand the reliability metrics to include: (1) curtailment history and forecast; (2) transmission congestion and generic transmission constraints (GTCs); (3) congestion rent paid by the existing generation resource due to GTCs; (4) transmission constraints; (5) avoided infrastructure costs; and (6) local load-to-generation ratio.

Commission Response

The commission declines to adopt Onward's recommendation to modify adopted §25.205(h)(1) to expand the reliability metrics to include: (1) curtailment history and forecast; (2) transmission congestion and GTCs; (3) congestion rent paid by the existing generation resource due to GTCs; (4) transmission constraints; (5) avoided infrastructure costs and (6) local load-to-generation ratio. ERCOT's analysis will be forward looking. Analyzing historical data to evaluate the accumulated benefits is not relevant to the impact of the netting arrangement to the future security of the grid. In addition, these metrics would significantly broaden the scope and depth of data needed for ERCOT's analysis which must be performed within 120 days.

Limit evaluation to a generation resource that makes dispatchable capacity available

TSSA recommended modifying proposed §25.205(h)(1) to specifically require an evaluation of a generation resource that makes dispatchable capacity available to the ERCOT power region.

Commission Response

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(h)(1) to specifically require an evaluation of a generation resource that makes dispatchable capacity available to the ERCOT power region because this change would exclude intermittent generation resources from the evaluation. PURA §39.169(d)(2) states that the commission may impose a condition that requires a generation resource to make capacity available to the ERCOT power region during certain events. Therefore, the commission determines that ERCOT's resource adequacy analysis should equally apply to dispatchable generation resources and intermittent generation resources. This approach will ensure that the commission has the necessary information to evaluate whether it should exercise its discretionary authority to require that an intermittent generation resource make capacity available during certain events by curtailing load or imposing operational conditions during certain events.

Minimize duplicative work

ERCOT recommended modifying proposed §25.205(h)(2) to state that ERCOT may adopt the applicable large load interconnection study in part or in whole, to the extent ERCOT deems appropriate. Relatedly, LCRA recommended that the ERCOT study should seek to minimize duplication of work.

Satoshi recommended modifying proposed §25.205(h)(2) consistent with its recommendation to modify proposed §25.205(g)(3) to clarify that any subsequent study conducted by ERCOT must not duplicate the analyses already performed as part of the large load interconnection study.

Commission Response

The commission agrees that duplicative work is not necessary. However, the commission declines to adopt ERCOT, LCRA, and Satoshi's recommendation to modify adopted §25.205(h)(2) to clarify that ERCOT may adopt, in whole or in part, the large load interconnection study conducted by a TSP because it is unnecessary. Instead, the commission modifies adopted §25.205(h)(2) to require ERCOT's study to include a transmission security analysis that is comprised of a steady state and stability load serving study with and without the generation, under peak scenarios and off-peak scenarios, including review of a completed interconnection study.

Conforming change to limit study of underutilized or stranded transmission assets to those that are necessary to maintain system reliability

Consistent with its recommended changes to proposed §25.205(g), TSSA recommended conforming changes to proposed §25.205(h)(3), limiting ERCOT's study of underutilized or stranded transmission assets to those that are necessary to maintain system reliability. Additionally, TSSA recommended modifying proposed §25.205(h)(3) to remove "and the degree to which any transmission assets are expected to be underutilized from both a delivery and a reliability perspective." TSSA reasoned that the "delivery" component departs from the plain text of PURA §39.169(d) and denotes a capacity obligation.

Commission Response

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(h)(3) to conform with its recommended change to adopted §25.205(g) to limit ERCOT's study of underutilized or stranded transmission assets to those that are necessary to maintain system reliability because the commission declines to adopt TSSA's recommendation to modify adopted §25.205(g). Therefore, the conforming change is unnecessary.

Remove the requirement for an analysis identifying transmission assets that may become stranded or underutilized

Calpine and TCPA recommended removing proposed §25.205(h)(3) from the proposed rule because the proposed analysis for identifying stranded or underutilized transmission assets is not a requirement under PURA §39.169(d) and the condition to hold customers harmless for stranded or underutilized transmission assets is not applicable to all proposed net metering arrangements.

Commission Response

The commission declines to adopt Calpine and TCPA's recommendation to remove adopted §25.205(h)(3), which requires an analysis identifying transmission assets that may become stranded or underutilized as a result of the net metering arrangement. Although holding customers harmless for stranded or underutilized transmission assets is not a required condition, PURA §39.169(d)(1) explicitly identifies it as a discretionary condition. The commission cannot evaluate the appropriateness of the condition without an analysis identifying whether transmission assets may become stranded or underutilized and in light of the 60-day deadline for the commission to issue a decision, it is appropriate for this analysis to be included as a necessary part of ERCOT's study.

Narrowly tailor other analysis or study to address gaps in the large load interconnection study

Calpine recommended modifying proposed §25.205(h)(4) to state that ERCOT must conduct any other analysis or study that ERCOT determines is necessary to address gaps in the large load interconnection study received from the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility. Calpine reasoned narrowly tailoring proposed §25.205(h)(4) ensures clear expectations to facilitate effective and timely processing of applications for net metering arrangements.

Commission Response

The commission declines to adopt Calpine's recommendation to modify adopted §25.205(h)(4) to state that ERCOT must conduct any other analysis or study that ERCOT determines is necessary to address gaps in the large load interconnection study. In light of the technical nature of the study, the commission determines that it is appropriate for ERCOT to exercise its technical expertise in determining what analysis or study is necessary to identify the system impacts of a net metering arrangement, including transmission security and resource adequacy impacts, and whether transmission assets are stranded or underutilized.

Remove the requirement for any other analysis or study that ERCOT determines is necessary

TCPA and Vistra recommended removing proposed §25.205(h)(4) from the proposed rule to conform with their recommended changes to proposed §25.205(g).

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to remove the requirement for any other analysis or study that ERCOT determines is necessary. In light of the technical nature of the study, the commission determines that it is appropriate for ERCOT to exercise its technical expertise in determining what analysis or study is necessary to identify the system impacts of a net metering arrangement, including transmission security and resource adequacy impacts, and whether transmission assets are stranded or underutilized.

Require ERCOT to study whether and to what degree GTCs are alleviated or eliminated

Onward recommended modifying proposed §25.205(h)(4) to require ERCOT to study whether, and to what degree, a proposed net metering arrangement alleviates or eliminates existing GTCs or enables stranded generation resources to deliver more power to the broader ERCOT grid. Specifically, Onward recommended that the additional analysis includes: (1) historical congestion rent paid by the existing power generation resource over the past three years; (2) the number of GTCs restricting power generation outflow; and (3) the likelihood of congestion relief due to planned transmission upgrades.

Commission Response

The commission declines to adopt Onward's recommendation to modify adopted §25.205(h)(4) to require ERCOT to study whether, and to what degree, a proposed net metering arrangement alleviates or eliminates existing GTCs or enables stranded generation resources to deliver more power to the broader ERCOT grid. ERCOT's analysis will be forward looking. Historical data is not relevant to analysis evaluating whether transmission assets will be stranded or underutilized in the future. In addition, this analysis may significantly broaden the scope and depth of data and time required for ERCOT's assessment which must be done within 120 days.

Proposed §25.205(i) - ERCOT study results

Proposed §25.205(i) requires ERCOT, not later than ten days before filing its study results and recommendations, to file notice in the docket indicating the date that ERCOT expects to file its study results and recommendations. Proposed §25.205(i) also sets forth the specific information that must be included with ERCOT's study results and recommendations.

Remove requirement to file notice indicating the date ERCOT expects to file its study results and recommendations

Calpine and TCPA recommended modifying proposed §25.205(i) to remove the requirement for ERCOT to file notice in the docket indicating the date that ERCOT expects to file its study results and recommendations. Calpine reasoned that timelines could change and ERCOT should have as much flexibility as is needed within their 120-day review period to conduct the required analysis. TCPA reasoned that the additional notice is unnecessary and could give the appearance of adding time to the 120-day required. Thus, creating the potential for confusion.

Commission Response

The commission declines to adopt Calpine and TCPA's recommendation to modify adopted §25.205(i) to remove the requirement for ERCOT to file notice in the docket indicating the date that ERCOT expects to file its study results and recommendations. Because the commission must issue its decision not later than 60 days after ERCOT files its study results and recommendations, it is imperative that the commission have notice of when the study results and recommendations will be filed so that the commission can ensure that a hearing on the merits can be scheduled, if requested by a party to the proceeding.

Protect competitively sensitive and confidential information

Vistra recommended modifying proposed §25.205(i) to require ERCOT to follow the Legislature's directive and ensure that its filings do not disclose information that is competitively sensitive or otherwise considered confidential.

Commission Response

The commission declines to adopt Vistra's recommendation to modify adopted §25.205(i) to ensure that ERCOT's filings do not disclose information that is competitively sensitive or otherwise considered confidential because it is unnecessary. The commission's procedural rules already protect against disclosure of competitively sensitive and confidential information.

Include stranded or underutilized transmission assets in the executive summary

CenterPoint recommended modifying proposed §25.205(i)(2) to require ERCOT to identify, in its executive summary of the study results and recommendations, potentially stranded or underutilized transmission assets and conditions to mitigate the potential of stranded or underutilized transmission assets.

Commission Response

The commission declines to adopt CenterPoint's recommendation to modify adopted §25.205(i)(2) to require ERCOT to identify, in its executive summary of the study results and recommendations, potentially stranded or underutilized transmission assets and conditions to mitigate the potential of stranded or underutilized transmission assets because it is unnecessary.

Remove requirement for ERCOT to include certain information in its filing related to its study results and recommendations

TCPA recommended modifying proposed §25.205(i)(2) to remove proposed §25.205(i)(2)(A) through (C) because these requirements are not required by statute. TCPA noted that regulatory policy tends to protect the identity of customers, particularly in competitive markets. Moreover, PURA §39.169 applies to only new interconnections, not expansions. Additionally, if another customer is already at the location site, then, by definition, this is not a stand-alone generator and PURA §39.169 does not apply.

Vistra recommended modifying proposed §25.205(i)(2)(B) and (C) because these provisions are superfluous since PURA §39.169 is limited to new interconnections.

Commission Response

The commission declines to adopt TCPA's recommendation to modify adopted §25.205(i)(2) to remove the requirements for ERCOT to identify in its executive summary the large load customer. The commission also declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(i)(2) to remove the requirements for ERCOT to identify in its executive summary whether the large load customer seeks a new or expanded interconnection and whether the large load customer or any other customer is already located at the requested interconnection site. As stated above, PURA §39.169(a) specifically cites to the description for a large load customer in PURA §37.0561(c). PURA §37.0561(c) describes a large load customer as a customer requesting 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. PURA §37.0561(c) also states the commission must establish a demand threshold of 75 MW unless the commission determines that a lower threshold is necessary to accomplish the purposes described by PURA §37.0561(b). Thus, the commission determines that a new large load customer as described by PURA §37.0561(c) encompasses the full description in PURA §37.0561, including a customer requesting expanded interconnection that would result in the total load at a single site exceeding 75 MW.

Replace the 10-year lookback

TEC recommended modifying proposed §25.205(i)(3)(D) to reduce the 10-year lookback to a five-year lookback.

CenterPoint recommended modifying proposed §25.205(i)(3)(D) to require an existing generation resource that must make dispatchable capacity available to make available the highest amount of capacity that was available over the 10-year period instead of the same amount.

ERCOT recommended modifying proposed §25.205(i)(3)(D) to remove the requirement to consider historical peak capacity availability over the past ten years because a generation resource could only reasonably be required to provide its maximum possible physical output at the time that ERCOT may need to call on the resource to address an emergency condition. Additionally, ERCOT noted that if its recommended interpretation of "make available" is adopted, requiring that the large load customer be curtailed, then proposed §25.203(i)(3)(D) is unnecessary.

OPUC recommended modifying proposed §25.205(i)(3)(D) to replace use of the amount of generation produced at the time of annual system peak demand averaged over the past ten years with use of the historical annual maximum generation produced by the existing generator averaged over a set number of years to determine the amount of dispatchable capacity to be made available.

Vistra recommended modifying proposed §25.205(i)(3)(D) to determine the dispatchable capacity that was made available to ERCOT before the net metering arrangement based on the most recent Summer Seasonal Net Maximum Sustainable Rating of dispatchable capacity instead of basing it on the dispatchable capacity made available to the ERCOT region at the time of annual peak demand each of the last 10 years. Vistra reasoned that the Seasonal Net Maximum Sustainable Ratings are calibrated to standard ambient air temperatures for the respective weather zones, which eliminates the impact of year-to-year fluctuations in peak load conditions.

Commission Response

The commission declines to adopt TEC's recommendation to reduce the 10-year lookback to a 5-year lookback and the commission declines to adopt OPUC's recommendation to replace use of the amount of generation produced at the time of annual system peak demand averaged over the past ten years with use of the historical annual maximum generation produced by the existing generator averaged over a set number of years to determine the amount of dispatchable capacity to be made available. The commission agrees with ERCOT that the requirement to consider historical peak capacity availability over the past ten years should be removed. The commission replaces the requirement with Vistra's recommendation to determine an existing generation resource's capacity based on its seasonal net maximum sustainable rating. However, the commission declines to adopt Vistra's recommendation to use the summer seasonal net maximum sustainable rating of dispatchable capacity. ERCOT needs accurate information on the capability of the unit depending on the season that the emergency may occur. Reporting seasonal net max sustainable ratings is required in the resource registration process and is used by ERCOT for planning purposes, as well as base case development and operational needs. The steady state working group manual and Planning guide both reference this data. This rating is preferred because it represents the net, sustained MW capability of a unit under seasonal ambient conditions, aligning with a more realistic capability. Additionally, these ratings can be updated and eliminate year-to-year fluctuations.

Remove certain requirements for ERCOT's filing relating to its study results and recommendations

TSSA recommended modifying proposed §25.205(i)(3) to remove proposed §25.205(i)(3)(D) and (F) because these provisions are redundant to provisions set forth in proposed §25.205(h). If TSSA's primary recommendation to remove proposed §25.205(i)(3)(D) and (F) is not adopted, then TSSA recommended, in the alternative, that the commission make conforming changes consistent with TSSA's recommendations to proposed §25.205(g) and (h).

Commission Response

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(i)(3) to remove the requirement for ERCOT's filing relating to its study results and recommendations to include the capacity made available to the ERCOT region before implementation of the net metering arrangement and the requirement to include whether any transmission assets are stranded or underutilized. Having this information clearly identified in the executive summary, as well as having a more detailed description in ERCOT's study results, is helpful to the commission in its evaluation of a net metering arrangement particularly because of the short time frame that applies to a proceeding under PURA §39.169.

Require analysis of stranded or underutilized transmission assets only if conditions are recommended

TCPA and Vistra recommended modifying proposed §25.205(i)(3)(F) to specify that if conditions are recommended, then ERCOT's study results must detail whether any transmission assets may be stranded or underutilized, including the degree to which any underutilized transmission assets could be underutilized from a delivery or a reliability perspective. TCPA reasoned that ERCOT's study should not evaluate potential stranded or underutilized transmission assets unless conditions are warranted due to resource adequacy concerns.

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(i)(3)(F) to specify that if conditions are recommended, then ERCOT's study results must detail whether any transmission assets may be stranded or underutilized, including the degree to which any underutilized transmission assets could be underutilized from a delivery or reliability perspective. The commission's authority to impose conditions is not derived from nor is it dependent on ERCOT's recommendations. Moreover, PURA §39.169 limits the time by which ERCOT must complete its study of a net metering arrangement to 120 days and limits the time by which the commission must issue a decision approving a net metering arrangement, with or without conditions, or denying a net metering arrangement to 60 days. This expedited timeframe requires that all the necessary analysis be completed at the outset. Therefore, it is appropriate for ERCOT to study whether conditions are appropriate as part of its overall analysis. Additionally, PURA §39.169 does not limit the circumstances that the commission may impose a condition holding customers harmless. Accordingly, the commission declines to limit the study of stranded or underutilized transmission assets based on whether ERCOT recommends other conditions.

Proposed §25.205(j) - Procedural schedule

Proposed §25.205(j) sets forth the requirements for a procedural schedule to process an application for approval of a net metering arrangement once ERCOT completes its study results and recommendations. Proposed §25.205(j)(1)(B) states that the deadline for ERCOT and the interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility to file a statement of position, direct testimony, or an objection to the net metering arrangement is ten days after ERCOT files its study results and recommendations. Proposed §25.205(j)(1)(F) states that if no hearing on the merits is requested, the deadline to file a stipulation or agreement, a joint motion to admit evidence, and a joint proposed order is 24 days after ERCOT files its study results and recommendations.

Authorize parties to agree to a different procedural schedule

TCPA recommended modifying proposed §25.205(j) to state that the procedural schedule must be substantially similar unless otherwise agreed to by the parties. TCPA reasoned that if the parties agree to a different procedural schedule that complies with the statutory timeline, then the procedural schedule that the parties agree to should be adopted.

Commission Response

The commission declines to adopt TCPA's recommendation to modify adopted §25.205(j) to state that the procedural schedule must be substantially similar unless otherwise agreed to by the parties. The procedural schedule must be substantially similar to ensure that the commission is able to process the net metering arrangement as a contested case within the timeframe set forth in PURA §39.169 and the requirements of Chapter 2001 of the Texas Government Code. Moreover, requiring substantial compliance ensures that the commission has sufficient time to issue a decision in the proceeding and that the parties do not agree to a procedural schedule that results in the application being considered approved without a commission determination.

Apply the 10-day deadline to all parties

AEP recommended modifying proposed §25.205(j)(1)(B) to set the deadline for parties to file statements of position, direct testimony, or an objection to the net metering arrangement so that the deadline applies to any party admitted to the proceeding, including the electric cooperative, transmission and distribution utility, or municipally owned utility that provides electric service at the location of the new net metering arrangement.

Commission Response

The commission declines to adopt AEP's recommendation to modify adopted §25.205(j)(1)(B) to set the deadline for parties to file statements of position, direct testimony, or an objection to the net metering arrangement so that the deadline applies to any party admitted to the proceeding. The applicants should file their direct testimony with their application. Additionally, commission staff's recommendation should take into consideration the other parties' filings. Thus, the same deadline should not apply to all parties to a proceeding.

Clarify the parties that may file after ERCOT's study results and recommendations are filed

TEC recommended modifying proposed §25.205(j)(1)(B) to replace the reference to "interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility" with "other parties to the proceeding other than the applicants." TPPA recommended modifying proposed §25.205(j)(1)(B) to clarify that the parties entitled to file a position following ERCOT's study under proposed §25.205(j) include the transmission utility certificated to serve the area and the distribution utility certificated to serve the area.

Commission Response

The commission declines to adopt TEC's recommendation to modify adopted §25.205(j)(1)(B) to replace the reference to "interconnecting electric cooperative, transmission and distribution utility, or municipally owned utility" with "other parties to the proceeding other than the applicants." Commission staff's recommendation should take into consideration the other parties' filings. Therefore, a different timeline should apply to commission staff's filing. Moreover, identifying the specific party that the deadline applies to is more transparent. The commission adopts TPPA's recommendation to specify the parties that must comply with the 10-day deadline are the interconnecting TSP and the interconnecting DSP.

Timing to file a stipulation or agreement

Calpine recommended modifying proposed §25.205(j)(1)(F) to add language stating that nothing precludes the parties from filing a stipulation or agreement at any time prior to the deadline identified. Calpine reasoned that the additional language would clarify that the parties may file a stipulation resolving the proceeding without the need for utilizing the full 60-day process, and to clarify that the stipulation may be filed at any time after the initial application is submitted.

Commission Response

The commission declines to adopt Calpine's recommendation to modify adopted §25.205(j)(1)(F) to add language stating that nothing precludes the parties from filing a stipulation or agreement at any time prior to the deadline identified because it is unnecessary and creates the impression that a commission determination may be overridden by a stipulation or agreement. A stipulation or agreement should be filed with sufficient expediency and should be supported by evidence such that the commission may properly evaluate the stipulation or agreement and determine whether the net metering arrangement should be approved, with or without conditions, or denied.

Modify the applicability of the timelines

CenterPoint recommended modifying proposed §25.205(j) to: (1) require the applicants to file their entire direct case, including supporting testimony, concurrently when they file the application for approval of the net metering arrangement; (2) give parties an opportunity to object to the ERCOT study results and recommendations within the same 10-day deadline for responding to the applicant's initial filing; and (3) apply the 15-day deadline to ERCOT's response to objections filed to the ERCOT study results and recommendations.

Commission Response

The commission adopts CenterPoint's recommendation to modify adopted §25.205(j) to require the applicants to file their entire direct case, including supporting testimony, concurrently when they file the application for approval of the net metering arrangement. However, the commission makes this clarification in adopted §25.205(d)(1) and the commission modifies adopted §25.205(j)(1)(A) to clarify that the deadline for the applicants applies to a statement of position or supplemental direct testimony, providing the applicants the opportunity to file a statement of position or supplemental direct testimony that addresses ERCOT's study results and recommendations.

The commission declines to adopt CenterPoint's recommendation to modify adopted §25.205(j)(1)(B) to give parties an opportunity to object to the ERCOT study results and recommendations within the same 10-day deadline for responding to the applicant's initial filing. It is appropriate for the ten-day deadline to run after ERCOT files its study results and recommendations, rather than when the application is filed. This provides the interconnecting TSP and the interconnecting DSP with the opportunity to file a statement of position, direct testimony, or an objection to a net metering arrangement that addresses both the application and ERCOT's study results and recommendations. The commission also declines to adopt CenterPoint's recommendation to modify adopted §25.205(j)(1)(C) to apply the 15-day deadline to ERCOT's response to objections filed to the ERCOT study results and recommendations because objections are limited to the net metering arrangement and an additional 15 days for ERCOT to file a response after the initial party's filing instead of 15 days after ERCOT's study results and recommendations are filed does not leave sufficient time in the procedural schedule for the commission to properly evaluate the net metering arrangement and issue a decision within 60 days after ERCOT files its study results and recommendation.

Proposed §25.205(k) - Commission decision

Proposed §25.205(k) describes the conditions that the commission may impose on a net metering arrangement. Proposed §25.205(k)(1) states that if the commission approves a net metering arrangement with conditions, then the conditions imposed on the net metering arrangement must include requiring the existing generation resource to make dispatchable capacity available to the ERCOT region as directed by ERCOT in advance of an anticipated emergency condition. The dispatchable capacity made available to the ERCOT region in such an event must be at least equal to the amount of dispatchable capacity that was made available to the ERCOT region before implementation of the net metering arrangement. Proposed §25.205(k)(2) lists conditions that may be imposed on a net metering arrangement. Proposed §25.205(k)(2)(C) specifies that the conditions imposed on a net metering arrangement may include requiring initiation of a separate hold harmless proceeding for each net metering arrangement that results in stranded or underutilized transmission assets to ensure TSPs and their customers are held harmless. Proposed §25.205(k)(2)(D) specifies that the conditions imposed on a net metering arrangement may include maximum ramp rates for load curtailment. Proposed §25.205(k)(2)(E) specifies that the conditions imposed on a net metering arrangement may include any other requirement that is necessary to maintain system reliability. Proposed §25.205(k)(4) states that if the commission imposes a condition requiring a hold harmless proceeding and the TSP associated with the stranded or underutilized transmission assets was not a party to the proceeding in which the commission considered approving, with or without conditions, or denying the proposed net metering arrangement, then commission staff must provide notice to the TSP of the requirement to initiate a hold harmless proceeding.

Resolving an objection or addressing a violation of law

TEC recommended modifying proposed §25.205(k) to state that the 60-day deadline also applies to resolving an objection or addressing a violation of law.

Commission Response

The commission declines to adopt TEC's recommendation to modify adopted §25.205(k) to state that the 60-day deadline also applies to resolving an objection or addressing a violation of law because it is unnecessary.

Limit to dispatchable generation resources

CTEI, Onward, and Sierra Club recommended modifying proposed §25.205(k)(1) to limit the application of proposed §25.205(k)(1) to dispatchable generation resources, instead of all existing generation resources.

Commission Response

The commission declines to adopt CTEI, Onward, and Sierra Club's recommendation to modify adopted §25.205(k)(1) to limit its application to dispatchable generation resources, instead of all existing generation resources. However, the commission adds a definition for "dispatchable capacity" and modifies adopted §25.205(k)(1) to clarify its application to existing generation resources that made dispatchable capacity available to the ERCOT region before the net metering arrangement.

Add an implementation clause clarifying the meaning of specific terms

Eolian recommended modifying proposed §25.205(k)(1) to add a new implementation clause that clarifies the meaning of "dispatchable capacity" and "make available" under PURA §39.169(d).

Commission Response

The commission declines to adopt Eolian's recommendation to modify adopted §25.205(k)(1) to add a new implementation clause that clarifies the meaning of "dispatchable capacity" and "make available" under PURA §39.169 because it is unnecessary. Instead, the commission adds a definition for dispatchable capacity. Additionally, the commission modifies adopted §25.205(k)(3) to clarify that an existing generation resource that is required to make capacity available under a condition imposed by the commission must do so by curtailing the large load customer and injecting its power to the system to comply.

Dynamic contingency response tool

Splight recommended modifying proposed §25.205(k)(2) to include installation of a dynamic contingency response tool as part of the list of possible conditions that may be imposed on a net metering arrangement.

Commission Response

The commission declines to adopt Splight's recommendation to modify adopted §25.205(k)(2) to include installation of a dynamic contingency response tool as part of the list of possible conditions that may be imposed on a net metering arrangement because it is unnecessary. If a dynamic contingency response tool is an appropriate condition, then the adopted rule provides ERCOT with the flexibility to recommend that condition.

Clarify that a separate hold harmless proceeding may only be imposed in specific circumstances and clarify number of hold harmless proceedings

Onward recommended modifying proposed §25.205(k)(2)(C) to clarify that a separate hold harmless proceeding may only be initiated as a condition on a proposed net metering arrangement when transmission upgrades that are associated with the arrangement will not be fully utilized at the time the upgrades are made available to the broader ERCOT system. Additionally, Onward recommended clarifying whether there can only be one hold harmless proceeding per net metering arrangement or if there could be subsequent hold harmless proceedings that could result in ongoing risk to the parties in a net metering arrangement, particularly existing power generation resources in the arrangement.

Commission Response

The commission declines to adopt Onward's recommendation to modify adopted §25.205(k)(2)(C) to clarify that a separate hold harmless proceeding may only be initiated as a condition on a proposed net metering arrangement when transmission upgrades that are associated with the arrangement will not be fully utilized at the time the upgrades are made available to the broader ERCOT system because the commission disagrees with this interpretation. PURA §39.169 does not limit the circumstances that the commission may impose a condition ensuring that customers are held harmless for stranded or underutilized transmission assets.

The commission declines to adopt Onward's recommendation to modify adopted §25.205(k)(2)(C) to clarify whether there can only be one hold harmless proceeding per net metering arrangement or if there could be subsequent hold harmless proceedings that could result in ongoing risk to the parties in a net metering arrangement, particularly existing power generation resources in the arrangement. The number of hold harmless proceedings may vary depending on the specific transmission assets that are identified as stranded or underutilized and the number of TSPs that are associated with those assets.

Limit the transmission assets for which customers may be held harmless and exclude TSPs from being held harmless

TCPA and Vistra recommended modifying proposed §25.205(k)(2)(C) to more closely align with the statutory language to ensure that the rule accomplishes the overarching policy directive of system reliability and to ensure that net metering arrangements are not reviewed for reliability as a one-off decision. Specifically, TCPA and Vistra recommended inserting "for which the commission has conditioned its approval because of a necessity to maintain system reliability" after "net metering arrangement" and striking "TSPs and their." TCPA and Vistra noted that the statute only specifies customers being held harmless.

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(k)(2)(C) by inserting "for which the commission has conditioned its approval because of a necessity to maintain system reliability" after "net metering arrangement" and striking "TSPs and their." PURA §39.169 does not limit the commission's authority to impose a condition holding customers harmless based on whether the stranded or underutilized transmission assets are necessary to maintain system reliability. With respect to also holding TSPs harmless, the commission notes that customers are held harmless by ensuring that TSPs do not include the costs for stranded or underutilized transmission assets in their rates.

Limit the circumstances for a hold harmless proceeding

Calpine recommended modifying proposed §25.205(k)(2)(C) to state that initiation of a hold harmless proceeding may only be required if a party to the net metering arrangement asserted during the proceeding that the arrangement would result in stranded or underutilized transmission assets.

Commission Response

The commission declines to adopt Calpine's recommendation to modify adopted §25.205(k)(2)(C) to state that initiation of a hold harmless proceeding may only be required if a party to the net metering arrangement asserted during the proceeding that the arrangement would result in stranded or underutilized transmission assets. The commission notes that the parties to a net metering arrangement have an interest in not identifying stranded or underutilized transmission assets that result from the net metering arrangement. Therefore, requiring that the parties to a net metering arrangement assert that the arrangement would result in stranded or underutilized transmission assets in order to hold customers harmless would frustrate the purpose of the statute's requirement that the commission consider imposing a condition requiring customers be held harmless for stranded or underutilized transmission assets. The commission determines that it is within its statutory authority and obligation to serve the public interest to independently evaluate whether transmission assets are stranded or underutilized and if so, to impose a condition holding customers harmless for those transmission assets.

Remove maximum ramp rates for load curtailment from the list of conditions that the commission may impose on a net metering arrangement

Onward and TCPA recommended removing proposed §25.205(k)(2)(D). Onward reasoned that maximum ramp rates for load curtailment are not listed as a possible condition in PURA §39.169. TCPA reasoned that controls on how fast a load can curtail or come back online, not the overall ramp rate for total energy use, are used in system planning and therefore are more appropriately taken up as a broader policy topic rather than in a narrow application to only one subset of loads based solely on their physical location relative to a generator.

Commission Response

The commission declines to adopt Onward and TCPA's recommendation to remove maximum ramp rates for load curtailment from the list of conditions that the commission may impose on a net metering arrangement. PURA §39.169(d) provides a non-exhaustive list of conditions that the commission may impose to maintain system reliability, which means that the commission may impose other conditions not identified in PURA §39.169.

The generic meaning of "ramp rate" refers to an increase or decrease of MW consumed (i.e., load) or produced (i.e., resource output) over a given period of time.

However, any ramp rate limitations for load curtailment is appropriately related to maintaining system reliability and therefore may be a condition that the commission imposes on a net metering arrangement, especially considering that the tool would be used during emergency conditions when system conditions may be more vulnerable. Therefore, for added clarity, the commission modifies adopted 25.205 (k)(2)(D) by replacing "maximum ramp rates" with "any ramp rate limitations or maximum duration" for load curtailment.

"Reasonable" requirements, conditions to resolve an objection or address a violation of law, and any other requirement necessary to maintain system reliability

TCPA and Vistra recommended modifying proposed §25.205(k)(2)(E) by inserting "reasonable" before "requirement." TEC recommended modifying proposed §25.205(k)(2)(E) to state that the commission may impose conditions to resolve an objection or address a violation of law. Onward recommended modifying adopted §25.205(k)(2) to remove the ability for the commission to impose any other requirement that is necessary to maintain system reliability because this language is not captured in PURA §39.169.

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(k)(2)(E) to insert "reasonable" before "requirement" because it is unnecessary. Any requirement that is imposed as a condition on a net metering arrangement must be based on findings of fact and conclusions of law, thus ensuring that the requirement is reasonable. The commission declines to adopt TEC's recommendation to modify adopted §25.205(k)(2)(E) to state that the commission may impose conditions to resolve an objection or address a violation of law because it is unnecessary. The commission has statutory authority to resolve an objection or address a violation of law without the need to restate that authority in the adopted rule. The commission declines to adopt Onward's recommendation to remove the ability for the commission to impose any other requirement that is necessary to maintain system reliability. PURA §39.169 provides a non-exhaustive list of conditions that the commission may impose to maintain system reliability, which means that the commission may impose other conditions not identified in PURA §39.169. For added clarity, the commission modifies adopted §25.205(k)(2) to specify that the commission may impose conditions, including one or more of the listed requirements and replaces "and" in the list of conditions with "or." The commission also adds §25.205(k)(7), which further clarifies that nothing in the adopted rule limits the commission's authority to impose conditions on a net metering arrangement under the Public Utility Regulatory Act.

Replace "behind-the-meter" and "behind the meter" with "net metering arrangement"

TPPA recommended modifying proposed §25.205(k)(2)-(3) to replace "behind-the-meter" and "behind the meter" with "net metering arrangement" for consistency.

Commission Response

The commission declines to adopt TPPA's recommendation to modify adopted §25.205(k)(2) and (5) to replace "behind-the-meter" and "behind the meter" with "net metering arrangement" because the terms are not synonymous.

Remove the requirement for ERCOT to include load reduction when calculating price adjustments for reliability deployments

TPPA recommended modifying proposed §25.205(k) to remove proposed §25.205(k)(3). TPPA noted that curtailments assumed under the proposed rule would not reduce the amount of load drawing energy from the grid but would instead introduce new generation to the grid that otherwise was serving the large load customer. Therefore, TPPA reasoned that such deployments should not impact price adjustments for reliability price adders. Moreover, the ERCOT stakeholder process remains the appropriate forum for discussing non-legislatively mandated price adder adjustments.

Commission Response

The commission declines to adopt TPPA's recommendation to remove adopted §25.205(k)(5). The purpose of any price adjustment is to bring transparency to the out of market actions performed by ERCOT for reliability, which cannot be predicted by market participants and incorporated in price formation. These can be both load and generation deployments. ERCOT runs an energy only market that relies on robust and transparent price formation. The adopted rule directs ERCOT to include such adjustments only for the out of market actions. The commission expects the details for the settlement of the load and generation to be developed in the ERCOT stakeholder process. However, the commission modifies adopted §25.205(k)(5) to include generation dispatched so that it is more transparent.

Remove requirement for notice to TSP that is not a party to the proceeding

Calpine recommended removing proposed §25.205(k)(4) because there is no likely scenario in which the TSP associated with a stranded or underutilized transmission asset relevant to a net metering arrangement would not have been a party to the proceeding which approved the net metering arrangement that includes a condition requiring a hold harmless proceeding.

Commission Response

The commission declines to adopt Calpine's recommendation to remove the requirement for commission staff to notify a TSP if its transmission assets are identified as stranded or underutilized and the TSP was not a party to the proceeding in which the commission considered approving, with or without conditions, or denying the net metering arrangement. A scenario could arise in which a TSP is not a party to the proceeding but has transmission assets that are identified as stranded or underutilized as a result of the net metering arrangement. Therefore, it is appropriate to ensure a mechanism for providing notice to that TSP is set forth in the adopted rule.

Address the stranded or underutilized transmission assets in the proceeding for the net metering arrangement instead of a separate hold harmless proceeding

CTEI recommended against a separate hold harmless proceeding and instead addressing all details related to a hold harmless condition in the proceeding approving the net metering arrangement. CTEI reasoned that the determination of a hold harmless condition could have significant financial impacts, and as a practical matter the applicants may be subject to additional regulatory delays beyond the timeline established by the Legislature for reviewing these net metering arrangements.

Commission Response

The commission declines to adopt CTEI's recommendation to address all details related to a hold harmless condition in the proceeding approving the net metering arrangement instead of addressing those details in a separate hold harmless proceeding. ERCOT must first recommend whether transmission assets will be stranded or underutilized as a result of a net metering arrangement, and the commission must then determine whether a condition holding customers harmless is appropriate. The 60-day deadline for processing the net metering arrangement does not provide sufficient time to gather the necessary evidence from the TSP that owns the stranded or underutilized transmission assets, and, in some cases, the associated TSP may not be a party to the proceeding in which the commission considers approving a net metering arrangement. Therefore, a separate hold harmless proceeding is appropriate to ensure that the necessary evidence is presented, and all necessary entities are a party to the proceeding.

Proposed §25.205(l) - Hold harmless proceeding

Proposed §25.205(l) sets forth the requirements for initiating a hold harmless proceeding and the general framework for the hold harmless proceeding. Proposed §25.205(l)(2) specifies that the parties to a hold harmless proceeding are not limited to the same parties that are authorized to participate in a net metering arrangement proceeding. Proposed §25.205(l)(3)(B) requires updated billing units to be applied when establishing rates reflecting the removal of the appropriate costs associated with the stranded or underutilized transmission assets.

Clarify transmission assets may be identified as potentially stranded or underutilized regardless of who the assets were installed for

CenterPoint recommended modifying proposed §25.205(l) to clarify that transmission assets installed for the large load customer and transmission assets installed for the generation resource may be identified as potentially stranded or underutilized.

Commission Response

The commission declines to adopt CenterPoint's recommendation to modify adopted §25.205(l) to clarify that transmission assets installed for the large load customer and transmission assets installed for the generation resource may be identified as potentially stranded or underutilized because it is unnecessary. Whether a transmission asset is stranded or underutilized is not dependent on whether the assets were installed for a specific purpose, as is demonstrated by the definitions for the terms.

Permit withdrawal of net metering arrangement application

TSSA recommended modifying proposed §25.205(l) to authorize the parties to a net metering arrangement to withdraw the net metering request at any time during the hold harmless proceeding, without penalty or prejudice, and to clarify the primary of any agreement between the parties to the net metering arrangement regarding potential stranded or underutilized cost recovery. With regard to its first recommended change, TSSA reasoned that the delays associated with the separate, extra proceeding and the regulatory uncertainty of potentially significant stranded cost responsibility could change the economics of the project, resulting in the parties no longer wishing to proceed once all of the facts are known. Regarding its second recommended change, TSSA reasoned that the parties to the net metering arrangement are better suited to manage potential financial risk and promote judicial economy of scarce commission rules. Therefore, the commission should give effect to the agreement of the parties and only absent contractual arrangement, decide the proportion of cost responsibility between the existing generation resource and the large load customer.

Commission Response

The commission declines to adopt TSSA's recommendation to modify adopted §25.205(l) to authorize the parties to a net metering arrangement to withdraw their application for a net metering arrangement at any time during the hold harmless proceeding, with or without prejudice, because it is unnecessary. The commission's procedural rules govern the process for withdrawing an application. The commission also declines to adopt TSSA's recommendation to modify adopted §25.205(l) to clarify the primary of any agreement between the parties to the net metering arrangement regarding the potential stranded or underutilized cost recovery. While an agreement may be considered and potentially given great weight, the commission determines that it is appropriate to maintain discretion over making such a determination to ensure that customers are held harmless based on the specific facts of each contested case proceeding.

Clarify what is referred to by "in a proportion" and specify a TSP may use existing process and procedures for recovery of debts owed by market participants

ETT recommended modifying proposed §25.205(l) to clarify that the phrase "in a proportion determined by the commission" is intended to refer to assigning proportion to the two entities that would be responsible for the costs (i.e., the existing generation resource owner and the interconnecting large load customer), rather than referring to a proportion of the costs themselves. ETT also recommended modifying proposed §25.205(l) to specify that in an instance where the existing generation resource owner or interconnecting large load customer fails to pay the costs established in a hold harmless proceeding, the TSP may utilize existing process and procedures for recovering debts owed by market participants, including mechanisms outlined in the existing ERCOT Protocols.

Commission Response

The commission declines to adopt ETT's recommendation to modify adopted §25.205(l) to clarify that the phrase "in a proportion determined by the commission" is intended to refer to assigning proportion to the two entities that would be responsible for the costs rather than referring to a proportion of the costs themselves because it is unnecessary. The commission also declines to modify §25.205(l) to specify that in an instance where the existing generation resource owner or interconnecting large load customer fails to pay the costs established in a hold harmless proceeding, the TSP may utilize existing process and procedures for recovering debts owed by market participants, including mechanisms outlined in the existing ERCOT Protocols because it is unnecessary to address in the adopted rule.

Limit the parties to a hold harmless proceeding

TCPA and Vistra recommended modifying proposed §25.205(l)(2) to limit the parties to a hold harmless proceeding to the same limited parties that are authorized to participate in a net metering arrangement proceeding under PURA §39.169.

Commission Response

The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(l) to limit the parties to a hold harmless proceeding to the same limited parties that are authorized to participate in a net metering arrangement proceeding under PURA §39.169. A TSP associated with the stranded or underutilized transmission assets may not be a party to the proceeding for the net metering arrangement. Therefore, such a limitation is not appropriate.

Leave billing units unchanged from the last commission-approved transmission cost of service

ETT recommended modifying proposed §25.205(l)(3)(B) to leave billing units unchanged from the last commission-approved transmission cost of service instead of updating billing units when establishing rates reflecting the removal of the appropriate costs associated with the stranded or underutilized transmission assets. ETT reasoned that the hold harmless proceeding should remain narrowly focused on quantifying and allocating costs specifically associated with stranded or underutilized transmission assets resulting from a net metering arrangement.

Commission Response

The commission agrees with ETT that the hold harmless proceeding should focus narrowly on removing the applicable costs from rates and not updating any other costs or billing determinants used to establish rates. The commission modifies adopted §25.205(l)(3)(B) accordingly.

Clarify a hold harmless proceeding will follow the Texas Administrative Procedures Act

CTEI and Onward recommended modifying proposed §25.205(l) to clarify that a hold harmless proceeding will follow the Texas Administrative Procedure Act rules for a contested case under Texas Government Code §2001.003(1) and otherwise allow for due process and an opportunity to examine the TSP's data and information.

Commission Response

The commission declines to adopt CTEI and Onward's recommendation to modify proposed §25.205(l) to clarify that a hold harmless proceeding will follow the Texas Administrative Procedure Act rules for a contested case under Texas Government Code §2001.003(1) and otherwise allow for due process and an opportunity to examine the TSP's data and information. The commission determines that restating the applicable body of law is not necessary.

Proposed §25.205(m) - Periodic evaluation of conditions imposed.

Proposed §25.205(m) requires periodic evaluation of conditions that are imposed on a net metering arrangement, and those conditions are not limited to a specific period.

ERCOT recommended modifying proposed §25.205(m) to add a requirement for the party to serve a copy of the application on all parties identified in proposed §25.205(d)(2). ERCOT reasoned that based on its responsibility for grid reliability, its role in recommending conditions to the commission, and its involvement as a party to the original proceeding in which the conditions were imposed, ERCOT should have an opportunity to be a party to any proceeding initiated under proposed §25.205(m).

TCPA and Vistra recommended modifying proposed §25.205(m) to remove "at least 36 months" because the restriction for a party to the arrangement to initiate the review to no less than 36 months conflicts with the statute.

TPPA recommended modifying proposed §25.205(m) to clarify that the conditions described "under this section" are linked to the conditions contemplated under proposed §25.205(k). TPPA also recommended specifying that the "parties to a net metering arrangement" are limited to the large load customer and generation resource. TPPA reasoned that without this clarification, the subsection could be read to require the interconnecting entity or ERCOT to file the application for a hold harmless proceeding.

Commission Response

The commission adopts ERCOT's recommendation to modify adopted §25.205(m) to add a requirement for the party to serve a copy of the application on all parties identified in adopted §25.205(d)(2). The commission declines to adopt TCPA and Vistra's recommendation to modify adopted §25.205(m) to remove "at least 36 months." The commission determines that 36 months is an appropriate time to allow the conditions to serve their purpose before being re-evaluated. Not identifying a minimum time frame for the conditions would allow parties to a net metering arrangement to immediately apply to remove the condition, which could result in inefficient use of staff and resources. The commission declines to adopt TPPA's recommendation to clarify that the conditions described "under this section" are linked to the conditions contemplated under adopted §25.205(k) because it is unnecessary. The commission also declines to adopt TPPA's recommendation to specify that the parties to a net metering arrangement are limited to the large load customer and generation resource because it is unnecessary. The definition for a net metering arrangement contemplates that a large load customer and an existing generation resource are parties to the net metering arrangement.

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This section is adopted under the following provisions of Public Utility Regulatory Act (PURA): §14.001, which grants the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §39.151, which grants the commission authority to oversee ERCOT; and PURA §39.169, which requires the commission to approve, deny, or impose reasonable conditions on a proposed net metering arrangement involving a large load customer and an existing generation resource.

Cross Reference to Statutes: PURA §14.001; §14.002; §39.151; and §39.169.

§25.205. Net Metering Arrangements Involving a Large Load Customer Co-Located with an Existing Generation Resource.

(a) Applicability. This section applies to a net metering arrangement involving a large load customer and an existing generation resource in the ERCOT region. This section does not apply to a generation resource or energy storage resource that meets the following criteria:

(1) the modeled generation resource or energy storage resource facility included a co-located large load customer at the time of the generation resource or energy storage resource's energization, regardless of whether the large load customer was energized at a later date; or

(2) a majority interest of the generation resource or energy storage resource was owned indirectly or directly as of January 1, 2025, by a parent company of a large load customer that participates in the new net metering arrangement.

(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise:

(1) Applicants--The large load customer and the power generation company, municipally owned utility, or electric cooperative that are parties to a net metering arrangement for which approval is sought under this section.

(2) Dispatchable capacity--Output capacity that can be controlled primarily by forces under human control.

(3) Energy storage resource--An energy storage resource as the term is defined in ERCOT protocols.

(4) ERCOT system--ERCOT system as the term is defined in ERCOT protocols.

(5) Existing generation resource--A generation resource registered with ERCOT as a stand-alone generation resource as of September 1, 2025 or an energy storage resource registered with ERCOT as a stand-alone energy storage resource as of September 1, 2025.

(6) Generation resource--A generation resource as the term is defined in ERCOT protocols.

(7) Interconnecting distribution service provider (DSP)--Includes the transmission and distribution utility, municipally owned utility, or electric cooperative that is certificated or otherwise authorized to provide either retail electric service or retail electric delivery service at the location in which the large load customer seeks to interconnect.

(8) Interconnecting transmission service provider (TSP)--The electric utility, municipally owned utility, or electric cooperative that owns and operates the facilities necessary to interconnect the large load customer or the existing generation resource to the ERCOT system.

(9) Large load customer--An entity requesting a new or expanded interconnection where the customer's total expected non-coincident peak demand at a single site is equal to or greater than 75 megawatts (MW), and as of September 1, 2025, was not modeled in ERCOT's Network Operations Model as part of a generation resource private use network (PUN) or an energy storage resource PUN.

(10) Net metering arrangement--An arrangement in which an existing generation resource and a large load customer agree to net the existing generation resource's output with the customer's load for settlement purposes based on a metering scheme approved by ERCOT.

(11) Stand-alone energy storage resource--An energy storage resource that, as of September 1, 2025, was included in ERCOT's Network Operations Model and such model of the resource site did not include modeled load other than auxiliary load.

(12) Stand-alone generation resource--A generation resource that, as of September 1, 2025, was included in ERCOT's Network Operations Model and such model of the resource site did not include modeled load other than auxiliary load.

(13) Stranded transmission asset--A transmission asset that, as a result of a net metering arrangement, is no longer providing service to the public or may otherwise be retired from service without impairing the ability of the ERCOT system to provide adequate transmission service to customers.

(14) Underutilized transmission asset--A transmission asset that, as a result of a net metering arrangement, is expected to transmit on an average, annual basis at least 25% less power commensurate with its maximum capacity to transmit power and is not providing significant reliability benefits to the ERCOT system.

(c) Commission approval required. A power generation company, municipally owned utility, or electric cooperative must not implement a net metering arrangement involving a large load customer and an existing generation resource unless the net metering arrangement is approved by the commission.

(d) Initiating the process for approval of a net metering arrangement.

(1) Prior to ERCOT commencing its study under subsection (g) of this section, the applicants seeking approval of a net metering arrangement must apply to the commission, using a new docket number, for approval of the net metering arrangement by filing an application that meets the requirements of §22.73 of this title (relating to General Requirements for Applications). The application must include:

(A) direct testimony supporting the application;

(B) a completed large load interconnection study as the term is defined in ERCOT protocols as of the date the application is filed with the commission or a study report from another completed study process to interconnect a large load customer that is required by ERCOT protocols as of the date the application is filed with the commission;

(C) identification of the interconnecting transmission service provider (TSP);

(D) if different from the interconnecting TSP, the identification of the interconnecting DSP; and

(E) a copy of the notice submitted to ERCOT.

(2) Upon filing its application with the commission, the applicants must serve copies of the application, consistent with the requirements in §22.74 of this title (relating to Service of Pleadings and Documents), on:

(A) ERCOT;

(B) the interconnecting TSP; and

(C) if different from the interconnecting TSP, the interconnecting DSP.

(3) Following the filing of an application under this section, if the physical characteristics of the proposed large load or the proposed physical configuration of the load in the net metering arrangement materially changes in a way that requires restudy under the large load interconnection study process, as described in ERCOT protocols in effect at the time the application for the net metering arrangement is filed with the commission, ERCOT must file notice in the docket that restudy is necessary. An application for approval of a net metering arrangement that requires restudy under this subsection is considered a new application and restarts the procedural deadlines.

(e) Parties to a proceeding under this section.

(1) The parties to a proceeding under this section are limited to:

(A) the applicants;

(B) commission staff;

(C) ERCOT;

(D) the interconnecting TSP; and

(E) if different from the interconnecting TSP, the interconnecting DSP.

(2) The parties to a proceeding under this section need not file a motion to intervene.

(3) A party to a proceeding under this section may file notice identifying whether the party intends to participate in the proceeding.

(f) Discovery.

(1) Discovery may commence on or after the date an application under this section is filed with the commission.

(2) ERCOT is not required to follow the discovery process to obtain the necessary information to conduct its study under subsection (g) of this section.

(3) The presiding officer may establish reasonable deadlines relating to discovery to facilitate the processing of the application within the statutory deadlines.

(g) Commencement of ERCOT study.

(1) The parties to a net metering arrangement must provide ERCOT all information that ERCOT deems necessary regarding the net metering arrangement.

(2) The interconnecting TSP must submit the following to ERCOT:

(A) all transmission security analysis studies that ERCOT requires of the TSP under the large load interconnection study process and described in ERCOT protocols that are in effect at the time the application for approval of the net metering arrangement is filed with the commission;

(B) assets and facilities that are de-energized as a result of the net metering arrangement, the results of power flow modeling, and any other information relevant to a determination of whether stranded or underutilized transmission assets may result from the arrangement; and

(C) any other information that ERCOT deems necessary.

(3) Upon confirmation of completion of all studies required by ERCOT under the large load interconnection study process, as described in ERCOT protocols, that is in effect at the time the application for approval of the net metering arrangement is filed with the commission and following receipt of the information described in paragraph (2) of this subsection, ERCOT must conduct a study of the system impacts of the net metering arrangement, including transmission security and resource adequacy impacts, and stranded or underutilized transmission assets associated with the net metering arrangement. Not later than seven days after commencing its study, ERCOT must file notice in the docket indicating ERCOT received all information it deems necessary to conduct its study regarding the net metering arrangement and specifying the date that ERCOT commenced its study and the date ERCOT must file its study results and recommendations.

(4) ERCOT must provide commission staff any access, information, support, or cooperation that commission staff determines is necessary to provide its recommendations under this section.

(h) General requirements of ERCOT study. ERCOT's study of a net metering arrangement must include:

(1) a resource adequacy analysis that considers:

(A) the large load customer's curtailment capability;

(B) on-site back up generation capability to offset the large load customer;

(C) expected net generation available to the ERCOT system after implementation of the net metering arrangement; and

(D) the impacts of reduced net capability or lower availability on reserve margins or other reliability criteria;

(2) a transmission security analysis that is comprised of a steady state and stability load serving study with and without the generation, under peak scenarios and off-peak scenarios, including review of a completed large load interconnection study as the term is defined in ERCOT protocols as of the effective date of this section or another study required by ERCOT under the large load interconnection study process described in ERCOT protocols in effect at the time the application for approval of a net metering arrangement is filed with the commission;

(3) an analysis identifying transmission assets that may become stranded or underutilized as a result of the net metering arrangement, including the identity of the TSP associated with each such asset and the degree to which any transmission assets are expected to be underutilized from both a delivery and a reliability perspective; and

(4) any other analysis or study that ERCOT determines is necessary.

(i) ERCOT study results. Not later than ten days before ERCOT files its study results and recommendations, ERCOT must file notice in the docket indicating the date that ERCOT expects to file its study results and recommendations. Not later than 120 days after ERCOT's filing indicating ERCOT received all information it deems necessary to conduct its study regarding the net metering arrangement and specifying the date ERCOT commenced its study, ERCOT must file its study results and associated recommendations. ERCOT's filing must include:

(1) direct testimony supporting the filing;

(2) an executive summary of the study, including any ERCOT recommendations, that identifies:

(A) the large load customer;

(B) whether the large load customer seeks a new or expanded interconnection;

(C) whether the large load customer or any other customer is already located at the requested interconnection site and if so, that customer's peak demand at the requested interconnection site;

(D) whether ERCOT identified any potentially stranded transmission assets or underutilized transmission assets, or any negative impacts to system reliability, including transmission security and resource adequacy impacts;

(E) ERCOT's recommendation to approve, with or without conditions, or deny the net metering arrangement; and

(F) whether ERCOT recommends conditions to mitigate an impact or potential impact to transmission security, resource adequacy, or both;

(3) the complete study, detailing:

(A) ERCOT's analysis;

(B) the underlying assumptions used in the study;

(C) the sources of data used in the study;

(D) the existing generation resource's seasonal net max sustainable rating for each season as reported to ERCOT in the existing generation resource's most recent resource registration data and how that existing generation resource can comply with a requirement to make at least that same amount of dispatchable capacity available after implementation of the net metering arrangement, as applicable; and

(E) whether ERCOT identified any negative impacts to resource adequacy that cannot be mitigated with curtailment of the large load customer; and

(F) whether any transmission assets are stranded or underutilized, including the degree to which any underutilized transmission assets are underutilized from a delivery or a reliability perspective, and the identity of the associated TSPs;

(4) a detailed explanation of the basis for any conditions that ERCOT recommends and the extent to which those conditions are expected to mitigate a reliability risk to the ERCOT system; and

(5) any other information that ERCOT relied on or considered.

(j) Procedural schedule. After ERCOT files its study results and recommendations, the presiding officer must set a procedural schedule that will enable the commission to issue an order in the proceeding within 60 days of ERCOT's filing.

(1) The procedural schedule must be substantially similar to the following:

(A) the deadline for the applicants to file a statement of position or supplemental direct testimony is five days after ERCOT files its study results and recommendations;

(B) the deadline for the interconnecting TSP, and, if different from the interconnecting TSP, the interconnecting DSP to file a statement of position, direct testimony, or an objection to the net metering arrangement is ten days after ERCOT files its study results and recommendations;

(C) the deadline to request a hearing on the merits is ten days after ERCOT files its study results and recommendations;

(D) the deadline for ERCOT to file a response to other parties' filings is 15 days after ERCOT files its study results and recommendations;

(E) the deadline for commission staff to file a statement of position or direct testimony, including its recommendations, is 17 days after ERCOT files its study results and recommendations;

(F) if no hearing on the merits is requested, the deadline to file a stipulation or agreement, a joint motion to admit evidence, and a joint proposed order is 24 days after ERCOT files its study results and recommendations;

(G) if a hearing on the merits is requested, the hearing on the merits will commence up to 28 days after ERCOT files its study results and recommendations; and

(H) if a hearing on the merits is requested:

(i) the deadline for initial briefs is 34 days after ERCOT files its study results and recommendations; and

(ii) the deadline for reply briefs and proposed orders is 40 days after ERCOT files its study results and recommendations.

(2) Notwithstanding any provision of this section, the presiding officer may set a different procedural schedule than the one set forth in this subsection or adjust any procedural deadlines to facilitate the commission issuing an order in the proceeding within 60 days after ERCOT files its study results and recommendations.

(k) Commission decision. Not later than 60 days after ERCOT files its study results and recommendations, the commission will approve, with or without conditions, or deny an application for a net metering arrangement as necessary to maintain system reliability, including transmission security and resource adequacy impacts.

(1) If the commission approves a net metering arrangement with conditions on an existing generation resource that makes dispatchable capacity available to the ERCOT region before the net metering arrangement, then the conditions imposed on the net metering arrangement must include requiring the existing generation resource to make dispatchable capacity available to the ERCOT region as directed by ERCOT in advance of an anticipated emergency condition. The dispatchable capacity made available to the ERCOT region in such an event must be at least equal to the amount of dispatchable capacity that was made available to the ERCOT region before implementation of the net metering arrangement.

(2) The commission may impose conditions on a net metering arrangement, including requiring one or more of the following:

(A) the retail customer(s) served behind-the-meter to reduce load during certain events;

(B) the existing generation resource to make capacity available to the ERCOT region during certain events;

(C) initiation of a separate hold harmless proceeding for each net metering arrangement that results in stranded or underutilized transmission assets in order to ensure TSPs and their customers are held harmless;

(D) any ramp rate limitations or maximum duration for load curtailment; or

(E) any other requirement that is necessary to maintain system reliability.

(3) An existing generation resource that must make dispatchable capacity available under paragraph (1) of this subsection must make dispatchable capacity available by adjusting the existing generation resource's output in accordance with ERCOT's instructions.

(4) An existing generation resource that must make capacity available under paragraph (2) of this subsection must make capacity available by complying with any conditions specific to the existing generation resource.

(5) If the commission imposes a condition that requires a large load customer to reduce load or requires an existing generation resource to adjust its output in accordance with ERCOT's instructions, ERCOT must include any such load reduction and generation increases when calculating any price adjustments for reliability deployments.

(6) If the commission imposes a condition requiring a hold harmless proceeding and the TSP associated with the stranded or underutilized transmission assets was not a party to the proceeding in which the commission considered approving, with or without conditions, or denying the proposed net metering arrangement, then commission staff must provide notice to the TSP of the requirement to initiate a hold harmless proceeding under subsection (l) of this section not later than seven days after the commission order imposing the condition. Notice may be served by delivering a copy of the commission order by physical or electronic mail to the TSP's authorized representative or attorney of record in the TSP's last comprehensive base rate case.

(7) Nothing in this section limits the commission's authority to impose conditions on a net metering arrangement under the Public Utility Regulatory Act.

(l) Hold harmless proceeding. Within 60 days of a commission order requiring a hold harmless proceeding, each TSP associated with stranded or underutilized transmission assets that result from a net metering arrangement must file an application to quantify the costs associated with such assets and to reflect removal of those costs from the TSP's rates. Such costs must not be included in the TSP's rates in future proceedings absent an explicit commission determination in a comprehensive base rate proceeding that the associated transmission assets are no longer stranded or underutilized, and that the TSP has not otherwise been compensated for those costs. Upon removal from rates, these costs must be collected by the TSP from the existing generation resource owner and the interconnecting large load customer in a proportion determined by the commission or by agreement between the existing generation resource owner and the interconnecting large load customer.

(1) The application must include information sufficient to identify the costs associated with the stranded or underutilized transmission assets.

(2) The parties to a hold harmless proceeding under this subsection are not limited to the parties identified in subsection (e) of this section.

(3) Removal from rates of the costs associated with stranded or underutilized transmission assets, along with all associated depreciation, tax, return, and other cost of service components including an appropriate amount of operations and maintenance expenses, may be implemented in a manner otherwise consistent with the ratemaking treatments associated with an interim update of transmission rates under §25.192 of this Title (related to Transmission Service Rates), provided that:

(A) increases in costs must not be included in a hold harmless proceeding;

(B) the timeline for approval included in §25.192 does not apply to a hold harmless proceeding under this subsection; and

(C) a hold harmless proceeding under this subsection is not an interim update to a TSP's rates for purposes of determining the frequency of interim updates authorized under §25.192.

(m) Periodic evaluation of conditions imposed. If the conditions imposed on a net metering arrangement under this section are not limited to a specific period, a party to the net metering arrangement must apply for a commission determination of whether the conditions should be extended, with or without modification, or rescinded at least 36 months and not more than 60 months after the order approving the net metering arrangement with conditions. A party to the net metering arrangement applying for a commission determination of whether the conditions should be extended, with or without modification, or rescinded must serve a copy of the application on all parties identified in subsection (d)(2) of this subsection.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on March 26, 2026.

TRD-202601385

Katelyn Lewis

Projects Coordinator

Public Utility Commission of Texas

Effective date: April 15, 2026

Proposal publication date: October 3, 2025

For further information, please call: (512) 936-7044

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