PART 2. PUBLIC UTILITY COMMISSION OF TEXAS
CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY
The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.52 relating to Reliability and Continuity of Service with changes to the proposed text as published in the August 30, 2024, issue of the Texas Register (49 TexReg 6666) and will be republished. The rule is adopted in Project No. 56897.
The amended rule requires each transmission and distribution utility to maintain an online outage tracker that provides detailed information regarding power outages in English and in Spanish. The amended rule also requires a utility to notify the commission if the outage tracker or outage map becomes unavailable.
Public Comments
Comments were received by the Alliance for Retail Markets, (ARM); AEP Texas Inc. and Southwestern Electric Power Company, (AEP Companies); CenterPoint Energy Houston Electric, LLC, (CenterPoint); Electric Transmission Texas, LLC, (ETT); Entergy Texas, Inc, (ETI); LCRA Transmission Services Corporation, (LCRA TSC); Office of Public Utility Counsel, (OPUC); Octopus Energy LLC, (Octopus); Oncor Electric Delivery Company LLC, (Oncor); Sharyland Utilities, LLC, (Sharyland); Southwestern Public Service Company, (SPS); Texas Electric Cooperatives, Inc, (TEC); Texas Energy Association for Marketers, (TEAM); Texas New Mexico Power Company, (TNMP); and Texas Public Power Association, (TPPA).
General Comments
Comments beyond the scope
OPUC requested that the rule require alerts of potential outages, clearly identify which customers may be affected by the outage, and limit the alerts to customers who may be affected, rather than all customers. Further, OPUC requested that alerts of potential outages should also be sent to OPUC.
TEC requested the addition of a new paragraph that would require transmission service providers to give updates regarding restoration efforts to their impacted distribution service providers during a system restoration event. TEC also requested the addition of a new subsection that would require transmission service providers to give equal priority to restoration of distribution systems that are operated by other utilities, municipally owned utilities, or electric cooperatives.
ARM proposed a new paragraph to authorize TDUs (Transmission and Distribution Utility) to use REPs' provided customer contact information for the purpose of communicating with customers about power outages and restorations during emergencies, when the TDU received such customer contact information from a REP pursuant to basic retail market transactions and the TDU's tariff. ARM recommended that the Commission withdraw the proposed revisions to §25.472, and instead, recommends adding amendments to 16 TAC §25.52 that specify TDU obligations with respect to the use of customer contact information, which is the more efficient and appropriate place to include TDU obligations.
TEAM proposed adding a new paragraph to establish a TDU's responsibilities with respect to the use of customer information provided by a REP, including permitted uses for contact information, content of the TDU' s outage and restoration communications, and requirements for the system used by the TDU to store the contact information and provide communications. Further, TEAM requested if the commission chooses to permit a utility to use contact information provided by a REP to facilitate customer communications, then TEAM recommends the adoption of rule language addressing a TDU's ability to use customer information that is currently provided by REPs.
ARM and TEAM recommended that the commission adopt a new paragraph to require TDUs to provide real-time outage information for impacted ESI IDs to the REP of record in a central repository, like Smart Meter Texas.
Octopus recommended the addition of a new subparagraph which would require transmission distribution utilities to provide retail electric providers with the option to receive customer outage status and restoration data for the retail electric provider own costumers via a REST API.
Commission response
The commission declines to modify the rule in response to the above comments. The focus of proposed subsection (b)(7) and this rulemaking proceeding is a utility's passive online resources. Issues involving active utility notification systems, consumer information, and power restoration priority are beyond the scope noticed in this proceeding.
Premise-specific information
TEAM stated that based on the proforma Tariff for Retail Delivery Service, the customer should not have to sign-up for an alert system or provide information other than their service address to receive basic, premise-specific outage information, and instead the responsibility should lie with the TDU.
Commission Response
The commission declines to modify the rule to specify what information a customer must provide to see premise-specific information. Some utilities have indicated that they do not provide premise specific information without a user providing some identifying information out of concern for the safety of the individuals and property in the unpowered houses illustrated on the outage tracker or outage map. This is a reasonable policy for a utility to have, and the commission will not prohibit it by rule.
Outage tracker granularity and accuracy
TPPA requested the rule specify the magnitude and duration of outage that must be captured on the utility's outage tracker. TPPA offers the example of an outage effecting a single customer for a single hour.
ARM recommended the commission establish accuracy standards for a utility's outage tracker to ensure that the information provided to customers and to the public is reasonably reliable. ARM suggested the commission measure and establish standards for outage tracker load time, customer demand support, speed from outage report to outage tracker notice, and the stability/accuracy of restoration time estimates.
Commission Response
The commission declines to specify a magnitude or duration threshold below which an outage is not required to be included on the outage tracker or outage map as recommended by TPPA. The commission expects utilities to provide information with as much granularity as is reasonably practicable and will use its enforcement discretion, as appropriate.
The commission also declines to develops accuracy standards for utility outage trackers as requested by ARM. This rulemaking represents the commission's first requirements related to utility outage trackers, and it is premature to adopt accuracy standards at this time.
Applicability of outage tracker requirements
Sharyland requested the commission clarify the rule to exempt transmission service providers with no certificated service territory or retail customers from the requirement to maintain an outage tracker.
Commission response
The commission agrees with Sharyland and modifies the rule to require an outage tracker or outage map from a utility that provides distribution service to retail customers. The primary purpose of this rule is to provide end-use customers with information about whether their homes and businesses have power.
Implementation timeline requirements
Oncor, AEP Companies, SPS, and CenterPoint Energy requested additional time to implement the requirements of the proposed rule amendments. Oncor requested the commission consider the time and resources required to make these changes. AEP Companies requested that the deadline to comply with the outage rule be the end of the first quarter of 2025 to provide entities with ample time. CenterPoint Energy requested (b)(7)(A) be modified to provide an electric utility until June 1, 2025, to have the electric utility's outage tracker provide information in Spanish.
Commission Response
The commission declines to extend the effective date of this rule, as requested by commenters. Each utility must begin maintaining a functional outage tracker and comply with the notification requirements proposed in the rule immediately upon the effective date of the rule. However, the commission modifies the rule to allow a utility to make a filing in this project identifying specific requirements that it needs more time to implement, the reason it cannot implement the requirement immediately, and a projected implementation date that is no later than June 1, 2025. A utility that makes such a filing, may delay compliance of these identified requirements until the earlier of the requirement's projected implementation date and June 1, 2025. This approach ensures that retail customers have immediate access to a functional outage tracker and there is transparency with regards to features that are not immediately available.
Rate treatment
SPS recommended amending subsection (b)(7)(D) to indicate that costs associated with necessary improvements be recoverable.
Commission Response
The commission declines to modify the rule to address what rate treatment is appropriate for system changes that a utility is required to make to comply with the provisions of this rule. Any costs incurred coming into compliance with this rule will be addressed in an appropriate rate case according to the applicable rules and standards.
Proposed §25.52(b)(6)
Proposed §25.52(b)(6) requires utilities to make available to state and local authorities a method to report a potential hazardous condition that may require disconnection of service six months after the effective date of this rule.
The commission received comments on subsection (b)(6) from AEP Companies, CenterPoint Energy, Oncor, SPS, TEC and TPPA. Commenters requested further clarity on the applicability of terms in this section, including "potential hazardous conditions" and "state and local authorities." Commenters also expressed confusion on which party ultimately had the responsibility to report hazards and who ultimately would make the decision to disconnect.
Commenters requested further clarity on the reporting requirements applicable to MOUs and Cooperatives. To address the concerns listed, commenters recommended the commission host a workshop to fine tune these details. TPPA recommended modifying the rule to require contact information provided in EOPs be used by the Commission, the Railroad Commission, and State Fire Marshall to report potential hazardous conditions that may require a disconnection of service instead of creating new methods.
Commission Response
The commission modifies the rule to remove proposed subsection (b)(6). The commission already has sufficient authority to obtain the necessary contact information, as needed. Accordingly, the commission does not accept any commenter suggestions, because they are moot.
Proposed §25.52(b)(7)
Proposed §25.52(b)(7) requires each utility to provide access to an outage tracker on their website.
Oncor requested that the references to outage tracker be replaced with "outage map or outage tracker." ETT recommended subsection (b)(7) be modified to specify that it applies to a utility that serves retail delivery customers.
LCRA TSC noted that the proposed rule does not distinguish the distribution system from the transmission system and, therefore, it is unclear whether the requirement to maintain a publicly available outage tracker applies to both transmission and distribution systems. LCRA TSC stated that because transmission-level outage information is protected from public disclosure under federal and state law and requested that this information not be disclosed to the public.
TPPA requested clarity on the applicability of the rule to river authorities.
Commission response
The commission agrees with Oncor and modifies the rule to refer to an outage tracker or "outage map".
The commission agrees with ETT, LCRA TSC, and TPPA and modifies the rule's applicability for clarity. Specifically, the commission modifies the rule to clarify the outage tracker requirements apply to distribution systems. This edit also sufficiently addresses LCRA and TPPA's concerns.
Proposed §25.52(b)(7)(A) - Map Requirements
Proposed §25.52(b)(7)(A) requires that the publicly available online outage tracker contain a map of the utility's service territory that identifies, for each active outage, the location of the outage, the date and time the outage was reported or otherwise identified, an estimated restoration time, the status of the restoration effort, and the date and time the information was most recently updated.
TEAM recommended the addition of language to subsection (b)(7)(A) that specifies the frequency with which the map and outage tracker are updated to ensure that new construction is captured in a timely manner. ARM requested modifying (b)(7)(A) to require that utilities regularly update the service addresses included in the outage tracker.
Commission response
The commission agrees with commenters that it is necessary that the outage tracker or outage map be updated to reflect new or updated service addresses as soon as practicable and modifies the rule accordingly.
AEP Companies requested that the outage tracker requirements be modified to require a general outage location instead of premise specific location and to remove the requirement for the status of restoration efforts.
TNMP and Oncor requested (b)(7)(A) be modified to require a map showing the "approximate location of the outage" and the "general status of the restoration effort."
Oncor recommended (b)(7)(A) be modified to require "a general, estimated restoration time for outages in a given area or region." Oncor argued that during large-scale outages where there has been significant damage to its facilities, Oncor typically uses banner messaging that provides updates on a region-based level. In these instances, Oncor provides a date and time when it expects a majority of customers that are capable of receiving power to be restored. Oncor also explained that during multi-day events, there may be subsequent outages that interfere with initial restoration attempts, further complicating Oncor's ability to provide accurate estimates.
Oncor also recommended the deletion of the requirement to provide the date and time the outage was reported or otherwise identified in (b)(7)(A). Oncor argued that in many cases, infrastructure damage and resulting outages may occur in an ongoing, compounding fashion, leading to nesting outages. Oncor also explained that during extended weather events, an area may lose power multiple times in succession. Oncor indicates that in many of these cases, providing information on when an outage began may result in a utility providing inconsistent information to customers.
With regard to the above issues, Oncor also noted that customers could receive more specific outage information via the My Oncor Alerts program.
Commission response
The commission agrees that providing an exact location and exact status of restoration may not be practical for utilities. The commission modifies the rule to require an approximate location of outages and a general status of restoration efforts.
However, the commission declines to revise the rule to eliminate the requirement that a utility provide the date and time the outage was reported or otherwise identified or modify the rule to only require a "general, estimated restoration time for outages in a given area or region" as requested by Oncor. While the commission acknowledges that there are challenges involved with providing this information during extended, significant outages events, it is incumbent upon utilities to provide customers with the best available information and estimates regarding ongoing outages as possible - and to continue to explore best practices across the industry to achieve improvements in this area.
Proposed §25.52(b)(7)(B) - Notice for Unavailable Tracker
Under proposed §25.52(b)(7)(B), if a utility's outage tracker is scheduled to be taken offline, it must post details of the scheduled activity on its website and provide notice of the scheduled activity to the commission no later than seven days prior to the scheduled activity. A utility must also immediately notify the commission if its outage tracker becomes unexpectedly unavailable.
Oncor recommended modifying subsection (b)(7)(B) to require a utility to notify the commission "as soon as reasonably practicable after discovering a malfunction" if the utility's outage tracker or map unexpectedly becomes unavailable and removing the requirement that the notification be made "in writing."
ARM requested modifying (b)(7)(B) to clarify that TDUs must notify the commission any time the outage tracker is down for any reason outside of planned maintenance or upgrades.
ETI request that the seven-day lead time proposed in (b)(7)(B) for notification and posting regarding planned or schedule maintenance of its outage tracker be changed to "as soon as reasonably practicable." Alternatively, ETI proposes that the required notice be reduced to two days. Additionally, ETI requests clarification of how a utility must notify the commission "in writing" if an outage tracker unexpectedly becomes unavailable, and what individuals or divisions should be notified.
Commission response
The commission agrees with Oncor that it may not be possible for a utility to notify the commission in writing immediately when its outage tracker becomes unexpectedly unavailable. The commission also agrees with ARM that the requirement to notify the commission as soon as practicable should apply more broadly than in the proposed rule. The commission also agrees with ETI that there may be instances when a utility determines that maintenance is required that needs to be initiated quicker than the seven day notice requirements allow. The commission modifies the rule to require a utility to notify the commission as soon as reasonably practicable if the utility's outage tracker unexpectedly becomes unavailable or if the utility determines that maintenance is required within the next seven days.
The commission declines to codify in rule exactly how a utility must notify the commission in writing of its outage tracker becoming unavailable, because communication pathways between the commission and utilities during emergency conditions may change. Initially, utilities should notify the commission regarding outage tracker unavailability at emc@puc.Texas.gov.
Proposed §25.52(b)(7)(C) - Reporting Methods
Proposed §25.52(b)(7)(B) requires that the outage tracker provide or link to information that indicates the different methods a customer may use to report an outage or hazardous condition, and a link to provide updates on the hazardous condition reported.
TEAM recommended modifying subsection (b)(7)(C) to require that either the outage tracker itself or the methods for reporting an outage or hazardous condition include one digital means for a consumer to make a report that will be received by the TDU.
Commission response
The commission agrees with TEAM and modifies the rule to require a utility to provide at least one digital means for a consumer to report an outage.
Statutory Authority
The amendment is adopted under 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; §38.005, which requires the commission to implement service quality and reliability standards relating to the delivery of electricity to customers by electric utilities; and PURA §38.072, which requires an electric utility to give nursing facilities, assisted living facilities and hospice facilities the same priority that it gives to a hospital in the utility's emergency operations plan for restoring power after an extended outage; and §38.074, which requires the commission to, in collaboration with the Railroad Commission of Texas, rules to establish a process to designate certain natural gas facilities and entities as critical natural gas customers during energy emergencies and to require utilities to prioritize these facilities for load-shed and power restoration purposes during an energy emergency.
Cross Reference to Statute: Public Utility Regulatory Act §§14.001, 14.002, 38.005, 38.072, 38.074.
§25.52.Reliability and Continuity of Service.
(a) Application. This section applies to all electric utilities as defined by §25.5 of this title (relating to Definitions) and all transmission and distribution utilities as defined by §25.5 of this title. When specifically stated, this section also applies to electric cooperatives and municipally-owned utilities (MOUs). The term "utility" as used in this section means an electric utility and a transmission and distribution utility.
(b) General.
(1) Every utility must make all reasonable efforts to prevent interruptions of service. When interruptions occur, the utility must reestablish service within the shortest possible time.
(2) Each utility must make reasonable provisions to manage emergencies resulting from failure of service, and each utility must issue instructions to its employees covering procedures to be followed in the event of emergency in order to prevent or mitigate interruption or impairment of service.
(3) In the event of national emergency or local disaster resulting in disruption of normal service, the utility may, in the public interest, interrupt service to other customers to provide necessary service to civil defense or other emergency service entities on a temporary basis until normal service to these agencies can be restored.
(4) Each utility must maintain adequately trained and experienced personnel throughout its service area so that the utility is able to fully and adequately comply with the service quality and reliability standards.
(5) With regard to system reliability, a utility must not neglect any local neighborhood or geographic area, including rural areas, communities of less than 1,000 persons, and low-income areas.
(6) Each utility that provides distribution service to retail customers must maintain an accurate and publicly available online outage tracker or outage map on its website.
(A) An online outage tracker or outage map must contain a map of the utility's distribution service territory that identifies, for each active outage impacting retail distribution customers, the approximate location of the outage, the date and time the outage was reported or otherwise identified, an estimated restoration time, the general status of the restoration effort, and the date and time the outage and restoration status information was most recently updated. Information provided by the outage tracker or outage map under this subparagraph must be updated to include new or updated service addresses in the utility's service territory as soon as practicable, and be available in English and Spanish, as applicable.
(B) If a utility's outage tracker or outage map is scheduled to be taken offline or may otherwise become unavailable due to maintenance or upgrades, the utility must post details of the scheduled activity on its website and provide notice of the scheduled activity to the commission's Consumer Protection and Critical Infrastructure Security and Risk Management divisions no later than seven days prior to the scheduled activity. A utility must, as soon as reasonably practicable, notify the commission in writing if the utility's outage tracker or outage map unexpectedly becomes unavailable or if the utility determines that maintenance is required within the next seven days.
(C) An outage tracker or outage map must provide or link to information that indicates the different methods a customer may use to report an outage or hazardous condition and provide or link to information on how a customer may request to receive updates on the status of outages and outage restoration efforts. The outage tracker or outage map must include at least one digital means for a customer to report an outage to the utility.
(D) Each utility must comply with each of the requirements of this paragraph upon the effective date of this rule except as provided in this subparagraph. A that utility requires additional time to upgrade its outage tracker or outage map to comply with one or more requirements of this paragraph must file an update in this project no later than five working days after the effective date of this rule identifying which requirements it is not capable of complying with, a brief explanation for why immediate compliance is infeasible, and a projected compliance date that is no later than June 1, 2025. A utility may delay compliance with any requirement described in a filing under this subparagraph until the earlier of its projected compliance date and June 1, 2025.
(c) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise.
(1) Critical loads--Loads for which electric service is considered crucial for the protection or maintenance of public safety; including but not limited to hospitals, police stations, fire stations, critical water and wastewater facilities, and customers with special in-house life-sustaining equipment.
(2) Critical natural gas facility--A facility designated as a critical customer by the Railroad Commission of Texas under §3.65(b) of this title (relating to Critical Designation of Natural Gas Infrastructure) unless the facility has obtained an exception from its critical status. Designation as a critical natural gas facility does not guarantee the uninterrupted supply of electricity.
(3) Energy emergency--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.
(4) Interruption classifications:
(A) Forced--Interruptions, exclusive of major events, that result from conditions directly associated with a component requiring that it be taken out of service immediately, either automatically or manually, or an interruption caused by improper operation of equipment or human error.
(B) Scheduled--Interruptions, exclusive of major events, that result when a component is deliberately taken out of service at a selected time for purposes of construction, preventative maintenance, or repair. If it is possible to defer an interruption, the interruption is considered a scheduled interruption.
(C) Outside causes--Interruptions, exclusive of major events, that are caused by influences arising outside of the distribution system, such as generation, transmission, or substation outages.
(D) Major events--Interruptions that result from a catastrophic event that exceeds the design limits of the electric power system, such as an earthquake or an extreme storm. These events must include situations where there is a loss of power to 10% or more of the customers in a region over a 24-hour period and with all customers not restored within 24 hours.
(5) Interruption, momentary--Single operation of an interrupting device which results in a voltage zero and the immediate restoration of voltage.
(6) Interruption, sustained--All interruptions not classified as momentary.
(7) Interruption, significant--An interruption of any classification lasting one hour or more and affecting the entire system, a major division of the system, a community, a critical load, or service to interruptible customers; and a scheduled interruption lasting more than four hours that affects customers that are not notified in advance. A significant interruption includes a loss of service to 20% or more of the system's customers, or 20,000 customers for utilities serving more than 200,000 customers. A significant interruption also includes interruptions adversely affecting a community such as interruptions of governmental agencies, military bases, universities and schools, major retail centers, and major employers.
(8) Reliability indices:
(A) System Average Interruption Frequency Index (SAIFI)--The average number of times that a customer's service is interrupted. SAIFI is calculated by summing the number of customers interrupted for each event and dividing by the total number of customers on the system being indexed. A lower SAIFI value represents a higher level of service reliability.
(B) System Average Interruption Duration Index (SAIDI)--The average amount of time a customer's service is interrupted during the reporting period. SAIDI is calculated by summing the restoration time for each interruption event times the number of customers interrupted for each event and dividing by the total number of customers. SAIDI is expressed in minutes or hours. A lower SAIDI value represents a higher level of service reliability.
(d) Record of interruption. Each utility must keep complete records of sustained interruptions of all classifications. Where possible, each utility must keep a complete record of all momentary interruptions. These records must show the type of interruption, the cause for the interruption, the date and time of the interruption, the duration of the interruption, the number of customers interrupted, the substation identifier, and the transmission line or distribution feeder identifier. In cases of emergency interruptions, the remedy and steps taken to prevent recurrence must be recorded. Each utility must retain records of interruptions for five years.
(e) Notice of significant interruptions.
(1) Initial notice. A utility must notify the commission, in a method prescribed by the commission, as soon as reasonably possible after it has determined that a significant interruption has occurred. The initial notice must include the general location of the significant interruption, the approximate number of customers affected, the cause if known, the time of the event, and the estimated time of full restoration. The initial notice must also include the name and telephone number of the utility contact person and must indicate whether local authorities and media are aware of the event. If the duration of the significant interruption is greater than 24 hours, the utility must update this information daily and file a summary report.
(2) Summary report. Within five working days after the end of a significant interruption lasting more than 24 hours, the utility must submit a summary report to the commission. The summary report must include the date and time of the significant interruption; the date and time of full restoration; the cause of the interruption, the location, substation and feeder identifiers of all affected facilities; the total number of customers affected; the dates, times, and numbers of customers affected by partial or step restoration; and the total number of customer-minutes of the significant interruption (sum of the interruption durations times the number of customers affected).
(f) Priorities for power restoration to certain medical facilities.
(1) A utility must give the same priority that it gives to a hospital in the utility's emergency operations plan for restoring power after an extended power outage, as defined by Texas Water Code, §13.1395, to the following:
(A) An assisted living facility, as defined by Texas Health and Safety Code, §247.002;
(B) A facility that provides hospice services, as defined by Texas Health and Safety Code, §142.001;
(C) A nursing facility, as defined by Texas Health and Safety Code, §242.301; and
(D) An end stage renal disease facility, as defined by Texas Health and Safety Code, §251.001.
(2) The utility may use its discretion to prioritize power restoration for a facility after an extended power outage in accordance with the facility's needs and with the characteristics of the geographic area in which power must be restored.
(g) System reliability. Reliability standards apply to each utility and are limited to the Texas jurisdiction. A "reporting year" is the 12-month period beginning January 1 and ending December 31 of each year.
(1) System-wide standards. The standards must be unique to each utility based on the utility's performance and may be adjusted by the commission if appropriate for weather or improvements in data acquisition systems. The standards will be the average of the utility's performance from the later of reporting years 1998, 1999, and 2000, or the first three reporting years the utility is in operation.
(A) SAIFI. Each utility must maintain and operate its electric distribution system so that its SAIFI value does not exceed its system-wide SAIFI standard by more than 5.0%.
(B) SAIDI. Each utility must maintain and operate its electric distribution system so that its SAIDI value does not exceed its system-wide SAIDI standard by more than 5.0%.
(2) Distribution feeder performance. The commission will evaluate the performance of distribution feeders with ten or more customers after each reporting year. Each utility must maintain and operate its distribution system so that no distribution feeder with ten or more customers sustains a SAIDI or SAIFI value for a reporting year that is more than 300% greater than the system average of all feeders during any two consecutive reporting years.
(3) Enforcement. The commission may take appropriate enforcement action, including action against a utility, if the system and feeder performance is not operated and maintained in accordance with this subsection. In determining the appropriate enforcement action, the commission will consider:
(A) the feeder's operation and maintenance history;
(B) the cause of each interruption in the feeder's service;
(C) any action taken by a utility to address the feeder's performance;
(D) the estimated cost and benefit of remediating a feeder's performance; and
(E) any other relevant factor as determined by the commission.
(h) Critical natural gas facilities. In accordance with §3.65 of this title, critical natural gas standards apply to each facility in this state designated as a critical customer under §3.65 of this title. In this subsection, the term "utility" includes MOUs, electric cooperatives, and entities considered utilities under subsection (a) of this section.
(1) Critical customer information.
(A) In accordance with §3.65 of this title, the operator of a critical natural gas facility must provide critical customer information to the entities listed in clauses (i) and (ii) of this subparagraph. The critical customer information must be provided by email using Form CI-D and any attachments, as prescribed by the Railroad Commission of Texas.
(i) The utility from which the critical natural gas facility receives electric delivery service; and
(ii) For critical natural gas facilities located in the ERCOT region, the independent organization certified under PURA §39.151.
(B) The commission will maintain on its website a list of utility email addresses to be used for the provision of critical customer information under subparagraph (A) of this paragraph. Each utility must ensure that the email address listed on the commission's website is accurate. If the utility's email address changes or is inaccurate, the utility must provide the commission with an updated email address within five business days of the change or of becoming aware of the inaccuracy.
(C) Within ten business days of receipt, the utility must evaluate the critical customer information for completeness and provide written notice to the operator of the critical natural gas facility regarding the status of its critical natural gas designation.
(i) If the information submitted is incomplete, the utility's notice must specify what additional information is required and provide a deadline for response that is no sooner than five business days from when the critical natural gas facility receives the written notice. If the utility does not receive the additional information in a timely fashion, the utility may use its discretion to determine if it is possible to treat the natural gas facility as critical for load shed and power restoration purposes.
(ii) If the information submitted is complete, the utility's notice must notify the operator of the facility's critical natural gas status, the date of its designation, any additional classifications assigned to the facility by the utility, and notice that its critical status does not constitute a guarantee of an uninterrupted supply of energy.
(iii) A utility must provide an additional notice to the operator of the critical natural gas facility regarding any changes to the information provided in the notice required under clause (i) of this subparagraph. Notice must be provided within ten business days of the effective date of the change.
(D) A utility or an independent system operator receiving or sending critical customer information regarding a critical natural gas facility under this subsection must not release critical customer information to any person unless authorized by the commission or the operator of the critical natural gas facility. This prohibition does not apply to the release of such information to the commission, the Railroad Commission of Texas, the utility from which the critical natural gas facility receives electric delivery service, the designated transmission operator, or the independent system operator or reliability coordinator for the power region in which the critical natural gas facility is located. This prohibition also does not apply if the critical customer information is redacted, aggregated, or organized in such a way as to make it impossible to identify the critical natural gas facility to which the information applies.
(2) Prioritization of critical natural gas facilities. A critical natural gas facility is a critical load during an energy emergency. A utility must incorporate critical natural gas facilities into its load-shed and restoration planning. For purposes of this paragraph, a utility may also treat a natural gas facility that self-designated as critical using the Application for Critical Load Serving Electric Generation and Cogeneration form as a critical natural gas facility, as circumstances require.
(A) A utility must prioritize critical natural gas facilities for continued power delivery during an energy emergency.
(B) A utility may use its discretion to prioritize power delivery and power restoration among critical natural gas facilities and other critical loads on its system, as circumstances require.
(C) A utility must consider any additional guidance or prioritization criteria provided by the commission, the Railroad Commission of Texas, or the reliability coordinator for its power region to prioritize among critical natural gas facilities and other critical loads during an energy emergency.
(D) Compliance with directives of a regional transmission organization having authority over a utility outside of the ERCOT power region will be deemed compliance for that utility.
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 February 13, 2025.
TRD-202500520
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: March 5, 2025
Proposal publication date: August 30, 2024
For further information, please call: (512) 936-7322
The Public Utility Commission of Texas (commission) adopts new 16 Texas Administrative Code (TAC) §25.512, relating to Texas Energy Fund (TEF) Grants for Facilities outside of the ERCOT Region (Outside of ERCOT Grant Program or OEGP). The commission adopts this rule with changes to the proposed text as published in the October 11, 2024, issue of the Texas Register (49 TexReg 8267) and will be republished. New §25.512 implements Public Utility Regulatory Act (PURA) §34.0103 and §34.0106, enacted as part of Senate Bill (SB) 2627 during the 88th Texas Legislature (R.S.). The new rule will establish procedures for applying for a grant award and the requirements and terms for grants to finance modernization, weatherization, reliability and resiliency enhancements, and vegetation management for transmission and distribution infrastructure and electric generation facilities in this state outside of the ERCOT region. The rule is adopted in Project No. 57004.
The commission received comments on the proposed rule from Arkansas Electric Cooperative Corporation (AECC), El Paso Electric Company (EPE), East Texas Distribution Cooperatives (ETDC), Entergy Texas (ETI), Golden Spread Electric Cooperative (Golden Spread), Hecate Grid, Sierra Club, Southwestern Electric Power Company (SWEPCO), Southwestern Public Services Company (SPS), Texas Electric Cooperatives (TEC), and Texas Public Power Association (TPPA).
Entity Eligibility and Expectations
Being eligible to submit an application does not guarantee receiving funds. Each applicant is encouraged to group projects into a single application and prioritize projects according to the applicant's identified needs because this will streamline evaluation. After submission, each application will undergo a detailed review process that includes initial screening for basic eligibility, followed by a comprehensive evaluation of the applicant's experience, the specifics of each proposed project, and how a project aligns with the OEGP goals. If an application is approved for an award, the recipient will be subject to ongoing monitoring and reporting to evaluate compliance and track progress. Each recipient must regularly report on its activities and outcomes to demonstrate effective use of the funds. Because of the potential range of projects, terms and requirements for monitoring, tracking, and reporting will be mutually agreed by each recipient and the TEF administrator and reflected in the associated grant agreement, rather than by rule.
Project Period of Performance
Although the adopted rule does not specify a period of performance for the projects that will be awarded, the commission's purpose is to prioritize "shovel ready" projects with impacts that can be realized in the near term. A shorter period of performance for these projects mitigates risks associated with project execution by providing for a manageable timeframe, reducing the likelihood of delays and cost overruns. This approach also aligns with legislative intent to expedite the implementation of projects, supporting prompt and efficient realization of intended benefits. Setting a shorter performance period enables the TEF administrator to more closely monitor progress, address issues swiftly, and assist projects to remain on track to meet objectives.
General Comments
Projects within Multiple Grids
TEC requested clarification from the commission that projects that benefit multiple grids, including the ERCOT region, are not precluded from receiving funding under the OEGP. TEC stated that some of its member cooperatives have service territories that span multiple power regions, and some projects intended for areas in Texas outside of ERCOT may also provide benefits to the ERCOT region. TEC emphasized that it may be physically impractical to limit the resiliency benefits of a project to outside the ERCOT region alone.
Commission Response
The commission agrees with TEC that project benefits may not always be limited to a single power region. However, the purpose of this program is to benefit areas in Texas that are outside of the ERCOT region. Therefore, the commission modifies subsection (c)(2)(B)(i) of the rule to require an application to include a description of benefits to all geographic areas that a project will provide, not just those areas in Texas outside the ERCOT region. This will allow the commission to determine the percentage of the project that will benefit areas of Texas outside of ERCOT, as necessary. A project approved by this program must deliver a significant majority of its benefits to areas in Texas that are outside of the ERCOT region.
In addition, only those parts of a project within Texas outside of ERCOT are eligible for funding through this program, and the commission adds subsection (e)(2) to clarify this point.
Public Comments
Proposed §25.512(b)(1)(A) - Applicant Eligibility
Proposed §25.512(b)(1)(A) describes the types of electric generating facilities eligible for a grant award and includes a qualifying facility (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA) as an eligible facility type.
ETI and EPE recommended that the provision allowing a QF as an eligible facility type be removed. ETI emphasized that public funding should be used to assist a certificated, load-serving entity, not a private entity serving its own interests. ETI contended that subsection (b)(1)(A) was likely included based on PURA §34.0106(b), which prevents the commission from providing funding for a facility that will be used primarily to serve an industrial load or private use network. ETI argued that public grant funds should not be awarded to any private entity serving its own interests. Rather, ETI believed that PURA §34.0106(b) was meant to prevent otherwise eligible entities (e.g., investor-owned utilities, MOUs, or river authorities) from using public funding to primarily serve one customer and not that utility's other customers. In addition, ETI argued that a QF cannot be controlled or relied upon by either the commission or utilities to ensure resource adequacy in the way a load-serving entity can be, and providing funding for such an entity would reduce the total amount available for utilities that serve the public.
EPE emphasized that the purpose of the rule is to support critical infrastructure projects that increase the state's resilience. By removing this provision, EPE believed that funds can be more effectively directed towards critical infrastructure needs, thereby enhancing the overall energy resilience of the state. ETI and EPE provided redlines consistent with their recommendations.
Commission Response
The commission declines to modify the rule to remove a QF as an eligible facility type because a QF could meet the statutory requirements for a grant under PURA §34.0103, and the commission does not have authority to disregard a QF's eligibility if it operates in Texas outside of the ERCOT region. The commission disagrees with ETI that this will result in grant funds being awarded to an electric generating facility that primarily serves one customer because the restriction in PURA §34.0106(b) prevents the commission from providing TEF funding to any electric generating facility that primarily serves an industrial load or PUN, regardless of the ownership of that electric generating facility. The commission has interpreted this provision in its other TEF rules (16 TAC §25.510 and §25.511) to mean that any electric generating facility that serves an industrial load or PUN, regardless of its ownership, must primarily serve the grid to be eligible for funding. If a QF serves an industrial load or PUN, that QF must meet the other requirements in subsection (b)(5) to be eligible for funding through this program.
Proposed §25.512(b)(1)(B) - Applicant Eligibility
Proposed §25.512(b)(1)(B) states an applicant must be compliant with the requirements in the Lone Star Infrastructure Protection Act (LSIPA) to be eligible for a grant.
TPPA recommended that an entity not be required to attest to its compliance with the LSIPA. TPPA agreed with requiring LSIPA compliance for the in-ERCOT loan and grant rules because, first, those rules supported construction of new generation resources, and second, ERCOT had already established a form that an applicant for those programs could reproduce. Conversely, TPPA stated that this rule targets facility modernization and reliability and resiliency enhancements, and the forms and processes for within the ERCOT region are not available to applicants outside the ERCOT region. TPPA argued that requiring LSIPA compliance could hinder the ability of utilities to modernize and enhance reliability and resiliency because some applications could include projects to replace non-compliant equipment. Therefore, TPPA suggested removing this compliance requirement.
Commission Response
The commission declines to remove the requirement for an applicant to attest to its compliance with the LSIPA. Requiring compliance with the LSIPA is a reasonable exercise of the commission's discretion in determining eligibility for public grant funds, especially because existing transmission and distribution infrastructure is as much a part of the critical infrastructure of this state as a new electric generating facility is, and the LSIPA applies to all owners and operators of critical infrastructure in Texas.
Proposed §25.512(b)(2) and §25.512(c) - Terminology
Proposed §25.512(b)(2) describes the project eligibility of the program. Proposed §25.512(c) describes the guidance, including rules and restrictions, regarding the application process.
TPPA recommended that the commission transpose sections of proposed §25.512(b)(2) and §25.512(c) because, TPPA argued, §25.512(b)(2)'s reference to measures is likely more appropriate for provisions governing the application itself, and §25.512(c)'s prohibition on multiple applications for the same objective makes more sense if placed with provisions governing project eligibility.
TPPA also recommended that the proposed rule language in §25.512(c)(2)(A)(v) include a citation to §25.512(b), "Project Eligibility," as opposed to §25.512(c). TPPA commented that the current reference to §25.512(c) appears to be a circular reference.
Commission Response
The commission declines to transpose language related to the projects, measures, and applications, as suggested by TPPA, because the rule is clear and understandable as is. However, the commission agrees that proposed subsection (c)(2)(A)(v) includes an incorrect reference to subsection (c) and modifies the rule to correct this.
Proposed §25.512(b)(3), §25.512(b)(3)(C), and §25.512(b)(3)(D) - Project Eligibility
Proposed §25.512(b)(3) lays out all the objectives eligible for a grant, including reliability and resiliency (subsection (b)(3)(C)) and vegetation management (subsection (b)(3)(D)).
TEC, ETI, ETDC, Golden Spread, Sierra Club, and TPPA requested that the commission clarify that the lists of items under each project objective in proposed §25.512(b)(3)(A) - (D) are examples and not an exclusive limit on what an applicant can seek for funding.
TEC advocated for a broader range of project eligibility, highlighting that certain projects, such as transformer restoration and upgrades and increasing the elevation or clearance height of electric lines, which are not included in the existing lists, still meet the objectives. TEC stated concerns that listing examples of specific eligible projects, without clarification, creates an implication that those are the only project objectives eligible for a grant, and suggested that it would be a futile exercise to attempt to create an all-encompassing list of eligible projects within the rule language. ETDC agreed with TEC's comments and further explained that it believed that the OEGP should be implemented liberally and broadly, in such a way that would give rural areas fair and broad access to the grant program as the legislature intended. Sierra Club stated that making the project lists examples, and not exclusive lists, would allow for energy efficiency and other demand-side resiliency solutions to be eligible if they meet one of the objectives. TPPA also requested clarification as to whether the project lists are exclusive because, for example, activities that fortify against fire, high winds, or freezing are not included in the project lists, but fortification against flooding is included. In suggesting that the lists be non-exclusive, Golden Spread argued that it would be impractical to attempt to identify all the potential activities that could meet the statutory objectives.
ETI also recommended that the project lists not be exclusive; rather, the introductory language should read: "Projects including, but not limited to." ETI also suggested that the commission add vegetation management projects specifically designed to mitigate wildfire risk to the list of measures contained in the vegetation management objective. ETI noted that vegetation can serve as fuel for wildfires, and targeted vegetation management can mitigate the potential for the ignition or spread of wildfires by reducing the potential fuel load.
SPS provided recommended redline revisions for draft rule §25.512(b)(3)(C) but no comments in support of the proposed redline revisions.
Commission Response
The subcategories under each project objective are exclusive. An exclusive list of eligible subcategories provides clarity for applicants and streamlines the grant administration processes of review and monitoring, allowing funds to be disbursed more quickly. However, the commission modifies §25.512(b)(3)(C), related to reliability and resiliency, to add undergrounding as a subcategory and clarify that "hardening" refers to electric transmission and distribution infrastructure. The commission also modifies the rule to clarify that the subcategories are an exclusive list and that applicants must specific which subcategory each project falls into.
Other measures suggested may fall under measures already in the proposed rule. Subsection (b)(3)(A) - (D) describe subcategories of each objective, each of which could include different project types. For example, TEC's suggestion of transformer restoration and upgrades would be covered by the reliability and resiliency objective (subparagraph (C)), and its suggestion of increasing the elevation or clearance height of electric lines would be covered by the facility weatherization objective (subparagraph (B)) or the reliability and resiliency objective (subparagraph (C)). TPPA's example of fortification against fire, high winds, or freezing would be covered by the facility weatherization objective (subparagraph (B)). TEC's suggested addition of specific wildfire risk mitigation measures is unnecessary because subcategories listed under subsection (b)(3)(D) already include such measures. For this reason, the commission declines to modify the rule to add the suggested project types to the lists of projects that meet each objective.
Parallel eligibility requirements in resiliency plans
ETI recommended adding additional project types to the eligibility lists, such as the resiliency measures listed in 16 TAC §25.62(c)(1), relating to Transmission and Distribution System Resiliency Plans, to the list of measures that meet the reliability and resiliency objective. ETI stated that this would maintain consistency and alignment between rules.
Commission Response
The commission declines to modify the rule to tie definitions and instances of "resiliency measures" in the OEGP with system resiliency plans, as defined in 16 TAC §25.62. Although, broadly speaking, the OEGP and system resiliency plans have similar goals, these are separate programs with specific objectives, funding mechanisms, and authorizing statutory language. Accordingly, direct adoption, alignment of terms, or inclusion by reference between the programs is not appropriate.
Furthermore, because of the enumerated differences between the two programs and to align with recent commission contested case decisions, the commission modifies the rule to add subsection (b)(4)(J), which disallows OEGP funding for any project that is included as a measure in a resiliency plan approved under 16 TAC §25.62. This modification ensures that a single project cannot both be recoverable through a resiliency plan and funded through the TEF.
Proposed §25.512(b)(3)(A) - Facility Modernization
Proposed §25.512(b)(3)(A) describes the facility modernization objective.
SWEPCO requested that the new rule interpret "facility modernization" broadly to include repowering a generating station to use a different fuel type and extending its useful life, thereby fostering a reliable and sufficient power supply. SWEPCO argued that by allowing the use of grants for upgrades of an existing generating station, the rule would adhere to the meaning of "modernization" and enable the TEF to foster power supply in areas of Texas outside the ERCOT region just as it is being used for the same purpose within the ERCOT region.
Commission Response
The commission declines to classify repowering a generating station as facility modernization, as recommended by SWEPCO, because changing the fuel and prime mover of an electric generating facility does not align with the facility modernization objective of the OEGP. The purpose and dollar amount available for the TEF loan and grant programs within ERCOT are different from the purpose and dollar amount available for the OEGP; therefore, the eligible project types differ between these programs.
Applicant Eligibility
TPPA recommended that the description of the reliability and resiliency objective be revised to maintain the eligibility of MOUs, cooperatives, and river authorities. TPPA pointed out that the commission's standard definition of "electric utility" does not include MOUs or electric cooperatives and recommended replacing the term with "electric utility, electric cooperative, or municipally owned utility."
TPPA also recommended revisions to the term "facility" throughout the rule language because the term is not defined in the rule, and the commission's standard definition references only electric utilities and excludes MOUs and cooperatives. TPPA recommended using the term "electric generation facilities and transmission and distribution infrastructure" in place of the term "facility," or a more specific term where needed.
Commission Response
The commission agrees with TPPA's recommendation to address the meaning of "electric utility" and "facility" to maintain the eligibility of MOUs, cooperatives, and river authorities for the program objectives and to distinguish transmission and distribution infrastructure from an electric generating facility where necessary. The commission modifies the rule accordingly throughout. Because of this change, the term "electric generating facility," which is a defined term in the commission's rules under §25.5, is used in the adopted rule rather than "facility" and does not need to be defined.
Proposed §25.512(b)(4)(E) - Exclusion of new generation resources from eligibility
Proposed §25.512(b)(4)(E) excludes the eligibility of construction of new electric generation resources.
AECC and Golden Spread both recommended that the commission modify the provision's language to allow the construction of new generating facilities as eligible for OEGP funding. AECC argued that this inclusion is crucial to support grid reliability, resiliency, and economic growth and emphasized that new generation resources bring modernization, efficiencies, and weatherization improvements that retrofitting older plants cannot achieve. AECC stated that this change aligns with §49q of the Texas Constitution and the Public Utility Regulatory Act, which aim to ensure grid reliability. AECC also argued that grants awarded to electric cooperatives would offset costs, reduce the need to raise rates, and ensure affordable electricity for member owners, especially in rural areas.
Golden Spread recommended removing section §25.512(b)(4)(E) from the rule. It argued that the exclusion of new electric generation resources is not supported by PURA §34.0103, which permits grant money to be used for various infrastructure enhancements and does not prohibit funding for new electric generating facilities. Because every project will involve new infrastructure--whether a pole, or weather-resistant equipment, or wires--Golden Spread believed that disallowing new infrastructure or facilities renders PURA §34.0103 meaningless. Golden Spread stated that new quick start dispatchable generation resources, such as natural gas-fired units, are critical for improving grid reliability and resiliency, especially in balancing the variability of renewable energy sources. Golden Spread stated that it recognized that not all new electric generating resource projects may be appropriate for a grant but argued they should at least be eligible for review. Golden Spread argued for the commission to use its discretion to review these projects on their individual merits.
TPPA recommended using the term "electric generation facility" instead of "electric generation resource" in §25.512(b)(4)(E) to match the terminology used throughout the rest of the proposed rule, as well as in the statute.
Commission Response
The commission declines to modify the rule to allow for new generation resources to be eligible for funding from the program, as recommended by AECC and Golden Spread. First, PURA §34.0103 specifically allows grants to modernize, weatherize, or enhance reliability and resiliency of infrastructure or a facility, indicating that the infrastructure or facility must already exist before it can be modernized, weatherized, or have its reliability or resiliency enhanced. Second, PURA §34.0103 outlines four specific categories, none of which encompass the construction of new generation facilities. Third, the cost associated with new generation construction does not align with the statutorily authorized funding available through the OEGP. Funding for the OEGP is capped at $1 billion, as opposed to a total of $7.2 billion authorized for the in-ERCOT loans and completion bonus grant programs, both of which have the explicit purpose of new construction. Because the funding amounts differ so drastically, and the purpose of new construction is omitted from the statutory language, the commission concludes that the legislative intent for the OEGP was only to fund the specific objectives outlined in the statute, not construction of new electric generating facilities.
The commission declines to change the terminology to "facility" from "resource," as recommended by TPPA. Use of the term "resource" in subsection (b)(4)(E) is purposeful because construction of new generation resources at an existing electric generating facility is not eligible for funding under this program, just as construction of a new electric generating facility itself is not.
Proposed §25.512(b)(3)(C) and §25.512(b)(4)(E) - Battery storage as an eligible project
Proposed §25.512(b)(3)(C) describes the reliability and resiliency objective, which specifically allows battery storage as an eligible project subcategory. Proposed §25.512(b)(4)(E) excludes construction of a new generation resource from funding under the OEGP.
Hecate Grid sought clarification on whether a battery storage system, especially a new build battery storage system, would be excluded from eligibility, as might be concluded under §25.512(b)(4)(E). Hecate Grid stated that a battery storage system that is to be newly energized will require construction and engineering activities, which involved parties may consider excluded from funding due to proposed §25.512(b)(4)(E). SWEPCO also stated that §25.512(b)(4)(E) could be interpreted to preclude the construction of a new utility battery energy storage system, contradicting the objectives in §25.512(b)(3)(C).
TEC recommended that an energy storage project used to sell energy or ancillary services at wholesale be excluded from the rule because this type of energy storage resource is considered a generation asset under Texas statute. TEC argued that the proposed rule expressly excludes new generation from eligibility, and this prohibition should extend to battery storage that is considered a generation asset.
Sierra Club suggested that the commission add language to the rule making energy storage technology for resiliency eligible for funding, except when its primary objective is to provide wholesale power to the market.
TEC and Sierra Club provided redlines consistent with their recommendations.
Commission Response
The commission agrees with TEC and Sierra Club that energy storage resources that provide energy and ancillary services at wholesale are a generation resource and, therefore, excluded from eligibility under this program. The Texas statute referred to by TEC, PURA §35.152, applies only within the ERCOT region. However, the commission interprets PURA §34.0103 to allow only modernization, weatherization, reliability and resiliency enhancements, and vegetation management as eligible objectives. Construction of a new generation resource is not among the eligible objectives, and a battery storage project that will provide energy like a generation resource is considered a generation resource for purposes of the OEGP, regardless of the geographic applicability of PURA §35.152. On the other hand, a battery storage project that improves the reliability or resiliency of transmission or distribution infrastructure or existing electric generating facility would be eligible. The commission modifies subsection (b)(4)(E) to clarify this point. In addition, like battery storage, generation may support transmission or distribution resiliency. For this reason, the commission also modifies (b)(4)(E) of the proposed rule to allow generation to be eligible for the limited purpose of supporting transmission or distribution resiliency.
The commission also modifies subsection (b)(3)(C) to state that battery storage or a generation resource that serves to maintain or restore energization of transmission or distribution infrastructure is an eligible subcategory. This modification ensures that any type of resource that supports resiliency of the transmission or distribution system is an eligible subcategory but maintains the funding exclusion of new generation in proposed (b)(4)(E).
Proposed §25.512(b)(4)(E) and §25.512(b)(4)(F) - Funding Exclusions
Proposed §25.512(b)(4)(E) excludes the construction of new electric generation resources as eligible for funding. Proposed §25.512(b)(4)(F) excludes operations expenses associated with any project funded by a grant.
SPS, TPPA, and SWEPCO suggested that both of these provisions be removed from the rule because they are not consistent with legislative intent. SPS argued that if the legislature had wanted to exclude construction of new electric generating facilities in this section of SB 2627, it would have expressly stated this prohibition in the bill, but that the law is silent on this topic. In addition, §49q of the Texas constitution lists construction of new electric generating facilities as eligible for funding under the TEF. SPS argued that this evidence shows that the legislature's intent was to specifically allow new electric generating facilities as an eligible project type under this program. TPPA stated that subsections (b)(4)(E) and (F) exceed statutory authority under PURA §34.0103, do not align with the funding exclusions specifically enumerated by the legislature, and should be removed. SWEPCO argued that these provisions do not align with the exclusions listed in PURA §34.0103 and that their source is unclear.
Specifically related to subsection (b)(4)(F), ETI requested that the draft rule be clarified to state that operations expenses associated with approved vegetation management projects and expenses appropriately capitalized as part of developing and placing a capital investment in service are not subject to the funding exclusions of the grant program. SWEPCO also requested the latter clarification. Additionally, SWEPCO stated that §25.512(b)(4)(F) might prohibit grants for valid operation and maintenance expenses, such as vegetation management, which is an express purpose of the TEF. SWEPCO further stated that §25.512(b)(4)(F) conflicts with the application process described in §25.512(c)(2)(D)(ii), which requires estimated project costs to include operating expenses. TPPA suggested that, if the adopted rule retains this provision, the commission define "operations expenses."
ETI, SWEPCO, and SPS provided redlines consistent with their recommendations.
Commission Response
The commission declines to modify the rule to remove §25.512(b)(4)(E) for the reasons enumerated in the section above, where this subsection is discussed. The commission also declines to modify the rule to remove §25.512(b)(4)(F) because one-time grant funds from a taxpayer-funded program should not be used to pay for regular operations and maintenance expected of a utility. However, expenses associated with the installation and the initial operations and commissioning or startup of a project are already eligible for program funding under the adopted rule, and the commission declines to add explicit language for this notion. Specifically, allowable vegetation management costs under subsection (b)(3)(D) of the adopted rule are capital costs, such as equipment purchased to trim vegetation or installation of drought-resistant vegetation. Ongoing operations expenses associated with vegetation management are not eligible for funding through this program. To eliminate potential confusion over eligible vegetation management-related costs, the commission modifies subsection (b)(3)(D) of the rule to state that eligible measures are "capital costs related to vegetation management not already included in the eligible applicant's rate base." The commission also modifies proposed subsection (e)(2) to remove the reference to vegetation management expenses.
The commission also declines to add a definition for "operations expenses" because it is unnecessary. This is a commonly understood accounting term distinguishable from capital costs.
The commission disagrees with SWEPCO's assertion that there is a conflict between the application requirement to submit operations expenses for a grant-funded project and the prohibition on grant funding for ongoing operations expenses. Having operations expenses for a grant-funded project gives the TEF administrator an evaluation point to determine whether the project is worthy of receiving grant funding. And, for the reasons articulated above, the adopted rule disallows operations expenses as an eligible cost.
Proposed §25.512(b)(5) - PUNs
Proposed §25.512(b)(5) describes the conditions that make an electric generating facility that serves an industrial load or PUN eligible for a grant.
TEC noted that it was unclear under the proposed rule language if a PUN would be able to utilize grant funds for a new facility and recommended amending the proposed rule language to expressly exclude the funding of a new electric generation resource associated with a PUN. TEC did not oppose the use of grant funds for new generation but stated that a PUN should have the same limitations as other electric providers.
TPPA agreed with the limitations proposed on PUNs and industrial loads in the proposed rule language. TPPA recommended that the language be expanded, such that utility-owned transmission and distribution infrastructure must also not be primarily used to serve a PUN or industrial load, in the same way that the current proposed language excludes an electric generating facility that primarily serves a PUN or industrial load. TPPA further recommended adding language to the proposed rule to clarify that the relevant meter is the transmission and distribution service provider's meter that is used for settlements.
Sierra Club recommended clarifying that a PUN can only use grant funding to augment existing generation and only for the portion of the project that meets the criteria set in §25.512(b).
TPPA and Sierra Club provided redlines consistent with their recommendations.
Commission Response
The commission declines to add language expressly excluding new generation resources associated with a PUN, as requested by TEC and Sierra Club, because it is unnecessary. New generation does not fall into any of the four specific objectives, so no new generation would be allowed for an electric generating facility serving an industrial load or PUN, just as with any other applicant.
With regards to transmission and distribution infrastructure, the commission agrees with TPPA's recommendation to clarify that the settlement meter is the demarcation point and modifies the rule accordingly. However, the commission declines to modify the rule to restrict eligibility for investor-owned transmission and distribution infrastructure that primarily serves an industrial load or PUN, because unlike generation facilities on the private use side of the meter, transmission and distribution infrastructure on the public use side of the meter is funded by the service provider, not the private entity. Moreover, abiding by a clear line of demarcation at the settlement meter allows a more precise determination of which projects are eligible for grant awards. Moreover, a utility applicant may be expecting load growth in an area that would justify an investment that, in the immediate term, might appear to benefit only a small number of customers.
The commission agrees with Sierra Club's recommendation to limit grant funding for an electric generating facility that serves an industrial load or PUN to only the portion of the project that does not serve the industrial load or PUN and adds subsection (e)(3) to the rule to state this. This modification aligns this rule with the commission's other TEF rules (16 TAC §25.510 and §25.511), which, in the case of an electric generating facility serving an industrial load or PUN, allow funding only for the portion of the facility's capacity that is dedicated to the grid.
Proposed §25.512(c) - Application restriction
Proposed §25.512(c) disallows an application for a project with the same objective as a project that the same applicant already applied for within the past 24 months.
TEC, ETI, and Sierra Club recommended that the commission change the wait times for a project with the same objective. TEC and ETI both requested that the commission remove the prohibition altogether, and Sierra Club suggested changing the allowable time between submitting two projects of the same objective to 18 months. TEC stated that an applicant with relatively minor but diverse needs may be unduly harmed by this two-year prohibition if that applicant submits an application containing projects that cover all listed objectives in the rule. TEC recommended that the commission consider these instances on a case-by-case basis, given the needs and realities of a variety of electric providers with differing service territory characteristics and operational processes.
In addition to removing the provision, ETI suggested revising the rule to encourage a utility to group projects with the same objective within one application when feasible. ETI also recommended an alternative approach where the 24-month restriction would only apply if the prior application resulted in a grant award exceeding a specified dollar threshold, such as $25 million, allowing a utility that received a smaller grant to apply for an additional project addressing the same objective without waiting 24 months. ETI provided redlines should the commission decide to adopt this alternative approach instead of striking the restriction altogether and requested that the restriction apply only if the prior application was granted.
SPS suggested changing the rule to clarify that the total utility threshold is only applicable to each application cycle and that an application for a similar project is not prohibited for 24 months unless the project was submitted in a previous cycle and was awarded and funded.
ETI and SPS provided redlines consistent with their recommendations.
Commission Response
The commission declines to modify the restriction for an application with the same objective, as recommended by TEC, ETI, and Sierra Club. The commission also declines to add language to encourage applicants to group projects with the same objective in the same application, as suggested by ETI, because it is unnecessary. The 24-month waiting period motivates an applicant to submit and prioritize its projects comprehensively within a specific objective, prevents an applicant from submitting applications in fragments or on a first-to-complete basis, and provides time for other applicants to submit an application before a prior applicant submits an additional application for the same objective.
The commission agrees with ETI's recommendation to apply the 24-month wait time only after the grant agreement for a project within that objective has been executed and modifies the provision accordingly. However, there is no funding cycle associated with this program, so it is unnecessary to modify the rule to account for an application or funding cycle as requested by SPS.
Proposed §25.512(c) and §25.512(i) - Filing requirements, templates, and project monitoring requirements
Proposed §25.512(c) describes the guidance, including rules and restrictions, regarding the application process. Proposed §25.512(i) describes the project monitoring process for a grantee.
ETI requested that the rule include the filing requirements and templates for grant applications and grant agreements, to the extent possible.
ETI also requested that the new rule establish objective and uniform reporting requirements. ETI provided the example of annual reports prepared by a grant recipient that provide details on project progress and grant spend.
Commission Response
The commission declines to include specific filing requirements and templates in the rule, as suggested by ETI. These requirements are already broadly outlined in the existing rule. Detailed information will be made available on the TEF application website.
The commission also declines to establish uniform reporting requirements in the rule because this level of detail is more appropriately addressed in individual grant agreements. The reporting requirements will, at a minimum, meet the Texas Grant Management Standards. An individual project that requires additional reporting will have those requirements outlined in the grant agreement.
Proposed §25.512(c)(1) - Applicant entity and joint applications
Proposed §25.512(c)(1) states that an application must be submitted at the highest entity level, and that an application for a project with multiple owners may be submitted, but only by the highest level of the entity with managing authority (i.e., owner with controlling interest, managing partner, or cooperative).
TEC, ETDC, and Sierra Club recommended adding language to the rule to clarify that utilities can submit joint applications and work together on similar projects. TEC stated that the rule language currently implies that joint applications must be filed by entities with certain vertical or affiliate corporate structures and that an electric cooperative or MOU is typically a single entity with its own individual management. TEC also argued that the ability to file joint applications will allow an electric cooperative or MOU that may not otherwise be able to participate or compete for competitive grant funding to pool its resources together with another cooperative or MOU in a way that creates administrative efficiencies for both the applicants and the commission staff overseeing the OEGP grant program. ETDC made the same argument as TEC for only electric cooperatives.
ETI, SWEPCO, and SPS recommended modification of subsection (c)(1), arguing that this provision conflicts with the eligibility requirements of the program because most non-ERCOT Texas utilities--including ETI and SWEPCO--are subsidiaries of public utility holding companies, which would not be eligible applicants under §25.512(b)(1). SWEPCO recommended removing subsection (c)(1) in its entirety because the required application information is descriptive of an operating utility, like SWEPCO, not its parent company. SPS recommended replacing the provision with language requiring an application to be submitted by the entity meeting the criteria in subsection (b)(1) of the proposed rule.
TEC, ETI, SWEPCO, and SPS provided redlines consistent with their recommendations.
Commission Response
The commission modifies the rule to allow for the submission of a joint application, as recommended by TEC, ETDC, and Sierra Club. An application must be submitted by one prime applicant for all participating entities, and the application must include a proposed allocation usage of the grant funding cap in §25.512(e)(3) for the included entities.
The commission agrees with ETI, SWEPCO, and SPS regarding the proposed language requiring that an application must be submitted at the highest entity level. The commission modifies the rule language to specify that an application must be submitted at the highest entity level that holds a Texas Certificate of Convenience and Necessity (CCN), if applicable. This modification ensures that the entity holding the CCN will be responsible for the project. The commission also modifies the provision to state that an entity that does not require a CCN must submit an application at the highest entity level that operates the electric generating facility or transmission or distribution infrastructure.
Proposed §25.512(c)(2)(C)(iv), §25.512(e)(4), and §25.512(i) - Performance Metrics and Targets
Proposed §25.512(c)(2)(C)(iv) requires an applicant to submit performance metrics and targets for the project. Proposed §25.512(e)(4) states that the TEF administrator may tailor any applicable reporting requirements, period of performance, milestones, performance metrics and targets, deliverables, and payment schedules for each individual project, all of which will be included in the grant agreement. Proposed §25.512(i) describes the project monitoring process for a grantee.
Role of the TEF administrator
ETI recommended that the commission, rather than the TEF administrator, establish performance metrics and targets for a project receiving grant funding, and that the performance metrics be established objectively by objective or project type. ETI argued that the commission has the requisite subject matter expertise and is best situated to establish these requirements.
Commission Response
The commission declines to modify the rule so that the commission, rather than the TEF administrator, establishes performance measures. The commission has final approval authority over any grant agreement, including performance metrics, based on the recommendations of the TEF administrator. Performance metrics and targets for each project that will vary widely by applicant, project, and objective cannot be established by rule in advance.
Purpose of performance metrics and targets
ETI requested that the adopted rule clarify that reporting requirements, including performance metrics and targets, do not serve as a basis to claw back grant funding awarded for a project included in a commission-approved TEF application.
SWEPCO recommended removing every instance of performance metrics and targets from the rule. SWEPCO argued that the primary purpose of ongoing performance monitoring should be to ensure that the grant recipient implements the project as approved, and including performance metrics and targets could create uncertainty and potentially penalize a utility for outcomes beyond its control.
ETI and SWEPCO provided redlines consistent with their recommendations.
Commission Response
The commission declines to remove language regarding performance metrics, as recommended by SWEPCO. It is imperative to have forms of oversight to ensure grant recipients are held accountable to the agreed-upon goals of the grant agreement.
The commission agrees with ETI that, generally, the commission should not withhold or claw back funds based on the performance of the project undertaken with TEF funds, and these terms will be included in an individual grant agreement. However, as a taxpayer-funded program, the OEGP must ensure that the proposed use of program funds aligns with actual spending of those funds. Therefore, the commission modifies subsection (f)(3) of the rule to state that the commission may withhold or require the return of funds for failure to comply with reporting requirements or applicable statutes, rules, regulations, or guidance.
Terms of agreements under other commission rules
ETI requested additional rule language to clarify that the terms of the grant agreement established by the commission or TEF administrator do not conflict with or exceed terms previously approved by the commission for the same projects in a different docket--for example, in an application for a system resiliency plan (SRP) submitted under 16 TAC §25.62. ETI argued that it is seeking approval for certain projects within its SRP conditioned upon receipt of TEF funding for those projects, that the projects in its SRP are already subject to performance metrics and other terms that must be approved by the commission, and that the adopted 16 TAC §25.512 should ensure that none of the terms in a grant agreement will conflict with or exceed the terms in its approved SRP.
ETI provided redlines consistent with its recommendation.
Commission Response
The commission disagrees with ETI that performance metrics in the OEGP must align with performance metrics a grantee is subject to under another voluntary program. The OEGP is a standalone, taxpayer-funded program, and the TEF administrator and commission will institute performance metrics appropriate for the projects funded under this program. The commission may consider the applicability of other requirements on a case-by-base basis but will not impose the requested outcome by rule.
New §25.512(c)(2)(E) - Scoring Criteria
SPS recommended adding a new section in §25.512(c)(2) pointing to www.txenergyfund.texas.gov, which, according to SPS's recommended language, would provide the scoring criteria for evaluating an application and selecting a project at least a month before the commission begins accepting applications. SPS argued that including this language will ensure that a potential applicant can develop an application that promotes the reliability and resiliency of its systems. SPS provided redlines consistent with its recommendation.
Commission Response
The commission declines modify the rule to add a reference to the TEF website to show the scoring criteria for evaluating an application and selecting a project. Subsection 25.512(d) states the factors according to which an application will be reviewed, and more information will be available on the TEF website later. However, this level of detail is not necessary or appropriate in a commission rule.
Transparency
Proposed §25.512(c)(3) and (4) - Application Project Information
Proposed §25.512(c)(3) states that the information submitted to the commission in an application is confidential and not subject to disclosure. Proposed §25.512(c)(4) states that an applicant must separately file a statement indicating that an application for a grant award has been presented to the commission for review with the date of the application submission, the eligible objective and project, and the total grant amount requested per objective.
Sierra Club suggested adding a new section allowing for the information in §25.512(c)(4) to be available to the public, such as whether an application is pending, rejected, or approved. Sierra Club stated that although the application is considered confidential, some minimal information should be available to the public, ratepayers, and policy makers. TPPA recommended that the commission require the separate statement indicating that an application for a grant award has been presented to the commission for review to be filed publicly. TPPA emphasized the importance of ensuring that there is adequate transparency into the implementation of any TEF programs. TPPA provided redlines consistent with its recommendation.
Conversely, SPS recommended ensuring that the statutory language governing the confidentiality of applications and bid information is incorporated into the final rule with an explicit statutory reference to PURA §34.0103(c). SPS argued that confidentiality is critical to protect an applicant from undue public disclosure of competitively sensitive information and potentially protected critical infrastructure information. SPS included redlines consistent with its recommendation.
Commission Response
The commission declines to modify the rule to require a public filing because the information filed as part of subsection (c)(4) will already be public information. In response to SPS's comment, the language in the proposed rule restates the statutory language concerning confidentiality and is retained in the adopted rule. No other additions regarding confidentiality are necessary.
New §25.512(e)(5) - Public Filings
TPPA recommended a new provision in §25.512(e) that would require a grant agreement to be filed publicly, with redactions only allowed for competitively sensitive or critical energy infrastructure information. TPPA provided redline additions consistent with its recommendation.
Commission Response
The commission declines to modify the rule to require a grant agreement to be filed publicly. Because application materials are confidential and not subject to disclosure, and a grant agreement will contain information from the corresponding application, it follows that the grant agreement must also be kept confidential.
Proposed §25.512(i) - Project Monitoring
Proposed §25.512(i) describes the project monitoring process for grantees.
TPPA requested that the TEF administrator provide regular updates on projects' progress during the public session portion of commission open meetings in lieu of private updates to the commission. TPPA provided redline revisions consistent with its recommendation.
Commission Response
The commission declines TPPA's recommendation to modify the rule to include regular public updates during the open meetings in the rule. The commission will follow, at a minimum, the statutory requirements for reporting in the Texas Grant Management Standards. Public updates to the commission during open meetings may risk the confidentiality guaranteed by PURA §34.0103, and the commission will not memorialize such a requirement in its rules. However, commission staff may provide relevant updates to the public at open meetings, as appropriate and allowed by statute, to ensure adequate transparency regarding the Texas Energy Fund.
Proposed §25.512(c)(5) - Filing Separate Statement
Proposed §25.512(c)(5) states that an applicant must separately file a statement indicating that an application for a grant award has been presented to the commission for review with the date of the application submission, the eligible objective and project, and the total grant amount requested per objective.
ETI requested clarification on how an applicant will comply with the requirement to file a separate statement with the commission. Specifically, ETI asked whether a new docket will be established for these statements.
Commission Response
A project will be opened on the interchange for the requirement to file a separate statement with the commission.
Proposed §25.512(d) - Application Review
Proposed §25.512(d) describes the application review process, which is the same for all applications.
TEC, ETDC, and Golden Spread recommended that the commission create an expedited process and simplified form for an applicant whose total application request is under $5 million. TEC stated that due to smaller size and fewer administrative resources, a smaller entity, such as a rural cooperative, may be less able to take advantage of the opportunities provided by the TEF as an entity with substantial in-house staff and resources, and that an expedited process with a simplified application form would improve the overall efficiency of the OEGP. ETDC agreed with TEC's comments. Golden Spread argued that many rural projects, although less costly, could significantly impact electric reliability in their communities. Golden Spread provided redlines consistent with its recommendation.
Commission Response
The commission declines to modify the rule to create an expedited process for a small project. Each application will be reviewed the same way, regardless of its size, to provide a fair process for all applicants.
Proposed §25.512(d)(1) - Application Review
Proposed §25.512(d)(1) states that applications will be reviewed in the order in which the commission receives them.
EPE recommended adding a 60-day submittal period for all applications to be considered. EPE argued that the first come, first served basis inherently benefits an applicant with more resources to submit an application quickly and does not account for the individual needs and capacities of a utility. EPE believed its recommended change would provide more flexibility in project selection and maximize a grant's value and effectiveness.
Commission Response
The commission declines to modify the rule to add a 60-day submittal period because it is unnecessary. Due to the potential variety of complexity of each project and the range of applicant readiness, a fixed application window would not be practicable. In addition, the per-applicant funding cap of $200 million will help ensure that large entities do not use the entirety of the available funds.
New §25.512(d)(5) - Review period
SPS recommended adding a new provision in §25.512(d) to require the commission to review and decide on an application within 30 days following the application close period. It recommended that the timelines for the application, review, award, and implementation of project phases under the OEGP be the same as what was used in the in-ERCOT generation loan program, which from start to due diligence took about four months. SPS provided redlines consistent with its recommendation.
Commission Response
The commission declines to add a 30-day review period. Because each submitted project and its complexity cannot be known in advance, the commission must have ample time to fully review each project, regardless of size. In addition, there is no application close date in the rule. Applications will be accepted and reviewed until the fund allocation is depleted.
Proposed §25.512(e)(3) - Grant Award Amount
Proposed §25.512(e)(3) states that a single applicant will not be awarded more than $200 million in grants.
TEC, ETDC, and Sierra Club recommended that the funding cap for the program be lowered from the proposed $200 million per applicant to $100 million per applicant. TEC argued that the $200 million cap, representing 20 percent of the $1 billion total allocation, would deplete the available funding before every applicant has an opportunity to apply. In addition, TEC expressed concern that only $500 million has been appropriated for this program as of now, so three grantees could deplete the entire available funding. ETDC agreed with TEC's comments and added that a smaller cap would allow for a fairer distribution of grant funds across the greatest number of rural applicants in Texas, each of which could significantly benefit from a grant of just a few million dollars. ETDC emphasized that a rural cooperative, as a not-for-profit, would use savings to lower member rates, unlike an investor-owned utility (IOU), whose savings benefit external investors.
ETI and SPS suggested that the proposed rule be revised to state that an individual applicant will be capped at $200 million per TEF funding cycle.
EPE requested that the rule allow an applicant to submit multiple projects that may collectively exceed the $200 million cap. EPE proposed that the TEF administrator and the commission evaluate these proposed projects, prioritize them, and then refer back to the applicant for final submission. Alternatively, an applicant could submit multiple projects for approval in the order of value to the applicant's system. EPE also argued for using a funding cap based on metrics, rather than a fixed amount. For example, the funding cap could be based on Texas customer count or energy sales. EPE argued that using a metric-based cap would ensure funds were distributed more fairly.
TPPA recommended that the proposed rule language be revised to use the terms "electric utility, electric cooperative, municipally owned utility, and river authority" instead of the term "applicant." TPPA stated that the current language could be misread to allow a single entity to be awarded more than $200 million if the grants were awarded through several different applications.
ETI, TPPA, and SPS provided redlines consistent with their recommendations.
Commission Response
The commission declines to modify the rule to revise the funding cap of $200 million per applicant. The amount of the cap is a reasonable compromise between distributing the TEF's dollars among various areas of Texas and types of applicants and providing enough per applicant to meaningfully contribute to the state's needs. In addition, the commission disagrees with the change recommended by ETI and SPS to add language referring to a funding cycle because there is no funding cycle for this program. The $200 million funding cap per applicant applies to the entire program, with its total allocated amount of $1 billion.
In response to EPE, the $200 million cap applies to an award, not an application. Therefore, the rule permits an applicant to submit multiple projects that may collectively exceed the cap. However, the TEF administrator will not review and pre-qualify lists of proposed projects or advise on an application submission. EPE's suggested alternative plan, which allows an applicant to prioritize its projects, is included in the proposed rule under §25.512(c)(2)(A)(viii) and retained in the adopted rule.
The commission declines to modify §25.512(e)(3) to revise the term "applicant," as requested by TPPA. The adopted rule includes modified subsection (c)(1), which requires the entity in Texas that holds a CCN (if applicable) to be the applicant to this program. This modification ensures that multiple applications by a single entity do not result in awards that exceed the funding cap.
Proposed §25.512(e)(4) - Grant Agreement
Proposed §25.512(e)(4) states that failure to enter into a grant agreement or an uncured breach of the executed grant agreement will be grounds for the TEF administrator to determine that an applicant is ineligible to obtain any future grant payments.
TPPA recommended that only an uncured breach of a grant agreement should make an applicant ineligible for future grants. TPPA stated concerns that the current rule language would disallow an entity from reapplying for a grant and that a future application may be rejected with prejudice should the entity fail to enter into a grant agreement. TPPA provided redline revisions consistent with its recommendation. ETI requested that the new rule provide and describe a process to allow for negotiation of, or the ability to review and propose revisions to, the grant agreement and to allow a grant recipient to address any potential issues identified.
Commission Response
The commission agrees with TPPA that failure to enter into an agreement should not render an applicant ineligible to apply again in the future. The commission modifies the provision accordingly.
The commission declines to modify the rule to include a process for negotiating the grant agreement, as requested by ETI, because it is unnecessary. Given the range of eligible objectives and unique nature of each project, the grant agreement will vary for each grantee.
New §25.512(e)(5) - Small Utility Allocation
TPPA supported the proposed cap of $200 million per applicant but recommended adding a new provision in §25.512(e) setting aside at least $75 million specifically for small utilities that each serve 5,000 meters or less. This allocation, TPPA argued, would help ensure that a small utility, which may lack the resources to compete for grants, can benefit from the OEGP. TPPA also suggested a simplified application process and streamlined reporting requirements for such a small utility.
Commission Response
The commission declines to set aside $75 million specifically for small utilities, as recommended by TPPA. The commission's goal with the OEGP is to build a portfolio that benefits Texas outside of the ERCOT region. Given the uncertainty of the type or complexity of each project that may be proposed, it would not be practicable to earmark funds in the rule and create a secondary tier of projects and a separate review process.
Proposed §25.512(f)(2) - Grant Payment Process
Proposed §25.512(f)(2) states that a grantee may receive grant funds in advance of incurring expenses, as specified in the grant agreement.
ETI recommended that the commission revise §25.512(f)(2) to allow for each grantee to receive grant funds in advance of incurring expenses unless the commission determines good cause warrants otherwise. ETI explained that this revision would not prevent the grant agreement from including additional details about the timing and payment terms for grants and would provide adequate regulatory certainty regarding when a grantee will receive funding for an approved project. ETI provided redlines consistent with its recommendation.
Commission Response
The commission disagrees with ETI that the default disbursement schedule for a grantee should be to receive grant funds in advance of incurring costs. Grant disbursement is typically agnostic as to when a cost is incurred, as long as there are receipts or other documentation to prove how the funds were used. In addition, each grant award and project will have unique circumstances, so funding and disbursement decisions will be made on a case-by-case basis. Accordingly, the commission declines to modify subsection (f)(2). However, the commission modifies subsection (f)(1) of the rule to require a grantee to comply with the terms of a grant agreement or with federal or state statutes, rules, regulations, or guidance applicable to the grant award to receive a grant disbursement.
In addition, the commission modifies the rule throughout to replace the term "expenses" with the term "capital costs" to emphasize that operations expenses are not eligible for funding through the OEGP.
Proposed §25.512(g)(2) - Period of Performance
Proposed §25.512(g)(2) states that the activities related to eligible expenses of the project must commence within 12 months of execution of the grant agreement and that all projects must complete work by December 31, 2030, or an earlier date if specified in the grant agreement.
ETI, TPPA, and Golden Spread all recommended removal or loosening of the project completion deadline, giving different reasons for removal and alternative suggestions. TPPA and Golden Spread recommended outright removal of the deadline because the commission may accept an application as late as 2028, making a 2030 completion deadline unworkable. Golden Spread also noted that a deadline is not included in PURA §34.0103, but that deadlines are included in other sections of PURA Chapter 34, indicating a legislative intent not to impose a deadline on this program. ETI proposed developing a project extension process to address a potential long lead time for materials.
TPPA suggested defining a completion deadline for each individual project in the grant agreement. Golden Spread's alternative suggestion to removing the provision was to extend the final project deadline to 2035. ETI's proposed solution would include an applicant either accepting the December 31, 2030 completion deadline or proposing an alternative completion deadline that the commission could accept or reject. ETI also requested clarification that the completion deadline applies only to a project from the initial round of TEF grant funding, with revised deadlines for any future funding.
ETI and Golden Spread provided redlines consistent with their recommendations.
Commission Response
The commission agrees with the issues raised by ETI, TPPA, and Golden Spread, modifies the rule at (g)(2) to remove the December 31, 2030 completion deadline, and instead specifies that each project deadline will be specified in the grant agreement. As stated above, there are no funding cycle or planned additional rounds of funding for this program.
In addition, the commission modifies the rule throughout to replace the term "expenses" with the term "capital costs" to emphasize that operations expenses are not eligible for funding through the OEGP.
Proposed §25.512(j) - Expiration
Proposed §25.512(j) states that the rule expires May 1, 2045.
TPPA commented that PURA §34.0103 does not have an expiration date and that the commission may be exceeding its authority by including an expiration date in the rule without legislative instruction.
Commission Response
The commission agrees with TPPA that PURA §34.0103 does not have an expiration date but modifies the rule to extend the expiration of the rule to match the expiration of the in-ERCOT generation loan program for consistency. The commission has broad authority under PURA §14.001 to do anything implied by PURA necessary and convenient to the exercise of its power, and the imposition of an expiration date is within this authority.
This new rule is adopted under the following provisions of 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; PURA §14.002, which provides the commission with the authority to make, adopt, and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §34.0103, which authorizes the commission to use money in the Texas Energy Fund to provide grants for modernization, weatherization, reliability and resiliency enhancements, and vegetation management for transmission and distribution infrastructure and electric generating facilities in this state outside of the ERCOT region; and PURA §34.0110, which authorizes the commission to establish procedures for the application and award of a grant under PURA chapter 34, subchapter A.
Cross reference to statutes: Public Utility Regulatory Act §§14.002, 14.002, 34.0103, and 34.0110.
§25.512.Texas Energy Fund Grants for Facilities outside of the ERCOT Region.
(a) Purpose. The purpose of this section is to implement Public Utility Regulatory Act (PURA) §34.0103 and §34.0106 and establish requirements and terms for grants to finance modernization, weatherization, reliability and resiliency enhancements, and vegetation management for transmission and distribution infrastructure and electric generating facilities in this state outside of the ERCOT region.
(b) Eligibility.
(1) Applicant eligibility. To be eligible for a grant under this section, an applicant must:
(A) be an electric utility, electric cooperative, municipally owned utility, or river authority that owns or manages transmission or distribution infrastructure or one or more electric generating facilities in this state outside of the ERCOT region; or
(B) own a qualifying facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA) §201, codified at 16 U.S.C.A. §§796(17) and (18); and
(C) be compliant with the requirements in the Lone Star Infrastructure Protection Act (codified at Texas Business and Commerce Code §117.002).
(2) Project eligibility. A project consists of one or more measures that share a specific objective over a defined duration. A measure may be an action or series of actions, acquisition of equipment, or construction of infrastructure. Measures that are inter-dependent must be submitted within the same project.
(3) Objectives. To be eligible for a grant under this section, a project must meet one of the following objectives. Only projects within the subcategories listed for each objective in subparagraphs (A) - (D) of this paragraph are eligible for a grant under this section.
(A) Facility modernization. This objective relates to upgrading or replacing infrastructure or equipment and improvements to facility or system situational awareness. Advanced metering installation and analytics, substation automation, water conservation, cooling system upgrades, and installation of heat-resistant technologies are subcategories of the facility modernization objective.
(B) Facility weatherization. This objective relates to measures that protect, strengthen, or improve the energy efficiency, operational parameters, or safety of a structure against the natural elements. Elevation of critical equipment, drainage system improvements, structure reinforcement, insulation and heating of critical areas and equipment, installation of advanced irrigation systems, and installation of weather-resistant equipment and fire or flood barriers are subcategories of the facility weatherization objective.
(C) Reliability and resiliency. This objective relates to helping transmission and distribution infrastructure and electric generating facilities prevent, withstand, mitigate, or more promptly recover from power outages and events involving extreme weather conditions, uncontrolled events, cyber and physical attacks, cascading failures, or unanticipated loss of system components that pose a material threat to the safe and reliable operation of an eligible applicant's transmission, distribution, and generation systems. Fortification against flooding, undergrounding, pole upgrading, electric transmission and distribution infrastructure hardening, battery storage or generation resource that serves to maintain or restore energization of transmission or distribution infrastructure, onsite fuel storage capacity increases, generation uprates, cybersecurity enhancements, and fortification against physical threats are subcategories of the reliability and resiliency objective.
(D) Vegetation management. This objective relates to capital costs for vegetation management not already included in the eligible applicant's rate base to prevent or curtail vegetation from interfering with electric transmission and distribution infrastructure. New data-driven trimming and removal scheduling technology, new GIS-based vegetation mapping technology, drought-resistant vegetation installation, and capital costs to prevent the growth of trees, shrubs, and other vegetation are subcategories of the vegetation management objective.
(4) Funding exclusions. Proceeds of a grant received under this section must not be used for the following:
(A) compliance with weatherization standards adopted before December 1, 2023;
(B) debt payments;
(C) upgrades to or operation of an electric generating facility that will be used primarily to serve an industrial load or private use network (PUN), as described by paragraph (5) of this subsection;
(D) construction of, upgrades to, or operation of transmission and distribution infrastructure that serves an industrial load or PUN and is on the customer's side of the settlement meter;
(E) construction or operation of a natural gas transmission pipeline, or any project related to natural gas transmission or distribution infrastructure;
(F) construction of a new electric generation resource, including any battery storage project, that will be used to sell electricity or ancillary services at wholesale or to serve end user load;
(G) operations expenses associated with a project funded by a grant under this section;
(H) construction of or upgrades to a facility that is not geographically located within Texas;
(I) any proposed project that will not provide the majority of its benefits to consumers of electricity that are located in Texas and outside of the ERCOT region; or
(J) any proposed project that is included as a measure in a resiliency plan approved under §25.62 of this title.
(5) For purposes of this section, an electric generating facility does not primarily serve an industrial load or PUN if that electric generating facility operates in such a manner that the portion of nameplate capacity that will serve the maximum non-coincident peak demand of the industrial load or PUN is less than 50 percent of the facility's total nameplate capacity.:
(c) Application. An eligible applicant may submit one or more applications for a grant under this section. Each application may contain multiple projects. An applicant must not submit an application containing a project with an objective, as described in subsection (b)(3) of this section, within 24 months of the date the applicant entered into a grant agreement for a project with that objective. Each application must be submitted electronically in a form and manner prescribed by the commission and contain the information required by this subsection.
(1) Applicant. An application must be submitted at the highest entity level (e.g., most senior parent or owner) that holds a Texas certificate of convenience and necessity, if applicable. An entity eligible under subsection (b)(1) of this section that is not required to hold a Texas certificate of convenience and necessity must submit its application at the highest entity level that operates the electric generating facility or transmission and distribution infrastructure that is the subject of the application. An application for a project with multiple owners must be submitted by the highest level of the entity with managing authority (e.g., owner with controlling interest, managing partner, or cooperative). A joint application for a project must be submitted by a single prime applicant with partner applicants listed as sub-applicants.
(A) Applicant information. Each application must include applicant information, including:
(i) the applicant's legal name;
(ii) the applicant's form of organization; and
(iii) the applicant's primary contact name and title, mailing address, business telephone number, business e-mail address, and web address.
(B) Applicant experience. Each application must include information on the applicant's history and experience, including:
(i) the applicant's history of transmission, distribution, and electric generation operations in this state and this country;
(ii) information describing the applicant's quality of services and management;
(iii) information describing the applicant's efficiency of operations;
(iv) evidence that the applicant is in good standing with financial institutions and is meeting all compliance requirements; and
(v) evidence of past grant management and administration.
(2) Project. An application must be organized by project and objective. Each application must include the following information for each project:
(A) Project information, including:
(i) proposed project name;
(ii) project objective and subcategory, as specified in subsection (b)(3) of this section;
(iii) grant amount requested for the project;
(iv) description of the proposed project;
(v) demonstration of the project's eligibility under subsection (b) of this section;
(vi) a description of the operational attributes of the transmission or distribution infrastructure or electric generating facility for which the applicant is requesting a grant;
(vii) the name, location, owner, and applicable share of ownership of the transmission or distribution infrastructure or electric generating facilities included in the project; and
(viii) the priority of the project relative to any other projects also proposed under this section by the same applicant.
(B) Expected benefits of the proposed project receiving a grant under this section, including:
(i) a description of the expected benefits for the entire project, including the location and magnitude of the expected benefits, and, if applicable, a description of the expected benefits for each state and power region in which the project will provide benefits;
(ii) a description of the project's ability to address regional and reliability needs;
(iii) evidence of past performance of similarly sized and scoped projects, as applicable; and
(iv) an explanation for why this project should be funded by a grant under this section, as opposed to other available funding sources.
(C) Project implementation details, including:
(i) a proposed project schedule with anticipated dates for major project milestones;
(ii) evidence of the technical feasibility of the project, including staffing plans, material contracts, and required permits, as applicable;
(iii) evidence of how any assets purchased with a grant under this section will be maintained through the depreciable life of the asset; and
(iv) performance metrics and targets for the project.
(D) Budget information and a description of estimated project costs, including, as applicable:
(i) capital costs, such as equipment, hardware, software, development, construction, and capital commitments required for the project to reach completion;
(ii) operating expenses in conjunction with the project and that result from the project, such as maintenance;
(iii) estimated timing requirements of the funds;
(iv) the portions of the proposed budget funded by:
(I) this grant program, limited to capital costs;
(II) applicant cost-share; and
(III) other sources, including federal grants; and
(v) in the case of a joint application, a proposed allocation of the award to each involved entity.
(3) Information submitted to the commission in an application for a grant under this section is confidential and not subject to disclosure under Government Code chapter 522.
(4) An applicant must separately file a statement indicating that an application for a grant award has been presented to the commission for review with the date of the application submission, the eligible objective and project, and the total grant amount requested per objective.
(d) Application review. The commission will approve in full, approve in part, or deny each project in an application based on the screening and evaluation criteria outlined in this subsection. Evaluations and other recommendations provided by the TEF administrator are advisory only. All final decisions on whether to approve or deny each project will be made by the commission.
(1) Applications will be reviewed in the order in which the commission receives them.
(2) Applications and proposed projects will be screened for eligibility under subsection (b) of this section.
(3) Each eligible project will be evaluated to determine whether it is reasonable. The following factors may also be considered in the evaluation:
(A) the applicant's past performance, personnel, and resources to implement the project;
(B) the project's expected benefits;
(C) the project's ability to address regional and reliability needs;
(D) the applicant's stated priority level for the project;
(E) the project's attributes;
(F) the project's cost; and
(G) any other factors the commission deems appropriate.
(4) The TEF administrator may request that an applicant provide any additional information necessary to screen and evaluate any project in an application.
(e) Grant award amount.
(1) The amount of a grant award is based on program funding availability and application evaluation by the TEF administrator. Applications may be funded entirely, or the commission may fund a portion of the proposed application.
(2) If a project is expected to benefit multiple states or power regions, the amount of grant funding will be based on the percentage of the project's benefits that are expected to be provided to areas in Texas and outside of the ERCOT region.
(3) If a project is awarded for an electric generating facility that serves an industrial load or PUN, the amount of grant funding will be based on the percentage of that electric generating facility's capacity that exclusively serves the power region or grid in which the electric generating facility is located.
(4) Grants will be awarded only to fund eligible capital costs to implement a project in an approved application. Any costs funded by a grant under this section must not be included in rates, or otherwise collected from customers.
(5) A single applicant will not be awarded more than $200 million in grants under this section. For purposes of this paragraph, grant funds awarded to joint applicants will be allocated to each applicant based on terms in the grant agreement mutually agreed to by the joint applicants and the TEF administrator.
(6) To receive a grant payment under this section, an applicant must enter into a grant agreement in the form and manner specified by the commission. The TEF administrator may separate or combine projects across applications into one or more grant agreements. An uncured breach of the executed grant agreement will be grounds for the TEF administrator to determine that an applicant is ineligible to obtain any future grant payments under this section. The TEF administrator may tailor any applicable reporting requirements, period of performance, milestones, performance metrics and targets, deliverables, and payment schedules for individual projects, all of which will be included in the grant agreement.
(f) Grant payment terms.
(1) Payment terms for each project will be determined by the TEF administrator and specified in the corresponding grant agreement. A grantee must comply with all terms and conditions outlined in the grant agreement, including all reporting requirements, and all federal or state statutes, rules, regulations, or guidance applicable to the grant award to be eligible for grant fund disbursement.
(2) A grantee may receive grant funds in advance of incurring costs, as specified in the grant agreement.
(3) The commission will withhold or require the return of payments for costs that are found ineligible, or if a grantee fails to comply with the requirements described in paragraph (1) of this subsection.
(g) Period of performance.
(1) Each project's period of performance will be stated in the respective grant agreement based on the project schedule provided in the grantee's application. The grant agreement will specify project milestones.
(2) Activities related to eligible costs of the project must commence within 12 months of execution of the grant agreement. Project deadlines will be specified in the grant agreement.
(h) No contested case or appeal. An application for a grant under this section is not a contested case. A commission decision on a grant award is not subject to a motion for rehearing or appeal under the commission's procedural rules.
(i) Project monitoring. Reporting and monitoring requirements for each grantee will be specified in the grant agreement. Asset performance and maintenance will be monitored for a period specified in the grant agreement for any asset funded by a grant under this section. The TEF administrator must track each grantee's project progress and provide the commission with regular updates.
(j) Expiration. This section expires September 1, 2050.
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 February 13, 2025.
TRD-202500519
Adriana Gonzales
Rules Coordinator
Public Utility Commission of Texas
Effective date: March 5, 2025
Proposal publication date: October 11, 2024
For further information, please call: (512) 936-7322