Texas Administrative Code
Title 16 - ECONOMIC REGULATION
Part 2 - PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25 - SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter C - INFRASTRUCTURE AND RELIABILITY
Section 25.52 - Reliability and Continuity of Service

Universal Citation: 16 TX Admin Code § 25.52

Current through Reg. 50, No. 13; March 28, 2025

(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.

Disclaimer: These regulations may not be the most recent version. Texas may have more current or accurate information. We make no warranties or guarantees about the accuracy, completeness, or adequacy of the information contained on this site or the information linked to on the state site. Please check official sources.
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