1. (a) Application. This section applies to all electric utilities providing distribution or transmission service in Texas.

2. (b) General.

   1. (1) Every utility shall make all reasonable efforts to prevent interruptions of service. When interruptions occur, the utility shall reestablish service within the shortest possible time.
   2. (2) Each utility shall make reasonable provisions to manage emergencies resulting from failure of service, and each utility shall 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. (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.

3. (c) Definitions. The following words and terms, when used in this section, shall have the following meanings unless the context clearly indicates otherwise.

   1. (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. (2) Interruption classifications:

      1. (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.
      2. (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.
      3. (C) Outside causes--Interruptions, exclusive of major events, that are caused by outside influences such as generation, transmission, or substation outages. (Non-distribution system causes)
      4. (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 shall 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.
   3. (3) Interruption, momentary--Single operation of an interrupting device which results in a voltage zero.
   4. (4) Interruption, sustained--All interruptions not classified as momentary.
   5. (5) Interruptions, significant--All interruptions of any classification lasting one hour or more and affecting the entire system, a major division of the system, a community, a critical load, service to interruptible customers, scheduled interruptions lasting more than four hours that affect customers that are not notified in advance, 20% or more of the system's customers, or 20,000 customers for utilities serving more than 200,000 customers. Significant interruptions also include interruptions adversely affecting a community such as interruptions of governmental agencies, military bases, universities and schools, major retail centers, and major employers.

   6. (6) Reliability indices:

      1. (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.
      2. (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.
   7. (7) Year 2000 compliant--A computer system or application that accurately processes date/time data (including but not limited to calculating, comparing, and sequencing) from, into, and between the 20th and 21st centuries, the years 1999 and 2000, and leap year calculations, and performs its intended applications accurately and without interruptions.
   8. (8) Year 2000 ready--A computer system or application that has been determined to be suitable for continued use into the year 2000 even though the computer system or application is not fully year 2000 compliant.
4. (d) Record of interruption. Each utility shall keep complete records of sustained interruptions of all classifications. Where possible, each utility shall keep a complete record of all momentary interruptions. These records shall 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 shall also be recorded. Beginning July 1, 1997, each utility shall retain records of interruptions for five years.

5. (e) Notice of significant interruptions.

   1. (1) Initial notice. An electric utility shall notify the commission, in a method prescribed by the commission, as soon as reasonably possible after it has determined that an significant interruption has occurred. The initial notice shall 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 shall also include the name and telephone number of the utility contact person, and shall 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 shall update this information daily and file a summary report.
   2. (2) Summary report. Within five working days after the end of a significant interruption lasting more than 24 hours, the utility shall submit a summary report to the commission. The summary report shall 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).

6. (f) Emergency Operations Plan. By December 31, 1998, each utility shall file with the commission a general description of its emergency operations plan. Each utility shall update its plan by filing a revised description that clearly indicates any changes in the plan at least 30 days before such changes take effect. A general description of the plan shall also be made available at the utility's main office for inspection by the public. A complete copy of the plan shall be made available at the utility's main office for inspection by the commission or its staff upon request. Each electric utility's emergency plan must include, but need not be limited to, the following:

   1. (1) A registry of critical loads directly served by the utility. This registry shall be updated as necessary but not less often than annually. The description filed with the commission shall include the location of the registry, how the utility ensures that it is maintaining an accurate registry, how the utility will provide assistance to critical load customers in the event of an unplanned outage, how the utility intends to communicate with the critical load customers, and how the utility is training its staff with respect to serving critical customers and loads.
   2. (2) A communications plan that describes the procedures for contacting the media and customers and critical loads directly served by the utility as soon as reasonably possible either before or at the onset of an electrical emergency. The communications plan should also address how the utility's telephone system and complaint handling procedures will be augmented during an emergency. Utilities should make every reasonable effort to solicit help from cogenerators and independent power producers during times of generation shortages to prevent interruptions in service;
   3. (3) curtailment priorities and procedures for shedding load and rotating black-outs;
   4. (4) priorities for restoration of service;
   5. (5) a summary of power plant weatherization plans and procedures;
   6. (6) a summary of the utility's alternative fuel and storage capacity;
   7. (7) a draft of the utility's "Year-2000" contingency plan and mitigation strategies for dealing with potential failures caused by computers that are not year 2000 ready or year 2000 compliant shall be filed by December 31, 1998. A final version shall be filed no later than June 30, 1999. This plan shall identify potentially vulnerable systems and business processes and prioritize them. The plan shall also include the utility's plans for backups for its customers' critical loads and processes, and report estimated costs for contingency operations.

7. (g) System reliability. Reliability standards shall apply to each electric utility, and shall be limited to the Texas jurisdiction. The standards shall 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. A "reporting year" is the 12-month period beginning May 1st and ending April 30th of each year.

   1. (1) System-wide standards. Interim standards shall be established for the 24-month period ending April 30, 1999. The interim standards shall be the system-wide average of the 1998 and the 1999 reporting years for each reliability index. The interim standards will be adjusted based on the 36-month period ending April 30, 2000. The resulting standards will be the average of the three reporting years 1998, 1999, and 2000.

      1. (A) SAIFI. Each utility shall maintain and operate its electric distribution system so that the SAIFI value for the 2000 reporting year does not exceed the interim system-wide SAIFI standard by more than 10%. For the 2001 reporting year and thereafter, the SAIFI value shall not exceed the system-wide SAIFI standard by more than 5.0%.
      2. (B) SAIDI. Each utility shall maintain and operate its electric distribution system so that the SAIDI value for the 2000 reporting year does not exceed the interim system-wide SAIDI standard by more than 10%. For the 2001 reporting year and thereafter, the SAIDI value shall not exceed the system-wide SAIDI standard by more than 5.0%.

   2. (2) Distribution feeder standards. Standards shall be established for the 24-month period ending April 30, 1999. The standards shall be average of the 1998 and the 1999 reporting years for each index at the value represented by the 10% of the distribution feeders with the highest values.

      1. (A) SAIFI. Each utility shall maintain and operate its electric distribution system so that 92% of the distribution feeders meet or exceed the SAIFI standard for the 2000 reporting year. For the 2001 reporting year and thereafter, 96% of the distribution feeders shall meet or exceed the SAIFI standard.
      2. (B) SAIDI. Each utility shall maintain and operate its electric distribution system so that 92% of the distribution feeders meet or exceed the SAIDI standard for the 2000 reporting year. For the 2001 reporting year and thereafter, 96% of the distribution feeders shall meet or exceed the SAIDI standard.
      3. (C) Each utility shall manage its distribution feeders so that no distribution feeder shall sustain 12-month SAIDI or SAIFI values that are among the highest (worst) 2.0% of that utility's feeders for two or more consecutive reporting years. Distribution feeder performance shall comply with this provision no later than April 30, 2000.

Source Note:The provisions of this §25.52 adopted to be effective December 6, 1998, 23 TexReg 11921.