Chapter PSC 113

PSC 113.0602(13) (13) “Operating area” means a geographical sub-division of each electric utility’s service territory that functions under the direction of a company office and may be used for interruption reporting under this part. These areas may also be referred to as regions, divisions, or districts.

PSC 113.0602(14) (14) “Outage” means the failure of a power system component that results in one or more customer interruptions.

PSC 113.0602(15) (15) “Outage duration” (reported in minutes) means the one minute or greater period from the initiation of an interruption to a customer until service has been restored to that customer.

PSC 113.0602(16) (16) “Partial circuit outage customer count” means where only part of a circuit experiences an outage, the number of customers affected is estimated, unless an actual count is available. When power is partially restored, the number of customers restored is also estimated. Most utilities use estimates based on the portion of the circuit restored.

PSC 113.0602(17) (17) “Planned outages” means those outages which the utility schedules. When customer service interruptions are necessary, the utility should notify affected customers in advance. These interruptions are sometimes necessary to connect new customers or perform maintenance activities safely. They shall not be included in the calculation of reliability indices.

PSC 113.0602 Note Note: Also see s. PSC 113.0502, Planned service interruptions.

PSC 113.0602(18) (18) “Police actions” means request or order of police or fire officials to interrupt service due to an emergency.

PSC 113.0602(19) (19) “Reliability” means the degree to which electric service is supplied without interruption.

PSC 113.0602(20) (20) “Reliability indexes” include the following performance indices for measuring frequency and duration of service interruptions that have been developed by the Edison Electric Institute (EEI), the Institute of Electrical and Electronics Engineers (IEEE), the Canadian Electric Association (CEA) and the American Public Power Association (APPA). They are recognized as standard definitions for the electric utility industry and may be applied to entire distribution systems, operating areas, sub-operating areas or individual circuits. Customer interruptions attributed to major storms, major catastrophic events, or police actions, as defined herein, shall be included in the calculation of these indices throughout this standard.

PSC 113.0602(20)(a) (a) System Average Interruption Frequency Index (SAIFI). The SAIFI index is the average number of interruptions per customer during a year. It is determined by dividing the total annual number of customer interruptions by the average number of customers served during the year.

SAIFI = total number of customer interruptions

  average number of customers served

PSC 113.0602(20)(b) (b) System Average Interruption Duration Index (SAIDI). The SAIDI index is the average customer-minutes of interruption per customer. It is determined by dividing the annual sum of customer-minutes of interruption by the average number of customers served during the year.

SAIDI = sum of customer-minutes of interruption

  average number of customers served

PSC 113.0602(20)(c) (c) Customer Average Interruption Duration Index (CAIDI). The CAIDI index is the average customer-minutes of interruption per customer interruption. It approximates the average length of time required to complete service restoration. It is determined by dividing the annual sum of all customer-minutes of interruption durations by the annual number of customer interruptions.

CAIDI = sum of customer-minutes of interruption

  total number of customer interruptions

PSC 113.0602 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00; CR 02-027: am. (8), Register December 2002 No. 564, eff. 1-1-03.

PSC 113.0603 PSC 113.0603 Recording standards.

PSC 113.0603(1) (1) Aggregate system reliability performance. Each electric utility with 100,000 customers or more shall keep a record of the necessary interruption data and calculate the SAIFI, SAIDI and CAIDI indices of its system and of each operating area, if applicable, at the end of each calendar year for the previous 12-month period.

PSC 113.0603(2) (2) Individual circuit reliability performance. Each utility also shall, at the end of each calendar year, calculate the SAIFI, SAIDI and CAIDI indices for each circuit in each operating area. Each circuit in each operating area shall then be listed in order separately according to its SAIFI index, its SAIDI index and also its CAIDI index, beginning with the highest values for each index.

PSC 113.0603(3) (3) Utilities shall maintain as much information as feasible on momentary outages. Each utility shall keep an annual count of recloser operations, or equivalent information through application of monitoring technology.

PSC 113.0603 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0604 PSC 113.0604 Annual report.

PSC 113.0604(1) (1) Beginning on May 1, 2001 and by May 1 of every year thereafter, each electric utility with 100,000 customers or more, shall file with the commission a report summarizing various measures of reliability. The form of the report shall be subject to review and approval by the commission staff. Names and/or numbers used to identify operating areas or individual circuits may conform to the utility’s practice, but should allow ready identification of the geographic location or the general area served. Electronic (computer) recording and reporting of the required data and information is encouraged. The report shall include at least the following information:

PSC 113.0604(2) (2) 

PSC 113.0604(2)(a) (a) An overall assessment of the reliability performance including the aggregate SAIFI, SAIDI and CAIDI indices by system and each operating area, as applicable.

PSC 113.0604(2)(b) (b) A list of the worst-performing circuits based on SAIFI, SAIDI and CAIDI indexes, for the calendar year. This section of the report shall describe the actions that the utility has taken or will take to remedy the conditions responsible for each listed circuit’s unacceptable performance. The action(s) taken or planned should be briefly described. Target dates for corrective action(s) shall be included in the report. When the utility determines that actions on its part are unwarranted, its report shall provide adequate justification for such a conclusion.

PSC 113.0604(2)(c) (c) Utilities that use or prefer alternative criteria for measuring individual circuit performance to those described in s. PSC 113.0603 and which are required by this section to submit an annual report of reliability data, shall submit their alternative listing of circuits along with the criteria used to rank circuit performance.

PSC 113.0604(2)(d) (d) A report on the accomplishment of the improvements proposed in prior reports for which completion has not been previously reported.

PSC 113.0604(2)(e) (e) A description of any new reliability or power quality programs and changes that are made to existing programs.

PSC 113.0604(2)(f) (f) A status report of any long range electric distribution plans.

PSC 113.0604(3) (3) In addition to the information included in sub. (1), each utility shall report the following additional service quality information:

PSC 113.0604(3)(a) (a) Route miles of electric distribution line reconstructed during the year. Separate totals for single- and three-phase circuits shall be provided.

PSC 113.0604(3)(b) (b) Total route miles of electric distribution line in service at year’s end, segregated by voltage level.

PSC 113.0604(3)(c) (c) Monthly average speed of answer, as defined in s. PSC 113.0503 (1) (b), for telephone calls received regarding emergencies, outages and customer billing problems.

PSC 113.0604(3)(d) (d) The average number of calendar days a utility takes to install and energize service to a customer site once it is ready to receive service. A separate average shall be calculated for each month, including all extensions energized during the calendar month.

PSC 113.0604(3)(e) (e) The total number of written and telephone customer complaints received in the areas of safety, customer billing, outages, power quality, customer property damage and other areas, by month filed.

PSC 113.0604(3)(f) (f) Total annual tree trimming budget and actual expenses.

PSC 113.0604(3)(g) (g) Total annual projected and actual miles of distribution line tree trimmed.

PSC 113.0604 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0605 PSC 113.0605 Initial historical reliability performance report.

PSC 113.0605(1) (1) Each electric utility with 100,000 customers or more that has historically used measures of system, operating area and circuit reliability performance, shall initially submit annual SAIFI, SAIDI and CAIDI data for the previous three years. Those utilities that have this data for some time period less than three years shall submit data for those years it is available.

PSC 113.0605(2) (2) Those utilities whose historical reliability performance data is similar or related to those measures defined above, but differs due to how the parameters are defined or calculated, should submit the data it has and explain any material differences from the prescribed indices. After the effective date of this section, utilities shall modify their reliability performance measures to conform to those specified herein for purposes of consistent reporting of comparable data in the future.

PSC 113.0605 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0606 PSC 113.0606 Interruptions of service.

PSC 113.0606(1) (1) Each utility shall keep a record of all interruptions to service affecting the entire distribution system of any single community or an important division of a community and include in such record the location, date and time of interruption, the duration, the approximate number of customers affected, the circuit or circuits involved and, when known, the cause of each interruption.

PSC 113.0606(2) (2) When complete distribution systems or portions of communities have service furnished from unattended stations, these records shall be kept to the extent practicable. The record of unattended stations shall show interruptions which require attention to restore service, with the estimated time of interruption. Breaker or fuse operations affecting service should also be indicated even though duration of interruption may not be known.

PSC 113.0606(3) (3) Each utility shall notify the commission of any event described in par. (a), (b), (c), (d) or (e) involving bulk power supply facilities (any generating unit or electric facilities operating at a nominal voltage of 69 kV or higher):

PSC 113.0606(3)(a) (a) Any interruption or loss of service to customers for 15 minutes or more to aggregate firm loads in excess of 200,000 kW. Such notification shall be made by telephone as soon as practicable without unduly interfering with service restoration and, in any event, within one hour after beginning of the interruption. A confirming written report shall be submitted within 2 weeks.

PSC 113.0606(3)(b) (b) Any interruption or loss of service to customers for 15 minutes or more to aggregate firm loads exceeding the lesser of 100,000 kW or half of the current annual system peak load and not required to be reported under par. (a). Such notification shall be made by telephone no later than the beginning of the commission’s next regular work day after the interruption occurred. A confirming written report shall be submitted within 2 weeks.

PSC 113.0606(3)(c) (c) Any decision to issue a public request for reduction in use of electricity. Notification of such decision shall be made by telephone at the time of issuing such request. A confirming written report shall be submitted within 2 weeks.

PSC 113.0606(3)(d) (d) Any action to reduce firm customer loads by reduction of voltage for reasons of maintaining adequacy of bulk electric power supply. Notification of such action shall be made by telephone at the time of taking such action. A confirming written report shall be submitted within 2 weeks.

PSC 113.0606(3)(e) (e) Any action to reduce firm customer loads by manual switching, operation of automatic load shedding devices, or any other means for reasons of maintaining adequacy of bulk electric power supply. Notification of such action shall be made by telephone at the time of taking such action.

PSC 113.0606(4) (4) Each utility shall notify the commission of service interruptions not involving bulk power supply facilities as follows:

PSC 113.0606(4)(a) (a) Interruptions of 60 minutes or more to an entire distribution substation bus or entire feeder serving either 500 or more customers or entire cities or villages having 200 or more customers shall be reported within 2 weeks by a written report.

PSC 113.0606(5) (5) The written reports of subs. (3) and (4) shall include the date, time, duration, general location, approximate number of customers affected, identification of circuit or circuits involved and, when known, the cause of the interruption. When extensive interruptions occur, as from a storm, a narrative report including the extent of the interruptions and system damage, estimated number of customers affected and a list of entire communities interrupted may be submitted in lieu of reports of individual interruptions.

PSC 113.0606 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0607 PSC 113.0607 Appropriate inspection and maintenance: system reliability.

PSC 113.0607(1) (1) Preventative maintenance plan. Each utility or other person subject to this chapter, including persons who own electric generating facilities in this state who provide service to utilities with contracts of 5 years or more, shall develop and have in place its own preventative maintenance plan. This section is applicable to electric generating facilities as set forth at s. 196.491 (5) (a) 1., Stats. Each plan shall include, among other things, appropriate inspection, maintenance and replacement cycles where applicable for overhead and underground distribution plant, transmission, generation and substation facilities.

PSC 113.0607(2) (2) Contents of the plan.

PSC 113.0607(2)(a) (a) Performance standard. The preventative maintenance plan shall be designed to ensure high quality, safe and reliable service, considering: cost, geography, weather, applicable codes, national electric industry practices, sound engineering judgment and experience.

PSC 113.0607(2)(b) (b) Elements of the plan.

PSC 113.0607(2)(b)1. 1. Inspection.

PSC 113.0607(2)(b)1.a. a. The plan under sub. (1) shall include a schedule for the periodic inspection of all facilities owned and operated by the utility and used to provide electric service to its customers. The plan under sub. (1) shall describe the method for inspection of each type of equipment as designated by the reporting utility. Checklist/report forms shall be included in the plan under sub. (1).

PSC 113.0607(2)(b)1.b. b. The plan under sub. (1) shall include guidelines for inspectors to determine the condition of a facility or piece of equipment.

PSC 113.0607(2)(b)2. 2. Condition rating criteria. A rating criteria shall be established to grade the condition of a facility or piece of equipment. Rating criteria for generating facilities should conform to generator availability data system (GADS) requirements as reported to the national electric reliability council, or other accepted industry practices.

PSC 113.0607(2)(b)3. 3. Corrective action schedule. The results of inspections, assessments and condition rating criteria shall be used to define the schedule for implementing maintenance on the facility or piece of equipment. The plan under sub. (1) shall describe how facilities or equipment corrective action schedules are added to the utility’s budget.

PSC 113.0607(2)(b)4. 4. Record keeping. Each utility shall maintain records to allow auditing of its preventative maintenance plan implementation. The records shall include inspection dates, condition rating, schedule for repair (if applicable) and the date of completion of the repair. Inspection and repair records shall be retained for a minimum of ten years.

PSC 113.0607(2)(b)5. 5. Filing of plans. Each utility, as well as the transmission company created by s. 196.485, Stats., shall file a plan in compliance with this rule within 180 days of acceptance of the rules or, in the alternative, within 180 days after the utility transmission company or other person subject to this chapter begins operation of a facility subject to this chapter.

PSC 113.0607(2)(b)6. 6. Reporting requirements. Each utility shall provide a periodic report to the commission showing compliance with its preventative maintenance plan. The report shall include a list of inspected circuits and facilities, the condition of facilities according to established rating criteria, schedules established and success at meeting the established schedules. For generation facilities, the report shall include a summary of each generating unit’s operating performance statistics based on the utility’s GADS data, or other accepted industry data convention. Reported generating unit performance data shall include net dependable capacity, capacity factor, forced outage rate, scheduled outage factor, primary fuel and production technology type. The commission shall establish a periodic report schedule for each utility of at least once every 2 years.

PSC 113.0607(2)(b)7. 7. Exchange of information. At least annually, utilities shall exchange planned outage information for the coming year for expected maintenance and other outages of generators of 50 MW or more and transmissions lines of 100 kV and higher voltage. Utilities shall also supply the same information for nonutility generators of 50 MW or more in their control areas. Utilities shall exchange updates of such information as soon as reasonably practicable when such updated information becomes known.

PSC 113.0607 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00; CR 02-027: am. (2) (a), (b) 1. a. and b. 2. and 3., and (2) (b) 6., Register December 2002 No. 564, eff. 1-1-03.

PSC 113.0608 PSC 113.0608 Emergency response. Each utility with 25,000 customers or more shall establish procedures to record and monitor its response times for emergencies, such as calls for assistance from police, fire, emergency medical services officials and any calls or reports of wire contacts, dig-ins, wires down, utility facilities on fire, unauthorized entry into utility facilities, unsecured public access to energized equipment, or any similar activity on or near utility facilities constituting a hazardous condition or an immediate threat or danger to persons, customers’ property, customers business operations or general property. In general, the records of these calls should include the date and time received; the identity (if known) of the caller; the identity of the person receiving the call; the location and nature of the problem, incident, or accident; the time the utility responder arrived at the location; the total time to respond; and the final disposition or resolution of the problem.

PSC 113.0608 Note Note: It is recognized that strict compliance with this rule may be difficult during major system-wide or large area emergencies, for example, major wind or ice storms where many outage reports may also involve reports of “wires down.” However, reasonable efforts should still be made to identify and give priority response to calls for assistance from police and fire officials who may be “first responders.” This will allow these locations to be secured so the police or fire units can be released to pursue other duties.

PSC 113.0608 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0609 PSC 113.0609 Customer satisfaction surveys.

PSC 113.0609(1) (1) Using methods approved by the commission, each municipally owned electric public utility and each investor-owned utility with a customer count of 20,000 or less, as directed by the commission where there is cause to do so, and each investor-owned electric public utility with a customer count greater than 20,000, on an annual basis, shall fund quantitative assessments, made by an independent entity, of the satisfaction of all customer classes with the services they have received from the utility. The results of these assessments shall be filed with the commission. The utility shall provide to the commission a detailed report of the information from any research it has conducted in the past year to help assess:

PSC 113.0609(1)(a) (a) The satisfaction of the utility’s customers with the services they have received from the utility.

PSC 113.0609(1)(b) (b) The specific new services or alterations to existing services desired by customers.

PSC 113.0609(2) (2) This information shall at a minimum include the following:

PSC 113.0609(2)(a) (a) A detailed description of the methods used to conduct the research and analyze the results.

PSC 113.0609(2)(b) (b) The results of the research, including mean scores for all variables studied, both for the study sample as a whole and for meaningful sample subgroups.

PSC 113.0609 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00; CR 02-027: am. (1) (intro.), Register December 2002 No. 564, eff. 1-1-03.

PSC 113.0610 PSC 113.0610 Customers’ complaints.

PSC 113.0610(1) (1) Each utility shall investigate and keep a record of complaints received by it from its customers in regard to safety, service, or rates and the operation of its system with appropriate response times designated for critical safety and monetary loss situations. The record shall show the name and address of the complainant, the date and nature of the complaint, the priority assigned to the assistance and its disposition and the time and date thereof.

PSC 113.0610(2) (2) Each utility also shall document all contacts and action relative to deferred payment agreements and disputes.

PSC 113.0610 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.