Chapter PSC 113

PSC 113.0511(5)(c) (c) Moving electrical facilities to accommodate road, pipeline, or building construction.

PSC 113.0511(5)(d) (d) Rebuilding or upgrading distribution facilities.

PSC 113.0511(6) (6) Counties where oak wilt has not been confirmed are exempted from these oak tree cutting and pruning restrictions. The commission shall annually provide the utilities with a list of exempted counties.

PSC 113.0511 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0512 PSC 113.0512 Identification of potential power line natural hazards.

PSC 113.0512(1) (1) Identification of potential power line natural hazards. Utilities shall conduct a program of identification of potential power line natural hazards in accordance with training approved by the commission.

PSC 113.0512(2) (2) Inspection to identify potential power line natural hazards.

PSC 113.0512(2)(a) (a) Inspection. The utilities shall conduct inspections of its operations, including its transmission and distribution lines and facility rights-of-way, every 3 to 8 years and within 60 days of an order for inspection issued by the commission.

PSC 113.0512(2)(b) (b) Request for inspection. Any person, organization or agency may request the utility to make an inspection for potential power line natural hazards and the commission on its own motion, may order the utility to inspect its transmission and distribution lines and rights-of-way for potential power line natural hazards. The utility shall make such inspection upon a showing that potential power line natural hazards may exist.

PSC 113.0512(3) (3) Response to identification of potential power line natural hazards. Upon identifying a potential power line natural hazard, the utility shall take action to eliminate the hazard to the power line. The utility shall make a reasonable effort to notify the owner or other individual with authority, to trim or remove the tree of the potential danger and method by which the danger may be minimized or removed. Nothing in this section shall preclude the utility’s obligation to immediately remove the hazard, as required by ch. PSC 114.

PSC 113.0512 Note Note: Section 26.14 (9) (b), Stats., subjects a person to liability for the cost of suppressing a forest fire if the forest fire is intentionally or negligently set and allowed to escape. A utility not inspecting its lines or operations to identify, trim or remove hazardous trees consistent with these rules may be found negligent and, therefore, responsible for payment of forest fire suppression costs resulting from a forest fire caused by a tree or branch breaking or damaging a line or equipment. A utility complying with these rules, is not expected to be responsible for costs associated with forest fire suppression under s. 26.14 (9) (b), Stats. If a utility complying with this section is not authorized to trim or remove a tree it identifies as hazardous, consistent with the training required by it; a landowner notified of the potential danger or damage that may be caused to the transmission or distribution line or operation, might be found later to have been negligent and responsible for the costs of setting and allowing a forest fire to escape; however, the agency seeking reimbursement for the costs has the burden of proving that the landowner is responsible. The goal of this effort is to reduce the likelihood of outages and forest fires, thereby reducing the likelihood that anyone is responsible for forest fire suppression costs.

PSC 113.0512 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0513 PSC 113.0513 Wetlands work. Insofar as is practical, any electric transmission and distribution line construction work in wetlands shall be scheduled and completed at times when the wetlands are frozen in order to minimize damage or disruption.

PSC 113.0513 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

subch. VI of ch. PSC 113 Subchapter VI — Safety and Service Standards

PSC 113.0601 PSC 113.0601 Standards for electric service reliability.

PSC 113.0601(1) (1) The purpose of ss. PSC 113.0601 to 113.0605 is to establish standards and reporting requirements to provide consumers, the commission and electric utilities with a uniform method to monitor the reliability of electric service delivered in an electric utility’s operating area. These rules adopt definitions and requirements for maintenance of interruption data, retention of records and report filing, in addition to those in the other sections of subch. IV.

PSC 113.0601(2) (2) In general, utilities are expected to provide sufficient resources to assure reasonably adequate and reliable service to all of their customers under normal operating conditions. These standards establish the reliability of service on an annual basis under all operating conditions, including during major storms, major catastrophic events and police actions. A utility may supply supplemental reliability statistics excluding the aforementioned situations (in addition to the statistics with those events included) with a written justification for exclusion.

PSC 113.0601(3) (3) The commission will use this information to measure and monitor overall reliability performance of individual utilities. The commission may review data by utility, trends of measures over time and comparison of measures between and among utilities of similar characteristics. Where necessary, the information may be used by the commission to take enforcement actions through other proceedings to maintain or improve reliability performance and to assure customers are receiving reasonably adequate service.

PSC 113.0601 History History: Cr. Register, July, 2000, No. 535, eff. 8-1-00.

PSC 113.0602 PSC 113.0602 Definitions. In ss. PSC 113.0602 to 113.0605, the following definitions shall apply:

PSC 113.0602(1) (1) “Average number of customers served” means the number of active metered customer accounts as available in a utility’s interruption reporting database on the day that an interruption occurs.

PSC 113.0602(2) (2) “Circuit” means a set of conductors serving customer loads that are capable of being separated from the serving substation automatically by a recloser, fuse, sectionalizing equipment, etc.

PSC 113.0602(3) (3) “Component” means a piece of equipment, a line, a section of line, or a group of items which is an entity for purposes of reporting, analyzing and predicting interruptions.

PSC 113.0602(4) (4) “Customer” means a separately-metered electrical service point for which a separate bill is rendered, i.e., each meter represents a customer.

PSC 113.0602(5) (5) “Customer interruption” means the loss of service due to a forced outage for more than five minutes, for one or more customers, which is the result of one or more component failures. For example, a downed house service is one interruption and a disconnected hot leg of a triplex house service, known as a “half-light” condition, is one customer interruption. However, failure of a transformer serving four customers is four customer interruptions.

PSC 113.0602(6) (6) “Customer interruptions caused by power restoration process” means when customers lose power as a result of the process of restoring power (such as from switching operations and fault isolation). The duration of these outages is included in the customer-minutes of interruption. However, only the customers affected by the power restoration outages that were not affected by the original outage are added to the number of customer interruptions.

PSC 113.0602(7) (7) “Customer-minutes of interruption” means the number of minutes of forced outage duration multiplied by the number of customers affected. For instance, a 90 minute forced outage on a circuit serving ten customers would total 900 customer-minutes of interruption.

PSC 113.0602(8) (8) “Electric distribution line” means circuits operating at less than 50,000 volts.

PSC 113.0602(9) (9) “Forced outage” means an outage which cannot be deferred.

PSC 113.0602(10) (10) “Major catastrophic events” means train wrecks, plane crashes, or explosions that are beyond the utility’s control and result in widespread system damages causing customer interruptions that affect at least ten percent of the customers in the system or in an operating area and/or result in customers being without electric service for durations of at least 24 hours.

PSC 113.0602(11) (11) “Major storm” means a period of severe adverse weather resulting in widespread system damage causing customer interruptions that affect at least ten percent of the customers on the system or in an operating area and/or result in customers being without electric service for durations of at least 24 hours.

PSC 113.0602(12) (12) “Momentary interruption” means an interruption of electric service with a duration shorter than the time necessary to be classified as a customer interruption.

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: