Wisconsin Legislature: PSC 113.0511(5)(d)

(d) That the practice may enable merchants to take advantage of the inability of customers to reasonably protect their interests by reason of physical or mental infirmities, illiteracy or inability to understand the language of the agreement, ignorance or lack of education or similar factors.

(e) That the terms of the transaction require customers to waive legal rights.

(f) That the terms of the transaction require customers to unreasonably jeopardize money or property beyond the money or property immediately at issue in the transaction.

(g) That the natural effect of the practice would reasonably cause or aid in causing customers to misunderstand the true nature of the transaction or their rights and duties thereunder.

(h) That the writing purporting to evidence the obligation of the customer in the transaction contains terms or provisions or authorizes practices prohibited by law.

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

PSC 113.0508 Oppressive and deceptive practices prohibited. A utility shall not engage in any oppressive or deceptive practices. It shall not do any of the following:

(1) Use or threaten force or violence to cause physical harm to the person, dependents, or property of the ratepayer.

(2) Threaten criminal prosecution without merit or authority.

(3) Initiate or threaten to initiate communications with the ratepayer’s employer except as permitted by statute.

(4) Engage in any conduct which can reasonably be expected to threaten or harass a ratepayer.

(5) Claim or attempt to claim to enforce a right, with knowledge or reason to know that the right does not exist.

(6) Use obscene, threatening, or abusive language in communicating with a ratepayer or a person related to a ratepayer.

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

PSC 113.0509 Landowner easements.

(1) When approaching a landowner in the course of negotiating new easements or renegotiating existing easements, the utility shall provide the landowner with materials approved or prepared by the commission describing the landowner’s rights and options in the easement negotiation process. The landowner shall have, unless voluntarily waived by the landowner, a minimum period of five days to examine these materials before signing any new or revised easement agreement.

(2) High-voltage transmission line easements shall describe the interest transferred by specifying, in addition to the length and width of the right-of-way, the number, type and maximum height of all structures to be erected thereon, the minimum height of the transmission lines above the landscape and the number and maximum voltage of the lines to be constructed and operated thereon, as required by s. 182.017 (7), Stats.

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

PSC 113.0510 Tree trimming contacts. When trimming trees and other vegetation in electric line right-of-way maintenance, the utility shall make a reasonable attempt to contact the landowner a minimum of twenty-four hours prior to beginning of work on the landowner’s property. This contact may take the form of a written notice delivered to the landowner’s residence, a telephone call to the landowner, or an in-person contact. Reasonable effort shall be made by the utility to accommodate a landowner’s desire to be present when work is done on his or her property. Emergency repairs are exempted from this notification requirement.

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

PSC 113.0511 Oak tree cutting and pruning.

(1) In urban/residential areas: From April 15 through July 1 of each year, no pruning or cutting of oak trees is permitted except in emergencies. Herbicide treatment of stumps to prevent sprouting may substitute for the painting of stumps. If a tree is dead at the time of cutting, no treatment is necessary.

(2) An urban/residential site is any site within incorporated village or city boundaries or any site in direct association with permanent or seasonal residences and dwellings. Residential sites include developed lawn areas and other intensively landscaped areas such as business and industrial properties, parks and golf courses. Residential sites include areas where the vegetation is intensively managed and typically involve yard and street trees of high landscape and ornamental value.

(3) In rural areas: From April 15 through July 1 of each year, pruning paint must be applied to all final cuts on oak trees immediately after cutting. Herbicide treatment of stumps to prevent sprouting may substitute for the painting of stumps. If a tree is dead at the time of cutting, no treatment is necessary.

(4) A rural site is any site not in direct association with a permanent or seasonal residence. Rural sites include sites in areas of agricultural and forest land use. Rural sites are not intensively developed and typically include areas occupied by native vegetation cover types and are stocked with naturally-occurring plants.

(5) Emergency pruning or removal of oaks within the April 15 to July 1 time period is permitted to maintain necessary levels of safety, service and reliability. Some situations where emergency tree pruning and removal may be necessary include:

(a) Storm-related damage to electrical facilities and/or adjacent trees has caused or could cause a power outage.

(b) Bringing electrical service into a new residence or business.

(d) Rebuilding or upgrading distribution facilities.

(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.

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

PSC 113.0512 Identification of potential power line natural hazards.

(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.

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

(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.

(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.

(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.

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.

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

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.

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

Subchapter VI — Safety and Service Standards

PSC 113.0601 Standards for electric service reliability.

(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.

(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.

(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.

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

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

(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.

(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.

(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.

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

(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.

(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.

(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.

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

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

(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.

(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.

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

(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.

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

(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.

(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.

(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.

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

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

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

(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.

(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

(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

(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

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 Recording standards.

(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.

(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.

(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.

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

PSC 113.0604 Annual report.

(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:

(2)

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