Subchapter N. ELECTRIC RELIABILITY STANDARDS

 The following words and terms, when used in this subchapter, have the following meanings, unless the context clearly indicates otherwise:

   Adequacy—The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers from various electric generation suppliers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

   Circuit—A conductor or system of conductors through which an electric current is intended to flow.

   Conductor—A material, usually in the form of a wire, cable, or bus bar, suitable for carrying an electric current.

   Control area—An electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnected systems.

   EDC—Electric distribution company—An electric distribution company as defined in 66 Pa.C.S. §  2803 (relating to definitions).

   Electric generation supplier or electricity supplier—An electric generation supplier or electricity supplier as defined in 66 Pa.C.S. §  2803.

   FERC—Federal Energy Regulatory Commission.

   IEEE—Institute of Electrical and Electronic Engineers.

   Interruption duration—A period of time measured to the nearest 1-minute increment which starts when an electric distribution company is notified or becomes aware of an interruption, unless an electric distribution company can determine a more precise estimate of the actual starting time of an interruption, and ends when service is restored. Interruptions shall be categorized, based on duration, such as momentary or sustained interruptions, or by similar descriptions, as adopted by the IEEE or similar organization identified by the Commission. This subchapter requires tracking, reporting and evaluation of two categories of interruption duration that will incorporate any changes in the terms used or the definitions of those terms as adopted by the IEEE or Commission order.

   Major event—

     (i)   Either of the following:

       (A)   An interruption of electric service resulting from conditions beyond the control of the EDC which affects at least 10% of the customers in the EDC’s service territory during the course of the event for a duration of 5 minutes each or greater. The event begins when notification of the first interruption is received and ends when service to all customers affected by the event is restored.

       (B)   An unscheduled interruption of electric service resulting from an action taken by an EDC to maintain the adequacy and security of the electrical system, including emergency load control, emergency switching and energy conservation procedures, as described in §  57.52 (relating to emergency load control and energy conservation by electric utilities), which affects at least one customer.

     (ii)   The term does not include scheduled outages in the normal course of business or an electric distribution company’s actions to interrupt customers served under interruptible rate tariffs.

   Momentary customer interruption—

     (i)   The loss of electric service by one or more customers for the period defined as a momentary customer interruption by the IEEE as it may change from time to time.

     (ii)   The term does not include interruptions described in subparagraph (ii) of the definition of “major event,” or the authorized termination of service to an individual customer.

   NERC—North American Electric Reliability Council—An organization of regional reliability councils established to promote the reliability of the electricity supply for North America.

   Performance benchmark—A numerical value that characterizes an EDC’s average historical reliability performance for a specific time period in the past. The benchmark is based on an EDC’s performance for the entire service territory and is a reference point for comparison of future reliability performance. The Commission will, from time to time, establish benchmarks for each reliability index and each EDC. The performance benchmarks are established by Commission Order at Docket No. M-00991220.

   Performance standard—A numerical value that establishes a minimum level of EDC reliability allowed by the Commission. The performance standard is a criterion tied to the performance benchmark that applies to reliability performance for the EDC’s entire service territory. The Commission will, from time to time, establish new performance standards for each reliability index for each EDC. The performance standards are established by Commission Order at Docket No. M-00991220.

   Regional reliability council—An organization established to augment the reliability of its members’ bulk electric supply systems through coordinated planning and operation of generation and transmission facilities. The following regional reliability councils impact the bulk electric supply systems within this Commonwealth:

     (i)   The East Central Area Reliability Coordination Agreement (ECAR).

     (ii)   The Mid-Atlantic Area Council (MAAC).

     (iii)   The Northeast Power Coordinating Council (NPCC).

   Reliability—The degree of performance of the elements of an electric system that results in electricity being delivered to customers within accepted standards and in the desired amount, measured by the frequency, duration and magnitude of adverse effects on the electric supply and by considering two basic and functional aspects of the electric system: adequacy and security.

   Reliability indices—Service performance indicators which measure the frequency, duration and magnitude of customer interruptions, excluding outages associated with major events.

     (i)   CAIDI—Customer Average Interruption Duration Index—The average interruption duration of sustained interruptions for those customers who experience interruptions during the analysis period. CAIDI represents the average time required to restore service to the average customer per sustained interruption. It is determined by dividing the sum of all sustained customer interruption durations, in minutes, by the total number of interrupted customers. This determination is made by using the following equation:

     where:

       i = an interruption event

       r_i = restoration time for each interruption event

     and N_i = number of customers who have experienced a sustained interruption during the reporting period

     (ii)   MAIFI—Momentary Average Interruption Frequency Index—The average frequency of momentary interruptions per customer occurring during the analysis period. It is calculated by dividing the total number of momentary customer interruptions by the total number of customers served. This determination is made by using the following equation:

     where:

     M_i = number of customers who have experienced a momentary interruption during the reporting period

     (iii)   SAIDI—System Average Interruption Duration Index—The average duration of sustained customer interruptions per customer occurring during the analysis period. It is the average time customers were without power. It is determined by dividing the sum of all sustained customer interruption durations, in minutes, by the total number of customers served. This determination is made by using the following equation:

     where:

     N_T = total number of customers served for the area being indexed

     (iv)   SAIFI—System Average Interruption Frequency Index—The average frequency of sustained interruptions per customer occurring during the analysis period. It is calculated by dividing the total number of sustained customer interruptions by the total number of customers served. This determination is made by using the following equation:

   Security—The ability of the electric system to withstand sudden disturbance such as electric short circuits or unanticipated loss of system elements.

   Sustained customer interruption—The loss of electric service by one or more customers for the period defined as a sustained customer interruption by IEEE as it may change from time to time. This term does not include interruptions described in subparagraph (ii) of the definition of ‘‘major event,’’ or the authorized termination of service to an individual customer.

   The provisions of this §  57.192 amended under the Public Utility Code, 66 Pa.C.S. §  501; and the Electric Generation Customer Choice and Competition Act, 66 Pa.C.S. § §  2801—2812.

   The provisions of this §  57.192 amended September 17, 2004, effective September 18, 2004, 34 Pa.B. 5135. Immediately preceeding text appears at serial pages (246395) to (246396) and (263685) to (263686).

 (a)  An electric distribution company shall install and maintain its transmission facilities, and ensure that its transmission facilities are operated, in conformity with the applicable requirements of the National Electrical Safety Code. An electric distribution company shall operate its transmission facilities in conformity with the operating policies, criteria, requirements and standards of NERC and the appropriate regional reliability council, or successor organizations, and other applicable requirements.

 (b)  The reliability of an electric distribution company’s transmission service provided to wholesale customers, such as electric cooperative corporations and municipal corporations, shall be comparable to the reliability which the transmission supplier provides at the wholesale level, taking into account the nature of each service area in which electricity is delivered to the customer, the delivery voltage and the configuration and length of the circuit from which electricity is delivered.

 (c)  An electric distribution company shall submit to the Commission, on or before May 31, 1999, and May 31 of each succeeding year, information concerning the performance of the transmission system, as built and operated, to serve a fully competitive generation market efficiently. The report shall include available transfer capability, total transfer capability and the use, in general, of the transmission system. The report shall include an assessment of the past performance of the transmission system and an appraisal of future transmission system performance. In complying with this requirement, electric distribution companies operating under a single system operator may submit a joint report by an independent system operator, or other appropriate transmission system operator.

 (a)  An EDC shall furnish and maintain adequate, efficient, safe and reasonable service and facilities, and shall make repairs, changes, alterations, substitutions, extensions and improvements in or to the service and facilities necessary or proper for the accommodation, convenience and safety of its patrons, employees and the public. The service shall be reasonably continuous and without unreasonable interruptions or delay.

 (b)  An EDC shall install, maintain and operate its distribution system in conformity with the applicable requirements of the National Electrical Safety Code.

 (c)  An EDC shall make periodic inspections of its equipment and facilities in accordance with good practice and in a manner satisfactory to the Commission.

 (d)  An EDC shall strive to prevent interruptions of electric service and, when interruptions occur, restore service within the shortest reasonable time. If service must be interrupted for maintenance purposes, an EDC should, where reasonable and practicable, attempt to perform the work at a time which will cause minimal inconvenience to customers and provide notice to customers in advance of the interruption.

 (e)  An EDC shall design and maintain procedures to achieve the reliability performance benchmarks and minimum performance standards established by the Commission.

 (f)  An EDC shall develop and maintain a program for analyzing the service performance of its circuits during the course of each year.

 (g)  An EDC shall maintain a 5-year historical record of all known customer interruptions by category of interruption duration, including the time, duration and cause of each interruption. An EDC shall retain all records to support the reporting requirements under §  57.195 (relating to reporting requirements) for 5 years.

 (h)  An EDC shall take measures necessary to meet the reliability performance benchmarks and minimum performance standards established by the Commission.

   (1)  The performance standard shall be the minimum level of EDC reliability performance allowed by the Commission for each measure for all EDCs. Performance that does not meet the standard for any reliability measure shall be the threshold for triggering additional scrutiny and potential compliance enforcement actions by the Commission’s prosecutorial staff.

     (i)   The Commission will consider historical performance levels, performance trends, and the number and type of standards violated when determining appropriate additional monitoring and compliance enforcement actions. The Commission will consider other information and factors including an EDC’s outage cause analysis, inspection and maintenance goal data, operations and maintenance and capital expenditure data, and staffing levels as presented in the quarterly and annual reports as well as in filed incident reports.

     (ii)   Additional monitoring and enforcement actions that may be taken are engaging in additional remedial review, requiring additional EDC reporting, conducting an informal investigation, initiating a formal complaint, requiring a formal improvement plan with enforceable commitments, requiring an implementation schedule, and assessing penalties and fines.

   (2)  An EDC shall inspect, maintain and operate its distribution system, analyze reliability results, and take corrective measures as necessary to achieve performance benchmarks and performance standards.

   The provisions of this §  57.194 amended under the Public Utility Code, 66 Pa.C.S. §  501; and the Electric Generation Customer Choice and Competition Act, 66 Pa.C.S. § §  2801—2812.

   The provisions of this §  57.194 amended September 17, 2004, effective September 18, 2004, 34 Pa.B. 5135. Immediately preceeding text appears at serial pages (246399) to (246400).

 (a)  An EDC shall submit an annual reliability report to the Commission, on or before April 30 of each year.

   (1)  An original and six copies of the report shall be filed with the Commission’s Secretary and one copy shall also be submitted to the Office of Consumer Advocate and the Office of Small Business Advocate.

   (2)  The name, title, telephone number and e-mail address of the persons who have knowledge of the matters, and can respond to inquiries, shall be included.

 (b)  The annual reliability report for larger EDCs (those with 100,000 or more customers) shall include, at a minimum, the following elements:

   (1)  An overall current assessment of the state of the system reliability in the EDC’s service territory including a discussion of the EDC’s current programs and procedures for providing reliable electric service.

   (2)  A description of each major event that occurred during the year being reported on, including the time and duration of the event, the number of customers affected, the cause of the event and any modified procedures adopted to avoid or minimize the impact of similar events in the future.

   (3)  A table showing the actual values of each of the reliability indices (SAIFI, CAIDI, SAIDI, and if available, MAIFI) for the EDC’s service territory for each of the preceding 3 calendar years. The report shall include the data used in calculating the indices, namely the average number of customers served, the number of sustained customer minutes interruptions, the number of customers affected and the minutes of interruption. If MAIFI values are provided, the number of customer momentary interruptions shall also be reported.

   (4)  A breakdown and analysis of outage causes during the year being reported on, including the number and percentage of service outages, the number of customers interrupted, and customer interruption minutes categorized by outage cause such as equipment failure, animal contact, tree related, and so forth. Proposed solutions to identified service problems shall be reported.

   (5)  A list of the major remedial efforts taken to date and planned for circuits that have been on the worst performing 5% of circuits list for a year or more.

   (6)  A comparison of established transmission and distribution inspection and maintenance goals/objectives versus actual results achieved during the year being reported on. Explanations of any variances shall be included.

   (7)  A comparison of budgeted versus actual transmission and distribution operation and maintenance expenses for the year being reported on in total and detailed by the EDC’s own functional account code or FERC account code as available. Explanations of any variances 10% or greater shall be included.

   (8)  A comparison of budgeted versus actual transmission and distribution capital expenditures for the year being reported on in total and detailed by the EDC’s own functional account code or FERC account code as available. Explanations of any variances 10% or greater shall be included.

   (9)  Quantified transmission and distribution inspection and maintenance goals/objectives for the current calendar year detailed by system area (that is, transmission, substation and distribution).

   (10)  Budgeted transmission and distribution operation and maintenance expenses for the current year in total and detailed by the EDC’s own functional account code or FERC account code as available.

   (11)  Budgeted transmission and distribution capital expenditures for the current year in total and detailed by the EDC’s own functional account code or FERC account code as available.

   (12)  Significant changes, if any, to the transmission and distribution inspection and maintenance programs previously submitted to the Commission.

 (c)  The annual reliability report for smaller EDCs (those with less than 100,000 customers) shall include all items in subsection (b) except for the requirement in paragraph (5).

 (d)  An EDC shall submit a quarterly reliability report to the Commission, on or before May 1, August 1, November 1 and February 1.

   (1)  An original and six copies of the report shall be filed with the Commission’s Secretary and one copy shall also be submitted to the Office of Consumer Advocate and the Office of Small Business Advocate.

   (2)  The name, title, telephone number and e-mail address of the persons who have knowledge of the matters, and can respond to inquiries, shall be included.

 (e)  The quarterly reliability report for larger companies (those with 100,000 or more customers) shall, at a minimum, include the following elements:

   (1)  A description of each major event that occurred during the preceding quarter, including the time and duration of the event, the number of customers affected, the cause of the event and any modified procedures adopted in order to avoid or minimize the impact of similar events in the future.

   (2)  Rolling 12-month reliability index values (SAIFI, CAIDI, SAIDI, and if available, MAIFI) for the EDC’s service territory for the preceding quarter. The report shall include the data used in calculating the indices, namely the average number of customers served, the number of sustained customer interruptions, the number of customers affected, and the customer minutes of interruption. If MAIFI values are provided, the report shall also include the number of customer momentary interruptions.

   (3)  Rolling 12-month reliability index values (SAIFI, CAIDI, SAIDI, and if available, MAIFI) and other pertinent information such as customers served, number of interruptions, customer minutes interrupted, number of lockouts, and so forth, for the worst performing 5% of the circuits in the system. An explanation of how the EDC defines its worst performing circuits shall be included.

   (4)  Specific remedial efforts taken and planned for the worst performing 5% of the circuits as identified in paragraph (3).

   (5)  A rolling 12-month breakdown and analysis of outage causes during the preceding quarter, including the number and percentage of service outages, the number of customers interrupted, and customer interruption minutes categorized by outage cause such as equipment failure, animal contact, tree related, and so forth. Proposed solutions to identified service problems shall be reported.

   (6)  Quarterly and year-to-date information on progress toward meeting transmission and distribution inspection and maintenance goals/objectives (for first, second and third quarter reports only).

   (7)  Quarterly and year-to-date information on budgeted versus actual transmission and distribution operation and maintenance expenditures in total and detailed by the EDC’s own functional account code or FERC account code as available. (For first, second and third quarter reports only.)

   (8)  Quarterly and year-to-date information on budgeted versus actual transmission and distribution capital expenditures in total and detailed by the EDC’s own functional account code or FERC account code as available. (For first, second and third quarter reports only.)

   (9)  Dedicated staffing levels for transmission and distribution operation and maintenance at the end of the quarter, in total and by specific category (for example, linemen, technician and electrician).

   (10)  Quarterly and year-to-date information on contractor hours and dollars for transmission and distribution operation and maintenance.

   (11)  Monthly call-out acceptance rate for transmission and distribution maintenance workers presented in terms of both the percentage of accepted call-outs and the amount of time it takes the EDC to obtain the necessary personnel. A brief description of the EDC’s call-out procedure should be included when appropriate.

 (f)  The quarterly reliability report for smaller companies (those with less than 100,000 customers) shall, at a minimum, include paragraphs (1), (2) and (5) identified in subsection (e).

 (g)  When an EDC’s reliability performance is found to not meet the Commission’s established performance standards, as defined in §  57.194(h) (relating to distribution system reliability), the Commission may require a report to include the following:

   (1)  The underlying reasons for not meeting the established standards.

   (2)  A description of the corrective measures the EDC is taking and target dates for completion.

 (h)  An EDC shall, within 30 calendar days, report to the Commission any problems it is having with its data gathering system used to track and report reliability performance.

 (i)  When an EDC implements a change in its outage management system for gathering and analyzing reliability performance that has the potential to affect reliability index values, the EDC shall conduct parallel measurement and analysis to isolate and quantify the influence that the measurement change exerts on reliability index values. The length of the parallel measurement period shall be sufficient to isolate and quantify the independent effects of the measurement change.

 (j)  The Commission will prepare an annual reliability report and make it available to the public.

   The provisions of this §  57.195 amended under the Public Utility Code, 66 Pa.C.S. §  501; and the Electric Generation Customer Choice and Competition Act, 66 Pa.C.S. § §  2801—2812.

   The provisions of this §  57.195 amended September 17, 2004, effective September 18, 2004, 34 Pa.B. 5135. Immediately preceeding text appears at serial pages (246400) and (252065).

 (a)  An electric generation supplier shall operate and maintain its generating facilities in conformity with the operating policies, criteria, requirements and standards of NERC and the appropriate regional reliability councils, or successor organizations.

 (b)  An electric generation supplier shall maintain appropriate generating reserve capacity in compliance with any applicable reserve requirement standards set forth by the appropriate regional reliability council, successor organizations or other entity or agency with jurisdiction to establish the requirements.

 (c)  An electric generation supplier shall abide by applicable Commission regulations, procedures and orders, including emergency orders.

 (d)  An electric generation supplier shall maintain membership, to the extent required by any regional reliability council, independent system operator or similar organization, in the appropriate regional reliability councils, or successor organizations.

 (a)  The Commission staff may initiate an investigation, or may do so upon complaint by an affected party, to determine whether an electric distribution company is providing service in accordance with § §  57.193 and 57.194 (relating to transmission system reliability; and distribution system reliability).

   (1)  Based upon the record developed in such an investigation, the Commission may enter an order directing the electric distribution company to take reasonable corrective action necessary to improve the reliability of electric service.

   (2)  If the Commission directs an electric distribution company to make expenditures to repair or upgrade its transmission or distribution system, the electric distribution company may seek an exception to the limitations in 66 Pa.C.S. §  2804(4) (relating to electric utility rate caps).

 (b)  The Commission staff may initiate an investigation, or may do so upon complaint by an affected party, to determine whether an electric generation supplier is providing reasonable service in accordance with §  57.196 (relating to generation reliability).

   (1)  Based upon the record developed in such an investigation, the Commission may enter an order directing the electric generation supplier to take the corrective action the Commission deems necessary to improve the reliability of service.

 (a)  Filing date and plan components. Every 2 years, by October 1, an EDC shall prepare and file with the Commission a biennial plan for the periodic inspection, maintenance, repair and replacement of its facilities that is designed to meet its performance benchmarks and standards under this subchapter. EDCs in Compliance Group 1, as determined by the Commission, shall file their initial plans on October 1, 2009. EDCs in Compliance Group 2, as determined by the Commission, shall file their initial plans on October 1, 2010. Each EDC’s biennial plan must cover the 2 calendar years beginning 15 months after filing, be implemented 15 months after filing, and must remain in effect for 2 calendar years thereafter. In preparing this plan, the following facilities are critical to maintaining system reliability:

   (1)  Poles.

   (2)  Overhead conductors and cables.

   (3)  Transformers.

   (4)  Switching devices.

   (5)  Protective devices.

   (6)  Regulators.

   (7)  Capacitors.

   (8)  Substations.

 (b)  Plan consistency. The plan must be consistent with the National Electrical Safety Code, Codes and Practices of the Institute of Electrical and Electronic Engineers, Federal Energy Regulatory Commission Regulations and the provisions of the American National Standards Institute, Inc.

 (c)  Time frames. The plan must comply with the inspection and maintenance standards in subsection (n). A justification for the inspection and maintenance time frames selected shall be provided, even if the time frame falls within the intervals prescribed in subsection (n). However, an EDC may propose a plan that, for a given standard, uses intervals outside the Commission standard, provided that the deviation can be justified by the EDC’s unique circumstances or a cost/benefit analysis to support an alternative approach that will still support the level of reliability required by law.

 (d)  Routine inspection and maintenance. The plan must specify for the standards in subsection (n) the routine inspection and maintenance requirements, and emergency maintenance plans and procedures.

 (e)  Reduction of risk of outages. The plan shall be designed to reduce the risk of outages by accounting for age, condition, technology, design and performance of system components and by inspecting, maintaining, repairing, replacing and upgrading the system.

 (f)  Clearance of vegetation. The plan must include a program for the maintenance of clearances of vegetation from the EDC’s overhead distribution facilities.

 (g)  Consistency with reliability reports. The plan must form the basis of, and be consistent with, the EDC’s inspection and maintenance goals and objectives included in subsequent annual and quarterly reliability reports filed with the Commission under § §  57.193(c) and 57.195 (relating to transmission system reliability; and reporting requirements).

 (h)  Review procedure. Within 90 days of receipt of the plan, the Commission or the Director of the Bureau of Conservation, Economics and Energy Planning (CEEP) will accept or reject the plan in writing.

 (i)  Deemed acceptance. Absent action by the Commission or the Director of CEEP to reject the plan within 90 days of the plan’s submission to the Commission, the plan will be deemed accepted.

 (j)  Plan deficiencies. If the plan is rejected, in whole or in part, by the Commission or the Director of CEEP, the EDC will be notified of the plan’s deficiencies and directed to submit one of the following:

     (i)   A revised plan, or pertinent parts of the plan, addressing the identified deficiencies.

     (ii)   An explanation why the EDC believes its plan is not deficient. The revised plan is deemed accepted absent any action by the Commission within 90 days of the filing.

 (k)  Appeal procedure. An EDC may appeal the Commission staff’s determination under subsection (h) by filing an appeal under §  5.44 (relating to petitions for appeal from actions of the staff) within 20 days after service of notice of the action. A final Commission determination is appealable to the Commonwealth Court. Absent having a granted stay, the EDC is obligated to comply with the Commission’s directives regarding its inspection, maintenance, repair and replacement plans.

 (l)  EDC updates. An EDC may request approval from the Commission for revising its approved plan. An EDC shall submit to the Commission, as an addendum to its quarterly reliability report under § §  57.193(c) and 57.195, prospective and past revisions to its plan and a discussion of the reasons for the revisions. Within 60 days, the Commission or the Director of CEEP will accept or reject the revisions to the plan. The appeal procedure in subsection (k) applies to the appeal of a rejection of revisions to the plan.

 (m)  Recordkeeping. An EDC shall maintain records of its inspection and maintenance activities sufficient to demonstrate compliance with its distribution facilities inspection, maintenenance, repair and replacement programs as required by subsection (n). The records shall be made available to the Commission upon request within 30 days. Examples of sufficient records include:

   (1)  Date-stamped records signed by EDC staff who performed the tasks related to inspection.

   (2)  Maintenance, repair and replacement receipts from independent contractors showing when and what type of inspection, maintenance, repair or replacement work was done.

 (n)  Inspection and maintenance intervals. An EDC shall maintain the following inspection and maintenance plan intervals:

   (1)  Vegetation management. The Statewide minimum inspection and treatment cycle for vegetation management is between 4-8 years for distribution facilities. An EDC shall submit a condition-based plan for vegetation management for its distribution system facilities explaining its treatment cycle.

   (2)  Pole inspections. Distribution poles shall be inspected at least as often as every 10—12 years except for the new southern yellow pine creosoted utility poles which shall be initally inspected within 25 years, then within 12 years annually after the initial inspection. Pole inspections must include:

     (i)   Drill tests at and below ground level.

     (ii)   A shell test.

     (iii)   Visual inspection for holes or evidence of insect infestation.

     (iv)   Visual inspection for evidence of unauthorized backfilling or excavation near the pole.

     (v)   Visual inspection for signs of lightening strikes.

     (vi)   A load calculation.

   (3)  Pole inspection failure. If a pole fails the groundline inspection and shows dangerous conditions that are an immediate risk to public or employee safety or conditions affecting the integrity of the circuit, the pole shall be replaced within 30 days of the date of inspection.

   (4)  Distribution overhead line inspections. Distribution lines shall be inspected by ground patrol a minimum of once every 1-2 years. A visual inspection must include checking for:

     (i)   Broken insulators.

     (ii)   Conditions that may adversely affect operation of the overhead transformer.

     (iii)   Other conditions that may adversely affect operation of the overhead distribution line.

   (5)  Inspection failure. If critical maintenance problems are found that affect the integrity of the circuits, they shall be repaired or replaced no later than 30 days from discovery.

   (6)  Distribution transformer inspections. Overhead distribution transformers shall be visually inspected as part of the distribution line inspection every 1-2 years. Above-ground pad-mounted transformers shall be inspected at least as often as every 5 years and below-ground transformers shall be inspected at least as often as every 8 years. An inspection must include checking for:

     (i)   Rust, dents or other evidence of contact.

     (ii)   Leaking oil.

     (iii)   Installation of fences or shrubbery that could adversely affect access to and operation of the transformer.

     (iv)   Unauthorized excavation or changes in grade near the transformer.

   (7)  Recloser inspections. Three-phase reclosers shall be inspected on a cycle of 8 years or less. Single-phase reclosers shall be inspected as part of the EDC’s individual distribution line inspection plan.

   (8)  Substation inspections. Substation equipment, structures and hardware shall be inspected on a cycle of 5 weeks or less.

   The provisions of this §  57.198 adopted under the Public Utility Code, 66 Pa.C.S. § §  501, 57.191—57.197 and Chapter 28.

   The provisions of this §  57.198 adopted September 26, 2008, effective September 27, 2008, 38 Pa.B. 5273.