§ 57.1. Definitions.

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

   Alternate route or alternative route—A reasonable right-of-way which includes not more than 25% of the right-of-way of the applicant’s proposed route.

   Commence construction—To begin clearing or disturbing the land or the first act in erecting thereon an artificial structure, but does not include action necessary for the purpose of gathering survey, geological, environmental or similar data.

   Customer—A party supplied with electric service by a public utility.

   Customer’s installation—Wiring and equipment on the premises of a customer, and poles, wires or cables and other facilities necessary to bring the terminus of the wiring of a customer to a location where it may be connected to the service line.

   Electric supply line—The wires or cables, with the necessary supporting or containing structures and appurtenances, used in connection with an overhead or underground system of a public utility, providing electric power, located on a public highway or utility right-of-way and used to transmit or distribute electric energy.

   Eminent domain application—An application filed with the Commission by a public utility for a certificate of public convenience for approval of the exercise of the power of eminent domain to acquire rights-of-way for the construction, operation and maintenance of an aerial transmission line.

   Existing transmission line right-of-way—A right-of-way of sufficient width to accommodate two or more transmission lines on May 20, 1978 and on which at least one transmission line was erected as of May 20, 1978, or a right-of-way of sufficient width to accommodate two or more lines for which siting approval was received and on which at least one line has been constructed.

   HV transmission line or HV line—An overhead electric supply line with a design voltage greater than 100,000 volts.

   Line extension—An addition to the public utility electric supply line necessary to serve the premises of a customer which addition is so located that it cannot be supplied by means of a service line from the existing electric supply line.

   Proposed route—The right-of-way on which the applicant desires to construct an HV transmission line.

   Public utility—Persons or corporations in this Commonwealth owning or operating equipment or facilities for generating, transmitting, distributing or furnishing electricity for the production of light, heat or power to or for the public for compensation. The term does not include either of the following:

     (i)   A person or corporation not otherwise a public utility who or which furnishes service only to himself or itself.

     (ii)   A bona fide cooperative association which furnishes service only to its stockholders or members on a nonprofit basis.

   Service line—The wires or cables and appurtenances which connect the electric supply line of the public utility with the customer’s installation and which comply with either of the following:

     (i)   If overhead-open-wire or cable-construction, the span, normally 100 feet, extending to a suitable support provided by the customer.

     (ii)   If the electric supply line is of underground construction, the underground facilities extending to but not exceeding 18 inches inside the property line of the customer.

   Service terminal—The point at which the service lines of the public utility terminate and the customer’s facilities for receiving the service begin.

   Siting application—An application filed with the Commission by a public utility under §  57.71 (relating to application).

   Transmission line—An overhead electric supply line with a design voltage greater than 35,000 volts.

   Transmission line right-of-way—A right enjoyed over the property of another subject to certain conditions which arise by reason of one of the following:

     (i)   A lease.

     (ii)   An easement.

     (iii)   A right to use or license.

     (iv)   An option to buy with right of possession.

     (v)   Ownership in fee simple absolute or any lesser estate of land, obtained for the purpose of constructing and maintaining a transmission line or HV line.

   The provisions of this §  57.1 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

   The provisions of this §  57.1 adopted February 25, 1946; amended through May 29, 1973; amended May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (78435) to (78436).

   Electric Supply Line and Service Line Distinguished

   A supply line, by definition, never connects to buildings, structures, or facilities that use or otherwise consume electrical energy; only service lines perform such a function. This definitional distinction is significant because it justifies consistently treating service lines differently from supply lines with respect to refunding contributions-in-aid-of-construction payments. Kossman v. Pennsylvania Public Utility Commission, 694 A.2d 1147 (Pa. Cmwlth. 1997).

   This section cited in 52 Pa. Code §  57.144 (relating to transmission line projection).

Subchapter B. SERVICE AND FACILITIES

Sec.

§ 57.11. Accidents.

 (a)  General. A public utility shall submit a report of each reportable accident involving the facilities or operations of the public utility in this Commonwealth to the Secretary of the Commission.

 (b)  Reportable accidents. Reportable accidents are those involving utility facilities or operations which result in one or more of the following circumstances:

   (1)  The death of a person.

   (2)  Injury to an employe on duty sufficient to incapacitate him from performing his ordinary duties for a period longer than 3 days.

   (3)  Injury to a person other than an employe on duty sufficient to incapacitate the injured person from following his customary vocation, or mode of life, for a period of more than 1 day.

   (4)  An occurrence of an unusual nature, whether or not death or injury of a person results, which apparently will result in a prolonged and serious interruption of normal service.

 (c)  Telegraphic reports. A report by telephone or telegraph shall be made at once in the event of the occurrence of a reportable accident resulting in the death of a person or in an occurrence of an unusual nature.

 (d)  Written reports. A written report shall be made on Form UCTA-8 immediately following the occurrence of a reportable accident. Accidents reportable on forms required by the Bureau of Workmen’s Compensation, Pennsylvania Department of Labor and Industry, may be reported by transmitting a copy of such reports in lieu of a report on Form UCTA-8.

 (a)  Investigations. A public utility shall make a full and prompt investigation of complaints made by its customers, either directly to it or through the Commission.

 (b)  Record of complaints. A public utility shall preserve written electric service complaints showing the name and address of the complainant, the date and nature of the complaint, the action taken and the date of final disposition.

 (a)  Standard voltage. A public utility shall adopt a standard nominal service voltage for the entire territory served by the public utility, and shall file with the Commission data on such standard service voltage or voltages as part of its officially filed tariff. The suitability and adequacy of the standard nominal service voltage or voltages adopted may be determined at any time by the Commission.

 (b)  Allowable voltage variation (primarily lighting). For service rendered primarily for lighting purposes, the allowable variation in voltage measured at the service terminals of the customer may not exceed, for a longer period than 1 minute in each instance, 5% above or below the standard nominal service voltage and a total variation from minimum to maximum of 8% during normal system operation.

 (c)  Allowable voltage variation (primarily power). For service rendered primarily for power purposes, the allowable variation in voltage measured at the service terminals of the customer may not exceed, for a longer period than 1 minute in each instance, 10% above or below the standard nominal service voltage during normal system operation.

 (d)  Variation in excess of allowable limits.

   (1)  A public utility may, if approved by the Commission, furnish service under conditions of greater voltage variations if there is a filing of the following with the Commission:

     (i)   A copy of existing contracts containing a provision for the supply of service with such greater variations of voltage.

     (ii)   A copy of contracts made which contemplate the supply of service under conditions of greater voltage variations and which in each case contain a clause stating the probable variations in voltage which will occur in the service rendered under such contract, and further that such greater variations in voltage will not result in unreasonable discrimination in favor of or against any customer.

   (2)  Variations of voltage in excess of those specified, caused by the operations of the facilities of the customer in violation of his contract or the filed tariff rules of the public utility, or from causes beyond the control of the public utility, will not be considered as violations of this section.

 (e)  Records. A public utility shall keep in continuous operation at least one graphic recording voltmeter on each primary network system or on at least one circuit from each substation supplying more than 1,000 customers. These meters shall be installed either at the substation or near the load center of such area or circuits. The hourly readings of indicating voltmeters recorded at points of supply, such as generating stations and main transmission or distribution substations where attendants are regularly on duty, shall constitute a satisfactory voltage record. A public utility shall also install additional graphic recording voltmeters at such places and for such periods of time as the Commission may require.

   The provisions of this §  57.14 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

 (a)  Standard frequency. An electric distribution company supplying alternating current service shall adopt and file with the Commission a standard frequency or frequencies for its system, the suitability of which may at any time be determined by the Commission.

 (b)  Allowable variation. An electric distribution company shall maintain the system frequency within 3% of the standard frequency adopted. Momentary variations of frequency of more than 3%, which are clearly not due to lack of proper equipment or reasonable care on the part of the electric distribution company will not be considered as violations of this section.

 (c)  Records. An electric distribution company shall continuously monitor and record system frequency variations. The records shall be provided to the Commission on request.

 (a)  Records required. A public utility shall keep in continuous operation meters and instruments and maintain records necessary to determine the characteristics of the system load and the mode of operation.

 (b)  Content of records. Records of load and operation shall include all of the following:

   (1)  Operation of a turboelectric and hydroelectric generating station.

   (2)  Readings of switchboard recording instruments at attended generating stations and substations. The hourly readings of indicating instruments recorded at regularly attended generating stations and substations shall constitute a satisfactory continuous record.

 (c)  Records of electric energy transactions. A public utility purchas-ing, selling or interchanging electric energy or power from, to, or with another public utility under the jurisdiction of the Commission shall install such instruments and meters as may be necessary to furnish continuous records of the energy and demand involved, unless such other public utility has itself installed such instruments and meters from which these records may be obtained. A public utility purchasing, selling, or interchanging electric energy or power from, to, or with a utility not under the jurisdiction of the Commission shall install or cause to be installed such instruments and meters as may be necessary to furnish continuous records of the energy and demand involved.

   The provisions of this §  57.16 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

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

   Contractor cost—The amount paid by a public utility to a contractor for work performed on a line extension.

   Direct labor cost—The pay and expenses of public utility employes directly attributable to work performed on line extensions, but does not include construction overheads or payroll taxes, workmen’s compensation expenses or similar expenses.

   Direct material cost—The purchase price of materials used for a line extension, but does not include related stores expenses. In computing direct material costs proper allowance should be made for unused materials, materials recovered from temporary structures, and discounts allowed and realized in the purchase of materials.

   Maximum extension distance—The distance in feet below which a public utility will provide a line extension without imposing a charge on or requiring a revenue guarantee from the customer requesting the extension.

 (b)  Duty to make line extensions. The public utility shall make line extensions within the territory in which it is authorized to operate.

 (c)  Tariffs to include line extension rule. The public utility shall file with the Commission as part of its tariffs a rule setting forth its maximum extension distance for single-phase line extensions and the conditions under which it will make the line extensions beyond this distance. The rule shall also include a plan whereby the public utility will construct, operate, and maintain single-phase and polyphase line extensions required to serve customers who will guarantee revenues in an amount sufficient to comply with the requirements set forth in the rule, and a statement of the terms upon which the guarantee shall be reduced to the minimum charges as provided in the rate schedules applicable to each class of service supplied.

 (d)  Determination of guarantees for single-phase line extensions. The amount of revenue to be guaranteed and subsequent changes thereto shall be determined solely on the basis of contractor costs, direct labor costs and direct material costs attributable to the construction of the line extension beyond the maximum extension distance. Appropriate adjustments shall be made at least annually in the amount of revenue guaranteed by a customer by reason of change in the number or classification of customers supplied from the line extension. The amount of costs attributable to the construction of a line extension below the maximum extension distance may be determined by multiplying the cost of the line extension by the percentage of distance of the line extension below the maximum extension distance.

 (e)  Determination of guarantees for polyphase line extensions. In determining the revenues originally to be guaranteed and subsequent changes, the following conditions shall be applicable, as appropriate:

   (1)  Guarantees of revenue shall be based upon the total construction cost to the public utility of the line extension.

   (2)  Guarantees of revenue shall be based upon the length of pole line required to furnish service.

   (3)  Guarantees shall be based upon a reasonable plan by which the construction cost, length of line extension, or number of customers served or to be served from the line extension are given consideration.

   (4)  Appropriate adjustments shall be made at least annually in the amount of revenue guaranteed by the customer by reason of change in the number or classification of customers supplied from the line extension.

 (f)  Service to additional customers. Additional customers shall be connected to a line extension of a line already built or to a further extension of a line only upon the same terms and conditions as would apply if the extension were being made for customers including the new customers, if the inclusion of new customers would not increase the guarantees of the existing customers. If the guarantees of existing customers would be increased, the line extension constructed to serve additional customers shall be considered and treated as a new and separate line extension for these additional customers.

 (g)  Wiring and equipment of customers. Wiring and equipment on the premises of the customer shall be installed to conform with the rules and standards established by the public utility. The customer shall provide poles, wires and other construction necessary to bring the terminus of the customer’s installation to a location where it may be connected to a line extension by means of a service line.

 (h)  Underground electrical service in new residential developments. Extensions of underground electrical service in new residential developments, as defined in §  57.81 (relating to definitions), shall conform to § §  57.81—57.87.

   The provisions of this §  57.19 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

 (a)  No watthour meter which has an incorrect register constant, test constant, gear ratio or dial train, or which ‘‘creeps,’’ that is, registers upon no load, may be placed in service or allowed to remain in service without adjustment and correction. A meter in service creeps if, with the load wires disconnected, the moving element makes one complete rotation in 5 minutes or less.

 (b)  For the purpose of this section, the term ‘‘light load’’ means not less than 10%, nor more than 15%, of the rated test current of the meter. The term ‘‘heavy load’’ means not less than 75%, nor more than 100%, of the rated test current of the meter.

 (c)  No watthour meter which has an error in registration of more than 2.0% at light load or heavy load may be placed in service or allowed to remain in service without adjustment. If, upon installation, periodic or other tests, a watthour meter is found to exceed these limits, it shall be adjusted or removed from service.

 (d)  A public utility shall maintain records of service watthour meters. The record for a meter shall identify the manufacturer, type, rating, year of purchase, year and location of the present installation in service, the year of the last test and the reason for the test, the registration accuracy recorded as found before adjustment and the registration accuracy recorded as left upon the completion of the test.

 (e)  A public utility shall make periodic tests of its watthour meters in service as follows:

   (1)  Two and three-wire single-phase and network-induction-type meters, up to and including 50 amperes rated test current, shall be tested at least once in each of the following periods:

     (i)   If manufactured prior to January 1, 1940, and the meters are not Class I and II temperature compensated and are not equipped with surge-proofed magnets or surge shields—3 years.

     (ii)   If the meters are Class I and II temperature compensated and are equipped with surge-proofed magnets or surge shields—15 years.

     (iii)   If manufactured since January 1, 1959, and the meters are Class I and II temperature compensated and are equipped with surge-proofed magnets, surge discharge gaps and a shielded magnetic bearing system—20 years.

   (2)  An an alternative, meters described in paragraph (1)(ii) and (iii) shall be tested according to statistical procedure in Section 8.1.8.6 of the current edition of the ANSI C-12 Code for Electric Meters, Fifth Edition.

     (i)   Groups which meet the accuracy requirements of the applied statistical procedure shall continue in service without test or adjustment until a subsequent annual statistical analysis indicates the need for corrective action or the Commission on its own motion requests retest of either entire groups or individual meters. Test results affecting billing shall be furnished to customers without charge.

     (ii)   Groups which fail to meet the accuracy requirements of the applied statistical procedure are subject to one of the following immediate corrective measures:

       (A)   Meters within the group affected shall be removed from service upon notification to the Commission and in compliance with a program acceptable to the Commission. A customer’s accounts billed according to registration by these meters shall be retained by the public utility from 2 years prior to discovery of registration error until date of meter removal or adjustment. Test results affecting billing shall be furnished to customers without charge and shall be retained by the public utility for at least 2 years after the meter is retired.

       (B)   Meters within groups affected shall be placed on an accelerated program of testing and maintenance until subsequent annual statistical analysis indicates that the affected groups again meet the accuracy requirements of the statistical testing program. Records of customer accounts and of test results affecting billing shall be retained by the public utility and furnished to customers under clause (A).

   (3)  Two and three-wire single-phase and network-induction-type meters, of over 50 amperes rated test current, shall be tested at least once every 8 years.

   (4)  Single-phase meters connected through current transformers or current and voltage transformers shall be tested as follows:

     (i)   Meters without surge-proof magnets, at least once every 8 years.

     (ii)   Meters with surge-proof magnets, at least once every 16 years.

   (5)  Self-contained polyphase meters shall be tested as follows:

     (i)   Meters without surge-proof magnets, at least once every 8 years.

     (ii)   Meters with surge-proof magnets, at least once every 16 years or according to statistical procedures as described in paragraph (2).

   (6)  Polyphase meters connected through current transformers or current and voltage transformers shall be tested as follows:

     (i)   Meter without surge-proof magnets, at least once every 8 years.

     (ii)   Meters with surge-proof magnets, at least once every 16 years.

 (f)  An alternating current watthour meter shall be tested and adjusted before installation for correct registration within ±2%, at a power factor of approximately 50% and 100% at rated test current. When in service, meters not tested and adjusted before installation shall be tested and adjusted to the percent accuracy specified as soon as the circumstances permit, or shall be removed from service.

 (g)  A service watthour meter installed shall be tested for accuracy by the public utility prior to its installation, or shall be so tested within 90 days after its installation. It shall also be inspected by the public utility for proper connection, mechanical condition and suitability of location within 90 days after installation.

 (h)  A service watthour meter which is removed from service shall be tested for ‘‘as found’’ registration accuracy.

   The provisions of this §  57.20 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.20 adopted February 25, 1946; amended through May 29, 1973; amended January 2, 1981, effective January 3, 1981, 11 Pa.B. 19; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324. Immediately preceding text appears at serial pages (103566) to (103567) and (80594) to (80595).

 (a)  A demand meter of the block interval type, which fails to properly reset completely to zero at the end of each time interval, or a demand meter which has an incorrect register constant, test constant gear ratio or dial train may not be placed in service or allowed to remain in service without adjustment and correction.

 (b)  Tests of graphic and indicating types of demand meters shall be made at points about 1/3 to 2/3 scale in terms of full scale indication. The deviation shall be recorded in terms of full scale deflection.

 (c)  A demand meter of the block interval type which has an error in demand indication of more than ±2% in terms of full scale indication on graphic and indicating meters may not be placed in service or allowed to remain in service without adjustment. If a timing element also serves to keep a record of the time of day at which the demand occurs, it shall be adjusted if its rate is more than ±.25% in error.

 (d)  A thermal type demand meter which has an error in demand indication or registration of more than ±3% in terms of full scale indication on graphic and indicating meters may not be placed in service or allowed to remain in service without adjustment. If a timing element also serves to keep a record of the time of day at which the demand occurs, it shall be adjusted if its rate is more than -.25% in error.

 (e)  A demand meter with solid state digital display for measured quantities shall be tested for accuracy of the register using its internal input pulse initiator and a watthour meter or using an auxiliary pulse device as the input source. The applied test current or pulse rate may not exceed the class of the meter. The accuracy of the displayed demand shall be within ±2.0% of the input.

 (f)  A utility shall make periodic test of its demand meters in service, as follows:

   (1)  Self-contained thermal demand meters, up to and including 50 amperes rated test current, shall be tested on the same schedule as the watthour meters with which they are associated.

   (2)  Self-contained thermal demand meters, of over 50 amperes rated test current, shall be tested at least once every 96 months.

   (3)  Thermal demand meters connected through current transformers or current and potential transformers shall be tested at least once every 48 months.

   (4)  Curve drawing watt meters used for determining demands shall be tested at least once every 24 months.

   (5)  Demand meters of the block interval type shall be tested on the same schedule as the watthour meters with which they are associated.

 (g)  A demand meter shall be tested for accuracy by the public utility prior to its installation, or be so tested within 90 days after its installation. It shall also be inspected by the public utility for proper connection, mechanical condition and suitability of location within 90 days after installation.

   The provisions of this §  57.21 issued under: the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501; amended under: Public Utility Code,66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.21 adopted February 25, 1946; amended through May 29, 1973; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324; amended March 8, 1991, effective March 9, 1991, 21 Pa.B. 947. Immediately preceding text appears at serial pages (125377) to (125378).

 (a)  Tests by the public utility. A public utility shall make a test of the accuracy of registration of a service meter upon the written request of the customer for whom the meter is installed upon payment of the fee specified in this section. If a customer desires either personally or by a representative to witness the testing of a meter, the customer may require the seal of the meter to be broken only in the customer’s presence or that of a representative. If the meter tested upon request is found to be accurate within the limits specified in § §  57.20 and 57.21 (relating to watthour meter testing; and demand meter testing), the fee shall be retained by the public utility. If not so found, the cost shall be borne by the public utility furnishing the service and the fee paid by the customer shall be refunded. A report of the test shall be made to the customer.

 (b)  Tests by the Commission. If service meter test is to be made by the Commission upon written request and payment of the fee by the customer, as specified in this section, the public utility owning the meter shall be notified that a test is to be made and shall have a representative present to open the meter, assist in the test and adjust and seal the meter after the test. If a tested meter is found to be accurate within the limits specified in § §  57.20 and 57.21, the fee paid for the test shall be retained by the Commission. If not so found, the fee shall be refunded to the customer and the cost of the test shall be borne by the public utility furnishing the service. A public utility may apply in writing for a test of a meter and, upon payment of the fee specified for that class of meter, the Commission will make the test and furnish the public utility with a record of the results.

 (c)  Meter testing fees. Meter testing fees for watthour and demand meters shall be as follows:

   (1)  Direct current and single-phase self-contained watthour meters operating on 600 volts or less shall be $20.

   (2)  Single-phase transformer-rated and polyphase watthour meters with or without instrument transformers shall be $38.

   (3)  In addition to charges associated with paragraphs (1) and (2) there shall be an additional charge of $11 for block interval or thermal demand registers and separate demand recorders.

   The provisions of this §  57.22 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.22 adopted February 25, 1946; amended through May 29, 1973; amended January 2, 1981, effective January 3, 1981, 11 Pa.B. 19; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324. Immediately preceding text appears at serial pages (80597) to (80598).

 (a)  Location. Tests provided for in § §  57.20 and 57.21 (relating to watthour meter testing; and demand meter testing), except those made previous to installation, shall be made in the place of permanent location on the premises of the customer or at a laboratory equipped with adequate facilities for making tests.

 (b)  Tests of meters with accessories. Service meters connected to the line through instrument transformers, shunts or multipliers shall be tested jointly with accessories, unless the tests for ratio and phase angle of the instrument transformers and the resistance of the shunts have been determined in a laboratory before installation, or unless their operating characteristics affecting metering accuracy have been determined in service within the previous 10 years and are on the records of the public utility. Laboratory tests shall be deemed acceptable only when made by the National Bureau of Standards, a standardizing laboratory approved by the Commission, or by the laboratory of the public utility, whose standards have been checked, and are subject to further checks or tests by the Commission.

 (c)  Adjustment after test. Meters shall be adjusted as closely as practicable to the condition of zero error; the tolerances specified shall be interpreted as maximum variations from adjustments to the condition of zero error. In the adjustment of meters no improper advantages of prescribed tolerance limits shall be taken.

 (d)  Change of frequency. If a public utility changes its standard of frequency, it shall give reasonable notice to the customers it is serving and make necessary tests and readjust service meters as soon as practicable.

   The provisions of this §  57.23 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.23 adopted February 25, 1946; amended through May 29, 1973; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324. Immediately preceding text appears at serial pages (80598) to (80599).

 (a)  Average meter error. In meter tests made by the public utility or by the Commission at the request of a customer, the correctness of adjustment of the meter and its performance in service shall be judged by its average error, determined as follows:

   (1)  If the meter is used to measure a load which is substantially constant, the meter shall be tested at that load. The error of the meter at the constant load shall be accepted as the average meter error.

   (2)  If the meter is used to measure a variable load, the average error shall be obtained by taking 1/5 of the algebraic sum of both of the following:

     (i)   One part of the error at light load.

     (ii)   Four parts of the error at heavy load.

   (3)  If, in the opinion of the Commission, another load is more representative of the average operating load, the error of the meter at the average operating load will be accepted as the average meter error.

 (b)  Fast meters. If, upon testing, a meter is found to have an average meter error of more than 2% fast, the public utility shall refund to the customer the overcharge, based upon the corrected meter reading for a period equal to 1/2 the time elapsed since the last previous test, but not to exceed 12 months. If the period of registration error is definitely fixed, the overcharge shall be computed for the period. If the meter has not been tested in accordance with §  57.20 (relating to watthour meter testing), the period for which it has been in service beyond the regular test period shall be added to the 12 months in computing the refund.

 (c)  Slow meters. If, upon testing, a meter is found to have an average meter error of more than 2% slow, the public utility may render a bill for the service furnished, but not covered by bills previously rendered, for a period equal to 1/2 the time elapsed since the last previous test, but not to exceed 3 months. If the period of registration error is definitely fixed, the charge may be computed for the period.

 (d)  Access to meters. The public utility shall, at reasonable times, have access to meters, service lines and other property owned by it on premises of customers, for purposes of maintenance and operation. Neglect or refusal on the part of customers to provide reasonable access to their premises for these purposes is deemed to be sufficient cause for the discontinuance of service.

   The provisions of this §  57.24 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.24 adopted February 25, 1946; amended through May 29, 1973; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324. Immediately preceding text appears at serial page (80599).

 (a)  Adequate testing facilities. A public utility shall provide for, and have available, suitable and adequate facilities for testing its meters. Public utilities not maintaining standardizing laboratories may, upon permission from the Commission, have their meters and instruments certified by a standardizing laboratory approved by the Commission.

 (b)  Periodic tests of reference standards. The watthour meter reference standard for the public utility and shall be periodically tested for accuracy and adjusted if necessary by a representative of the Commission at a place the Commission may direct. Immediately after making final adjustment, the tester shall seal and date tag the reference standard and shall furnish the public utility with a correction curve properly dated and signed.

 (c)  Periodic tests of watthour standards. The portable watthour standards, together with other measuring equipment the Commission may require, shall also be tested and adjusted periodically by a representative of the Commission if necessary as the Commission may direct. The tester shall furnish the public utility with a correction curve properly dated and signed.

 (d)  Frequency of portable watthour standard check tests. During the interval between tests by the Commission, the portable watthour standards shall be compared with the reference standard at least every month for induction type meters, and every 3 months for the solid state meter standards. The calibration obtained shall be used in determining the accuracy of the service meters. If a portable standard is subject to either a mechanical or electrical shock, it shall be tested before being used.

 (e)  Records of check tests and correction curves. A record of check tests shall be kept showing the condition and accuracy of the watthour standard before and after testing, indicated by the words ‘‘as found’’ and ‘‘as left,’’ in form and detail to permit convenient checking of the methods and results. A complete record of the check tests and correction curves furnished by the Commission shall be preserved for 5 years.

 (f)  Fees for testing appliances of public utilities. The Commission will charge and collect from public utilities, for the testing of their instruments of precision and measuring apparatus, fees according to the following schedule:

   The provisions of this §  57.25 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501; amended under the Public Utility Code, 66 Pa.C.S. § §  501, 1501 and 1504.

   The provisions of this §  57.25 adopted February 25, 1946; amended through May 29, 1973; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended August 7, 1987, effective August 8, 1987, 17 Pa.B. 3324. Immediately preceding text appears at serial pages (80600) to (80601).

   The provisions of this §  57.26 adopted February 25, 1946; amended through May 29, 1973; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended January 24, 1997, effective January 25, 1997, 27 Pa.B. 414; amended July 17, 1998, effective July 18, 1998, 28 Pa.B. 3385. Immediately preceding text appears at serial pages (225733) to (225734).

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

   Contractor costs—The amount paid by a public utility to a contractor for work performed on a pole removal or relocation.

   Direct labor costs—The pay and expenses of public utility employes directly attributable to work performed on pole removals or relocations, but does not include construction overheads or payroll taxes, workmen’s compensation expenses or similar expenses.

   Direct material costs—The purchase price of materials used in performing a pole removal or relocation, but does not include related stores expenses. In computing direct material costs, proper allowance should be made for unused materials, materials recovered from temporary structures, and for discounts allowed and realized in the purchase of materials.

   Pole removal or relocation—The removal or relocation of distribution line poles and their associated attachments made under the request of a residential property owner who is not entitled to receive condemnation damages to cover the cost of the pole removal or relocation. The term does not include pole repairs or replacements necessitated by the intentional or negligent conduct of a party.

 (b)  Tariff provisions. A public utility shall file as part of its tariff provisions setting forth its method of determining pole removal or relocation charges.

 (c)  Charges. Pole removal or relocation charges shall be limited to the contractor, direct labor and direct material costs associated with the pole removal or relocation less an amount equal to maintenance expenses avoided as a result of the pole removal or relocation.

   The provisions of this §  57.27 adopted July 12, 1985, effective July 13, 1985, 15 Pa.B. 2568.

Subchapter C. PURCHASE AND SALE OF ENERGY AND CAPACITY

Sec.

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

   Avoided costs—The incremental costs to an electric utility of electric energy or capacity, or both, which, but for the purchase from the qualifying facility or qualifying facilities, the utility would generate itself or purchase from another source.

   Back-up power—Electric energy or capacity supplied by an electric utility to replace energy or capacity ordinarily generated by a qualifying facility’s own generation equipment which equipment is not available during an unscheduled outage of the facility.

   Capacity payment—A payment to a supplier of electric capacity by a purchasing utility as provided in §  57.34(c) (relating to purchases of energy and capacity).

   Competitive bidding or auction or solicitation—An established procedure through which offers from qualifying facilities and other suppliers of electric generation or providers of demand-side management programs, or both, are solicited, obtained and selected in order to meet a specified need for electric capacity and associated energy.

   DSM—demand-side management—Programs designed to influence use of electricity on the customer side of the meter.

   EWG—exempt wholesale generator—Independent power producers and utility affiliated generators created under the Energy Policy Act of 1992 (42 U.S.C.A. §  13201), and defined at 15 U.S.C.A. §  79z-5a(a), which sell power exclusively to wholesale power markets.

   Energy payment—A payment to a qualifying facility by a purchasing utility for energy, as defined in §  57.34(b).

   Independent power producer—An electric power supplier which is not a qualifying facility or a public utility.

   Interconnection costs—The reasonable costs of connection, switching, metering, transmission, distribution, safety provisions and administration incurred by the electric utility directly related to the installation and maintenance of the physical facilities necessary to permit interconnection operations with a qualifying facility to the extent these costs are in excess of the corresponding costs which the electric utility would have incurred or charged to the entire customer base to serve the supplier of electric capacity if it had been a customer only.

   Interruptible power—Electric energy or capacity supplied by an electric utility subject to interruption by the electric utility under specified conditions.

   Maintenance power—Electric energy or capacity supplied by an electric utility during scheduled outages of the qualifying facilities.

   Net generating capacity—The gross generation of a power plant minus all of the power that the plant consumes for internal uses.

   Power Plant Life Extension Program—A utility program involving major capital investment in an existing baseload generating facility which will result in a continuation of the facility’s operation beyond its normal operating life.

   Purchases—The buying of electric energy or capacity, or both, from a qualifying facility by an electric utility.

   Qualifying facility—A cogeneration facility or a small power production facility which meets the criteria contained in 18 CFR Part 292 (relating to regulations under sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 with regard to small power producers and cogenerators).

   Rate—A price, rate, charge or classification made, demanded, observed or received with respect to the sale or purchase of electric energy or capacity; a rule, regulation or practice respecting a rate, charge or classification; and a contract pertaining to the sale or purchase of electric energy or capacity.

   Sale—The selling of electric energy or capacity, or both, by an electric utility to a qualifying facility.

   Short-term capacity purchase—A purchase of capacity and associated energy under a contract of not more than 5 years in duration.

   Standard schedule—A tariff schedule available to small qualifying facilities as defined at §  57.34(f).

   Supplementary power—Electric energy or capacity, supplied by an electric utility, regularly used by a qualifying facility in addition to that which the facility generates itself.

   System emergency—A condition on a utility’s system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

   Utility peak periods—The seasonal cost-causative peaks of the electric utility.

   The provisions of this §  57.31 adopted February 25, 1946; amended through May 29, 1973; amended December 29, 1995, effective December 30, 1995, 25 Pa.B. 6085. Immediately preceding text appears at serial pages (195592) to (195593).

   Application

   The regulations found at 52 Pa. Code § §  57.31—57.39 govern only the purchase and sale of energy and energy capacity between public utilities and private ‘‘qualifying facilities’’ and have no application to the internal accounting methods of a utility which allocates cost of its facility generating both steam and electric power to only the steam consumers. University of Pennsylvania v. Pennsylvania Public Utility Commission, 485 A.2d 1217 (Pa. Cmwlth. 1984).

   Federal Requirements

   The practical effect of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C.A. §  824a-3, is to divert potential profits from regulated electric companies, whose earnings are largely based on the value of their owned facilities, to the owners of qualifying facilities. Pennsylvania Electric Co. v. Pennsylvania Public Utility Commission, 677 A.2d 831 (Pa. 1996).

   Notice

   It was unlawful for the Commission to effect a substantive change to a prior opinion and order by applying a 15% limitation to interruptable as well as firm back-up power provided to utility’s self-generating customers without notice to the parties and full opportunity to be heard. Scott Paper Co. v. Pennsylvania Public Utility Commission, 558 A.2d 914 (Pa. Cmwth. 1989).

   Rate

   Under section 1303 of the Code, 66 Pa.C.S. §  1303, the public utility must have actual knowledge of service conditions before it is required to compute the most favorable rate for its customers. Springfield Township v. Pennsylvania Public Utility Commission, 676 A.2d 304 (Pa. Cmwlth. 1996).

 (a)  Purpose. The purpose of this subchapter is to implement §  210 of the Public Utility Regulatory Policies Act of 1978, Pub. L. 95-617, Title II, §  210, 92 Stat. 3144 (16 U.S.C.A. §  824a-3(a)—(j)). To this end, this subchapter details the methodology to be used in establishing rates for sales and purchases, the responsibility for interconnection costs, the standards for system safety and reliability, and the processes by which the Commission will attempt to resolve disputes between utilities and qualifying facilities. This subchapter is intended to equalize the bargaining power of qualifying facilities with that of the utilities and protect the interests of the ratepayers. Furthermore as detailed in subsection (c), utilities are required to implement competitive bidding programs for the purchase of capacity and associated energy unless they are granted a waiver or exemption.

 (b)  Applicability. This subchapter governs the purchases and sales of energy between qualifying facilities and electric utilities. It also governs the purchases and sales of capacity and associated energy between suppliers of electric generation and electric utilities.

 (c)  Negotiated contracts for the purchase of energy.

   (1)  Regarding negotiated contracts for the purchase of energy from a qualifying facility, nothing in this subchapter:

     (i)   Limits or extends the authority of an electric utility to agree to a price for a purchase or to terms or conditions relating to a purchase which differ from the terms or conditions which would otherwise be required by this subchapter.

     (ii)   Affects the validity of a contract entered into between a qualifying facility and an electric utility for any purchase to the extent that contract is valid and in compliance with applicable statutes and regulations.

 (d)  Contract negotiations with winning bidders. Contract negotiations with winning bidders following an auction for the purchase of capacity and associated energy are governed by §  57.34(c)(10) (relating to purchases of energy and capacity).

 (e)  Filing of contracts. A utility shall file with the Commission a copy of a contract or agreement that it enters into with a qualifying facility or other supplier of electric generation with design capacity of 500 kilowatts or more under this subchapter. The contract or agreement shall be filed within 45 days of execution.

   The provisions of this §  57.32 adopted September 17, 1982, effective January 11, 1983, 12 Pa.B. 4237; amended December 29, 1995, effective December 30, 1995, 25 Pa.B. 6085. Immediately preceding text appears at serial pages (195594) to (195595).

   Capacity

 (a)  General provisions. Each utility shall purchase any energy which is made available from a qualifying facility as required by applicable statutes and regulations. Each utility is required to implement an all-source competitive bidding program for the purchase of capacity and associated energy under subsection (c).

 (b)  Purchases of energy only.

   (1)  Energy payments in mills per kilowatt hour shall be based upon costs in this paragraph.

     (i)   Energy payments will be equal to a utility’s highest cost source of energy used to supply the energy requirements of its domestic load customers at all times. When basing contract payments to qualifying facilities on the electric utility’s future avoided cost, the avoided energy cost shall be determined without considering the qualifying facility about to come on line as part of the supply mix.

     (ii)   When the utility’s energy payments for the purchases are based on its own generation, the energy payments shall include the costs of fuel, variable operation and maintenance expenses, and other costs associated with that generation. The costs of units which run, but are not economically dispatched, may be excluded by the utility in the calculation of energy payments. The energy payments shall incorporate the costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility.

     (iii)   When the qualifying facility is larger than 5,000 kilowatts, the utility may base its energy payments on the average cost of its last block of energy of equivalent size rather than its single highest source of energy.

   (2)  Energy payments shall, at the option of the qualifying facility, be based on actual, projected or levelized costs.

     (i)   The actual costs of the purchasing utility calculated at the time of delivery, as described in paragraph (1).

     (ii)   The utility’s projection—for up to 10 years or the length of the contract, whichever is shorter—as filed with the Commission, of its energy costs, as defined in paragraph (1), at the time the qualifying facility elects to accept this projection.

     (iii)   The utility’s filed levelized projected energy costs, as determined by converting the cumulative present value of each year’s costs (projected in accordance with subparagraph (ii)) to an annuity with the same present value, at the time the qualifying facility elects to accept this projection. A zero risk discount factor should be used—such as, the current rate on a United States Treasury Bill of corresponding term. The term of levelization may be no longer than the term of the contract or 10 years, whichever is shorter.

     (iv)   Contracts are required where the parties agree to use a projection or a levelized projection as outlined in subparagraphs (ii) and (iii). When a levelized projection of energy costs is used, or when early year payments exceed projected avoided energy costs, for energy-only contracts, a utility may require security from the qualifying facility only to the extent the early year costs exceed the projection of energy costs for those years. The security may not be a cash deposit and shall be the least burdensome form of security among the following: an irrevocable letter of credit; a payment bond; a fully paid noncancelable project failure insurance policy; or corporate guarantee, lien, mortgage or deed of trust on the facility itself. A utility may not require a qualifying facility to reconcile payments to utility costs actually experienced during the contract period.

     (v)   Contracts may be for a period mutually agreed upon by both buyer and seller.

   (3)  Utilities shall purchase energy from qualifying facilities of 500 kilowatts or greater on a uniform, time of day, seasonal or other cost-justified basis, as determined by the utility.

   (4)  Qualifying facilities of less than 50 kilowatts may opt for net energy billing. Under net energy billing, the energy taken by the qualifying facility from the purchasing utility is billed net of the energy supplied by the qualifying facility to the purchasing utility. However, net energy billing shall not reduce the qualified facility’s minimum bill. Utility policy for net billing is to be filed with the Commission concurrent with other filings required in this subpart.

   (5)  If a qualifying facility and a utility agree for the utility to broker the qualifying facility’s power, the qualifying facility will then be entitled to the total price received by the utility for the energy, less any brokerage fee and other identifiable costs incurred.

 (c)  Mandatory competitive bidding for purchases of capacity and associated energy. Jurisdictional electric utilities with annual gross intrastate operating revenues in excess of $500 million shall establish competitive bidding programs to obtain capacity resources. Utilities are responsible for developing requests for proposals, and negotiating and enforcing contracts. Small qualifying facilities (under 5 megawatts), are exempted from the mandatory competitive bidding requirements. Utilities may purchase capacity and associated energy from small qualifying facilities outside of an all-source competitive bidding program. Utility sponsored DSM programs are exempt from competitive bidding until January 2, 2000.

   (1)  Sources of capacity.

     (i)   A utility shall allow all sources of capacity to submit offers in a competitive bidding program. These sources may include the utility conducting the bid, other electric utilities, qualifying facilities, independent power producers, exempt wholesale generators, marketers, brokers and other entities. An exempt wholesale generator which is an affiliate or an associate of the utility conducting the bid is subject to the prohibitions appearing at 15 U.S.C.A. §  79z-5a(k) (‘‘Protection against abusive affiliate transactions’’). All source bidding programs are encouraged.

     (ii)   Utility participation in its own auction. A utility seeking capacity resources and companies affiliated with the utility may participate in the capacity solicitation. All bids are to be evaluated fairly by an independent third-party evaluator selected by the utility. Abusive self-dealing is prohibited. A utility seeking to participate in its own solicitation or allow its affiliate to participate in that solicitation shall also adhere to the following requirements:

       (A)   Not less than 90 days prior to the filing of a Request for Proposal (RFP) under paragraph (4), the electric utility shall specify in writing to the Commission the names, addresses and job titles of the utility personnel that shall be directly or indirectly involved, in any fashion, in any of the following groups: the development of the requests for proposals to be utilized in the competitive selection process; the ultimate selection of successful projects or developers, or both; and the development and formulation of the bids expected to be submitted by, or on behalf of, the electric utility or any of its affiliates, or both. The utility shall identify the group in which each person will work and that person’s duties and responsibilities within the group.

       (B)   Nothing in clause (A) limits the ability of an electric utility to add personnel after the initial designation if:

         (I)   An amendment to the filing required by clause (A) is filed with the Commission within 15 days after the new personnel are added.

         (II)   Other applicable requirements of this subparagraph have been satisfied.

       (C)   No one participating in the bidding process on behalf of the utility conducting the auction may be a member of more than one of the groups identified in clause (A).

       (D)   Each member of the groups specified in clause (A) shall execute and file with the Commission within 60 days prior to the utility’s RFP filing, a written affidavit under oath acknowledging its obligations during the competitive selection process to:

         (I)   Maintain in the strictest of confidence the information, data, and the like, relating to the operators of its group and the work-product thereof.

         (II)   Refrain from communicating any information, data and the like, relating to the operations or work-product of their group to any individuals who are members of any other groups specified in clause (A).

     (iii)   DSM projects. Electric utilities have the option of including DSM providers and electric generation suppliers in the same auction or in separate auctions. In auctions which include DSM providers, the amount and type of DSM programs solicited shall be consistent with the amount and type of DSM programs contained in the utility’s Annual Resource Planning Report filed with the Commission.

       (A)   Eligible DSM projects shall include conservation as well as load management programs.

       (B)   DSM proposals shall be reliable and quantifiably cost effective.

       (C)   Bidders of DSM projects shall include in their bids the costs to consumers participating in the DSM programs.

       (D)   Commercial or industrial DSM may not contemplate only reductions in commercial or industrial plant output.

       (E)   The utility shall make known the criteria and procedures for evaluating DSM proposals in its Request for Proposals.

   (2)  Development of the Capacity Resource Plan. A competitive bidding process shall be responsive to the needs of the jurisdictional electric utilities. To provide maximum flexibility in the purchase of capacity and associated energy and DSM programs, there will be no Commission mandated benchmarks, price factors and nonprice factors in a competitive bidding process. Each electric utility initiating a competitive bidding process may propose benchmarks, price factors and nonprice factors and otherwise follow these principles:

     (i)   A utility’s competitive bidding program shall be an integral part of its Annual Resource Planning Report filed under 66 Pa.C.S. §  524 (relating to data to be supplied by electric utilities) and the Commission’s regulations. A utility’s Annual Resource Planning Report shall include information on system reliability sufficient to establish a reasonable bid block for procurement.

     (ii)   A utility’s need for capacity as identified in its Request for Proposal shall be consistent with the long-term resource plans reflected in its Annual Resource Planning Report. If the Request for Proposal is not consistent with those long-term resource plans, the utility shall justify any differences to the Commission before a Request for Proposal is issued.

     (iii)   A utility’s competitive bidding program shall be conducted at appropriate times consistent with the capacity need reflected in the utility’s Annual Resource Planning Report filings.

     (iv)   A utility is not required to hold an auction if its Annual Resource Planning Report shows that it has sufficient existing capacity to meet the needs of its customers unless the Commission determines otherwise.

     (v)   Power plant life extension programs are exempted from competitive bidding.

   (3)  Petition for Approval of Capacity Resource Plan.

     (i)   As provided in this subchapter, each jurisdictional Class A utility shall file with the Commission a Petition for Approval of its Capacity Resource Plan (petition). The petition shall be based on each utility’s then-current Annual Resource Planning Report (ARPR), filed under §  57.141 (relating to general). The petition shall contain the following information based upon the ARPR:

       (A)   The types, amounts and timing of capacity resources, which include associated energy, that the utility plans to construct or own, or both, in whole or in part, or which the utility plans to purchase from unaffiliated or affiliated utilities, independent power producers, exempt wholesale generators, qualifying facilities, marketers, brokers or other entities.

       (B)   The proposed analytical method for determining the timing, amount and duration of capacity resources, if any, that the electric utility would purchase from unaffiliated or affiliated utilities, independent power producers, exempt wholesale generators, qualifying facilities, marketers, brokers or other entities over an appropriate planning period, and the amount of capacity resources, if any, that the electric utility should construct or own, or both, itself.

       (C)   The amount, type, timing, duration, ownership and configuration of capacity resources needed over an appropriate planning period calculated in accordance with the methodology provided in compliance with §  57.150 (relating to evaluation and integration of resources).

       (D)   The type of information provided in compliance with §  57.150 for generation supply shall also be provided in regard to the utility’s plans to procure and implement demand-side management programs.

       (E)   Other data and information requested by the Commission to assist it in its ruling on the utility’s petition.

     (ii)   The Commission will provide notice of the filing of a petition to be published in the Pennsylvania Bulletin within 30 days after the petition is filed. The notice must contain sufficient information to advise the utility’s customers, the entities referenced in subparagraph (i), and other interested parties of the utility’s overall capacity resource needs and the operation of the utility’s competitive selection process. The notice will provide the interested parties with the opportunity to participate in a formal Commission proceeding concerning the petition.

     (iii)   Within 30 days of the filing of a petition, the utility shall provide further notice, including publication in newspapers of general circulation, media advertising, customer bill inserts or other notice as the Commission reasonably believes to be required to notify the utility’s customers and interested parties of the proceeding concerning the utility’s petition.

     (iv)   Within 60 days after the petition is filed, the Commission will assign the petition to the Office of Administrative Law Judge for hearings and the issuance of a recommended decision. The Commission will adopt a final order on the petition within 210 days after the petition is filed. If the Commission does not enter a final order concerning the petition within that time, the petition shall become effective as filed, requiring no further action by the Commission or the electric utility.

     (v)   A Commission order on a petition will contain findings concerning the following:

       (A)   The method or approach to be used by the electric utility to establish the amount of its capacity resource needs to be filled by its own facilities or the facilities of unaffiliated or affiliated utilities, independent power producers, exempt wholesale generators, qualifying facilities, marketers, brokers or other entities over an appropriate planning period.

       (B)   The appropriate planning period for evaluating capacity resource needs, avoided costs and the utility’s actual commitment to capacity resources.

       (C)   The electric utility’s appropriate interconnection requirements, including physical inspection and testing requirements, cost and payment procedures, reconciliation of actual costs to estimates and the like

       (D)   The appropriate allocation of costs for system upgrades among affected unaffiliated or affiliated utilities, independent power producers, exempt wholesale generators, qualifying facilities, marketers, brokers or other entities.

       (E)   The timing, type and amount of DSM programs the utility will procure and implement.

       (F)   The utility’s methodology for evaluating DSM programs.

       (G)   The utility’s proposed dispute resolution process designed to resolve in an efficient and expeditious manner disputes associated with the competitive bidding process.

       (H)   Other findings that the Commission deems reasonable and appropriate relating to the petition.

 (vi)  When a utility’s capacity resource plan, approved by Commission order under this paragraph becomes outdated or fully implemented, or becomes inappropriate for any reason, the utility shall file a new petition with the Commission consistent with this paragraph. This filing shall not affect any contract submitted under paragraph (7).

   (4)  Request for Proposal (RFP).

     (i)   Following the Commission’s disposition of the petition, a utility shall develop an RFP for the purchase of capacity. The utility’s RFP shall be filed with the Commission at the appropriate time in order to meet the utility’s capacity needs. A utility’s RFP shall provide accurate information about its need for capacity. The RFP shall provide whether the utility is seeking baseload, intermediate or peaking capacity. The RFP shall include information necessary to the preparation of the bid proposal and the following:

       (A)   The size, type and timing for which the utility anticipates contracting.

       (B)   The RFP shall specify any nonprice, benchmark or other considerations, such as fuel diversity and how those factors will be evaluated.

       (C)   Thresholds that shall be met by bidders.

       (D)   The criteria which will be used in evaluating the bids.

       (E)   Major assumptions to be used by the utility in its bid evaluation process.

       (F)   Explicit instructions for preparing bids so that bids can be evaluated on a consistent basis.

       (G)   The preferred general location of additional capacity and availability of offsets or allowances.

       (H)   Standard power purchase and operating agreements.

     (ii)   A utility shall provide bidders with the information that would reasonably be expected to have a bearing on the viability of a proposed project. Potential bidders shall be able to meet with the utility to discuss the RFP and the utility’s capacity needs.

     (iii)   Notice of the RFP shall be filed with the Commission, served on the Office of Consumer Advocate, the Office of Small Business Advocate and the Pennsylvania Energy Office and published by the Commission in the Pennsylvania Bulletin. The notice shall include information regarding when the RFP will be released, when bidders must submit their proposals, and when the utility will announce the winning bidder.

     (iv)   The RFP shall be consistent with the Commission’s order on the utility’s petition.

     (v)   There shall be a single due date for all proposals, so that all proposals may be delivered to the evaluator and opened at the same time without amendment.

     (vi)   Performance incentives and penalties are encouraged to ensure efficient project operation. Performance incentives and penalties, if used, shall be included in the RFP.

   (5)  Determination of procurement block size.

     (i)   The amount of capacity or block size which the utility solicits shall be based on the utility’s incremental capacity and associated energy needs as forecast beyond the next 5 years from the date of the utility’s most recent ARPR, consistent with the Commission’s disposition of the utility’s petition. Projects may be appropriately considered in the bid assessment when their proposed in-service date is later than the time-frame used to determine the block size.

     (ii)   Incremental needs refer to the level of capacity and associated energy needs in excess of the following, less planned utility plant retirements:

       (A)   Current utility-owned generating capacity.

       (B)   Short-term power purchase contracts, and commitments with other utility sources.

       (C)   Current signed power purchase contracts and commitments with nonutility generators which are likely to operate, with recognition of their likely in-service dates.

   (6)  Evaluation of bids.

     (i)   Evaluation of bids submitted in a competitive bidding program shall be based on the criteria identified in the utility’s RFP. All resource options competing to meet the utility’s procurement needs as determined by the Commission’s disposition of the Capacity Resource Plan shall be evaluated against each other, consistent with the requirements of the Capacity Resource Plan and the RFP.

     (ii)   For auctions in which neither the utility nor any affiliate is a participant, the utility shall objectively evaluate all bids consistent with the RFP. If the utility or its affiliates participate in their own bidding process, the Commission will require independent, third-party evaluation of all bids. The Commission will closely scrutinize all evaluations of bids.

     (iii)   A utility shall establish reasonable interconnection procedures to facilitate the wheeling of power from unsuccessful bidders to wholesale purchasers of power.

   (7)  Contract negotiations.

     (i)   Contract negotiations between the utility and a potential supplier of electricity shall be in strict accordance with the utility’s RFP. Contract negotiations may not be extensive. Fundamental changes in the nature of the project and purchase payments may not be negotiated. The fully executed contract shall include provisions that assure a facility’s performance and continued availability under that contract.

     (ii)   Security provisions for levelized contracts may not be onerous or anticompetitive.

     (iii)   Line loss savings are a matter of location integration with the current system and may be incorporated in final contracts when negotiated.

     (iv)   The price negotiated to be paid to the successful bidder for power shall reflect its share of necessary upgrades to the transmission system. The utility is encouraged to establish a standard contribution format for partial compensation by power producers to transmission system upgrades where these upgrades can be negotiated.

     (v)   Promptly upon the completion of contract negotiations, the utility shall submit a petition to the Commission seeking approval of the contract and cost recovery.

   (8)  Purchases outside of a bidding program.

     (i)   A utility with a competitive bidding program under this subsection may refuse offers of capacity that are made outside of that bidding program. Energy-only shall be purchased from an offering qualifying facility under subsection (b).

     (ii)   When a utility and a potential supplier of capacity resources intends to negotiate a purchased power contract outside of the utility’s competitive bidding program, the parties shall jointly file a petition for waiver of this subchapter under §  5.43 (relating to petitions for issuance, amendment, waiver or repeal of regulations). The parties shall demonstrate that the transaction cannot be accommodated in the competitive bidding program and that the purchase is in the public interest from both a cost and reliability standpoint.

     (iii)   An electric utility may file a petition for permission to construct its own generating plant outside of a competitive bidding program. The Commission will hold hearings on the utility’s petition and the Commission will adopt a final order within 210 days after the petition is filed. If the Commission does not adopt a final order within that time, the utility’s petition for permission to construct its own generating plant outside of a competitive bidding process shall be deemed approved as filed, requiring no further action by the Commission or the utility. The Commission may consider the following factors in reviewing the electric utility’s proposal:

       (A)   The electric utility’s proposal is the best least-cost option compared to other options.

       (B)   The electric utility’s proposal has the lowest rate impact compared to other options.

       (C)   The electric utility’s proposal has the best reliability standard compared to the reliability offered by other competitors.

       (D)   The utility’s proposal offers the greatest improvement in the electric utility’s financial standing.

       (E)   The electric utility’s proposal offers the largest economies of scale and best optimum fuel mix.

       (F)   Other factors which the Commission believes are in the public interest.

   (9)  Disputes.

     (i)   The Commission will determine the dispute resolution process to be followed during the course of a competitive bidding program in its final order on the utility’s petition filed under paragraph (3).

     (ii)   Disputes concerning the competitive bidding process specific to the unsuccessful bidder shall be brought to the Commission as a Petition for Reconsideration within 15 days of the Commission’s final order on the utility’s petition for contract approval and cost recovery.

     (iii)   The Commission will refer disputes concerning the administrative process of the RFP to the Office of the Administrative Law Judge.

   (10)  Utility reporting requirements.

     (i)   A utility conducting a competitive bid solicitation shall file a written report to the Commission within 45 days of the completion of its evaluation of bids received. This report shall describe in detail the evaluation of the bids and the electric utility’s comparison of the bids received to its own construction options. The report will be treated as proprietary information.

     (ii)   A second report shall be prepared as a public document and accompany the proprietary report.

     (iii)   A utility shall cooperate fully with Commission staff in review of the solicitation and evaluation process.

   The provisions of this §  57.34 adopted September 17, 1982, effective January 11, 1983, 13 Pa.B. 4237; corrected December 24, 1982, effective January 11, 1983, 12 Pa.B. 4338; amended December 29, 1995, effective December 30, 1995, 25 Pa.B. 6085. Immediately preceding text appears at serial pages (195595) to (195603).

   Capacity Credits

   The Commission exceeded its authority under the Public Utility Regulatory Policies Act by calculating capacity credits, for purpose of calculating payments owing to a facility and recoverable from ratepayers, based on an ‘‘offer of acceptance’’ and not a ‘‘legally enforceable obligation.’’ Armco Advanced Materials Corporation v. Pennsylvania Public Utility Commission, 579 A.2d 1337 (Pa. Cmwlth. 1990), affirmed per curiam 634 A.2d 207 (Pa. 1993).

   Fixed Charge Rate

   The fixed charge rate represents those costs that change over time, such as the cost of debt or cost of capital. Armco Advanced Materials Corp. v. Pennsylvania Public Utility Commission, 664 A.2d 630 (Pa. Cmwlth. 1995); appeal denied 674 A.2d 1079 (Pa. 1996).

   Need

   A utility is not free to claim that it does not have a need for additional capacity and refuse to negotiate contracts with qualifying facilities when in fact it does need to add capacity. The Public Utility Regulatory Policies Act of 1978 (PURPA) (16 U.S.C.A. §  824a-3), required utilities to make purchases from qualifying facilities when a need exists that qualifying facilities can fulfill. In cases where a utility denies the existence of its needs, there must be a means for compelling a capacity purchase. Otherwise, the aims of PURPA would be frustrated. Pennsylvania Electric Co. v. Pennsylvania Public Utility Commission, 677 A.2d 831 (Pa. 1996).

   The Public Utility Commission did not err in calculating capacity needs and avoided costs as of the date when the petition to compel a purchase was filed. This approach was consistent with Milesburg II (Armco Advanced Materials Corp. v. Pennsylvania Public Utility Commission, 135 Pa. Cmwlth. 15, 579 A.2d 1337 (1990), aff’d per curiam, 535 Pa. 108, 634 A.2d 207 (1993), cert. denied, 130 L. Ed. 2d 274 (1994)) and was within the bounds of the Commission’s authority under the Public Utility Regulatory Policies Act of 1978, 16 U.S.C.A. §  824a-3. Pennsylvania Electric Co. v. Pennsylvania Public Utility Commission, 677 A.2d 831 (Pa. 1996).

   Price

   Where a petitioner challenged the Pennsylvania Public Utility Commission’s order approving a utility agreement to purchase power from a cogeneration facility, the question of whether prices in the agreement were equal or below full avoided costs was preserved. The utility’s ratepayers must be provided notice and an opportunity to be heard on the terms of the agreement relating to prices. GPU Industrial Intervenors v. Pennsylvania Public Utility Commission, 628 A.2d 1187 (Pa. Cmwlth. 1993).

   Qualifying Facility Petition Date

   To hold that a contract to supply capacity must be executed before a qualifying facility can ‘‘lock in’’ needs and avoided costs would allow utility companies to impede the development of qualifying facilities by denying needs and refusing to negotiate contracts. Determining need and cost factors with reference to the date when a qualifying facility files a petition to compel a purchase is a reasonable course. Pennsylvania Electric Co. v. Pennsylvania Public Utility Commission, 677 A.2d 831 (Pa. 1996).

 (a)  Each electric utility shall establish and maintain rates, rules and regulations within its tariff for the provisions of the following services to qualifying facilities:

   (1)  Supplementary power.

   (2)  Back-up power.

   (3)  Maintenance power.

 (b)  A utility’s rate for sales of supplementary power to qualifying facilities shall recover the same costs that the utility is permitted to recover from another utility customer of the same customer class and with the same usage characteristics.

 (c)  A utility’s rate for sales of back-up power to qualifying facilities may not be based upon an assumption that forced outages or other reductions in electric output by qualifying facilities on an electric utility’s system will occur simultaneously or during the system peak, or both, unless supported by factual data. The utility’s rate for back-up power shall recover energy costs incurred by the utility plus an appropriate portion of fixed costs. Fixed costs shall be prorated over the actual days in a billing period during which back-up power is consumed by the qualifying facility.

 (d)  A utility’s rate for sales of firm maintenance power to qualifying facilities shall include energy costs and a demand or capacity charge required to recover the appropriate transmission plant and full distribution plant costs. When the scheduled outages of a qualifying facility cannot be scheduled during other than utility peak periods, the demand or capacity charge shall be the full charge stated in the utility’s filed tariff under which the qualifying facility receives this service.

 (e)  When appropriate, a utility shall provide supplementary back-up and maintenance power on both a firm and interruptible basis.

   The provisions of this §  57.35 adopted September 17, 1982, effective January 11, 1983, 13 Pa.B. 4237; amended December 29, 1995, effective December 30, 1995, 25 Pa.B. 6085; corrected February 9, 1996, effective December 30, 1995, 26 Pa.B. 590. Immediately preceding text appears at serial page (205824).

   Notice and Opportunity To Be Heard

 (a)  Obligation to pay.

   (1)  A qualifying facility shall pay any reasonable additional—that is, incremental—connection costs above the costs to service the customer’s electrical load which an electric utility may incur to allow the utility to purchase power from the qualifying facility.

   (2)  A qualifying facility shall provide the equipment necessary for it to interconnect with the utility on the qualifying facility’s side of the interconnection point in a manner which is compatible with and meets the safety standards of the utility.

   (3) The qualifying facility shall submit its interconnection plans and specifications to the utility. The utility shall accept or reject these plans within 60 days of receipt of all required documents. The utility’s acceptance or rejection shall be in writing. When plans or specifications are rejected, the utility shall identify and explain the rejection and identify actions necessary to cure the defects.

   (4)  The utility shall provide general interconnection requirements upon request.

   (5)  The qualifying facility may hire an independent contractor to perform interconnection work on the qualifying facility side of the interconnection. After the qualifying facility installs the necessary interconnection equipment, the utility can require an inspection before making the interconnection. The utility shall have this inspection conducted within 20 days of notice by the qualifying facility that the installation has been completed and shall provide the qualifying facility with the results of this inspection in writing within 5 working days. If after inspection the utility considers the interconnection to be unsatisfactory, the utility shall identify and explain the basis of its determination and described specific steps to remedy the defects. The utility shall bear the cost of this inspection.

   (6)  If the utility is performing interconnection work for the qualifying facility, the utility shall complete the work in a timely manner.

 (b)  Reimbursement of interconnection costs. Payments for the incremental interconnection costs described in subsection (a) may, at the option of the qualifying facility, be made either as one lump sum payment or be spread over a mutually agreeable period of 5 years or less. When the qualifying facility chooses to spread the payment over a reasonable time period, the payments to the utility shall include an interest payment to cover the utility’s allowed rate of return on common equity as last approved by the Commission.

 A utility shall establish reasonable standards to insure system safety and reliability of interconnected operations subject to the approval of the Commission. The standards shall be filed as part of the utility’s tariff and shall be supported by information which demonstrates the need for the standards on the basis of system safety and reliability. A utility shall provide a copy of the standards or a summary of the standards to prospective qualifying facilities upon request.

 The Commission will consider access to utility-owned transmission lines by qualifying facilities, when appropriate. Utilities shall file with the Commission their Federal Energy Regulatory Commission-approved wheeling rate applicable to qualifying facilities selling power to other utilities.

 (a)  A qualifying facility or utility may request Commission assistance concerning charges and conditions of the purchase or sale of power under this subchapter. The Commission may designate staff to consult with such parties as the need arises. Upon request for assistance, staff will attempt to aid the parties in understanding and complying with this subchapter. Staff may also suggest possible solutions to problems and disputes arising from application of this subchapter. Assistance or suggestions, however, will be wholly informational and nonbinding on both the Commission and the parties. The assistance or suggestions may not form the basis for any decision by the Commission. Requests for Commission assistance shall be in writing with copy to other parties, be addressed to the Secretary’s office, and include as a minimum the following information:

   (1)  Name of the qualifying facility.

   (2)  Owner of the qualifying facility.

   (3)  Description of the qualifying facility including type, for example, run-of-river hydro or topping cycle cogeneration; capacity in kilowatts; and estimated annual output in kilowatt-hours.

   (4)  Proposed purchasing utility.

   (5)  Whether the qualifying facility is offering to sell energy or energy and capacity.

   (6)  Terms and conditions under which the purchasing utility has offered to purchase the energy or energy and capacity and all terms and conditions the qualifying facility was willing to accept for its energy or energy and capacity.

   (7)  A short summary of the problem or question with which the party wishes Commission assistance.

 (b)  Any qualifying facility wishing to contest utility actions before the Commission under this subchapter shall comply with the act, and Chapters 1, 3 and 5 (relating to rules of administrative practice and procedure; special provisions; and formal proceedings). In addition, an initial pleading petition, or other document filed with the Commission should include, as a minimum, the information as required in subsection (a).

   The provisions of this §  57.39 adopted September 17, 1982, effective January 11, 1983, 13 Pa.B. 4237.

Subchapter D. ACCOUNTS AND RECORDS

Sec.

§ 57.41. Classification of electric public utilities.

 For accounting and reporting purposes, electric public utilities are classified as follows:

   (1)  Class A. Public utilities having annual electric operating revenues of $2.5 million or more.

   (2)  Class B. Public utilities having annual electric operating revenues of $1 million or more but less than $2.5 million.

   (3)  Class C. Public utilities having annual electric operating revenues of $150,000 or more but less than $1,000,000.

   (4)  Class D. Public utilities having annual electric operating revenues of $25,000 or more but less than $150,000.

 (a)  Each Class A and Class B electric public utility shall keep its accounts in conformity with the ‘‘Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class A and Class B)’’ of the Federal Energy Regulatory Commission.

 (b)  Each Class C electric public utility shall keep its accounts in conformity with the ‘‘Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class C)’’ of the Federal Energy Regulatory Commission.

 (c)  Each Class D electric public utility shall keep its accounts in conformity with the ‘‘Uniform System of Accounts Prescribed for Public Utilities and Licensees (Class D)’’ of the Federal Energy Regulatory Commission.

   The provisions of this §  57.42 issued under Public Utility Code,66 Pa.C.S. § §  331, 501, 504 and 1501.

   The provisions of this §  57.42 adopted February 25, 1946; amended through May 29, 1973; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (78456) to (78457).

   Federal Energy Regulatory Commission

   Although a public utility is required to keep its accounts in conformity with the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC), there is no evidence that the regulations governing the FERC were inextricably tied to or wholly incorporated into the Tax Reform Code (72 P. S. §  8101 et seq.). To the contrary, the FERC’s authority over state matters has been specifically limited such that federal regulation only extends to those matters which are not subject to regulation by the states. Thus, taxation on the ‘‘sales of electric energy’’ was governed by the Tax Reform Code and accordingly the taxability of gross receipts from residential and nonresidential late charges was not governed by the FERC regulations. Pennsylvania Power & Light Co. v. Commonwealth, 668 A.2d 620 (Pa. Cmwlth. 1995); affirmed 717 A.2d 504 (Pa. 1998).

   Gross Receipts

   The Federal accounting procedure which the Pennsylvania Code requires the electric utility to follow does not control the court’s interpretation of the Pennsylvania Tax Reform Code; thus, the gross receipts received from the higher rates imposed on late-paying customers constitute payment for the electricity sold as much as do gross receipts derived from rates applicable to timely payments. Pennsylvania Power & Light Co. v. Board of Finance and Revenue, 717 A.2d 504 (Pa. 1998).

   The gross receipts received from the higher rates imposed on late-paying customers constitute payment for the electricity sold as much as gross receipts derived from rates applicable to timely payments. Pennsylvania Power & Light Co. v. Commonwealth, 668 A.2d 620 (Pa. Cmwlth. 1995); affirmed 717 A.2d 504 (Pa. 1998).

 Revenues, costs and expenses pertaining to merchandising, jobbing and contract work shall be recorded appropriately in accounts 914 and 915 or accounts 592 and 593 in the uniform accounting system prescribed in §  57.42 (relating to systems of accounts prescribed).

 A public utility having annual electric operating revenues of $25,000 or more shall, in its accounting for plant retirements, conform to the ‘‘Units of Property for Use in Accounting for Additions and Retirements of Electric Plant’’ of the Federal Energy Regulatory Commission.

   The provisions of this §  57.44 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

 Each electric utility shall keep and preserve its records in conformity with the provisions applicable to it in the most recent publication of the National Association of Regulatory Utility Commissioners, entitled ‘‘Regulations to Govern the Preservation of Records of Electric Gas and Water Utilities, except as follows when the following retention periods apply:

   The provisions of this §  57.45 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501; amended under the Public Utility Code, 66 Pa.C.S. § §  501, 504—506, 1301 and 1501.

 (a)  A public utility having annual electric operating revenues of $25,000 or more shall maintain a continuing property record of its electric plant, the cost of which is recorded in accounts 101, 102, 103, 104, and 105 in the uniform accounting system prescribed in §  57.42 (relating to systems of accounts prescribed).

 (b)  An outline of the plan of the company for the establishment and maintenance of its continuing property record shall be submitted to the Commission for approval. Major changes in the plan shall also be submitted to the Commission.

 (c)  The continuing property record shall contain the detailed description and classification of property record units as will provide all of the following:

   (1)  An inventory of plant by property record units which may be readily checked for proof of existence.

   (2)  The association of costs with the units, to assure accurate retirement accounting.

   (3)  The dates of installation and removal of property record units, to provide age and life data for use in depreciation studies.

 (d)  The continuing property record, or records supplemental to it, shall include information as to the kind, character, size, quantity, location, year of placement and retirement, percentage of ownership and original cost of electric plant.

 (e)  Plants comprising a large number of similar units, such as poles, wire, meters and line transformers, may be grouped, and the average cost used for retirement accounting. Grouping should be by years of construction within one cost-keeping area. The entire system may be considered as one cost-keeping area unless otherwise required for regulatory purposes. If it is impracticable to account for construction by years, the public utility may, with Commission approval, cost certain items by bands of years or by average costs for all years. The grouping does not relieve the utility from its requirements to provide age and life data and to maintain location records for such plant.

 Under 66 Pa.C.S. § §  504 and 3301 (relating to reports by public utilities; and civil penalties for violations), the Commission may require a public utility to file, and invoke penalties for failure to file, certain reports. In this regard, the following apply:

   (1)  Unless prior permission to do otherwise is granted, a public utility, other than transportation, subject to the jurisdiction of the Commission, shall file annual financial reports with the Commission by April 30 immediately following the reporting year, for reports based upon the calendar year; or by July 31 immediately following, for reports permitted to be based upon the fiscal year ending May 31. A request for an extension of time for filing an annual report shall be submitted to the Commission prior to the filing dates specified in this paragraph.

   (2)  If a public utility, other than transportation, fails to file its annual report in compliance with this section, the public utility may be subject to a penalty as provided under 66 Pa.C.S. §  3301. Continued failure to file annual reports may result in additional penalties.

   The provisions of this §  57.47 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501; amended under the Public Utility Code, 66 Pa.C.S. § §  501 and 504.

   The provisions of this §  57.47 adopted February 25, 1946; amended through May 29, 1973; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended May 6, 1988, effective May 7, 1988, 18 Pa.B. 2106. Immediately preceding text appears at serial pages (125403) to (125404).

   Gross Receipts

   The gross receipts received from the higher rates imposed on late-paying customers constitute payment for the electricity sold as much as gross receipts derived from rates applicable to timely payments. Pennsylvania Power & Light Co. v. Commonwealth, 668 A.2d 620 (Pa. Cmwlth. 1995); affirmed 717 A.2d 504 (Pa. 1998).

   The provisions of this §  57.49 adopted January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended February 12, 1988, effective February 13, 1988, 18 Pa.B. 662; reserved January 13, 1995, effective January 14, 1995, 25 Pa.B. 150. Immediately preceding text appears at serial pages (125405) to (125411).

   Construction

   This regulation is an expansion of 66 Pa.C.S. §  524. Pennsylvania Indus. Energy Coalition v. Pennsylvania Public Utility Commission, 653 A.2d 1336 (Pa. Cmwlth.), appeal granted, 665 A.2d 471 (Pa. 1995).

   General Comment

   The provisions of this §  57.50 adopted January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; amended February 12, 1988, effective February 13, 1988, 18 Pa.B. 662; reserved January 13, 1995, effective January 14, 1995, 25 Pa.B. 150. Immediately preceding text appears at serial pages (125411) to (125426).

Subchapter E. EMERGENCY REGULATIONS

Sec.

§ 57.51. Discontinuance of generating units.

 (a)  An electric public utility within the jurisdiction of the Commission shall petition for and obtain the consent of the Commission before discontinuing a generating unit from normal operation, as defined in this section.

 (b)  Petitions shall contain data covering recent and projected peak loads, net generating capabilities, firm power commitments and other information to enable the Commission to determine whether consent will be granted or refused. Public hearing may be ordered upon a petition if the information contained in the petition is not sufficient for the formation of the judgment.

 (c)  For the purpose of this section, the term ‘‘generating unit’’ means a turbogenerator and the related steam, hydro or other propulsion equipment. Normal operation of a generating unit shall be referred to as its continuing availability to meet consumer demands, except during:

   (1)  Scheduled outages for repairs, tests, nuclear refueling or other procedures essential to its further use.

   (2)  Unscheduled outages caused by its physical malfunctioning or breakdown.

   The provisions of this §  57.51 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

 (a)  An electric public utility subject to the jurisdiction of the Commission shall include in its electric tariff rules and regulations filed with the Commission the following provision:

   (1)  RULE

     (i)   A load emergency situation exists whenever:

       (A)   The demands for power on all or part of the utility’s system exceed or threaten to exceed the capacity then actually and lawfully available to supply the demands.

       (B)   System instability or cascading outages could result from actual or expected transmission overloads or other contingencies.

       (C)   The conditions exist in the system or another public utility or power pool with which the utility’s system is interconnected and cause a reduction in the capacity available to the utility from that source or threaten the integrity of the utility’s system.

     (ii)   In this case, the utility shall take the reasonable steps as the time available permits to bring the demands within the then-available capacity or to otherwise control load. The steps shall include, but are not limited to, reduction or interruption of service to one or more customers, in accordance with the utility’s procedures for controlling load.

   (2)  RULE

 (b)  A utility shall establish procedures for controlling load and emergency conservation.

   (1)  These procedures shall include schedules of load shedding priorities to be followed in compliance with subsection (a).

   (2)  These procedures may be revised by the utility, and shall be revised if required by the Commission.

   (3)  A copy of the procedures or of the revision currently in effect shall be kept available for public inspection at the office at which the utility maintains a copy of its tariff for public inspection, and another copy shall be kept on file with the Commission’s Bureau of Conservation, Economics and Energy Planning.

 (c)  In the event of either a load emergency situation or an emergency energy conservation situation, as defined under subsection (a), the following emergency notification procedures apply:

   (1)  During load emergencies, initial notice shall be provided by telephone to the Commission no later than the time a voltage reduction warning is issued on the electric system. If a utility does not have the capability to implement system-wide automatic voltage reductions, notice shall be provided to the Commission prior to the implementation of emergency measures which would have a direct impact on firm customers. Notification shall be provided to the Commission as each subsequent load control procedure is either implemented or cancelled. During the course of the load emergency situation, the affected utility shall provide other emergency related information to the Commission that the Commission determines to be necessary. Information shall be provided by fax at a minimum of every 3 hours commencing with initial notification of an emergency situation and shall include the following:

     (i)   System operating capacity.

     (ii)   Current system load.

     (iii)   Projected system peak load and hour.

     (iv)   System operating reserve capacity.

     (v)   Capacity transactions.

     (vi)   Unavailable generating units.

     (vii)   Status of implementation of emergency operating procedures.

     (viii)   Customers and loads affected by manual load shedding, if applicable.

   (2)  During energy conservation emergencies, notice shall be provided by telephone to the Commission at the time of initial implementation of measures which the utility determines to be necessary to conserve available fuel supplies and which would have a direct impact on firm customers. Notification shall be provided to the Commission as each subsequent emergency conservation procedure is either implemented or cancelled. During the course of the emergency energy conservation situation, the affected utility shall provide other emergency related information to the Commission that the Commission determines to be necessary. Information shall be provided by fax at a minimum of every 3 hours commencing with initial notification of an emergency situation and shall include the following:

     (i)   Fuel inventories.

     (ii)   Fuel deliveries.

     (iii)   Burn rates.

     (iv)   Curtailment schedules, if applicable.

   (3)  The utility shall designate emergency contact individuals from which emergency information may be obtained and provide the Commission with a current list of contacts.

   (4)  Utilities which operate within a power pool or similarly integrated bulk power system with a single system operator shall provide notification and other emergency related information to the Commission through their designated representative if the emergency situation affects the entire integrated system, in lieu of individual utility notification.

   (5)  Section 67.1 (relating to general provisions) does not apply to either load emergency situations or emergency energy conservation situations.

   (6)  The Commission will provide information to the Pennsylvania Emergency Management Agency during emergency situations.

   (7)  The Commission will designate emergency contact individuals to be contacted by the utilities to meet the requirements of this section. The Commission will provide the current list of Commission contacts to the utilities and the Pennsylvania Emergency Management Agency.

   The provisions of this §  57.52 issued under the Public Utility Code, 66 Pa.C.S. § §  331, 501, 504 and 1501.

   The provisions of this §  57.52 adopted August 19, 1977, effective August 20, 1977, 7 Pa.B. 2350; amended through January 7, 1983, effective January 8, 1983, 13 Pa.B. 131; corrected January 21, 1983, effective January 8, 1983, 13 Pa.B. 523; amended July 12, 1996, effective July 13, 1996, 26 Pa.B. 3339. Immediately preceding text appears at serial pages (216061) and (205833).

   This section cited in 52 Pa. Code §  57.192 (relating to definitions).

Subchapter F. [Reserved]

§ § 57.61—57.67. [Reserved].

   The provisions of these § §  57.61—57.67 adopted October 9, 1970, effective October 10, 1970, 1 Pa.B. 367; amended July 23, 1993, effective July 24, 1993, 23 Pa.B. 3472; reserved May 21, 1999, effective May 22, 1999, 29 Pa.B. 2667. Immediately preceding text appears at serial pages (246392), (217209) and (205835) to (205839).

Subchapter G. COMMISSION REVIEW OF SITING AND
CONSTRUCTION OF ELECTRIC TRANSMISSION LINES

Sec.

 Upon the application of a public utility for authorization to locate and construct a HV transmission line or any portion thereof, upon approval of the application by the Commission first had and obtained, and upon compliance with existing laws, it shall be lawful for a public utility to commence construction of the HV transmission line or portion thereof.

   The provisions of this §  57.71 issued under the Public Utility Code, 66 Pa.C.S. §  501.

   The provisions of this §  57.71 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403.

 (a)  Applications shall be in conformity with §  1.31 (relating to form of documentary filings generally). Supporting exhibits such as maps, photographs and other engineering materials may be on paper not exceeding 28 inches by 40 inches.

 (b)  The application shall be signed by a person having authority with respect thereto and having knowledge of the matters therein set forth and shall be verified under oath.

 (c)  An application shall contain:

   (1)  The name of the applicant and the address of its principal business office.

   (2)  The name, title and business address of the attorney of the applicant and the person authorized to receive notice and communications with respect to the application if other than the attorney of the applicant.

   (3)  A general description—not a legal or metes and bounds description—of the proposed route of the HV line, to include the number of route miles, the right-of-way width and the location of the proposed HV line within each city, borough, town and township traversed.

   (4)  The names and addresses of known persons, corporations and other entities of record owning property within the proposed right-of-way, together with an indication of HV line rights-of-way acquired by the applicant.

   (5)  A general statement of the need for the proposed HV line in meeting identified present and future demands for service, of how the proposed HV line will meet that need and of the engineering justifications for the proposed HV line.

   (6)  A statement of the safety considerations which will be incorporated into the design, construction and maintenance of the proposed HV line.

   (7)  A description of studies which had been made as to the projected environmental impact of the HV line as proposed and of the efforts which have been and which will be made to minimize the impact of the HV line upon the environment and upon scenic and historic areas, including but not limited to impacts, where applicable, upon land use, soil and sedimentation, plant and wildlife habitats, terrain, hydrology and landscape.

   (8)  A description of the efforts of the applicant to locate and identify archaeologic, geologic, historic, scenic or wilderness areas of significance within 2 miles of the proposed right-of-way and the location and identity of the areas discovered by the applicant.

   (9)  The location and identity of airports within 2 miles of the nearest limit of the right-of-way of the proposed HV line.

   (10)  A general description of reasonable alternative routes to the proposed HV line, including a description of the corridor planning methodology, a comparison of the merits and detriments of each route, and a statement of the reasons for selecting the proposed HV line route;

   (11)  A list of the local, State and Federal governmental agencies which have requirements which shall be met in connection with the construction or maintenance of the proposed HV line and a list of documents which have been or are required to be filed with those agencies in connection with the siting and construction of the proposed HV line.

   (12)  The estimated cost of construction of the proposed HV line, and the projected date for completion.

   (13)  The following exhibits:

     (i)   A depiction of the proposed route on aerial photographs and topographic maps of suitable detail.

     (ii)   A description of the proposed HV line, including the length of the line, the design voltage, the size, number and materials of the conductors, the design of the supporting structures and their height, configuration and materials of construction, the average distance between supporting structures, the number of supporting structures, the line to structure clearances and the minimum conductor to ground clearance at mid-span under normal load and average weather conditions and under predicted extreme load and weather conditions.

     (iii)   A simple drawing of a cross section of the proposed right-of-way of the HV line and any adjoining rights-of-way showing the placement of the supporting structures at typical locations, with the height and width of the structures, the width of the right-of-way and the lateral distance between the conductors and the edge of the right-of-way indicated.

     (iv)   A system map which shows in suitable detail the location and voltage of existing transmission lines and substations of the applicant and the location and voltage of the proposed HV line and associated substations.

   (14)  A statement identifying litigation concluded or in progress which concerns property or matter relating to the proposed HV line, right-of-way route or environmental matters.

   (15)  Additional information as the Commission may require.

 (d)  Letter of notification in lieu of application:

   (1)  A letter of notification may be filed with the Commission in lieu of the application process set forth in § §  57.71—57.76 for the following:

     (i)   An HV line which is proposed to be located entirely on an existing transmission line right-of-way, so long as the size, character design or configuration of the proposed HV line does not substantially alter the right-of-way.

     (ii)   An HV line which is proposed to be located entirely within a public road.

     (iii)   An HV line which is proposed to be located entirely within applicant’s existing transmission line right-of-way and the property of the sole customer to be served by the line, so long as the size, character, design or configuration of the proposed HV line does not substantially alter the right-of-way.

     (iv)   A line for which the voltage is proposed to be increased above its present levels, so long as the size, character, design or configuration of the proposed HV line does not substantially alter the right-of-way.

     (v)   An HV line which is to be reconductored or reconstructed so long as the size, character, design or configuration of the proposed HV line does not substantially alter the right-of-way.

     (vi)   An HV line having a proposed route of 2 miles or less.

   (2)  The applicant shall file with the Commission the original and six copies of the letter of notification and an affidavit of service showing the identity of those served under paragraph (3).

   (3)  At the time of filing, the applicant shall serve a copy of the letter of notification by registered or certified mail upon those who would have otherwise been entitled to receive a copy of an application or notice of filing an application as set forth in §  57.74 (relating to filing and service of application and notice of filing).

   (4)  A letter of notification shall contain:

     (i)   The information described in subsection (c)(1)—(3), (5) and (6).

     (ii)   The anticipated construction commencement date and the proposed in-service date of the project.

     (iii)   Evidence to show that the size, character, design and configuration of the proposed HV line will not substantially alter its right-of-way where the letter is filed under paragraph (1)(i)—(v).

     (iv)   A statement identifying the filing date on which the filing of the letter of notification was or is to be made, together with substantially the language set forth in paragraph (5).

   (5)  The Commission will review and, by order, approve or disapprove a letter of notification. If the Commission approves a letter of notification, the HV line shall be located and constructed without the application process set forth in this subchapter. If the Commission does not approve the letter of notification, its order shall direct the applicant to comply with the application process set forth in this subchapter.

 (e)  The Commission or the presiding officer may—upon the petition of any party, upon the Commission’s own motion, or upon the presiding officer’s own motion—waive one or more or all of the requirements in this subchapter. The petition shall clearly state the requirement sought to be waived and the reasons therefor.

   The provisions of this §  57.72 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial page (50512).

 (a)  Filing. The applicant shall file with the Commission the original and six copies of the application. An affidavit of service showing the identity of those served under subsections (b) and (c) shall accompany the original and the copies of the application filed with the Commission.

 (b)  Copies. At the time of filing, the applicant shall serve a copy of the application by registered or certified mail, return receipt requested, upon the following:

   (1)  The chief executive officer, the governing body and the body charged with the duty of planning land use in each city, borough, town, township and county in which any portion of the HV line is proposed to be located.

   (2)  The president of the public utility, other than the applicant, in whose service territory any portion of the HV line is proposed to be located.

   (3)  The Department of Environmental Resources, Attention: Bureau of Environmental Planning; Post Office Box 2357, 101 S. Second Street, Harrisburg, Pennsylvania 17120.

 (c)  Notice.

   (1)  At the time of filing, the applicant shall serve a notice of filing and a map of suitable detail showing the proposed route of the proposed facility by registered or certified mail, return receipt requested, upon the following:

     (i)   The Secretary of the Department of Transportation, Room 1200 Transportation and Safety Building, Harrisburg, Pennsylvania 17120.

     (ii)   The Chairman of the Historical and Museum Commission, Post Office Box 1026, Harrisburg, Pennsylvania 17120.

     (iii)   Other local, State or Federal agencies designated in §  57.72(c)(11) (relating to form and content of application).

     (iv)   The persons, corporations and other entities designated in §  57.72(c)(4), unless they are served with a copy of the application under §  57.75(i) (relating to hearing and notice).

   (2)  The notice of filing shall contain a statement identifying the filing, the date on which the filing was or is to be made, a description of the proposed line, the design voltage, the number of route miles, the right-of-way width and the location of the proposed HV line within each township traversed and a statement that a copy of the application is available for public examination as provided in subsection (d).

 (d)  Examination. On the day of filing of the application, the applicant shall make a copy of the application available for public examination during ordinary business hours at a convenient location within a county in which any part of the proposed HV line will be located.

 (e)  Additional notice. The applicant shall provide an additional notice and shall serve such additional copies of the application without cost as the Commission may require.

   The provisions of this §  57.74 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (50514) to (50515).

 (a)  Upon the filing of an application, the Commission will set the time and place for hearing or hearings of the application and will thereupon require the applicant to cause the weekly publication for two consecutive weeks of a notice of hearing in a newspaper of general circulation within each municipality in which the HV line is proposed to be located. The publication of the notice of hearings shall begin at least 45 days before the date set for the commencement of the hearings. The notice of hearing for publication shall contain a brief description of the proposed HV line, its location, a statement of the date, time and place of the hearing and of its purpose and a statement as to where and when a copy of the application is available for public examination.

 (b)  The Commission will notify each person or agency designated in §  57.74(b) and (c) (relating to filing and service of application and notice of filing), parties granted leave to intervene under subsection (c), and parties under subsection (i) of the time and place of hearings on the application. After the initial hearing, further hearing notices will be given by the Commission.

 (c)  Where it appears desirable, the Commission or the presiding officer may provide for the grouping of parties with substantially similar interests for the purpose of serving notices and other documents. If a group does not designate a representative for the service of notices and documents, the presiding officer may designate a representative. Notice and documents shall be served only on the designated representative. This subsection may not be construed, however, to limit the right of a party to the proceeding to file motions, briefs, and the like with the presiding officer or Commission when appropriate.

 (d)  A request for leave to intervene shall be in writing and shall state briefly the interest of the intervenor and the objections to be raised. Upon proper request, the Commission will allow the timely intervention of any of the persons or agencies listed in §  57.74(b) and (c). Upon proper request, the Commission may allow the timely intervention of another party deemed to have a substantial interest in the proceeding or whose intervention will aid the Commission in its consideration of the application.

 (e)  At hearings held under this section, the Commission will accept evidence upon, and in its determination of the application it will consider, inter alia, the following matters:

   (1)  The present and future necessity of the proposed HV line in furnishing service to the public.

   (2)  The safety of the proposed HV line.

   (3)  The impact and the efforts which have been and will be made to minimize the impact, if any, of the proposed HV line upon the following:

     (i)   Land use.

     (ii)   Soil and sedimentation.

     (iii)   Plant and wildlife habitats.

     (iv)   Terrain.

     (v)   Hydrology.

     (vi)   Landscape.

     (vii)   Archeologic areas.

     (viii)   Geologic areas.

     (ix)   Historic areas.

     (x)   Scenic areas.

     (xi)   Wilderness areas.

     (xii)   Scenic rivers.

   (4)  The availability of reasonable alternative routes.

 (f)  Upon the order of the Commission or the presiding officer, the applicant may amend its application prior to the closing of the record, if every party, utility, agency or municipality affected by the amendment is given reasonable notice thereof and an opportunity to present evidence with respect to the amendment.

 (g)  Upon petition of the applicant, setting forth the circumstances which require the prompt availability of an HV line, the Commission may grant expedited consideration of the application. The Commission will give to the hearing and decision of expedited applications preference over other applications filed under this subchapter and will decide the same as speedily as possible.

 (h)  If no protests or petitions to intervene other than that of the Commission staff or petitions to intervene which support an application have been received by the Commission 7 days prior to the hearing scheduled under subsection (a), the applicant may move, and the presiding officer may order, that the case be submitted on the applications, exhibits, written testimony and briefs of the applicants and written testimony, exhibits or briefs filed by the Commission’s staff. The motion may not be granted over the protest of the Commission’s staff, but, in such a case, hearings shall be held. To move for a decision without hearing, the applicant shall have filed written testimony and exhibits at least 30 days prior to the date of hearing. The applicant shall also have given notice that it may make a motion under this subsection in its notice of hearing published as provided for in subsection (a).

 (i)  Eminent domain:

   (1)  Proceedings on eminent domain applications for the same HV line are entitled to be consolidated with the proceeding on the HV line’s siting application.

   (2)  An eminent domain application for which consolidation with a siting application is desired under subsection (a) shall be considered by the presiding officer at the hearing on the siting application, and the Commission shall issue an order granting or denying the eminent domain application; provided that, prior to the hearing, the public utility filing the eminent domain application serves a copy of the proposed HV line’s siting application upon the persons, corporations or other entities having a property interest sought to be acquired by the eminent domain application.

   (3)  Unless the applicable eminent domain application has been withdrawn by the public utility, a person, corporation or other entity which is served a copy of the siting application as required by subsection (b) shall be a party to the proceeding on the siting application.

   (4)  A portion of the record of a proceeding under this subchapter may be admitted into the record of a subsequent proceeding on an eminent domain application for the same HV line, upon reasonable notice by motion plainly identifying the matters offered. If only part of the record is offered, a party may require the movant to introduce portions relevant to the part introduced and a party may introduce other portions.

   The provisions of this §  57.75 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (50515) to (50516).

 (a)  The Commission will issue its order, with its opinion, if any, either granting or denying the application, in whole or in part, as filed or upon the terms, conditions or modifications, of the location, construction, operation or maintenance of the line as the Commission may deem appropriate. The Commission will not grant the application, either as proposed or as modified, unless it finds and determines as to the proposed HV line:

   (1)  That there is a need for it.

   (2)  That it will not create an unreasonable risk of danger to the health and safety of the public.

   (3)  That it is in compliance with applicable statutes and regulations providing for the protection of the natural resources of this Commonwealth.

   (4)  That it will have minimum adverse environmental impact, considering the electric power needs of the public, the state of available technology and the available alternatives.

 (b)  A Commission order granting a siting application will be deemed to include a grant of authority, subject to the provisions of law, to locate and construct the proposed HV transmission line within a corridor consisting of the area of 500 feet on each side of the centerline of the proposed HV transmission line unless the applicant requests and the Commission approves a corridor of a different size. A proposed HV transmission line may not be constructed outside the corridor, except upon petition to and approval by the Commission.

   The provisions of this §  57.76 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (50516) to (50517).

 This subchapter is effective on January 8, 1983, and is applicable to every HV line or portion thereof which is not in regular permanent service on the effective day of this subchapter.

   The provisions of this §  57.77 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; amended April 4, 1980, effective April 5, 1980, 10 Pa.B. 1439; amended January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial pages (50517) and (78469) to (78470).

   This section cited in 52 Pa. Code §  5.14 (relating to applications requiring notice).

Subchapter H. UNDERGROUND ELECTRICAL SERVICE IN NEW RESIDENTIAL DEVELOPMENTS

Sec.

§ 57.81. Definitions.

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

   Applicant for electric service—The developer of a recorded plot plan consisting of five or more lots, or of one or more five unit apartment houses.

   Developer—The party responsible for constructing and providing im- provements in a development, that is, streets, sidewalks and utility-ready lots.

   Development—A planned project which is developed by a developer/applicant for electric service set out in a recorded plot plan of five or more adjoining unoccupied lots for the construction of single-family residences, detached or otherwise, mobile homes or apartment houses, all of which are intended for year-around occupancy, if electric service to the lots necessitates extending the utility’s existing distribution lines.

   Distribution line—An electric supply line of untransformed voltage from which energy is delivered to one or more service lines.

   Service line—An electric supply line of untransformed voltage from which service is delivered to the residence.

   Subdivider—The party responsible for dividing a tract of land into building lots which are not to be sold as utility-ready lots.

   Subdivision—A tract of land divided by a subdivider into five or more adjoining unoccupied lots for the construction of single-family residences, detached or otherwise or apartment houses, all of which are intended for year-around occupancy, if electric service to the lots necessitates extending the utility’s existing distribution lines.

   The provisions of this §  57.81 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2280. Immediately preceding text appears at serial page (80638).

 (a)  Distribution and service lines installed under an application for electric service within a development shall be installed underground, shall conform to the utility’s construction standards, §  57.26 (relating to construction and maintenance of facilities), the specifications set forth in the National Electric Safety Code (NESC), and shall be owned and maintained by the utility. Pad-mounted transformers may be installed as a utility construction standard. Excavating and backfilling shall be performed by the developer of the project or by another agent the developer may authorize. Installation of service-related utility facilities shall be performed by the utility or by another agent the utility may authorize. Street-lighting lines installed then or thereafter within the same development shall also be installed underground, upon terms and conditions prescribed elsewhere in each utility’s tariff. The utility is not liable for injury or damage occasioned by the willful or negligent excavation, breakage or other interference with its underground lines occasioned by anyone other than its own employes or agents.

 (b)  Nothing in this section shall prohibit a utility from performing its own excavating and backfilling for greater system design flexibility. No charges other than those specified in §  57.83(4) (relating to applicants for electric service) shall be permitted.

   The provisions of this §  57.82 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2230. Immediately preceding text appears at serial page (80639).

 The applicant for electric service to a development shall conform with the following:

   (1)  At its own cost, provide the utility with a copy of the recorded development plot plan identifying property boundaries, and with easements satisfactory to the utility for occupancy by distribution, service and street-lighting lines and related facilities.

   (2)  At its own cost, clear the ground in which the lines and related facilities are to be laid of trees, stumps and other obstructions, provide the excavating and backfilling subject to the inspection and approval of the utility, and rough grade it to within 6 inches of final grade, so that the utility’s part of the installation shall consist only of laying of the lines and installing other service-related facilities. Excavating and backfilling performed or provided by the applicant shall follow the utility’s underground construction standards and specifications set forth by the utility in written form and presented to the applicant at the time of application for service and presentation of the recorded plot plan to the utility. If the utility’s specifications have not been met by the applicant’s excavating and backfilling, the excavating and backfilling shall be corrected or redone by the applicant or its authorized agent. Failure to comply with the utility’s construction standards and specifications permits the utility to refuse utility service until the standards and specifications are met.

   (3)  Request electric service at such time that the lines may be installed before curbs, pavements and sidewalks are laid; carefully coordinate scheduling of the utility’s line and facility installation with the general project construction schedule, including coordination with other utilities sharing the same trench; keep the route of lines clear of machinery and other obstructions when the line installation crew is scheduled to appear; and otherwise cooperate with the utility to avoid unnecessary costs and delay.

   (4)  Pay to the utility necessary and additional costs incurred by the utility as a result of the following:

     (i)   Installation of underground facilities that deviate from the utility’s underground construction standards and specifications if the deviation is requested by the applicant for electric service and is acceptable to the utility.

     (ii)   A change in the plot plan by the applicant for electric service after the utility has completed engineering for the project or has commenced installation of its facilities.

     (iii)   Physical characteristics, such as oversized lots or lots with extreme setback where under the utility’s line extension policy contained in its tariff a charge is mandated for overhead service.

   (5)  No charges other than those described in paragraph (4) shall be borne by the applicant for electric service or by another utility sharing the same trench, even if the electric utility elects to perform its own excavating and backfilling.

   The provisions of this §  57.83 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250. Immediately preceding text appears at serial pages (80639) to (80641).

 Whenever the distance from the end of the utility’s existing distribution line to the boundary of the development is 100 feet or more, the 100 feet of new distribution line nearest to but outside the boundary shall be installed underground if practicable; and whenever the distance is less than 100 feet from the boundary, all of the new distribution line nearest to but outside the boundary shall be installed underground if practicable. The installation required by this section shall be provided by the utility, without cost to the applicant.

   The provisions of this §  57.84 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577.

   Public Utility Commission Has Exclusive Jurisdiction to Determine Installation of Electric Distribution Line

   Township did not have the power to order underground installation of a main feeder electric distribution line; Public Utility Commission has exclusive jurisdiction to determine, in the context of a municipality’s redevelopment project, matters related to the design, location, installation, and maintenance of public utility facilities, and any other determination would clearly signal the end of unified utility regulation within the Commonwealth. Pennsylvania Power Co. v. Township of Pine, 926 A.2d 1241, 1252, (Pa. Cmwlth. 2007)

 Public utilities furnishing electric service to the public shall file their underground construction, specification standards and revisions thereto with the Commission’s Bureau of Fixed Utility Services. These standards shall be filed within 20 working days from their date of adoption or revision.

   The provisions of this §  57.85 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250; amended May 21, 1999, effective May 22, 1999, 29 Pa.B. 2667. Immediately preceding text appears at serial pages (213699) to (213700).

 (a)  Request for exception.

   (1)  Whenever a public utility or an affected person believes that the application of the requirements in §  57.83 (relating to applicants for electric service) works an undue hardship, involves a physical impossibility, or is otherwise inappropriate, the utility or persons may request an exception from the underground requirements by providing the Commission with the following:

     (i)   A copy of the recorded plot plan of the development for which the exception is sought.

     (ii)   A petition setting forth:

       (A)   The name of the applicant.

       (B)   The location and the size of the development involved.

       (C)   The names of the electric utility and telephone utility which will provide service to the development.

       (D)   The date on which the construction began or will begin; whether the development is a new development or one phase in a development to be completed in several phases; and whether facilities in the area surrounding the development have been installed underground or overhead.

   (2)  The petition shall comply with the Commission regulations governing petitions in §  5.41 (relating to petitions generally).

 (b)  Additional requirement of petitioner. At the same time that the petition is filed with the Commission, a copy of the petition shall be mailed to the appropriate local government authorities, and to other affected persons and utilities by the person requesting the exception. The Commission will issue a decision on the petition within 180 days of the date of its filing, if sufficient data upon which the exception can be granted has been provided in the petition.

 (c)  Grant of exception. If an exception request initiated by an applicant for electric service is granted, and the applicant thereafter desires underground electric service, this subchapter applies as if no exception has been granted.

   The provisions of this §  57.86 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250; amended May 21, 1999, effective May 22, 1999, 29 Pa.B. 2667. Immediately preceding text appears at serial pages (213700) to (213701).

 This chapter applies to applications for service to developments which are filed after June 30, 1984.

   The provisions of this §  57.87 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; amended June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250. Immediately preceding text appears at (80643).

 Underground facilities in new residential developments are only required by § §  57.81—57.87 (relating to underground electrical service in new residential developments) when a bona fide developer exists, that is, only when utility-ready lots are provided by the developer. A mere subdivision is not required to have underground service. Should the lot owner or owners in a subdivision desire underground service, the service shall be provided by the utility if the lot owner, at his option, either complies with §  57.83 (relating to applicants for electric service) or pays to the utility charges that are contained in the utility’s tariff for underground electric service not required by this title.

   The provisions of this §  57.88 adopted June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250.

Subchapter I. DISCLOSURE OF EMINENT DOMAIN POWER OF ELECTRIC UTILITIES

Sec.

§ 57.91. Disclosure of eminent domain power of electric utilities.

 (a)  A public utility may not, by its officers, employes, attorneys or agents, communicate in any manner, for the purpose of negotiating for the acquisition of a transmission line right-of-way, with a property owner or with a property owner’s representative, until at least 15 days after receipt by the property owner or the property owner’s representative of the notice required in this section. Communication with a property owner or with a property owner’s representative for the purpose of locating the owner of record or for the purpose of securing permission to survey the owner’s land is not prohibited and need not be preceded by this notice.

 (b)  A public utility shall cause the following notice, with the appropriate information inserted where blanks appear, to be sent by registered or certified mail, return receipt requested or to be delivered in person to each property owner or property owner’s representative with whom the utility anticipates negotiating for the purchase of transmission line rights-of-way; the notice shall be legibly printed or typewritten on paper 8 1/2 inches wide and 11 inches long:

NOTICE

 The Pennsylvania Public Utility Commission requires that

 No. You may refuse to accept it. However, the utility has the power to take property by eminent domain, subject to the approval of the Public Utility Commission, for the construction of transmission lines if the utility is unable to negotiate an agreement to buy a right-of-way. If your property is condemned, you must be paid ‘‘just compensation.’’ ‘‘Just compensation’’ has been defined by the courts in Pennsylvania as the difference between the fair market value of your property before condemnation, unaffected by the condemnation, and the fair market value of your remaining property after condemnation, as affected by the condemnation. CAN THE UTILITY CONDEMN YOUR HOUSE?

 No. The company cannot condemn your house or a reasonable ‘‘curtilage’’ around your house. Generally, curtilage includes the land or buildings within 300 feet of your house which are used for your domestic purposes. However, the 300-foot limit does not automatically extend beyond the homeowner’s property line. DO YOU HAVE A RIGHT TO A PUBLIC HEARING WHEN THE UTILITY SEEKS TO CONDEMN YOUR PROPERTY?

 Yes. When an electric utility seeks to have your property condemned, the utility must first apply to the Pennsylvania Public Utility Commission for a certificate finding the condemnation to be necessary or proper for the service, accommodation, convenience, or safety of the public. The Commission will then hold a public hearing. As the landowner whose property may be condemned, you are a party to the proceeding and may retain counsel, present evidence, and/or testify yourself in opposition to the application for a certification. If you wish to testify at the public hearing, you should make your intention known by letter to Secretary, Pennsylvania Public Utility Commission, P. O. Box 3265, Harrisburg, Pennsylvania 17120.

 If the Commission approves the utility’s application for a certificate finding the condemnation in the public interest, then the utility may proceed before the local Court of Common Pleas to condemn your land. If the Commission denies the utility’s application, the utility cannot condemn your land. If you retain an attorney to represent you before the Commission, you must do so at your own expense.

 The Commission will not decide how much money you should receive if your land is condemned. The only issue the Commission will decide is whether the condemnation serves the public interest. If the Commission approves the utility’s application for condemnation, the amount of money to which you are entitled will be determined by a local Board of View or the Court of Common Pleas. However, you may at any time make an agreement with the utility as to the amount of damages you are to be paid.

NOTICE

 The Pennsylvania Public Utility Commission requires that (company name) give you the following information on the RIGHT-OF-WAY MAINTENANCE PRACTICES for the (name of project):

 The methods currently used by (name of company) are set forth in (title and description of applicable specification), which will be made available to you for your inspection upon request. If you wish further information concerning right-of-way maintenance methods, you may contact (name, address and telephone number of company representative). You may discuss with this person, either before or during negotiation of the right-of-way agreement, these methods and any other questions you may have about right-of-way maintenance.

 Once a utility has constructed an electric transmission line on a right-of-way across your land, the utility must maintain the right-of-way free of tall-growing trees and brush which might impair the reliability of electric service, the safety of the line, and access to the line or its towers. The utility or its contractors may remove and control tall-growing trees and brush by several methods: handcutting of trees, limbs, and brush; mechanical cutting with chain saws or motorized cutting machines; application of herbicides, either from the ground or from a helicopter. The utility must confine its maintenance activities to the approved right-of-way across your land, except where tall-growing trees or brush or their root systems grow into the right-of-way from adjoining land and constitute a threat to the electric transmission line and its structures.

 If you believe that the maintenance method(s) used by the company would raise problems with your use of your land adjacent to the right-of-way, it is your responsibility as the landowner to bring this to the attention of the utility before you sign the right-of-way agreement.

 The utility company has the responsibility to maintain its rights-of-way, and regular maintenance must occur. Although you as the landowner cannot determine whether or not maintenance will occur, your right-of-way agreement may specify certain conditions on the performance of the maintenance program which are important to you. These conditions can be part of the negotiations between you and the utility company for your land, since a right-of-way agreement is a legal contract between a landowner and a utility company. It is important for you to understand also that the maintenance methods used by the utility company may change over time as the costs of maintenance or the methods of performing maintenance change. You may want to specify in your right-of-way agreement that the utility company inform you of changes in its maintenance methods or in the maintenance schedule for your land.

 The provisions of the right-of-way agreement are enforceable in the local Court of Common Pleas. The right-of-way agreement cannot be enforced by the Pennsylvania Public Utility Commission. Any claims for damage resulting from improper maintenance of the right-of-way must be settled with the utility, its contractors, or in the local Court of Common Pleas at your own expense. The Commission cannot award damages for violations of the right-of-way agreement.

   The provisions of this §  57.93 adopted May 19, 1978, effective May 20, 1978, 8 Pa.B. 1403; reserved January 7, 1983, effective January 8, 1983, 13 Pa.B. 131. Immediately preceding text appears at serial page (37400).

Subchapter J. CONSTRUCTION COSTS OF ELECTRIC
GENERATING UNITS

Sec.

§ 57.101. Purpose.

 The purpose of this subchapter is to:

   (1)  Promote and obtain information concerning the management efficiency of electric utilities engaged in major construction projects.

   (2)  Encourage electric utilities to seek and secure contractual agreements for construction and procurement which will minimize construction costs. The contractual agreements shall be consistent with considerations of quality, reliability and life cycle costs.

   (3)  Gather information about electric utility construction practices and construction management programs, so that the Commission is able to arrive at carefully reasoned decisions about the prudency of utility management, when construction costs are considered in a rate case.

   The provisions of this §  57.101 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

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

   AFUDC—Allowance for funds used during construction.

   Auditor in charge—The Commission designee charged with the responsibility to track construction progress and costs. The auditor in charge is granted reasonable access to the construction site and to relevant oral and documentary evidence under 66 Pa.C.S. §  515 (relating to construction cost of electric generating units).

   Beginning of construction—To begin clearing or disturbing the land or the first act in erecting thereon an artificial structure; or the first act in adding to, modifying or altering an existing generating unit. The term does not include action necessary for the purpose of gathering survey, geological, environmental or similar data. In the case of work performed on an existing unit the term does not include actions necessary as a prerequisite to but not actually involving work on the generating unit.

   Construction—Work performed on an electric generating unit which is expected to require the affected public utility to incur an aggregate of at least $100 million of expenses which, in accordance with generally accepted accounting principles, are capital expenses and not operating or maintenance expenses.

   The provisions of this §  57.102 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

 A utility required under 66 Pa.C.S. §  515(a) (relating to construction cost of electric generating units) to submit an estimate of the construction costs of electric generating units shall file the following information with the Commission as part of that estimate:

   (1)  An estimate of total costs.

   (2)  An estimate of the following costs:

     (i)   The cost and quantity of each category of major equipment, such as switchgear, pumps, diesel generators and the like.

     (ii)   The cost and quantity of each category of bulk materials, such as concrete, cable and structural steel and the like.

     (iii)   Manual labor.

     (iv)   Direct and indirect costs of architect/engineering services.

     (v)   Direct and indirect costs of subcontracts or other contracts involving major components or systems such as turbines, generators, nuclear steam supply systems, major structures and the like.

     (vi)   Distributable costs.

   The provisions of this §  57.103 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

   The provisions of this §  57.103 adopted January 9, 1988, effective January 10, 1988, 18 Pa.B. 181.

 (a)  A utility which is involved in the construction of an electric generating unit as defined in 66 Pa.C.S. §  515(d) (relating to construction cost of electric generating units) and is the construction manager of that electric generating unit, shall have a construction management program. A description of the construction management program shall be filed with the Commission when the utility files its construction costs estimate under 66 Pa.C.S. §  515(a) as prescribed by §  57.103 (relating to estimate of construction costs).

 (b)  A utility which is required to file a description of its construction management program shall include the following in the description:

   (1)  A statement of the duties, responsibilities and procedures of the construction management program’s organization and personnel.

   (2)  A list of reports which are forwarded to executive level utility managers from the utility construction management organization. For purposes of this subchapter, executive level management includes the level of vice president and higher. The list shall include the title and a brief description of the report to be included on the list.

   (3)  The schedules and controls used in planning construction activities, with the project milestones and, if requested by the auditor in charge, copies of critical path network diagrams.

   The provisions of this §  57.104 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

 (a)  A utility which is involved in the construction of an electric generating unit as defined by 66 Pa.C.S. §  515(d) (relating to construction cost of electric generating units) but is not the construction manager of the electric generating unit, shall have a construction monitoring program. A description of the construction monitoring program shall be filed with the Commission when the utility files its construction cost estimate under 66 Pa.C.S. §  515(a) as prescribed by §  57.103 (relating to estimate of construction costs).

 (b)  A utility which is required to file a description of its construction monitoring program shall include the following in the description:

   (1)  A statement of the duties, responsibilities and procedures of the construction monitoring program’s organization and personnel.

   (2)  A list of reports which are forwarded to executive level utility managers from the utility construction monitoring organization. For the purposes of this subchapter, executive level management includes the level of vice president and higher. The list shall include the title and a brief description of the report to be included on the list.

   (3)  The project milestones and if requested by the auditor in charge, copies of the critical path network diagrams.

 (c)  Although a noncontrolling owner may not have the authority to establish or change the construction management procedures, the owner shall monitor the progress of construction and, if necessary, take action to compel the construction manager to use prudent and proper management procedures.

   The provisions of this §  57.105 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

 A utility which is involved or becomes involved in construction as defined by 66 Pa.C.S. §  515(d) (relating to construction cost of electric generating units), shall file quarterly construction reports with the Commission.

   (1)  Quarterly construction reports shall be based upon a calendar year quarter and be received by the Commission no later than 45 days after the end of a calendar year quarter.

   (2)  Quarterly construction reports shall provide a detailed schedule of construction and cost milestones and shall notify and explain an occurrence which causes a deviation from cost projections, including AFUDC, in excess of $5 million.

   (3)  The acceptance for filing of the quarterly reports by the Commission does not constitute an approval of cost or schedule changes.

   (4)  Unexplained inconsistencies or unexplained substantive changes in the construction progress reports or in the methods used to track progress and completion may be considered as evidence of management imprudence.

   (5)  The utility shall provide other documents or information concerning construction, as may be requested from time to time, by the auditor in charge.

   The provisions of this §  57.106 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

 The following guidelines represent recommendations and are nonbinding on the public utility involved in a construction program as defined in 66 Pa.C.S. §  515 (relating to construction cost of electric generating units). The following guidelines are not intended to include all actions which a prudent management could or should take but are intended to provide guidance to a utility engaged in a major construction program:

   (1)  The extent of a construction management or monitoring program by a utility should be commensurate with the financial risks of the project.

   (2)  The utility should have a management or monitoring program designed to recognize problems, react to them in a timely fashion and mitigate the effect of those problems.

   (3)  The utility management or monitoring program should provide information on the status of expenditures and cash flow requirements to upper level management.

   (4)  The utility management or monitoring program should provide meaningful reports on construction progress and completion to upper level management.

   (5)  The utility should have a management program which coordinates the diverse elements involved in large construction projects, including but not limited to: scheduling, licensing, design, engineering, construction, procurement, quality control, quality assurance, vendors, consultants, systems turnover and startup testing.

   (6)  The utility management program should ensure that utility staff has the training and experience, which is necessary to successfully oversee the particular construction project. The utility should also review the training and certification of contractor personnel.

   (7)  In the case of a nuclear unit, the utility should ensure that construction management treats Nuclear Regulatory Commission regulations as minimum requirements and not as ultimate goals.

   (8)  The utility should ensure that construction is adhering to quality assurance/quality control standards generally accepted by the respective construction industry.

   (9)  The utility construction management program should be able to evaluate the effectiveness of its own organization and should require periodic internal or external audits of the project. Evaluations of the utility construction management program should be forwarded directly to upper level utility management.

   (10)  The utility construction management program should define its own organizational and personnel responsibilities as well as have review and approval authority over the organizational and personnel responsibilities of other groups involved in the project.

   (11)  The utility construction management program should ensure that its own personnel are knowledgeable about the organizational and personnel responsibilities of the diverse groups—for example, architect/engineer, constructor, subcontractor, Nuclear Steam Supply System (NSSS) vendor and the like—involved in the project.

   (12)  If possible, vendors and contractors should be selected by competitive bidding. A utility should maintain documentation on the rationale used in the selection of the vendors and contractors.

   (13)  The construction management program should ensure that construction personnel are aware that cost and schedule considerations are not more important than safety and the application of sound engineering judgment.

   The provisions of this §  57.107 issued under Public Utility Code,66 Pa.C.S. § §  501, 515, 1301 and 1308.

   The provisions of this §  57.107 adopted January 9, 1988, effective January 10, 1988, 18 Pa.B. 181.

Subchapter K. UPGRADING OF COAL-FIRED
GENERATING UNITS

Sec.

 This subchapter requires jurisdictional electric utilities with existing coal-fired generating units to uprate their electric power production by increasing the capability to use coal where economically feasible and where the uprate is beneficial to ratepayers. This subchapter also establishes an optional rate rider and preferential base rate recognition mechanisms for special cost recovery for upgradings. This subchapter is required by 66 Pa.C.S. §  514 (relating to use of coal).

   The provisions of this §  57.121 amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 504 and 1501.

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

   Coal-fired unit—An electric generating station fueled by coal or coal derivatives.

   Equivalent availability—A measure of generating unit availability calculated as follows:

 (a)  An electric utility with coal-fired generating capacity shall, within a reasonable period of time, commence all coal-fired unit uprating projects which are found to be economically feasible and beneficial to ratepayers.

 (b)  Upon application of the affected utility, the Commission may qualify an uprating project for special cost recovery under §  57.124 (relating to special cost recovery). The application shall provide cost/ benefit analyses which clearly demonstrate, under present value revenue requirements calculations, that the benefits of uprating the unit will exceed project costs over the operational life of the investment or the remaining life of the unit, whichever is less.

 (c)  If a utility fails, within a reasonable period of time, to commence a project shown to be cost effective and economically feasible, the utility shall be subject to adjustment of rates under 66 Pa.C.S. §  1309 (relating to rates fixed on complaint; investigation of costs of production).

   The provisions of this §  57.123a issued under the Public Utility Code, 66 Pa.C.S. § §  308, 331, 501, 504 and 1501.

 (a)  When a qualified project is completed, a utility may institute a rider under 66 Pa.C.S. §  1307 (relating to sliding scale of rates; adjustments) to surcharge base rates for more timely recovery of associate costs until a time when the costs are reflected in base rates. To be eligible for this cost recovery mechanism, the utility shall comply with the following requirements:

   (1)  The rider surcharge shall be calculated to recover the annual level of revenue required to support the project based upon depreciation and rate of return findings in the utility’s most recently litigated rate proceeding. The revenue requirement calculation shall include the net effect of anticipated operation and maintenance expense changes, exclusive of fuel expense, resulting from the project.

   (2)  The rider shall take the form of a percentage multiplier applied to base rates which shall be recomputed at least once every 12 months.

   (3)  In the course of each general rate proceeding, projected revenues from the rider shall be rolled into base rates.

   (4)  The rider may be initiated or adjusted upon 30-days notice to the Commission for either recognition of additional qualified projects or annual recomputation of the surcharge.

 (b)  Qualified projects involving existing coal-fired units which utilize Commonwealth-mined coal for more than half of the total fuel requirements may be included in the rate base of the utility up to 50% of the undepreciated original cost of the unit involved where the project has not been completed but is expected to be completed within 2 years from the end of the test year claimed in a general rate proceeding under 66 Pa.C.S. §  1308 (relating to voluntary changes in rates).

 Under 66 Pa.C.S. §  514 (relating to use of coal), revenue collected under §  57.124(b) (relating to special cost recovery) is subject to refund with interest, as specified under 66 Pa.C.S. §  514(c), if a qualified project is not completed within 2 years from the end of the test period in which the project was initially claimed and qualified.

   The provisions of this §  57.125 amended under the Public Utility Code, 66 Pa.C.S. § §  308, 331, 501, 504 and 1501.

   The provisions of this §  57.125 amended January 13, 1995, effective January 14, 1995, 25 Pa.B. 150. Immediately preceding text appears at serial page (178486).

Subchapter L. ANNUAL
RESOURCE PLANNING REPORT

Sec.

 (a)  An electric distribution company (EDC), as defined in 66 Pa.C.S. §  2803 (relating to definitions), shall submit to the Commission the Annual Resource Planning Report (ARPR) that contains the information prescribed in this subchapter. An original and three copies of the report shall be submitted on or before May 1, 2000 and May 1 of each succeeding year. One copy of the report shall also be submitted to the Office of Consumer Advocate (OCA) and the Office of Small Business Advocate (OSBA). The name and telephone number of all persons having knowledge of the matters, and to whom inquiries should be addressed, shall be included.

 (b)  As a condition to receiving a copy of the ARPR, the OCA and OSBA shall be obligated to honor and treat as confidential those portions of the report designated by the utility as proprietary.

   (1)  If the Commission, OCA, OSBA or any person challenges the proprietary claim as frivolous or not otherwise justified, the Secretary’s Bureau will issue, upon written request, a Secretarial letter directing the EDC to file a petition for protective order under §  5.423 (relating to orders to limit availability of proprietary information) within 14 days.

   (2)  Absent the timely filing of such a petition, the proprietary information claim will be deemed to have been waived. The proprietary claim will be honored during the Commission’s consideration of the petition for protective order.

   The provisions of this §  57.141 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 (a)  The Annual Resource Planning Report (ARPR) shall include a forecast of energy demand in megawatt-hours per calendar year.

   (1)  The data shall include actual data for the past year and estimated data for the ensuing 5 years.

   (2)  The data shall be displayed by the following component parts:

     (i)   Residential, commercial and industrial sectors.

     (ii)   Other demand, including public street and highway lighting, other sales to public authorities and sales to railroads and railways.

     (iii)   Sales for resale.

     (iv)   Total consumption, as the sum of (i), (ii) and (iii).

     (v)   System losses and company use.

     (vi)   Net energy for load, as (iv) minus (v).

 (b)  The ARPR shall include a forecast of connected peak load.

   (1)  The data shall include actual data for the past year and estimated data for the ensuing 5 years.

   (2)  The data shall be displayed by the following component parts:

     (i)   Peak loads for both summer and winter seasons, the latter being the winter following the summer of the past year.

     (ii)   The date and time of the summer and winter peak loads.

     (iii)   Annual peak load.

     (iv)   Annual load factor.

   (3)  The summer season is June through September and the winter season is December through March.

 (c)  The ARPR shall include a forecast of the number of connected customers.

   (1)  The data shall include actual data for the past year and estimated data for the ensuing 5 years.

   (2)  The data shall be displayed by the following component parts:

     (i)   Residential, commercial and industrial sectors.

     (ii)   Other, including public street and highway lighting, other sales to public authorities and sales to railroads and railways.

     (iii)   Total number of customers.

 (d)  The ARPR shall include an aggregate forecast of energy demand and peak load for the EDC’s control area and appropriate regional reliability council, as defined under §  57.192 (relating to definitions). The data shall include actual data for the past year and estimated data for the ensuing 5 years.

   The provisions of this §  57.142 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 (a)  The Annual Resource Planning Report (ARPR) shall include a description of existing generating capability, the cost of which is being recovered by the EDC in a competitive transition charge, as defined under 66 Pa.C.S. §  2803 (relating to definitions), and planned generating capability installations, changes and removals.

   (1)  The data shall include station name and unit number, location, date installed or to be installed, unit type, primary fuel type and fuel transportation method, summer and winter net capability in megawatts, changes in capability occurring during the past year and percent ownership share.

   (2)  The data shall include those facilities which are owned in whole or in part by the reporting EDC. A jointly owned unit shall be designated as such and the EDC’s share of the unit shall be indicated.

   (3)  The data shall include actual data for the past year and estimated data for the ensuing 5 years.

 (b)  The ARPR shall include a description of existing generating capability and planned generating capability installations, changes and removals for the EDC’s control area and appropriate regional reliability council, as defined under §  57.192 (relating to definitions).

   (1)  The data shall include actual data for the past year and estimated data for the ensuing 5 years.

   (2)  The data shall include station name and unit number, location, date installed or to be installed, unit type, primary fuel type and fuel transportation method and summer and winter net capability in megawatts.

 (c)  The ARPR shall include a synopsis of major occurrences where electric generation suppliers were unable to supply scheduled loads within the EDC’s service territory during the previous year. The synopsis shall include the electric generation supplier’s name, the amount of energy and capacity involved in megawatt-hours and megawatts, respectively, the period of time involved and other pertinent information relating to the major occurrences.

   The provisions of this §  57.143 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 (a)  The Annual Resource Planning Report (ARPR) shall contain a description of transmission lines, as defined in §  57.1 (relating to definitions), or any portions thereof for which construction or acquisition of right-of-way is scheduled to begin within the 5-year forecast period; and additions to or modifications of existing electric supply lines which will result in the creation of a transmission line, whether or not located entirely on existing rights-of-way, public roads or the property of the sole customer served by the line, for which construction or acquisition of right-of-way is scheduled to begin within the 5-year forecast period.

 (b)  The description shall contain the following:

   (1)  A descriptive title of the line or portion thereof.

   (2)  The design voltage.

   (3)  The length of the line in miles.

   (4)  The location of the township and county.

   (5)  The date on which construction is scheduled to begin.

   (6)  The date on which the line is scheduled to be placed in service.

   (7)  The actual cost or most recent estimated cost for a line described in subsection (c), provided that an estimate furnished be updated at the next annual filing.

 (c)  The ARPR shall also identify HV transmission lines, as defined in §  57.1, which have been completed since the filing of the previous report.

 (d)  The ARPR shall also identify measures that the utility has taken to reduce the levels of electro-magnetic field (EMF) emissions produced by the proposed HV transmission lines.

 (e)  The ARPR shall include an estimate of change in import and export capability or change in system transmission constraints which will will result from any planned transmission change identified in subsection (a).

   The provisions of this §  57.144 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 The Annual Resource Planning Report (ARPR) shall include a description of each existing and planned qualifying facility and independent power producer, as defined under §  57.31 (relating to definitions), from which the EDC will purchase energy or capacity, or both. Projects shall be grouped by status and subtotals shall be provided.

   (1)  The data shall include the amount of energy in kilowatt-hours from each facility during the past calendar year, or the expected amount of energy to be purchased from the facility, and the contract capacity in kilowatts, if applicable.

   (2)  Facilities with an individual annual output of less than 20,000 kilowatt-hours or capacity less than 5 kilowatts may be consolidated by customer class and energy source—for example: residential/wind.

   (3)  If an entity has requested anonymity, the EDC does not have to name it, but shall only provide the facility’s characteristics.

   The provisions of this §  57.145 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 The Annual Resource Planning Report (ARPR) shall include a forecast of scheduled imports and exports in megawatts for the EDC, the EDC’s control area and appropriate regional reliability council, as defined under §  57.192 (relating to definitions).

   (1)  Actual data for the past year and estimated data for the ensuing 5 years shall be provided.

   (2)  The data shall be provided for both summer and winter seasons, the latter being the winter following the summer of the past year.

   (3)  A breakdown of scheduled imports and exports shall be provided including the name and type of each participating entity.

   The provisions of this §  57.147 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 The Annual Resource Planning Report (ARPR) shall include a summary of demand, resource and energy data for the past year.

   (1)  The peak day data shall be provided for both summer and winter seasons, the latter being the winter following the summer of the past year.

   (2)  The report shall provide peak day purchases and sales of the electric distribution company in megawatts and calendar year purchases and sales in megawatt-hours.

   (3)  The report shall identify each electric generation supplier’s peak day unregulated load in megawatts and calendar year sales in megawatt-hours.

   The provisions of this §  57.148 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 The Annual Resource Planning Report (ARPR) shall include a detailed description of conservation and load management programs implemented or operational during the past calendar year and all programs which are proposed to be implemented within 1 year following the filing of this report.

   (1)  A conservation program shall include a method designed to produce a reduction in total annual energy use, regardless of its effect on peak demand.

   (2)  A load management program shall include a method which will reduce the peak or maximum load or demand, regardless of its effect on total annual energy use.

   (3)  The program description shall include actual or anticipated results and a breakdown of monetary and personnel resources.

   The provisions of this §  57.149 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 In preparing the Annual Resource Planning Report required by this subchapter, each EDC shall use the current forms and schedules specified by the Commission, which shall include the following:

   (1)  ARPR 1—Historical and Forecast Energy Demand.

   (2)  ARPR 2—Historical and Forecast Connected Peak Load.

   (3)  ARPR 3—Historical and Forecast Number of Connected Customers.

   (4)  ARPR 4—Historical and Forecast Peak Load and Energy.

   (5)  ARPR 5—Existing Generating Capability.

   (6)  ARPR 6—Future Generating Capability Installations, Changes and Removals.

   (7)  ARPR 7—Projected Capacity and Demand.

   (8)  ARPR 8—Qualifying Facility and Independent Power Production Facilities.

   (9)  ARPR 9—Scheduled Imports and Exports.

   (10)  ARPR 10—Summary of Demands, Resources and Energy for the Previous Year.

   (11)  ARPR 11—Transmission Line Projection.

   (12)  ARPR 12—Conservation and Loan Management Program Description.

   The provisions of this §  57.152 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

 The Annual Resource Planning Report shall be accompanied by a summary which is suitable for public distribution. Electric distribution companies shall maintain copies of the summary open to public inspection during normal business hours.

   The provisions of this §  57.154 amended under the Public Utility Code, 66 Pa.C.S. § §  501, 524, 1501, 1504 and 2809.

   The provisions of this §  57.154 amended February 25, 2000, effective February 26, 2000, 30 Pa.B. 1129. Immediately preceding text appears at serial page (250670).

Subchapter M. STANDARDS FOR CHANGING A CUSTOMER’S ELECTRICITY GENERATION SUPPLIER

Sec.

 When a contact occurs between a customer or a person authorized to act on the customer’s behalf and an EGS to request a change of the EGS, upon receiving direct oral confirmation or written authorization from the customer to change the EGS, the contacted EGS shall:

   (1)  Notify the EDC of the customer’s EGS selection by the end of the next business day following the customer contact.

   (2)  Upon receipt of this notification, the EDC shall send the customer a confirmation letter noting the proposed change of EGS. This letter shall include notice of a 10-day waiting period in which the order may be canceled before the change of the EGS takes place. The notice shall include the date service with the new EGS will begin unless the customer contacts the EDC to cancel the change. The 10-day waiting period shall begin on the day the letter is mailed. The letter shall be mailed by the end of the next business day following the receipt of the notification of the customer’s selection of an EGS.

 (a)  When a customer contacts an EDC or an EGS and alleges that the EGS has been changed without consent, the company contacted shall:

   (1)  Consider the matter a customer registered dispute.

   (2)  Investigate and respond to the dispute consistent with § §  56.151 and 56.152 (relating to utility company dispute procedures).

 (b)  When the customer’s dispute has been filed within the first two billing periods since the customer should reasonably have known of a change of the EGS and the dispute investigation establishes that the change occurred without the customer’s consent, the customer is not responsible for EGS bills rendered during that period. If the customer has made payments during this period, the company responsible for initiating the change of supplier shall issue a complete refund within 30 days of the close of the dispute. The refund or credit provision applies only to the generation charges.

 (c)  A customer who has had an EGS changed without having consented to that change shall be switched back to the original EGS for no additional fee. Any charges involved in the switch back to the prior EGS are the responsibility of the company that initiated the change without the customer’s consent.

 (d)  If a customer files an informal complaint with the Commission alleging that the customer’s EGS was changed without the customer’s consent, the Bureau of Consumer Services will issue an informal decision that includes a determination of customer liability for any EGS bills or administrative charges that might otherwise apply, rendered since the change of the EGS.

 (e)  In addition to customer-specific remedies, the Commission may, after investigation and decision, assess fines under 66 Pa.C.S. Chapter 33 (relating to violations and penalties) and initiate proceedings to revoke the license of an EGS that demonstrates a pattern of violating this subchapter. The Commission may order a particular EGS that has a pattern of violating this subchapter to obtain written authorization from every new customer as a condition of providing service in this Commonwealth. Nothing in this subchapter is intended to limit the Commission’s authority.

 This subchapter does not apply when the customer’s service is discontinued by the EGS and subsequently provided by the default service provider because no other EGS is willing to provide service to the customer.

 Each EDC and each EGS shall preserve all records relating to unauthorized change of EGS disputes for 3 years from the date the customers filed the dispute. These records shall be made available to the Commission or its staff upon request.

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.

Subchapter O. ADVANCED METER DEPLOYMENT

Sec.

 (a)  The purpose of this subchapter is to facilitate the deployment of advanced metering equipment and the associated development of generation services based on these technologies. This subchapter establishes a procedure for identifying and providing for customer selection of qualified advanced meters, meter-related devices or deployment of automatic meter reading network equipment from the EDC while maintaining the safety and reliability of the electric system in this Commonwealth. This subchapter does not require the public to participate in an advanced metering program.

 (b)  This subchapter will not preclude the Commission from approving a restructuring settlement agreement which incorporates advanced meter provisions contrary to the requirements in §  57.255 (relating to EDC responsibilities regard-

 (a)  A qualified advanced meter, meter-related device or network shall be the customer’s billing meter and shall meet certain advanced meter standards established by the Commission according to the following process:

   (1)  The Office of the Executive Director will appoint and chair a Metering Committee (Committee) composed of, to the extent possible, a balanced number of representatives from EDCs and EGSs, as well as representatives of consumer, environmental and EDC electrical worker union interests. The Committee will be designated an advisory body to the Commission as provided in this subsection.

   (2)  The Committee will meet as necessary to establish and modify recommendations to the Commission for a catalog of qualified advanced meters, meter-related devices and networks or to review recognized changes and improvements in metering technology.

     (i)   The Committee will include recommendations to the Commission in the catalog for a variety of technologies that support the demands of customers and the services of EGSs expected in the market. These technologies may include: networks, two-way communication, time of use capabilities, load management, net metering for self-generation and similar services. Qualified advanced meters, meter-related devices and networks shall meet the standards described in §  57.254 (relating to advanced meter standards)

     (ii)   The Committee will consider applicable technical standards, manufacturers’ information, another state’s approval of a particular type of meter, meter-related device or network and other appropriate areas in its meter catalog deliberations.

     (iii)   An interested party shall request, in writing, to have an advanced meter, meter-related device or network to be considered for review by the Committee. The written request shall include a brief description of the subject meter, meter-related device, or network, manufacturers’ information, any proposal to use the device other than on a Statewide basis, a statement claiming compliance with applicable standards in §  57.254, and other information necessary for a Committee recommendation.

     (iv)   Upon receipt of a written request for inclusion of an advanced meter in the Catalog, the Committee shall serve notice on an affected EDC. The EDC shall have 30 days from the date of receipt of the notice to respond to the Committee regarding costs and incompatibility. In the absence of an EDC response to costs and incompatibility, the Committee may assume that the subject device is compatible and incremental costs are de minimis.

     (v)   The Committee will make a recommendation to the Commission regarding the subject meter, meter-related device or network within 60 days from the date the request is received. The interested party that proposed the meter or device, and any other interested party, shall have 14 days to submit comments to the Commission concerning the Committee’s recommendation.

     (vi)   Upon receipt of the Committee’s recommendations, the Commission will serve the recommendations on affected parties consistent with a service list developed by the Office of Executive Director, including all EDCs, the OCA, the Office of Small Business Advocate (OSBA) and the Office of Trial Staff. The Commission will issue a decision regarding approval of the subject meter, meter-related device or network within 60 days of the receipt of the Committee’s recommendation.

   (3)  The Committee will submit a report to the Commission by October 1, 1999, and at least annually thereafter, with its considerations and recommendations.

   (4)  The Committee shall include in its reports to the Commission facts concerning anticipated net incremental costs of qualified advanced meters or meter-related devices and recommendations concerning the appropriate level and manner of payment of the charges, if any.

 (b)  Customers or EGSs, or both, shall be responsible for any net incremental costs incurred by the EDC as a result of using a qualified advanced meter or meter-related device.

   (1)  Customers using a qualified advanced meter or meter-related device may be assessed a bill surcharge by the EDC to cover any net incremental cost associated with the choice to use an advanced meter.

   (2)  Instead of a customer surcharge, the EGS may pay the EDC for net incremental costs.

   (3)  The customer and EGS may mutually agree to allocate the charges between them.

 (a)  A qualified advanced meter, meter-related device and a network shall conform to § §  57.20—57.25 (relating to meter testing) and the American National Standards Institute Standard C12, as applicable, or as these standards may be updated.

 (b)  A qualified advanced meter, meter-related device and network shall be the customer’s billing meter and shall meet the standards adopted by the Commission from time to time after consideration of the recommendations of the Committee. Qualified advanced meters, meter-related devices or networks shall possess open, nonproprietary communications capabilities to allow both an EGS and an EDC to access information in a standard data format. In addition, a qualified advanced meter, meter-related device or network shall be capable of measuring hourly usage and may support one or more functional requirements, such as the ability to do one or more of the following:

   (1)  Modify a profile interval.

   (2)  Provide a communications port for a customer to monitor usage.

   (3)  Provide a pulse output to allow for usage monitoring.

   (4)  Provide password protection.

   (5)  Measure in two directions.

   (6)  Have multiple callout capability.

 (c)  Access to meter reading information shall be limited only to the customer, the EDC or the current EGS.

 (d)  A meter, meter-related device and network that meets the requirements in subsections (a) and (b) shall be considered a qualified advanced meter, meter-related device and network and shall be subject to applicable surcharges and other requirements of this subchapter. The Commission will periodically review and revise these requirements as necessary.

 (a)  Upon written request from both a customer and the EGS of that customer, the EDC shall make available and install for use a qualified advanced meter or meter-related device. The qualified advanced meter shall be the customer’s billing meter and shall meet certain standards established by the Commission in §  57.254 (relating to advanced meter standards).

 (b)  A qualified advanced meter, meter-related device and network, as well as related infrastructure, shall be owned and operated by the EDC as part of its regulated local distribution function. A network may be owned by an EDC or its chosen network provider. An EDC shall be responsible for compliance with the applicable requirements related to installation, calibration, maintenance, testing, physical reading, safety and reliability, as well as installing and maintaining associated infrastructure as applicable.

 (c)  An EDC shall provide meter reading for billing purposes except when the customer has chosen to receive a separate generation supply bill from its EGS.

 (d)  An EDC shall install and make operational a qualified advanced meter or meter-related device within 20 business days from the date the request is received by an EDC.

 (e)  An EDC shall physically read an automated meter in compliance with §  56.12(5)(i) (relating to remote meter reading; estimated billing; ratepayer readings).

 (f)  The EDC shall develop a procedure to ensure that qualified advanced meters or meter-related devices are available for installation as required in this subchapter. The EDC may purchase and stock the meters, meter-related devices or may otherwise arrange with EGSs and other EDCs for the most economical way to ensure availability.

 (g)  An EDC responsible for providing metering services on a customer’s premises shall ensure that the work be done by responsible individuals whose activities in the performance of these services are under the control of the EDC and who are qualified to perform the work according to the EDC’s specifications and good utility practices.

 (h)  If the Commission approves a restructuring settlement agreement incorporating EDC metering responsibilities contrary to the provisions in any section of this subchapter, the terms and conditions of the agreement shall, to the extent applicable, govern EDC responsibilities.

 An EDC may deploy a network for automatic meter reading capability if the following conditions are met:

   (1)  The network is compatible with market requirements as a qualified advanced meter based on Committee review and recommendations as adopted by the Commission.

   (2)  The application shall include proposed tariffs concerning any charges for deployment of the network.

   (3)  The application shall include, at a minimum:

     (i)   A description of the system.

     (ii)   Implementation time frame.

     (iii)   Certification on compliance with applicable standards as provided in §  57.254 (relating to advanced meter standards).

     (iv)   Implementation costs.

     (v)   Summary of educational materials on new technologies.

     (vi)   Impacts on customer electric bills.

 (a)  A dispute between an EDC and a residential or small commercial customer, or between an EGS and a residential or small commercial customer, shall be filed with the Bureau of Consumer Services as an informal complaint for mediation and dispute resolution under § §  3.111, 3.112 and 56.161—56.224. The Bureau of Consumer Services will provide a notice of the dispute and notice of the opportunity to participate to the EDC, EGS and to other parties associated with the complaint.

 (a)  An EDC shall maintain the following records:

   (1)  Updated lists of all qualified advanced meters and meter-related devices.

   (2)  General summary of procedures for advanced meter or meter-related device acquisition and installation.

   (3)  The date of advanced meter purchase request by customer and supplier and date of installation.

   (4)  The summary of qualified advanced meters deployed, including name of manufacturer and serial numbers.

   (5)  The summary of the characteristics and capabilities of each qualified advanced meter deployed.

 (b)  An EDC shall retain and make available to the general public upon request information required under subsection (a)(1) and (2). An EDC shall retain and make available to the Commission upon request the information required under subsection (a)(3)—(5). The EDC shall retain the information required under subsections (a)(3)—(5) for 1-calendar year from the date of qualified advanced meter or meter-related device deployment.

 (a)  An EDC shall provide an initial summary statement to its customers which describes the availability and general uses of advanced metering. The initial summary statement may be distributed as part of a regularly scheduled customer electric usage bill or other regularly scheduled customer communications as applicable.

 (b)  The EGS shall ensure that a customer is informed as to the capabilities, advantages and disadvantages of a qualified advanced meter prior to installation or participation in a generation service program utilizing advanced metering. An EGS shall provide to the customer a terms of service disclosure statement that addresses advanced metering.

 (c)  An EDC shall provide, as part of the customer education program, information addressing the use of an advanced meter, basic meter operations and capabilities, advantages and disadvantages of advanced metering, including qualified advanced meter options, applicable costs/surcharges and methods to obtain additional information.

 (d)  The informational and promotional materials are required to:

   (1)  Comply with applicable requirements of the act and existing truth-in advertising requirements.

   (2)  Prominently disclose that additional information is available from either the local EDC, the customer’s EGS or the Commission.

   (3)  State that the available advanced meters are qualified to meet current Commission performance and technical standards.

   This section cited in 52 Pa. Code §  57.258 (relating to record retention and reporting requirements).